10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2013

OR

¨ 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)

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

Securities Registered Pursuant to Section 12(b) of the Act:

Common Stock, par value $0.20 per share	New York Stock Exchange
Depositary Shares, Each Representing 1/1000 Interest in a Share of 9.75% Series D Cumulative Preferred Stock, par value $1.00 per share	New York Stock Exchange
Depositary Shares, Each Representing 1/1000 Interest in a Share of 10.00% Series C Cumulative Preferred Stock, par value $1.00 per share	New York Stock Exchange
(Title of Each Class)	(Name of Each Exchange)

Securities Registered Pursuant to Section 12(g) of the Act:

Series B Preferred Stock, par value $1.00 per share

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨        No x

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨        No x

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

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  ¨    Small reporting company  ¨

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

The aggregate market value of Common Stock, par value $0.20 per share (Common Stock), held by non-affiliates (based upon the closing sales price on the New York Stock Exchange on June 30, 2013, the last business day of the registrant’s most recently completed second fiscal quarter) was approximately $339.1 million. The number of shares of the registrant’s common stock outstanding as of February 18, 2014 was 44,272,621.

Documents Incorporated By Reference:

Portions of Goodrich Petroleum Corporation’s definitive Proxy Statement, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2013, are incorporated by reference in Part III of this Form 10-K.

GOODRICH PETROLEUM CORPORATION

ANNUAL REPORT ON FORM 10-K

FOR THE FISCAL YEAR ENDED

December 31, 2013

	Page
PART I
Items 1. and 2. Business and Properties		3
Item 1A. Risk Factors		20
Item 1B. Unresolved Staff Comments		31
Item 3. Legal Proceedings		31
Item 4. Mine Safety Disclosures		31
PART II
Item  5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		32
Item 6. Selected Financial Data		34
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		35
Item 7A. Quantitative and Qualitative Disclosures about Market Risk		56
Item 8. Financial Statements and Supplementary Data		58
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		94
Item 9A. Controls and Procedures		94
Item 9B. Other Information		94
PART III
Item 10. Directors, Executive Officers and Corporate Governance		95
Item 11. Executive Compensation		97
Item  12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		97
Item 13. Certain Relationships and Related Transactions and Director Independence		97
Item 14. Principal Accounting Fees and Services		97
PART IV
Item 15. Exhibits, Financial Statement Schedules		98

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PART I

Items 1. and 2.    Business and Properties

General

Goodrich Petroleum Corporation, a Delaware corporation (together with its subsidiary, “we,” “our,” or “the Company”) formed in 1995, 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, which includes the Eagle Ford Shale Trend, (ii) Northwest Louisiana and East Texas, which includes the Haynesville Shale and Cotton Valley Taylor Sand and (iii) Southwest Mississippi and Southeast Louisiana which includes the Tuscaloosa Marine Shale (“TMS”). In the continuing depressed natural gas price environment, we are concentrating the vast majority of our development efforts on existing leased acreage within formations that are prospective for oil. We own working interests in 436 producing oil and natural gas wells located in 44 fields in eight states. At December 31, 2013, we had estimated proved reserves of approximately 452.2 Bcfe, comprised of 329.6 Bcf of natural gas, 6.3 MMBbls of NGLs and 14.1 MMBbls of oil and condensate.

We operate as one segment as each of our operating areas have similar economic characteristics and each meet the criteria for aggregation as defined by accounting standards related to disclosures about segments of an enterprise.

Available Information

Our principal executive offices are located at 801 Louisiana Street, Suite 700, Houston, Texas 77002.

Our website address is http://www.goodrichpetroleum.com. We make available, free of charge through the Investor Relations portion of our website, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”). Reports of beneficial ownership filed pursuant to Section 16(a) of the Exchange Act are also available on our website. Information contained on our website is not part of this report.

We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC at http://www.sec.gov.

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

As used herein, the following terms have specific meanings as set forth below:

Bbls	Barrels of crude oil or other liquid hydrocarbons
Bcf	Billion cubic feet
Bcfe	Billion cubic feet equivalent
MBbls	Thousand barrels of crude oil or other liquid hydrocarbons
Mcf	Thousand cubic feet of natural gas
Mcfe	Thousand cubic feet equivalent
MMBbls	Million barrels of crude oil or other liquid hydrocarbons
MMBtu	Million British thermal units
Mmcf	Million cubic feet of natural gas
Mmcfe	Million cubic feet equivalent
MMBoe	Million barrels of crude oil or other liquid hydrocarbons equivalent
NGL	Natural gas liquids
U.S.	United States

Crude oil and other liquid hydrocarbons are converted into cubic feet of natural gas equivalent based on six Mcf of natural gas to one barrel of crude oil or other liquid hydrocarbons.

Development well is a well drilled within the proved area of an oil or natural gas field to the depth of a stratigraphic horizon known to be productive.

Dry hole is an exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Economically producible as it relates to a resource, means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil-and-natural gas producing activities.

Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

Exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, a service well or a stratigraphic test well.

Farm-in or farm-out is an agreement whereby the owner of a working interest in an oil and natural gas lease or license assigns the working interest or a portion thereof to another party who desires to drill on the leased or licensed acreage. Generally, the assignee is required to drill one or more wells to earn its interest in the acreage. The assignor (the “farmor”) usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in”, while the interest transferred by the assignor is a “farm-out”.

Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition. The SEC provides a complete definition of field in Rule 4-10 (a) (15).

PV-10 is the pre-tax present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying the 12-month average price for the year and holding that price constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by contractual arrangements), and deducting the estimated future costs to be incurred in

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developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions). PV-10 is not a Generally Accepted Accounting Principles (“GAAP”) financial measure.

Productive well is an exploratory, development or extension well that is not a dry well.

Proved reserves are those quantities of oil and natural gas which, by analysis of geosciences and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. As used in this definition, “existing economic conditions” include prices and costs at which economic producibility from a reservoir is to be determined. The prices shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based on future reconditions. The SEC provides a complete definition of proved reserves in Rule 4-10 (a) (22) of Regulation S-X.

Developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimates if the extraction is by means not involving a well.

Reasonable certainty means a high degree of confidence that the quantities will be recovered, if deterministic methods are used. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geosciences (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease. The deterministic method of estimating reserves or resources uses a single value for each parameter (from the geosciences, engineering, or economic data) in the reserves calculation. The probabilistic method of estimation of reserves or resources uses the full range of values that could reasonably occur for each unknown parameter (from the geosciences and engineering data) to generate a full range of possible outcomes and their associated probabilities of occurrence.

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project.

Undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

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Working interest is the operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover is a series of operations on a producing well to restore or increase production.

Gross well or acre is a well or acre in which the registrant owns a working interest. The number of gross wells is the total number of wells in which the registrant owns a working interest.

Net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres expressed as whole numbers and fractions of whole numbers.

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Oil and Natural Gas Operations and Properties

Overview.    As of December 31, 2013, nearly all of our proved oil and natural gas reserves were located in Louisiana, Texas and Mississippi. We spent substantially all of our 2013 capital expenditures of $256.8 million in these areas, with $109.2 million, or 43%, spent on the Eagle Ford Shale Trend, $107.5 million, or 42%, on the Tuscaloosa Marine Shale and $37.5 million, or 15%, spent on the Haynesville Shale Trend. Excluding capitalized asset retirement additions of $1.8 million, we had capital expenditures of $255.0 million, including $108.9 million, or 43%, spent on the Eagle Ford Shale Trend, $107.3 million, or 42%, on the Tuscaloosa Marine Shale and $37.3 million, or 15%, spent on the Haynesville Shale Trend. Our total capital expenditures, including accrued costs for services performed during 2013 consist of $215.0 million for drilling and completion costs, $23.5 million in property acquisitions, $14.9 million for leasehold acquisitions, $1.8 million for asset retirement obligation and $1.6 for facilities, infrastructure and equipment.

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The table below details our acreage positions, average working interest and producing wells as of December 31, 2013.

Field or Area	Acreage As of December 31, 2013				Average Producing Well Working Interest			Producing Wells at December 31, 2013
	Gross		Net
Tuscaloosa Marine Shale		415,139		306,359		52	%		17
Haynesville Shale Trend		112,111		66,761		42	%		91
Eagle Ford Shale Trend		45,130		30,041		67	%		73
Cotton Valley Taylor Sand		42,226		37,402		76	%		5
Other		31,832		6,691		83	%		250

Eagle Ford Shale Trend

As of December 31, 2013, we have acquired or farmed-in leases totaling approximately 45,100 gross (30,000 net) lease acres. In 2010, we began development and production activity in the Eagle Ford Shale and Buda Lime formations (“Eagle Ford Shale Trend”) in La Salle and Frio Counties located in South Texas. During 2013, we conducted drilling operations on 16 gross (11 net) oil wells in the Eagle Ford Shale Trend.

Tuscaloosa Marine Shale

As of December 31, 2013, we have acquired approximately 415,100 gross (306,400 net) lease acres in the Tuscaloosa Marine Shale Trend, an emerging oil shale play in Southwest Mississippi and Southeast Louisiana. During 2013, we conducted drilling operations on 9 gross (5 net) wells and added 7 gross (3 net) wells to production in the Tuscaloosa Marine Shale.

Haynesville Shale Trend

As of December 31, 2013, we have acquired or farmed-in leases totaling approximately 112,100 gross (66,800 net) acres in the Haynesville Shale. During 2013, we added 13 gross (6 net) previously cased Haynesville Shale wells to production, with the majority of those wells (12 gross, 5 net) originating in Northwest Louisiana in our joint venture with Chesapeake Energy Corporation. Our Haynesville Shale drilling activities are located in five primary leasehold areas in Northeast Texas and Northwest Louisiana.

Cotton Valley Taylor Sand

As of December 31, 2013, we have acquired or farmed-in leases totaling approximately 42,200 gross (37,400 net) acres in the Cotton Valley Taylor Sand Trend. During 2013, we conducted workovers and recompletions on the existing wells in the area and did not drill any new wells.

Other

As of December 31, 2013, we maintained ownership interests in acreage and/or wells in several additional fields, including the Midway field in San Patricio County, Texas and the Garfield Unit in Kalkaska County, Michigan.

See “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report on Form 10-K for additional information on our recent operations and plans for 2014 in the Haynesville Shale, Eagle Ford Shale and Tuscaloosa Marine Shale Trends.

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Oil and Natural Gas Reserves

The following tables set forth summary information with respect to our proved reserves as of December 31, 2012, as estimated by Netherland, Sewell & Associates, Inc. (“NSAI”) and as of December 31, 2013, as estimated by NSAI and by Ryder Scott Company (“RSC”), our independent reserve engineers. Approximately 79% and 21% of the proved reserves estimates shown herein at December 31, 2013 have been independently prepared by NSAI and RSC, respectively. NSAI prepared the estimates on all our proved reserves as of December 31, 2013 on properties other than in the TMS and the Eagle Ford Shale Trend areas. RSC prepared the estimate of proved reserves as of December 31, 2013 for our TMS and Eagle Ford Trend areas. Copies of the summary reserve reports of NSAI and RSC for 2013 are included as exhibits to this Annual Report on Form 10-K. For additional information see Supplemental Information “Oil and Natural Gas Producing Activities (Unaudited)” to our consolidated financial statements in Part II Item 8 of this Annual Report on Form 10-K.

	Proved Reserves at December 31, 2013
	Developed Producing		Developed Non-Producing		Undeveloped		Total
	(dollars in thousands)
Net Proved Reserves:
Oil (MBbls) (1)		7,738		5		6,335		14,078
NGL (MBbls) (4) (5)		2,264		93		3,996		6,353
Natural Gas (Mmcf)		112,682		4,502		212,431		329,615
Natural Gas Equivalent (Mmcfe) (2)		172,695		5,091		274,417		452,203
Estimated Future Net Cash Flows							$	1,067,708
PV-10 (3)							$	472,268
Discounted Future Income Taxes								(4,121	)
Standardized Measure of Discounted Net Cash Flows (3)							$	468,147

	Proved Reserves at December 31, 2012
	Developed Producing		Developed Non-Producing		Undeveloped		Total
	(dollars in thousands)
Net Proved Reserves:
Oil (MBbls) (1)		3,549		1,058		3,453		8,060
NGL (MBbls) (4) (5)		1,674		166		3,289		5,129
Natural Gas (Mmcf)		100,949		18,722		134,310		253,981
Natural Gas Equivalent (Mmcfe) (2)		132,284		26,068		174,764		333,116
Estimated Future Net Cash Flows							$	675,529
PV-10 (3)							$	359,094
Discounted Future Income Taxes								(1,645	)
Standardized Measure of Discounted Net Cash Flows (3)							$	357,449

(1) Includes condensate.

(2) Based on ratio of six Mcf of natural gas per Bbl of oil and per Bbl of NGLs.

(3) PV-10 represents the discounted future net cash flows attributable to our proved oil and natural gas reserves before income tax, discounted at 10%. PV-10 of our total year-end proved reserves is considered a non-GAAP financial measure as defined by the SEC. We believe that the presentation of the PV-10 is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. We further believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. Our standardized measure of discounted future net cash flows of proved

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reserves, or standardized measure, as of December 31, 2013 was $468.1 million. See the reconciliation of our PV-10 to the standardized measure of discounted future net cash flows in the table above.

(4) NGL reserves for 2012 and 2013 include our Eagle Ford Shale Trend, Tuscaloosa Marine Shale Trend, West Brachfield, Minden and Beckville fields.

(5) Our production and sales volumes are accounted for and disclosed based on the wet gas stream at the point of sale. We report no NGL production, as NGLs are processed after the point of sale. However, we share and receive the pricing benefit of the revenue stream of the gas through the processing. We believe that presenting NGLs separately from natural gas and oil in our reserve report provides more information for our investors. The presentation of NGLs as a separate commodity more accurately presents to investors our economic interest in those NGLs separated, produced and sold from the wet gas streams (which we realize through our sharing in the revenue stream attributable to the processed NGLs). These commodities have separate pricing that is monitored in the marketplace.

The following table presents our reserves by targeted geologic formation in Mmcfe.

	December 31, 2013
Area	Proved Developed		Proved Undeveloped		Proved Reserves		% of Total
Haynesville Shale Trend		77,617		134,603		212,220		46	%
Cotton Valley Taylor Sand Trend		8,531		98,322		106,853		24	%
Eagle Ford Shale Trend		46,630		24,503		71,133		16	%
Tuscaloosa Marine Shale Trend		8,672		16,989		25,661		6	%
Other		36,336		—		36,336		8	%
Total		177,786		274,417		452,203		100	%

Reserve engineering is a subjective process of estimating underground accumulations of crude oil, condensate and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may differ from those assumed in these estimates. Therefore, the PV-10 amounts shown above should not be construed as the current market value of the oil and natural gas reserves attributable to our properties.

In accordance with the guidelines of the SEC, our independent reserve engineers’ estimates of future net revenues from our estimated proved reserves, and the PV-10 and standardized measure thereof, were determined to be economically producible under existing economic conditions, which requires the use of the 12-month average price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price for the period of January 2013 through December 2013, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. For reserves at December 31, 2013, the average twelve month prices used were $3.67 per MMBtu of natural gas, $96.94 per Bbl of crude oil/condensate and $31.44 per Bbl of natural gas liquids. These prices do not include the impact of hedging transactions, nor do they include the adjustments that are made for applicable transportation and quality differentials, and price differentials between natural gas liquids and oil, which are deducted from or added to the index prices on a well by well basis in estimating our proved reserves and related future net revenues.

Our proved reserve information as of December 31, 2013 included in this Annual Report on Form 10-K was estimated by our independent petroleum engineers, NSAI and RSC, in accordance with petroleum engineering and evaluation principles and definitions and guidelines set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserve Information promulgated by the Society of Petroleum Engineers. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the

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Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Our principal engineer has over 30 years of experience in the oil and natural gas industry, including over 25 years as a reserve evaluator, trainer or manager. Further professional qualifications of our principal engineer include a degree in petroleum engineering, extensive internal and external reserve training, and experience in asset evaluation and management. In addition, the principal engineer is an active participant in professional industry groups and has been a member of the Society of Petroleum Engineers for over 30 years.

Our estimates of proved reserves are made by NSAI and RSC, as our independent petroleum engineers. Our internal professional staff works closely with our external engineers to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. In addition, other pertinent data such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria is provided to them. We make available all information requested, including our pertinent personnel, to the external engineers as part of their evaluation of our reserves.

We consider providing independent fully engineered third-party estimates of reserves from nationally reputable petroleum engineering firms, such as NSAI and RSC, to be the best control in ensuring compliance with Rule 4-10 of Regulation S-X for reserve estimates.

While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the NSAI and RSC reserve reports are reviewed by our senior management with representatives of NSAI and RSC and our internal technical staff. Additionally, our senior management reviews and approves any internally estimated significant changes to our proved reserves semi-annually.

Proved reserves are those quantities of oil and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, NSAI and RSC employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, available downhole and production data, seismic data and well test data.

Our total proved reserves at December 31, 2013, as estimated by NSAI and RSC, were 452.2 Bcfe, consisting of 329.6 Bcf of natural gas, 6.4 MMBbls of NGLs and 14.1 MMBbls of oil and condensate. In 2013 we added approximately 13.2 Bcfe related to the Haynesville Shale Trend and Cotton Valley Taylor Sand Trend, 17.8 Bcfe related to the Eagle Ford Shale Trend and 23.8 Bcfe related to the Tuscaloosa Marine Shale Trend. We had positive revisions of approximately 90.9 Bcfe, acquired minerals in place of 2.8 Bcfe and produced 29.4 Bcfe in 2013. The vast majority of our positive revisions related to the adding back of proved undeveloped natural gas reserves, which were uneconomic at year end 2012, but are now economic for the year ended 2013.

Our proved undeveloped reserves at December 31, 2013 were 274.4 Bcfe or 61% of our total proved reserves, consisting of 212.4 Bcf of natural gas, 4.0 MMBbls of NGLs and 6.3 MMBbls of oil and condensate. In 2013, we added approximately 11.1 Bcfe related to the Eagle Ford Shale Trend and 16.9 Bcfe related to the Tuscaloosa Marine Shale Trend. We had positive revisions of 80.0 Bcfe and we developed approximately 8.3 Bcfe, or 5% of our total proved undeveloped reserves booked as of December 31, 2012 through the drilling of 10 gross (6.7 net) development wells at an aggregate capital cost of approximately $45.6 million. Of the proved undeveloped reserves in our December 31, 2013 reserve reports, none have remained undeveloped for more than five years since the date of initial booking as proved undeveloped reserves and none are scheduled for

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commencement of development on a date more than five years from the date the reserves were initially booked as proved undeveloped.

Productive Wells

The following table sets forth the number of productive wells in which we maintain ownership interests as of December 31, 2013:

	Oil				Natural Gas				Total
	Gross (1)		Net (2)		Gross (1)		Net (2)		Gross (1)		Net (2)
South Texas		73		49		—		—		73		49
East Texas		1		—		206		195		207		195
Northwest Louisiana		—		—		113		47		113		47
Southeast Louisiana (3)		7		5		—		—		7		5
Southwest Mississippi (3)		10		4		—		—		10		4
Other		12		3		14		—		26		3
Total Productive Wells		103		61		333		242		436		303

(1) Royalty and overriding interest wells that have immaterial values are excluded from the above table. As of December 31, 2013, only three wells with royalty-only and overriding interests-only are included.

(2) Net working interest.

(3) Tuscaloosa Marine Shale producing wells.

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections. A gross well is a well in which we maintain an ownership interest, while a net well is deemed to exist when the sum of the fractional working interests owned by us equals one. Wells that are completed in more than one producing horizon are counted as one well. Of the gross wells reported above, 50 wells had completions in multiple producing horizons.

Acreage

The following table summarizes our gross and net developed and undeveloped acreage under lease as of December 31, 2013. Acreage in which our interest is limited to a royalty or overriding royalty interest is excluded from the table.

	Developed				Undeveloped				Total
	Gross		Net		Gross		Net		Gross		Net
South Texas		14,559		7,804		30,571		22,237		45,130		30,041
East Texas		79,911		50,424		24,126		18,668		104,037		69,092
Northwest Louisiana		38,285		20,515		802		802		39,087		21,317
Southeast Louisiana		13,750		9,172		295,896		222,029		309,646		231,201
Southwest Mississippi		6,792		3,529		98,702		71,628		105,494		75,157
Other		2,103		195		9		9		2,112		204
Total		155,400		91,639		450,106		335,373		605,506		427,012

Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to the extent that would permit the production of commercial quantities of natural gas or oil, regardless of whether or not such acreage contains proved reserves. As is customary in the oil and natural gas industry, we can retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by payment of delay rentals during the remaining primary term of such a lease. The oil and natural gas leases in which we have an interest are for varying primary terms; however,

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most of our developed lease acreage is beyond the primary term and is held so long as natural gas or oil is produced.

Lease Expirations

Our undeveloped lease acreage, excluding optioned acreage, will expire during the next four years, unless the leases are converted into producing units or extended prior to lease expiration. The following table sets forth the lease expirations as of December 31, 2013:

Year	Net Acreage
2014		25,797
2015		148,194
2016		31,546
2017		1,382

Operator Activities

We operate a majority of our producing properties by value, and will generally seek to become the operator of record on properties we drill or acquire. Chesapeake Energy Corporation (“Chesapeake”) continues to operate our jointly-owned Northwest Louisiana acreage in the Haynesville Shale.

Drilling Activities

The following table sets forth our drilling activities for the last three years. As denoted in the following table, “gross” wells refer to wells in which a working interest is owned, while a “net” well is deemed to exist when the sum of the fractional working interests we own in gross wells equals one.

	Year Ended December 31,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Development Wells:
Productive		14		9.3		40		25.3		46		24.1
Non-Productive		—		—		—		—		—		—
Total		14		9.3		40		25.3		46		24.1
Exploratory Wells:
Productive		8		4.1		5		1.0		1		0.7
Non-Productive		—		—		1		0.8		—		—
Total		8		4.1		6		1.8		1		0.7
Total Wells:
Productive		22		13.4		45		26.3		47		24.8
Non-Productive		—		—		1		0.8		—		—
Total		22		13.4		46		27.1		47		24.8

At December 31, 2013, we had 3 gross (2.6 net) exploration wells in progress of being drilled or completed.

Net Production, Unit Prices and Costs

The following table presents certain information with respect to oil and natural gas production attributable to our interests in all of our properties (including each of the two fields which have attributed more than 15% of

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our total proved reserves as of December 31, 2013), the revenue derived from the sale of such production, average sales prices received and average production costs during each of the years in the three-year period ended December 31, 2013.

	Sales Volumes						Average Sales Prices (1)						Average Production Cost (2) Per Mcfe
	Natural Gas Mmcf		Oil & Condensate MBbls		Total Mmcfe		Natural Gas Mcf		Oil & Condensate Per Bbl		Total Per Mcfe
For Year 2013
Haynesville Shale Trend		14,406		1		14,409	$	3.00	$	100.05	$	3.01	$	0.40
Cotton Valley Taylor Sand		853		8		898		4.40		101.53		4.99		0.59
Eagle Ford Shale Trend		1,129		1,132		7,919		5.66		101.56		15.32		1.61
TMS		—		165		990		—		105.29		17.58		1.02
Other		3,372		32		3,569		3.33		97.21		3.55		1.13
Total		19,760		1,338		27,785	$	3.35	$	101.96	$	7.29	$	0.98
For Year 2012
Haynesville Shale Trend		15,395		1		15,401	$	2.20	$	97.28	$	2.20	$	0.27
Cotton Valley Taylor Sand		3,715		68		4,123		4.27		99.92		5.66		0.33
Eagle Ford Shale Trend		1,142		960		6,902		4.26		100.01		14.64		0.81
Other		4,592		66		4,989		3.78		98.43		4.79		2.75
Total		24,844		1,095		31,415	$	2.86	$	99.91	$	5.75	$	0.83
For Year 2011
Haynesville Shale Trend		24,753		1		24,760	$	3.57	$	94.80	$	3.57	$	0.18
Cotton Valley Taylor Sand		5,008		104		5,634		4.43		93.38		5.74		0.21
Eagle Ford Shale Trend		838		464		3,624		5.16		90.22		12.89		0.76
Other		5,568		75		6,011		4.80		94.60		5.69		2.11
Total		36,167		644		40,029	$	3.92	$	91.34	$	5.01	$	0.54

(1) Excludes the impact of commodity derivatives.

(2) Excludes ad valorem and severance taxes.

In addition, three of our fields, the Bethany Longstreet, Beckville and the Eagle Ford Shale Trend fields each account for more than 15% of our estimated proved reserves as of December 31, 2013. The table below provides production volume data for each of the fields for the years presented:

	Sales volumes
	Natural Gas		Oil & Condensate		Total
	(Mmcf)		(MBbls)		(Mmcfe)
For Year 2013
Bethany Longstreet		9,956		—		9,956
Beckville		2,539		17		2,641
Eagle Ford Shale Trend		1,129		1,138		7,955
For Year 2012
Bethany Longstreet		8,852		—		8,852
Beckville		3,208		21		3,337
Eagle Ford Shale Trend		1,142		960		6,902
For Year 2011
Bethany Longstreet		14,962		—		14,962
Beckville		4,372		30		4,551
Eagle Ford Shale Trend		838		464		3,624

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For a discussion of comparative changes in our sales volumes, revenues and operating expenses for the three years ended December 31, 2013, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Results of Operations.”

Oil and Natural Gas Marketing and Major Customers

Marketing. Our natural gas production is sold under spot or market-sensitive contracts to various natural gas purchasers on short-term contracts. Our oil production is sold to various purchasers under short-term rollover agreements based on current market prices.

Customers. Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. Revenues from the largest of these sources as a percent of oil and natural gas revenues for the year ended December 31, 2013 were as follows:

	2013
BP Energy Company		64	%
Genesis Crude Oil, LP		7	%

Competition

The oil and natural gas industry is highly competitive. Major and independent oil and natural gas companies, drilling and production acquisition programs and individual producers and operators are active bidders for desirable oil and natural gas properties, as well as the equipment and labor required to operate those properties. Many competitors have financial resources substantially greater than ours, and staffs and facilities substantially larger than us.

Employees

At February 18, 2014, we had 103 full-time employees in our Houston administrative office and our two field offices, none of whom is represented by any labor union. We closed our Shreveport office on December 31, 2013. We regularly use the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design, well-site supervision, permitting and environmental assessment. Independent contractors usually perform field and on-site production operation services for us, including gauging, maintenance, dispatching, inspection, and well testing.

