Edgar Filing: GOODRICH PETROLEUM CORP

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the Quarterly Period Ended June 30, 2013

¨	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 2, 2013 was 36,806,242.

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, 2013 and December 31, 2012		3
	Consolidated Statements of Operations for the three and six months ended June 30, 2013 and 2012		4
	Consolidated Statements of Cash Flows for the six months ended June 30, 2013 and 2012		5
	Notes to Consolidated Financial Statements		6
ITEM 2	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		17
ITEM 3	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		27
ITEM 4	CONTROLS AND PROCEDURES		28
PART II	OTHER INFORMATION		29
ITEM 1	LEGAL PROCEEDINGS		29
ITEM 1A	RISK FACTORS		29
ITEM 6	EXHIBITS		30

PART 1 – FINANCIAL INFORMATION

Item 1—Financial Statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)


	June 30, 2013			December 31, 2012
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,650		$	1,188
Accounts receivable, trade and other, net of allowance		3,366			7,078
Accrued oil and natural gas revenue		19,246			19,054
Fair value of oil and natural gas derivatives		5,808			2,125
Inventory		1,872			2,202
Prepaid expenses and other		4,118			926

Total current assets		37,060			32,573

PROPERTY AND EQUIPMENT:
Oil and natural gas properties (successful efforts method)		1,703,778			1,619,914
Furniture, fixtures and equipment		6,415			6,212

		1,710,193			1,626,126
Less: Accumulated depletion, depreciation and amortization		(957,351	)		(906,377	)

Net property and equipment		752,842			719,749
Fair value of oil and natural gas derivatives		2,597			—
Deferred tax assets		1,594			636
Deferred financing cost and other		13,493			15,427

TOTAL ASSETS	$	807,586		$	768,385

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	67,858		$	73,094
Accrued liabilities		38,174			37,634
Accrued abandonment costs		112			168
Deferred tax liabilities current		1,594			636
Fair value of oil and natural gas derivatives		1,744			351

Total current liabilities		109,482			111,883
LONG-TERM DEBT		554,108			568,671
Accrued abandonment costs		18,635			18,138
Fair value of oil and natural gas derivatives		—			3,987
Transportation obligation		5,755			5,461

Total liabilities		687,980			708,140

Commitments and contingencies (See Note 9)
STOCKHOLDERS’ EQUITY:
Preferred stock: 10,000,000 shares $1.00 par value per share authorized:
5.375% Series B convertible preferred stock, issued and outstanding 2,250,000 shares		2,250			2,250
10% Series C cumulative preferred stock, issued and outstanding 4,400 shares		4			—
Common stock: $0.20 par value, 100,000,000 shares authorized; issued and outstanding 36,806,209 and 36,758,141 shares, respectively		7,361			7,352
Treasury stock (77,788 and 77,142 shares, respectively)		(647	)		(639	)
Additional paid in capital		757,888			648,458
Retained earnings (accumulated deficit)		(647,250	)		(597,176	)

Total stockholders’ equity		119,606			60,245

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	807,586		$	768,385

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,
	2013			2012			2013			2012
REVENUES:
Oil and natural gas revenues	$	48,071		$	41,411		$	95,125		$	86,788
Other		414			(65	)		444			(134	)

		48,485			41,346			95,569			86,654

OPERATING EXPENSES:
Lease operating expense		5,881			6,695			13,097			15,049
Production and other taxes		2,742			2,087			5,502			4,080
Transportation and processing		2,476			3,522			5,073			7,650
Depreciation, depletion and amortization		34,513			34,562			69,487			66,840
Exploration		9,511			2,019			12,846			4,232
Impairment		—			—			—			2,662
General and administrative		7,645			6,690			17,032			14,611
Gain on sale of assets		—			(72	)		(43	)		(72	)
Other		(91	)		—			(91	)		—

		62,677			55,503			122,903			115,052

Operating income (loss)		(14,192	)		(14,157	)		(27,334	)		(28,398	)

OTHER INCOME (EXPENSE):
Interest expense		(13,027	)		(13,089	)		(26,400	)		(26,002	)
Interest income and other		15			1			19			1
Gain on derivatives not designated as hedges		11,061			24,043			9,109			33,468

		(1,951	)		10,955			(17,272	)		7,467

Income (loss) before income taxes		(16,143	)		(3,202	)		(44,606	)		(20,931	)
Income tax benefit		—			—			—			—

Net income (loss)		(16,143	)		(3,202	)		(44,606	)		(20,931	)
Preferred stock dividends		3,956			1,512			5,468			3,024

Net loss applicable to common stock	$	(20,099	)	$	(4,714	)	$	(50,074	)	$	(23,955	)

PER COMMON SHARE
Net loss applicable to common stock - basic	$	(0.55	)	$	(0.13	)	$	(1.36	)	$	(0.66	)
Net loss applicable to common stock - diluted	$	(0.55	)	$	(0.13	)	$	(1.36	)	$	(0.66	)
Weighted average common shares outstanding - basic		36,701			36,366			36,692			36,352
Weighted average common shares outstanding - diluted		36,701			36,366			36,692			36,352

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,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(44,606	)	$	(20,931	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization		69,487			66,840
Unrealized (gain) loss on derivatives not designated as hedges		(8,874	)		3,753
Impairment		—			2,662
Amortization of leasehold costs		9,744			2,551
Share based compensation (non-cash)		3,474			3,035
Gain on sale of assets		(43	)		(72	)
Exploration cost		589			—
Amortization of finance cost and debt discount		6,842			6,272
Amortization of transportation obligation		636			589
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance		3,649			(1,964	)
Accrued oil and natural gas revenue		(192	)		5,692
Inventory		330			4,371
Prepaid expenses and other		(2,618	)		3,196
Accounts payable		(5,236	)		6,095
Accrued liabilities		2,678			(4,159	)

Net cash provided by operating activities		35,860			77,930

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(114,673	)		(131,777	)
Proceeds from sale of assets		433			39

Net cash used in investing activities		(114,240	)		(131,738	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from bank borrowings		105,500			63,000
Principal payments of bank borrowings		(125,500	)		(7,500	)
Proceeds from preferred stock offering		105,610			—
Preferred stock dividends		(5,468	)		(3,024	)
Debt issuance costs		(312	)		(56	)
Other		(8	)		(20	)
Exercise of stock options and warrants		20			16

Net cash provided by financing activities		79,842			52,416

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		1,462			(1,392	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		1,188			3,347

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	2,650		$	1,955

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 (together with its subsidiary, “we,” “our,” or the “Company”) is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in (i) South Texas, primarily targeting the Eagle Ford Shale Trend, (ii) Northwest Louisiana and East Texas, which includes the Haynesville Shale and Cotton Valley Taylor Sand, and (iii) Southwest Mississippi and Southeast Louisiana, primarily targeting the Tuscaloosa Marine Shale.

Principles of Consolidation—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 (the “SEC”) and accordingly, certain information normally included in the 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 include the financial statements of Goodrich Petroleum Corporation and its wholly-owned subsidiary. Intercompany balances and transactions have been eliminated in consolidation. The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation. Certain data in prior periods’ financial statements have been adjusted to conform to the presentation of the current period. We have evaluated subsequent events through the date of this filing.

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.

Cash and Cash Equivalents—Cash and cash equivalents include cash on hand, demand deposit accounts and temporary cash investments with maturities of ninety days or less at date of purchase.

Inventory—Inventory consists of casing and tubulars that are expected to be used in our capital drilling program and oil in storage tanks. Inventory is carried on our Consolidated Balance Sheets at the lower of cost or market.

Property and Equipment—We follow the successful efforts method of accounting for exploration and development expenditures. Under this method, costs of acquiring unproved and proved oil and natural gas leasehold acreage are capitalized. When proved reserves are found on an unproved property, the associated leasehold cost is transferred to proved properties. Significant unproved leases are reviewed periodically, and a valuation allowance is provided for any estimated decline in value. Costs of all other unproved leases are amortized over the estimated average holding period of the leases. Development costs are capitalized, including the costs of unsuccessful development wells.

Exploration—Exploration expenditures, including geological and geophysical costs, delay rentals and exploratory dry hole costs are expensed as incurred. Costs of drilling exploratory wells are initially capitalized pending determination of whether proved reserves can be attributed to the exploratory well. If management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are expensed.

Fair Value Measurement—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.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. Included in this level is our senior notes;

•

Level 2 Inputs—quotes which are derived principally from or corroborated by observable market data. Included in this level are our Senior Credit Facility 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; and

•

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 natural gas properties which are deemed impaired.

At each of June 30, 2013 and December 31, 2012, the carrying amounts of our cash and cash equivalents, trade receivables and payables represented fair value because of the short-term nature of these instruments.

Impairment—We periodically assess our long-lived assets recorded in oil and natural 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. An evaluation is performed on a field-by-field basis at least annually or whenever changes in facts and circumstances indicate that our oil and natural gas properties may be impaired. There was no indication of impairment of the carrying value of our oil and natural gas properties as of June 30, 2013.

