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

Quarterly Report for the Quarterly Period Ended June 30, 2011

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, 2011

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

Commission file number: 001-12719

GOODRICH PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

76-0466193

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

801 Louisiana, Suite 700

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes 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 1, 2011 was 36,124,862.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

TABLE OF CONTENTS


		Page
PART I	FINANCIAL INFORMATION		3
ITEM 1	FINANCIAL STATEMENTS		3
	Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010		3
	Consolidated Statements of Operations for the three and six months ended June 30, 2011 and 2010		4
	Consolidated Statements of Cash Flows for the six months ended June 30, 2011 and 2010		5
	Notes to Consolidated Financial Statements		6
ITEM 2	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		15
ITEM 3	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		27
ITEM 4	CONTROLS AND PROCEDURES		29

PART II	OTHER INFORMATION		30
ITEM 1	LEGAL PROCEEDINGS		30
ITEM 1A	RISK FACTORS		30
ITEM 6	EXHIBITS		31

PART 1 – FINANCIAL INFORMATION

Item 1—Financial Statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED BALANCE SHEET

(In thousands, except share amounts)


	June 30, 2011			December 31, 2010
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	547		$	17,788
Restricted cash		30,800			4,232
Accounts receivable, trade and other, net of allowance		7,508			9,231
Income taxes receivable		453			4,335
Accrued oil and gas revenue		22,960			14,920
Fair value of oil and natural gas derivatives		20,835			24,467
Inventory		6,743			7,831
Prepaid expenses and other		1,497			3,045

Total current assets		91,343			85,849

PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		1,415,054			1,217,891
Furniture, fixtures and equipment		5,316			4,962

		1,420,370			1,222,853
Less: Accumulated depletion, depreciation and amortization		(740,082	)		(685,110	)

Net property and equipment		680,288			537,743
Fair value of oil and natural gas derivatives		8,605			15,732
Deferred tax assets		8,736			19,695
Deferred financing cost		12,211			5,558

TOTAL ASSETS	$	801,183		$	664,577

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	49,433		$	47,106
Accrued liabilities		60,886			47,105
Accrued abandonment costs		4,499			4,392
Deferred tax liabilities current		8,736			19,695
Fair value of oil and natural gas derivatives		92			—
Current portion of debt		26,022			167,086

Total current liabilities		149,668			285,384
LONG-TERM DEBT		481,060			179,171
Accrued abandonment costs		11,604			11,683
Fair value of oil and natural gas derivatives		5,684			4,367

Total liabilities		648,016			480,605

Commitments and contingencies (See Note 9)
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 36,121,963 and 37,685,378 shares, respectively		7,224			7,212
Treasury stock (74 and 12,377 shares, respectively)		(1	)		(196	)
Additional paid in capital		638,926			643,828
Retained earnings (accumulated deficit)		(495,232	)		(469,122	)

Total stockholders’ equity		153,167			183,972

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	801,183		$	664,577

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, Except Per Share Amounts)

(Unaudited)


	Three months ended June 30,						Six months ended June 30,
	2011			2010			2011			2010
REVENUES:
Oil and gas revenues	$	52,434		$	34,051		$	93,352		$	74,477
Other		437			111			750			140

		52,871			34,162			94,102			74,617

OPERATING EXPENSES:
Lease operating expense		5,215			6,329			10,118			13,561
Production and other taxes		1,645			390			2,595			1,353
Transportation		2,301			2,189			4,687			4,642
Depreciation, depletion and amortization		30,927			28,403			55,886			58,616
Exploration		2,325			2,627			4,741			5,606
Impairment		1,050			—			1,050			—
General and administrative		7,328			7,001			15,578			16,447
Gain on sale of assets		—			—			(236	)		—
Other		—			—			—			8,500

		50,791			46,939			94,419			108,725

Operating income (loss)		2,080			(12,777	)		(317	)		(34,108	)

OTHER INCOME (EXPENSE):
Interest expense		(12,965	)		(9,195	)		(23,793	)		(18,315	)
Interest income and other		10			53			22			106
Gain on derivatives not designated as hedges		10,954			320			944			35,049
Gain on extinguishment of debt		3			—			58			—

		(1,998	)		(8,822	)		(22,769	)		16,840

Income (loss) before income taxes		82			(21,599	)		(23,086	)		(17,268	)
Income tax benefit (expense)		—			—			—			—

Net income (loss)		82			(21,599	)		(23,086	)		(17,268	)
Preferred stock dividends		1,512			1,512			3,024			3,024

Net loss applicable to common stock	$	(1,430	)	$	(23,111	)	$	(26,110	)	$	(20,292	)

PER COMMON SHARE
Net loss applicable to common stock - basic	$	(0.04	)	$	(0.64	)	$	(0.72	)	$	(0.57	)
Net loss applicable to common stock - diluted	$	(0.04	)	$	(0.64	)	$	(0.72	)	$	(0.57	)
Weighted average common shares outstanding - basic		36,110			35,918			36,093			35,888
Weighted average common shares outstanding - diluted		36,110			35,918			36,093			35,888

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six months ended June 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(23,086	)	$	(17,268	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization		55,886			58,616
Unrealized (gain) loss on derivatives not designated as hedges		12,168			(26,829	)
Exploration costs		—			1,005
Impairment of oil and gas properties		1,050			—
Amortization of leasehold costs		2,977			3,190
Share based compensation (non-cash)		3,177			3,989
Gain on sale of assets		(236	)		—
Gain on extinguishment of debt		(58	)		—
Amortization of finance cost and debt discount		8,203			9,495
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance		441			9,357
Accrued oil and gas revenue		(8,040	)		3,453
Inventory		1,088			(6,982	)
Income tax receivable/payable		3,882			—
Prepaid expenses and other		175			357
Accounts payable		2,259			1,443
Accrued liabilities		8,035			7,827

Net cash provided by operating activities		67,921			47,653

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(193,508	)		(112,391	)
Proceeds from sale of assets		172			—

Net cash used in investing activities		(193,336	)		(112,391	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments of bank borrowings		(30,000	)		—
Proceeds from bank borrowings		52,500			—
Repurchase from convertible notes		(150,277	)		—
Cash restricted for repurchase of convertible notes		(26,568	)		—
Proceeds from high yield offering		275,000			—
Exercise of stock options and warrants		—			10
Debt issuance costs		(9,094	)		(318	)
Preferred stock dividends		(3,024	)		(3,024	)
Other		(363	)		(574	)

Net cash (used in) provided by financing activities		108,174			(3,906	)

DECREASE IN CASH AND CASH EQUIVALENTS		(17,241	)		(68,644	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		17,788			125,116

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	547		$	56,472

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—Description of Business and Significant Accounting Policies

Goodrich Petroleum Corporation is an independent oil and gas company engaged in the exploration, development and production of oil and natural gas properties primarily in Northwest Louisiana and East Texas, which includes the Haynesville Shale and Cotton Valley trends and South Texas, which includes the Eagle Ford Shale trend.

The consolidated financial statements of the Company 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 (“US GAAP”) has been condensed or omitted. The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation. Significant intercompany balances and transactions have been eliminated in consolidation.

The accompanying consolidated financial statements of the Company should be read in conjunction with the consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2010. The results of operations for the three and six months ended June 30, 2011 are not necessarily indicative of the results to be expected for the full year.

Reclassifications—Certain amounts for prior periods have been reclassified to conform to current year presentation. These reclassifications have no impact on net income or loss.

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

Restricted Cash—Restricted cash represents cash held in escrow of $30.8 million as of June 30, 2011 which includes $4.2 million for a suspensive appeal bond and $26.6 million for the remaining outstanding 3.25% Convertible Senior Notes due 2026. See Notes 3 and 9.

Inventory—Inventory consists of casing and tubulars that are expected to be used in our drilling operations and crude oil in storage tanks. Crude oil inventory is carried on the balance sheet at the lower of cost or market.

Derivative Instruments—We use derivative instruments such as collars and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas and to hedge our exposure to changing interest rates. Accounting standards related to derivative instruments and hedging activities require that all derivative instruments subject to the requirements of those standards be measured at fair value and recognized as assets or liabilities in the balance sheet. Changes in fair value are required to be recognized in earnings unless specific hedge accounting criteria are met. We do not designate our derivative contracts as hedges, and accordingly changes in fair value are reflected in earnings. See Note 7.