Regulations

The availability of a ready market for any oil and natural gas production depends upon numerous factors beyond our control. These factors include regulation of oil and natural gas production, federal and state regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be “shut-in” because of an oversupply of natural gas or the lack of an available natural gas pipeline in the areas in which we may conduct operations. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies as well.

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Environmental and Occupational Health and Safety Matters

General

Our operations are subject to stringent and complex federal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. Compliance with these laws and regulations may require the acquisition of permits before drilling or other related activity commences, restrict the type, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling and production activities on certain lands lying within wilderness, wetlands and other protected areas, impose specific health and safety criteria addressing worker protection, and impose substantial liabilities for pollution arising from drilling and production operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that may limit or prohibit some or all of our operations.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and, any changes in environmental laws and regulations that result in more stringent and costly well construction, drilling, waste management or completion activities or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business. While we believe that we are in substantial compliance with current applicable federal and state environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations or financial condition, there is no assurance that we will be able to remain in compliance in the future with such existing or any new laws and regulations or that such future compliance will not have a material adverse effect on our business and operating results.

The following is a summary of the more significant existing environmental laws to which our business operations are subject and with which compliance may have a material adverse effect on our capital expenditures, earnings or competitive position.

Hazardous Substances and Wastes

The Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred, and companies that disposed or arranged for the disposal of hazardous substances released at the site. Under CERCLA, these persons may be subject to joint and several, strict liabilities for remediation cost at the site, natural resource damages and for the costs of certain health studies. Additionally, it is not uncommon for neighboring landowners and other third parties to file tort claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. We generate materials in the course of our operations that are regulated as hazardous substances.

We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes that impose stringent requirements related to the handling and disposal of non-hazardous and hazardous wastes. There exists an exclusion under RCRA from the definition of hazardous wastes for drilling fluids, produced waters and certain other wastes generated in the exploration, development or production of oil and natural gas, efforts have been made from time to time to remove this exclusion such that those wastes would be regulated under the more rigorous RCRA hazardous waste standards. A loss of this RCRA exclusion could result in increased costs to us and the oil and gas industry in general to manage and dispose of generated wastes.

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We currently own or lease, and in the past have owned or leased, properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes and petroleum hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties whose treatment and disposal of hazardous substances, wastes and petroleum hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges and Subsurface Injections

The Federal Water Pollution Control Act, as amended, (“Clean Water Act”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into state and federal waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the U.S. Environmental Protection Agency (“EPA”) or an analogous state agency. Spill prevention, control and countermeasure (“SPCC”) plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In addition, the Oil Pollution Act of 1990, as amended (“OPA”), imposes a variety of requirements related to the prevention of oil spills into navigable waters as well as liabilities for oil cleanup costs, natural resource damages and a variety of public and private damages that may result from such oil spills.

The disposal of oil and natural gas wastes into underground injection wells are subject to the federal Safe Drinking Water Act, as amended (“SDWA”), and analogous state laws. Under Part C of the SDWA, the EPA established the Underground Injection Control Program, which establishes requirements for permitting, testing, monitoring, recordkeeping and reporting of injection well activities as well as a prohibition against the migration of fluid containing any contaminants into underground sources of drinking water. State programs may have analogous permitting and operational requirements. Any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource, and imposition of liability by third parties for property damages and personal injury.

Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in our drilling and completion programs. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and has published draft permitting guidance addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking in the Semi-annual Regulatory Agenda published on July 3, 2013, on such disclosure regulations. In addition, Congress has from

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time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, including Louisiana and Texas, where we operate, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nevertheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review in 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities in 2014. These studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

Air Emissions

The Federal Clean Air Act, as amended (“CAA”), and comparable state laws, regulate emissions of various air pollutants from many sources in the United States, including crude oil and natural gas production activities through air emissions standards, construction and operating programs and the imposition of other compliance requirements. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions of certain pollutants. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. For example, in 2012, the EPA published final rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare. However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors and from pneumatic controllers and storage vessels. Compliance with these requirements could increase our costs of development and production, which costs could be significant.

Climate Change

Based on findings by the EPA in December 2009 that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of

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such gases are contributing to the warming of the earth’s atmosphere and other climatic changes, the EPA has adopted regulations under existing provisions of the CAA that, among things, establish pre-construction and operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. This rule could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources that exceed GHG emission threshold levels. The EPA also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, including, among others, certain onshore and offshore oil and natural gas production facilities, which include certain of our operations. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.

Congress has from time to time considered legislation to reduce emissions of GHGs but it has not adopted such legislation in recent years. A number of state and regional efforts have emerged that seek to reduce GHG emissions by means of cap and trade programs that often require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production interests and operations.

Endangered Species

The Federal Endangered Species Act, as amended (“ESA”), and analogous state laws restrict activities that could have an adverse effect on threatened or endangered species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Some of our operations may be located in or near areas that are designated as habitat for endangered or threatened species. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to our activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of numerous species as endangered or threatened under the ESA before the completion of the agency’s 2017 fiscal year. The presence of protected species or the designation of previously unidentified endangered or threatened species could impair our ability to timely complete well drilling and development and could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

Employee Health and Safety

We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended, (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act, as amended, and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws relating to worker health and safety.

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Other Laws and Regulations

State statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. In addition, there are state statutes, rules and regulations governing conservation matters, including the unitization or pooling of oil and natural gas properties, establishment of maximum rates of production from oil and natural gas wells and the spacing, plugging and abandonment of such wells. Such statutes and regulations may limit the rate at which oil and natural gas could otherwise be produced from our properties and may restrict the number of wells that may be drilled on a particular lease or in a particular field.

Item 1A. Risk Factors

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

The Company has 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 the Company’s 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. The Company has based these forward-looking statements on its current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by the Company in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it 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; the Company undertakes 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 the Company’s expectations include, but are not limited to, the following risk and uncertainties:

• planned capital expenditures;

• future drilling activity;

• our financial condition;

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

• the market prices of oil and natural gas;

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

• financial market conditions and availability of capital;

• production;

• hedging arrangements;

• future cash flows and borrowings;

• litigation matters;

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• 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 are doing business;

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

• the creditworthiness of our financial counterparties and operation partners;

• the securities, capital or credit markets;

• our ability to repay our debt; and

• other factors discussed below and elsewhere in this Annual Report on Form 10-K and in our other public filings, press releases and discussions with our management.

Our actual production, revenues and expenditures related to our reserves are likely to differ from our estimates of proved reserves. We may experience production that is less than estimated and drilling costs that are greater than estimated in our reserve report. These differences may be material.

The proved oil and natural gas reserve information included in this report are estimates. These estimates are based on reports prepared by NSAI and RSC, our independent reserve engineers, and were calculated using the unweighted average of first-day-of-the-month oil and natural gas prices in 2013. These prices will change and may be lower at the time of production than those prices that prevailed during 2013. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:

• historical production from the area compared with production from other similar producing wells;

• the assumed effects of regulations by governmental agencies;

• assumptions concerning future oil and natural gas prices; and

• assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.

Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:

• the quantities of oil and natural gas that are ultimately recovered;

• the production and operating costs incurred;

• the amount and timing of future development expenditures; and

• future oil and natural gas sales prices.

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material. The discounted future net cash flows included in this document should not be considered as the current market value of the estimated oil and natural gas reserves attributable to our properties. As required by the SEC, the standardized measure of discounted future net cash flows from proved reserves are generally based on 12-month average prices and costs as of the date of the

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estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:

• the amount and timing of actual production;

• supply and demand for oil and natural gas;

• increases or decreases in consumption; and

• changes in governmental regulations or taxation.

In addition, the 10% discount factor, which is required by the SEC to be used to calculate discounted future net cash flows for reporting purposes, and which we use in calculating our PV-10, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Our operations are subject to governmental risks that may impact our operations.

Our operations have been, and at times in the future may be, affected by political developments and are subject to complex federal, state, tribal, local and other laws and regulations such as restrictions on production, permitting and changes in taxes, deductions, royalties and other amounts payable to governments or governmental agencies or price gathering-rate controls. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state, tribal and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.

Our operations are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities.

Our oil and natural gas exploration and production operations are subject to stringent and complex federal, regional, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of permits, including drilling permits, before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations as a result of our handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to our operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to strict, joint and several liabilities for the removal or remediation of previously released materials or property contamination. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. Changes in environmental laws and regulations occur frequently; for example, a number of state and regional legal initiatives have emerged in recent years that seek to reduce GHG emissions and the EPA, based on its findings that emissions of GHGs present a

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danger to public health and the environment, has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, restrict emissions of GHGs and require the monitoring and reporting of GHG emissions from specified onshore and offshore production sources in the United States on an annual basis, which includes certain of our operations. Any changes in legal requirements that restrict emissions or releases of GHGs or other pollutants or result in more stringent or costly well drilling, construction, completion or water management activities, or waste control, handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance, may reduce demand for the oil and gas we produce and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as government reviews of such activity could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations such as shales. The process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. The process is typically regulated by state oil and natural gas commissions, but due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, including Louisiana and Texas, where we operate, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and EPA expects to issue a draft report for public comment and peer review in 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities in 2014. These studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

Our future revenues are dependent on the ability to successfully complete drilling activity.

Drilling and exploration are the main methods we utilize to replace our reserves. However, drilling and exploration operations may not result in any increases in reserves for various reasons. Exploration activities involve numerous risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

• lack of acceptable prospective acreage;

• inadequate capital resources;

• unexpected drilling conditions;

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• pressure or irregularities in formations;

• equipment failures or accidents;

• unavailability or high cost of drilling rigs, equipment or labor;

• reductions in oil and natural gas prices;

• limitations in the market for oil and natural gas;

• title problems;

• compliance with governmental regulations;

• mechanical difficulties; and

• risks associated with horizontal drilling.

Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain.

In addition, while lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically, higher oil and natural gas prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increased costs for, such drilling equipment, services and personnel. Such shortages could restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could adversely affect our ability to increase our reserves and production and reduce our revenues.

Oil and natural gas prices are volatile; a sustained decrease in the price of oil or natural gas would adversely impact our business.

Our success will depend on the market prices of oil and natural gas. These market prices tend to fluctuate significantly in response to factors beyond our control. The prices we receive for our crude oil production are based on global market conditions. The general pace of global economic growth, the continued instability in the Middle East and other oil and natural gas producing regions and actions of the Organization of Petroleum Exporting Countries and its maintenance of production constraints, as well as other economic, political, and environmental factors will continue to affect world supply and prices. Domestic natural gas prices fluctuate significantly in response to numerous factors including U.S. economic conditions, weather patterns, other factors affecting demand such as substitute fuels, the impact of drilling levels on crude oil and natural gas supply, and the environmental and access issues that limit future drilling activities for the industry.

Natural gas and crude oil prices are extremely volatile. Average oil and natural gas prices varied substantially during the past few years. Any actual or anticipated reduction in natural gas and crude oil and prices may further depress the level of exploration, drilling and production activity. We expect that commodity prices will continue to fluctuate significantly in the future.

Changes in commodity prices significantly affect our capital resources, liquidity and expected operating results. Our average realized prices for natural gas increased slightly in 2013 but still remain below average historical prices. These lower prices, coupled with the slow recovery in financial markets that has significantly limited and increased the cost of capital, have compelled most oil and natural gas producers, including us, to reduce the level of exploration, drilling and production activity. This will have a significant effect on our capital resources, liquidity and expected operating results. Any sustained reductions in oil and natural gas prices will directly affect our revenues and can indirectly impact expected production by changing the amount of funds available to us to reinvest in exploration and development activities. Further reductions in oil and natural gas prices could also reduce the quantities of reserves that are commercially recoverable. A reduction in our reserves

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could have other adverse consequences including a possible downward redetermination of the availability of borrowings under our senior credit facility, which would restrict our liquidity. Additionally, further or continued declines in prices could result in non-cash charges to earnings due to impairment write downs. Any such writedown could have a material adverse effect on our results of operations in the period taken.

We have limited experience drilling wells on our Tuscaloosa Marine Shale trend acreage, which has a limited operational history and is subject to more uncertainties than our drilling program in more established formations.

We, along with other operators, have begun drilling wells in the Tuscaloosa Marine Shale trend only recently. Accordingly, we have limited information on which we can determine optimum drilling and completion strategies, or estimate production decline rates or recoverable reserves from drilling on our acreage in this trend. Our drilling plans with respect to the Tuscaloosa Marine Shale trend are flexible and depend on a number of factors, including the extent to which our initial wells in the trend are commercially successful.

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

We intend to devote a substantial portion of our near term capital expenditures on drilling and completion activity (including facilities and infrastructure) in the Tuscaloosa Marine Shale. The results of these investments may not prove as attractive as we anticipate, and the concentration of such funding and activity in the Tuscaloosa Marine Shale will 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.

The enactment of derivatives legislation 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.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (CFTC) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position-limits rule was vacated by the U.S. District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce cash available to us for capital expenditures; therefore reducing our ability to execute hedges to reduce risk and protect cash flow. The proposed margin rules are not yet final, and therefore the impact of those

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provisions on us is uncertain at this time. The Dodd-Frank Act and regulations may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.

The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts or, increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of proposed legislation.

Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively impact the value of an investment in our common stock.

Our use of oil and natural gas price hedging contracts may limit future revenues from price increases and result in significant fluctuations in our net income.

We use hedging transactions with respect to a portion of our oil and natural gas production to achieve more predictable cash flow and to reduce our exposure to price fluctuations. While the use of hedging transactions limits the downside risk of price declines, their use may also limit future revenues from price increases. We hedged approximately 32% (approximately 5% of natural gas production and approximately 99% of oil production) of our total production volumes for the year ended December 31, 2013.

Our results of operations may be negatively impacted by our commodity derivative instruments and fixed price forward sales contracts in the future and these instruments may limit any benefit we would receive from increases in the prices for oil and natural gas.

	December 31,
Oil and Natural Gas Derivatives (in thousands)	2013			2012			2011
Realized gain (loss) on oil and natural gas derivatives	$	(3,786	)	$	73,160		$	31,305
Unrealized gain (loss) on oil and natural gas derivatives		3,084			(41,278	)		3,234
Total gain (loss) on oil and natural gas derivatives	$	(702	)	$	31,882		$	34,539

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We account for our oil and natural gas derivatives using fair value accounting standards. Each derivative is recorded on the balance sheet as an asset or liability at its fair value. Additionally, changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met at the time the derivative contract is executed. We have elected not to apply hedge accounting treatment to our swaps and, as such, all changes in the fair value of these instruments are recognized in earnings. Our fixed price physical contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment.

In the future, we will continue to be exposed to volatility in earnings resulting from changes in the fair value of our derivative instruments. See Note 8-“Derivative Activities” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.

Because our operations require significant capital expenditures, we may not have the funds available to replace reserves, maintain production or maintain interests in our properties.

We must make a substantial amount of capital expenditures for the acquisition, exploration and development of oil and natural gas reserves. Historically, we have paid for these expenditures with cash from operating activities, proceeds from debt and equity financings and asset sales. Our revenues or cash flows could be reduced because of lower oil and natural gas prices or for other reasons. If our revenues or cash flows decrease, we may not have the funds available to replace reserves or maintain production at current levels. If this occurs, our production will decline over time. Other sources of financing may not be available to us if our cash flows from operations are not sufficient to fund our capital expenditure requirements. We cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms. If funding is not available as needed, or is available only on more expensive or otherwise unfavorable terms, we may be unable to meet our obligations as they come due or we may be unable to implement our development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. Where we are not the majority owner or operator of an oil and natural gas property, we may have no control over the timing or amount of capital expenditures associated with the particular property. If we cannot fund such capital expenditures, our interests in some properties may be reduced or forfeited.

If we are unable to replace reserves, we may not be able to sustain production at present levels.

Our future success depends largely upon our ability to find, acquire or develop additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves will decline over time. In addition, approximately 61% of our total estimated proved reserves by volume at December 31, 2013, were undeveloped. By their nature, estimates of proved undeveloped reserves and timing of their production are less certain particularly because we may chose not to develop such reserves on anticipated schedules in future adverse oil or natural gas price environments. Recovery of such reserves will require significant capital expenditures and successful drilling operations. The lack of availability of sufficient capital to fund such future operations could materially hinder or delay our replacement of produced reserves. We may not be able to successfully find and produce reserves economically in the future. In addition, we may not be able to acquire proved reserves at acceptable costs.

We may incur substantial impairment writedowns.

If management’s estimates of the recoverable proved reserves on a property are revised downward or if oil and natural gas prices decline, we may be required to record additional non-cash impairment writedowns in the future, which would result in a negative impact to our financial position. Furthermore, any sustained decline in oil and natural gas prices may require us to make further impairments. We review our proved oil and natural gas properties for impairment on a depletable unit basis when circumstances suggest there is a need for such a

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review. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and natural gas prices to the estimated future production of oil and natural gas reserves over the economic life of the property. Future net cash flows are based upon our independent reservoir engineers’ estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions. For each property determined to be impaired, we recognize an impairment loss equal to the difference between the estimated fair value and the carrying value of the property on a depletable unit basis.

Fair value is estimated to be the present value of expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future cash flows and fair value. For the years ended December 31, 2012 and 2011, we recorded impairments related to oil and natural gas properties of $47.8 million and $8.1 million, respectively.

Management’s assumptions used in calculating oil and natural gas reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. Any change could cause impairment expense to be recorded, impacting our net income or loss and our basis in the related asset. Any change in reserves directly impacts our estimate of future cash flows from the property, as well as the property’s fair value. Additionally, as management’s views related to future prices change, the change will affect the estimate of future net cash flows and the fair value estimates. Changes in either of these amounts will directly impact the calculation of impairment.

A majority of our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.

Essentially all of our estimated proved reserves at December 31, 2013, and all our production during 2013 were associated with our Louisiana, Texas and Mississippi properties which include the Tuscaloosa Marine Shale, Haynesville Shale, Cotton Valley Taylor Sand and Eagle Ford Shale Trend. Accordingly, if the level of production from these properties substantially declines or is otherwise subject to a disruption in our operations resulting from operational problems, government intervention (including potential regulation or limitation of the use of high pressure fracture stimulation techniques in these formations) or natural disasters, it could have a material adverse effect on our overall production level and our revenue.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. For example, Chesapeake operates certain properties in the Haynesville Shale. We have less ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them versus those fields in which we are the operator. Our dependence on the operator and other working interest owners for these projects and our reduced influence or ability to control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital and lead to unexpected future costs.

Our ability to sell natural gas and receive market prices for our natural gas may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions.

We operate primarily in (i) South Texas, which includes the Eagle Ford Shale Trend, (ii) Northwest Louisiana and East Texas, which includes the Haynesville Shale and Cotton Valley Taylor Sand and (iii) Southwest Mississippi and Southeast Louisiana which includes the Tuscaloosa Marine Shale. A number of companies are currently operating in the Haynesville Shale and Eagle Ford Shale. If drilling in these areas

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continues to be successful, the amount of natural gas being produced could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in this region. If this occurs, it will be necessary for new pipelines and gathering systems to be built. Because of the current economic climate, certain pipeline projects that are planned for Northwest Louisiana and East Texas may not occur or may be substantially delayed for lack of financing. In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our natural gas to interstate pipelines. In such an event, we might have to shut in our wells awaiting a pipeline connection or capacity or sell natural gas production at significantly lower prices than those quoted on New York Mercantile Exchange (NYMEX) or that we currently project, which would adversely affect our results of operations.

A portion of our oil and natural gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.

Our debt instruments impose restrictions on us that may affect our ability to successfully operate our business.

Our Senior Credit Facility contains customary restrictions, including covenants limiting our ability to incur additional debt, grant liens, make investments, consolidate, merge or acquire other businesses, sell assets, pay dividends and other distributions and enter into transactions with affiliates. We also are required to meet specified financial ratios under the terms of our Senior Credit Facility. As of December 31, 2013, we were in compliance with all the financial covenants of our Senior Credit Facility. These restrictions may make it difficult for us to successfully execute our business strategy or to compete in our industry with companies not similarly restricted. The Senior Credit Facility matures on February 25, 2016. Any replacement credit facility may have more restrictive covenants or provide us with less borrowing capacity.

We may be unable to identify liabilities associated with the properties that we acquire or obtain protection from sellers against them.

The acquisition of properties requires us to assess a number of factors, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well, facility or pipeline. We cannot necessarily observe structural and environmental problems, such as pipeline corrosion or subsurface groundwater contamination, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities relating to the acquired assets and indemnities are unlikely to cover liabilities relating to the time periods after closing. We may be required to assume any risk relating to the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. The incurrence of an unexpected liability could have a material adverse effect on our financial position and results of operations.

Competition in the oil and natural gas industry is intense, and we are smaller and have a more limited operating history than some of our competitors.

We compete with major and independent oil and natural gas companies for property acquisitions. We also compete for the equipment and labor required to operate and to develop these properties. Some of our competitors have substantially greater financial and other resources than us. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for oil and natural gas properties and may be able to define, evaluate, bid for and acquire a greater number of properties

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than we can. Our ability to acquire additional properties and develop new and existing properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

Our success depends on our management team and other key personnel, the loss of any of whom could disrupt our business operations.

Our success will depend on our ability to retain and attract experienced engineers, geoscientists and other professional staff. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.

The oil and natural gas exploration and production business involves many uncertainties, economic risks and operating risks that can prevent us from realizing profits and can cause substantial losses.

The nature of the oil and natural gas exploration and production business involves certain operating hazards such as:

• well blowouts;

• cratering;

• explosions;

• uncontrollable flows of oil, natural gas, brine or well fluids;

• fires;

• formations with abnormal pressures;

• shortages of, or delays in, obtaining water for hydraulic fracturing operations;

• environmental hazards such as crude oil spills;

• natural gas leaks

• pipeline and tank ruptures;

• unauthorized discharges of brine, well stimulation and completion fluids or toxic gases into the environment;

• encountering naturally occurring radioactive materials;

• other pollution; and

• other hazards and risks.

Any of these operating hazards could result in substantial losses to us. As a result, substantial liabilities to third parties or governmental entities may be incurred. The payment of these amounts could reduce or eliminate the funds available for exploration, development or acquisitions. These reductions in funds could result in a loss of our properties. Additionally, some of our oil and natural gas operations are located in areas that are subject to weather disturbances such as hurricanes. Some of these disturbances can be severe enough to cause substantial damage to facilities and possibly interrupt production.

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We cannot be certain that the insurance coverage maintained by us will be adequate to cover all losses that may be sustained in connection with all oil and natural gas activities.

We maintain general and excess liability policies, which we consider to be reasonable and consistent with industry standards. These policies generally cover:

• personal injury;

• bodily injury;

• third party property damage;

• medical expenses;

• legal defense costs;

• pollution in some cases;

• well blowouts in some cases; and

• workers compensation.

As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position and results of operations. There can be no assurance that the insurance coverage that we maintain will be sufficient to cover every claim made against us in the future. A loss in connection with our oil and natural gas properties could have a materially adverse effect on our financial position and results of operations to the extent that the insurance coverage provided under our policies cover only a portion of any such loss.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

A discussion of our current legal proceedings is set forth in Note 9—“Commitments and Contingencies” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.

Item 4. Mine Safety Disclosures

Not Applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Price of Our Common Stock

Our common stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “GDP”.

At February 18, 2014, the number of holders of record of our common stock was 1,184 and 44,272,621 shares were outstanding. High and low closing sales prices for our common stock for each quarter during 2013 and 2012 as reported on the NYSE were as follows:

	2013				2012
	High		Low		High		Low
First Quarter	$	15.65	$	9.40	$	20.04	$	14.06
Second Quarter		15.85		11.49		19.49		12.29
Third Quarter		27.32		12.38		15.12		10.86
Fourth Quarter		28.04		15.93		13.68		7.95

Dividends

We have neither declared nor paid any cash dividends on our common stock and do not anticipate declaring any dividends in the foreseeable future. We expect to retain our cash for the operation and expansion of our business, including exploration, development and production activities. In addition, our senior bank credit facility contains restrictions on the payment of dividends to the holders of common stock. For additional information, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Issuer Repurchases of Equity Securities

We made no open market repurchases of our common stock for the year ended December 31, 2013. Through November of 2013, when an employee’s restricted stock shares vested we (at the option of the employee) generally withheld an amount of shares necessary to cover that employees’ minimum payroll tax withholding obligation. We then remitted the withholding amount to the appropriate tax authority and subsequently retired the shares. During 2013, we withheld 3,469 shares of common stock from issuance in this manner and paid less than $0.1 million to the appropriate tax authority as minimum withholding. Beginning in December 2013, we no longer offer our employees the option to have the Company withhold shares to cover the employee’s taxes on restricted stock vestings.

For information on securities authorized for issuance under our equity compensation plans, see Item 12. “Security Ownership of Certain Beneficial Owners and Management.”

Unregistered Sales of Equity Securities

None not previously reported by us on a Current Report on Form 8-K.

Performance

The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the company specifically incorporates it by reference into such filing.

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The following graph compares the cumulative five-year total return to stockholders on our common stock relative to the cumulative total returns of the S&P 500 Index and the Russell 2000 Index. An investment of $100 is assumed to have been made in our common stock and the indexes on December 31, 2008 and its relative performance is tracked through December 31, 2013.

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Item 6. Selected Financial Data

The following table sets forth our selected financial data and other operating information. The selected consolidated financial data in the table are derived from our consolidated financial statements. This data should be read in conjunction with the consolidated financial statements, related notes and other financial information included herein.