Depreciation—Depreciation and depletion of producing oil and natural gas properties is calculated using the units-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible development costs, and proved reserves are used for unamortized leasehold costs.

Gains and losses on disposals or retirements that are significant or include an entire depreciable or depletable property unit are included in operating income. Depreciation of furniture, fixtures and equipment, consisting of office furniture, computer hardware and software and leasehold improvements is computed using the straight-line method over their estimated useful lives, which vary from three to five years.

Transportation Obligation—We entered into a natural gas gathering agreement with an independent service provider, effective July 27, 2010. The agreement is scheduled to remain in effect for a period of ten years and requires the service provider to construct pipelines and facilities to connect our wells to the service provider’s gathering system in our Eagle Ford Shale area of South Texas. In compensation for the services, we agreed to pay the service provider 110% of the total capital cost incurred by the service provider to construct new pipelines and facilities. The service provider will bill us for 20 percent of the accumulated unpaid capital costs annually.

We account for the agreement by recording a long-term asset, included in “Deferred financing cost and other” on our Consolidated Balance Sheets. The asset is amortized using the units-of-production method and the amortization expense is included in “Transportation and processing” on our Consolidated Statements of Operations. The related current and long-term liabilities are presented on our Consolidated Balance Sheets in “Accrued liabilities” and “Transportation obligation,” respectively.

Asset Retirement Obligations— These obligations are related to the abandonment and site restoration requirements that result from the acquisition, construction and development of our oil and natural gas properties. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Accretion expense is included in depreciation, depletion and amortization on our Consolidated Statements of Operations.

Revenue Recognition—Oil and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues from the production of oil and natural gas properties in which we have an interest with other producers are recognized using the entitlements method. We record a liability or an asset for natural gas balancing when we have sold more or less than our working interest share of natural gas production, respectively. At each of June 30, 2013 and December 31, 2012, the net liability for natural gas balancing was immaterial. Differences between actual production and net working interest volumes are routinely adjusted.

Derivative Instruments—We use derivative instruments such as futures, forwards, options, 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.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. We offset the fair value of our asset and liability positions with the same counter party for each commodity type. Changes in fair value are required to be recognized in earnings unless specific hedge accounting criteria are met. We have not designated any of our derivative contracts as hedges, accordingly; changes in fair value are reflected in earnings.

Income Taxes—We account for income taxes, as required, under the 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 carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

We recognize, as required, the financial statement benefit of an uncertain tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority.

Earnings Per Share— Basic income per common share is computed by dividing net income available to common stockholders for each reporting period by the weighted-average number of common shares outstanding during the period. Diluted income per common share is computed by dividing net income available to common stockholders for each reporting period by the weighted average number of common shares outstanding during the period, plus the effects of potentially dilutive stock options, restricted stock, convertible notes and convertible preferred stock. We use the Treasury Stock method to calculate dilution associated with stock options and restricted stock. The potential dilutive effect of the conversion of shares are associated with our 5.375% Series B Convertible Preferred Stock, 3.25% Convertible Senior Notes due 2026 (the “2026 Notes”) and 5% Convertible Senior Notes due 2029 (the “2029 Notes”) .

Commitments and Contingencies—Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Recoveries from third parties, when probable of realization, are separately recorded and are not offset against the related liability.

Guarantee—On March 2, 2011, we issued and sold $275 million aggregate principal amount of our 8.875% Senior Notes due 2019 (the “2019 Notes”). Upon issuance of the guarantee related to the 2019 Notes, our subsidiary also became a guarantor on our outstanding 2029 Notes and our 2026 Notes, pursuant to the respective indentures governing the 2029 Notes and 2026 Notes. The 2019 Notes, 2029 Notes and 2026 Notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Goodrich Petroleum Company, L.L.C.

Goodrich Petroleum Corporation, as the parent company (the “Parent Company”), has no independent assets or operations. The guarantee is full and unconditional, subject to customary exceptions pursuant to the indenture governing our 2019 notes, 2026 notes and 2029 notes, as discussed below. The Parent Company has no other subsidiaries. In addition, there are no restrictions on the ability of the Parent Company to obtain funds from its subsidiary by dividend or loan. Finally, the Parent Company’s wholly-owned subsidiary does not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by the subsidiary without the consent of a third party.

Guarantees of the 2019 Notes will be released under certain circumstances, including in the event a Subsidiary Guarantor is sold or disposed of (whether by merger, consolidation, the sale of its capital stock or the sale of all or substantially all of its assets (other than by lease)) and whether or not the Subsidiary Guarantor is the surviving entity in such transaction to a person which is not the Parent Company or a Restricted Subsidiary of the Parent Company, such Subsidiary Guarantor will be released from its obligations under its Subsidiary Guarantee if the sale or other disposition does not violate the covenants described under “Limitation on Sales of Assets and Subsidiary Stock” in the indenture governing the 2019 Notes. In addition, a Subsidiary Guarantor will be released from its obligations under the indenture and its guarantee if such Subsidiary Guarantor ceases to guarantee any other indebtedness of the Parent Company or a Subsidiary Guarantor under a credit facility, and is not a borrower under the Senior Secured Credit Agreement, provided no Event of Default (as defined in the indenture governing the 2019 Notes) has occurred and is continuing; or if the Parent Company designates such subsidiary as an Unrestricted Subsidiary and such designation complies with the other applicable provisions

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

of the indenture or if such subsidiary otherwise no longer meets the definition of a Restricted Subsidiary; or in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the 2019 Notes in accordance with the indenture.

Guarantees of the 2029 Notes and 2026 Notes will be released if the Subsidiary Guarantor no longer guarantees the 2019 Notes, if the Subsidiary Guarantor is dissolved or liquidated, if the Subsidiary Guarantor is no longer the Parent Company’s subsidiary or upon satisfaction and discharge of the 2029 Notes or 2026 Notes in accordance with their respective indentures.

New Accounting Pronouncements

Accounting Standards Update (“ASU”) 2011-11 “Balance Sheet: Disclosures about Offsetting Assets and Liabilities.”—In December 2011, the Financial Accounting Standards Board (“FASB”) issued guidance intended to result in convergence between United States Generally Accepted Accounting Principles (“US GAAP”) and International Financial Reporting Standards (“IFRS”) requirements for offsetting (netting) assets and liabilities presented in the statements of financial position. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The disclosure affects all entities with financial instruments and derivatives that are either offset on the balance sheet in accordance with Accounting Standards Codification (“ASC”), ASC 210-20-45 or ASC 815-10-45, or subject to a master netting arrangement, irrespective of whether they are offset on the balance sheet. This information will enable users of an entity’s financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. The guidance is effective for annual periods beginning on or after January 1, 2013 and interim periods within those annual periods. Entities should provide the disclosures required by this ASU retrospectively for all comparative periods presented. We have adopted this guidance effective January 1, 2013.

We enter into oil and natural gas derivative contracts under which we have netting arrangements with each counter party. The following table discloses and reconciles the gross amounts to the amounts as presented on the Statement of Financial Position for the periods ending June 30, 2013 and December 31, 2012.


	June 30, 2013									December 31, 2012
Fair Value of Oil and Natural Gas Derivatives (in thousands)	Gross Amount			Amount Offset			As Presented			Gross Amount			Amount Offset			As Presented
Derivative Current Asset	$	6,406		$	(598	)	$	5,808		$	2,410		$	(285	)	$	2,125
Derivative Non-current Asset		5,497			(2,900	)		2,597			—			—			—
Derivative Current Liability		(2,342	)		598			(1,744	)		(636	)		285			(351	)
Derivative Non-current Liability		(2,900	)		2,900			—			(3,987	)		—			(3,987	)

Total	$	6,661		$	—		$	6,661		$	(2,213	)	$	—		$	(2,213	)

NOTE 2—Asset Retirement Obligations

The reconciliation of the beginning and ending asset retirement obligation for the six months ended June 30, 2013, is as follows (in thousands):


	June 30, 2013
Beginning balance	$	18,306
Liabilities incurred		213
Revisions in estimated liabilities		—
Liabilities settled		(56	)
Accretion expense		609
Dispositions		(325	)

Ending balance	$	18,747

Current liability	$	112
Long term liability	$	18,635

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3—Debt

Debt consisted of the following balances as of the dates indicated (in thousands):


	June 30, 2013						December 31, 2012
	Principal		Carrying Amount		Fair Value (1)		Principal		Carrying Amount		Fair Value (1)
Senior Credit Facility	$	75,000	$	75,000	$	75,000	$	95,000	$	95,000	$	95,000
3.25% Convertible Senior Notes due 2026		429		429		429		429		429		429
5.0% Convertible Senior Notes due 2029 (2)		218,500		203,679		215,791		218,500		198,242		204,975
8.875% Senior Notes due 2019		275,000		275,000		268,125		275,000		275,000		261,250

Total debt	$	568,929	$	554,108	$	559,345	$	588,929	$	568,671	$	561,654

(1)	The carrying amount for the Senior Credit Facility represents fair value because the variable interest rates are reflective of current market condition. The fair value of the notes was obtained by direct market quotes within Level 2 of the fair value hierarchy.