Impairment—Proved oil and gas properties are reviewed for impairment on a field-by-field basis when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net cash flows are calculated based on estimated future oil and gas sales revenues less future expenditures necessary to develop and produce the reserves. If the sum of these estimated future cash flows (undiscounted) is less than the carrying amount of the property, an impairment loss is recognized for the excess of the property’s carrying amount over its estimated fair value based on estimated discounted future cash flows. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We perform this comparison using estimates of future commodity prices and our estimates of proved and probable reserves and recent market transactions. For the quarter ended June 30, 2011, we recorded impairments of $1.0 million.

Income Taxes—We account for income taxes 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. See Note 5.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 2—Asset Retirement Obligations

The reconciliation of the beginning and ending asset retirement obligation (“ARO”) for the period ending June 30, 2011, is as follows (in thousands):


	June 30, 2011
Beginning balance	$	16,075
Liabilities incurred		261
Liabilities settled or sold		(1,885	)
Revisions in estimated liabilities		1,050
Accretion expense		602

Ending balance		16,103

Current liability		4,499
Long term liability	$	11,604

NOTE 3—Debt

Debt consisted of the following balances (in thousands):


	June 30, 2011			December 31, 2010
Senior Credit Facility	$	22,500		$	—
8.875% Senior Notes due 2019		275,000			—
3.25% Convertible Senior Notes due 2026		26,568			175,000
Debt discount on 3.25% Convertible Senior Notes due 2026		(546	)		(7,914	)
5.0% Convertible Senior Notes due 2029		218,500			218,500
Debt discount on 5.0% Convertible Senior Notes due 2029		(34,940	)		(39,329	)

Total debt	$	507,082		$	346,257

Senior Credit Facility

On May 5, 2009, we entered into a Second Amended and Restated Credit Agreement (the “Senior Credit Facility”) that replaced our previous facility. On February 25, 2011, we entered into a Fourth Amendment to the Senior Credit Facility. Included among the conditions required for the Fourth Amendment to become effective were (i) the closing of the issuance and sale of our 8.875% Notes due 2019 (the “2019 Notes”), and (ii) the placement of not less than $175 million of net proceeds from the sale of the 2019 Notes in an escrow account with the lenders to be used for the redemption or earlier repurchase of all our outstanding 3.25% Convertible Senior Notes due 2026 (the “2026 Notes”), both of which occurred on March 2, 2011.

Total lender commitments under the Senior Credit Facility are $600 million subject to current borrowing base limitations of $225 million. The Senior Credit Facility matures on July 1, 2014 (subject to automatic extension to February 25, 2016, if, prior to maturity, we prepay or escrow certain proceeds sufficient to prepay our $218.5 million 5% Convertible Senior Notes due 2029 (the “2029 Notes”). Revolving borrowings under the Senior Credit Facility are limited to, and subject to, periodic redeterminations of the borrowing base. Interest on revolving borrowings under the Senior Credit Facility accrues at a rate calculated, at our option, at the bank base rate plus 1.00% to 1.75%, or LIBOR plus 2.00% to 2.75%, depending on borrowing base utilization. Pursuant to the terms of the Senior Credit Facility, borrowing base redeterminations occur on a semi-annual basis on April 1 and October 1. As of June 30, 2011, we had $22.5 million outstanding under the Senior Credit Facility. Substantially all our assets are pledged as collateral to secure the Senior Credit Facility.

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

•

Current Ratio of 1.0/1.0;

•

Interest Coverage Ratio of EBITDAX of not less than 2.5/1.0 for the trailing four quarters or when measured for the first three quarters of 2011, shall be based on annualized 2011 interim EBITDAX amounts rather than trailing four quarters. The interest for such period to apply solely to the cash portion of interest expense; and

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

•

Total Debt no greater than 4.0 times EBITDAX for the trailing four quarters. Total Debt used in such ratio to be reduced by the amount of any restricted cash held in an escrow account established for the benefit of the lenders and dedicated to the redemption or prepayment of the 2026 Notes, the 2029 Notes or the 2019 Notes; provided that such ratios, when measured for the first three quarters of 2011, shall be based on annualized 2011 interim EBITDAX amounts rather than trailing four quarters.

As defined in the credit agreement EBITDAX is earnings before interest expense, income tax, DD&A, exploration expense and impairment of oil and gas properties. In calculating EBITDAX for this purpose, earnings include realized gains (losses) from derivatives but exclude unrealized gains (losses) from derivatives.

We were in compliance with all the financial covenants of the Senior Credit Facility as of June 30, 2011.

8.875% Senior Notes due 2019

On March 2, 2011, we sold $275 million of our 2019 Notes. The 2019 Notes mature on March 15, 2019, unless earlier redeemed or repurchased. The 2019 Notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The 2019 Notes accrue interest at a rate of 8.875% annually, and interest is paid semi-annually in arrears on March 15 and September 15. The 2019 notes are guaranteed by our subsidiary that also guarantees our Senior Credit Facility.

Before March 15, 2014, we may on one or more occasions redeem up to 35% of the aggregate principal amount of the 2019 Notes at a redemption price of 108.875% of the principal amount of the 2019 Notes, plus accrued and unpaid interest to the redemption date, with the net cash proceeds of certain equity offerings. On or after March 15, 2015, we may redeem all or a portion of the 2019 Notes at redemption prices (expressed as percentages of principal amount) equal to (i) 104.438% for the twelve-month period beginning on March 15, 2015; (ii) 102.219% for the twelve-month period beginning on March 15, 2016 and (iii) 100.000% on or after March 15, 2017, in each case plus accrued and unpaid interest to the redemption date. In addition, prior to March 15, 2015, we may redeem all or a part of the 2019 Notes at a redemption price equal to 100% of the principal amount of the 2019 Notes to be redeemed plus a make-whole premium, plus accrued and unpaid interest to the redemption date.

The indenture governing the 2019 Notes restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem or retire such capital stock; (iii) sell assets, including the capital stock of our restricted subsidiaries; (iv) pay dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company. These covenants are subject to a number of important exceptions and qualifications. At any time when the 2019 Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the indenture governing the 2019 Notes) has occurred and is continuing, many of these covenants will terminate.

Interest expense recognized relating to the contractual interest rate and amortization of financing cost for the three and six months ended June 30, 2011 was $6.3 million and $8.3 million, respectively. The effective interest rate on the liability component of the 2019 Notes was 9.2% for both the three and six month periods ended June 30, 2011.

5% Convertible Senior Notes due 2029

In September 2009, we sold $218.5 million of our 2029 Notes. The 2029 Notes mature on October 1, 2029, unless earlier converted, redeemed or repurchased. The 2029 Notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The 2029 Notes accrue interest at a rate of 5% annually, and interest is paid semi-annually in arrears on April 1 and October 1 of each year, beginning in 2010. Interest began accruing on the 2029 Notes on September 28, 2009.

Before October 1, 2014, we may not redeem the 2029 Notes. On or after October 1, 2014, we may redeem all or a portion of the 2029 Notes for cash, and the investors may require us to repurchase the 2029 Notes on each of October 1, 2014, 2019 and 2024. Upon conversion, we have the option to deliver shares at the applicable conversion rate, redeem in cash or in certain circumstances redeem in a combination of cash and shares.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Investors may convert their 2029 Notes at their option at any time prior to the close of business on the second business day immediately preceding the maturity date under the following circumstances: (1) during any fiscal quarter (and only during such fiscal quarter), if the last reported sale price of our common stock is greater than or equal to 135% of the conversion price of the notes (as defined in the indenture governing the 2029 Notes) for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter; (2) prior to October 1, 2014, during the five business-day period after any ten consecutive trading-day period (the “measurement period”) in which the trading price of $1,000 principal amount of 2029 Notes for each trading day in the measurement period was less than 97% of the product of the last reported sale price of our common stock and the conversion rate on such trading day; (3) if the 2029 Notes have been called for redemption; or (4) upon the occurrence of one of the specified corporate transactions described in the indenture governing the 2029 Notes. Investors may also convert their 2029 Notes at their option at any time beginning on September 1, 2029, and ending at the close of business on the second business day immediately preceding the maturity date.

We separately account for the liability and equity components of the 2029 Notes in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. As of June 30, 2011, the $218.5 million aggregate principal amount of the 2029 Notes was carried on the balance sheet at $183.6 million with a debt discount balance of $34.9 million. As of December 31, 2010, the $218.5 million aggregate principal amount of the 2029 Notes was carried on the balance sheet at $179.2 million with a debt discount of $39.3 million. The debt discount will be amortized using the effective interest rate method based upon an original five year term through October 1, 2014. Interest expense recognized relating to the contractual interest rate and amortization of debt discount and financing cost for the three and six months ended June 30, 2011, was $5.2 million and $10.3 million, respectively. The effective interest rate on the liability component of the 2029 Notes was 11.4% and 11.5% for the three and six month periods ended June 30, 2011, respectively. The 2029 Notes are guaranteed by our subsidiary that also guarantees our Senior Credit Facility.