	Summary Financial Information
	2013			2012			2011			2010			2009
	(In thousands, except per share amounts)
Revenues:
Oil and natural gas revenues	$	202,557		$	180,543		$	200,456		$	148,031		$	110,784
Other		738			302			613			302			(358	)
		203,295			180,845			201,069			148,333			110,426
Operating Expenses:
Lease operating expense		27,293			25,938			21,490			26,306			30,188
Production and other taxes		9,812			8,115			5,450			3,627			4,317
Transportation and processing		10,498			13,900			12,974			9,856			9,459
Depreciation, depletion and amortization		135,357			141,222			131,811			105,913			160,361
Exploration		22,774			23,122			8,289			10,152			9,292
Impairment		—			47,818			8,111			234,887			208,905
General and administrative		34,069			28,930			29,799			30,918			27,923
Loss (gain) on sale of assets		(107	)		(44,606	)		(236	)		2,824			(297	)
Other		(91	)		91			448			4,268			—
		239,605			244,530			218,136			428,751			450,148
Operating loss		(36,310	)		(63,685	)		(17,067	)		(280,418	)		(339,722	)
Other income (expense):
Interest expense		(51,187	)		(52,403	)		(49,351	)		(37,179	)		(26,148	)
Interest income and other		101			4			59			117			458
Gain (loss) on derivatives not designated as hedges		(702	)		31,882			34,539			55,275			47,115
Gain (loss) on extinguishment of debt		(7,088	)		—			62			—			—
		(58,876	)		(20,517	)		(14,691	)		18,213			21,425
Loss before income taxes		(95,186	)		(84,202	)		(31,758	)		(262,205	)		(318,297	)
Income tax benefit		—			—			—			85			67,311
Net loss		(95,186	)		(84,202	)		(31,758	)		(262,120	)		(250,986	)
Preferred stock dividends		18,604			6,047			6,047			6,047			6,047
Net loss applicable to common stock	$	(113,790	)	$	(90,249	)	$	(37,805	)	$	(268,167	)	$	(257,033	)
PER COMMON SHARE
Net loss applicable to common stock—basic	$	(2.99	)	$	(2.48	)	$	(1.05	)	$	(7.47	)	$	(7.17	)
Net loss applicable to common stock—diluted	$	(2.99	)	$	(2.48	)	$	(1.05	)	$	(7.47	)	$	(7.17	)
Weighted average common shares outstanding—basic		38,098			36,390			36,124			35,921			35,866
Weighted average common shares outstanding—diluted		38,098			36,390			36,124			35,921			35,866
Balance Sheet Data:
Total assets	$	974,213		$	768,385		$	862,103		$	664,577		$	860,274
Total long-term debt		435,866			568,671			566,126			179,171			330,147
Stockholders’ equity		356,523			60,245			143,700			183,972			445,385

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Annual Report on Form 10-K in Item 8, and the information set forth in Risk Factors under Item 1A.

Overview

We are an independent oil and natural gas company engaged in the exploration, development and production of properties primarily in (i) South Texas, which includes the Eagle Ford Shale Trend, (ii) Northwest Louisiana and East Texas, which includes the Haynesville Shale, Bossier Shale and Cotton Valley Trends and (iii) Southwest Mississippi and Southeast Louisiana which includes 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. In our opinion, on a long term basis, growth in oil and natural gas reserves and production on a cost-effective basis are the most important indicators of performance success for an independent oil and natural gas company.

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

We place primary emphasis on our 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), non-cash general and administrative expenses and impairments.

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

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.

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• 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 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 December 31, 2013, we held 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 December 31, 2013, we had a borrowing base of $270 million under our $600 million Second Amended and Restated Credit Agreement (including all amendments, the “Senior Credit Facility”), on which we had no amounts drawn. 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.

2013 Highlights

• We increased our annual oil production from 21% in 2012 to 29% of our equivalent production in 2013 and achieved average daily oil production volume growth of 22% for the year, with production volumes growing from an average of 2,992 barrels of oil per day in 2012 to 3,665 barrels of oil per day in 2013.

• We ended the year with estimated proved reserves of approximately 452 Bcfe (approximately 330 Bcf of natural gas, 6 MMBbls of NGL and 14 MMBbls of oil and condensate), with a PV-10 of $472 million and a standardized measure of $468 million, approximately 39% of which is proved developed.

• We conducted drilling operations on 25 gross (16 net) wells in 2013, including 16 gross (11 net) Eagle Ford Shale Trend wells in South Texas and 9 gross (5) wells in the TMS. We added 43 gross (24 net) wells to production in 2013, of which 23 gross (15 net) were in the Eagle Ford Shale Trend, 7 gross (3 net) in the TMS and 13 gross (6 net) in the Haynesville Shale Trend.

• In August 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 $21.7 million.

• We completed our underwritten public offerings of our 10% Series C Cumulative Preferred Stock (“Series C Preferred Stock”) and 9.75% Series D Cumulative Preferred Stock (“Series D Preferred Stock) realizing combined net proceeds of approximately $230.6 million. We used the proceeds to fund the acquisition of the TMS properties from Devon and to repay amounts outstanding under our Senior Credit Facility.

• In October 2013, we completed our 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 $166.1 million to the fund the acceleration of our drilling program in the TMS.

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Eagle Ford Shale Trend

We entered into the Eagle Ford Shale Trend in April 2010, with our leasehold position located in La Salle and Frio counties, Texas. We held approximately 45,000 gross (30,000 net) acres as of December 31, 2013, all of which are either producing from or prospective for the Eagle Ford Shale Trend. During 2013, we conducted drilling operations on approximately 16 gross (11 net) Eagle Ford Shale Trend wells. In 2014, we plan to spend approximately $45 million, representing approximately 12% of our 2014 capital budget, to conduct drilling operations on eight gross (five net) wells in the Eagle Ford Shale Trend.

Tuscaloosa Marine Shale Trend

We held approximately 415,000 gross (306,000 net) acres in the TMS as of December 31, 2013. Our acreage is located in Southeastern Louisiana and Southwestern Mississippi. Since December 31, 2012, we have added approximately 257,000 gross (172,000 net) acres in the trend.

In August 2013, we closed on the acquisition of a 66.7% working interest in producing assets and approximately 277,000 gross acres in the TMS from Devon, with an effective date of March 1, 2013. The remaining 33.3% working interest owner in the producing assets and leasehold has elected to retain its interest and participate with us in developing the assets. We will prioritize the acreage, with the ultimate number of retained acreage to be based on geologic location, timing and amount of lease extension payments and the overall future success of the play. The closing price after purchase price adjustments was $24.6 million. The closing price included $2.9 million of lease extensions executed by Devon on our behalf after the effective date. The adjusted purchase price net of lease extension costs totaled $21.7 million.

During 2013, we conducted drilling operations on approximately 9 gross (5 net), TMS wells. During the quarter ended December 31, 2013, we added a second rig in the TMS and commenced drilling operations on the Weyerhauser 51H, the first well drilled by us on the acreage we acquired from Devon. For 2014, we have set a preliminary capital budget of $300 million in the TMS to drill 32 gross (24 net) wells on both our legacy and recently acquired TMS acreage. Our preliminary 2014 capital budget is predicated on adding a third rig in the first quarter and two additional rigs in the second quarter, for a total of up to five horizontal rigs running in the TMS by the second half of 2014, depending on well results.

Haynesville Shale Trend

Our relatively low risk development acreage in this trend is primarily centered in and around Rusk, Panola, Angelina and Nacogdoches counties, Texas and DeSoto and Caddo parishes, Louisiana. We hold approximately 112,000 gross (67,000 net) acres as of December 31, 2013 producing from or prospective for the Haynesville Shale. During the year-ended December 31, 2013, we added 13 gross (6 net) previously cased wells to production primarily from our joint venture in Northeast Louisiana operated by Chesapeake Energy Company. Our net production volumes from our Haynesville Shale wells aggregated approximately 39,400 Mcfe per day in 2013, or approximately 52% of our total oil and natural gas production for the year. In 2014, we plan to spend approximately $15-$20 million to conduct drilling operations on 1-2 gross wells in our Angelina River/ Shelby Trough Trend.

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 currently hold approximately 61,000 gross (39,000 net) acres as of December 31, 2013. Our net production volumes from our core Haynesville Shale wells totaled approximately 32,700 Mcfe per day in 2013, or approximately 43% of our total production for the year.

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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 32,000 gross (25,000 net) acres as of December 31, 2013. Our net production volumes from our Shelby Trough wells totaled approximately 4,000 Mcfe per day in 2013, or approximately 5% of our total production for the year.

Results of Operations

For the year ended December 31, 2013, we reported net loss applicable to common stock of $113.8 million, or $2.99 per share (basic and diluted), on operating revenues of $203.3 million. This compares to net loss applicable to common stock of $90.2 million, or $2.48 per share (basic and diluted), for the year ended December 31, 2012 and net loss applicable to common stock of $37.8 million, or $1.05 per share (basic and diluted), for the year ended December 31, 2011.

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.

Summary Operating Information:	Year End December 31,											Year End December 31,
	2013			2012			Variance					2012			2011			Variance
Revenues:
Natural gas	$	66,180		$	71,136		$	(4,956	)	(7	%)	$	71,136		$	141,665		$	(70,529	)	(50	%)
Oil and condensate		136,377			109,407			26,970		25	%		109,407			58,791			50,616		86	%
Natural gas, oil and condensate		202,557			180,543			22,014		12	%		180,543			200,456			(19,913	)	(10	%)
Operating revenues		203,295			180,845			22,450		12	%		180,845			201,069			(20,224	)	10	%
Operating expenses		239,605			244,530			(4,925	)	(2	%)		244,530			218,136			26,394		12	%
Operating loss		(36,310	)		(63,685	)		27,375		43	%		(63,685	)		(17,067	)		(46,618	)	(273	%)
Net loss applicable to common stock		(113,790	)		(90,249	)		(23,541	)	(26	%)		(90,249	)		(37,805	)		(52,444	)	(139	%)
Net Production:
Natural gas (Mmcf)		19,760			24,844			(5,084	)	(20	%)		24,844			36,167			(11,323	)	(31	%)
Oil and condensate (MBbls)		1,338			1,095			243		22	%		1,095			644			451		70	%
Total (Mmcfe)		27,785			31,415			(3,630	)	(12	%)		31,415			40,029			(8,614	)	(22	%)
Average daily production (Mcfe/d)		76,124			85,832			(9,708	)	(11	%)		85,832			109,669			(23,837	)	(22	%)
Average Realized Sales Price Per Unit:
Natural gas (per Mcf)	$	3.35		$	2.86		$	0.49		17	%	$	2.86		$	3.92		$	(1.06	)	(27	%)
Natural gas (per Mcf) including the effect of realized gains/losses on derivatives		3.38			5.50			(2.12	)	(39	%)		5.50			4.70			0.80		17	%
Oil and condensate (per Bbl)		101.96			99.91			2.05		2	%		99.91			91.34			8.57		9	%
Oil and condensate (per Bbl) including the effect of realized gains/losses on derivatives		98.70			106.98			(8.28	)	(8	%)		106.98			96.23			10.75		11	%
Average realized price (per Mcfe)		7.29			5.75			1.54		27	%		5.75			5.01			0.74		15	%

Oil and Natural Gas Revenue

Oil and natural gas revenues increased in 2013 compared to 2012 reflecting an increase in oil and condensate production and an increase in our average realized sales prices, partially offset by a decline in natural gas production. The increases in oil production and realized sales prices compared to 2012 contributed

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approximately $39.1 million to the increase in oil and natural gas revenue partially offset by decreased natural gas production compared to 2012 of approximately $17.1 million. During 2013, we focused on increasing oil production, which we are able to sell at a more favorable relative price than natural gas. In 2013, 67% of our oil and natural gas revenue was attributable to oil compared to 61% in 2012.

The difference between our average realized prices inclusive of hedge realizations in the years ended December 31, 2013 and 2012 relates to our oil and natural gas swap contracts. During 2013, we had 10,000 MMBtus per day hedged only for the fourth quarter of 2013 at a floor price of $4.18 per MMBtu and during the full year of 2012 we had 60,000 MMBtus per day hedged at a floor price of $5.78 per MMBtu. During 2013, we had an average of 3,626 Bbls per day hedged at an average fixed price of $94.65 per Bbl. During 2012, we had 3,500 Bbls per day hedged at an average fixed price of $100.12 per Bbl.

Our oil and natural gas revenues decreased in 2012 compared to 2011 reflecting a net decrease in production, partially offset by a net increase in average realized sales prices. The decrease in net production compared to 2011 contributed approximately $49.5 million to the decrease in oil and natural gas revenue partially offset by the increase in average realized sales price compared to 2011 of approximately $29.6 million. We focused on drilling oil wells in 2012 resulting in a corresponding decline in our natural gas production. The average realized sales price increase of 15% in 2012 was led by the increased oil production which we sold at a more favorable relative price than our natural gas production. In 2012, 61% of our oil and natural gas revenue was attributable to oil revenue compared to 29% in 2011.

The difference between our average realized prices inclusive of the hedge realizations in the year ended December 31, 2012 and 2011 periods relates to our natural gas and oil swap contracts. During 2012, we had 60,000 MMBtus per day hedged at a floor price of $5.78 per MMBtu and during 2011 we had 40,000 MMBtus per day hedged at a floor price of $6.00 per MMBtu. During 2012, we had 3,500 Bbls per day hedged at an average fixed price of $100.12 per Bbl and during 2011 we had 2,000 Bbls per day hedged at an average fixed price of $100.20 per Bbl.

Operating Expenses

Our operating expenses in 2013 include $4.4 million of dry hole expense and lease expirations of $11.5 million. When eliminating these items from the operating expenses in both 2013 and 2012, the adjusted operating expense of $223.7 million in 2013 decreased 3%, or $8.0 million, from adjusted operating expense of $231.7 million in 2012. This decrease in operating expenses is driven by decreased depreciation, depletion and amortization (“DD&A”) expense.

Our operating expenses in 2012 included a $47.8 million asset impairment, $12.8 million dry hole expense, other expense of $0.1 million and a gain on the sale of assets of $44.6 million. When eliminating these items from the operating expenses in both 2012 and 2011, the adjusted operating expense of $228.4 million in 2012 increased 9%, or $18.6 million, from adjusted operating expense of $209.8 million in 2011. This increase in operating expenses was driven by increased DD&A expense.

	Year Ended December 31,									Year Ended December 31,
(in thousands)	2013		2012		Variance					2012		2011		Variance
Lease operating expenses	$	27,293	$	25,938	$	1,355		5	%	$	25,938	$	21,490	$	4,448	21	%
Production and other taxes		9,812		8,115		1,697		21	%		8,115		5,450		2,665	49	%
Transportation and processing		10,498		13,900		(3,402	)	(24	%)		13,900		12,974		926	7	%
Exploration		22,774		23,122		(348	)	(2	%)		23,122		8,289		14,833	179	%

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	Year Ended December 31,									Year Ended December 31,
Per Mcfe	2013		2012		Variance					2012		2011		Variance
Lease operating expenses	$	0.98	$	0.83	$	0.15		18	%	$	0.83	$	0.54	$	0.29	54	%
Production and other taxes		0.35		0.26		0.09		35	%		0.26		0.14		0.12	86	%
Transportation and processing		0.38		0.44		(0.06	)	(14	%)		0.44		0.32		0.12	38	%
Exploration		0.82		0.74		0.08		11	%		0.74		0.21		0.53	252	%

Lease Operating Expense

Our lease operating expense (“LOE”) during 2013 included an expense of $6.0 million in workover costs which added $0.22 per Mcfe to unit expense. Our LOE during 2012 included $4.3 million in workover costs, which added $0.13 per Mcfe to unit expense. LOE excluding workover expense decreased in 2013 compared to 2012. The absence of $2.1 million in LOE for the South Henderson Field, which we sold in late September 2012, was partially by offset by increased expense related to oil production. Our LOE will generally trend 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 2013 compared to 21% in 2012.

Our LOE during 2012 included an expense of $4.3 million in workover costs which added $0.13 per Mcfe to unit expense compared to only $0.3 million in 2011. LOE excluding workover expense decreased in 2012 compared to 2011. The absence of $0.6 million in LOE for the South Henderson Field, which we sold in late September 2012, was partially by offset by increased expense related to oil production. Our LOE will generally trend higher as we add more oil wells to our well count which carry higher operating costs than natural gas wells. Oil contributed 21% to our equivalent production volumes in 2012 compared to 10% in 2011.

Production and Other Taxes

Our production and other taxes for the year 2013 include production tax of $7.4 million and ad valorem tax of $2.4 million. We did not earn any tax credits in 2013 attributed to Tight Gas Sands (“TGS”) credits for our wells in the State of Texas. Production and other taxes for the year 2012 include production tax of $5.6 million and ad valorem tax of $2.5 million. Production tax in 2012 is net of $1.6 million of tax credits attributed to TGS credits. Production and other taxes for the year 2011 include production tax of $3.9 million and ad valorem tax of $1.6 million. Production tax in 2011 is net of $1.6 million of tax credits attributed to TGS credits. The higher production tax for both periods relate to the increasing portion of our production coming from Eagle Ford Shale oil wells, which are not exempt from Texas severance tax, and the expiration of the Louisiana tax exemption on certain of our horizontal natural gas wells.

The TGS tax credits allow for reduced and in many cases the complete elimination of severance taxes in the State of Texas for qualifying wells for up to ten years of production. We only accrue for such credits once we have been notified of the State’s approval. 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.

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

The sale of the South Henderson Field in September 2012, which contributed $2.3 million of expense in 2012, and overall lower natural gas production, which carries substantially all of our transportation and processing cost, decreased our transportation and processing expense in 2013 compared to 2012.

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Our transportation and processing expense increased in 2012 compared to 2011. The increase in expense was partially a result of higher gathering costs related to our gas production from the Eagle Ford Shale Trend wells but more predominately related to the renegotiation of certain natural gas gathering and processing contracts. We pay higher gathering and processing fees on our gas production from our Eagle Ford Shale Trend wells, as compared to our gas production from our Haynesville Shale wells, however, we also receive higher prices for our gas production from our Eagle Ford Shale Trend wells due to the presence of natural gas liquids.

Exploration

Exploration expense decreased slightly in 2013 from 2012. Dry hole cost declined $8.4 million as we suspended operations on the Denkmann 33H-1 and expensed $12.8 million of the well cost in 2012. We opted not to drill a new well utilizing the existing well bore and expensed the remaining well costs of $4.4 million in 2013. Lease amortization in 2013 increased $7.8 million from $5.9 million in 2012 to $13.7 million in 2013 which mostly offsets the decrease in dry hole cost. Lease amortization in 2013 included lease expiration expense. As part of our ongoing review of capital allocation, we elected not to renew certain expiring leases in non-core Eagle Ford Shale Trend acreage resulting in $11.1 million lease expiration expense.

The increase in exploration expenses in 2012 compared to 2011 is attributable primarily to $12.8 million in dry hole expense related to the Denkmann 33H-1 well drilled on our TMS acreage. Exploration expense for 2012 also includes $5.9 million of amortization of leasehold costs.

	Year Ended December 31,											Year Ended December 31,
(in thousands)	2013			2012			Variance					2012			2011			Variance
Depreciation, depletion & amortization	$	135,357		$	141,222		$	(5,865	)	(4	%)	$	141,222		$	131,811		$	9,411		7	%
Impairment		—			47,818			(47,818	)	(100	%)		47,818			8,111			39,707		490	%
General & administrative		34,069			28,930			5,139		18	%		28,930			29,799			(869	)	(3	%)
Gain on sale of assets		(107	)		(44,606	)		44,499		100	%		(44,606	)		(236	)		(44,370	)	NM
	Year Ended December 31,											Year Ended December 31,
Per Mcfe	2013			2012			Variance					2012			2011			Variance
Depreciation, depletion & amortization	$	4.87		$	4.50		$	0.37		8	%	$	4.50		$	3.29		$	1.21		37	%
Impairment		—			1.52			(1.52	)	(100	%)		1.52			0.20			1.32		660	%
General & administrative		1.23			0.92			0.31		34	%		0.92			0.74			0.18		24	%
Gain on sale of assets		—			(1.42	)		1.42		100	%		(1.42	)		(0.01	)		(1.41	)	NM

NM—Not meaningful.

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

DD&A expense for 2013 decreased as compared to 2012 despite an increase in the DD&A rate between the periods. The decrease in DD&A expense resulted from lower 2013 production volumes. We calculated DD&A rates for the first six months of 2013 using our December 31, 2012 reports. We calculated DD&A rates for the second half of 2013 using our mid-year reserve reports as of June 30, 2013. 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 partially offset the DD&A rate increase for the second half of 2013 and for 2013 overall.

DD&A expense for 2012 increased as compared to 2011 as a result of higher production from our Eagle Ford Shale Trend oil properties which carried a relatively higher DD&A rate. We calculated the first six months of 2012 DD&A rates using the December 31, 2011 reserves and the last six months of 2012 DD&A rates using our June 30, 2012 mid-year reserves. Since our Eagle Ford Shale properties were still in the early development

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stage at the time, both reserve reports had not yet fully reflected the reserves associated with our development resulting in a higher DD&A rate.

Impairment

We recorded impairment expense of $47.8 million in the year ended December 31, 2012, $44.4 million of which related to our Angelina River trend field and is a result of declining natural gas prices. We calculated the fair value of our oil and natural gas properties based on a natural gas five year average futures strip price of $4.17 per MMcf.

We recorded impairment expense of $8.1 million on four fields for the year ended December 31, 2011. The majority of the impairment expense is related to our non-core Beckville field due to falling natural gas prices.

General and Administrative Expense (“G&A”)

G&A expense increased in 2013 compared to 2012. The increase reflects higher compensation expense, increased share based compensation and the restructuring cost of approximately $1.2 million associated with closing our Shreveport 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 $7.7 million in 2013 compared to $6.9 million in 2012. The increase in stock compensation reflects a restricted stock awarded to certain key employees in June 2012, which was amortized for the full year in 2013.

Our G&A expense decreased in 2012 compared to 2011. Salaries and payroll taxes were lower in 2012 as a result of the timing of filling open positions, partially offset by increased stock compensation for a one time issuance to certain key employees. Also contributing to the decrease was the expiration of a previous incentive program for certain employees based on stock price performance.

Share based compensation expense, which is a non-cash item, amounted to $6.9 million in 2012 compared to $6.5 million in 2011.

Gain on Sale of Assets

We recorded a gain of $44.6 million in the year ended December 31, 2012 representing the sale of our interest in three non-core properties, which included the sale of our South Henderson field in East Texas for a gain of $44.0 million.

Other Income (Expense)

	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Other Income (Expense):
Interest expense	$	(51,187	)	$	(52,403	)	$	(49,351	)
Interest income and other		101			4			59
Gain (loss) on derivatives not designated as hedges		(702	)		31,882			34,539
Gain (loss) on extinguishment of debt		(7,088	)		—			62
Income tax benefit (expense)		—			—			—
Average funded borrowings adjusted for debt discount		552,935			606,801			508,323
Average funded borrowings		567,494			631,129			543,688

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Interest Expense

Our interest expense decreased in 2013 compared to 2012 as a result of the lower average level of outstanding debt in 2013. The lower average level of debt resulted from the repayment of the amounts due under our Senior Credit Facility with proceeds from our equity offerings. Non-cash interest of $12.7 million is included in the interest expense reported for the year 2013.

Our interest expense increased in 2012 compared to 2011 as a result of the higher average level of outstanding debt in 2012. The higher average level of debt resulted from increased borrowings under our Senior Credit Facility. Non-cash interest of $12.8 million is included in the interest expense reported for the year 2012.

Gain (Loss) on 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 expensed 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 extinguishment of debt of $4.8 million.

On October 1, 2013, we exchanged $57.4 million of our 2029 Notes for $57.0 million of new 2032 Notes. We retired the 2029 Notes with a carrying of $54.3 million and expensed unamortized debt issuance cost of $0.3 million, offset by $9.9 million attributable to the fair value of the equity portion of the 2029 Notes. The 2032 Notes had a fair value of $66.2 million, which resulted in a loss of on extinguishment of debt of $2.3 million.

Gain (Loss) on Derivatives Not Designated as Hedges

We produce and sell oil and natural gas into a market where selling prices are historically volatile. We enter into swap contracts, swaptions or other derivative agreements from time to time to manage our exposure to commodity price risk for a portion of our production.

Loss on derivatives not designated as hedges was $0.7 million for 2013. The loss includes a realized loss of $3.8 million and an unrealized gain of $3.1 million. The unrealized gain reflects the lower average futures strip prices from December 31, 2012 as compared to December 31, 2013 in addition to the expiration of the oil swaption contract.

Gain on derivatives not designated as hedges was $31.9 million for 2012. The gain includes a realized gain of $73.2 million on our natural gas derivatives and an unrealized loss of $41.3 million for the change in fair value of our oil and natural gas commodity contracts. The unrealized gain reflects the lower average futures strip prices from December 31, 2011 as compared to December 31, 2012.

Gain on derivatives not designated as hedges was $34.5 million for 2011. The gain includes a realized gain of $31.3 million on our natural gas derivatives and an unrealized gain of $3.2 million for the change in fair value of our oil and natural gas commodity contracts. The unrealized gain reflects the lower average futures strip prices from December 31, 2010 as compared to December 31, 2011.

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

Income Tax Benefit

We recorded no income tax benefit for the years 2013, 2012 and 2011. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2009 after considering all available positive and

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negative evidence related to the realization of our deferred tax assets. Our assessment of the realization of our deferred tax assets has not changed and as a result, we continue to maintain a full valuation allowance for our net deferred asset as of December 31, 2013.

Adjusted EBITDAX (1)

	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Net loss (GAAP)	$	(95,186	)	$	(84,202	)	$	(31,758	)
Exploration Expense		22,774			23,122			8,289
Depreciation, depletion and amortization		135,357			141,222			131,811
Impairment		—			47,818			8,111
(Gain) Loss on extinguishment of debt		7,088			—			(62	)
Stock based compensation.		7,680			6,903			6,495
Interest expense		51,187			52,403			49,351
Unrealized (gain) loss on derivatives not designated as hedges		(3,084	)		41,278			(3,234	)
Other items (2)		(299	)		(44,519	)		153
Adjusted EBITDAX		125,517		$	184,025		$	169,156

(1) Adjusted EBITDAX as defined in our Senior Credit Facility, is earnings before interest expense, income tax, DD&A, exploration expense and impairment of oil and gas properties. In calculating EBITDAX for this purpose, earnings include realized gains (losses) from derivatives but exclude unrealized gains (losses) from derivatives. 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 other, (gain) loss on sale of assets, income taxes and other expense.

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 gas exploration and production industry.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Our primary sources of cash during 2013 were from cash on hand, cash flow from operating activities, borrowings under our Senior Credit Facility and proceeds from our Series C and D Preferred Stock and our common stock offerings. We used cash in 2013 to fund our capital spending program and the TMS acreage acquisition, pay down debt, pay interest on outstanding debt, and pay preferred stock dividends. Our primary sources of cash during 2012 were from cash on hand, cash flow from operating activities, borrowings under our Senior Credit Facility and proceeds from sale of assets. We primarily used cash in 2012 to fund our capital spending program, pay interest on outstanding debt and pay preferred stock dividends. Our primary sources of cash during 2011 were from cash on hand, cash flow from operating activities, borrowings under our Senior Credit Facility and proceeds from the issuance of our 2019 Notes. We primarily used cash in 2011 to fund our capital spending program, retire debt, pay interest on outstanding debt and pay preferred stock dividends.

We have in place a $600 million Senior Credit Facility, entered into with a syndicate of U.S. and international lenders. As of December 31, 2013, we had a $270 million borrowing base with no outstanding borrowings. Pursuant to the terms of the Senior Credit Facility, borrowing base redeterminations occur on a

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semi-annual basis on April 1 and October 1. We were in compliance with existing covenants under the Senior Credit Facility at December 31, 2013.

