Edgar Filing: GOODRICH PETROLEUM CORP

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 September 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.


Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨	Smaller reporting company	¨

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 November 1, 2013 was 43,672,866.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

TABLE OF CONTENTS


		Page
PART I	FINANCIAL INFORMATION		3
ITEM 1	FINANCIAL STATEMENTS		3
	Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012		3
	Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and 2012		4
	Consolidated Statements of Cash Flows for the nine months ended September 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		19
ITEM 3	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		30
ITEM 4	CONTROLS AND PROCEDURES		31

PART II	OTHER INFORMATION		32
ITEM 1	LEGAL PROCEEDINGS		32
ITEM 1A	RISK FACTORS		32
ITEM 6	EXHIBITS		33

PART 1 – FINANCIAL INFORMATION

Item 1—Financial Statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)


	September 30, 2013			December 31, 2012
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,901		$	1,188
Accounts receivable, trade and other, net of allowance		3,631			7,078
Accrued oil and natural gas revenue		22,591			19,054
Fair value of oil and natural gas derivatives		8,129			2,125
Inventory		2,002			2,202
Prepaid expenses and other		1,524			926

Total current assets		39,778			32,573

PROPERTY AND EQUIPMENT:
Oil and natural gas properties (successful efforts method)		1,795,190			1,619,914
Furniture, fixtures and equipment		6,573			6,212

		1,801,763			1,626,126
Less: Accumulated depletion, depreciation and amortization		(993,809	)		(906,377	)

Net property and equipment		807,954			719,749
Restricted cash		109,250			—
Fair value of oil and natural gas derivatives		43			—
Deferred tax assets		820			636
Deferred financing cost and other		15,512			15,427

TOTAL ASSETS	$	973,357		$	768,385

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	53,819		$	73,094
Accrued liabilities		45,521			37,634
Accrued abandonment costs		86			168
Deferred tax liabilities current		820			636
Fair value of oil and natural gas derivatives		5,735			351

Total current liabilities		105,981			111,883
LONG-TERM DEBT		625,990			568,671
Accrued abandonment costs		19,162			18,138
Fair value of oil and natural gas derivatives		887			3,987
Transportation obligation		4,822			5,461

Total liabilities		756,842			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 and zero shares, respectively		4			—
9.75% Series D cumulative preferred stock, issued and outstanding 5,200 and zero shares, respectively		5			—
Common stock: $0.20 par value, 100,000,000 shares authorized; issued and outstanding 36,749,710 and 36,758,141 shares, respectively		7,350			7,352
Treasury stock (4,022 and 77,142 shares, respectively)		(52	)		(639	)
Additional paid in capital		886,998			648,458
Retained earnings (accumulated deficit)		(680,040	)		(597,176	)

Total stockholders’ equity		216,515			60,245

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	973,357		$	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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
REVENUES:
Oil and natural gas revenues	$	56,824		$	45,967		$	151,949		$	132,755
Other		337			(7	)		781			(141	)

		57,161			45,960			152,730			132,614

OPERATING EXPENSES:
Lease operating expense		7,072			6,218			20,169			21,267
Production and other taxes		2,462			1,672			7,964			5,752
Transportation and processing		2,768			3,410			7,841			11,060
Depreciation, depletion and amortization		33,320			37,298			102,807			104,138
Exploration		4,115			2,523			16,961			6,755
Impairment		—			—			—			2,662
General and administrative		8,294			7,142			25,326			21,753
Gain on sale of assets		(16	)		(44,157	)		(59	)		(44,229	)
Other		—			—			(91	)		—

		58,015			14,106			180,918			129,158

Operating income (loss)		(854	)		31,854			(28,188	)		3,456

OTHER INCOME (EXPENSE):
Interest expense		(12,679	)		(13,314	)		(39,079	)		(39,316	)
Interest income and other		(1	)		2			18			3
Loss on early extinguishment of debt		(4,792	)		—			(4,792	)
Gain (loss) on derivatives not designated as hedges		(8,759	)		(6,137	)		350			27,331

		(26,231	)		(19,449	)		(43,503	)		(11,982	)

Income (loss) before income taxes		(27,085	)		12,405			(71,691	)		(8,526	)
Income tax		—			—			—			—

Net income (loss)		(27,085	)		12,405			(71,691	)		(8,526	)
Preferred stock dividends		5,705			1,511			11,173			4,535

Net income (loss) applicable to common stock	$	(32,790	)	$	10,894		$	(82,864	)	$	(13,061	)

PER COMMON SHARE
Net income (loss) applicable to common stock—basic	$	(0.89	)	$	0.30		$	(2.26	)	$	(0.36	)
Net income (loss) applicable to common stock—diluted	$	(0.89	)	$	0.30		$	(2.26	)	$	(0.36	)
Weighted average common shares outstanding—basic		36,732			36,391			36,706			36,365
Weighted average common shares outstanding—diluted		36,732			36,619			36,706			36,365

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(71,691	)	$	(8,526	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization		102,807			104,138
Unrealized (gain) loss on derivatives not designated as hedges		(3,762	)		28,696
Impairment		—			2,662
Amortization of leasehold costs		13,192			3,873
Share based compensation (non-cash)		5,211			4,711
Gain on sale of assets		(59	)		(44,229	)
Exploration cost		658			—
Amortization of finance cost, debt discount and accretion		10,005			9,407
Loss on early extinguishment of debt		4,792			—
Amortization of transportation obligation		920			895
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance		3,447			(1,287	)
Accrued oil and natural gas revenue		(3,537	)		3,991
Inventory		200			5,657
Prepaid expenses and other		(114	)		3,268
Accounts payable		(19,275	)		(4,119	)
Accrued liabilities		(1,953	)		(11,564	)

Net cash provided by operating activities		40,841			97,573

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(195,624	)		(184,944	)
Proceeds from sale of assets		449			93,708

Net cash used in investing activities		(195,175	)		(91,236	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from bank borrowings		274,800			102,500
Principal payments of bank borrowings		(227,000	)		(106,000	)
Restricted cash		(109,250	)		—
Proceeds from preferred stock offering		230,822			—
Preferred stock dividends		(11,173	)		(4,535	)
Debt issuance costs		(3,440	)		(56	)
Exercise of stock options and warrants		322			16
Other		(34	)		(39	)

Net cash provided by financing activities		155,047			(8,114	)

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		713			(1,777	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		1,188			3,347

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	1,901		$	1,570

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 Trend and Cotton Valley Taylor Sand, and (iii) Southwest Mississippi and Southeast Louisiana, primarily targeting the Tuscaloosa Marine Shale (“TMS”).

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 United States Generally Accepted Accounting Principles (“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.

Restricted Cash—Cash held in escrow at September 30, 2013 totaled $109.25 million. This cash is restricted for the repayment of our remaining outstanding 5.0% Convertible Senior Notes due 2029. See “– Note 3 – Debt”.

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 September 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 September 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 September 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.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. 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”) and 5% Convertible Senior Notes due 2032 (the “2032 Notes).