3.25% Convertible Senior Notes Due 2026

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

During March 2011, we repurchased $145.9 million of our 2026 Notes using a portion of the net proceeds from the issuance of our 2019 Notes. We paid a premium of 101.25% and accrued interest. We recorded in the three months ended March 31, 2011, a $0.1 million gain on the early extinguishment of debt related to the repurchase. Due to the repurchase, the debt discount was reduced resulting in a balance of $1.0 million to be amortized over the next 8 months.

During June 2011, we repurchased $2.5 million of our 2026 Notes using a portion of the net proceeds from the issuance of our 2019 Notes. We paid a premium of 100.75% and accrued interest. We recorded in the three months ended June 30, 2011, a gain of less than $0.1 million on the early extinguishment of debt related to the repurchase. Under the terms of our Senior Credit Facility, we have deposited in escrow $26.6 million to be used for the redemption of the remaining outstanding 2026 Notes.

Due to the repurchase, the debt discount as of June 30, 2011 was reduced resulting in a balance of $0.5 million to be amortized over the next 5 months. Interest expense relating to the contractual interest rate and amortization of debt discount and financing cost relating to the 2026 Notes for the three and six months ended June 30, 2011 was $0.6 million and $3.4 million, respectively. The effective interest rate on the liability component of the 2026 Notes was 8.9% and 9.2% for the three and six month periods ended June 30, 2011.

We intend to redeem all of the remaining outstanding 2026 Notes on or before December 1, 2011. As of June 30, 2011, we have classified the 2026 Notes as a current liability.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 4—Net Loss Per Common Share

Net loss applicable to common stock was used as the numerator in computing basic and diluted income per common share for the three and six months ended June 30, 2011, and 2010. The following table reconciles the weighted average shares outstanding used for these computations (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(Amounts in thousands, except per share data)
Basic loss per share:
Net loss applicable to common stock	$	(1,430	)	$	(23,111	)	$	(26,110	)	$	(20,292	)
Average shares of common stock outstanding (1)		36,110			35,918			36,093			35,888

Basic loss per share	$	(0.04	)	$	(0.64	)	$	(0.72	)	$	(0.57	)

Diluted loss per share:
Net loss applicable to common stock	$	(1,430	)	$	(23,111	)	$	(26,110	)	$	(20,292	)
Dividends on convertible preferred stock (2)		—			—			—			—
Interest and amortization of loan cost on senior convertible notes, net of tax (3)		—			—			—			—

	$	(1,430	)	$	(23,111	)	$	(26,110	)	$	(20,292	)

Average shares of common stock outstanding (1)		36,110			35,918			36,093			35,888
Assumed conversion of convertible preferred stock (2)		—			—			—			—
Assumed conversion of convertible senior notes (3)		—			—			—			—
Stock options and restricted stock (4)		—			—			—			—

Average diluted shares outstanding		36,110			35,918			36,093			35,888

Diluted loss per share	$	(0.04	)	$	(0.64	)	$	(0.72	)	$	(0.57	)

(1)	The 2010 balance does not include 1,624,300 shares of common stock outstanding under the Share Lending Agreement. See Note 6.

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

(3)

Common shares issuable upon assumed conversion of the 2026 Notes and the 2029 Notes amounting to 7,511,157 shares in 2011 and 8,958,394 shares in 2010 and the accrued interest on the 2026 Notes and the 2029 Notes were not included in the computation of diluted loss per share for all periods presented as they would have been anti-dilutive.

(4)

Common shares issuable on assumed conversion of restricted stock and employee stock options for the three and six months ended June 30, 2011 in the amounts of 196,536 and 178,093 shares, respectively, were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive. Common shares issuable on assumed conversion of restricted stock and employee stock options for the three and six months ended June 30, 2010 in the amounts of 74,363 and 89,690 shares, respectively, were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive.

NOTE 5—Income Taxes

We recorded no income tax benefit for the three and six months ended June 30, 2011. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2009 after considering all available positive and negative evidence related to the realization of our deferred tax assets. Our assessment of the realization of our deferred tax assets has not changed and as a result, we continue to maintain a full valuation allowance for our net deferred assets as of June 30, 2011.

As of June 30, 2011, we had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2010. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or prior to the expiration of statute of limitations prior to June 30, 2012.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 6—Stockholders’ Equity

Restricted Stock

During the three months ended June 30, 2011, 2,398 restricted shares vested. These shares had a weighted average grant date value of $24.57 per share. During the six months ended June 30, 2011, 69,713 restricted shares, which had a weighted average grant date value of $21.93 per share, vested.

Share Lending Agreement

In connection with the offering of our 2026 Notes in December 2006, 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. In March 2008, BSC returned 1,497,963 shares of the 3,122,263 originally borrowed shares. The 1,497,963 shares returned to us were recorded as treasury stock and retired. In May 2008, JP Morgan Chase & Co. completed its acquisition of and assumed all counterparty liabilities of BSC.

In conjunction with the partial repurchase of our 2026 Notes in March 2011, the Share Lending Agreement was terminated and JP Morgan Chase & Co. returned the remaining 1,624,300 shares. The shares returned to us were recorded as treasury shares and retired in March 2011. The shares were 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 had no impact on the earnings per share calculation.

NOTE 7—Derivative Activities

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

The following table summarizes the realized and unrealized gains and losses we recognized on our oil and natural gas derivatives for the three and six month periods ended June 30, 2011 and 2010.


	Three Months Ended June 30,					Six Months Ended June 30,
Oil and Natural Gas Derivatives (in thousands)	2011		2010			2011			2010
Realized gain on oil and natural gas derivatives	$	5,964	$	7,686		$	13,112		$	9,329
Unrealized gain (loss) on oil and natural gas derivatives		4,990		(7,364	)		(12,168	)		25,742

Total gain on oil and natural gas derivatives	$	10,954	$	322		$	944		$	35,071

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 derivatives are in effect. As of June 30, 2011, the commodity derivatives we used were in the form of:

(a)

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

(b)

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

(c)

swaption, where we granted the counter party the right but not the obligation to enter into an underlying swap by a specific date.

During the second quarter of 2011, we did not enter into any new derivative contracts. After June 30, 2011 we entered into a 500 Bbl/day NYMEX swap contract with a strike price of $101.50 per Bbl. The contract term begins on August 1, 2011 and ends on January 31, 2013.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

As of June 30, 2011, our open forward positions on our outstanding commodity derivative contracts, all of which were with BNP Paribas, Bank of Montreal and Royal Bank of Canada, were as follows:


Collars (NYMEX)	Daily Volume		Total Volume		Average Floor/Cap		Fair Value at June 30, 2011 (in thousands)
Natural gas (MMBtu)							$	29,440
3Q 2011		40,000		3,680,000	$	6.00 –$7.09
4Q 2011		40,000		3,680,000	$	6.00 –$7.09
1Q 2012		40,000		3,640,000	$	6.00 –$7.09
2Q 2012		40,000		3,640,000	$	6.00 –$7.09
3Q 2012		40,000		3,680,000	$	6.00 –$7.09
4Q 2012		40,000		3,680,000	$	6.00 –$7.09

					Fixed Price
Oil Swaps (BBL)								1,176
3Q 2011		1,000		92,000	$	100 – $112
4Q 2011		1,000		92,000	$	100 – $112
Oil Swaptions (BBL)								(6,952	)
2012		1,000		366,000	$	100 – $112
2013		1,000		365,000	$	100 – $112

						Total	$	23,664

The fair value of our natural gas derivative contracts in place at June 30, 2011, resulted in a current asset of $20.8 million, a non-current asset of $8.6 million, a current liability of $0.1 million and a non-current liability of $5.7 million. We measure the fair value of our commodity derivatives contracts by applying the income approach, and these contracts are classified within Level 2 of the valuation hierarchy. See Note 8.

NOTE 8—Fair Value

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

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

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

•

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

•

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

•

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

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

As of June 30, 2011, the carrying amounts of our cash and cash equivalents, restricted cash, trade receivables and payables represented fair value because of the short-term nature of these instruments.

We periodically assess our long-lived assets recorded in oil and gas properties on the Consolidated Balance Sheets to ensure that they are not carried in excess of fair value, which is computed using Level 3 inputs such as discounted cash flow models or valuations, based on estimated future commodity prices and our various operational assumptions.