(2)	The debt discount is amortized using the effective interest rate method based upon an original five year term through October 1, 2014, the first repurchase date applicable to these notes. The debt discount was $14.8 million and $20.3 million as of June 30, 2013 and December 31, 2012, respectively.

The following table summarizes the total interest expense (contractual interest expense, amortization of debt discount and financing costs) and the effective interest rate on the liability component of the debt (amounts in thousands, except effective interest rates):


	Three Months Ended June 30, 2013					Three Months Ended June 30, 2012					Six Months Ended June 30, 2013					Six Months Ended June 30, 2012
	Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate
Senior Credit Facility	$	998		4.9	%	$	1,336		3.7	%	$	2,341		4.6	%	$	2,496		3.9	%
3.25% Convertible Senior Notes due 2026		3		3.3	%		3		3.3	%		7		3.3	%		7		3.3	%
5.0% Convertible Senior Notes due 2029		5,699		11.3	%		5,423		11.3	%		11,398		11.5	%		10,846		11.4	%
8.875% Senior Notes due 2019		6,327		9.2	%		6,327		9.2	%		12,654		9.3	%		12,653		9.2	%

Total	$	13,027				$	13,089				$	26,400				$	26,002

Senior Credit Facility

On May 5, 2009, we entered into a Second Amended and Restated Credit Agreement (including all amendments, the “Senior Credit Facility”) that replaced our previous facility. On February 25, 2011, we entered into a Fourth Amendment to the Senior Credit Facility. The primary conditions for the effectiveness of the Fourth Amendment 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 the 2026 Notes, both of which occurred on March 2, 2011.

On March 13, 2013, we entered into an Eighth Amendment to our Senior Credit Facility, which was declared effective as of March 25, 2013, to amend certain covenants applicable to permit payment of regular cash dividends on up to $250 million in stated or liquidation value of any new series of preferred stock, for so long as no Default, Event of Default or Borrowing Base Deficiency (as such terms are defined in the Senior Credit Facility) exists. The Eighth Amendment also permits us to fund an escrow on or prior to June 30, 2014 sufficient to provide for the repurchase or redemption of $218.5 million outstanding principal amount of our 2029 Notes with future bank borrowings or cash on hand in an amount of aggregate net proceeds from any future offerings of certain qualifying debt or equity securities. Our Senior Credit Facility currently matures on July 1, 2014, however, to the extent that sufficient funds are deposited in the escrow account on or prior to June 30, 2014 to redeem any remaining 2029 Notes at par, our Senior Credit Facility will automatically be extended to February 25, 2016. The Eighth Amendment also provides additional flexibility to exchange or modify the 2029 Notes for certain qualifying debt and equity securities.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Total lender commitments under the Senior Credit Facility are $600 million subject to borrowing base limitations. Pursuant to the terms of the Senior Credit Facility, borrowing base redeterminations occur on a semi-annual basis on April 1 and October 1. In connection with the April 1, 2013 redetermination, the borrowing base was established at $225 million. 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. As of June 30, 2013, we had $75 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;

•

Ratio of EBITDAX to cash Interest Expense of not less than 2.5/1.0 for the trailing four quarters; and

•

Total Debt no greater than 4.0 times EBITDAX for the trailing four quarters.

As used in connection with the Senior Credit Facility, Current Ratio is consolidated current assets (including current availability under the Senior Credit Facility, but excluding non-cash assets related to our derivatives) to consolidated current liabilities (excluding non-cash liabilities related to our derivatives, accrued capital expenditures and current maturities under the Senior Credit Facility).

As used in connection with the Senior Credit Facility, EBITDAX is earnings before interest expense, income tax, depreciation, depletion and amortization, exploration expense, stock based compensation and impairment of oil and natural gas properties. In calculating EBITDAX for this purpose, earnings include realized gains (losses) from derivatives not designated as hedges but exclude unrealized gains (losses) from derivatives not designated as hedges.

We were in compliance with all the financial covenants of the Senior Credit Facility as of June 30, 2013.

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% 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.

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-

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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 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 specified corporate transactions. 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.

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 per share).

Proceeds received from the issuance of the 2029 Notes were used, in part, to fully pay-off a second lien term loan of $75 million and for general corporate purposes.

We separately account for the liability and equity components of our 2029 Notes in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. Upon issuance of the notes in September 2009, in accordance with accounting standards related to convertible debt instruments that may be settled in cash upon conversion, we recorded a debt discount of $49.4 million, thereby reducing the carrying the value of $218.5 million notes on the December 31, 2009 balance sheet to $171.1 million and recorded an equity component net of tax of $32.1 million. The debt discount is amortized using the effective interest rate method based upon an original five year term through October 1, 2014. At June 30, 2013, $14.8 million debt discount remains to be amortized on the 2029 notes.

3.25% Convertible Senior Notes Due 2026

During the year ended December 31, 2011, we repurchased $174.6 million of our 3.25% Convertible Senior Notes due 2026 (the “2026 Notes”) using a portion of the net proceeds from the issuance of our 2019 Notes. At June 30, 2013, $0.4 million of the 2026 Notes remained outstanding. Holders may present to us for redemption the remaining outstanding 2026 Notes on December 1, 2016 and December 1, 2021. 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.

The 2026 Notes are convertible into shares of our common stock at a rate equal to the sum of:

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

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

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 4—Net Loss Per Common Share

Net loss applicable to common stock was used as the numerator in computing basic and diluted loss per common share for the three and six months ended June 30, 2013 and 2012. The following table sets forth information related to the computations of basic and diluted loss per share (amounts in thousands, except per share data):


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(Amounts in thousands, except per share data)
Basic loss per share:
Loss applicable to common stock	$	(20,099	)	$	(4,714	)	$	(50,074	)	$	(23,955	)
Weighted average shares of common stock outstanding		36,701			36,366			36,692			36,352

Basic loss per share	$	(0.55	)	$	(0.13	)	$	(1.36	)	$	(0.66	)

Diluted loss per share:
Loss applicable to common stock	$	(20,099	)	$	(4,714	)	$	(50,074	)	$	(23,955	)
Dividends on convertible preferred stock (1)		—			—			—			—
Interest and amortization of loan cost on senior convertible notes, net of tax (2)		—			—			—			—

	$	(20,099	)	$	(4,714	)	$	(50,074	)	$	(23,955	)

Weighted average shares of common stock outstanding		36,701			36,366			36,692			36,352
Assumed conversion of convertible preferred stock (1)		—			—			—			—
Assumed conversion of convertible senior notes (2)		—			—			—			—
Stock options and restricted stock (3)		—			—			—			—

Weighted average diluted shares outstanding		36,701			36,366			36,692			36,352

Diluted loss per share	$	(0.55	)	$	(0.13	)	$	(1.36	)	$	(0.66	)

(1) Common shares issuable upon assumed conversion of convertible preferred stock were not presented as they would have been anti-dilutive.		3,587,850			3,587,850			3,587,850			3,587,850
(2) Common shares issuable upon assumed conversion of the 2026 Notes and the 2029 Notes were not presented as they would have been anti-dilutive.		6,310,974			6,310,974			6,310,974			6,310,974
(3) Common shares issuable on assumed conversion of restricted stock and employee stock option were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive.		509,845			216,846			423,819			199,001

NOTE 5—Income Taxes

We recorded no income tax expense or benefit for the three and six months ended June 30, 2013. 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, 2013.

As of June 30, 2013, we have no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2012.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6—Stockholders’ Equity

On April 10, 2013, we issued $100 million of 10% Series C Cumulative Preferred Stock (the “Series C Preferred Stock”) and received $96.5 million net proceeds from the sale. The sale consisted of 4,000,000 depositary shares each representing a 1/1000th ownership interest in a share, par value $1.00 per preferred share with a liquidation preference of $25,000 per preferred share ($25.00 per depositary share) in an underwritten public offering. On April 18, 2013, we issued $10 million of Series C Preferred Stock and received proceeds of $9.7 million from the sale. The sale consisted of an additional 400,000 depositary shares issued pursuant to the partial exercise of the over-allotment option granted to the underwriters.

The Series C Preferred Stock ranks senior to our common stock and on parity with our 5.375% Series B Cumulative Convertible Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series C Preferred Stock has no stated maturity and is not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by us or converted into our common stock in connection with certain changes of control.

At any time on or after April 10, 2018, we may, at our option, redeem the Series C Preferred Stock, in whole at any time or in part from time to time, for cash at a redemption price of $25,000 per preferred share, plus all accumulated and unpaid dividends to, but not including, the date of redemption. We may redeem the Series C Preferred Stock following certain changes of control, if we do not exercise this option, then the holders of the Series C Preferred Stock have the option to convert the shares of preferred stock into up to 3,371.54 shares of our common stock per share of Series C Preferred Stock, subject to certain adjustments. If we exercise any of our redemption rights relating to shares of Series C Preferred Stock, the holders of Series C Preferred Stock will not have the conversion right described above with respect to the shares of Series C Preferred Stock called for redemption.