As of December 31, 2013, we held $51.8 million in an escrow account to provide for the repurchase of the remaining 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 $51.8 million in escrow as of December 31, 2013 is reflected in our financial statements as Restricted Cash. 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. Holders of the remaining outstanding 2029 Notes have the right to require us to purchase some or all of such notes at par on October 1, 2014. Accordingly, the $49.7 million carrying value of the 2029 Notes, which is net of debt discount, is reflected on our December 31, 2013 financial statements as a current liability.

Outlook

Our total capital expenditures for 2014 are expected to be approximately $375 million. We plan to spend approximately $360 million on drilling and completion cost and $15 million on leasehold and infrastructure costs. We plan to focus our 2014 drilling efforts in the TMS by allocating approximately $300 million, or 80% of our total capital budget, to the play. We will continue to develop our oil assets in the Eagle Ford Shale Trend and plan to spend approximately $45 million in the play for 2014. We plan on spending approximately $15 million in 2014 on gas directed drilling activity in the Haynesville Shale trend on our Angelina River Trend acreage. We believe that our expected level of operating cash flows, cash on hand as of December 31, 2013, and our borrowing base will be sufficient to fund our projected operational and capital programs for 2014.

In addition, to support 2014 cash flows, we entered into strategic derivative positions as of December 31, 2013, covering approximately 61% of our anticipated oil and condensate sales volumes for 2014. See Note 8—“Derivative Activities” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.

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.

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.

Our next borrowing base redetermination is currently scheduled for April 2014. At December 31, 2013, our borrowing base under our Senior Credit Facility is $270 million with no outstanding borrowings. Our borrowing base is typically reviewed twice annually by our bank group using their price deck applied to our most recent reserve report, in this case as of December 31, 2013.

The following section discusses significant sources and uses of cash for the three-year period ending December 31, 2013. Forward-looking information related to our liquidity and capital resources are discussed above in Outlook.

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Capital Resources

We intend to fund our capital expenditure program, contractual commitments, including settlement of derivative contracts and future acquisitions with cash flows from our operations and borrowings under our Senior Credit Facility. In the future, as we have done on several occasions over the last few years, we may also access public markets to issue additional debt and/or equity securities.

Our primary sources of cash during 2013 were from cash on hand, cash flow from operating activities, borrowings under our Senior Credit Facility and the proceeds from our underwritten public offerings of $110 million of our Series C Preferred Stock, $130 million of our Series D Preferred Stock and 6,900,000 shares of our common stock.

Our primary sources of cash during 2012 were from cash on hand, cash flow from operating activities, borrowings under our Senior Credit Facility and proceeds from the sale of assets.

Our primary sources of cash during 2011 were from cash on hand, cash flow from operating activities, available borrowings under our Senior Credit Facility and the proceeds from our issuance of the 2019 Notes.

The table below summarizes the sources of cash during 2013, 2012 and 2011:

	Year Ended December 31,									Year Ended December 31,
Cash flow statement information:	2013			2012			Variance			2012			2011			Variance
	(In thousands)
Net Cash:
Provided by operating activities	$	71,405		$	173,789		$	(102,384	)	$	173,789		$	136,340		$	37,449
Used in investing activities		(250,654	)		(161,494	)		(89,160	)		(161,494	)		(335,064	)		173,570
Provided by (used) financing activities		227,281			(14,454	)		241,735			(14,454	)		184,283			(198,737	)
Increase (decrease) in cash and cash equivalents	$	48,032		$	(2,159	)	$	50,191		$	(2,159	)	$	(14,441	)	$	12,282

At December 31, 2013, we had a working capital deficit of $20.8 million and long-term debt, net of debt discount, of $435.9 million.

Cash Flows

Year ended December 31, 2013 Compared to Year Ended December 31, 2012

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 decreased $102.4 million in 2013. The three main drivers for the variance between 2013 and 2012 include the realized gain (loss) on derivatives not designated as hedges, operating revenues and changes in working capital. The gain on derivatives not designated as hedges of $73.2 million for 2012 compared to a loss on derivatives not designated as hedges of $3.8 mllion in 2013 led to a variance of $77.0 million. Partially offsetting this variance was an increase in operating revenues of $22.5 million from 2012 of $180.5 million to $202.6 million for 2013. The combination of increases in oil sales volumes and realized sales prices drove the increase in operating revenues. Oil volumes as a percentage of total volumes grew to 29% in 2013 from 21% in 2012. Average realized sales prices increased to $7.29 per Mcfe in 2013 from $5.75 per Mcfe in 2012. The difference in changes in working capital of $45 million from 2012 of $32.3 million in positive working capital changes to $12.7 million in negative working capital changes for 2013 results from timing of payments related to drilling and completion activity for each respective year-end.

Investing activities    Net cash used in investing activities was $250.7 million for the year ended December 31, 2013, compared to $161.5 million for 2012. While we booked capital expenditures of

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approximately $256.8 million in 2013, we paid out cash amounts totaling $251.1 million in 2013, with differences being attributed to approximately $22.5 million in drilling and completion costs which were accrued at December 31, 2013 and non-cash asset retirement obligation additions of $1.8 million offset by $19.2 million in drilling and completion cost accrued at December 31, 2012 of which $18.6 million was paid in 2013. Net cash used in investing activities was offset by the receipt of $0.4 million of cash proceeds from the sale of fixed assets in 2013.

We drilled 25 gross wells in 2013 compared to 46 gross wells in 2012. Of the $251.1 million cash spent in 2013, $209.0 million was for drilling and completion activities (of which $18.6 million related to 2012 wells); $23.5 million was for property acquisition, $14.9 million was for leasehold acquisition, $1.1 million for facilities and infrastructure, $1.9 million for capital workovers and $0.7 million for furniture, fixtures and equipment. Of the $252.4 million cash spent in 2012, $220.8 million was for drilling and completion activities (of which $20.8 million related to 2011 wells); $22.3 million was for leasehold acquisition, $5.2 million for facilities and infrastructure, $3.5 million for capital workovers and $0.6 million for furniture, fixtures and equipment.

Financing activities.    The cash provided by financing activities for 2013 consisted primarily of $230.6 million in net proceeds from our offerings of Series C and Series D Preferred Stock and net proceeds of $166.1 million from our offering of common stock. The cash used in financing activities consisted primarily of the net $95 million repayment of the amount outstanding under our Senior Credit Facility, establishment of escrow of $51.8 million for the repayment of our 2029 Notes, payment of preferred stock dividends of $18.6 million and $4.8 million in debt and equity issuance costs.

Year ended December 31, 2012 Compared to Year Ended December 31, 2011

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 increased $37.4 million in 2012. Derivative settlements of $41.8 million and working capital savings of $22.9 million increased operating cash offset by a $13.3 million decreased related to oil and natural gas revenue year over year with (i) a 22% decrease in total production offset by (ii) growth in oil volumes as a percentage of total volumes from 10% in 2011 to 21% in 2012, and (iii) a 15% increase in the average realized sales price from $5.01 to $5.75 per Mcfe. Operating costs increase related to increased cost of producing oil reduced cash by $9.4 million in 2012 as compared to 2011. Decreases to cash flow in 2012 also include (i) $4.6 million in additional cash interest paid in 2012 as we replaced $175 million of our 3.25% Convertible Senior Notes due 2026 with $275 million of our 8.875% 2019 Notes.

Investing activities.    Net cash used in investing activities was $161.5 million for the year ended December 31, 2012, compared to $335.1 million for 2011. While we booked capital expenditures of approximately $252.0 million in 2012, we paid out cash amounts totaling $252.4 million in 2012, with differences being attributed to approximately $19.2 million in drilling and completion costs which were accrued at December 31, 2012 and non-cash asset retirement obligation additions of $2.7 million offset by $22.3 million in drilling and completion cost accrued at December 31, 2011 and paid in 2012. Net cash used in investing activities was offset by the receipt of $90.9 million of cash proceeds from the sale of fixed assets in 2012.

We drilled 46 gross wells in 2012 compared to 47 gross wells in 2011. Of the $252.4 million cash spent in 2012, $220.8 million was for drilling and completion activities (of which $20.8 million related to 2011 wells); $22.3 million was for leasehold acquisition, $5.2 million for facilities and infrastructure, $3.5 million for capital workovers and $0.6 million for furniture, fixtures and equipment. Of the $335.2 million cash spent in 2011, $299.9 million was for drilling and completion activities (of which $29.8 million related to 2010 wells); $22.7 million was for leasehold acquisition, $9.2 million for facilities and infrastructure, $2.8 million for capital workovers and $0.6 million for furniture, fixtures and equipment.

Financing activities.    The net cash provided by financing activities for 2012 consisted primarily of net payments under our Senior Credit Facility of $7.5 million and preferred stock dividends of $6.1 million. We had

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$95.0 million of borrowings outstanding under our Senior Credit Facility as of December 31, 2012. In 2011, the cash provided by financing activities consisted primarily of proceeds from the issuance of $275 million of the 2019 Notes and net borrowings under our Senior Credit Facility of $102.5 million.

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

	December 31, 2013						December 31, 2012
	Principal		Carrying Amount		Fair Value (1)		Principal		Carrying Amount		Fair Value (1)
Senior Credit Facility	$	—	$	—	$	—	$	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)		51,816		49,663		51,686		218,500		198,242		204,975
5.0% Convertible Senior Notes due 2032 (3)		167,405		160,437		171,863		—		—		—
8.875% Senior Notes due 2019		275,000		275,000		288,063		275,000		275,000		261,250
Total debt	$	494,650	$	485,529	$	512,041	$	588,929	$	568,671	$	561,654

(1) The carrying amount for the Senior Credit Facility represents fair value as the variable interest rates are reflective of current market conditions. The fair value of the notes 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 debt discount was $2.1 million and $20.3 million as of December 31, 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 $7.0 million as of December 31, 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):

	December 31, 2013					December 31, 2012					December 31, 2011
	Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate
Senior Credit Facility		3,936		5.3	%		5,114		3.7	%		3,180		—	*
3.25% Convertible Senior Notes due 2026		14		3.3	%		14		3.3	%		4,305		9.0	%
5.0% Convertible Senior Notes due 2029		17,400		11.4	%		21,968		11.4	%		20,948		10.5	%
5.0% Convertible Senior Notes due 2032		4,529		8.8	%		—		—			—		—
8.875% Senior Notes due 2019		25,308		9.2	%		25,308		9.2	%		20,910		8.9	%

* An Effective Interest Rate Calculation is not meaningful for the year ended December 31, 2011 since there were only minimal average amounts borrowed under the Senior Credit Facility during those periods.

Senior Credit Facility

Total lender commitments under the Senior Credit Facility are $600 million subject to borrowing base limitations. 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 December 31, 2013, we had no amounts outstanding under the Senior Credit Facility. Substantially all of our assets are pledged as collateral to secure the Senior Credit Facility.

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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 permitted 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 December 31, 2013, we had deposited $51.8 million in an escrow account to provide for the repurchase of the remaining outstanding principal amount of our 2029 Notes, which is reflected on our financial statements 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 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.

We were in compliance with all the financial covenants of the Senior Credit Facility as of December 31, 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 senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The 2019 Notes accrue interest at a rate of 8.875% annually, and interest is paid semi-annually in arrears on March 15 and September 15. The 2019 Notes are guaranteed by our subsidiary that also guarantees our Senior Credit Facility.

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

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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.

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. During 2013, we entered into separate, privately negotiated exchange agreements under which we retired $166.7 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 principal amount of $166.3 million. The 2032 Notes will mature on October 1, 2032. As of December 31, 2013, $51.8 million in aggregate principal amount of the 2029 Notes remain outstanding with terms unchanged. 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.

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).

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 2013 exchange transactions, $2.1 million of debt discount remains to be amortized on the 2029 Notes as of December 31, 2013. Investors can demand repayment on October 1, 2014, accordingly the $49.7 million carrying value of the 2029 Notes is reflected on our financial statements as a current liability.

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5% Convertible Senior Notes due 2032

In 2013, we entered into separate, privately negotiated exchange agreements under which we retired $166.7 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 principal amount of $166.3 million. The 2032 Notes will mature on October 1, 2032.

Many terms of the 2032 Notes 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 accretes 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 recorded $1.2 million of accretion during 2013.

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, these exchange transactions are 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 $166.7 million of outstanding 2029 Notes with a carrying value of $156.9 million and wrote-off unamortized debt issuance cost of $0.8 million offset by $20.0 million attributable to the fair value of the equity portion of the 2029 Notes. The 2032 Notes had a fair value of $183.2 million which resulted in a loss on the early extinguishment of debt of $7.1 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 $158.8 million of the fair value to the 2032 Note to debt component which compared to the face results in a debt discount of $7.5 million which will be amortized through the first put date of October 1, 2017. Additionally, we recorded $24.4 million within additional paid-in capital representing the equity component of the 2032 Notes. A debt discount of $7.0 million remains to be amortized on the 2032 Notes as of December 31, 2013.

3.25% Convertible Senior Notes Due 2026

During the year ended December 31, 2011, we repurchased $174.6 million of our 2026 Notes for $176.4 million using a portion of the net proceeds from the issuance of our 2019 Notes. We recorded a $0.1 million gain on the early extinguishment of debt related to the repurchase for the year ended December 31, 2011.

At December 31, 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.

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

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

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

For additional information on our debt instruments, see Note 4—“Debt” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.

5.375% Series B Convertible Preferred Stock

Our 5.375% Series B Convertible Preferred Stock (the “Series B Preferred Stock”) was initially issued on December 21, 2005, in a private placement of 1,650,000 shares for net proceeds of $79.8 million (after offering costs of $2.7 million). Each share of the Series B Preferred Stock has a liquidation preference of $50 per share, aggregating to $82.5 million, and bears a dividend of 5.375% per annum. Dividends are payable quarterly in arrears.

On January 23, 2006, the initial purchasers of the Series B Preferred Stock exercised their over-allotment option to purchase an additional 600,000 shares at the same price per share, resulting in net proceeds of $29.0 million, which was used to fund our 2006 capital expenditure program.

10% Series C Cumulative Preferred Stock

In April 2013, we issued $110 million of Series C Preferred Stock and received $105.4 million in 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 Series B Preferred Stock and our Series D 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.

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9.75% Series D Cumulative Preferred Stock

In August 2013, we issued $130 million of Series D Preferred Stock and received $124.9 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 Series B 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.

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.

Common Stock Offering

On October 21, 2013, we closed an underwritten public offering of 6.9 million shares of our common stock sold at a price to the public of $25.25 per share. We intend to use the $166.1 million in net proceeds from the offering to fund the acceleration of our drilling program in the TMS in 2014. Pending such use, we used a portion of the proceeds to fully repay amounts outstanding under our Senior Credit Facility.

For additional information on our debt and equity instruments, see Note 4—“Debt” and 7—“Stockholders’ Equity” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.

Credit Risks

Our exposure to non-payment or non-performance by our customers and counterparties presents a credit risk. Generally, non-payment or non-performance results from a customer’s or counterparty’s inability to satisfy obligations. We monitor the creditworthiness of our customers and counterparties and established credit limits according to our credit policies and guidelines. We have the ability to require cash collateral as well as letters of credit from our financial counterparties to mitigate our exposure above assigned credit thresholds. We routinely exercise our contractual right to net realized gains against realized losses when settling with our financial counterparties.

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Future Commitments

The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2013. In addition to the contractual obligations presented in the table below, our Consolidated Balance Sheet at December 31, 2013 reflects accrued interest on our bank debt of $10.7 million payable in the first half of 2014. For additional information see Note 4— “Long-Term Debt” and Note 9— “Commitments and Contingencies” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K

	Payment due by Period
			(in thousands)
	Note		Total		2014		2015		2016		2017		2018 and After
Contractual Obligations
Debt (1)		4	$	507,620	$	51,816	$	—	$	—	$	180,375	$	275,429
Interest on notes		4		87,053		34,676		32,733		13,410		6,234		—
Office space leases		9		8,232		1,450		1,332		1,381		1,430		2,639
Office equipment leases		9		461		298		140		23		—		—
Drilling rigs & operations contracts		9		14,534		14,353		133		43		5		—
Transportation contracts		9		6,327		1,552		955		955		955		1,910
Total contractual obligations (2)			$	624,227	$	104,145	$	35,293	$	15,812	$	188,999	$	279,978

(1) The 2026 Notes have a provision at the end of years 5, 10 and 15, for the investors to demand payment on these dates; the first such date was December 1, 2011; all but the remaining $0.4 million were redeemed. The next ‘put’ date for the remaining 2026 Notes is December 1, 2016. The 2029 Notes have a provision by which on or after October 1, 2014, we may redeem all or a portion of the notes for cash and the investors may require us to repurchase the notes on each of October 1, 2014, 2019 and 2024. The 2032 Notes have a provision by which on or after October 1, 2017, we may redeem all or a portion of the notes for cash, and the investors may require us to repurchase the notes on each of October 1, 2017, 2022 and 2027.

(2) This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $20.9 million as of December 31, 2013. We record a separate liability for the fair value of this asset retirement obligation. See Note 3-“Asset Retirement Obligations” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K.

Summary of Critical Accounting Policies

The following summarizes several of our critical accounting policies. See a complete list in Note 1—“Description of Business and Accounting Policies” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.

Proved Oil and Natural Gas Reserves

Proved reserves are defined by the SEC as those quantities of oil and natural gas which, by analysis of geosciences and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimates if the extraction is by means not involving a well. Although our external engineers are knowledgeable of and follow the guidelines for reserves as established

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by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. Estimated reserves are often subject to future revision, certain of which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation rates used by us. We cannot predict the types of reserve revisions that will be required in future periods.

While the estimates of our proved reserves at December 31, 2013 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the SEC rules, those estimates could differ materially from our actual results.

Successful Efforts Accounting

We use the successful efforts method to account for exploration and development expenditures and to calculate DD&A. Unsuccessful exploration wells, as well as other exploration expenditures such as seismic costs, are expensed and can have a significant effect on operating results. Successful exploration drilling costs, all development capital expenditures and asset retirement costs are capitalized and systematically charged to expense using the units of production method based on proved developed oil and natural gas reserves as estimated by engineers. Leasehold costs are charged to expense using the units of production method based on total proved oil and natural gas reserves.

Fair Value Measurement

Fair value is defined by Accounting Standards Codification (“ASC”) 820 as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We carry our derivative instruments at fair value and measure their fair value by applying the income approach provided for ASC 820, using Level 2 inputs based on third-party quotes or available interest rate information and commodity pricing data obtained from third party pricing sources and our credit worthiness or that of our counterparties. We carry our oil and natural gas properties held for use at historical cost. We use Level 3 inputs, which are unobservable data such as discounted cash flow models or valuations, based on our various assumptions and future commodity prices to determine the fair value of our oil and natural gas properties in determining impairment. We carry cash and cash equivalents, account receivables and payables at carrying value which represent fair value because of the short-term nature of these instruments. For definitions for Level 1, Level 2 and Level 3 inputs see Note 1-“Description of Business and Accounting Policies” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.

Impairment of Properties

We monitor our long-lived assets recorded in oil and natural gas properties in the Consolidated Balance Sheets to ensure that they are not carried in excess of fair value. We must evaluate our properties for potential impairment when certain indicators or circumstances indicate that the carrying value of an asset could exceed its fair value. Performing these evaluations requires a significant amount of judgment since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable proved and probable oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or natural gas, unfavorable adjustments to reserves or other changes to contracts, environmental regulations or tax laws. We cannot predict the amount of impairment charges that may be recorded in the future.

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Asset Retirement Obligations

We make estimates of the future costs of the retirement obligations of our producing oil and natural gas properties in order to record the liability as required by the applicable accounting standard. This requirement necessitates us to make estimates of our property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.

Income Taxes

We are subject to income and other related taxes in areas in which we operate. When recording income tax expense, certain estimates are required by management due to timing and the impact of future events on when income tax expenses and benefits are recognized by us. We periodically evaluate our tax operating loss and other carry-forwards to determine whether a gross deferred tax asset, as well as a related valuation allowance, should be recognized in our financial statements.

Accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a 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. See Note 1-“Description of Business and Accounting Policies-Income Taxes” and Note 6-“Income Taxes” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.

Share-Based Compensation Plans

For all new, modified and unvested share-based payment transactions with employees, we measure the fair value on the grant date and recognize it as compensation expense over the requisite period. The fair value of each option award is estimated using a Black-Scholes option valuation model that requires us to develop estimates for assumptions used in the model. The Black-Scholes valuation model uses the following assumptions: 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.

New Accounting Pronouncements

See Note 1— “Description of Business and Accounting Policies”— “New Accounting Pronouncements” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.

Off-Balance Sheet Arrangements

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

Item 7A. 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

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instruments utilized by us include futures, swaps, options and fixed-price physical-delivery contracts. The volume of commodity derivative instruments utilized by us may vary from year to year and is governed by risk-management policies with levels of authority delegated by the 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—“Summary of Significant Accounting Policies”, Note 8—“Derivative Instruments” and Note 4—“Debt” in the Notes to Consolidated Financial Statements in Part II Item 8 of this Annual Report on Form 10-K.

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 write-down 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.

We had derivative instruments in place to reduce the price risk associated with production in 2014 of approximately 3,800 Bbls per day of crude oil as of December 31, 2013. At December 31, 2013, we had a net asset derivative position of $0.9 million related to these derivative instruments. Utilizing actual derivative contractual volumes, a hypothetical 10% increase in underlying commodity prices would have resulted in net derivative liability position of $18.2 million, while a hypothetical 10% decrease in underlying commodity prices would have increased the net derivative asset to $18.1 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.

Interest Rate Risk

As of December 31, 2013, we had no outstanding variable-rate debt and $485.5 million of principal fixed-rate debt. To the extent we incur borrowings under our Senior Credit Facility, our exposure to variable interest rates will increase. In the past, we have entered into interest rate swaps to help reduce our exposure to interest rate risk, and we may seek to do so in the future if we deem appropriate. As of December 31, 2013, we had no interest rate swaps.

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Item 8. Financial Statements and Supplementary Data

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Management’s Annual Report on Internal Controls over Financial Reporting		59
Report of Independent Registered Public Accounting Firm—Internal Controls over Financial Reporting		60
Report of Independent Registered Public Accounting Firm—Consolidated Financial Statements for the years ended December 31, 2013, 2012 and 2011		61
Consolidated Balance Sheets as of December 31, 2013 and 2012		62
Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011		63
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011		64
Consolidated Statements of Stockholders’ Equity for the years ended December  31, 2013, 2012 and 2011.		65
Notes to the Consolidated Financial Statements		66

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MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROLS OVER FINANCIAL  REPORTING

Management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and board of directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

We assessed the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (COSO). Based on our evaluation under the framework in Internal Control—Integrated Framework, we have concluded that our internal control over financial reporting was effective as of December 31, 2013. The effectiveness of our internal control over financial reporting as of December 31, 2013 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included on page 60.