The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value in our Consolidated Balance Sheet by applying the income approach and are classified in Level 2 as of June 30, 2011 (in thousands):


	June 30, 2011 Fair Value Measurements
Description	Level 1		Level 2			Level 3		Total
Current Assets
Commodity Derivatives	$	—	$	20,835		$	—	$	20.835
Non-current Assets
Commodity Derivatives		—		8,605			—		8,605
Current Liabilities
Commodity Derivatives		—		(92	)		—		(92	)
Non-current Liability
Commodity Derivatives		—		(5,684	)		—		(5,684	)

Total	$	—	$	23,664		$	—	$	23,664

The following table reflects the carrying value, as recorded in our Consolidated Balance Sheet, and fair value of our debt financial instruments which we classified as Level 2 at June 30, 2011 (in thousands):


	June 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Senior Credit Facility	$	22,500	$	22,500	$	—	$	—
3.25% Convertible Senior Notes due 2026		26,022		26,435		167,089		173,478
5.0% Convertible Senior Notes due 2029		183,560		212,426		179,168		212,164
8.875% Senior Notes due 2019		275,000		275,688		—		—

Total debt	$	507,082	$	537,049	$	346,257	$	385,642

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

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 9—Commitments and Contingencies

Hoover Tree Farm, LLC v. Goodrich Petroleum Company, LLC et al. On April 29, 2010, a state court in Caddo Parish, Louisiana, granted a judgment holding us solely responsible for the payment of $8.5 million in additional oil and gas lease bonus payments and related interest in an ongoing lawsuit involving the interpretation of a unique oil and gas lease provision. The lease provided for the payment of additional bonuses under certain circumstances in the event higher lease bonuses were paid by us, our successors or assigns, within the surrounding area. Without our knowledge, one of the sub-lessees subject to the same lease paid substantially higher bonuses in the area. We believe that this ruling was improperly decided and, on July 8, 2010, filed a motion for suspensive appeal. We satisfied the requirements for posting a suspensive appeal bond by depositing $8.5 million in July 2010 with Iberia Bank in Shreveport, Louisiana for the account of the Clerk of Caddo Parish Court.

On July 9, 2010, the sub-lessee agreed to reimburse us for one half of any sums for which we may be cast in judgment in this lawsuit in any final non-appealable judgment, and further agreed to reimburse us for one half of the cash bond. We reduced our accrual by $4.2 million in the third quarter of 2010.

On March 23, 2011, the State of Louisiana Second Circuit Court of Appeals issued an opinion which affirmed the trial court’s judgment against the Company and amended the judgment to make both the Company and the sub-lessee responsible for the money judgment. On June 10, 2011, the Company filed an application for writ of certiorari with the Supreme Court of Louisiana.

NOTE 10—Acquisitions and Divestitures

On December 30, 2010, we sold the shallow rights in certain of our non-core properties located in Northwest Louisiana and East Texas for approximately $65 million with an effective date of July 1, 2010. We have retained all of the deep drilling rights on these divested properties, including the rights to both the Haynesville Shale and Bossier Shale formations. We issued our final settlement statement in the current quarter resulting in a gain of less than $0.1 million.

In January 2011, we sold other non-core assets for which we recorded a $0.2 million gain.

In June 2011, we acquired approximately 79,000 acres in leases in the Tuscaloosa Marine Shale, an oil-rich formation that straddles the middle of Louisiana and part of southern Mississippi. We paid approximately $13 million in cash for the acreage.

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

We have made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with Company management, 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 concerning our operations, economic performance and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements accompanied by or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “predicts,” “target,” “goal,” “plans,” “objective,” “potential,” “should,” or similar expressions or variations on such expressions that convey the uncertainty of future events or outcomes. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made; we undertake no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise.

These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risk and uncertainties:

•

planned capital expenditures;

•

future drilling activity;

•

our financial condition;

•

business strategy, including our ability to successfully transition to more liquids-focused operations;

•

the market prices of oil and natural gas;

•

uncertainties about the estimated quantities of oil and natural gas reserves;

•

financial market conditions and availability of capital;

•

production;

•

hedging arrangements;

•

future cash flows and borrowings;

•

litigation matters;

•

pursuit of potential future acquisition opportunities;

•

sources of funding for exploration and development;

•

general economic conditions, either nationally or in the jurisdictions in which we or our subsidiary are doing business;

•

legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, drilling and permitting regulations, derivatives reform, changes in state and federal corporate taxes, environmental regulation, environmental risks and liability under federal, state and foreign and local environmental laws and regulations;

•

the creditworthiness of our financial counterparties and operation partners;

•

the securities, capital or credit markets;

•

our ability to repay our debt; and

•

other factors discussed below and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2010, and in our other public filings, press releases and discussions with management.

Overview

We are an independent oil and gas company engaged in the exploration, development and production of oil and natural gas properties primarily in Northwest Louisiana and East Texas, which includes the Haynesville Shale and Cotton Valley trends and South Texas, which includes the Eagle Ford Shale trend.

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

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

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

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

Business Strategy

Our business strategy is to provide long term growth in reserves and cash flow on a cost-effective basis. We focus on adding reserve value through the development of our large, relatively low risk Haynesville Shale, Eagle Ford Shale and Cotton Valley trend acreage. Our current expectations are that we will commence exploration activities on our recently acquired Tuscaloosa Marine Shale acreage in 2012. We regularly evaluate possible acquisitions of prospective acreage and oil and gas drilling opportunities.

Several of the key elements of our business strategy are the following:

•

Develop existing property base. We seek to maximize the value of our existing assets by developing and exploiting our properties with the lowest risk and the highest potential rate of return. We intend to concentrate on developing our multi-year inventory of drilling locations on our acreage in the Eagle Ford Shale, Haynesville Shale and Cotton Valley Taylor Sand trend. We estimate that our Eagle Ford Shale acreage currently includes approximately 385 net unrisked drilling locations on 100 acre spacing. Our Haynesville Shale acreage currently includes approximately 1,000 net unrisked drilling locations based on anticipated well spacing of 80 acres, and our Cotton Valley Taylor Sand horizontal inventory includes approximately 189 net unrisked drilling locations based on anticipated well spacing of 160 acres.

•

Increase our oil production. During the past year, we have concentrated on increasing our crude oil production, cash flow and reserves by investing and drilling in the Eagle Ford Shale. We intend to take advantage of the more favorable sales price of oil compared to the relative sales price of natural gas.

•

Expand acreage position in shale plays. We recently acquired approximately 79,000 net acres in the Tuscaloosa Marine Shale trend in Southeastern Louisiana and Southwestern Mississippi. We continue to concentrate our efforts in areas where we can apply our technical expertise and where we have significant operational control or experience. To leverage our extensive regional knowledge base, we seek to acquire leasehold acreage with significant drilling potential in areas that exhibit similar characteristics to our existing properties. We continually strive to rationalize our portfolio of properties by selling marginal properties in an effort to redeploy capital to exploitation, development and exploration projects that offer a potentially higher overall return.

•

Focus on maximizing cash flow margins. We intend to maximize cash flow margins by focusing on higher-margin oil development in the Eagle Ford Shale trend in South Texas and the Cotton Valley Taylor Sand trend in our South Henderson field in Rusk County, Texas. In the current commodity price environment, our Eagle Ford Shale assets offer more attractive cash flow margins than our natural gas assets. From the second quarter 2010 to the second quarter of 2011, we lowered our lease operating costs on a consolidated basis from $0.76 per Mcfe to $0.51 per Mcfe by focusing on lower cost Haynesville Shale potential and divesting higher cost mature assets. We expect this trend to continue as it relates to our natural gas properties.

•

Maintain financial flexibility. As of June 30, 2011, we had a borrowing base of $225 million under our Senior Credit Facility, of which $22.5 million was outstanding. We have historically funded growth through cash flow from operations, equity and equity-linked security issuances, debt security issuances, divestments of non-core assets and strategic joint ventures. We actively manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, typically fixed price swaps and costless collars. The level of our hedging activity and the duration of the instruments employed depend upon our view of market conditions, available hedge prices and our operating strategy.

Primary Operating Areas

Eagle Ford Shale

During the second half of 2010, we commenced drilling operations on our acreage in the Eagle Ford Shale trend. Our leasehold position is located in both La Salle and Frio counties, Texas. During the first six months of 2011, we conducted drilling operations on approximately 16 gross (11 net) operated Eagle Ford Shale trend wells. During the second half of 2011, the Company plans to conduct drilling operations on approximately 8-11 gross Eagle Ford Shale/Buda Lime formation wells on its properties in South Texas.