Holders of the Series C Preferred Stock have no voting rights except for limited voting rights if we fail to pay dividends for six or more quarterly periods (whether or not consecutive) and in certain other limited circumstances or as required by law.

We used the net proceeds from the offering of our Series C Preferred Stock to enhance liquidity and financial flexibility through the repayment of borrowings outstanding under our Senior Credit Facility and used the remainder for general corporate purposes.

NOTE 7—Derivative Activities

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

The 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, 2013 and 2012.


	Three Months Ended June 30,				Six Months Ended June 30,
Oil and Natural Gas Derivatives (in thousands)	2013		2012		2013		2012
Realized gain on oil and natural gas derivatives	$	83	$	21,328	$	235	$	37,221
Unrealized gain (loss) on oil and natural gas derivatives		10,978		2,715		8,874		(3,753	)

Total gain on oil and natural gas derivatives	$	11,061	$	24,043	$	9,109	$	33,468

Commodity Derivative Activity

We enter into swap contracts, costless collars or other derivative agreements from time to time to manage commodity price risk for a portion of our production. Our policy is that all hedges are approved by the Hedging Committee of our Board of Directors, and reviewed periodically by the entire Board of Directors. As of June 30, 2013, the commodity derivatives we used were in the form of:

(a)

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

(b)

swaptions, where we grant the counter party the right but not the obligation to enter into an underlying swap by a specific date at a specific strike price; and

(c)

calls, where we grant the counter party the option to buy an underlying commodity at a specified strike price, within a certain period.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Despite the measures taken by us to attempt to control price risk, we remain subject to price fluctuations for natural gas and crude oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due to seasonality of demand and other factors beyond our control. Domestic crude oil and natural 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 routinely exercise our contractual right to net realized gains against realized losses when settling with our financial counterparties. Neither our counterparties nor we require any collateral upon entering derivative contracts. We would have been at risk of losing fair value of $7.9 million had our counterparties as a group been unable to fulfill their obligations as of June 30, 2013.

As of June 30, 2013, our open forward positions on our outstanding commodity derivative contracts, all of which were with BNP Paribas, Royal Bank of Canada, JPMorgan Chase Bank, N.A., Merrill Lynch Commodities, Inc. and Wells Fargo Bank, N.A., were as follows:


Contract Type	Daily Volume		Total Remaining Volume		Fixed Price		Fair Value at June 30, 2013 (in thousands)
Natural gas (MMBtu):
2013 Swaps		10,000		920,000	$	4.1825	$	461
2014 Swaptions		20,000		7,300,000		5.35		(129	)
2014 Swaps		30,000		10,950,000		4.1825 - 5.06		9,158
2015-2016 Calls		20,000		14,620,000		5.05 - 5.06		(2,900	)
Oil (BBL):
2013 Swaps		3,500		644,000		92.25 - 103.15		(394	)
2014 Swaps		2,000		730,000		90.95 - 92.95		1,428
2014 Swaptions		1,500		547,500		97.30 - 101.00		(963	)

						Total	$	6,661

During the second quarter of 2013 we entered into the following contracts:


Contract Type	Daily Volume		Strike Price		Contract Start Date		Contract Termination
Oil swap (BBL)		1,000	$	92.95		January 1, 2014		December 31, 2014
Natural Gas swap (MMBtu)		20,000	$	5.05 - 5.06		January 1, 2014		December 31, 2014
Natural Gas calls (MMBtu)		20,000	$	5.05 - 5.06		January 1, 2015		December 31, 2016
Natural Gas swap (MMBtu)		10,000	$	4.1825		October 1, 2013		December 31, 2014

The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each level as of June 30, 2013 (in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See Note 1 “Description of Business and Significant Accounting Policies—Fair Value Measurement” for our discussion for inputs used and valuation techniques for determining fair values.


	June 30, 2013 Fair Value Measurements Using
Description	Level 1		Level 2			Level 3		Total
Current Assets Commodity Derivatives	$	—	$	5,808		$	—	$	5,808
Non-current Assets Commodity Derivatives		—		2,597			—		2,597
Current Liabilities Commodity Derivatives		—		(1,744	)		—		(1,744	)
Non-current Liabilities Commodity Derivatives		—		—			—		—

Total	$	—	$	6,661		$	—	$	6,661

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8—Subsequent Event

We have entered into a definitive agreement to purchase a 66.7% working interest in producing assets and approximately 277,000 gross acres in the Tuscaloosa Marine Shale (“TMS”) for $26.7 million, with an effective date of March 1, 2013. The remaining 33.3% working interest owner in the producing assets and leasehold has elected to retain its interest and participate with us in developing the assets.

NOTE 9—Commitments and Contingencies

As of June 30, 2013, we did not have any changes in material commitments and contingencies, including outstanding and pending litigation.

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 natural 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, the Company claims 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;

•

our ability to repay our debt;

•

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

•

the market prices of oil and natural gas;

•

uncertainties about our 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 do 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; and

•

other factors discussed below and elsewhere in this Quarterly Report on Form 10-Q and in our other public filings, press releases and discussions with our management. For additional information regarding known material factors that could cause our actual results to differ from projected results, please read the rest of this report and Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012.

Overview

We are an independent oil and natural gas company engaged in the exploration, development and production of properties primarily in (i) South Texas, primarily targeting the Eagle Ford Shale Trend, (ii) Northwest Louisiana and East Texas, primarily targeting the Haynesville Shale, Bossier Shale and Cotton Valley Trends and (iii) Southwest Mississippi and Southeast Louisiana primarily targeting the Tuscaloosa Marine Shale.

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

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 cash flow from operating activities (“operating cash flow”) in managing our business. 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), noncash general and administrative expenses and impairments.

Our revenues and operating cash flow depend on the successful development of our inventory of drilling locations, the volume and timing of our production, as well as commodity prices for oil and natural gas. Such pricing factors are largely beyond our control, but 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 maximizing our return on capital employed and adding reserve value through the timely development of our Eagle Ford Shale Trend, Haynesville Shale, Cotton Valley Taylor Sand and Tuscaloosa Marine Shale acreage. We regularly evaluate possible acquisitions of prospective acreage and oil and natural 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 develop our multi-year inventory of drilling locations on our acreage in the Eagle Ford Shale Trend, Haynesville Shale, Cotton Valley Taylor Sand and Tuscaloosa Marine Shale in order to develop our oil and natural gas reserves.

•

Increase our oil production. During the past two years, we have concentrated on increasing our crude oil production and reserves by investing and drilling in the Eagle Ford Shale Trend and, more recently, the Tuscaloosa Marine Shale. We intend to take advantage of the current favorable sales price of oil compared to the relative sales price of natural gas, and continue to grow our oil production as a percentage of total production.

•

Expand acreage position in shale plays. As of June 30, 2013, we had acquired approximately 135,000 net acres in the Tuscaloosa Marine Shale 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 characteristics similar to our existing properties. We continually strive to rationalize our portfolio of properties by selling marginal non-core 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 operating cash flow by focusing on higher-margin oil development in the Eagle Ford Shale Trend and the Tuscaloosa Marine Shale. In the current commodity price environment, our Eagle Ford Shale Trend and Tuscaloosa Marine Shale assets offer more attractive rates of return on capital invested and cash flow margins than our natural gas assets.

•

Maintain financial flexibility. As of June 30, 2013, we had a borrowing base of $225 million under our $600 million Senior Credit Facility, of which $75 million was outstanding. In April 2013, we repaid approximately $100 million of the amount outstanding on our Senior Credit Facility using the proceeds received from the offering of our Series C Preferred Stock. We have historically funded growth through operating cash flow, debt, equity and equity-linked security issuances, divestments of non-core assets and entering into 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, including fixed price swaps, swaptions 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.

Recent Events

The gross oil production associated with the properties averaged approximately 750 barrels of oil per day for March 2013. At closing, we will own approximately 320,000 net acres in the TMS when combined with our current position. We will prioritize the acreage, with the ultimate number of retained acreage to be based on geologic location, timing and amount of lease extension payments and the overall future success of the play.

We plan to fund the acquisition with borrowings under our senior credit facility. Upon closing of the transaction, the borrowing base of our senior credit facility will increase by $18 million to $243 million.

Overview of Second Quarter 2013 Results

Second Quarter 2013 financial and operating results included:

•

Our oil and condensate production for the second quarter of 2013 increased to 26% of our total equivalent production compared to 18% of our total equivalent production in the second quarter of 2012.

•

We conducted drilling operations on nine gross (5.6 net) wells in the second quarter of 2013, including seven gross (4.7 net) Eagle Ford Shale Trend wells in South Texas and two gross (0.9 net) wells in the Tuscaloosa Marine Shale Trend. We added 17 gross (8.9 net) wells to production in the second quarter of 2013, of which nine gross (6.0 net) were in the Eagle Ford Shale Trend, two gross (0.2 net) in the Tuscaloosa Marine Shale and six gross (2.7 net) in the Haynesville Shale. As of June 30, 2013, we had 11 gross (5.9 net) wells drilled and waiting on completion comprised of three gross (1.5 net) Haynesville Shale Trend, five gross (3.3 net) Eagle Ford Shale and three gross (1.1 net) Tuscaloosa Marine Shale wells.