Management of Goodrich Petroleum Corporation

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of

Goodrich Petroleum Corporation

We have audited Goodrich Petroleum Corporation and subsidiary’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). Goodrich Petroleum Corporation and subsidiary’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Controls Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Goodrich Petroleum Corporation and subsidiary maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2013 consolidated financial statements of Goodrich Petroleum Corporation and subsidiary and our report dated February 21, 2014, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 21, 2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of

Goodrich Petroleum Corporation

We have audited the accompanying consolidated balance sheets of Goodrich Petroleum Corporation and subsidiary as of December 31, 2013 and 2012, and the related consolidated statements of operations, cash flows, and stockholders’ equity, for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Goodrich Petroleum Corporation and subsidiary at December 31, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Goodrich Petroleum Corporation’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 21, 2014 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 21, 2014

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In Thousands)

	December 31,
	2013			2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	49,220		$	1,188
Restricted cash		51,816			—
Accounts receivable, trade and other, net of allowance		3,113			7,078
Accrued oil and natural gas revenue		19,455			19,054
Fair value of oil and natural gas derivatives		6,187			2,125
Inventory		2,076			2,202
Prepaid expenses and other		1,278			926
Total current assets		133,145			32,573
PROPERTY AND EQUIPMENT:
Oil and natural gas properties (successful efforts method)		1,838,220			1,619,914
Furniture, fixtures and equipment		6,960			6,212
		1,845,180			1,626,126
Less: Accumulated depletion, depreciation and amortization		(1,021,863	)		(906,377	)
Net property and equipment		823,317			719,749
Fair value of oil and natural gas derivatives		1,396			—
Deferred tax assets		665			636
Deferred financing cost and other		15,690			15,427
TOTAL ASSETS	$	974,213		$	768,385
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	50,551		$	73,094
Accrued liabilities		48,603			37,634
Accrued abandonment costs		99			168
Deferred tax liabilities current		665			636
Fair value of oil and natural gas derivatives		4,341			351
Current portion of debt		49,663			—
Total current liabilities		153,922			111,883
Long term debt		435,866			568,671
Accrued abandonment costs		20,757			18,138
Fair value of oil and natural gas derivatives		2,371			3,987
Transportation obligation		4,774			5,461
Total liabilities		617,690			708,140
Commitments and contingencies (See Note 9)
STOCKHOLDERS’ EQUITY:
Preferred stock: 10,000,000 shares $1.00 par value authorized:
Series B convertible preferred stock, issued and outstanding 2,250,000		2,250			2,250
Series C cumulative preferred stock, issued and outstanding 4,400 and zero shares, respectively		4			—
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 44,258,824 and 36,758,141 shares, respectively		8,852			7,352
Treasury stock (zero and 77,142 shares, respectively)		—			(639	)
Additional paid in capital		1,056,378			648,458
Retained earnings (accumulated deficit)		(710,966	)		(597,176	)
Total stockholders’ equity		356,523			60,245
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	974,213		$	768,385

See accompanying notes to consolidated financial statements.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

	Year Ended December 31,
	2013			2012			2011
REVENUES:
Oil and natural gas revenues	$	202,557		$	180,543		$	200,456
Other		738			302			613
		203,295			180,845			201,069
OPERATING EXPENSES:
Lease operating expense		27,293			25,938			21,490
Production and other taxes		9,812			8,115			5,450
Transportation and processing		10,498			13,900			12,974
Depreciation, depletion and amortization		135,357			141,222			131,811
Exploration		22,774			23,122			8,289
Impairment		—			47,818			8,111
General and administrative		34,069			28,930			29,799
Gain on sale of assets		(107	)		(44,606	)		(236	)
Other		(91	)		91			448
		239,605			244,530			218,136
Operating loss		(36,310	)		(63,685	)		(17,067	)
OTHER INCOME (EXPENSE):
Interest expense		(51,187	)		(52,403	)		(49,351	)
Interest income and other		101			4			59
Gain (loss) on derivatives not designated as hedges		(702	)		31,882			34,539
Gain (loss) on extinguishment of debt		(7,088	)		—			62
		(58,876	)		(20,517	)		(14,691	)
Loss before income taxes		(95,186	)		(84,202	)		(31,758	)
Income tax benefit		—			—			—
Net loss		(95,186	)		(84,202	)		(31,758	)
Preferred stock dividends		18,604			6,047			6,047
Net loss applicable to common stock	$	(113,790	)	$	(90,249	)	$	(37,805	)
PER COMMON SHARE
Net loss applicable to common stock—basic	$	(2.99	)	$	(2.48	)	$	(1.05	)
Net loss applicable to common stock—diluted	$	(2.99	)	$	(2.48	)	$	(1.05	)
Weighted average common shares outstanding—basic		38,098			36,390			36,124
Weighted average common shares outstanding—diluted		38,098			36,390			36,124

See accompanying notes to consolidated financial statements.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

	Year Ended December 31,
	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(95,186	)	$	(84,202	)	$	(31,758	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization		135,357			141,222			131,811
Unrealized (gain) loss on derivatives not designated as hedges		(3,084	)		41,278			(3,234	)
Impairment		—			47,818			8,111
Exploration costs		4,728			12,848			—
Amortization of leasehold costs		13,675			5,948			5,487
Share based compensation (non-cash)		7,680			6,903			6,495
Gain on sale of assets		(107	)		(44,606	)		(236	)
(Gain) loss on extinguishment of debt		7,088			—			(62	)
Amortization of finance cost and debt discount		12,745			12,819			14,351
Amortization of transportation obligation		1,226			1,457			2,873
Change in assets and liabilities:
Restricted cash		—			—			4,232
Accounts receivable, trade and other, net of allowance		3,965			580			355
Income taxes receivable/payable		—			277			3,995
Accrued oil and natural gas revenue		(401	)		1,399			(5,500	)
Inventory		126			6,415			(796	)
Prepaid expenses and other		386			3,356			(2,953	)
Accounts payable		(22,543	)		26,999			(1,079	)
Accrued liabilities		5,750			(6,722	)		4,248
Net cash provided by operating activities		71,405			173,789			136,340
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(251,103	)		(252,416	)		(335,236	)
Proceeds from sale of assets		449			90,922			172
Net cash used in investing activities		(250,654	)		(161,494	)		(335,064	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments of bank borrowings		(382,800	)		(132,000	)		(42,000	)
Proceeds from bank borrowings		287,800			124,500			144,500
Proceeds from preferred stock offering		230,625			—			—
Proceeds from equity offering		166,149			—			—
Proceeds from high yield offering		—			—			275,000
Repurchase of convertible notes		—			—			(176,422	)
Debt issuance costs		(4,636	)		(66	)		(9,341	)
Preferred stock dividends		(18,604	)		(6,047	)		(6,047	)
Cash restricted for repurchase of convertible notes		(51,816	)		—			—
Exercise of stock options and warrants		807			16			—
Other		(244	)		(857	)		(1,407	)
Net cash provided by (used in) financing activities		227,281			(14,454	)		184,283
Increase (decrease) in cash and cash equivalents		48,032			(2,159	)		(14,441	)
Cash and cash equivalents, beginning of period		1,188			3,347			17,788
Cash and cash equivalents, end of period	$	49,220		$	1,188		$	3,347
Supplemental disclosures of cash flow information:
Cash paid during the year for interest	$	38,087		$	39,516		$	35,000
Cash paid during the year for taxes	$	—		$	—		$	—

See accompanying notes to consolidated financial statements.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In Thousands)

	Preferred Stock				Common Stock						Additional Paid-in Capital			Treasury Stock						Retained Earnings/ (Deficit)			Total Stockholders’ Equity
	Shares		Value		Shares			Value						Shares			Value
Balance at January 1, 2011		2,250	$	2,250		37,685		$	7,212		$	643,828			(12	)	$	(196	)	$	(469,122	)	$	183,972
Net loss		—		—		—			—			—			—			—			(31,758	)		(31,758	)
Employee stock plans		—		—		350			70			6,425			—			—			—			6,495
Equity portion of convertible notes redeemed		—		—		—			—			(7,944	)		—			—			—			(7,944	)
Director stock grants		—		—		21			4			385			—			—			—			389
Repurchases of stock		—		—		—			—			—			(86	)		(1,407	)		—			(1,407	)
Retirement of stock		—		—		(53	)		(10	)		(904	)		53			914			—			—
Shares returned pursuant to Share Lending Agreement		—		—		(1,624	)		—			—			—			—			—			—
Dividends		—		—		—			—			—			—			—			(6,047	)		(6,047	)
Balance at December 31, 2011		2,250	$	2,250		36,379		$	7,276		$	641,790			(45	)	$	(689	)	$	(506,927	)	$	143,700
Net loss		—		—		—			—			—			—			—			(84,202	)		(84,202	)
Employee stock plans		—		—		386			77			6,826			—			—			—			6,903
Director stock grants		—		—		57			11			721			—			—			—			732
Repurchases of stock		—		—		—			—			—			(100	)		(857	)		—			(857	)
Options Exercised .		—		—		4			1			15			—			—			—			16
Retirement of stock		—		—		(68	)		(13	)		(894	)		68			907			—			—
Dividends		—		—		—			—			—			—			—			(6,047	)		(6,047	)
Balance at December 31, 2012		2,250	$	2,250		36,758		$	7,352		$	648,458			(77	)	$	(639	)	$	(597,176	)	$	60,245
Net loss		—		—		—			—			—			—			—			(95,186	)		(95,186	)
Equity portion of convertible notes redeemed												4,398												4,398
Employee stock plans		—		—		594			119			7,561			—			—			—			7,680
Director stock grants		—		—		47			9			637			—			—			—			646
Repurchases of stock		—		—		—			—			—			(3	)		(74	)		—			(74	)
Options Exercised		—		—		41			8			799			—			—			—			807
Preferred Stock Offering		9		9		—			—			230,616			—			—			—			230,625
Equity Offering		—		—		6,900			1,380			164,769			—			—			—			166,149
Retirement of stock		—		—		(81	)		(16	)		(697	)		80			713			—			—
Other		—		—		—			—			(163	)		—			—			—			(163	)
Dividends		—		—		—			—			—			—			—			(18,604	)		(18,604	)
Balance at December 31, 2013		2,259	$	2,259		44,259		$	8,852		$	1,056,378			—		$	—		$	(710,966	)	$	356,523

See accompanying notes to consolidated financial statements.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—Description of Business and 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, which includes the Eagle Ford Shale Trend, (ii) Northwest Louisiana and East Texas, which includes the Haynesville Shale and Cotton Valley Taylor Sand, and (iii) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale (“TMS”).

Principles of Consolidation—The consolidated financial statements of the Company are included in this Annual Report on Form 10-K have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) and in accordance with accounting principles generally accepted in the United States (“US GAAP”). 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—Restricted cash at December 31, 2013 of $51.8 million is held in escrow for the repurchase of the remaining outstanding principal amount on our 5% Convertible Senior Notes due 2029. See Note 4.

Allowance for Doubtful Accounts—We routinely assess the recoverability of all material trade and other receivables to determine their collectability. Many of our receivables are from a limited number of purchasers. Accordingly, accounts receivable from such purchases could be significant. Generally, our natural gas and crude oil receivables are collected within thirty to sixty days of production. We also have receivables from joint interest owners of properties we operate. We may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.

We accrue a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. As of each of December 31, 2013 and 2012, our allowance for doubtful accounts was immaterial.

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 the 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.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 discovery. 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.

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.

As of December 31, 2013 and 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.

As of December 31, 2013, we had interests in oil and natural gas properties totaling $821.8 million, net of accumulated depletion, which we account for under the successful efforts method. The expected future cash flows used for impairment reviews and related fair-value calculations are based on judgmental assessments of future production volumes, prices, and costs, considering all available information at the date of review. Due to

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the uncertainty inherent in these factors, we cannot predict when or if additional future impairment charges will be recorded. We estimate future net cash flows generated from our oil and natural gas properties by using forecasted oil and natural gas prices published by the New York Mercantile Exchange (“NYMEX”).

We had no impairment associated with our oil and natural gas properties for 2013. For the years ended December 31, 2012 and 2011, we recorded impairments on our oil and natural gas properties of $47.8 million and $8.1 million, respectively. The impairment in 2012 reduced the fields’ carrying value to an estimated fair value of $3.3 million.

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 Trend area of South Texas. In compensation for the services, we agreed to pay the service provider 110 percent of the total capital cost incurred by the service provider to construct new pipelines and facilities. The service provider bills us for 20 percent of the accumulated unpaid capital costs annually.

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

Asset Retirement Obligations—We follow the accounting standard related to accounting for asset retirement obligations. These obligations are related to the abandonment and site restoration requirements that result from the exploration and development of our oil and 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 Statement 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 crude 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 December 31, 2013 and 2012, the net liability for natural gas balancing was immaterial. Differences between actual production and net working interest volumes are routinely adjusted.

Derivative Instruments—We use derivative instruments such as futures, forwards, options, collars and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas and to hedge

our exposure to changing interest rates. Accounting standards related to derivative instruments and hedging

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 counterparty 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 and restricted stock calculated using the Treasury Stock method and the potential dilutive effect of the conversion of shares associated with 5.375% Series B Convertible Preferred Stock (“Series B Preferred Stock”), 3.25% Convertible Senior Notes due 2026 (the “2026 Notes”), 5% Convertible Senior Notes due 2029 (the “2029 Notes”) and 5% Convertible Senior Notes due 2032 (the “2032 Notes”).

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

Concentration of Credit Risk—Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. The revenues compared to our total oil and natural gas revenues from the top purchasers for the years ended December 31, 2013, 2012 and 2011 are as follows:

	Year Ended December 31,
	2013			2012			2011
BP Energy Company		64	%		34	%		—
Genesis Crude Oil LP		7	%		—			—
Flint Hill Resources, LLC		—			15	%		—
Shell Energy Resources LP		—			—			11	%
Regency Field Services LLC		—			—			10	%

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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 and October 1, 2013, we issued $109.25 million and $57.0 million, respectively, 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, 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.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 December 31, 2013 and December 31, 2012.

	December 31, 2013									December 31, 2012
Fair Value of Oil and Natural Gas Derivatives	Gross Amount			Amount Offset			As Presented			Gross Amount			Amount Offset			As Presented
	(in thousands)
Derivative Current Asset	$	6,658		$	(471	)	$	6,187		$	2,410		$	(285	)	$	2,125
Derivative Non-current Asset		1,396			—			1,396			—			—			—
Derivative Current Liability		(4,812	)		471			(4,341	)		(636	)		285			(351	)
Derivative Non-current Liability		(2,371	)		—			(2,371	)		(3,987	)		—			(3,987	)
Total	$	871		$	—		$	871		$	(2,213	)	$	—		$	(2,213	)

NOTE 2—Share-Based Compensation Plans

Overview

At our annual meeting of stockholders in May 2006, our shareholders approved our 2006 Long-Term Incentive Plan (the “2006 Plan”). The 2006 Plan provides for grants to officers, employees and non-employee directors. Under the 2006 Plan as amended in 2011, a maximum of 4.0 million shares are authorized for issuance as awards of restricted stock and stock options. We had 1.6 million shares of granted but unvested restricted stock and 0.2 million shares were available for future grants as of December 31, 2013.

The 2006 Plan is intended to promote the interests of the Company by providing a means by which employees, consultants and directors may acquire or increase their equity interest in the Company and may develop a sense of proprietorship and personal involvement in the development and financial success of the Company, and to encourage them to remain with and devote their best efforts to the business of the Company, thereby advancing the interests of the Company and its stockholders. The 2006 Plan is also intended to enhance the ability of the Company and its Subsidiary to attract and retain the services of individuals who are essential for the growth and profitability of the Company.

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The 2006 Plan provides that the Compensation Committee shall have the authority to determine the participants to whom stock options, restricted stock, performance awards, phantom shares and stock appreciation rights may be granted.

We measure the cost of stock based compensation granted, including stock options and restricted stock, based on the fair value of the award as of the grant date, net of estimated forfeitures. Awards granted are valued at fair value and recognized on a straight-line basis over the service periods (or the vesting periods) of each award. We estimate forfeiture rates for all unvested awards based on our historical experience.

The following table summarizes the pretax components of our share-based compensation programs recorded, recognized as a component of general and administrative expenses in the Consolidated Statement of Operations (in thousands):

	Year Ended December 31,
	2013		2012		2011
Restricted stock expense	$	7,586	$	6,670	$	6,194
Stock option expense		94		233		301
Director stock expense		568		585		525
Total share-based compensation:	$	8,248	$	7,488	$	7,020

Stock Options

The 2006 Plan provides that the option price of shares issued be equal to the market price on the date of grant. With the exception of option grants to non-employee directors, which vest immediately, options vest ratably on the anniversary of the date of grant over a period of time, typically three years. Our stock options expire in seven or ten years after the date of grant.

Option activity under our stock option plans as of December 31, 2013, and changes during the year ended December 31, 2013 were as follows:

	Shares		Weighted Average Exercise Price		Remaining Contractual Term		Aggregate Intrinsic Value
					(years)		(thousands)
Outstanding at January 1, 2013		900,984	$	21.57		2.92	$	18
Granted		—		—		—		—
Exercised		40,500		19.94		—		—
Forfeited		5,850		21.59		—		—
Outstanding at December 31, 2013		854,634	$	21.64		1.84	$	88
Exercisable at December 31, 2013		854,634	$	21.64		1.84	$	88

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The aggregate intrinsic value in the preceding table represents the total pre-tax intrinsic value (the difference between our closing stock price on the last trading day of the fourth quarter of 2013 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2013. The amount of aggregate intrinsic value will change based on the fair market value of our stock. The total intrinsic value of options exercised during the years ended December 31, 2013, and 2012 was less than $0.1 million in both years. There were no exercises in 2011.

	Options Outstanding						Options Exercisable
Range of Exercise Prices	Number Outstanding at December 31, 2013		Weighted Average Remaining Contractual Life		Weighted Average Exercise Price		Number Exercisable at December 31, 2013		Weighted Average Exercise Price
			(years)
$16.46 and $19.78		307,300		1.11		18.08		307,300		18.08
$21.59 to $27.81		547,334		2.26		23.64		547,334		23.64
		854,634		1.84	$	21.64		854,634	$	21.64

As of December 31, 2013, all compensation cost related to the stock options has been recognized in earnings. No stock options were granted in 2013, 2012 or 2011.

Restricted Stock

In 2003, we began granting a series of restricted stock awards. Restricted stock awarded under the 2006 Plan typically has a vesting period of three years. During the vesting period, ownership of the shares cannot be transferred and the shares are subject to forfeiture if employment ends before the end of the vesting period. Certain restricted stock awards provide for accelerated vesting. Restricted shares are not considered to be currently issued and outstanding until the restrictions lapse and/or they vest.

Restricted stock activity and values under our plan for the years ended December 31, 2013, 2012 and 2011 were as follows:

	Number of Shares Granted		Value of Shares Granted		Fair Value of Stock Vested
			(thousands)		(thousands)
2013		746,163	$	13,194	$	9,960
2012		1,073,727		9,533		3,335
2011		561,714		7,921		5,764

Restricted stock activity under our plan for the year ended December 31, 2013, and changes during the year then ended were as follows:

	Number of Shares			Weighted Average Grant-Date Fair Value		Total Value
						(thousands)
Unvested at January 1, 2013		1,541,650		$	10.60	$	16,345
Vested		(594,301	)		11.57		(6,863	)
Granted		746,163			17.68		13,194
Forfeited		(112,305	)		10.69		(1,200	)
Unvested at December 31, 2013		1,581,207		$	13.58	$	21,476

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2013, total unrecognized compensation cost related to restricted stock is as follows:

	Unrecognized compensation costs		Weighted Average years to recognition
	(thousands)		(years)
December 31, 2013	$	19,938		2.44

NOTE 3—Asset Retirement Obligations

The reconciliation of the beginning and ending asset retirement obligation for the periods ending December 31, 2013 and 2012 is as follows (in thousands):

	December 31,
	2013			2012
Beginning balance	$	18,306		$	17,425
Liabilities incurred		471			693
Revisions in estimated liabilities (1)		1,290			2,005
Liabilities settled		(82	)		(767	)
Accretion expense		1,243			1,111
Dispositions		(372	)		(2,161	)
Ending balance	$	20,856		$	18,306
Current liability	$	99		$	168
Long term liability	$	20,757		$	18,138

(1) We increased our estimated liability in 2013 by $1.3 million as a result of a change in estimated plugging and abandonment cost on several of our fields.

NOTE 4—Debt

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

	December 31, 2013						December 31, 2012
	Principal		Carrying Amount		Fair Value (1)		Principal		Carrying Amount		Fair Value (1)
Senior Credit Facility (1)	$	—	$	—	$	—	$	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)		51,816		49,663		51,686		218,500		198,242		204,975
5.0% Convertible Senior Notes due 2032 (3)		167,405		160,437		171,863		—		—		—
8.875% Senior Notes due 2019		275,000		275,000		288,063		275,000		275,000		261,250
Total debt	$	494,650	$	485,529	$	512,041	$	588,929	$	568,671	$	561,654

(1) The carrying amount for the Second Amended and Restated Credit Agreement represents fair value as the variable interest rates are reflective of current market conditions. The fair value of the notes 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 debt discount was $2.1 million and $20.3 million as of December 31, 2013 and December 31, 2012, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(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 $7.0 million as of December 31, 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):

	December 31, 2013					December 31, 2012					December 31, 2011
	Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate
Senior Credit Facility		3,936		5.3	%		5,114		3.7	%		3,180		—	*
3.25% Convertible Senior Notes due 2026		14		3.3	%		14		3.3	%		4,305		9.	%
5.0% Convertible Senior Notes due 2029		17,400		11.4	%		21,968		11.4	%		20,948		10.5	%
5.0% Convertible Senior Notes due 2032		4,529		8.8	%		—		—			—		—
8.875% Senior Notes due 2019		25,308		9.2	%		25,308		9.2	%		20,910		8.9	%

* An Effective Interest Rate Calculation is not meaningful for the years ended December 31, 2011 since there were only minimal average amounts borrowed under the Senior Credit Facility during the period.

Senior Credit Facility

Total lender commitments under the Second Amended and Restated Credit Agreement (including all amendments, 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 December 31, 2013, we had no amounts outstanding 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 permitted 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 December 31, 2013, we held $51.8 million in an escrow account to provide for the repurchase of the remaining outstanding principal amount of our 2029 Notes, which is reflected on our financial statements 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 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;

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

We were in compliance with all the financial covenants of the Senior Credit Facility as of December 31, 2013.

8.875% Senior Notes due 2019

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. During 2013, we entered into separate, privately negotiated exchange agreements under which we retired $166.7 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 principal amount of $166.3 million. The 2032 Notes will mature on October 1, 2032. As of December 31, 2013, $51.8 million in aggregate principal amount of the 2029 Notes remain outstanding with terms unchanged. Please see the 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.

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).

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 2013 exchange transactions, $2.1 million of debt discount remains to be amortized on the 2029 Notes as of December 31, 2013. 2013. Investors can demand repayment on October 1, 2014, accordingly the $49.7 million carrying value of the 2029 Notes is reflected on our financial statements as a current liability.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5% Convertible Senior Notes due 2032

We entered into separate, privately negotiated exchange agreements under which we retired $166.7 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 principal amount of $166.3 million. The 2032 Notes will mature on October 1, 2032.

Many terms of the 2032 Notes 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 accretes 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 $1.2 million of accretion during 2013.

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 $166.7 million of outstanding 2029 Notes with a carrying value of $156.9 million and wrote-off unamortized debt issuance cost of $0.8 million offset by $20.0 million attributable to the fair value of the equity portion of the 2029 Notes. The 2032 Notes had a fair value of $183.2 million which resulted in a loss on the early extinguishment of debt of $7.1 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 $158.8 million of the fair value to the 2032 Note to debt component which compared to the face results in a debt discount of $7.5 million which will be amortized through the first put date of October 1, 2017. Additionally, we recorded $24.4 million within additional paid-in capital representing the equity component of the 2032 Notes. A debt discount of $7.0 million remains to be amortized on the 2032 Notes as of December 31, 2013.

3.25% Convertible Senior Notes Due 2026

During the year ended December 31, 2011, we repurchased $174.6 million of our 2026 Notes for $176.4 million using a portion of the net proceeds from the issuance of our 2019 Notes. We recorded a $0.1 million gain on the early extinguishment of debt related to the repurchase for the year ended December 31, 2011.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 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 notes are convertible into shares of our common stock at a rate equal to the sum of:

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

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

NOTE 5—Loss Per Common Share

Net loss applicable to common stock was used as the numerator in computing basic and diluted loss per common share for the years ended December 31, 2013, 2012 and 2011. The following table sets forth information related to the computations of basic and diluted loss per share.

	Year Ended December 31,
	2013			2012			2011
	(Amounts in thousands, except per share data)
Basic loss per share:
Loss applicable to common stock	$	(113,790	)	$	(90,249	)	$	(37,805	)
Weighted-average shares of common stock outstanding		38,098			36,390			36,124
Basic loss per share	$	(2.99	)	$	(2.48	)	$	(1.05	)
Diluted loss per share:
Loss applicable to common stock	$	(113,790	)	$	(90,249	)	$	(37,805	)
Dividends on convertible preferred stock (1)		—			—			—
Interest and amortization of loan cost on convertible senior notes, net of tax (3)		—			—			—
Diluted loss	$	(113,790	)	$	(90,249	)	$	(37,805	)
Weighted-average shares of common stock outstanding		38,098			36,390			36,124
Assumed conversion of convertible preferred stock (1)		—			—			—
Assumed conversion of convertible senior notes (2)		—			—			—
Stock options and restricted stock (3)		—			—			—
Weighted-average diluted shares outstanding		38,098			36,390			36,124
Diluted loss per share	$	(2.99	)	$	(2.48	)	$	(1.05	)
(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
(2)    Common shares issuable upon assumed conversion of the 2026 Notes, the 2029 Notes and 2032 Notes were not presented as they would have been anti-dilutive.		6,307			6,311			7,067
(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.		620			238			171

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6—Income Taxes

Income tax (expense) benefit consisted of the following (in thousands):

	Year Ended December 31,
	2013		2012		2011
Current:
Federal	$	—	$	—	$	—
State		—		—		—
		—		—		—
Deferred:
Federal		—		—		—
State		—		—		—
		—		—		—
Total	$	—	$	—	$	—

The following is a reconciliation of the U.S. statutory income tax rate at 35% to our income (loss) before income taxes (in thousands):

	Year Ended December 31,
	2013			2012			2011
Income tax (expense) benefit
Tax at U.S. statutory income tax	$	33,315		$	29,471		$	11,115
Valuation allowance		(30,967	)		(29,952	)		(9,909	)
State income taxes-net of federal benefit		(902	)		1,618			(762	)
Nondeductible expenses and other		(1,446	)		(1,137	)		(444	)
Total tax (expense) benefit	$	—		$	—		$	—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below (in thousands):

	December 31,
	2013			2012
Current deferred tax assets:
Accrued liabilities	$	133		$	375
Contingent liabilities and other		—			134
Less valuation allowance		(126	)		(498	)
Total current deferred tax assets		7			11
Current deferred tax liabilities:
Derivative financial instruments		(646	)		(621	)
Accrued liabilities		(26	)		(26	)
Total current deferred tax liabilities		(672	)		(647	)
Net current deferred tax liability	$	(665	)	$	(636	)
Noncurrent deferred tax assets:
Operating loss carry-forwards	$	211,589		$	156,723
State Tax NOL and Credits		5,805			3,867
Statutory depletion carry-forward		7,035			7,035
AMT tax credit carry-forward		1,227			1,324
Compensation		3,496			3,364
Contingent liabilities and other		858			1,907
Property and equipment		(3,248	)		26,848
Total gross noncurrent deferred tax assets		226,762			201,068
Less valuation allowance		(217,558	)		(193,459	)
Net noncurrent deferred tax assets		9,204			7,609
Noncurrent deferred tax liabilities:
Bond discount		(74	)		(61	)
Debt discount		(8,465	)		(6,912	)
Total non-current deferred tax liabilities		(8,539	)		(6,973	)
Net non-current deferred tax asset	$	665		$	636

The valuation allowance for deferred tax assets increased by $23.7 million in 2013. In determining the carrying value of a deferred tax asset, accounting standards provide for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. As we have incurred net operating losses in 2013 and prior years, relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are insufficient to overcome a history of such losses. Therefore, with the before-mentioned adjustment of $23.7 million, we have reduced the carrying value of our net deferred tax asset to zero. The valuation allowance has no impact on our net operating loss (“NOL”) position for tax purposes, and if we generate taxable income in future periods, we will be able to use our NOLs to offset taxes due at that time. We will continue to assess the valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2013, we have federal NOL carry-forwards of approximately $608.9 million for tax purposes which begin to expire in 2026. We also have an alternative minimum tax credit carry-forward not subject to expiration of $1.2 million which will not begin to be used until after the available NOLs have been used or expired and when regular tax exceeds the current year alternative minimum tax.

We did not have any unrecognized tax benefits as of December 31, 2013. The amount of unrecognized tax benefits may change in the next twelve months; however we do not expect the change to have a significant impact on our results of operations or our financial position. We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions. With limited exceptions, we are no longer subject to U.S. Federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2006.

Our continuing practice is to recognize estimated interest and penalties related to potential underpayment on any unrecognized tax benefits as a component of income tax expense in the Consolidated Statement of Operations. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations before December 31, 2014.

NOTE 7—Stockholders’ Equity

5.375% Series B Convertible Preferred Stock

Our 5.375% Series B Convertible Preferred Stock (the “Series B Preferred Stock”) was initially issued on December 21, 2005, in a private placement of 1,650,000 shares for net proceeds of $79.8 million (after offering costs of $2.7 million). Each share of the Series B Preferred Stock has a liquidation preference of $50 per share, aggregating to $82.5 million, and bears a dividend of 5.375% per annum. Dividends are payable quarterly in arrears beginning March 15, 2006. If we fail to pay dividends on our Series B Preferred Stock on any six dividend payment dates, whether or not consecutive, the dividend rate per annum will be increased by 1.0% until we have paid all dividends on our Series B Preferred Stock for all dividend periods up to and including the dividend payment date on which the accumulated and unpaid dividends are paid in full.

On January 23, 2006, the initial purchasers of the Series B Preferred Stock exercised their over-allotment option to purchase an additional 600,000 shares at the same price per share, resulting in net proceeds of $29.0 million, which was used to fund our 2006 capital expenditure program.