Haynesville Shale

Our relatively low risk development drilling program in the Haynesville Shale trend is primarily centered in and around Angelina and Nacogdoches counties, Texas and DeSoto and Caddo parishes, Louisiana. We continue to build our acreage position in this trend and hold approximately 88,000 net acres producing from and prospective for the Haynesville Shale as of June 30, 2011. As of June 30, 2011, we conducted drilling operations on 10 gross wells in the trend with a 100% success rate. Haynesville Shale wells produced net volumes of approximately 74,082 Mcfe per day in the second quarter of 2011, or approximately 65.5% of our total oil and gas production for the quarter ended June 30, 2011.

Core Haynesville Shale

Our core Haynesville Shale drilling program is primarily concentrated in the Bethany-Longstreet and Greenwood-Waskom fields in Caddo and DeSoto Parishes in northwest Louisiana. Our core Haynesville Shale drilling activity includes both operated and non-operated drilling in and around our core acreage positions in northwest Louisiana. We continue to build our acreage position in the trend and hold approximately 33,000 gross (16,000 net) acres as of June 30, 2011. Our net production volumes from our core Haynesville Shale wells totaled approximately 55,393 Mcfe per day in the first half of 2011, or approximately 49% of our total production for the quarter ended June 30, 2011.

Shelby Trough / Angelina River Trend

Our properties in the Shelby Trough/Angelina River trend, where we are the operator of the vast majority of our drilling activities, are primarily located in Nacogdoches, Angelina and Shelby counties in East Texas. We currently hold approximately 36,000 gross (28,000 net) acres as of June 30, 2011. Our net production volumes from our Shelby Trough wells totaled approximately 12,934 Mcfe per day in the second quarter of 2011, or approximately 11.5% of our total production for the second quarter of 2011. During the second half of 2011, the Company plans to conduct drilling operations on one well in the Shellby Trough/Angelina River Trend area.

Cotton Valley Taylor Sand

We have conducted drilling and completion operations on three horizontal Cotton Valley Taylor Sand wells on our acreage position in the South Henderson field of East Texas. The three wells had an average initial production rate of 10.6 Mmcfe per day and 300 barrels of oil per day. We have approximately 8,100 net acres prospective for the Cotton Valley Taylor Sand in the South Henderson field. Net production volumes from our Cotton Valley Taylor Sand wells companywide totaled approximately 12,998 Mcfe per day in the second quarter of 2011, or approximately 11.5% of our total oil and gas production for the quarter ended June 30, 2011. During the second half of 2011, the Company plans to conduct completion operations on two gross Cotton Valley Taylor Sand wells in the South Henderson field.

Overview of Second Quarter 2011 Results

Second Quarter 2011 financial and operating results include:

•

We increased our average oil and gas production volumes to 113,268 Mcfe per day for the second quarter of 2011, representing an increase of 23% from 92,015 Mcfe per day for the second quarter of 2010.

•

We conducted drilling operations on 18 gross (10 net) wells in the second quarter of 2011, including four in the Haynesville Shale and 11 in South Texas. We added 15 gross (seven net) wells to production in the second quarter of 2011. As of June 30, 2011, we had 10 gross (five net) wells drilled, but not completed.

•

We acquired approximately 79,000 net acres in the Tuscaloosa Marine Shale.

•

We quadrupled our oil production in the quarter from the prior period, which currently represents 8% of our total production compared to 2% of our total production in the second quarter of 2010.

•

We reduced our lease operating expense per Mcfe by 33% in the second quarter of 2010 to $0.51 per Mcfe in the second quarter of 2011.

Results of Operations

For the three months ended June 30, 2011, we reported a net loss applicable to common stock of $1.4 million, or $0.04 per basic and diluted share, on total revenue of $52.9 million as compared to a net loss applicable to common stock of $23.1 million, or $0.64 per basic and diluted share, on total revenue of $34.2 million for the three months ended June 30, 2010. The increase in production volumes contributed $9.9 million to the $18.4 million increase in oil and gas revenues and the increase average realized prices contributed $8.5 million as compared to the three months ended June 30, 2010. We recorded an $11.0 million gain on derivatives not designated as hedges in the three months ended June 30, 2011 compared to a $0.3 million gain on derivatives not designated as hedges for the three months ended June 30, 2010.

For the six months ended June 30, 2011, we reported a net loss applicable to common stock of $26.1 million, or $0.72 per basic and diluted share, on total revenue of $94.1 million as compared to a net loss applicable to common stock of $20.3 million, or $0.57 per basic and diluted share, on total revenue of $74.6 million for the six months ended June 30, 2010. The increase in production volumes contributed $14.6 million to the $18.9 million increase in oil and gas revenues and the increase in average realized prices contributed $4.3 million as compared to the six months ended June 30, 2010. We recorded a $0.9 million gain on derivatives not designated as hedges in the six months ended June 30, 2011 compared to a $35.0 million gain on derivatives not designated as hedges for the six months ended June 30, 2010. The reduced derivative gain between periods was the primary driver behind the decrease in net income and was due to the increase in futures oil prices.

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.

Summary Operating Information:


(In thousands, except for price data)	Three Months Ended June 30,									Six Months Ended June 30,
(In thousands, except for price data)	2011		2010			Variance				2011			2010			Variance
Revenues:
Natural gas	$	39,347	$	31,772		$	7,575	24	%	$	72,990		$	69,690		$	3,300		5	%
Oil and condensate		13,087		2,279			10,808	474	%		20,362			4,787			15,575		325	%
Natural gas, oil and condensate		52,434		34,051			18,383	54	%		93,352			74,477			18,875		25	%
Operating revenues		52,871		34,162			18,709	55	%		94,102			74,617			19,485		26	%
Operating expenses		50,791		46,939			3,852	8	%		94,419			108,725			(14,306	)	(13	%)
Operating income (loss)		2,080		(12,777	)		14,857	116	%		(317	)		(34,108	)		33,791		99	%
Natural gas (MMcf)		9,501		8,187			1,314	16	%		18,094			15,967			2,127		13	%
Oil and condensate (MBbls)		134		31			103	332	%		215			64			151		236	%
Total (Mmcfe)		10,307		8,373			1,934	23	%		19,382			16,351			3,031		19	%
Average daily production (Mcfe/d)		113,268		92,015			21,253	23	%		107,085			90,340			16,745		19	%
Average realized sales price per unit:
Natural gas (per Mcf)	$	4.14	$	3.88		$	0.26	7	%	$	4.03		$	4.36		$	(0.33	)	(8	%)
Oil and condensate (per Bbl)		97.36		73.21			24.15	33	%		94.85			74.66			20.19		27	%
Total (per Mcfe)		5.09		4.07			1.02	25	%		4.82			4.55			0.27		6	%

Revenues from operations increased for the three months ended June 30, 2011 compared to the same period in 2010 as a result of a 23% increase in production coupled with a 25% increase in average realized sales price. Revenues from operations increased for the six months ended June 30, 2011 compared to the same period in 2010 as a result of a 19% increase in production and a 6% increase in average realized sales price. The production increase in the three and six month periods ended June 30, 2011 over the same period in 2010 is due to the increase in the oil production volumes obtained from our Eagle Ford Shale wells. Production also increased as a result of increased gas production in our Haynesville Shale properties partially offset by non-core properties sold in December 2010. For the three months ended 2010, 7% of our oil and gas revenue was attributable to oil sales whereas for the three months ended June 30, 2011 oil sales contributed 25% to our oil and gas revenues.

For the three months ended June 30, 2011, our average realized price for natural gas was $4.14 per Mcf, excluding the effect of the realized gains and losses on our natural gas derivatives. For the same period in 2010, our average realized price for natural gas was $3.88 per Mcf, excluding the effect of the realized gains and losses on our natural gas derivatives. For the three months ended June 30, 2011, our average realized price for natural gas was $4.77 per Mcf, including the effect of the realized gains and losses on our natural gas derivatives. For the same period in 2010, our average realized price for natural gas was $4.82 per Mcf, including the effect of the realized gains and losses on our natural gas derivatives.

For the six months ended June 30, 2011, our average realized price for natural gas was $4.03 per Mcf, excluding the effect of the realized gains and losses on our natural gas derivatives. For the same period in 2010, our average realized price for natural gas was $4.36 per Mcf, excluding the effect of the realized gains and losses on our natural gas derivatives. For the six months ended June 30, 2011, our average realized price for natural gas was $4.74 per Mcf, including the effect of the realized gains and losses on our natural gas derivatives. For the same period in 2010, our average realized price for natural gas was $4.95 per Mcf, including the effect of the realized gains and losses on our natural gas derivatives.