Primary Operating Areas

Eagle Ford Shale Trend

We entered the Eagle Ford Shale Trend in April 2010. Our leasehold position is located in both La Salle and Frio Counties, Texas. We held approximately 47,000 gross (32,000 net) acres as of June 30, 2013, all of which are either producing from or prospective for the Eagle Ford Shale. During the first half of 2013, we conducted drilling operations on approximately 12 gross (8 net) Eagle Ford Shale Trend wells. During the remainder of 2013, we plan to conduct drilling operations on 9 gross (6 net) wells in the Eagle Ford Shale Trend. During the first six months of 2013, we spent $64.8 million on drilling and completion, leasehold and infrastructure capital expenditures in the Eagle Ford Shale Trend.

Tuscaloosa Marine Shale

We held approximately 161,000 gross (135,000 net) acres in the Tuscaloosa Marine Shale as of June 30, 2013, an emerging oil shale play. Our acreage is located in East Feliciana, West Feliciana, St. Helena, Concordia and Washington Parishes in Southeastern Louisiana and Wilkinson, Pike and Amite Counties in Southwestern Mississippi. Since December 31, 2012, we have added approximately 2,900 gross (800 net) acres in the trend. During the first half of 2013, we conducted drilling operations on approximately 5 gross (1.2 net) wells in the Tuscaloosa Marine Shale. During the first six months of 2013, we spent $20.2 million on drilling and completion, leasehold and infrastructure capital expenditures in the Tuscaloosa Marine Shale.

Haynesville Shale Trend

Our relatively low risk development acreage in this trend is primarily centered in Rusk, Panola, Angelina and Nacogdoches Counties, Texas and Desoto and Caddo Parishes, Louisiana. We held approximately 116,000 gross (70,000 net) acres as of June 30, 2013 producing from and prospective for the Haynesville Shale. Our net production volumes from our Haynesville Shale wells aggregated approximately 39,461 Mcfe per day in the second quarter of 2013, or approximately 54% of our total production for the quarter. During the first six months of 2013, we spent $26.9 million in this trend including completion operations on approximately 10 gross (4.2 net) Haynesville Shale Trend wells, which were drilled in prior years but were cased in early 2013. As of June 30, 2013, we had approximately 3 gross (1.5 net) Haynesville Shale Trend wells drilled and waiting on completion.

Core Haynesville Shale

Our core Haynesville Shale acreage 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 held approximately 32,000 gross (16,000 net) acres as of June 30, 2013. Our net production volumes from our core Haynesville Shale wells totaled approximately 31,354 Mcfe per day in the second quarter of 2013, or approximately 43% of our total production for the quarter. We spent $10.9 million in the first six months of 2013 on completion of wells previously drilled on which completion activities had been deferred.

Shelby Trough / Angelina River Trend

We operate all of our acreage in this area, which is primarily located in Nacogdoches, Angelina and Shelby Counties, Texas. We held approximately 36,000 gross (28,000 net) acres as of June 30, 2013. Our net production volumes from the Shelby Trough wells totaled approximately 5,268 Mcfe per day in the second quarter of 2013, or approximately 7% of our total production for the quarter. During the first six months of 2013, we spent $16.0 million in this trend which includes completion operations on one 100% owned Angelina River Trend well that was previously drilled.

Results of Operations

For the three months ended June 30, 2013, we reported a net loss applicable to common stock of $20.1 million, or $0.55 per basic and diluted share, on total revenue of $48.5 million as compared to net loss applicable to common stock of $4.7 million, or $0.13 per basic and diluted share, on total revenue of $41.3 million for the three months ended June 30, 2012. Oil and natural gas revenues increased $6.7 million compared to the same period in 2012. Increased realized natural gas prices partially offset by decreased natural gas production volumes resulted in a $2.1 million increase in natural gas revenues compared to the same period in 2012. Increased oil production and a slight increase in realized oil prices resulted in a $4.6 million increase in oil revenues compared to the same period in 2012. Derivatives activity was the largest difference between the comparative periods as we recorded a $11.1 million gain on derivatives not designated as hedges in the three months ended June 30, 2013, compared to a $24.0 million gain on derivatives not designated as hedges for the three months ended June 30, 2012.

For the six months ended June 30, 2013, we reported a net loss applicable to common stock of $50.1 million, or $1.36 per basic and diluted share, on total revenue of $95.6 million as compared to a net loss applicable to common stock of $24.0 million, or $0.66 per basic and diluted share, on total revenue of $86.7 million for the six months ended June 30, 2012. Oil and natural gas revenues increased $8.3 million compared to the same period in 2012. Decreased natural gas production volumes partially offset by increased realized natural gas prices resulted in a $6.1 million decrease in natural gas revenues compared to the same period in 2012. Increased oil production and a slight increase in realized oil prices resulted in $14.4 million increase in oil revenues compared to the same period in 2012. Derivatives activity was the largest difference between the comparative periods as we recorded a $9.1 million gain on derivatives not designated as hedges in the six months ended June 30, 2013, compared to a $33.5 million gain on derivatives not designated as hedges for the six months ended June 30, 2012.

The following table reflects our summary operating information for the periods presented (in thousands except for price and volume data). Because of normal production declines, increased or decreased drilling activity and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as indicative of future results.


(In thousands, except for price data)	Three Months Ended June 30,											Six Months Ended June 30,
(In thousands, except for price data)	2013			2012			Variance					2013			2012			Variance
Revenues:
Natural gas	$	18,397		$	16,279		$	2,118		13	%	$	32,477		$	38,623		$	(6,146	)	(16	%)
Oil and condensate		29,674			25,132			4,542		18	%		62,648			48,165			14,483		30	%
Natural gas, oil and condensate		48,071			41,411			6,660		16	%		95,125			86,788			8,337		10	%
Operating revenues		48,485			41,346			7,139		17	%		95,569			86,654			8,915		10	%
Operating expenses		62,677			55,503			7,174		13	%		122,903			115,052			7,851		7	%
Operating income (loss)		(14,192	)		(14,157	)		(35	)	(0	%)		(27,334	)		(28,398	)		1,064		4	%
Net income (loss) applicable to common stock		(20,099	)		(4,714	)		(15,385	)	(326	%)		(50,074	)		(23,955	)		(26,119	)	(109	%)
Net Production:
Natural gas (MMcf)		4,906			6,758			(1,852	)	(27	%)		9,050			14,224			(5,174	)	(36	%)
Oil and condensate (MBbls)		292			254			38		15	%		600			471			129		27	%
Total (Mmcfe)		6,658			8,282			(1,624	)	(20	%)		12,651			17,047			(4,396	)	(26	%)
Average daily production (Mcfe/d)		73,167			91,006			(17,839	)	(20	%)		69,893			93,665			(23,772	)	(25	%)

(In thousands, except for price data)	Three Months Ended June 30,											Six Months Ended June 30,
(In thousands, except for price data)	2013			2012			Variance					2013			2012			Variance
Average realized sales price per unit:
Natural gas (per Mcf)	$	3.75		$	2.41		$	1.34		56	%	$	3.59		$	2.72		$	0.87		32	%
Natural gas (per Mcf) including realized derivatives		3.75			5.26			(1.51	)	(29	%)		3.59			5.22			(1.63	)	(31	%)
Oil and condensate (per Bbl)		101.62			98.96			2.66		3	%		104.40			102.36			2.04		2	%
Oil and condensate (per Bbl) including realized derivatives		101.91			107.16			(5.25	)	(5	%)		104.79			105.63			(0.84	)	(1	%)
Average realized price (per Mcfe)		7.22			5.00			2.22		44	%		7.52			5.09			2.43		48	%

Oil and Natural Gas Revenue

Oil and natural gas revenues increased $6.7 million for the three months ended June 30, 2013 compared to the same period in 2012 reflecting the increases in oil production and an increase in realized natural gas prices partially offset by a decline in natural gas production. In addition to the sale of our South Henderson Field in the third quarter of 2012, we continued to focus on drilling oil wells in 2013 instead of natural gas wells, resulting in a decline in our natural gas production. We continue to focus our resources on increasing oil production, which we are currently able to sell at a more favorable relative price. For the three months ended June 30, 2013, 62% of our oil and natural gas revenue was attributable to oil compared to 61% for the three months ended June 30, 2012.

Oil and natural gas revenues increased $8.3 million for the six months ended June 30, 2013 compared to the same period in 2012 reflecting the increase in oil and condensate production and increases in average realized sales prices which increased revenues by approximately $26.8 million partially offset by a decrease in natural gas production which decreased revenues by approximately $18.5 million. In addition to the sale of our South Henderson Field in the third quarter of 2012, we continued to focus on drilling oil wells in 2013 instead of natural gas wells, resulting in a corresponding decline in our natural gas production. For the six months ended June 30, 2013, 66% of our oil and natural gas revenue was attributable to oil compared to 55% for the six months ended June 30, 2012.