Share-Based Compensation—We account for our share-based transactions using fair value and recognize compensation expense over the requisite service period. The fair value of each option award is estimated using a Black-Scholes option valuation model with various assumptions based on our estimates. Our assumptions include expected volatility, expected term of option, risk-free interest rate and dividend yield. Expected volatility estimates are developed by us based on historical volatility of our stock. We use historical data to estimate the expected term of the options. The risk-free interest rate for periods within the expected life of the option is based on the U.S. Treasury yield in effect at the grant date. Our common stock does not pay dividends; therefore, the dividend yield is zero. The fair value of restricted stock is measured using the close of the day stock price on the day of the award.

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. On August 26, 2013, we issued $109.25 million aggregate principal amount of our 2032 Notes, which are also guaranteed by our subsidiary pursuant to the terms of the indenture governing the 2032 Notes. The 2019 Notes, 2029 Notes, 2026 Notes and 2032 Notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Goodrich Petroleum Company, L.L.C.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2029 Notes and 2032 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 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 2032 Notes, 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 2032 Notes, 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 (“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 September 30, 2013 and December 31, 2012.


	September 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	$	8,223		$	(94	)	$	8,129		$	2,410		$	(285	)	$	2,125
Derivative Non-current Asset		2,172			(2,129	)		43			—			—			—
Derivative Current Liability		(5,829	)		94			(5,735	)		(636	)		285			(351	)
Derivative Non-current Liability		(3,016	)		2,129			(887	)		(3,987	)		—			(3,987	)

Total	$	1,550		$	—		$	1,550		$	(2,213	)	$	—		$	(2,213	)

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2—Asset Retirement Obligations

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


	September 30, 2013
Beginning balance	$	18,306
Liabilities incurred		429
Revisions in estimated liabilities		—
Liabilities settled		(82	)
Accretion expense		920
Dispositions		(325	)

Ending balance	$	19,248

Current liability	$	86
Long term liability	$	19,162

NOTE 3—Debt

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


	September 30, 2013						December 31, 2012
	Principal		Carrying Amount		Fair Value (1)		Principal		Carrying Amount		Fair Value (1)
Senior Credit Facility	$	142,800	$	142,800	$	142,800	$	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)		109,250		103,199		118,482		218,500		198,242		204,975
5.0% Convertible Senior Notes due 2032 (3)		109,462		104,562		122,633		—		—		—
8.875% Senior Notes due 2019		275,000		275,000		281,188		275,000		275,000		261,250

Total debt	$	636,941	$	625,990	$	665,532	$	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 the 2029 Notes. The debt discount was $6.1 million and $20.3 million as of September 30, 2013 and December 31, 2012, respectively.

(3)	The debt discount is amortized using the effective interest rate method based upon a four year term through October 1, 2017, the first repurchase date applicable to the 2032 Notes. The debt discount was $4.9 million as of September 30, 2013.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	Three Months Ended September 30, 2013					Three Months Ended September 30, 2012					Nine Months Ended September 30, 2013					Nine Months Ended September 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	$	894		5.9	%	$	1,561		3.5	%	$	3,235		4.9	%	$	4,057		3.6	%
3.25% Convertible Senior Notes due 2026		3		3.3	%		3		3.2	%		10		3.3	%		10		3.2	%
5.0% Convertible Senior Notes due 2029		4,578		11.1	%		5,423		10.9	%		15,976		11.3	%		16,269		11.2	%
5.0% Convertible Senior Notes due 2032		877		8.7	%		—		—	%		877		8.7	%		—		—
8.875% Senior Notes due 2019		6,327		9.2	%		6,327		9.0	%		18,981		9.2	%		18,981		9.1	%

Total Total	$	12,679				$	13,314				$	39,079				$	39,317

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. 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 October 1, 2013 redetermination, the borrowing base was increased to $270 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 September 30, 2013, we had $142.8 million outstanding with a borrowing base of $243 million under the Senior Credit Facility. Substantially all our assets are pledged as collateral to secure the Senior Credit Facility.

On March 25, 2013, we entered into an Eighth Amendment to our Senior Credit Facility, which was declared effective as of March 13, 2013, to amend certain covenants to permit payment of regular cash dividends 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 account on or prior to June 30, 2014 sufficient to repurchase the outstanding principal amount of our 2029 Notes with future bank borrowings or cash on hand. As of September 30, 2013, we deposited $109.25 million in an escrow account to provide for the repurchase of the remaining outstanding principal amount of our 2029 Notes, which is reflected as restricted cash. Pursuant to the terms of our Senior Credit Facility, the funding of this escrow automatically extended the maturity of the Senior Credit Facility to February 25, 2016. The $109.25 million in escrow as of September 30, 2013 is reflected in these financial statement as restricted cash.

The Eighth Amendment also provides additional flexibility to exchange or modify the 2029 Notes for certain qualifying debt and equity securities.

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.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We were in compliance with all the financial covenants of the Senior Credit Facility as of September 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. On August 21, 2013, we entered into separate, privately negotiated exchange agreements under which we retired $109.25 million in aggregate principal amount of these outstanding 2029 Notes in exchange for our issuance of a new series of 5.0% Convertible Senior Notes due 2032 (the “2032 Notes”) in an aggregate original principal amount of $109.25 million. The 2032 Notes will mature on October 1, 2032. Following these transactions, $109.25 million in aggregate principal amount of the 2029 Notes remain outstanding with terms unchanged. The exchange closed on August 26, 2013. Please see description of the 2032 Notes below.

The 2029 Notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The 2029 Notes accrue interest at a rate of 5% annually, and interest is paid semi-annually in arrears on April 1 and October 1 of each year, beginning in 2010. Interest began accruing on the 2029 Notes on September 28, 2009.

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

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.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. Subject to the adjustments made as the result of the August 21, 2013 exchange transaction, $6.1 million of debt discount remains to be amortized on the 2029 notes as of September 30, 2013.

On October 1, 2013, we closed a private note exchange transaction in which we retired an additional $57.434 million aggregate principal amount of our 2029 Notes in exchange for the issuance of $57.0 million of our 2032 Notes. See “–Note 10 – Subsequent Events.”

5% Convertible Senior Notes due 2032

We entered into separate, privately negotiated exchange agreements under which we retired $109.25 million in aggregate principal amount of our outstanding 2029 Notes in exchange for issuance of a new series of 5.0% Convertible Senior Notes due 2032 (the “2032 Notes”) in an aggregate original principal amount of $109.25 million. The 2032 Notes will mature on October 1, 2032. The exchange transaction closed on August 26, 2013.

Many terms of the 2032 Notes will remain the same as the 2029 Notes they replace, including the 5.0% annual cash interest rate and the conversion rate of 28.8534 shares of our common stock per $1,000 principal amount of notes (equivalent to an initial conversion price of approximately $34.6580 per share of common stock), subject to adjustment in certain circumstances.