The difference between our realized prices inclusive of the hedge realizations in the 2011 and 2010 periods relates to the floor price on our collars. As of June 30, 2011, we had 40,000 MMBtu per day hedged at a floor price of $6.00 per MMBtu and in 2010, we had 50,000 MMBtu per day hedged at an average floor price of $6.00 per MMbtu.

Operating Expenses

The following tables present our comparative operating expenses:


	Three Months Ended June 30,									Six Months Ended June 30,
Operating Expenses (in thousands)	2011		2010		Variance					2011		2010		Variance
Lease operating expenses	$	5,215	$	6,329	$	(1,114	)	(18	%)	$	10,118	$	13,561	$	(3,443	)	(25	%)
Production and other taxes		1,645		390		1,255		322	%		2,595		1,353		1,242		92	%
Transportation		2,301		2,189		112		5	%		4,687		4,642		45		1	%
Exploration		2,325		2,627		(302	)	(11	%)		4,741		5,606		(865	)	(15	%)

	Three Months Ended June 30,									Six Months Ended June 30,
Operating Expenses per Mcfe	2011		2010		Variance					2011		2010		Variance
Lease operating expenses	$	0.51	$	0.76	$	(0.25	)	(33	%)	$	0.52	$	0.83	$	(0.31	)	(37	%)
Production and other taxes		0.16		0.05		0.11		220	%		0.13		0.08		0.05		63	%
Transportation		0.22		0.26		(0.04	)	(15	%)		0.24		0.28		(0.04	)	(14	%)
Exploration		0.23		0.31		(0.08	)	(26	%)		0.24		0.34		(0.10	)	(29	%)

Lease Operating. Lease operating expense (“LOE”) for the three months ended June 30, 2011, decreased in comparison to the same period in 2010 as a result of our sale in December 2010 of our high cost non-core gas properties and a greater percentage of our production volumes coming from our Haynesville Shale wells which carry a lower LOE per unit of production. On a per unit basis, LOE decreased for the three months ended June 30, 2011 compared to the same period in 2010 as a result of the sale of higher cost properties sold in December 2010, a 23% increase in production volumes and an increasing portion of our production coming from the lower production cost Haynesville Shale wells.

LOE for the six months ended June 30, 2011, decreased in comparison to the same period in 2010 as a result of our sale in December 2010 of our high cost non-core gas properties and a greater percentage of our production volumes coming from our Haynesville Shale wells which carry a lower LOE per unit of production. On a per unit basis, LOE decreased for the six months ended June 30, 2011 compared to the same period in 2010 as a result of the sale of higher cost properties sold in December 2010, a 19% increase in daily production volumes and an increasing portion of our production coming from our lower production cost Haynesville Shale wells.

Production and Other Taxes. Production and other taxes for the three months ended June 30, 2011 includes ad valorem tax of $0.7 million and $0.9 million in production tax. The production tax represents $1.3 million current period expense reduced by $0.4 million in Texas high cost severance tax credits. During the comparable period in 2010, production and other taxes for the three months ended June 30, 2010 was $0.4 million which includes ad valorem tax of $0.5 million reduced by a $0.1 million production tax credit. The production tax represents $0.6 million for the three month period expense reduced by $0.7 million in Tight Gas Sands (“TGS”) tax credits.

Production and other taxes for the six months ended June 30, 2011 includes ad valorem tax of $1.3 million and $1.3 million in production tax. The production tax represents $2.2 million current period expense reduced by $0.9 million in Texas high cost severance tax credits. During the comparable period in 2010, production and other taxes for the six months ended June 30, 2010 was $1.3 million which includes ad valorem tax of $0.9 million and production tax of $0.4 million. The production tax represents $1.6 million for the six month period expense reduced by $1.2 million of new TGS tax credits for our wells in the State of Texas and for our horizontally drilled wells in Louisiana.

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

Our Louisiana horizontal wells are eligible for a two year severance tax exemption from the date of first production or until payout of qualified costs, whichever comes first. During the third quarter of 2011 our exempt Louisiana wells will begin reaching the two year maturity.

Transportation. Transportation expense in the three months ended June 30, 2011 increased as compared to the three months ended June 30, 2010 as a result of expenses generated by our new production in the Angelina River and Eagle Ford Shale trends partially offset by the sale of our non-core properties in December 2010. Transportation expense in the six months ended June 30, 2011 increased as compared to the six months ended June 30, 2010 as a result of expenses generated by our new production in the Angelina River and Eagle Ford Shale trends partially offset by the sale of our non-core properties in December 2010.

Exploration. Exploration expense for the three months ended June 30, 2011 decreased from that in the same period in 2010. We recorded lower undeveloped leasehold cost amortization offset by slightly higher seismic cost in the current period. Exploration expense for the six months ended June 30, 2011 decreased from that in the same period in 2010. We recorded lower undeveloped leasehold cost amortization in addition to incurring lower seismic cost in the current period.


	Three Months Ended June 30,									Six Months Ended June 30,
Operating Expenses (in thousands)	2011		2010		Variance					2011		2010		Variance
Depreciation, depletion and amortization	$	30,927	$	28,403	$	2,524		9	%	$	55,886	$	58,616	$	(2,730	)	(5	%)
Impairment		1,050		—		1,050		100	%		1,050		—		1,050		100	%
General and administrative		7,328		7,001		327		5	%		15,578		16,447		(869	)	(5	%)

	Three Months Ended June 30,									Six Months Ended June 30,
Operating Expenses per Mcfe	2011		2010		Variance					2011		2010		Variance
Depreciation, depletion and amortization	$	3.00	$	3.39	$	(0.39	)	(12	%)	$	2.88	$	3.58	$	(0.70	)	(20	%)
Impairment		0.10		—		0.10		100	%		0.05		—		0.05		100	%
General and administrative		0.71		0.84		(0.13	)	(15	%)		0.80		1.01		(0.21	)	(21	%)

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) increased for the three month comparative second quarter principally due to 23% higher volumes in second quarter of 2011 and decreased for the six month comparative period due to lower depletion rates at certain fields resulting from our semi-annual rate revision process applied to higher volumes in 2011. The impairment of our oil and gas properties recorded in the third quarter of 2010 and the sale of our non-core properties in December 2010 partially offset by the cost of newly drilled wells reduced our overall DD&A rate. We calculated the first half of 2011 and 2010 DD&A rates using the December 31, 2010 and December 31, 2009 reserves, respectively. Proved developed reserves increased 10.3% from 420.6 Bcfe at December 31, 2009 to 463.9 Bcfe at December 31, 2010.

Impairment. We recorded impairment expense of $1.0 million on a single field in the three and six months ended June 30, 2011, related to an increase in asset retirement obligation for a field that is no longer producing.

General and Administrative. G&A expense increased in the three months ended June 30, 2011, compared to the same period in 2010. The increase relates to generally higher labor costs including employee medical benefits. G&A expense on a per unit basis decreased as a result of a 23% increase in our daily production volumes in the second quarter of 2011 as compared to the second quarter of 2010. Stock based compensation expense, which is a non-cash item, decreased to $1.3 million in the second quarter of 2011 from $1.5 million in 2010.

General and administrative (“G&A”) expense decreased in the six months ended June 30, 2011, compared to the same period in 2010. The decrease relates primarily to decreases in stock based compensation and consulting cost. The six months ended June 30, 2010 included the cost of a consulting agreement related to the resignation of an executive officer. G&A expense on a per unit basis decreased as a result of a 19% increase in our daily production volumes in the first half of 2011 as compared to the first half of 2010. Stock based compensation expense, which is a non-cash item, decreased to $3.2 million in the six months ended June 30, 2011 from $4.0 million in 2010.


	Six Months Ended June 30,
Operating Expenses (in thousands)	2011			2010		Variance
Gain on sale of assets		(236	)		—		(236	)	100	%
Other		—			8,500		(8,500	)	(100	%)

	Six Months Ended June 30,
Operating Expenses per Mcfe	2011			2010		Variance
Gain on sale of assets		(0.01	)		—		(0.01	)	100	%
Other		—			0.52		(0.52	)	(100	%)

Gain on sale of assets. We recorded a gain of $0.2 million on the sale on non-core oil and gas properties in the first quarter of 2011.

Other. In the first quarter of 2010, we accrued the full amount of $8.5 million as a reserve for litigation as relating to the lawsuit with a lessee, Hoover Tree Farm LLC vs. Goodrich Petroleum Company LLC filed in Caddo Parish Louisiana as described in Note 9-Commitments and Contingencies to our consolidated financial statements contained in this report.