The difference in our realized prices inclusive of the effect of the realized gains and losses on our natural gas derivatives between the three and six month periods ended June 30, 2013 and 2012 relates to our natural gas swap contracts. In the first six months of 2013, we did not have any realized natural gas hedges while in the first six months of 2012, we had 60,000 MMBtu per day realized at an average floor price of $5.78 per MMbtu. In the six months ended June 30, 2013, we had an average of 3,586 Bbls of oil per day hedged at a weighted average fixed price of $94.66 per Bbl and during the six months ended June 30, 2012, we had 3,000 Bbls of oil per day hedged at an average fixed price of $101.18 per Bbl.

Operating Expenses

As described below, operating expenses increased $7.2 million, or 13% to $62.7 million in the three months ended June 30, 2013 and increased $7.9 million, or 7%, to $122.9 million in the six months ended June 30, 2013, each compared to the same periods in 2012.


	Three Months Ended June 30,									Six Months Ended June 30,
Operating Expenses (in thousands)	2013		2012		Variance					2013		2012		Variance
Lease operating expenses	$	5,881	$	6,695	$	(814	)	(12	%)	$	13,097	$	15,049	$	(1,952	)	(13	%)
Production and other taxes		2,742		2,087		655		31	%		5,502		4,080		1,422		35	%
Transportation and processing		2,476		3,522		(1,046	)	(30	%)		5,073		7,650		(2,577	)	(34	%)
Exploration		9,511		2,019		7,492		371	%		12,846		4,232		8,614		204	%

	Three Months Ended June 30,									Six Months Ended June 30,
Operating Expenses per Mcfe	2013		2012		Variance					2013		2012		Variance
Lease operating expenses	$	0.88	$	0.81	$	0.07		9	%	$	1.04	$	0.88	$	0.16		18	%
Production and other taxes		0.41		0.25		0.16		64	%		0.43		0.24		0.19		79	%
Transportation and processing		0.37		0.43		(0.06	)	(14	%)		0.40		0.45		(0.05	)	(11	%)
Exploration		1.43		0.24		1.19		496	%		1.02		0.25		0.77		308	%

Lease Operating Expense

Lease operating expense (“LOE”) during the three month period ended June 30, 2013 decreased compared to the three months ended June 30, 2012 as a result of the sale of the South Henderson Field in September 2012 and sales tax refunds in 2013 partially offset by an increase in expense related to our Eagle Ford Shale oil activity. Our LOE per unit of production is trending higher as we add more oil wells which carry higher operating costs than natural gas wells. Oil contributed 26% to our equivalent production volumes in the second quarter 2013 compared to only 18% in second quarter 2012.

LOE for the six months ended June 30, 2013, decreased in comparison to the same period in 2012. The sale of the South Henderson Field in September 2012 and decreased workover activity was partially offset by an increase in expense related to our Eagle Ford Shale oil activity. Our LOE is trending higher as we add more oil wells to our well count which carry higher operating costs than natural gas wells. Oil contributed 28% to our production volumes in the first half of 2013 compared to only 17% in the first half of 2012.

Production and Other Taxes

Production and other taxes for the three months ended June 30, 2013 include production tax of $1.8 million and ad valorem tax of $0.9 million. Production tax for the current period does not include any tax credits attributed to Tight Gas Sands (“TGS”) credits for our natural gas wells in the State of Texas. During the comparable period in 2012, production and other taxes included production tax of $1.6 million and ad valorem tax of $0.5 million. Production tax for that comparable period was net of $0.2 million in TGS credits.

Production and other taxes for the six months ended June 30, 2013 include production tax of $3.7 million and ad valorem tax of $1.8 million. Production tax for the current period does not include any tax credits attributed to Tight Gas Sands (“TGS”) credits for our natural gas wells in the State of Texas. During the comparable period in 2012, production and other taxes included production tax of $3.3 million and ad valorem tax of $0.8 million. Production tax for that comparable period was net of $0.4 million in TGS credits.

The slightly higher production tax for 2013 compared to 2012 is attributable to the increasing portion of our production coming from the Eagle Ford Shale oil wells which are not exempt from severance tax and the expiration of the Louisiana tax exemption on certain horizontal natural gas wells. These increases are partially offset by the impact from the sale of the South Henderson Field in September 2012. The Louisiana horizontal wells are eligible for a two year severance tax exemption from the date of first production or until payout of qualified costs, whichever is first. Ad valorem tax, which is based on property value, is trending higher driven by the increasing oil production and increasing well count in the Eagle Ford shale.

The State of Mississippi has enacted an exemption from the existing 6% severance tax for horizontal wells drilled after July 1, 2013 with production commencing before July 1, 2018, which will be partially offset by a 1.3 % local severance tax on such wells. The exemption is applicable until the earlier of (i) 30 months beginning on the date of first sale of production or (ii) until payout of the well cost is achieved. We expect the net revenues from our future wells drilled in our Tuscaloosa Marine Shale acreage in Southwestern Mississippi to be favorably impacted by this exemption.

Transportation and Processing Expense

Transportation and processing expense decreased in the three months and six month ended June 30, 2013 compared to the same periods in 2012, as a result of the sale of the South Henderson Field in September 2012 and generally lower natural gas production which carries substantially all of our transportation and processing cost.

Exploration

The increase in exploration expense for the three months and six months ended June 30, 2013 compared to the same periods in 2012 is attributable to expiring leases primarily in South Texas. As part of our ongoing review of capital allocation, we elected not to renew expiring leases in non-core Eagle Ford Shale Trend acreage.


	Three Months Ended June 30,											Six Months Ended June 30,
Operating Expenses (in thousands)	2013			2012			Variance					2013			2012			Variance
Depreciation, depletion and amortization		34,513		$	34,562		$	(49	)	(0	%)	$	69,487		$	66,840		$	2,647		4	%
Impairment		—			—			—		—			—			2,662			(2,662	)	(100	%)
General and administrative		7,645			6,690			955		14	%		17,032			14,611			2,421		17	%
Gain on sale of assets		—			(72	)		72		100	%		(43	)		(72	)		29		40	%
Other		(91	)		—			(91	)	(100	%)		(91	)		—			(91	)	(100	%)

	Three Months Ended June 30,											Six Months Ended June 30,
Operating Expenses per Mcfe	2013			2012			Variance					2013			2012			Variance
Depreciation, depletion and amortization	$	5.18		$	4.17		$	1.01		24	%	$	5.49		$	3.92		$	1.57		40	%
Impairment		—			—			—		—			—			0.16			(0.16	)	(100	%)
General and administrative		1.15			0.81			0.34		42	%		1.35			0.86			0.49		57	%
Gain on sale of assets		—			(0.01	)		0.01		100	%		—			—			—		—
Other		(0.01	)		—			(0.01	)	(100	)%		—			—			—		—

Depreciation, Depletion and Amortization (“DD&A”)

DD&A expense for the three months ended June 30, 2013 compared to the same period in 2012 was slightly lower reflecting decreased production. The DD&A rate increased, impacted by greater percentage of our production volumes coming from oil operating areas with higher DD&A rates, such as our Eagle Ford Shale Trend. The average DD&A rate increased 24%, while our oil production increased 15% period to period.

DD&A expense in the six months ended June 30, 2013 compared to the same period in 2012 was affected by an increase in oil production volumes and a greater percentage of our production volumes coming from operating areas with higher DD&A rates, such as our Eagle Ford Shale Trend oil properties. The average DD&A rate increased 40%, while our oil production increased 27% period to period.

Impairment

We did not record impairment expense for the three and six months ended June 30, 2013 compared to impairment expense of $2.7 million on three fields for the six months ended June 30, 2012. The majority of our impairment expense in 2012 was related to certain of our non-core fields due to declining natural gas prices.

General and Administrative (“G&A”) Expense

G&A expense increased in the three months ended June 30, 2013 compared to the same period in 2012. The increase reflects higher compensation expense and increased share-based compensation. Share-based compensation expense, which is a non-cash item, amounted to $1.7 million in the three months ended June 30, 2013, a $0.2 million increase over the same period in 2012

G&A expense increased in the six months ended June 30, 2013 compared to the same period 2012. The increase reflects higher compensation and increased share based compensation. Share based compensation expense, which is a non-cash item, amounted to $3.5 million in the six months ended June 30, 2013 compared to $3.0 million in the period in 2012.

Other Income (Expense)


	Three Months Ended June 30,						Six Months Ended June 30,
Other income (expense) (in thousands):	2013			2012			2013			2012
Interest expense	$	(13,027	)	$	(13,089	)	$	(26,400	)	$	(26,002	)
Interest income and other		15			1			19			1
Gain on derivatives not designated as hedges		11,061			24,043			9,109			33,468
Average funded borrowings adjusted for debt discount		558,260			622,609			579,391			600,480
Average funded borrowings		574,863			635,765			597,346			618,342

Interest Expense

The slight decrease in interest expense for the three months ended June 30, 2013 compared to the three months ended June 30, 2012 reflects our lower average level of outstanding borrowings on our Senior Credit Facility in the three months ended June 30, 2013. We paid off a substantial portion of the amount outstanding under our Senior Credit Facility with the proceeds of our Series C Preferred Stock offering in April 2013. Non-cash interest of $3.4 million is included in the $13.0 million interest expense reported for the three months ended June 30, 2013.