Each share is convertible at the option of the holder into our common stock at any time at an initial conversion rate of 1.5946 shares of common stock per share, which is equivalent to an initial conversion price of approximately $31.36 per share of common stock. Upon conversion of the Series B Preferred Stock, we may choose to deliver the conversion value to holders in cash, shares of common stock, or a combination of cash and shares of common stock.

If a fundamental change occurs, holders may require us in specified circumstances to repurchase all or part of the Series B Convertible Preferred Stock. In addition, upon the occurrence of a fundamental change or specified corporate events, we will under certain circumstances increase the conversion rate by a number of additional shares of common stock. A “fundamental change” will be deemed to have occurred if any of the following occurs:

• We consolidate or merge with or into any person or convey, transfer, sell or otherwise dispose of or lease all or substantially all of our assets to any person, or any person consolidates with or merges into us or with us, in any such event pursuant to a transaction in which our outstanding voting shares are changed into or exchanged for cash, securities, or other property; or

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

• We are liquidated or dissolved or adopt a plan of liquidation or dissolution.

A “fundamental change” will not be deemed to have occurred if at least 90% of the consideration in the case of a merger or consolidation under the first clause above consists of common stock traded on a U.S. national securities exchange and the Series B Preferred Stock becomes convertible solely into such common stock.

On or after December 21, 2010, we may, at our option, cause the Series B Preferred Stock to be automatically converted into the number of shares of common stock that are issuable at the then-prevailing conversion rate, pursuant to the Company Conversion Option. We may exercise our conversion right only if, for 20 trading days within any period of 30 consecutive trading days ending on the trading day before the announcement of our exercise of the option, the closing price of the common stock equals or exceeds 130% of the then-prevailing conversion price of the Series B Preferred Stock. The Series B Preferred Stock is non-redeemable by us. There have been no redemptions or conversions in any periods.

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 $105.4 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.

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 $124.9 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 Series B 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.

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.

Common Stock Offering

On October 21, 2013, we closed an underwritten public offering of 6.9 million shares of our common stock sold at a price to the public of $25.25 per share.

NOTE 8—Derivative Activities

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

The following table summarizes the realized and unrealized gains and losses we recognized on our oil and natural gas derivatives for the years ended December 31, 2013, 2012 and 2011.

	December 31,
Oil and Natural Gas Derivatives (in thousands)	2013			2012			2011
Realized gain (loss) on oil and natural gas derivatives	$	(3,786	)	$	73,160		$	31,305
Unrealized gain (loss) on oil and natural gas derivatives		3,084			(41,278	)		3,234
Total gain (loss) on oil and natural gas derivatives	$	(702	)	$	31,882		$	34,539

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 hedged are approved by the Hedging

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Committee of our Board of Directors, and reviewed periodically by the Board of Directors. As of December 31, 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, Argus LLS or specific transfer point quoted prices, and

(b) 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 primarily 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 a fair value amount of $3.3 million had our counterparties as a group been unable to fulfill their obligations as of December 31, 2013.

As of December 31, 2013, our open positions on our outstanding commodity derivative contracts, all of which were with 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 Volume		Fixed Price	Fair Value at December 31, 2013 (in thousands)
Natural gas swaps (MMBtu)
2014		30,000		10,950,000	$4.18 – 5.06	$	6,187
Natural gas calls (MMBtu)
2015		20,000		7,300,000	$5.05 – 5.06		(1,125	)
2016		20,000		7,300,000	$5.05 – 5.06		(1,246	)
Oil swaps (BBL)
2014		3,800		1,387,000	$90.95 –$98.02		(4,341	)
2015		1,300		474,500	$94.55		1,396
					Total	$	871

During 2013, we entered into the following derivative contracts. Unless otherwise noted, West Texas Intermediate (“WTI”) quoted on the New York Mercantile Exchange (“NYMEX”) is used for the floating price of oil and Henry Hub as quoted on NYMEX is used for the floating price of natural gas.

Contract Type	Daily Volume		Strike Price		Contract Start Date		Contract Termination
Oil swap (BBL)		1,000	$	92.95		January 1, 2014		December 31, 2014
Oil swap (BBL)		500	$	98.02		November 1, 2013		December 31, 2014
Oil swap (BBL) (1)		1,300	$	94.55		January 1, 2014		December 31, 2014
Oil swap (BBL) (1)		1,300	$	94.55		January 1, 2015		December 31, 2015
Natural Gas swap (MMBtu)		10,000	$	4.1825		October 1, 2013		December 31, 2014
Natural Gas swap (MMBtu)		20,000	$	5.05 – 5.06		January 1, 2014		December 31, 2014
Natural Gas calls (MMBtu)		20,000	$	5.05 – 5.06		January 1, 2015		December 31, 2016

(1) Commodity contract pricing based on Louisiana Light Sweet crude (Argus) trade month swap.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each level as of December 31, 2013 and 2012 (in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See Footnote 1 “Fair Value Measurement” for our discussion for inputs used and valuation techniques for determining fair values.

	2013 Fair Value Measurements Using
Description	Level 1		Level 2			Level 3		Total
Current Assets Commodity Derivatives	$	—	$	6,187		$	—	$	6,187
Non-current Assets Commodity Derivatives		—		1,396			—		1,396
Current Liabilities Commodity Derivatives		—		(4,341	)		—		(4,341	)
Non-current Liabilities Commodity Derivatives		—		(2,371	)		—		(2,371	)
Total	$	—	$	871		$	—	$	871
	2012 Fair Value Measurements Using
Description	Level 1		Level 2			Level 3		Total
Current Assets Commodity Derivatives	$	—	$	2,125		$	—	$	2,125
Current Liabilities Commodity Derivatives		—		(351	)		—		(351	)
Non-current Liabilities Commodity Derivatives		—		(3,987	)		—		(3,987	)
Total	$	—	$	(2,213	)	$	—	$	(2,213	)

NOTE 9—Commitments and Contingencies

We are party to various lawsuits from time to time arising in the normal course of business, including, but not limited to, royalty, contract, personal injury, and environmental claims. We have established reserves as appropriate for all such proceedings and intend to vigorously defend these actions. Management believes, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our consolidated financial position results of operations or liquidity.

The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2013 (in thousands).

	Payment due by Period
	Note		Total		2014		2015		2016		2017		2018 and After
Debt (1)		4	$	507,620	$	51,816	$	—	$	—	$	180,375	$	275,429
Interest on notes		4		87,053		34,676		32,733		13,410		6,234		—
Office space leases				8,232		1,450		1,332		1,381		1,430		2,639
Office equipment leases				461		298		140		23		—		—
Drilling rigs & operations contracts				14,534		14,353		133		43		5		—
Transportation contracts				6,327		1,552		955		955		955		1,910
Total contractual obligations (2)			$	624,227	$	104,145	$	35,293	$	15,812	$	188,999	$	279,978

(1) The 2026 Notes have a provision at the end of years 5, 10 and 15, for the investors to demand payment on these dates; the first such date was December 1, 2011; all but the remaining $0.4 million were redeemed. The next ‘put’ date for the remaining 2026 Notes is December 1, 2016. The 2029 Notes have a provision by which on or after October 1, 2014, we may redeem all or a portion of the notes for cash and the investors

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

may require us to repurchase the notes on each of October 1, 2014, 2019 and 2024. The 2032 Notes have a provision by which on or after October 1, 2017, we may redeem all or a portion of the notes for cash, and the investors may require us to repurchase the notes on each of October 1, 2017, 2022 and 2027. The balance outstanding under our Senior Credit Facility is not included as it is revolving debt.

(2) This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $20.9 million as of December 31, 2013. We record a separate liability for the asset retirement obligations. See Note 3.

Operating Leases—We have commitments under an operating lease agreement for office space and office equipment leases. Total rent expense for the years ended December 31, 2013, 2012, and 2011, was approximately $1.3 million, $1.2 million and $1.1 million, respectively.

Drilling Contracts—We have two drilling rigs under contract as of December 31, 2013 which are scheduled to expire in 2014.

Defined Contribution Plan—We have a defined contribution plan (“DCP”) which matches a portion of employees’ contributions. Participation in the DCP is voluntary and all regular employees of the Company are eligible to participate. We charged to expense plan contributions of $0.7 million, $0.7 million and $0.7 million for 2013, 2012 and 2011, respectively.

Transportation Contracts—We have commitments under a transportation contract for our Eagle Ford Shale Trend properties. See Note 1 “—Transportation Obligation” for further information.

NOTE 10—Related Party Transactions

Patrick E. Malloy, III, Chairman of the Board of Directors of our company is a principal of Malloy Energy Company, LLC (“MEC”). MEC owns various small working interests in the Bethany Longstreet field for which we are the operator. In accordance with industry standard joint operating agreements, we bill MEC for its share of capital and operating cost on a monthly basis. As of December 31, 2013 and 2012, the amounts billed and outstanding to MEC for its share of monthly capital and operating costs were both less than $0.1 million and are included in trade and other accounts receivable at each year-end. Such amounts at each year-end were paid by MEC to us in the month after billing and is current on payment of its billings.

We also serve as the operator for a number of other oil and natural gas wells owned by affiliates of MEC in which we will earn a working interest after payout. In accordance with industry standard joint operating agreements, we bill the affiliates for its share of the capital and operating costs of these wells on a monthly basis. As of December 31, 2013 and 2012, the amounts billed and outstanding to the affiliate for its share of monthly capital and operating costs were both less than $0.3 million and are included in trade and other accounts receivable at each year-end. Such amounts at each year-end were paid by the affiliate to us in the month after billing and the affiliate is current on payment of its billings.

NOTE 11—Acquisitions and Divestitures

Acquisitions

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 $24.6 million. The closing price included $2.7 million of lease extensions executed by Devon for the Company after the effective date. The adjusted purchase price net of lease extension costs totaled $21.8 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We recorded $21.8 million to oil and gas properties in the purchase price allocation inclusive of $0.1 million in asset retirement obligations for net cash paid of $23.7 million.

For the period, August 21, 2013 through December 31, 2013, the acquired property has generated operating income of $2.5 million on revenues of $2.8 million which is included on our Consolidated Statement of Operations for the year ended December 31, 2013. Expenses associated with the acquisition for the year ended December 31, 2013 were less than $0.1 million and are included in General and Administrative expense. The acquisition was recorded at fair value which was determined using both the market and income approaches. The income approach is based on inputs and natural gas reserves estimates, estimated future commodity prices and estimated future production and development costs. The market approach was based on recent transactions for similar leases.

The following tables present the Unaudited Pro forma Condensed Consolidated Statements of Operations, giving effect to the acquisition as if it had occurred on January 1, 2012:

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

For the Year Ended December 31, 2013

(In Thousands, Except Per Share Amounts)

	As Reported			Adjustments		As Adjusted
Total revenues	$	203,295		$	7,380	$	210,675
Operating expenses		239,605			497		240,102
Operating loss		(36,310	)		6,883		(29,427	)
Net loss		(95,186	)		6,883		(88,303	)
Net loss applicable to common stock	$	(113,790	)	$	6,883	$	(106,907	)
Per Common Share
Net loss applicable to common stock—basic	$	(2.99	)			$	(2.81	)
Net loss applicable to common stock—diluted	$	(2.99	)			$	(2.81	)
Weighted average common shares outstanding—basic		38,098					38,098
Weighted average common shares outstanding—diluted		38,098					38,098

For the Year Ended December 31, 2012

(In Thousands, Except Per Share Amounts)

	As Reported			Adjustments		As Adjusted
Total revenues	$	180,845		$	10,223	$	191,068
Operating expenses		244,530			1,657		246,187
Operating loss		(63,685	)		8,566		(55,119	)
Net loss		(84,202	)		8,566		(75,636	)
Net loss applicable to common stock	$	(90,249	)	$	8,566	$	(81,683	)
Per Common Share
Net Loss applicable to common stock—basic	$	(2.48	)			$	(2.24	)
Net loss applicable to common stock—diluted	$	(2.48	)			$	(2.24	)
Weighted average common shares outstanding—basic		36,390					36,390
Weighted average common shares outstanding—diluted		36,390					36,390

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During 2012, we acquired rights to an additional 56,400 gross (54,000 net) acres in undeveloped leases in the Tuscaloosa Marine Shale for a total of $18.4 million.

Divestitures

On September 28, 2012, we sold our interest in certain non-core properties in the South Henderson field located in East Texas for $95 million, realizing a gain on the sale of assets of $44.0 million. The sale was effective on July 1, 2012.

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SUPPLEMENTAL INFORMATION

(Unaudited)

Oil and Natural Gas Producing Activities (Unaudited)

Overview

All of our reserve information related to crude oil, condensate and natural gas liquids and natural gas was compiled based on estimates prepared and reviewed by our engineers. The technical persons primarily responsible for overseeing the preparation of the reserves estimates meet the requirements regarding qualifications. The reserves estimation is part of our internal controls process subject to management’s annual review and approval. These reserves estimates are prepared by Netherland, Sewell & Associates, Inc. (“NSAI”) and Ryder Scott Company (“RSC”), our independent reserve engineer consulting firms, as of December 31, 2013. NSAI prepared the reserves estimates as of December 31, 2012 and 2011. Approximately 79% and 21% of the proved reserves estimates shown herein at December 31, 2013 have been independently prepared by NSAI and RSC, respectively. NSAI prepared the estimates on all our proved reserves as of December 31, 2013 on our properties other than in the TMS and the Eagle Ford Shale Trend areas. RSC prepared the estimate of proved reserves as of December 31, 2013 for our TMS and Eagle Ford Trend areas. Copies of the summary reserve reports of NSAI and RSC for 2013 are filed as exhibits 99.1 and 99.2, respectively to this Annual Report on Form 10-K. All of the subject reserves are located in the continental United States, primarily in Texas, Louisiana and Mississippi.

Many assumptions and judgmental decisions are required to estimate reserves. Quantities reported are considered reasonable but are subject to future revisions, some of which may be substantial, as additional information becomes available. Such additional knowledge may be gained as the result of reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes, and other factors.

Regulations published by the SEC define proved oil and natural gas reserves as those quantities of oil and natural gas which, by analysis of geosciences and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimates if the extraction is by means not involving a well.

Prices we used to value our reserves are based on the twelve-month un-weighted arithmetic average of the first-day-of-the-month price for the period January through December 2013. For oil volumes, the average price of $96.94 per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For natural gas volumes, the average price of $3.67 per MMBtu is adjusted by lease for energy content, transportation fees, and regional price differentials. For natural gas liquids, the average price was $31.44 per Bbl.

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SUPPLEMENTAL INFORMATION

(Unaudited)

Capitalized Costs

The table below reflects our capitalized costs related to our oil and natural gas producing activities at December 31, 2013, and 2012 (in thousands):

	2013			2012
Proved properties	$	1,728,352		$	1,532,199
Unproved properties		109,867			87,715
		1,838,219			1,619,914
Less accumulated depreciation, depletion and amortization		(1,016,422	)		(901,621	)
Net oil and natural gas properties	$	821,797		$	718,293

We have $9.7 million of capitalized exploratory well costs that are pending the determination of proved reserves as of December 31, 2013 and had $9.7 million as of December 31, 2012. During 2013, $4.4 million of the December 31, 2012 pending capitalized exploratory well costs were expensed.

Costs Incurred

Costs incurred in oil and natural gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows (in thousands):

	Year Ended December 31,
	2013		2012		2011
Property Acquisition
Unproved	$	22,973	$	22,325	$	22,698
Proved		15,533		—		—
Exploration		85,425		34,529		4,815
Development (1)		136,242		198,918		304,215
	$	260,173	$	255,772	$	331,728

(1) Includes asset retirement costs of $1.8 million in 2013, $2.7 million in 2012 and $2.1 million in 2011.

The following table sets forth our net proved oil and natural gas reserves at December 31, 2013, 2012 and 2011 and the changes in net proved oil and natural gas reserves during such years:

	Natural Gas (Mmcf) (5)									Oil, Condensate and NGLs (MBbls)
	2013			2012			2011 (4)			2013			2012			2011 (4)
Proved reserves at beginning of period		253,981			408,707			454,189			13,189			13,516			1,618
Revisions of previous estimates (1)		78,965			(112,601	)		(78,859	)		1,992			(1,372	)		6,485
Extensions, discoveries and improved recovery (2)		17,776			4,420			69,643			6,165			4,661			6,059
Purchases of minerals in place		49			—			—			476			—			—
Sales of minerals in place		(148	)		(20,919	)		(99	)		—			(2,524	)		(3	)
Production		(21,007	)		(25,626	)		(36,167	)		(1,391	)		(1,092	)		(643	)
Proved reserves at end of period		329,616			253,981			408,707			20,431			13,189			13,516
Proved developed reserves:
Beginning of period		119,671			169,344			187,417			6,447			6,532			746
End of period		117,184			119,671			169,344			10,100			6,447			6,532

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

SUPPLEMENTAL INFORMATION

(Unaudited)

	Natural Gas Equivalents (Mmcfe)
	2013			2012			2011
Proved reserves at beginning of period		333,116			489,805			463,899
Revisions of previous estimates (1)		90,919			(120,832	)		(39,949	)
Extensions, discoveries and improved recovery (2)		54,765			32,387			106,000
Purchases of minerals in place		2,903			—			—
Sales of minerals in place (3)		(148	)		(36,063	)		(116	)
Production		(29,352	)		(32,181	)		(40,029	)
Proved reserves at end of period		452,203			333,116			489,805
Proved developed reserves:
Beginning of period		158,352			208,538			191,893
End of period		177,786			158,352			208,538

(1) Revisions of previous estimates in 2013 were positive reflecting cases, which were uneconomic at year end 2012 pricing, but are now economic under year ended 2013 pricing.

(2) Extensions and discoveries were positive on an overall basis in all three periods presented, primarily related to our continued drilling activity on existing and newly acquired properties in the Northwest Louisiana, East Texas and South Texas areas. We recognized reserve adds of 54.8 Bcfe in 2013 related to extensions and discoveries, of which approximately 13.2 Bcfe is attributed to the Haynesville Shale Trend and Cotton Valley Taylor Sand, approximately 17.8 Bcfe is attributed to the Eagle Ford Shale Trend and 23.8 Bcfe to the Tuscaloosa Marine Shale Trend.

(3) In 2012, we sold approximately 36.1 Bcfe attributed to the sale of properties in the South Henderson field located in East Texas.

Standardized Measure

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of year-end is shown below (in thousands):

	2013			2012			2011
Future revenues	$	2,568,448		$	1,608,629		$	2,242,060
Future lease operating expenses and production taxes		(787,619	)		(467,600	)		(497,901	)
Future development costs (1)		(713,121	)		(465,500	)		(694,192	)
Future income tax expense		(7,004	)		(4,149	)		(11,384	)
Future net cash flows		1,060,704			671,380			1,038,583
10% annual discount for estimated timing of cash flows		(592,557	)		(313,931	)		(590,613	)
Standardized measure of discounted future net cash flows	$	468,147		$	357,449		$	447,970
Index price used to calculate reserves (2)
Natural gas (per Mcf)	$	3.67		$	2.76		$	4.12
Oil (per Bbl)	$	96.94		$	91.21		$	92.71

(1) Includes cumulative asset retirement obligations of $42.8 million, $34.9 million, and 32.8 million in 2013, 2012 and 2011, respectively.

(2) These index prices, used to estimate our reserves at these dates, are before deducting or adding applicable transportation and quality differentials on a well-by-well basis.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

SUPPLEMENTAL INFORMATION

(Unaudited)

Changes in the Standardized Measure

The following are the principal sources of change in the standardized measure of discounted net cash flows for the years shown (in thousands):

	Year Ended December 31,
	2013			2012			2011
Balance, beginning of year	$	357,449		$	447,970		$	358,678
Net changes in prices and production costs related to future production		(5,614	)		(193,096	)		(1,607	)
Sales and transfers of oil and natural gas produced, net of production costs		(165,452	)		(146,490	)		(160,543	)
Net change due to revisions in quantity estimates		156,009			(178,468	)		(47,233	)
Net change due to extensions, discoveries and improved recovery		145,843			197,583			259,967
Net change due to purchases and sales of minerals in place		16,371			(74,633	)		(127	)
Changes in future development costs		(103,033	)		208,619			6,709
Previously estimated development cost incurred in period		50,402			69,688			18,080
Net change in income taxes		(2,476	)		2,394			(591	)
Accretion of discount		35,909			45,201			36,213
Change in production rates (timing) and other		(17,261	)		(21,319	)		(21,576	)
Net increase (decrease) in standardized measures		110,698			(90,521	)		89,292
Balance, end of year	$	468,147		$	357,449		$	447,970

We believe with reasonable certainty that we will be able to obtain such capital in the normal course of business. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. The standardized measure of discounted cash flows is the future net cash flows less the computed discount.

Summarized Quarterly Financial Data (Unaudited)

(In Thousands, Except Per Share Amounts)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
2013
Revenues		47,084			48,485			57,161			50,565			203,295
Operating income (loss)		(13,142	)		(14,192	)		(854	)		(8,122	)		(36,310	)
Net income (loss)		(28,463	)		(16,143	)		(27,085	)		(23,495	)		(95,186	)
Net income (loss) applicable to common stock		(29,975	)		(20,099	)		(32,790	)		(30,926	)		(113,790	)
Basic income (loss) per common share		(0.82	)		(0.55	)		(0.89	)		(0.73	)		(2.99	)
Diluted income (loss) per common share		(0.82	)		(0.55	)		(0.89	)		(0.73	)		(2.99	)
2012
Revenues	$	45,308		$	41,346		$	45,960		$	48,231		$	180,845
Operating income (loss)		(14,241	)		(14,157	)		31,854			(67,141	)		(63,685	)
Net income (loss)		(17,729	)		(3,202	)		12,405			(75,676	)		(84,202	)
Net income (loss) applicable to common stock		(19,241	)		(4,714	)		10,894			(77,188	)		(90,249	)
Basic income (loss) per common share		(0.53	)		(0.13	)		0.30			(2.12	)		(2.48	)
Diluted income (loss) per common share		(0.53	)		(0.13	)		0.30			(2.12	)		(2.48	)

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. 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 SEC rule 13a-15(b), 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 December 31, 2013, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective.

Management’s Annual Report on Internal Control Over Financial Reporting

See Management’s Assessment of Internal Control Over Financial Reporting under Item 8 of this Annual Report on Form 10-K.

Attestation Report of the Registered Public Accounting Firm

See Report of Independent Registered Public Accounting Firm under Item 8 of this Annual Report on Form 10-K.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Our executive officers and directors and their ages and positions as of February 21, 2014, are as follows:

Name	Age		Position
Patrick E. Malloy, III		71	Chairman of the Board of Directors
Walter G. “Gil” Goodrich		55	Vice Chairman, Chief Executive Officer and Director
Robert C. Turnham, Jr.		56	President, Chief Operating Officer and Director
Mark E. Ferchau		60	Executive Vice President
Jan L. Schott		45	Senior Vice President and Chief Financial Officer
Michael J. Killelea		51	Senior Vice President, General Counsel and Corporate Secretary
Henry Goodrich		83	Chairman—Emeritus and Director
Josiah T. Austin		66	Director
Peter D. Goodson		71	Director
Michael J. Perdue		59	Director
Arthur A. Seeligson		55	Director
Stephen M. Straty		58	Director
Gene Washington		67	Director

Josiah T. Austin is the managing member of El Coronado Holdings, L.L.C., a privately owned investment holding company. He and his family own and operate agricultural properties in the state of Arizona and northern Sonora, Mexico through El Coronado Ranch & Cattle Company, L.L.C. and other entities. Mr. Austin previously served on the Board of Directors of Monterey Bay Bancorp of Watsonville, California, and is a prior board member of New York Bancorp, Inc., which merged with North Fork Bancorporation in 1998. He is an active investor in publicly traded financial institutions and is currently on The Board of Directors of Novogen, LTD. He became one of our directors in 2002.

Mark E. Ferchau became Executive Vice President of the Company in 2004. He had previously served as the Company’s Senior Vice President, Engineering and Operations, after initially joining the Company as a Vice President in 2001. Mr. Ferchau previously served as Production Manager for Forcenergy Inc. from 1997 to 2001 and as Vice President, Engineering of Convest Energy Corporation from 1993 to 1997. Prior thereto, Mr. Ferchau held various positions with Wagner & Brown, Ltd. and other independent oil and natural gas companies.

Henry Goodrich is Chairman of the Board—Emeritus. Mr. Goodrich began his career as an exploration geologist with the Union Producing Company and McCord Oil Company in the 1950’s. From 1971 to 1975, Mr. Goodrich was President, Chief Executive Officer and a partner of McCord-Goodrich Oil Company. In 1975, Mr. Goodrich formed Goodrich Oil Company, which held interests in and served as operator of various properties owned by a predecessor of the Company. He was elected to our board in 1995, and served as Chairman of our Board from 1996 through 2003. Henry Goodrich is the father of Walter G. Goodrich.

Walter G. “Gil” Goodrich became Vice Chairman of our Board in 2003. He has served as our Chief Executive Officer since 1995. Mr. Goodrich was Goodrich Oil Company’s Vice President of Exploration from 1985 to 1989 and its President from 1989 to 1995. He joined Goodrich Oil Company, which held interests in and served as operator of various properties owned by a predecessor of the Company, as an exploration geologist in 1980. Gil Goodrich is the son of Henry Goodrich. He has served as a director since 1995.

Peter D. Goodson has been a lead member of the Mekong Capital Advisory Board, a Vietnamese private equity firm since 2010, an operating partner of Dubilier & Company since 1998 and a visiting lecturer at Haas Business School of the University of California, Berkeley, and the Berkeley-Columbia program where he has

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lectured since January 2004. Mr. Goodson is a former director of dELiA*s, Inc., Montgomery Ward & Co., Kidder, Peabody & Co., Broadgate Consultants, Silicon Valley Bancshares, the former New York Bancorp, Inc., and Dial Industries. He was elected to the Company’s Board of Directors in 2011.

Michael J. Killelea joined the Company as Senior Vice President, General Counsel and Corporate Secretary in 2009. Mr. Killelea has almost 25 years of experience in the energy industry. In 2008, he served as interim Vice President, General Counsel and Corporate Secretary for Maxus Energy Corporation. Prior to that time, Mr. Killelea was Senior Vice President, General Counsel and Corporate Secretary of Pogo Producing Company from 2000 through 2007.

Patrick E Malloy, III became Chairman of the Board of Directors in 2003. He has been President and Chief Executive Officer of Malloy Enterprises, Inc., a real estate and investment holding company, and Malloy Real Estate, Inc. since 1973. In addition, Mr. Malloy served as a director of North Fork Bancorp (NYSE) from 1998 to 2002 and was Chairman of the Board of New York Bancorp (NYSE) from 1991 to 1998. He joined our Board of Directors in 2000.