Unlike the 2029 Notes, the principal amount of the 2032 Notes will accrete at a rate of 2% per year commencing August 26, 2013, compounding on a semi-annual basis, until October 1, 2017. The accreted portion of the principal is payable in cash upon maturity but does not bear cash interest and is not convertible into our common stock. Holders have the option to require us to purchase any outstanding 2032 Notes on each of October 1, 2017, October 1, 2022 and October 1, 2027, at a price equal to 100% of the principal amount plus the accretion thereon. Accretion of principal will be reflected as a non-cash component of interest expense on our statement of operations during the term of the 2032 Notes. We have recorded $0.2 million of accretion in the current period.

We have the right to redeem the 2032 Notes on or after October 1, 2016 at a price equal to 100% of the principal amount, plus accrued but unpaid interest and accretion thereon. The 2032 Notes also provide us with the option, at our election, to convert the new notes in whole or in part, prior to maturity, into the underlying common stock, provided the trading price of our common stock exceeds $45.06 (or 130% of the then applicable conversion price) for the required measurement period. If we elect to convert the 2032 Notes on or before October 1, 2016, holders will receive a make-whole premium.

Pursuant to ASC 470-50, this exchange transaction is being accounted for as an extinguishment of debt because the terms of the two debt instruments are substantially different under the accounting rules. We retired $109.25 million of outstanding 2029 Notes with a carrying value of $102.6 million and wrote-off unamortized debt issuance cost of $0.5 million offset by $10.1 million attributable to the fair value of the equity portion of the 2029 Notes. The 2032 Notes had a fair value of $117.0 million which resulted in a loss on the early extinguishment of debt of $4.8 million.

We separately account for the liability and equity components of our 2032 Notes in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. We measured the debt component of the 2032 Notes using an effective interest rate of 8%. We attributed $104.3 million of the fair value to the 2032 Note to debt component which compared to the face results in a debt discount of $5.0 million which will be amortized through the first put date of October 1, 2017. Additionally, we recorded $12.7 million within additional paid-in capital representing the equity component of the 2032 Notes. A debt discount of $4.9 million remains to be amortized on the 2032 notes as of September 30, 2013.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3.25% Convertible Senior Notes Due 2026

During the year ended December 31, 2011, we repurchased $174.6 million of our (2026 Notes) using a portion of the net proceeds from the issuance of our 2019 Notes. At September 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.

NOTE 4—Net Income (Loss) Per Common Share

Net income (loss) applicable to common stock was used as the numerator in computing basic and diluted loss per common share for the three and nine months ended September 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 September 30,					Nine Months Ended September 30,
	2013			2012		2013			2012
	(Amounts in thousands, except per share data)
Basic Income (loss) per share:
Income (loss) applicable to common stock	$	(32,790	)	$	10,894	$	(82,864	)	$	(13,061	)
Weighted average shares of common stock outstanding		36,732			36,391		36,706			36,365

Basic income (loss) per share	$	(0.89	)	$	0.30	$	(2.26	)	$	(0.36	)

Diluted income (loss) per share:
Income (loss) applicable to common stock	$	(32,790	)	$	10,894	$	(82,864	)	$	(13,061	)
Dividends on convertible preferred stock (1)		—			—		—			—
Interest and amortization of loan cost on senior convertible notes, net of tax (2)		—			2		—			—

	$	(32,790	)	$	10,896	$	(82,864	)	$	(13,061	)

Weighted average shares of common stock outstanding		36,732			36,391		36,706			36,365
Assumed conversion of convertible preferred stock (1)		—			—		—			—
Assumed conversion of convertible senior notes (2)		—			7		—			—
Stock options and restricted stock (3)		—			221		—			—

Weighted average diluted shares outstanding		36,732			36,619		36,706			36,365

Diluted income (loss) per share	$	(0.89	)	$	0.30	$	(2.26	)	$	(0.36	)

(1) Common shares issuable upon assumed conversion of convertible preferred stock were not presented as they would have been anti-dilutive.		3,588			3,588		3,588			3,588
(2) Common shares issuable upon assumed conversion of the 2026 Notes, the 2029 Notes and the 2032 Notes were not presented as they would have been anti-dilutive.		6,311			6,304		6,311			6,311
(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.		771			—		540			206

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5—Income Taxes

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

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

NOTE 6—Stockholders’ Equity

10% Series C Cumulative Preferred Stock

In April 2013, we issued $110 million of 10% Series C Cumulative Preferred Stock (the “Series C Preferred Stock”) and received $105.5 million net proceeds from the sale. The sale consisted of 4,400,000 depositary shares each representing a 1/1000th ownership interest in a share of Series C Preferred Stock, 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.

The Series C Preferred Stock ranks senior to our common stock and on parity with our 5.375% Series B Cumulative Convertible Preferred Stock and our 9.75% Series D Cumulative 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.

9.75% Series D Cumulative Preferred Stock

In August 2013, we issued $130 million of 9.75% Series D Cumulative Preferred Stock (the “Series D Preferred Stock”) and received $125.3 million net proceeds from the sale. The sale consisted of 5,200,000 depositary shares each representing a 1/1000th ownership interest in a share of Series D Preferred Stock, 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.

The Series D Preferred Stock ranks senior to our common stock and on parity with our 5.375% Series B Cumulative Convertible Preferred Stock and our Series C Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series D 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.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

At any time on or after August 19, 2018, we may, at our option, redeem the Series D 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 D Preferred Stock following certain changes of control, if we do not exercise this option, then the holders of the Series D Preferred Stock have the option to convert the shares of preferred stock into up to 2,297.79 shares of our common stock per share of Series D Preferred Stock, subject to certain adjustments. If we exercise any of our redemption rights relating to shares of Series D Preferred Stock, the holders of Series D Preferred Stock will not have the conversion right described above with respect to the shares of Series D Preferred Stock called for redemption.

Holders of the Series D 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 D Preferred Stock to enhance liquidity and financial flexibility through the repayment of borrowings outstanding under our Senior Credit Facility, fund our acquisition of additional TMS acreage 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 nine month periods ended September 30, 2013 and 2012.


	Three Months Ended September 30,						Nine Months Ended September 30,
Oil and Natural Gas Derivatives (in thousands)	2013			2012			2013			2012
Realized gain (loss) on oil and natural gas derivatives	$	(3,647	)	$	18,806		$	(3,412	)	$	56,027
Unrealized gain (loss) on oil and natural gas derivatives		(5,112	)		(24,943	)		3,762			(28,696	)

Total gain (loss) on oil and natural gas derivatives	$	(8,759	)	$	(6,137	)	$	350		$	27,331

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 derivatives are approved by the Hedging Committee of our Board of Directors, and reviewed periodically by the entire Board of Directors. As of September 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.