The increase in interest expense for the six months ended June 30, 2013 compared to the six months ended June 30, 2012 was driven by higher amortization of debt discount on the 5% Senior Notes due 2029 as the put right on October 1, 2014 approaches. Non-cash interest of $6.8 million is included in the interest expense in 2013 compared to $6.3 million in 2012.

Gain on Derivatives Not Designated as Hedges

Gain on derivatives not designated as hedges for the three months ended June 30, 2013 includes an unrealized gain of $11.0 million for the change of the fair value of our oil and natural gas derivative contracts and a realized gain of $0.1 million on the settlement of our oil derivatives. The unrealized gain consisted of a $3.9 million gain on our oil derivatives and a $7.1 million gain on our natural gas derivatives. The unrealized gain on oil derivatives reflects the decrease in oil futures prices for the period while the gain on the natural gas derivatives reflects the shorter maturity on the swaptions and the decrease in natural gas future prices for the period.

Gain on derivatives not designated as hedges for the three months ended June 30, 2012 includes a realized gain of $21.3 million and an unrealized gain of $2.7 million for the change in the fair value of our oil and natural gas derivative contracts. Gain on oil derivatives was $27.0 million for the three months ended June 30, 2012 consisting of a realized gain of $2.1 million and an unrealized gain of $24.9 million reflecting the fall in oil futures prices for the period. Loss on natural gas derivatives for the three months ended June 30, 2012 was $3.0 million, consisting of a realized gain of $19.2 million offset by an unrealized loss of $22.2 million. The unrealized loss was the result of the roll off of settled contracts and natural gas futures price improvements.

Gain on derivatives not designated as hedges for the six months ended June 30, 2013 includes an unrealized gain of $8.9 million for the change of the fair value of our oil and natural gas derivative and a realized gain of $0.2 million on the settlement of our oil derivatives. The unrealized gain consisted of a $1.6 million gain on our oil derivatives and a $7.3 million gain on our natural gas derivatives. The unrealized gain on oil derivatives reflects the decrease in oil futures prices for the period while the gain on the natural gas derivatives reflects the shorter maturity on the swaptions and the decrease in natural gas future prices for the period.

Gain on derivatives not designated as hedges for the six months ended June 30, 2012 includes a realized gain of $37.2 million, partially offset by an unrealized loss of $3.8 million for the change in the fair value of our oil and natural gas derivative contracts. Gain on oil derivatives was $21.1 million for the six months ended June 30, 2012 consisting of a realized gain of $1.5 million and an unrealized gain of $19.6 million reflecting the fall in oil futures prices for the period. Gain on natural gas derivatives for the six months ended June 30, 2012 was $12.4 million, consisting of a realized gain of $35.7 million offset by an unrealized loss of $23.3 million. The unrealized loss was the result of the roll off of settled contracts and natural gas futures price improvements.

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 Tax Benefit

We recorded no income tax benefit for the three and six months ended June 30, 2013. 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 asset as of June 30, 2013.

Adjusted EBITDAX (in thousands) (1)

The following table reconciles net loss to Adjusted EBITDAX for the periods indicated:


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Net Loss (GAAP)	$	(16,143	)	$	(3,202	)	$	(44,606	)	$	(20,931	)
Exploration Expense		9,511			2,019			12,846			4,232
Depreciation, depletion and amortization		34,513			34,562			69,487			66,840
Impairment		—			—			—			2,662
Stock compensation expense		1,700			1,483			3,474			3,035
Interest expense		13,027			13,089			26,400			26,002
Unrealized loss/(gain) on derivatives not designated as hedges		(10,978	)		(2,715	)		(8,874	)		3,753
Other items (2)		(106	)		(73	)		(153	)		(73	)

Adjusted EBITDAX	$	31,524		$	45,163		$	58,574		$	85,520

(1)

Adjusted EBITDAX is earnings before interest expense, income tax, DD&A, exploration expense and impairment of oil and natural gas properties. In calculating EBITDAX for this purpose, earnings include realized gains (losses) from derivatives but exclude unrealized gains (losses) from derivatives. Other excluded items include Interest income and other, Gain on sale of assets, Gain on early extinguishment of debt and other expense.

(2)	Other items include interest income and gain on sale of assets.

Management believes Adjusted EBITDAX is a good financial indicator of our ability to internally generate operating funds. Adjusted EBITDAX should not be considered an alternative to net income, as defined by GAAP. Management believes that this non-GAAP financial measure provides useful information to investors because it is monitored and used by our management and widely used by professional research analysts in the valuation and investment recommendations of companies within the oil and natural gas exploration and production industry.

Liquidity and Capital Resources

Overview

We have in place a $600 million Senior Credit Facility, entered into with a syndicate of U.S. and international lenders. As of June 30, 2013, we had a $225 million borrowing base with $75 million outstanding. Pursuant to the terms of the Senior Credit Facility, borrowing base redeterminations occur on a semi-annual basis on April 1 and October 1. In connection with the April 1, 2013 redetermination, the borrowing base was increased to $225 million. We were in compliance with existing covenants under the Senior Credit Facility at June 30, 2013.

Our Senior Credit Facility has a maturity date of July 1, 2014, subject to extension under certain circumstances. After July 1, 2013, any amounts outstanding under our Senior Credit Facility will be reflected as a current liability unless we redeem our 2029 Notes. Should we redeem the 2029 Notes, the maturity of our Senior Credit Facility will automatically extend to February 25, 2016. The first put date for our 2029 Notes is October 1, 2014; therefore, our 2029 Notes become a current liability after October 1, 2013, unless we have borrowing availability under our Senior Credit Facility or cash on hand to prepay or escrow proceeds sufficient to prepay our 2029 Notes. We anticipate accessing the capital markets before our 2029 Notes become subject to a put right requiring us to repurchase the 2029 Notes on October 1, 2014; however, we can make no assurances that we will be able to do so on terms that are acceptable to us.

In April 2013, we issued $110 million of Series C Preferred Stock and received $106.2 million net proceeds from the sale. The sale consisted of 4,400,000 depositary shares each representing a 1/1000th ownership interest of a share, with a par value $1.00 per preferred share, with a liquidation preference of $25,000 per preferred share ($25.00 per depositary share) in an underwritten public offering. We used the net proceeds from the offering to enhance liquidity and financial flexibility through the repayment of borrowings outstanding under our Senior Credit Facility and for general corporate purposes. See Note 6—“Stockholders’ Equity” in the Notes to Consolidated Financial Statements under Part 1 Item 1 of this Form 10-Q for more information about the offering.

Our total 2013 capital expenditure budget is between $175 million and $200 million, exclusive of acquisitions. We plan on spending between $160 million and $175 million on drilling and completion cost and approximately $15 million on leasehold and infrastructure costs. We will concentrate on developing our oil assets in 2013 by allocating approximately 85% of our drilling and completion budget to oil directed activity. Oil directed activity will be concentrated in the Eagle Ford Shale and the Tuscaloosa Marine Shale trends.

Our primary sources of liquidity during the first six months of 2013 were from cash on hand, cash flow from operating activities, borrowings under our Senior Credit Facility and proceeds from the offering of our Series C Preferred Stock. We used cash primarily to fund our capital spending program, pay interest on outstanding debt and pay preferred stock dividends. We expect to finance our estimated capital expenditures for the remainder of 2013 through a combination of cash from operating activities, borrowings under our Senior Credit Facility and proceeds from our securities offerings.

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;

•

joint venture partnerships in our Tuscaloosa Marine Shale, Eagle Ford Shale Trend, and/or core Haynesville Shale acreage;

•

availability under our Senior Credit Facility; and

•

issuance of debt or equity securities.

We have supported our cash flows with oil derivative contracts which covered approximately 31% of our oil and natural gas sales volumes for the first half of 2013. We have also supported our cash flows by entering into derivative positions currently covering approximately 29% of our projected oil and natural gas sales volumes for the remainder of 2013. See Note 7—“Derivative Activities” in the Notes to Consolidated Financial Statements under Part I, 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,
Cash flow statement information:	2013			2012			Variance
Net cash:
Provided by operating activities	$	35,860		$	77,930			(42,070	)
Used in investing activities		(114,240	)		(131,738	)		17,498
Provided by financing activities		79,842			52,416			27,426

Increase (Decrease) in cash and cash equivalents	$	1,462		$	(1,392	)	$	2,854

Operating activities. Production from our wells, the price of oil and natural gas and operating costs represent the main drivers behind our cash flow from operations. Changes in working capital also impact cash flows. Net cash provided by operating activities for the six months ended June 30, 2013 totaled $35.8 million down $42.1 million from the six months ended June 30, 2012. The decrease reflects $37.0 million lower derivative settlements and working capital changes offset by improved operating results.