Michael J. Perdue is the President of PacWest Bancorp., a publicly traded holding company and of its subsidiary, Pacific Western Bank, both based in San Diego, California. Before assuming his present position in 2006, Mr. Perdue served as President and Chief Executive Officer of Community Bancorp Inc., from 2003. Over the course of his career, Mr. Perdue has held executive positions with several banking and real estate development organizations. He was elected to our Board of Directors in 2001.

Arthur A. Seeligson has been Managing Partner of Seeligson Oil Co. Ltd. since 1996 and also manages a family investment office in Houston, Texas. Previously, Mr. Seeligson was an investment banker focused on the oil and gas industry. He has served as one of our directors since 1995.

Jan L. Schott has served as Senior Vice President and Chief Financial Officer since 2010 and currently serves as both the Company’s Principal Financial Officer and Principal Accounting Officer. She joined the company in 2007 as Vice President and Controller. Ms. Schott has over 20 years of experience with the energy industry. Prior to joining the Company, Ms. Schott served in various accounting management positions with Apache Corporation from 1997 to 2007. Ms. Schott was in public accounting with KPMG LLP from 1991 to 1997. Ms. Schott is a certified public accountant.

Stephen M. Straty is the America’s Co-Head Energy Investment Banking Group at Jefferies & Company, Inc. Mr. Straty joined the firm in 2008 and has nearly 30 years of experience in finance, most recently as Senior Managing Director and Head of the Natural Resources Group at Bear, Stearns & Co., Inc. where he worked for 17 years. Mr. Straty has extensive experience in serving a broad array of energy clients, having completed over $40.0 billion in merger and acquisition and financing assignments during the past ten years. He has served as a director since 2009.

Robert C. Turnham, Jr. has served as our Chief Operating Officer since 1995 and became President and Chief Operating Officer in 2003. He has held various positions in the oil and natural gas business since 1981. From 1981 to 1984, Mr. Turnham served as a financial analyst for Pennzoil. In 1984, he formed Turnham Interests, Inc. to pursue oil and natural gas investment opportunities. From 1993 to 1995, he was a partner in and served as President of Liberty Production Company, an oil and natural gas exploration and production company. He has served as a director since 2006.

Gene Washington is the former Director of Football Operations with the National Football League in New York. He previously served as a professional sportscaster and as Assistant Athletic Director for Stanford University prior to assuming his present position with the NFL in 1994. Mr. Washington serves and has served on numerous corporate and civic boards, including serving as a director of the former New York Bancorp, a NYSE listed company. He was elected to the Company’s Board of Directors in 2003.

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Additional information required under Item 10, “Directors, Executive Officers and Corporate Governance,” will be provided in our Proxy Statement for the 2014 Annual Meeting of Stockholders. The information required by this Item is incorporated by reference to the information provided in our definitive proxy statement for the 2014 annual meeting of stockholders to be filed within 120 days from December 31, 2013. Additional information regarding our corporate governance guidelines as well as the complete text of our Code of Business Conduct and Ethics and the charters of our Audit Committee, Compensation Committee and our Nominating and Corporate Governance Committee may be found on our website at www.goodrichpetroleum.com.

Item 11. Executive Compensation

The information required by this Item is incorporated by reference to the information provided under the caption “Executive Compensation” in our definitive proxy statement for the 2014 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2013.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this Item is incorporated by reference to the information provided under the caption “Security Ownership of Certain Beneficial Owners and Management” in our definitive proxy statement for the 2014 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2013.

Item 13. Certain Relationships and Related Transactions and Director Independence

The information required by this Item is incorporated by reference to the information provided under the caption “Transactions with Related Persons” and “Corporate Governance-Our Board-Board Size; Director Independence” in our definitive proxy statement for the 2014 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2013.

Item 14. Principal Accounting Fees and Services

The information required by this Item is incorporated by reference to the information provided under the caption “Audit and Non-Audit Fees” in our definitive proxy statement for the 2014 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2013.

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PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)(1) and (2) Financial Statements and Financial Statement Schedules

See “Index to Consolidated Financial Statements” on page 58.

All schedules are omitted because they are not applicable, not required or the information is included within the consolidated financial information or related notes.

(a)(3) Exhibits

3.2	Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Acquisition II, Inc., dated January 31, 1997 (Incorporated by reference to Exhibit 3.1 B of the Company’s Third Amended Registration Statement of Form S-1 (Registration No. 333-47078) filed on December 8, 2000).
3.3	Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated March 12, 1998 (Incorporated by reference to Exhibit 3.2 of the Company’s Annual Report on Form 10-K (File No. 001-12719) for the year ended December 31, 1997).
3.4	Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated May 9, 2002 (Incorporated by reference to Exhibit 3.4 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on December 3, 2007).
3.5	Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated May 30, 2007 (Incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on August 9, 2007).
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).
3.7	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 (File No. 001-12719) filed on December 22, 2005).
3.8	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 Current Report on Form 8-K filed on April 10, 2013).
3.9	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 Current Report on Form 8-K filed on August 19, 2013).
4.1	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)).
4.2	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 Current Report on Form 8-K filed on April 10, 2013).
4.3	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 Current Report on Form 8-K filed on April 10, 2013).
4.4	Form of Certificate representing the 10.00% Series C Cumulative Preferred Stock (Incorporated by reference to Exhibit 4.4 of the Company’s Current Report on Form 8-K filed on April 10, 2013).

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4.5	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 Current Report on Form 8-K filed on August 19, 2013).
4.6	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 Current Report on Form 8-K filed on August 19, 2013).
4.7	Form of Certificate representing the 9.75% Series D Cumulative Preferred Stock (Incorporated by reference to Exhibit 4.4 of the Company’s Current Report on Form 8-K filed on August 19, 2013).
4.8	Indenture, dated December 6, 2006, between Goodrich Petroleum Corporation and Wells Fargo Bank, National Association, as Trustee (Incorporated by reference to Exhibit 4.12 of the Company’s Annual Report on Form 10-K (File No. 001-12719) for the year ended December 31, 2006).
4.9	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 (File No. 001-12719) filed on September 30, 2009).
4.10	First Supplemental Indenture dated as of September 28, 2009, between Goodrich Petroleum Corporation and Wells Fargo Bank, National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on September 30, 2009).
4.11	Form of 5.00% Convertible Senior Note due 2029 (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on September 30, 2009).
4.12	Indenture (including the Form of Note), related to our 8.875% Senior Notes due 2019, dated as of March 2, 2011 among the Company, the Guarantor 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 (File No. 001-12719) filed on March 8, 2011).
4.13	First Supplemental Indenture dated as of April 1, 2011 among Goodrich Petroleum Corporation and Goodrich Petroleum Company, L.L.C. and Wells Fargo Bank, National Association, as Trustee (Incorporated by reference to Exhibit 4.10 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2012).
4.14	Second Supplemental Indenture dated as of April 1, 2011 among Goodrich Petroleum Corporation and Goodrich Petroleum Company, L.L.C. and Wells Fargo Bank, National Association, as Trustee (Incorporated by reference to Exhibit 4.11 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2012).
4.15	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 Current Report on Form 8-K filed on August 27, 2013).
10.1	Goodrich Petroleum Corporation 1995 Stock Option Plan (Incorporated by reference to Exhibit 10.21 to the Company’s Registration Statement filed May 30, 1995 on Form S-4 (File No. 333-58631)).
10.2†	Goodrich Petroleum Corporation 2006 Long-Term Incentive Plan (Incorporated by reference to the Company’s Proxy Statement (File No. 001-12719) filed April 17, 2006).
10.3†	Goodrich Petroleum Corporation 1997 Non-Employee Director Compensation Plan (Incorporated by reference to the Company’s Proxy Statement (File No. 001-12719) filed April 27, 1998.

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10.4†	Goodrich Petroleum Corporation Annual Bonus Plan (Incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on November 8, 2007).
10.5†	Non-employee Director Compensation Summary (Incorporated by reference to Exhibit 10.49 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007).
10.6†	Form of Subscription Agreement dated September 27, 1999 (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-12719) dated October 15, 1999).
10.7†	Form of Grant of Restricted Phantom Stock (1995 Stock Option Plan) (Incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-8 (File No. 333-138156) filed on October 23, 2006).
10.8†	Form of Grant of Restricted Phantom Stock (2006 Long-Term Incentive Plan) (Incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-8 (File No. 333-138156) filed on October 23, 2006).
10.9†	Form of Director Stock Option Agreement (with vesting schedule) (Incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-8 (File No. 333-138156) filed on October 23, 2006).
10.10†	Form of Director Stock Option Agreement (immediate vesting) (Incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-8 (File No. 333-138156) filed on October 23, 2006).
10.11†	Form of Incentive Stock Option Agreement (Incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form S-8 (File No. 333-138156) filed on October 23, 2006).
10.12†	Form of Nonqualified Option Agreement (Incorporated by reference to Exhibit 4.7 to the Company’s Registration Statement on Form S-8 (File No. 333-138156) filed on October 23, 2006).
10.13*†	Director Compensation Agreement between Patrick E. Malloy and Goodrich Petroleum Corporation dated June 1, 2011.
10.14†	Amended and Restated Severance Agreement between the Company and Walter G. Goodrich dated November 5, 2007 (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on November 8, 2007).
10.15†	Amended and Restated Severance Agreement between the Company and Robert C. Turnham, Jr. dated November 5, 2007 (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on November 8, 2007).
10.16†	Amended and Restated Severance Agreement between the Company and Mark E. Ferchau dated November 5, 2007 (Incorporated by reference to Exhibit 10.4 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on November 8, 2007).
10.17	Second Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas and certain lenders dated May 5, 2009 (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on May 7, 2009).
10.18	First Amendment to Second Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas and certain lenders, dated as of September 22, 2009 (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on September 28, 2009).
10.19	Participation Agreement between the Company and Turnham Interests, Inc. dated May 25, 2010 (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on August 5, 2010).

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10.20	Third Amendment to Second Amended and Restated Credit Agreement dated as of February 4, 2011 among Goodrich Petroleum Company, L.L.C., BNP Paribas, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on February 10, 2011).
10.21	Second Amendment to Second Amended and Restated Credit Agreement dated as of October 29, 2010 among Goodrich Petroleum Company, L.L.C., BNP Paribas, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on February 10, 2011).
10.22	Fourth Amendment to Second Amended and Restated Credit Agreement dated as of February 25, 2011 among Goodrich Petroleum Company, L.L.C., BNP Paribas, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on March 3, 2011).
10.23	Sixth Amendment to Second Amended and Restated Credit Agreement dated as of October 31, 2011 among Goodrich Petroleum Company, L.L.C., BNP Paribas, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-12719) filed on November 4, 2011).
10.24	Fifth Amendment to Second Amended and Restated Credit Agreement dated as of May 16, 2011 among Goodrich Petroleum Company, L.L.C., BNP Paribas, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 to the Company’s Annual Report on Form 10-K (File No. 001-12719) filed on February 24, 2012).
10.25	Seventh Amendment to Second Amended and Restated Credit Agreement dated as of November 2, 2012 among Goodrich Petroleum Company, L.L.C., Well Fargo Bank, National Association, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on May 7, 2013).
10.26	Eighth Amendment to Second Amended and Restated Credit Agreement dated as of March 13, 2013 among Goodrich Petroleum Company, L.L.C., Well Fargo Bank, National Association, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed on May 7, 2013).
10.27	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 (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on November 5, 2013).
10.28*†	Director Compensation Agreement between Patrick E. Malloy and Goodrich Petroleum Corporation dated June 1, 2013.
12.1*	Ratio of Earnings to Fixed Charges.
12.2*	Ratio of Earnings to Fixed Charges and Preference Securities Dividends.
21.1*	Subsidiary of the Registrant:
	Goodrich Petroleum Company LLC—Organized in the State of Louisiana.
23.1*	Consent of Ernst & Young LLP—Independent Registered Public Accounting Firm.
23.2*	Consent of Netherland, Sewell & Associates, Inc.
23.3*	Consent of Ryder Scott Company
31.1*	Certification by Chief Executive Officer Pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

101

31.2*	Certification by 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 by 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 by Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*	Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists.
99.2*	Report of Ryder Scott Company, Independent Petroleum Engineers and Geologists.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.LAB*	XBRL Labels Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document

* Filed herewith.

** Furnished herewith.

† Denotes management contract or compensatory plan or arrangement.

102

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, on February 21, 2014.

GOODRICH PETROLEUM CORPORATION
By:	/s/    WALTER G. GOODRICH
	Walter G. Goodrich Chief Executive Officer

POWER OF ATTORNEY

Each person whose signature appears below hereby constitutes and appoints Walter G. Goodrich and Jan L. Schott and each of them, his true and lawful attorney-in-fact and agent, with full powers of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report of Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission granting to said attorneys-in-fact, and each of them, full power and authority to perform any other act on behalf of the undersigned required to be done in connection therewith.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant in the capacities indicated on February 21, 2014.

Signature	Title
/s/ WALTER G. GOODRICH Walter G. Goodrich	Vice Chairman, Chief Executive Officer and Director (Principal Executive Officer)
/s/ JAN L. SCHOTT Jan L. Schott	Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
/s/ PATRICK E. MALLOY, III Patrick E. Malloy, III	Chairman of Board of Directors
/s/ ROBERT C. TURNHAM, JR. Robert C. Turnham, Jr.	President, Chief Operating Officer and Director
/s/ JOSIAH T. AUSTIN Josiah T. Austin	Director
/s/ HENRY GOODRICH Henry Goodrich	Director
/s/ PETER D. GOODSON Peter D. Goodson	Director
/s/ MICHAEL J. PERDUE Michael J. Perdue	Director
/s/ ARTHUR A. SEELIGSON Arthur A. Seeligson	Director

103

Signature	Title
/s/ STEPHEN M. STRATY Stephen M. Straty	Director
/s/ GENE WASHINGTON Gene Washington	Director

104

EX-10.13

Exhibit 10.13

GOODRICH PETROLEUM CORPORATION

DIRECTOR COMPENSATION AGREEMENT

This Director Compensation Agreement (“Agreement”), effective as of June 1, 2011 is by and between Patrick E. Malloy (“Malloy”) and Goodrich Petroleum Corporation (“GPC”).

WHEREAS, Malloy serves as the Chairman of the Board of Directors of GPC; and

WHEREAS, GPC desires to incentivize Malloy to continue as the Chairman;

NOW, THEREFORE, the parties hereby agree that Malloy’s compensation for serving as the Chairman for the period beginning June 1, 2011 and ending May 31, 2013 shall be as follows:

1. Beginning on June 15, 2011 and on or about the 15^th business day of each month thereafter on which Malloy continues as the Chairman, until May 15, 2013, GPC shall pay Malloy $41,667.00 (Forty One Thousand Six Hundred and Sixty Seven Dollars).

2. On December 1, 2011, and on December 1, 2012, Malloy shall be granted a Stock Payment Award under the GPC Long-Term Incentive Plan with respect to that number of restricted “phantom” shares of Common Stock of GPC that have, on such date, an aggregate Value of $500,000.00 (Five Hundred Thousand Dollars), with Value being the closing price per share of the Common Stock on such date, as reported on the New York Stock Exchange. Such shares to vest on the anniversary date of each respective grant over the next three years.

3. If Malloy ceases to be the Chairman for any reason prior to May 31, 2013, all future monthly payments and stock grants provided hereunder shall automatically cease.

IN WITNESS WHEREOF, the parties have executed this Agreement effective for all purposes as provided above.

GOODRICH PETROLEUM CORPORATION
By:	/s/    Michael Killelea
Title:	Senior Vice President, General Counsel and
	Corporate Secretary
CHAIRMAN OF THE BOARD
/s/ Patrick E. Malloy
Patrick E. Malloy

EX-10.28

Exhibit 10.28

GOODRICH PETROLEUM CORPORATION

DIRECTOR COMPENSATION AGREEMENT

This Director Compensation Agreement (“Agreement”), effective as of June 1, 2013 is by and between Patrick E. Malloy (“Malloy”) and Goodrich Petroleum Corporation (“GPC”).

WHEREAS, Malloy serves as the Chairman of the Board of Directors of GPC; and

WHEREAS, GPC desires to incentivize Malloy to continue as the Chairman;

NOW, THEREFORE, the parties hereby agree that Malloy’s compensation for serving as the Chairman for the period beginning June 1, 2013 and ending May 31, 2015 shall be as follows:

1. Beginning on June 15, 2013 and on or about the 15^th business day of each month thereafter on which Malloy continues as the Chairman, until May 15, 2015, GPC shall pay Malloy $41,667 (Forty One Thousand Six Hundred and Sixty Seven Dollars).

2. Beginning December 1, 2013 Malloy, and on December 1, 2014, Malloy shall be granted a Stock Payment Award under the GPC Long-Term Incentive Plan with respect to that number of restricted “phantom” shares of Common Stock of GPC that have, on such date, an aggregate Value of $500,000 (Five Hundred Thousand Dollars), with Value being the closing price per share of the Common Stock on such date, as reported on the New York Stock Exchange. Such shares to vest on the anniversary date of the grant over the next three years.

3. If Malloy ceases to be the Chairman for any reason prior to May 31, 2015, all future monthly payments and stock grants provided hereunder shall automatically cease.

IN WITNESS WHEREOF, the parties have executed this Agreement effective for all purposes as provided above.

GOODRICH PETROLEUM CORPORATION
By:	/s/ Michael Killelea
Title:	Senior Vice President, General Counsel and Corporate Secretary
CHAIRMAN OF THE BOARD
/s/    Patrick E. Malloy
Patrick E. Malloy

EX-12.1

Exhibit 12.1

GOODRICH PETROLEUM CORPORATION

RATIO OF EARNINGS TO FIXED CHARGES

(In Thousands, Except Ratios)

	Year ended December 31,
	2013			2012			2011			2010			2009
Earnings:
Income (loss) before income taxes	$	(95,186	)	$	(84,202	)	$	(31,758	)	$	(262,205	)	$	(318,297	)
Plus: fixed charges		51,187			52,403			49,351			37,179			26,148
Earnings available for fixed charges	$	(43,999	)	$	(31,799	)	$	17,593		$	(225,026	)	$	(292,149	)
Fixed Charges:
Interest expense	$	51,187		$	52,403		$	49,351		$	37,179		$	26,148
Total fixed charges	$	51,187		$	52,403		$	49,351		$	37,179		$	26,148
Ratio of Earnings to Fixed Charges			(a )			(b)			(c)			(d )			(e)

(a) Earnings for the year ended December 31, 2013 were inadequate to cover fixed charges. The coverage deficiency was $95.2 million.

(b) Earnings for the year ended December 31, 2012 were inadequate to cover fixed charges. The coverage deficiency was $84.2 million.

(c) Earnings for the year ended December 31, 2011 were inadequate to cover fixed charges. The coverage deficiency was $31.8 million.

(d) Earnings for the year ended December 31, 2010 were inadequate to cover fixed charges. The coverage deficiency was $262.2 million.

(e) Earnings for the year ended December 31, 2009 were inadequate to cover fixed charges. The coverage deficiency was $318.3 million.

EX-12.2

Exhibit 12.2

GOODRICH PETROLEUM CORPORATION

RATIO OF EARNINGS TO FIXED CHARGES AND PREFERENCE SECURITIES DIVIDENDS

(In Thousands, Except Ratios)

	Year ended December 31,
	2013			2012			2011			2010			2009
Earnings:
Income (loss) before income taxes	$	(95,186	)	$	(84,202	)	$	(31,758	)	$	(262,205	)	$	(318,297	)
Plus: fixed charges		51,187			58,450			55,398			43,226			33,816
Preference securities dividends		(18,604	)		(6,047	)		(6,047	)		(6,047	)		(7,668	)
Earnings available for fixed charges	$	(62,603	)	$	(31,799	)	$	17,593		$	(225,026	)	$	(292,149	)
Fixed Charges:
Interest expense	$	51,187		$	52,403		$	49,351		$	37,179		$	26,148
Preference securities dividends		18,604			6,047			6,047			6,047			7,668
Total fixed charges	$	69,791		$	58,450		$	55,398		$	43,226		$	33,816
Ratio of Earnings to Fixed Charges and Preference Securities Dividends			(a )			(b )			(c )			(d)			(e)

(a) Earnings for the year ended December 31, 2013 were inadequate to cover fixed charges and preference securities dividends. The coverage deficiency was $113.8 million.

(b) Earnings for the year ended December 31, 2012 were inadequate to cover fixed charges and preference securities dividends. The coverage deficiency was $90.2 million.

(c) Earnings for the year ended December 31, 2011 were inadequate to cover fixed charges and preference securities dividends. The coverage deficiency was $37.8 million.

(d) Earnings for the year ended December 31, 2010 were inadequate to cover fixed charges and preference securities dividends. The coverage deficiency was $268.3 million.

(e) Earnings for the year ended December 31, 2009 were inadequate to cover fixed charges and preference securities dividends. The coverage deficiency was $326.0 million.

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

1. Registration Statement (Form S-3 No. 333-186129) of Goodrich Petroleum Corporation,

2. Registration Statement (Form S-4 No. 333-178967) of Goodrich Petroleum Corporation,

3. Registration Statement (Form S-8 No. 333-120427) pertaining to the 1995 Stock Option Plan of Goodrich Petroleum Corporation, and

4. Registration Statement (Form S-8 No. 333-138156) pertaining to the 2006 Long-Term Incentive Plan of Goodrich Petroleum Corporation;

of our reports dated February 21, 2014, with respect to the consolidated financial statements of Goodrich Petroleum Corporation and the effectiveness of internal control over financial reporting of Goodrich Petroleum Corporation included in this Annual Report (Form 10-K) for the year ended December 31, 2013.

/s/ Ernst & Young LLP

Houston, Texas

February 21, 2014

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We consent to the incorporation by reference in the Registration Statements No. 333-186129 on Form S-3; No. 333-178967 on Form S-4 No. 333-120427 on S-8 and No. 333-138156 on Form S-8 of Goodrich Petroleum Corporation of information relating to Goodrich Petroleum Corporation’s estimated proved reserves as set forth under the captions “Part I, Item 1 and 2. Business and Properties – Oil and Natural Gas Reserves” in Goodrich Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2013 and to the inclusion of our report dated February 5, 2014 in Goodrich Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2013.

NETHERLAND SEWELL & ASSOCIATES, INC.
By:	/s/ J. Carter Henson, Jr.
	J. Carter Henson, Jr., P.E. Senior Vice President

Houston, Texas

February 21, 2014

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supercede the digital document.

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We consent to the incorporation by reference in the Registration Statements:

1. Registration Statement (Form S-3 No. 333-186129) of Goodrich Petroleum Corporation,

2. Registration Statement (Form S-4 No. 333-178967) of Goodrich Petroleum Corporation,

3. Registration Statement (Form S-8 No. 333-120427) pertaining to the 1995 Stock Option Plan of Goodrich Petroleum Corporation, and

4. Registration Statement (Form S-8 No. 333-138156) pertaining to the 2006 Long-Term Incentive Plan of Goodrich Petroleum Corporation.

of information relating to Goodrich Petroleum Corporation’s estimated proved reserves as set forth under the captions “Part I, Item 1 and 2. Business and Properties – Oil and Natural Gas Reserves” in Goodrich Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2013 and to the inclusion of our report dated January 24, 2014 in Goodrich Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2013.

/s/ Ryder Scott Company, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

February 21, 2014

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

15 U.S.C. SECTION 7241

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Walter G. Goodrich, certify that:

1. I have reviewed this annual report on Form 10-K of Goodrich Petroleum Corporation (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiary, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 21, 2014

/s/ Walter G. Goodrich

Walter G. Goodrich

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

15 U.S.C. SECTION 7241

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Jan L. Schott, certify that:

1. I have reviewed this annual report on Form 10-K of Goodrich Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiary, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 21, 2014

/s/ Jan L. Schott

Jan L. Schott

Senior Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Goodrich Petroleum Corporation (the “Company”) on Form 10-K for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Walter G. Goodrich, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes Oxley Act of 2002, that, to my knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities and Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Walter G. Goodrich

Walter G. Goodrich

Chief Executive Officer

February 21, 2014

This certification is provided pursuant to Section 906 of the Sarbanes Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes Oxley Act of 2002, be deemed filed by the Company or the certifying officer for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

A signed original of this written statement required by Section 906 has been provided to Goodrich Petroleum Corporation and will be retained by it and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Goodrich Petroleum Corporation (the “Company”) on Form 10-K for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jan L. Schott, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes Oxley Act of 2002, that, to my knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities and Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Jan L. Schott

Jan L. Schott

Senior Vice President and Chief Financial Officer

February 21, 2014

This certification is provided pursuant to Section 906 of the Sarbanes Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes Oxley Act of 2002, be deemed filed by the Company or the certifying officer for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

A signed original of this written statement required by Section 906 has been provided to Goodrich Petroleum Corporation and will be retained by it and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.1

Exhibit 99.1

February 5, 2014

Mr. Mark E. Ferchau

Goodrich Petroleum Corporation

801 Louisiana Street, Suite 700

Houston, Texas 77002

Dear Mr. Ferchau:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2013, to the Goodrich Petroleum Corporation (Goodrich) interest in certain oil and gas properties located in the United States. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute approximately 79 percent of the proved reserves owned by Goodrich. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Goodrich’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Goodrich interest in these properties, as of December 31, 2013, to be:

	Net Reserves						Future Net Revenue (M$)
Category	Oil (MBBL)		NGL (MBBL)		Gas (MMCF)		Total		Present Worth at 10%
Proved Developed Producing		128.8		1,446.3		107,942.8		205,378.9		118,804.7
Proved Developed Non-Producing		5.5		92.8		4,502.2		4,720.9		1,849.1
Proved Undeveloped(1)		536.2		3,532.1		208,514.8		186,759.8		(21,040.2	)
Total Proved		670.4		5,071.2		320,959.8		396,859.6		99,613.5

Totals may not add because of rounding.

⁽¹⁾  Estimates of proved undeveloped reserves have been included for certain locations that would generate positive future net revenue but would have negative present worth discounted at 10 percent based on the constant prices and costs discussed in subsequent paragraphs of this letter.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved reserves. Estimates of proved undeveloped reserves have been included for certain locations that generate positive future net revenue but have negative present worth discounted at 10 percent based on the constant prices and costs discussed in subsequent paragraphs of this letter. These locations have been included based on the operators’ declared intent to drill these wells, as evidenced by Goodrich’s internal budget, reserves estimates, and price forecast. No study was made to determine whether probable or possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is Goodrich’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Goodrich’s share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2013. For oil and NGL volumes, the average West Texas Intermediate spot price of $96.94 per barrel is adjusted by field for quality, transportation fees, and regional price differentials. For gas volumes, the average Henry Hub spot price of $3.670 per MMBTU is adjusted by field for energy content, transportation fees, and regional price differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $100.38 per barrel of oil, $31.44 per barrel of NGL, and $2.974 per MCF of gas.