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 $5.8 million had our counterparties as a group been unable to fulfill their obligations as of September 30, 2013.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of September 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 September 30, 2013 (in thousands)
Natural gas (MMBtu):
2013 Swaps		10,000		920,000	$	4.18	$	538
2014 Swaptions		20,000		7,300,000		5.35		(23	)
2014 Swaps		30,000		10,950,000		4.18-5.06		9,742
2015-2016 Calls		20,000		14,620,000		5.05-5.06		(2,842	)
Oil (BBL):
2013 Swaps		3,500		322,000		92.25-103.15		(2,245	)
2014 Swaps		2,000		730,000		90.95-92.95		(2,325	)
2014 Swaptions		1,500		547,500		97.30-101.00		(1,295	)

						Total	$	1,550

Subsequent to September 30, 2013, we entered into the following contract:

Contract Type

Daily
Volume

Strike
Price

Contract Start
Date

Contract Termination

Oil swap (BBL)

500

98.02

November 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 September 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.


	September 30, 2013 Fair Value Measurements Using
Description	Level 1		Level 2			Level 3		Total
Current Assets Commodity Derivatives	$	—	$	8,129		$	—	$	8,129
Non-current Assets Commodity Derivatives		—		43			—		43
Current Liabilities Commodity Derivatives		—		(5,735	)		—		(5,735	)
Non-current Liabilities Commodity Derivatives		—		(887	)		—		(887	)

Total	$	—	$	1,550		$	—	$	1,550

NOTE 8—Acquisition

On August 21, 2013, we closed on an acquisition of a 66.7% working interest in producing assets and mineral lease acreage in the TMS from Devon Energy Production Company, L.P. (“Devon”) with an effective date of March 1, 2013. The closing price after purchase price adjustments was $23.7 million. The closing price included $2.9 million of lease extensions executed by Devon for the Company after the effective date. The adjusted purchase price net of lease extension costs totaled $20.8 million.

The acquisition of producing assets and lease acreage is accounted for in accordance with ASC 805. The overall estimated fair value of the assets acquired and liabilities assumed is $20.8 million. Therefore a bargain purchase gain or goodwill was not recorded for this acquisition as the estimated fair value approximates the adjusted purchase price.

We allocated $6.2 million, $10.6 million and $4.0 million net of asset retirement obligation to undeveloped leasehold, developed leasehold and lease and well equipment, respectively.

For the period, August 21, 2013 through September 30, 2013, the acquired property has generated operating income of $0.9 million on revenues of $1.0 million which is included in the three and nine months ended September 30, 2013 on our Consolidated Statement of Operations.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On a pro forma basis, giving effect to the acquisition as if it had occurred on January 1, 2013, the acquired properties would have generated operating earnings of $8.5 million on revenues of $9.1 million for the nine months ended September 30, 2013 compared to operating earnings of $4.8 million on revenues of $5.8 million for the same period in 2012.

NOTE 9—Commitments and Contingencies

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

NOTE 10—Subsequent Event

On October 1, 2013 we closed on a privately negotiated exchange transaction where we retired $57.434 million in aggregate principal amount of our outstanding 2029 Notes in exchange for issuance of our 2032 Notes in an aggregate principal amount of $57.0 million. These 2032 Notes, together with the $109.25 million of 2032 Notes previously issued by us on August 26, 2013, form a single class of $166.25 million principal amount of the 2032 Notes. Currently, a total of $51.816 million aggregate principal amount of 2029 Notes remaining outstanding, with terms unchanged by our private note exchange transactions. See “- Note 3 – Debt”.

On October 21, 2013 we closed an underwritten public offering of 6,900,000 shares of our common stock sold at a price to the public of $25.25 per share. We intend to use the net proceeds from the offering of approximately $165.9 million to fund the acceleration of our drilling program in the TMS, including an increase in our number of horizontal rigs running in the TMS from two currently to five by the end of 2014.

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 Trend, Bossier Shale and Cotton Valley Trends and (iii) Southwest Mississippi and Southeast Louisiana primarily targeting the Tuscaloosa Marine Shale (“TMS”).

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 Trend, Cotton Valley Taylor Sand and TMS 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 Trend, Cotton Valley Taylor Sand and TMS 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 TMS. 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 September 30, 2013, we had acquired and leased a total of approximately 306,000 net acres in the TMS 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 TMS. In the current commodity price environment, our Eagle Ford Shale Trend and TMS assets offer more attractive rates of return on capital invested and cash flow margins than our natural gas assets.

•

Maintain financial flexibility. As of September 30, 2013, we had a borrowing base of $243 million under our $600 million Senior Credit Facility, of which $142.8 million was outstanding. Of the amount outstanding, $109.25 million was cash deposited in an escrow account for the repurchase of the outstanding principal amount of our 5.0% Convertible Senior Notes due 2029 (“2029”). 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

On October 1, 2013 we closed on privately negotiated exchange transactions where we retired $57.434 million in aggregate principal amount of our outstanding 2029 Notes in exchange for issuance of a new series of 5.00% Convertible Senior Notes due 2032 (“2032 Notes”) in an aggregate principal amount of $57.0 million. These 2032 Notes, together with the $109.25 million of 2032 Notes previously issued by us on August 26, 2013, will form a single class of $166.25 million principal amount of the 2032 Notes. Currently, a total of $51.816 million aggregate principal amount of 2029 Notes remaining outstanding, with terms unchanged by our private note exchange transactions. See “- Note 3 – Debt.”

On October 21, 2013 we closed an underwritten public offering of 6,900,000 shares of our common stock at $25.25 per share. We intend to use the net proceeds from the offering of approximately $165.9 million to the fund the acceleration of our drilling program in the TMS, including an increase in our number of horizontal rigs running in the TMS from two currently to five by the end of 2014.

Overview of Third Quarter 2013 Results

Third Quarter 2013 financial and operating results included:

•

Our oil and condensate production for the third quarter of 2013 increased to 29% of our total equivalent production compared to 23% of our total equivalent production in the third quarter of 2012.

•

On August 21, 2013, we closed on an acquisition of a 66.7% working interest in producing assets and mineral lease acreage in the TMS from Devon with an effective date of March 1, 2013. The closing price after purchase price adjustments was $23.7 million. The closing price included $2.9 million of lease extensions executed by Devon on our behalf post effective date. The adjusted purchase price net of lease extension costs totaled $20.8 million.

•

We conducted drilling operations on 8 gross (6.0 net) wells in the third quarter of 2013, including 6 gross (4.0 net) Eagle Ford Shale Trend wells in South Texas and 2 gross (1.96 net) wells in the TMS. We added 9 gross (4.9 net) wells to production in the third quarter of 2013, of which 5 gross (3 net) were in the Eagle Ford Shale Trend, 1 gross (0.9 net) in the TMS and 1 gross (0.5 net) in the Haynesville Shale Trend. As of September 30, 2013, we had 8 gross (5.3 net) wells drilled and waiting on completion comprised of 2 gross (1.0 net) Haynesville Shale Trend, 5 gross (3.3 net) Eagle Ford Shale Trend and 1 gross (0.99 net) TMS wells.

•

Combined net proceeds of $230.3 million from our underwritten public offerings of our 10% Series C Cumulative Preferred Stock and 9.75% Series D Cumulative Preferred Stock.