Investing activities. Net cash used in investing activities was $114.2 million for the six months ended June 30, 2013, compared to $131.7 million for 2012. While we booked capital expenditures of approximately $113.0 million in the six months ended June 30, 2013, we paid out cash amounts totaling $114.7 million in the six months ended June 30, 2013. The difference is attributed to $18.6 million in drilling and completion cost accrued at December 31, 2012 and paid in the six months ended June 30, 2013 partially offset by $16.7 million in drilling and completion costs accrued at June 30, 2013 and non-cash asset retirement obligation additions of $0.2 million. Offsetting our capital expenditures was the receipt of $0.4 million in net proceeds, primarily from the sale of non-core assets located in Northwest Louisiana.

Financing activities. Net cash used in financing activities for the six months ended June 30, 2013 consisted of $105.6 million net proceeds from the offering of our Series C Preferred Stock partially offset by net a repayment under our Senior Credit Facility of $20.0 million and preferred stock dividends of $5.5 million. We have $75 million in borrowings outstanding under our Senior Credit Facility as of June 30, 2013. In the six months ended June 30, 2012 net cash provided by financing activities consisted of $55.5 million of net proceeds from the borrowings under our Senior Credit Facility offset by a preferred stock dividend of $3.0 million.

Debt consisted of the following balances as of the dates indicated (in thousands):


	June 30, 2013						December 31, 2012
	Principal		Carrying Amount		Fair Value (1)		Principal		Carrying Amount		Fair Value (1)
Senior Credit Facility	$	75,000	$	75,000	$	75,000	$	95,000	$	95,000	$	95,000
3.25% Convertible Senior Notes due 2026		429		429		429		429		429		429
5.0% Convertible Senior Notes due 2029 (2)		218,500		203,679		215,791		218,500		198,242		204,975
8.875% Senior Notes due 2019		275,000		275,000		268,125		275,000		275,000		261,250

Total debt	$	568,929	$	554,108	$	559,345	$	588,929	$	568,671	$	561,654

(1)	The carrying amount for the Senior Credit Facility represents fair value because the variable interest rates are reflective of current market otherwise; fair value was obtained by direct market quotes within Level 2 of the fair value hierarchy.

(2)	The debt discount is amortized using the effective interest rate method based upon an original five year term through October 1, 2014, the first put date applicable to these notes. The debt discount was $14.8 million and $20.3 million as of June 30, 2013 and December 31, 2012, respectively.


	Three Months Ended June 30, 2013					Three Months Ended June 30, 2012					Six Months Ended June 30, 2013					Six Months Ended June 30, 2012
	Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate
Senior Credit Facility	$	998		4.9	%	$	1,336		3.7	%	$	2,341		4.6	%	$	2,496		3.9	%
3.25% Convertible Senior Notes due 2026		3		3.3	%		3		3.3	%		7		3.3	%		7		3.3	%
5.0% Convertible Senior Notes due 2029		5,699		11.3	%		5,423		11.3	%		11,398		11.5	%		10,846		11.4	%
8.875% Senior Notes due 2019		6,327		9.2	%		6,327		9.2	%		12,654		9.3	%		12,653		9.2	%

Total	$	13,027				$	13,089				$	26,400				$	26,002

For additional information on our financing activities, see Note 3 – “Debt” in the Notes to Consolidated Financial Statements under Part 1 Item I of this Form 10-Q.

Off-Balance Sheet Arrangements

We do not currently have any off-balance sheet arrangements for any purpose.

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, 2012, includes a discussion of our critical accounting policies and there have been no material changes to such policies during the three months or six months ended June 30, 2013.

Item 3—Quantitative and Qualitative Disclosures about Market Risk

Our primary market risks are attributable to fluctuations in commodity prices and interest rates. These fluctuations can affect revenues and cash flow from operating, investing and financing activities. Our risk-management policies provide for the use of

derivative instruments to manage these risks. The types of derivative instruments we utilize include futures, swaps, options and fixed-price physical-delivery contracts. The volume of commodity derivative instruments we utilize may vary from year to year and is governed by risk-management policies with levels of authority delegated by our Board of Directors. Both exchange and over-the-counter traded commodity derivative instruments may be subject to margin deposit requirements, and we may be required from time to time to deposit cash or provide letters of credit with exchange brokers or its counterparties in order to satisfy these margin requirements.

For information regarding our accounting policies and additional information related to our derivative and financial instruments, see Note 1—“Description of Business and Significant Accounting Policies”, Note 7—“Derivative Activities” and Note 3—“Debt” in the Notes to Consolidated Financial Statements under Part 1, Item I of this Quarterly Report on Form 10-Q.

Commodity Price Risk

Our most significant market risk relates to fluctuations in natural gas and crude oil prices. Management expects the prices of these commodities to remain volatile and unpredictable. As these prices decline or rise significantly, revenues and cash flow will also decline or rise significantly. In addition, a non-cash impairment of our oil and natural gas properties may be required if future commodity prices experience a sustained and significant decline. Below is a sensitivity analysis of our commodity-price-related derivative instruments.

As of June 30, 2013, we had derivative instruments in place for 2013 of 3,500 Bbls per day (crude oil). At June 30, 2013, we have a net asset derivative position of $6.6 million related to all our derivative instruments. Utilizing actual derivative contractual volumes a hypothetical 10% decrease in oil and natural gas prices would have increased the net derivative asset to $14.9 million, while a hypothetical 10% increase in oil and natural gas prices would have turned our derivative position to a net derivative liability of $9.7 million. However, a gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instruments.

Adoption of Comprehensive Financial Reform

The 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, 2012.

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, 2013, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting occurred during our most recent 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

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially affect our business, financial condition or future results.

Item 6—Exhibits


Exhibit Number		Description

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

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

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

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

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

3.5		Goodrich Petroleum Corporation Amended and Restated Bylaws, effective February 12, 2008 (Incorporated by reference to Exhibit 3.2(1) of the Company’s Current Report on Form 8-K filed on February 19, 2008).

3.6		Bylaws of the Company, as amended and restated (Incorporated by reference to Exhibit 3.2 of the Company’s Form 8-K (File No. 001-12719) filed on February 19, 2008).

4.1		Certificate of Designation of 5.375% Series B Cumulative Convertible Preferred Stock (Incorporated by reference to Exhibit 1.1 of the Company’s Form 8-K filed on December 22, 2005).

4.2		Certificate of Designation with respect to the 10.00% Series C Cumulative Preferred Stock (Incorporated by reference to Exhibit 4.3 of the Company’s Form 8-K filed on April 10, 2013).

4.3		Specimen Common Stock Certificate (Incorporated by reference to Exhibit 4.6 of the Company’s Registration Statement filed February 20, 1996 on Form S-8 (File No. 33-01077)).

4.4		Deposit Agreement, dated as of April 10, 2013, by and among Goodrich Petroleum Corporation, American Stock Transfer & Trust Company, as Depositary, and the holders from time to time of the depositary receipts described therein (Incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K filed on April 10, 2013).

4.5		Form of Depositary Receipt representing the Depositary Shares (included as Exhibit A to Exhibit 4.1) (Incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K filed on April 10, 2013).

4.6		Form of Certificate representing the 10.00% Series C Cumulative Preferred Stock (Incorporated by reference to Exhibit 4.4 of the Company’s Form 8-K filed on April 10, 2013).

*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 7, 2013	By:	/S/ WALTER G. GOODRICH
		Walter G. Goodrich
		Vice Chairman & Chief Executive Officer

Date: August 7, 2013	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, 2013


Exhibit Number		Description

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

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

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

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

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

3.5		Goodrich Petroleum Corporation Amended and Restated Bylaws, effective February 12, 2008 (Incorporated by reference to Exhibit 3.2(1) of the Company’s Current Report on Form 8-K filed on February 19, 2008).

3.6		Bylaws of the Company, as amended and restated (Incorporated by reference to Exhibit 3.2 of the Company’s Form 8-K (File No. 001-12719) filed on February 19, 2008).

4.1		Certificate of Designation of 5.375% Series B Cumulative Convertible Preferred Stock (Incorporated by reference to Exhibit 1.1 of the Company’s Form 8-K filed on December 22, 2005).

4.2		Certificate of Designation with respect to the 10.00% Series C Cumulative Preferred Stock (Incorporated by reference to Exhibit 4.3 of the Company’s Form 8-K filed on April 10, 2013).

4.3		Specimen Common Stock Certificate (Incorporated by reference to Exhibit 4.6 of the Company’s Registration Statement filed February 20, 1996 on Form S-8 (File No. 33-01077)).

4.4		Deposit Agreement, dated as of April 10, 2013, by and among Goodrich Petroleum Corporation, American Stock Transfer & Trust Company, as Depositary, and the holders from time to time of the depositary receipts described therein (Incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K filed on April 10, 2013).

4.5		Form of Depositary Receipt representing the Depositary Shares (included as Exhibit A to Exhibit 4.1) (Incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K filed on April 10, 2013).

4.6		Form of Certificate representing the 10.00% Series C Cumulative Preferred Stock (Incorporated by reference to Exhibit 4.4 of the Company’s Form 8-K filed on April 10, 2013).

*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

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