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,
	2011			2010			2011			2010
Other income (expense):
Interest expense	$	(12,965	)	$	(9,195	)	$	(23,793	)	$	(18,315	)
Interest income and other		10			53			22			106
Gain (loss) on derivatives not designated as hedges		10,954			320			944			35,049
Average funded borrowings		531,867			393,500			489,347			393,500
Average funded borrowings adjusted for debt discount		494,670			335,487			448,761			333,512
Weighted average interest rate		10.5	%		10.3	%		10.7	%		10.4	%

Interest Expense. Interest expense in the three and six months ended June 30, 2011, increased compared to the three and six months ended June 30, 2010, as a result of the higher average level of outstanding debt in the three and six months ended June 30, 2011. The higher average level of debt in the three and six month periods ended June 30, 2011 resulted from the issuance of our $275 million 8.875% senior notes in March 2011. Non-cash interest of $3.6 million is included in the $13.0 million interest expense reported for the three months ended June 30, 2011. Non-cash interest of $8.2 million is included in the $23.8 million interest expense reported for the six months ended June 30, 2011.

Gain on Derivatives Not Designated as Hedges. Gain on derivatives not designated as hedges for the three months ended June 30, 2011, consists of a realized gain of $6.0 million and an unrealized gain of $5.0 million for the change in fair value of our oil and natural gas derivative contracts. The average futures strip prices for oil and natural gas were lower in the current period compared to the previous quarter resulting in an unrealized gain in the current period. As a comparison, gain on derivatives not designated as hedges for the three months ended June 30, 2010, included a realized gain of $7.7 million and an unrealized loss of $7.4 million for the changes in fair value of our natural gas derivative contracts.

Gain on derivatives not designated as hedges for the six months ended June 30, 2011, consists of a realized gain of $13.1 million offset by an unrealized loss of $12.2 million for the change in fair value of our oil and natural gas derivative contracts. The average futures strip prices for oil and natural gas were higher in the current period compared to year end 2010 resulting in an unrealized loss

in the current period. As a comparison, gain on derivatives not designated as hedges for the six months ended June 30, 2010, included a realized gain of $9.3 million and an unrealized gain of $25.8 million for the changes in fair value of our natural gas derivative contracts.

We will continue to be exposed to volatility in earnings resulting from changes in the fair value of our commodity contracts as we do not designate these contracts as hedges.

Income taxes. We recorded no income tax benefit for the three and six months ended June 30, 2011. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2010 after considering all available positive and negative evidence related to the realization of our deferred tax assets. Our assessment of the realization of our deferred tax assets has not changed and as a result, we continue to maintain a full valuation allowance for our net deferred asset as of June 30, 2011.

Liquidity and Capital Resources

Our primary sources of funding during the first six months of 2011 were from cash on hand, cash flow from operating activities, availability from our Senior Credit Facility and issuance of the 2019 Notes. We used cash primarily to fund our capital spending program, retire debt and pay preferred stock dividends. Our primary sources of cash during the first six months of 2010 were cash flow from operating activities and proceeds from the sale of assets. We used cash primarily to fund our capital spending program, and pay preferred stock dividends. We expect to finance our estimated capital expenditures for the remainder of 2011 through a combination of cash on hand, cash from operating activities and availability under our Senior Credit Facility.

The 2011 capital expenditure budget is being increased 34% to $315 million, up from $235 million to reflect a 35% increase in the number of net wells drilled during the year, an increased leasehold acquisition budget for the Tuscaloosa Marine Shale and completion cost inflation. Of the 35% increase in number of net wells drilled for the year, 79% is associated with non-operated properties.

We have in place a $600 million Senior Credit Facility, which we entered into with a syndicate of United States and International lenders, and as of June 30, 2011, we had a $225 million borrowing base with $22.5 million outstanding borrowings. On February 25, 2011, we entered into a Fourth Amendment to the Senior Credit Facility. The Fourth Amendment became effective upon the closing of the issuance and sale of our 2019 Notes, which occurred on March 2, 2011, and the placement of $175 million of net proceeds in an escrow account to be used for the redemption or earlier repurchase of all of our outstanding 2026 Notes. As of June 30, 2011, we were in compliance with existing covenants, as amended, and $202.5 million of the borrowing base of our Senior Credit Facility was available for borrowing.

We continuously monitor our leverage position and coordinate our capital program with our expected cash flows and repayment of our projected debt. We will continue to evaluate funding alternatives as needed.

Funding alternatives available to us include:

•

sale of non-core assets,

•

bring in joint venture partners in core Haynesville and/or Eagle Ford Shale acreage,

•

availability under our Senior Credit Facility, and

•

issuance of debt or equity securities.

Our Senior Credit Facility matures on July 31, 2014. In addition, holders of our remaining 2026 Notes have the right to require us to purchase some or all of such notes at par on December 1, 2011. Because the conversion price of those notes is substantially above the recent trading price of our common stock, we expect that it is more likely than not that some or all of these 2026 Notes will be put to us for repurchase on such date. Under the terms of our Senior Credit Facility, we have $26.6 million remaining in escrow related to the remaining outstanding 2026 Notes. We intend to use these escrowed funds to redeem all of the remaining outstanding 2026 Notes on or before December 1, 2011. As of June 30, 2011, we have classified the remaining 2026 Notes of $26.6 million as a current liability.

We also have supported our cash flows by entering into derivative positions as of June 30, 2011, covering approximately 37% of our projected natural gas and oil sales volumes for the remainder of 2011 and 2012. See Note 7-Derivative Activities in the Notes to Consolidated Financial Statements under Part 1 Item 1 of this Form 10-Q.

Cash Flows

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


	Six months ended June 30,
	2011			2010			Variance
Cash flow statement information:
Net cash:
Provided by operating activities	$	67,921		$	47,653		$	(20,268	)
Used in investing activities		(193,336	)		(112,391	)		(80,945	)
Provided by (used in) financing activities		108,174			(3,906	)		112,080

Decrease in cash and cash equivalents	$	(17,241	)	$	(68,644	)	$	51,403

Operating activities. Net cash provided by operating activities increased $20.3 million to $67.9 million for the six months ended June 30, 2011, from $47.7 million for the comparable 2010 period as more cash was realized from derivative settlements and production levels during the current six month period increased compared to 2010.

Investing activities. Net cash used in investing activities was $193.3 million for the six months ended June 30, 2011. We drilled 31 gross wells including 10 wells in the Haynesville Shale and 16 wells in the Eagle Ford Shale in the first six months of 2011. In comparison, we conducted drilling operations on 28 gross wells, 25 of these wells penetrated the Haynesville Shale during the first six months of 2010. The increase in the investing amount between the six month periods reflects more wells drilled in 2011 and higher completion costs. The $193.3 million used in investing activities consists of $193.5 million related to capital expenditures offset by $0.2 million from the sale of non-core assets. Of the $193.5 million capital expenditures spent in the six months ended June 30, 2011, approximately $170.7 million was for drilling and completion activities, $18 million was for leasehold acquisition, $4.1 million was for facilities and infrastructure, $0.3 million was for capital workovers and $0.4 million was for furniture, fixtures and equipment.

Financing activities. Net cash provided by financing activities was $108.2 million for the six months ended June 30, 2011, compared to cash used in financing activities of $3.9 million for the same period in 2010. The net cash provided by financing activities for the current period consisted of proceeds from the issuance our 2019 Notes partially offset by the redemption of a portion of our 2026 Notes, cash restricted for the repurchase of convertible notes, financing cost on the issuance of 2026 Notes and preferred stock dividend.

Senior Credit Facility

On May 5, 2009, we entered into the Senior Credit Facility that replaced our previous facility. On February 25, 2011, we entered into a Fourth Amendment to the Senior Credit Facility. Included among the conditions required for the Fourth Amendment to become effective were (i) the closing of the issuance and sale of our 2019 Notes, and (ii) the placement of not less than $175 million of net proceeds from the sale of the 2019 Notes in an escrow account with the lenders to be used for the redemption or earlier repurchase of all our outstanding 2026 Notes, both of which occurred on March 2, 2011.