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 45,000 gross (30,000 net) acres as of September 30, 2013, all of which are either producing from or prospective for the Eagle Ford Shale Trend. During the nine months of 2013, we conducted drilling operations on approximately 18 gross (12 net) Eagle Ford Shale Trend wells. During the remainder of 2013, we plan to conduct drilling operations on 1 gross (0.7 net) wells in the Eagle Ford Shale Trend. During the first nine months of 2013, we spent $94.2 million on drilling and completion, leasehold and infrastructure capital expenditures in the Eagle Ford Shale Trend.

Tuscaloosa Marine Shale

We held approximately 414,000 gross (306,000 net) acres in the TMS as of September 30, 2013, an emerging oil shale play. Our extensive acreage is located in several parishes in Southeastern Louisiana and several counties in Southwestern Mississippi. Since December 31, 2012, we have added approximately 256,000 gross (172,000 net) acres in the trend which includes the acreage purchased from Devon. During the first nine months of 2013, we conducted drilling operations on approximately 7 gross (3.16 net) wells in the TMS. During the same period, we spent $49.7 million on drilling and completion, leasehold and infrastructure capital expenditures in the TMS.

We recently announced an increase in our expected total 2013 capital expenditures to an estimated $255 million from the previous capital budget estimate of $230 million. The increase is attributable to the addition of a second rig to our horizontal drilling program in the TMS and leasehold extension payments in the TMS during the fourth quarter of 2013.

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 115,000 gross (69,000 net) acres as of September 30, 2013 producing from and prospective for the Haynesville Shale. Our net production volumes from our Haynesville Shale wells aggregated approximately 44,640 Mcfe per day in the third quarter of 2013, or approximately 53% of our total production for the quarter. During the first nine months of 2013, we spent $36.5 million in this trend including completion operations on approximately 11 gross (4.7 net) Haynesville Shale Trend wells, which were drilled in prior years but were cased in early 2013. As of September 30, 2013, we had approximately 2 gross (1.0 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 64,000 gross (41,000 net) acres as of September 30, 2013. Our net production volumes from our core Haynesville Shale wells totaled approximately 37,070 Mcfe per day in the third quarter of 2013, or approximately 44% of our total production for the quarter. We spent $20.2 million in the first nine 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 35,000 gross (27,000 net) acres as of September 30, 2013. Our net production volumes from the Shelby Trough wells totaled approximately 4,887 Mcfe per day in the third quarter of 2013, or approximately 6% of our total production for the quarter. During the first nine months of 2013, we spent $16.3 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 September 30, 2013, we reported a net loss applicable to common stock of $32.8 million, or $0.89 per basic and diluted share, on total revenue of $57.2 million as compared to income applicable to common stock of $10.9 million, or $0.30 per basic and diluted share, on total revenue of $46.0 million for the three months ended September 30, 2012. Oil and natural gas revenues increased $10.9 million compared to the same period in 2012. Decreased natural gas production offset by increased realized natural gas prices resulted in gas revenues remaining substantially the same between periods. Increased oil production and an increase in realized oil prices resulted in a $10.9 million increase in oil revenues compared to the same period in 2012. Gain on the sale of assets was the largest difference between the comparative periods as we recorded a $44.2 million gain related the sale of our interest in the South Henderson Field in the three months ended September 30, 2012.

For the nine months ended September 30, 2013, we reported a net loss applicable to common stock of $82.9 million, or $2.26 per basic and diluted share, on total revenue of $152.7 million as compared to a net loss applicable to common stock of $13.1 million, or $0.36 per basic and diluted share, on total revenue of $132.6 million for the nine months ended September 30, 2012. Oil and natural gas revenues increased $19.2 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 an increase in realized oil prices resulted in $25.3 million increase in oil revenues compared to the same period in 2012. Other than the increase in oil revenues, results of derivatives activity and the gain on sale of assets were the largest other differences between the comparative periods. We recorded a $27.3 million gain on derivatives not designated as hedges in the nine months ended September 30, 2012, compared to a $0.4 million gain on derivatives not designated as hedges for the nine months ended September 30, 2013. We recorded a $44.2 million gain on the sale of assets related to the sale of our interest in the South Henderson Field in the nine months ended September 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 September 30,										Nine Months Ended September 30,
(In thousands, except for price data)	2013			2012		Variance					2013			2012			Variance
Revenues:
Natural gas	$	17,167		$	17,168	$	(1	)	0	%	$	49,643		$	55,791		$	(6,148	)	(11	%)
Oil and condensate		39,657			28,799		10,858		38	%		102,306			76,964			25,342		33	%
Natural gas, oil and condensate		56,824			45,967		10,857		24	%		151,949			132,755			19,194		14	%
Operating revenues		57,161			45,960		11,201		24	%		152,730			132,614			20,116		15	%
Operating expenses		58,015			14,106		43,909		311	%		180,918			129,158			51,760		40	%
Operating income (loss)		(854	)		31,854		(32,708	)	(103	%)		(28,188	)		3,456			(31,644	)	(916	%)
Net income (loss) applicable to common stock		(32,790	)		10,894		(43,684	)	(401	%)		(82,864	)		(13,061	)		(69,803	)	534	%
Net Production:
Natural gas (MMcf)		5,456			5,991		(535	)	(9	%)		14,506			20,215			(5,709	)	(28	%)
Oil and condensate (MBbls)		374			296		78		26	%		974			766			208		27	%
Total (Mmcfe)		7,698			7,764		(66	)	(1	%)		20,349			24,811			(4,462	)	(18	%)
Average daily production (Mcfe/d)		83,676			84,396		(720	)	(1	%)		74,538			90,553			(16,015	)	(18	%)

(In thousands, except for price data)	Three Months Ended September 30,										Nine Months Ended September 30,
(In thousands, except for price data)	2013			2012		Variance					2013			2012			Variance
Average realized sales price per unit:
Natural gas (per Mcf)	$	3.15		$	2.87	$	0.28		10	%	$	3.42		$	2.76		$	0.66		24	%
Natural gas (per Mcf) including realized derivatives		3.15			5.60		(2.45	)	(44	%)		3.42			5.34			(1.92	)	(36	%)
Oil and condensate (per Bbl)		106.11			97.43		8.68		9	%		105.06			100.46			4.60		5	%
Oil and condensate (per Bbl) including realized derivatives		96.36			105.63		(9.30	)	(9	%)		101.54			105.63			(4.11	)	(4	%)
Average realized price (per Mcfe)		7.38			5.92		1.46		25	%		7.47			5.35			2.12		40	%

Oil and Natural Gas Revenue

Oil and natural gas revenues increased $10.9 million for the three months ended September 30, 2013 compared to the same period in 2012 reflecting the increases in oil and condensate production and increases in average realized 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 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 September 30, 2013, 70% of our oil and natural gas revenue was attributable to oil compared to 63% for the three months ended September 30, 2012.

Oil and natural gas revenues increased $19.2 million for the nine months ended September 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 $38.7 million partially offset by a decrease in natural gas production which decreased revenues by approximately $19.5 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 nine months ended September 30, 2013, 67% of our oil and natural gas revenue was attributable to oil compared to 58% for the nine months ended September 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 nine month periods ended September 30, 2013 and 2012 relates to our natural gas swap contracts. In the first nine months of 2013, we did not have any realized natural gas hedges while in the first nine months of 2012, we had 60,000 MMBtu per day realized at an average floor price of $5.78 per MMbtu. In the nine months ended September 30, 2013, we had an average of 3,557 Bbls of oil per day hedged at a weighted average fixed price of $94.60 per Bbl and during the nine months ended September 30, 2012, we had an average of 2,891 Bbls of oil per day hedged at an average fixed price of $100.61 per Bbl.

Operating Expenses

As described below, operating expenses excluding gain from sale of assets decreased $0.2 million to $58.0 million in the three months ended September 30, 2013 and increased $7.6 million, or 4%, to $181.0 million in the nine months ended September 30, 2013, each compared to the same periods in 2012.


	Three Months Ended September 30,									Nine Months Ended September 30,
Operating Expenses (in thousands)	2013		2012		Variance					2013		2012		Variance
Lease operating expenses	$	7,072	$	6,218	$	854		14	%	$	20,169	$	21,267	$	(1,098	)	(5	%)
Production and other taxes		2,462		1,672		790		47	%		7,964		5,752		2,212		38	%
Transportation and processing		2,768		3,410		(642	)	(19	%)		7,841		11,060		(3,219	)	(29	%)
Exploration		4,115		2,523		1,592		63	%		16,961		6,755		10,206		151	%

	Three Months Ended September 30,									Nine Months Ended September 30,
Operating Expenses per Mcfe	2013		2012		Variance					2013		2012		Variance
Lease operating expenses	$	0.92	$	0.80	$	0.12		15	%	$	0.99	$	0.86	$	0.13		15	%
Production and other taxes		0.32		0.22		0.10		45	%		0.39		0.23		0.16		70	%
Transportation and processing		0.36		0.44		(0.08	)	(18	%)		0.39		0.45		(0.06	)	(13	%)
Exploration		0.53		0.32		0.21		66	%		0.83		0.27		0.56		207	%

Lease Operating Expense

Lease operating expense (“LOE”) during the three month period ended September 30, 2013 increased compared to the three months ended September 30, 2012. Higher workover activity in the third quarter of 2013 of $1.2 million, mostly in the Eagle Ford Shale, was partially offset by the absence of $0.6 million in LOE for the South Henderson Field, which we sold late in September 2012. Generally, 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 29% to our equivalent production volumes in the third quarter 2013 compared to 23% in third quarter 2012.

LOE for the nine months ended September 30, 2013 decreased in comparison to the same period in 2012. The absence of $2.1 million in LOE for the South Henderson Field, which we sold in late September 2012, was partially offset by higher workover activity in the first nine months of 2013 of $0.9 million, mostly in the Eagle Ford Shale. Our LOE is generally trending higher as we add more oil wells to our well count which carry higher operating costs than natural gas wells. Oil contributed 29% to our equivalent production volumes in the first nine months of 2013 compared to only 19% in the first nine months of 2012.

Production and Other Taxes

Production and other taxes for the three months ended September 30, 2013 include production tax of $2.0 million and ad valorem tax of $0.5 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 $0.9 million and ad valorem tax of $0.7 million. Production tax for that comparable period was net of $0.8 million in TGS credits.

Production and other taxes for the nine months ended September 30, 2013 include production tax of $5.7 million and ad valorem tax of $2.3 million. Production tax for the current period does not include any tax credits attributed to 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 $4.2 million and ad valorem tax of $1.6 million. Production tax for that comparable period was net of $1.3 million in TGS credits.

The higher production tax for 2013 compared to 2012 is attributable to the increasing portion of our production coming from the Eagle Ford Shale Trend 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 late 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 Trend.

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 nine month ended September 30, 2013 compared to the same periods in 2012, as a result of the sale of the South Henderson Field in September 2012 and overall 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 nine months ended September 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 September 30,											Nine Months Ended September 30,
Operating Expenses (in thousands)	2013			2012			Variance					2013			2012			Variance
Depreciation, depletion and amortization		33,320		$	37,298		$	(3,978	)	(11	%)	$	102,807		$	104,138		$	(1,331	)	(1	%)
Impairment		—			—			—		—	%		—			2,662			(2,662	)	(100	%)
General and administrative		8,294			7,142			1,152		16	%		25,326			21,753			3,573		16	%
Gain on sale of assets		(16	)		(44,157	)		44,141		(100	%)		(59	)		(44,229	)		44,170		100	%
Other		—			—			—		—	%		(91	)		—			(91	)	(100	%)

	Three Months Ended September 30,											Nine Months Ended September 30,
Operating Expenses per Mcfe	2013			2012			Variance					2013			2012			Variance
Depreciation, depletion and amortization	$	4.33		$	4.80		$	(0.47	)	(10	%)	$	5.05		$	4.20		$	0.85		20	%
Impairment		—			—			—		—	%		—			0.11			(0.11	)	(100	%)
General and administrative		1.08			0.92			0.16		17	%		1.24			0.88			0.36		41	%
Gain on sale of assets		—			(5.69	)		5.69		100	%		—			(1.78	)		1.78		100	%
Other		—			—			—		—	%		—			—			—		—	%

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

DD&A expense for the three and nine months ended September 30, 2013 decreased as compared to the same periods in 2012 as a result of a lower DD&A rate. We calculated DD&A rates for the first six months of each of 2013 and 2012 using our year-end reserve reports. We calculated DD&A rates for the third quarter of each of 2013 and 2012 using our mid-year reserve reports as of June 30, 2013 and June 30, 2012, respectively. Our mid-year reserve report as of June 30, 2013 reflected additional proved reserves as a result of our activity in our Eagle Ford Shale properties and drilling cost reductions, which reduced the DD&A rate for the third quarter of 2013.

Impairment

We did not record impairment expense for the three and nine months ended September 30, 2013 compared to impairment expense of $2.7 million on three fields for the nine months ended September 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 September 30, 2013 compared to the same period in 2012. The increase reflects higher compensation expense and the accrued restructuring cost associated with transitioning our Shreveport office to our Houston office. Share-based compensation expense, which is a non-cash item, amounted to $1.7 million in the three months ended September 30, 2013, less than a $0.1 million increase over the same period in 2012.

G&A expense increased in the nine months ended September 30, 2013 compared to the same period 2012. The increase reflects higher compensation expense, increased share based compensation and the accrued restructuring cost associated with transitioning our Shreveport office to our Houston office. The consolidation of our administrative offices in Houston is expected to create operational efficiencies, but will not materially change our future G&A expenses.

Share based compensation expense, which is a non-cash item, amounted to $5.2 million in the nine months ended September 30, 2013 compared to $4.7 million in the period in 2012. The increase in stock compensation reflects the restricted stock awarded to our essential managers in June 2012.