Total lender commitments under the Senior Credit Facility are $600 million subject to current borrowing base limitations of $225 million. Our Senior Credit Facility matures on July 1, 2014 (subject to automatic extension to February 25, 2016, if, prior to maturity, we prepay, or escrow certain proceeds sufficient to prepay, our $218.5 million 2029 Notes). Revolving borrowings under our Senior Credit Facility are limited to, and subject to periodic redeterminations of, the borrowing base. Interest on revolving borrowings under our Senior Credit Facility accrues at a rate calculated, at our option, at the bank base rate plus 1.00% to 1.75%, or LIBOR plus 2.00% to 2.75%, depending on borrowing base utilization. Pursuant to the terms of our Senior Credit Facility, borrowing base redeterminations occur on a semi-annual basis on April 1 and October 1. As of June 30, 2011, we had $22.5 million outstanding under our Senior Credit Facility. Substantially all our assets are pledged as collateral to secure the Senior Credit Facility.

•

Current Ratio of 1.0/1.0;

•

Total Debt no greater than 4.0 times EBITDAX for the trailing four quarters, Total Debt used in such ratio to be reduced by the amount of any restricted cash held in an escrow account established for the benefit of the lenders and dedicated to the redemption or prepayment of the 2026 Notes, the 2029 Notes or the 2019 Notes; provided that such ratios, when measured for the first three quarters of 2011, shall be based on annualized 2011 interim EBITDAX amounts rather than trailing four quarters.

As defined in the credit agreement, EBITDAX is earnings before interest expense, income tax, DD&A, exploration expense and impairment of oil and gas properties. In calculating EBITDAX for this purpose, earnings include realized gains (losses) from derivatives but exclude unrealized gains (losses) from derivatives.

We were in compliance with all the financial covenants of the Senior Credit Facility as of June 30, 2011.

8.875% Senior Notes due 2019

On March 2, 2011, we sold $275 million of our 2019 Notes. The 2019 Notes mature on March 15, 2019, unless earlier redeemed or repurchased. The 2019 Notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The 2019 Notes accrue interest at a rate of 8.875% annually, and interest is paid semi-annually in arrears on March 15 and September 15. The notes are guaranteed by our subsidiary that also guarantees our Senior Credit Facility.

The Indenture governing the 2019 Notes restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem or retire such capital stock;

(iii) sell assets, including the capital stock of our restricted subsidiaries; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company. These covenants are subject to a number of important exceptions and qualifications. At any time when the 2019 Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indenture governing the 2019 Notes) has occurred and is continuing, many of these covenants will terminate.

Interest expense recognized relating to the contractual interest rate and amortization of financing cost for the three and six months ended June 30, 2011 was $6.3 million and $8.3 million respectively. The effective interest rate on the liability component of the 2019 Notes was 9.2% for the three and six month periods ended June 30, 2011.

5% Convertible Senior Notes due 2029

The 2029 Notes are convertible into shares of our common stock at a rate equal to 28.8534 shares per $1,000 principal amount of 2029 Notes (equal to an “initial conversion price” of approximately $34.66 per share of common stock). We separately account for the liability and equity components of the 2029 Notes in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. As of June 30, 2011, the $218.5 million aggregate principal amount of 2029 Notes were carried on the balance sheet at $183.6 million with a debt discount balance of $34.9 million. As of December 31, 2010, the $218.5 million aggregate principal amount of 2029 Notes was carried on the balance sheet at $179.2 million with a debt discount of $39.3 million. The debt discount will be amortized using the effective interest rate method based upon an original five year term through October 1, 2014. Interest expense recognized relating to the contractual interest rate and amortization of debt discount and financing cost for the three and six months ended June 30, 2011 was $5.2 million and $10.3 million respectively. The effective interest rate on the liability component of the 2029 Notes were11.4% and 11.5% for the three and six month periods ended June 30, 2011, respectively. The 2029 Notes are guaranteed by our subsidiary that also guarantees our Senior Credit Facility.

3.25% Convertible Senior Notes Due 2026

We intend to redeem all of the remaining outstanding 2026 Notes on or before December 1, 2011. As of June 30, 2011, we have classified the 2026 Notes as a current liability.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which were prepared in accordance with generally accepted accounting principles in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We believe that certain accounting policies affect the 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, 2010, includes a discussion of our critical accounting policies and there have been no material changes to such policies during the six months ended June 30, 2011.

Item 3—Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

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

We enter into futures contracts or other derivative agreements from time to time to manage the commodity price risk for a portion of our production. Our strategy, which is administered by the Hedging Committee of our Board of Directors, and reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and 70% of our production. As of June 30, 2011, the commodity hedges we utilized were in the form of:

(a)

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

(b)

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

(c)

swaptions, where we grant the counterparty the right but not the obligation to enter into a swap agreement by a specific date.

Our hedging contracts fall within our targeted range of 30% to 70% of our estimated net oil and gas production volumes for the applicable periods of 2011. The fair value of the natural gas hedging contracts in place at June 30, 2011, resulted in a net asset of $23.7 million. Based on oil and gas pricing in effect at June 30, 2011, a hypothetical 10% increase in oil and gas prices would have decreased the derivative asset to $90.9 million, while a hypothetical 10% decrease in oil and gas prices would have increased the derivative asset to $111.5 million. See Note 7-Derivative Activities in the Notes to Consolidated Financial Statements under Part 1 of this Form 10-Q.

As of June 30, 2011, our open forward positions on our outstanding commodity derivative contracts, all of which were with BNP Paribas, Royal Bank of Canada or Bank of Montreal, were as follows:


Collars (NYMEX)	Daily Volume		Total Volume		Average Floor/Cap		Fair Value at June 30, 2011 (in thousands)
Natural gas (MMBtu)							$	29,440
3Q 2011		40,000		3,680,000	$	6.00 – $7.09
4Q 2011		40,000		3,680,000	$	6.00 – $7.09
1Q 2012		40,000		3,640,000	$	6.00 – $7.09
2Q 2012		40,000		3,640,000	$	6.00 – $7.09
3Q 2012		40,000		3,680,000	$	6.00 – $7.09
4Q 2012		40,000		3,680,000	$	6.00 – $7.09

					Fixed Price
Oil Swaps (BBL)								1,176
3Q 2011		1,000		92,000	$	100 – $112
4Q 2011		1,000		92,000	$	100 – $112
Oil Swaptions (BBL)								(6,952	)
4Q 2011		1,000		366,000	$	100 – $112
4Q 2011		1,000		365,000	$	100 – $112

						Total	$	23,664

The following table summarizes the realized and unrealized gains and losses we recognized on our oil and natural gas derivatives for the three and six month periods ended June 30, 2011 and 2010.


	Three Months Ended June 30,					Six months Ended June 30,
Oil and Natural Gas Derivatives (in thousands):	2011		2010			2011			2010
Realized gain on natural gas derivatives	$	5,964	$	7,686		$	13,112		$	9,329
Unrealized gain (loss) on natural gas derivatives		4,990		(7,364	)		(12,168	)		25,742

Total gain on oil and natural gas derivatives	$	10,954	$	322		$	944		$	35,071

Adoption of Comprehensive Financial Reform

The recent adoption of comprehensive financial reform legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. See Risk Factors in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

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, 2011, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

No changes in our system of internal control over financial reporting occurred during our last fiscal 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

A discussion of current legal proceedings is set forth in Part I, Item 1. Financial Statements, under “Note 9—Commitments and Contingencies” to our consolidated financial statements in this Form 10-Q.

Item 1A—Risk Factors

There are no material changes from risk factors previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Item 6—Exhibits



*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.

*101.INS		XBRL Instance Document

*101.SCH		XBRL Schema Document

*101.CAL		XBRL Calculation Linkbase Document

*101.DEF		XBRL Definition Linkbase Document

*101.LAB		XBRL Labels Linkbase Document

*101.PRE		XBRL Presentation Linkbase Document

*	Filed herewith

**	Furnished herewith

SIGNATURES

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


	GOODRICH PETROLEUM CORPORATION (Registrant)

Date: August 5, 2011	By:	/S/ WALTER G. GOODRICH
		Walter G. Goodrich
		Vice Chairman & Chief Executive Officer

Date: August 5, 2011	By:	/S/ JAN L. SCHOTT
		Jan L. Schott
		Senior Vice President & Chief Financial Officer

GOODRICH PETROLEUM CORPORATION LIST OF EXHIBITS TO FORM 10-Q

FOR QUARTER ENDED JUNE 30, 2011


*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.

*101.INS		XBRL Instance Document

*101.SCH		XBRL Schema Document

*101.CAL		XBRL Calculation Linkbase Document

*101.DEF		XBRL Definition Linkbase Document

*101.LAB		XBRL Labels Linkbase Document

*101.PRE		XBRL Presentation Linkbase Document

*	Filed herewith

**	Furnished herewith

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company