Other Income (Expense)


	Three Months Ended September 30,						Nine Months Ended September 30,
Other income (expense) (in thousands):	2013			2012			2013			2012
Interest expense	$	(12,679	)	$	(13,314	)	$	(39,079	)	$	(39,316	)
Interest income and other		(1	)		2			18			3
Loss on early extinguishment of debt		(4,792	)		—			(4,792	)		—
Gain (loss) on derivatives not designated as hedges		8,759			(6,137	)		350			27,331
Average funded borrowings adjusted for debt discount		540,889			645,195			566,416			615,494
Average funded borrowings		554,259			669,782			582,826			640,225

Interest Expense

The decrease in interest expense for the three and nine months ended September 30, 2013 compared to the same periods in 2012 reflects the lower average level of outstanding borrowings on our Senior Credit Facility in the comparative periods. We paid off a substantial portion of the amount outstanding under our Senior Credit Facility with the proceeds from our Series D Preferred Stock offering in August 2013 and from our Series C Preferred Stock offering in April 2013. Non-cash interest of $3.2 million and $10.0 million is included in the $12.7 million and the $39.1 million interest expense reported for the three and nine months ended September 30, 2013, respectively.

Loss on Early Extinguishment of Debt

On August 26, 2013 we exchanged half of our outstanding 2029 Notes for new 2032 Notes. We retired $109.25 million of outstanding 2029 Notes with a carrying value of $102.6 million and wrote-off unamortized debt issuance cost of $0.5 million offset by $10.1 million attributable to the fair value of the equity portion of the 2029 Notes. The 2032 Notes had a fair value of $117.0 million which resulted in a loss on the early extinguishment of debt of $4.8 million.

Gain (loss) on Derivatives Not Designated as Hedges

Loss on derivatives not designated as hedges for the three months ended September 30, 2013 includes an unrealized loss of $5.1 million for the change of the fair value of our oil and natural gas derivative contracts and a realized loss of $3.7 million on the settlement of our oil derivatives. The unrealized loss consisted of a $5.9 million loss on our oil derivatives and a $0.8 million gain on our natural gas derivatives. The unrealized loss on oil derivatives reflects the increase in oil futures prices for the period partially offset by the realization of settled contracts, while the gain on the natural gas derivatives reflects the shorter maturity of the open contracts. Natural gas futures prices declined only slightly during the period. There were no natural gas derivative contract settlements during the period. We will begin settlements of natural gas contacts in the fourth quarter 2013.

Gain on derivatives not designated as hedges for the nine months ended September 30, 2013 includes an unrealized gain of $3.8 million for the change of the fair value of our oil and natural gas derivative and a realized loss of $3.4 million on the settlement of our oil derivatives. The unrealized gain consisted of an $8.1 million gain on our natural gas derivatives and a $4.3 million loss on our oil derivatives. The gain reflects our net favorable position on the natural gas contracts we entered into in 2013 and to the maturing of our swaption contract which is the only natural gas derivative that we had in place at year end 2012. The unrealized loss on oil derivatives reflects the increase in oil futures prices for the period partially by the realization of settled contracts.

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

Income Tax Benefit

Adjusted EBITDAX (in thousands) (1)

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net Loss (GAAP)	$	(27,085	)	$	12,405		$	(71,691	)	$	(8,526	)
Exploration Expense		4,115			2,523			16,961			6,755
Depreciation, depletion and amortization		33,320			37,298			102,807			104,138
Impairment		—			—			—			2,662
Stock compensation expense		1,737			1,676			5,211			4,711
Interest expense		12,679			13,314			39,079			39,316
Loss on early extinguishment of debt		4,792			—			4,792			—
Unrealized loss/(gain) on derivatives not designated as hedges		5,112			24,943			(3,762	)		28,696
Other items (2)		(15	)		(44,159	)		(168	)		(44,232	)

Adjusted EBITDAX	$	34,655		$	48,000		$	93,229		$	133,520

(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 September 30, 2013, we had a $243 million borrowing base with $142.8 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 October 1, 2013 redetermination, the borrowing base was increased to $270 million. We were in compliance with existing covenants under the Senior Credit Facility at September 30, 2013.

As of September 30, 2013, we deposited $109.25 million in an escrow account to provide for the repurchase of the then outstanding principal amount of our 2029 Notes. Pursuant to the terms of our Senior Credit Facility, the funding of this escrow account automatically extended the maturity of the Senior Credit Facility to February 25, 2016. The $109.25 million in escrow as of September 30, 2013 is reflected in our financial statement as restricted cash. On October 1, 2013, we closed a private note exchange transaction in which we retired an additional $57.434 aggregate principal amount of our 2029 Notes in exchange for the issuance of $57.0 million of our 2032 Notes. After the closing of this transaction, the aggregate principal amount of our 2029 Notes remaining outstanding was $51.816 million, and we received a corresponding disbursement of $57.434 million of cash from escrow. We currently have $51.816 million in cash escrowed in satisfaction of this requirement. In the event the outstanding amount of 2029 Notes is further reduced, the amount required to be held in escrow will be correspondingly reduced and released to us. Any amounts remaining in escrow pursuant to this requirement will be released to us on October 2, 2014. The first put date for our 2029 Notes is October 1, 2014; therefore, our 2029 Notes become a current liability after October 1, 2013. After October 1, 2013, the funds escrowed for the repurchase of the 2029 Notes will become a current asset.

See Note 3—“Debt” and Note 10—“Subsequent Events” in the Notes to Consolidated Financial Statements under Part 1 Item 1 of this Form 10-Q for more information.

In April 2013, we issued $110 million of Series C Preferred Stock and received $105.5 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 of Series C Preferred Stock, 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.

In August 2013, we issued $130 million of Series D Preferred Stock and received $125.3 million net proceeds from the sale. The sale consisted of 5,200,000 depositary shares each representing a 1/1000th ownership interest of a share of Series D Preferred Stock, 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, fund our acquisition of additional TMS acreage 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 offerings.

Our total expected 2013 capital expenditure budget has been increased to $255 million, exclusive of acquisitions. The increase is attributable to the addition of a second rig to our horizontal drilling program in the TMS and leasehold extension payments in the TMS during the fourth quarter. For the year 2013, we plan on spending approximately $75 million in the TMS, approximately $100 million in the Eagle Ford Shale Trend, approximately $35 million in our Haynesville core area and approximately $45 million on leasehold and infrastructure.

We also expect our preliminary 2014 capital budget to be $375 million. The 2014 budget includes an increase to five horizontal rigs running in the TMS by the end of 2014 from the two current TMS rigs. We plan to spend approximately $300 million on drilling and completion activity (including facilities and infrastructure) in the TMS. We also plan to spend approximately $30 million on drilling and completion activities in both our Eagle Ford Shale Trend and Angelina River Trend/Haynesville Shale Trend areas. An additional $15 million is budgeted for leasehold acquisitions and extensions as well as for general corporate purposes, including working capital.

Our primary sources of liquidity during the first nine months of 2013 were from cash on hand, cash flow from operating activities, borrowings under our Senior Credit Facility and proceeds from the offerings of our Series C and Series D 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 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 TMS, 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 29% of our oil and natural gas sales volumes for the first nine months of 2013. We have also supported our cash flows by entering into derivative positions currently covering approximately 35% 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):


	Nine Months Ended September 30,
	2013			2012			Variance
Cash flow statement information:
Net cash:
Provided by operating activities	$	40,841		$	97,573			(56,732	)
Used in investing activities		(195,175	)		(91,236	)		(103,939	)
Provided (used) by financing activities		155,047			(8,114	)		163,161

Increase (Decrease) in cash and cash equivalents	$	713		$	(1,777	)	$	2,490

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 nine months ended September 30, 2013 totaled $40.8 million down $56.7 million from the nine months ended September 30, 2012. The decrease reflects $59.4 million negative change in derivative settlements and working capital changes offset by improved operating results.

Investing activities. Net cash used in investing activities was $195.2 million for the nine months ended September 30, 2013, compared to $91.2 million for 2012. While we booked capital expenditures of approximately $204.2 million in the nine months ended September 30, 2013, we paid out cash amounts totaling $195.6 million in the nine months ended September 30, 2013. The difference is attributed to $27.2 million in drilling and completion cost accrued at September 30, 2013 but not paid at September 30 offset by $18.6 million in drilling and completion costs accrued at December 31, 2012 and paid in 2013. 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 provided by financing activities for the nine months ended September 30, 2013 consisted of $230.8 million net proceeds from the offering of our Series C Preferred Stock and Series D Preferred Stock, net credit facility borrowings of $47.8 million and proceeds of $0.3 million from the exercise of stock options partially offset by $109.3 million escrow account funding, preferred dividends of $11.2 million and $3.4 million in finance and issuance cost. We have $142.8 million in borrowings outstanding under our Senior Credit Facility as of September 30, 2013 of which $109.3 million was used to fund the escrow account for the repurchase of the outstanding 2029 Notes as of that date.

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


	September 30, 2013						December 31, 2012
	Principal		Carrying Amount		Fair Value (1)		Principal		Carrying Amount		Fair Value (1)
Senior Credit Facility	$	142,800	$	142,800	$	142,800	$	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)		109,250		103,199		118,482		218,500		198,242		204,975
5.0% Convertible Senior Notes due 2032 (3)		109,462		104,562		122,633		—		—		—
8.875% Senior Notes due 2019		275,000		275,000		281,188		275,000		275,000		261,250

Total debt	$	636,941	$	625,990	$	665,532	$	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 1 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 $6.1 million and $20.3 million as of September 30, 2013 and December 31, 2012, respectively.

(3)	The debt discount is amortized using the effective interest rate method based upon an four year term through October 1, 2017, the first put date applicable to these notes. The debt discount was $4.9 million as of September 30, 2013.

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 September 30, 2013					Three Months Ended September 30, 2012					Nine Months Ended September 30, 2013					Nine Months Ended September 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	$	894		5.9	%	$	1,561		3.5	%		3,235		4.9	%	$	4,057		3.6	%
3.25% Convertible Senior Notes due 2026		3		3.3	%		3		3.2	%		10		3.3	%		10		3.2	%
5.0% Convertible Senior Notes due 2029		4,578		11.1	%		5,423		10.9	%		15,976		11.3	%		16,269		11.2	%
5.0% Convertible Senior Notes due 2032		877		8.7	%		—		—			877		8.7	%		—		—
8.875% Senior Notes due 2019		6,327		9.2	%		6,327		9.0	%		18,981		9.2	%		18,981		9.1	%

Total	$	12,679				$	13,314				$	39,079				$	39,317

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 nine months ended September 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 September 30, 2013, we had derivative instruments in place for 2013 of 3,500 Bbls per day (crude oil). At September 30, 2013, we have a net asset derivative position of $1.6 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 $6.9 million, while a hypothetical 10% increase in oil and natural gas prices would have turned our derivative position to a net derivative liability of $22.5 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 September 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.

A substantial proportion of our near term capital investments will be concentrated in the development of the recently acquired acreage in the Tuscaloosa Marine Shale.

Following our recent acquisitions in the TMS, we intend to devote a substantial portion of our near term capital expenditures on drilling and completion activity (including facilities and infrastructure) in the TMS. The results of these investments may not prove as attractive as we anticipate, and the concentration of such funding and activity in the TMS will necessarily divert those resources from use to further develop our other properties. There can be no assurance that these investments will generate any specific return on investment.

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).

4.7		Certificate of Designation with respect to the 9.75% Series D Cumulative Preferred Stock (Incorporated by reference to Exhibit 4.3 of the Company’s Form 8-K filed on August 19, 2013).

4.8		Deposit Agreement, dated as of August 19, 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 August 19, 2013).

4.9		Form of Depositary Receipt representing the Depositary Shares (included as Exhibit A to Exhibit 4.8) (Incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K filed on August 19, 2013).

4.10		Form of Certificate representing the 9.75% Series D Cumulative Preferred Stock (Incorporated by reference to Exhibit 4.4 of the Company’s Form 8-K filed on August 19, 2013).

4.11		Indenture dated as of September 28, 2009, between Goodrich Petroleum Corporation and Wells Fargo Bank, National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on September 30, 2009).



4.12		Third Supplemental Indenture, dated as of August 26, 2013, between Goodrich Petroleum Corporation, Goodrich Petroleum Company, L.L.C. and Wells Fargo Bank, National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K filed on August 27, 2013).

*10.1		Ninth Amendment to Second Amended and Restated Credit Agreement dated as of October 25, 2013 among Goodrich Petroleum Company, L.L.C., Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto.

*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: November 5, 2013	By:	/s/ Walter G. Goodrich
		Walter G. Goodrich
		Vice Chairman & Chief Executive Officer

Date: November 5, 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 September 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).

4.7		Certificate of Designation with respect to the 9.75% Series D Cumulative Preferred Stock (Incorporated by reference to Exhibit 4.3 of the Company’s Form 8-K filed on August 19, 2013).

4.8		Deposit Agreement, dated as of August 19, 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 August 19, 2013).

4.9		Form of Depositary Receipt representing the Depositary Shares (included as Exhibit A to Exhibit 4.8) (Incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K filed on August 19, 2013).

4.10		Form of Certificate representing the 9.75% Series D Cumulative Preferred Stock (Incorporated by reference to Exhibit 4.4 of the Company’s Form 8-K filed on August 19, 2013).



4.11		Indenture dated as of September 28, 2009, between Goodrich Petroleum Corporation and Wells Fargo Bank, National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on September 30, 2009).

4.12		Third Supplemental Indenture, dated as of August 26, 2013, between Goodrich Petroleum Corporation, Goodrich Petroleum Company, L.L.C. and Wells Fargo Bank, National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K filed on August 27, 2013).

*10.1		Ninth Amendment to Second Amended and Restated Credit Agreement dated as of October 25, 2013 among Goodrich Petroleum Company, L.L.C., Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto.

*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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