Operating costs used in this report are based on operating expense records of Goodrich. For nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, operating costs for the operated properties are limited to direct lease- and field-level costs and Goodrich’s estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Goodrich and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Goodrich’s estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Goodrich interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Goodrich receiving its net revenue interest share of estimated future gross production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and material balance, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Goodrich, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

		Sincerely,
		NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699
			/s/ C.H. (Scott) Rees III
		By:
			C.H. (Scott) Rees III, P.E.
			Chairman and Chief Executive Officer
	/s/ J. Carter Henson, Jr.		/s/ Mike K. Norton
By:		By:
	J. Carter Henson, Jr., P.E. 73964		Mike K. Norton, P.G. 441
	Senior Vice President		Senior Vice President
Date Signed: February 5, 2014		Date Signed: February 5, 2014

JCH:LRG

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves—Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves—Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Definitions - Page 1 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

Definitions - Page 2 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

Definitions - Page 3 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

Definitions - Page 4 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90%

Definitions - Page 5 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:

a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a. Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.

d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Definitions - Page 6 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects—such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations—by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

• The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

• The company’s historical record at completing development of comparable long-term projects;

• The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

• The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

• The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 7 of 7

EX-99.2

Exhibit 99.2

January 24, 2014

Goodrich Petroleum Corporation

801 Louisiana, Suite 700

Houston, Texas 77002

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of Goodrich Petroleum Corporation (Goodrich) as of December 31, 2013. The subject properties are located in the states of Louisiana, Mississippi, and Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 17, 2014 and presented herein, was prepared for public disclosure by Goodrich in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott account for a portion of Goodrich’s total net proved reserves as of December 31, 2013. Based on information provided by Goodrich, the third party estimate conducted by Ryder Scott addresses 83.4 percent of the total proved developed net liquid hydrocarbon reserves, 4 percent of the total proved developed net gas reserves, 60.6 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 1.8 percent of the total proved undeveloped net gas reserves of Goodrich.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2013, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Goodrich Petroleum Corporation

As of December 31, 2013

	Proved
	Developed							Total Proved
	Producing		Non-Producing			Undeveloped
Net Remaining Reserves
Oil/Condensate—Barrels		7,608,821		0			5,798,694		13,407,515
Plant Products—Barrels		818,163		0			463,891		1,282,054
Gas—MMCF		4,739		0			3,917		8,656
Income Data
Future Gross Revenue	$	745,219,960	$	0		$	571,695,887	$	1,316,915,847
Deductions		267,195,391		150,288	*		378,722,082		646,067,761
Future Net Income (FNI)	$	478,024,569	$	(150,288	)	$	192,973,805	$	670,848,086
Discounted FNI @ 10%	$	314,433,059	$	(136,813	)	$	58,358,235	$	372,654,481

* Abandonment costs for two wells

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants L.C. The program was used at the request of Goodrich. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. Other deductions consist of variable expenses based oil and gas production rates. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 98 percent and gas reserves account for the remaining 2 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded annually. Future net income was discounted at four other discount rates which were also compounded annually. These results are shown in summary form as follows.

	Discounted Future Net Income As of December 31, 2013
Discount Rate Percent	Total Proved
9	$	390,610,851
15	$	302,174,463
20	$	253,298,449
25	$	217,536,527

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the behind pipe category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Goodrich’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Goodrich’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Goodrich owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties that we evaluated were estimated by performance methods or the analogy method. All of the proved producing reserves attributable to producing wells and/or reservoirs that we evaluated were estimated by decline curve analysis which utilized extrapolations of historical production data available through December 2013, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Goodrich or obtained from public data sources and were considered sufficient for the purpose thereof. All of the proved undeveloped reserves that we evaluated were estimated by the analogy method. The data utilized from the analogues incorporated into our analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Goodrich has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Goodrich with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Goodrich. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Goodrich. Wells or locations

that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Goodrich furnished us with the above mentioned average prices in effect on December 31, 2013. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Goodrich. The differentials furnished by Goodrich were reviewed by us for their reasonableness using information furnished by Goodrich for this purpose.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$96.94/Bbl		$98.83/Bbl
	NGLs	WTI Cushing	$96.94/Bbl		$31.44/Bbl
	Gas	Henry Hub	$3.67/MMBTU		$2.51/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by Goodrich and are based on the operating expense reports of Goodrich and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished by Goodrich were reviewed by us for their reasonableness using information furnished by Goodrich for this purpose. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Goodrich and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by Goodrich were accepted without independent verification.

The proved undeveloped reserves in this report have been incorporated herein in accordance with Goodrich’s plans to develop these reserves as of December 31, 2013. The implementation of Goodrich’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Goodrich’s management. As the result of our inquiries during the course of preparing this report, Goodrich has informed us that the development activities included herein have been subjected to and received the internal approvals required by Goodrich’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Goodrich. Additionally, Goodrich has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Goodrich were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy-five years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Goodrich. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Goodrich.

Goodrich makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Goodrich has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3, Form S-4 and Form S-8 of Goodrich of the references to our name as well as to the references to our third party report for Goodrich, which appears in the December 31, 2013 annual report on Form 10-K of Goodrich. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Goodrich.

We have provided Goodrich with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Goodrich and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ Michael F. Stell

Michael F. Stell, P.E.

TBPE License No. 56416

Advising Senior Vice President

[SEAL]

MFS (FWZ)/pl

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Michael F. Stell was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.

Mr. Stell, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1992, is an Advising Senior Vice President and is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Stell served in a number of engineering positions with Shell Oil Company and Landmark Concurrent Solutions. For more information regarding Mr. Stell’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Stell fulfills. As part of his 2009 continuing education hours, Mr. Stell attended an internally presented 13 hours of formalized training as well as a day-long public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Stell attended an additional 15 hours of formalized in-house training as well as an additional five hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. As part of his 2010 continuing education hours, Mr. Stell attended an internally presented six hours of formalized training and ten hours of formalized external training covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, reserve reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves, evaluation of enhanced oil recovery reserves, and ethics training. For each year starting 2011 through 2013, as of the date of this report, Mr. Stell has 20 hours of continuing education hours relating to reserves, reserve evaluations, and ethics.

Based on his educational background, professional training and over 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications for a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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Summary of Unrecognized Compensation Cost (Detail) (Restricted Stock, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation costs	$ 19,938
Weighted Average years to recognition	2 years 5 months 9 days

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Derivative Activities - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Derivative [Line Items]
Loss of fair value	$ 3.3

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Components of Income Tax Expense (Benefit) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Expense Benefit [Line Items]
Current,Federal
Current,State
Current income tax expense (benefit)
Deferred,Federal
Deferred,State
Deferred income tax expense (benefit)
Total tax (expense) benefit

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Outstanding Commodity Derivative Contracts (Detail) (USD $) In Thousands, unless otherwise specified						12 Months Ended								12 Months Ended								12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Natural Gas Swaps (MMBtu) 2014	Dec. 31, 2013 Natural Gas Swaps (MMBtu) Minimum 2014	Dec. 31, 2013 Natural Gas Swaps (MMBtu) Maximum 2014	Dec. 31, 2013 Natural Gas Swaps (MMBtu) Daily Not Designated as Hedging Instrument 2014 MMBTU	Dec. 31, 2013 Natural Gas Swaps (MMBtu) Annual Not Designated as Hedging Instrument 2014 MMBTU	Dec. 31, 2013 Natural Gas calls (MMBtu) 2015	Dec. 31, 2013 Natural Gas calls (MMBtu) 2016	Dec. 31, 2013 Natural Gas calls (MMBtu) Minimum 2015	Dec. 31, 2013 Natural Gas calls (MMBtu) Minimum 2016	Dec. 31, 2013 Natural Gas calls (MMBtu) Maximum 2015	Dec. 31, 2013 Natural Gas calls (MMBtu) Maximum 2016	Dec. 31, 2013 Natural Gas calls (MMBtu) Daily Not Designated as Hedging Instrument 2015 MMBTU	Dec. 31, 2013 Natural Gas calls (MMBtu) Daily Not Designated as Hedging Instrument 2016 MMBTU	Dec. 31, 2013 Natural Gas calls (MMBtu) Annual Not Designated as Hedging Instrument 2015 MMBTU	Dec. 31, 2013 Natural Gas calls (MMBtu) Annual Not Designated as Hedging Instrument 2016 MMBTU	Dec. 31, 2013 Oil Swap (BBL) 2014	Dec. 31, 2013 Oil Swap (BBL) 2015	Dec. 31, 2013 Oil Swap (BBL) Minimum 2014	Dec. 31, 2013 Oil Swap (BBL) Maximum 2014	Dec. 31, 2013 Oil Swap (BBL) Daily Not Designated as Hedging Instrument 2014 bbl	Dec. 31, 2013 Oil Swap (BBL) Daily Not Designated as Hedging Instrument 2015 bbl	Dec. 31, 2013 Oil Swap (BBL) Annual Not Designated as Hedging Instrument 2014 bbl	Dec. 31, 2013 Oil Swap (BBL) Annual Not Designated as Hedging Instrument 2015 bbl
Derivative [Line Items]
Volume						30,000	10,950,000							20,000	20,000	7,300,000	7,300,000
Volume																						3,800	1,300	1,387,000	474,500
Fixed Price, swaps				4.18	5.06														94.55	90.95	98.02
Fixed Price, calls										5.05	5.05	5.06	5.06
Fair Value at December 31, 2013	$ 871	$ (2,213)	$ 6,187					$ (1,125)	$ (1,246)									$ (4,341)	$ 1,396

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Computations of Basic and Diluted Income (Loss) Per Share (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Basic loss per share:
Loss applicable to common stock	$ (30,926)	$ (32,790)	$ (20,099)	$ (29,975)	$ (77,188)	$ 10,894	$ (4,714)	$ (19,241)	$ (113,790)		$ (90,249)		$ (37,805)
Weighted-average shares of common stock outstanding									38,098		36,390		36,124
Basic loss per share	$ (0.73)	$ (0.89)	$ (0.55)	$ (0.82)	$ (2.12)	$ 0.30	$ (0.13)	$ (0.53)	$ (2.99)		$ (2.48)		$ (1.05)
Diluted loss per share:
Loss applicable to common stock	(30,926)	(32,790)	(20,099)	(29,975)	(77,188)	10,894	(4,714)	(19,241)	(113,790)		(90,249)		(37,805)
Dividends on convertible preferred stock										[1]		[1]		[1]
Interest and amortization of loan cost on convertible senior notes, net of tax										[2]		[2]		[2]
Diluted loss									$ (113,790)		$ (90,249)		$ (37,805)
Weighted-average shares of common stock outstanding									38,098		36,390		36,124
Assumed conversion of convertible preferred stock										[1]		[1]		[1]
Assumed conversion of convertible senior notes										[3]		[3]		[3]
Stock options and restricted stock										[2]		[2]		[2]
Weighted-average diluted shares outstanding									38,098		36,390		36,124
Diluted loss per share	$ (0.73)	$ (0.89)	$ (0.55)	$ (0.82)	$ (2.12)	$ 0.30	$ (0.13)	$ (0.53)	$ (2.99)		$ (2.48)		$ (1.05)

[1] Common shares issuable upon assumed conversion of convertible preferred stock were not presented as they would have been anti-dilutive.

[2] 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.

[3] Common shares issuable upon assumed conversion of the 2026 Notes, the 2029 Notes and 2032 Notes were not presented as they would have been anti-dilutive.

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Share-Based Compensation Plans - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended		1 Months Ended	12 Months Ended
	Dec. 31, 2013	May 31, 2006	May 31, 2006 Restricted Stock	Dec. 31, 2013 Maximum	Dec. 31, 2012 Maximum	Dec. 31, 2011 Maximum	Dec. 31, 2013 2006 Plan	Dec. 31, 2013 2006 Plan Restricted Stock	Dec. 31, 2013 2006 Plan Minimum	Dec. 31, 2013 2006 Plan Maximum
Share Based Compensation [Line Items]
Shares reserved for issuance as awards		4.0
Shares granted but unvested			1.6
Shares available for future grants	0.2
Vesting Period							3 years	3 years
Expiry date from the date of grant									7 years	10 years
Intrinsic value of options exercised				$ 0.1	$ 0.1	$ 0

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Derivative Assets and Liabilities Recorded at Fair Value (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Current Assets Commodity Derivatives	$ 6,187	$ 2,125
Non-current Assets Commodity Derivatives	1,396
Current Liabilities Commodity Derivatives	(4,341)	(351)
Non-current Liabilities Commodity Derivatives	(2,371)	(3,987)
Total	871	(2,213)
Fair Value, Inputs, Level 2
Derivative [Line Items]
Current Assets Commodity Derivatives	6,187	2,125
Non-current Assets Commodity Derivatives	1,396
Current Liabilities Commodity Derivatives	(4,341)	(351)
Non-current Liabilities Commodity Derivatives	(2,371)	(3,987)
Total	$ 871	$ (2,213)

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Loss Per Common Share (Tables)

12 Months Ended

Dec. 31, 2013

Computation of Net Income (Loss) Per Common Share

The following table sets forth information related to the computations of basic and diluted loss per share.

	Year Ended December 31,
	2013			2012			2011
	(Amounts in thousands, except per share data)
Basic loss per share:
Loss applicable to common stock	$	(113,790	)	$	(90,249	)	$	(37,805	)
Weighted-average shares of common stock outstanding		38,098			36,390			36,124
Basic loss per share	$	(2.99	)	$	(2.48	)	$	(1.05	)
Diluted loss per share:
Loss applicable to common stock	$	(113,790	)	$	(90,249	)	$	(37,805	)
Dividends on convertible preferred stock (1)		—			—			—
Interest and amortization of loan cost on convertible senior notes, net of tax (3)		—			—			—
Diluted loss	$	(113,790	)	$	(90,249	)	$	(37,805	)
Weighted-average shares of common stock outstanding		38,098			36,390			36,124
Assumed conversion of convertible preferred stock (1)		—			—			—
Assumed conversion of convertible senior notes (2)		—			—			—
Stock options and restricted stock (3)		—			—			—
Weighted-average diluted shares outstanding		38,098			36,390			36,124
Diluted loss per share	$	(2.99	)	$	(2.48	)	$	(1.05	)
(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
(2)    Common shares issuable upon assumed conversion of the 2026 Notes, the 2029 Notes and 2032 Notes were not presented as they would have been anti-dilutive.		6,307			6,311			7,067
(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.		620			238			171

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Schedule Of Deferred Tax (Liabilities) Assets (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Schedule of Deferred Income Tax Assets and Liabilities [Line Items]
Accrued liabilities	$ 133	$ 375
Contingent liabilities and other		134
Less valuation allowance	(126)	(498)
Total current deferred tax assets	7	11
Derivative financial instruments	(646)	(621)
Accrued liabilities	(26)	(26)
Total current deferred tax liabilities	(672)	(647)
Net current deferred tax liability	(665)	(636)
Operating loss carry-forwards	211,589	156,723
State Tax NOL and Credits	5,805	3,867
Statutory depletion carry-forward	7,035	7,035
AMT tax credit carry-forward	1,227	1,324
Compensation	3,496	3,364
Contingent liabilities and other	858	1,907
Property and equipment	(3,248)	26,848
Total gross noncurrent deferred tax assets	226,762	201,068
Less valuation allowance	(217,558)	(193,459)
Net noncurrent deferred tax assets	9,204	7,609
Bond discount	(74)	(61)
Debt discount	(8,465)	(6,912)
Total non-current deferred tax liabilities	(8,539)	(6,973)
Net non-current deferred tax asset	$ 665	$ 636

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Components of Debt (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2013 5% Convertible Senior Notes due 2032		Sep. 30, 2013 5% Convertible Senior Notes due 2032	Aug. 26, 2013 5% Convertible Senior Notes due 2032	Dec. 31, 2012 Senior Credit Facility		Dec. 31, 2013 3.25% Convertible Senior Notes due 2026		Dec. 31, 2012 3.25% Convertible Senior Notes due 2026		Dec. 31, 2013 5.0% Convertible Senior Notes due 2029		Dec. 31, 2012 5.0% Convertible Senior Notes due 2029		Dec. 31, 2009 5.0% Convertible Senior Notes due 2029	Sep. 30, 2009 5.0% Convertible Senior Notes due 2029	Dec. 31, 2013 8.875% Senior Notes due 2019		Dec. 31, 2012 8.875% Senior Notes due 2019		Mar. 02, 2011 8.875% Senior Notes due 2019
Debt Instrument [Line Items]
Debt Instrument, Principal	$ 494,650		$ 588,929		$ 167,405	[1]	$ 57,000	$ 109,250	$ 95,000	[2]	$ 429		$ 429		$ 51,816	[3]	$ 218,500	[3]		$ 218,500	$ 275,000		$ 275,000		$ 275,000
Debt Instrument, Carrying Amount	485,529		568,671		160,437	[1]			95,000	[2]	429		429		49,663	[3]	198,242	[3]	171,100		275,000		275,000
Debt Instrument, Fair Value	$ 512,041	[2]	$ 561,654	[2]	$ 171,863	[1],[2]			$ 95,000	[2]	$ 429	[2]	$ 429	[2]	$ 51,686	[2],[3]	$ 204,975	[2],[3]			$ 288,063	[2]	$ 261,250	[2]

[1] 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 $7.0 million as of December 31, 2013.

[2] The carrying amount for the Senior Credit Facility represents fair value as the variable interest rates are reflective of current market conditions. The fair value of the notes was obtained by direct market quotes within Level 1 of the fair value hierarchy.

[3] The debt discount is amortized using the effective interest rate method based upon an original five year term through October 1, 2014. The debt discount was $2.1 million and $20.3 million as of December 31, 2013 and December 31, 2012, respectively.

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Schedule of Restricted Stock Activity And Values (Detail) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share Based Compensation [Line Items]
Number of Shares Granted	746,163	1,073,727	561,714
Value of Shares Granted	$ 13,194	$ 9,533	$ 7,921
Fair Value of Stock Vested	$ 9,960	$ 3,335	$ 5,764

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Stockholders' Equity - Additional Information (Detail) (USD $)	12 Months Ended			0 Months Ended					0 Months Ended		1 Months Ended			12 Months Ended		1 Months Ended				1 Months Ended			12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Oct. 21, 2013 Underwritten Public Offering	Dec. 21, 2010 Series B Convertible Preferred Stock	Jan. 23, 2006 Series B Convertible Preferred Stock	Dec. 21, 2005 Series B Convertible Preferred Stock	Dec. 31, 2013 Series B Convertible Preferred Stock	Dec. 31, 2012 Series B Convertible Preferred Stock	Dec. 21, 2010 Series B Convertible Preferred Stock Minimum D	Dec. 21, 2010 Series B Convertible Preferred Stock Maximum D	Apr. 30, 2013 Series C Cumulative Preferred Stock	Dec. 31, 2013 Series C Cumulative Preferred Stock	Dec. 31, 2012 Series C Cumulative Preferred Stock	Dec. 31, 2013 Series C Cumulative Preferred Stock Minimum	Dec. 31, 2013 Series C Cumulative Preferred Stock Maximum	Aug. 31, 2013 Depositary Shares	Apr. 30, 2013 Depositary Shares	Aug. 31, 2013 American Depository Share	Apr. 30, 2013 American Depository Share	Aug. 31, 2013 Series D Cumulative Preferred Stock	Dec. 31, 2013 Series D Cumulative Preferred Stock	Dec. 31, 2012 Series D Cumulative Preferred Stock	Dec. 31, 2013 Series D Cumulative Preferred Stock Minimum	Dec. 31, 2013 Series D Cumulative Preferred Stock Maximum
Stockholders Equity [Line Items]
Preferred stock issued					600,000	1,650,000	2,250,000	2,250,000			110,000,000	4,400,000	0							130,000,000	5,200,000	0
Net proceeds of preferred stock	$ 230,625,000				$ 29,000,000	$ 79,800,000					$ 105,400,000									$ 124,900,000
Offering costs						2,700,000
Preferred stock, liquidation preference						$ 50					$ 25,000							$ 25.00	$ 25.00	$ 25,000
Aggregate preferred stock liquidation preference						$ 82,500,000
Preferred stock, dividend rate, percentage	5.375%					5.375%					10.00%									9.75%
Increase in dividend rate, percentage						1.00%
Preferred stock conversion to number of common stock shares					1.5946
Preferred stock conversion price					$ 31.36							$ 25,000									$ 25,000
Consideration percentage in case of merger or consolidation					90.00%
Exercise of conversion right period									20	30
Common stock closing price percentage				130.00%
Common stock, shares issued	44,258,824	36,758,141	6,900,000													5,200,000	4,400,000
Percent of ownership interest held																0.001	0.001
Preferred share par value											$ 1.00									$ 1.00
Preferred sock redemption date														Apr. 10, 2018									Aug. 19, 2018
Maximum per share convertible rate															3,371.54									2,297.79
Common stock, price			$ 25.25

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Related Party Transactions - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Board of Directors Chairman
Related Party Transaction [Line Items]
Share of monthly capital and operating costs	$ 0.1	$ 0.1
Malloy Energy Company, LLC
Related Party Transaction [Line Items]
Share of monthly capital and operating costs	$ 0.3	$ 0.3

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Computations of Basic and Diluted Income (Loss) Per Share (Parenthetical) (Detail) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Assumed Conversion Of Preferred Stock
Earnings Per Share Disclosure [Line Items]
Common shares issuable upon assumed conversion	3,588	3,588	3,588
Assumed Conversion Of Notes
Earnings Per Share Disclosure [Line Items]
Common shares issuable upon assumed conversion	6,307	6,311	7,067
Assumed Conversion Of Restricted Stock and Employee Stock Options
Earnings Per Share Disclosure [Line Items]
Common shares issuable upon assumed conversion	620	238	171

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligations

NOTE 3—Asset Retirement Obligations

The reconciliation of the beginning and ending asset retirement obligation for the periods ending December 31, 2013 and 2012 is as follows (in thousands):

	December 31,
	2013			2012
Beginning balance	$	18,306		$	17,425
Liabilities incurred		471			693
Revisions in estimated liabilities (1)		1,290			2,005
Liabilities settled		(82	)		(767	)
Accretion expense		1,243			1,111
Dispositions		(372	)		(2,161	)
Ending balance	$	20,856		$	18,306
Current liability	$	99		$	168
Long term liability	$	20,757		$	18,138

(1) We increased our estimated liability in 2013 by $1.3 million as a result of a change in estimated plugging and abandonment cost on several of our fields.

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Acquisitions and Divestitures - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	0 Months Ended	12 Months Ended	0 Months Ended	4 Months Ended	12 Months Ended
	Sep. 28, 2012	Dec. 31, 2012 acre	Aug. 21, 2013 TMS	Dec. 31, 2013 TMS	Dec. 31, 2013 TMS Maximum	Aug. 21, 2013 TMS Oil and Gas Properties
Acquisitions And Divestitures [Line Items]
Percentage of working interest purchased in producing assets			66.70%
Acquisition effective date			Mar. 01, 2013
Closing price after purchase price adjustments			$ 24.6
Lease extensions cost			2.7
Adjusted purchase price net of lease extension costs			21.8
Purchase price allocation						21.8
Asset retirement obligation			0.1
Net cash paid			23.7
Operating income from acquired property				2.5
Revenue from acquired property				2.8
Expenses associated with the acquisition					0.1
Area of property, Gross		56,400
Acquired lease area of property		54,000
Payment in cash for acreage		18.4
Proceeds from sale of interest in non-core properties in South Henderson field	95
Realized gain on sale of assets	$ 44.0
Effective sales date of non-core properties	Jul. 01, 2012

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Components of Debt (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2009
5% Convertible Senior Notes due 2032
Debt Instrument [Line Items]
Debt discount	$ 7.5
Period of amortization on debt instrument	4 years
Debt discount amortization end date	Oct. 01, 2017
Unamortized debt discount	7.0
5.0% Convertible Senior Notes due 2029
Debt Instrument [Line Items]
Debt discount	$ 2.1	$ 20.3	$ 49.4
Period of amortization on debt instrument	5 years
Debt discount amortization end date		Oct. 01, 2014

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Summarized Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Summarized Quarterly Financial Data

Summarized Quarterly Financial Data (Unaudited)

(In Thousands, Except Per Share Amounts)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
2013
Revenues		47,084			48,485			57,161			50,565			203,295
Operating income (loss)		(13,142	)		(14,192	)		(854	)		(8,122	)		(36,310	)
Net income (loss)		(28,463	)		(16,143	)		(27,085	)		(23,495	)		(95,186	)
Net income (loss) applicable to common stock		(29,975	)		(20,099	)		(32,790	)		(30,926	)		(113,790	)
Basic income (loss) per common share		(0.82	)		(0.55	)		(0.89	)		(0.73	)		(2.99	)
Diluted income (loss) per common share		(0.82	)		(0.55	)		(0.89	)		(0.73	)		(2.99	)
2012
Revenues	$	45,308		$	41,346		$	45,960		$	48,231		$	180,845
Operating income (loss)		(14,241	)		(14,157	)		31,854			(67,141	)		(63,685	)
Net income (loss)		(17,729	)		(3,202	)		12,405			(75,676	)		(84,202	)
Net income (loss) applicable to common stock		(19,241	)		(4,714	)		10,894			(77,188	)		(90,249	)
Basic income (loss) per common share		(0.53	)		(0.13	)		0.30			(2.12	)		(2.48	)
Diluted income (loss) per common share		(0.53	)		(0.13	)		0.30			(2.12	)		(2.48	)

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Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2013

Unaudited Pro forma Condensed Consolidated Statements of Operations

The following tables present the Unaudited Pro forma Condensed Consolidated Statements of Operations, giving effect to the acquisition as if it had occurred on January 1, 2012:

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

For the Year Ended December 31, 2013

(In Thousands, Except Per Share Amounts)

	As Reported			Adjustments		As Adjusted
Total revenues	$	203,295		$	7,380	$	210,675
Operating expenses		239,605			497		240,102
Operating loss		(36,310	)		6,883		(29,427	)
Net loss		(95,186	)		6,883		(88,303	)
Net loss applicable to common stock	$	(113,790	)	$	6,883	$	(106,907	)
Per Common Share
Net loss applicable to common stock—basic	$	(2.99	)			$	(2.81	)
Net loss applicable to common stock—diluted	$	(2.99	)			$	(2.81	)
Weighted average common shares outstanding—basic		38,098					38,098
Weighted average common shares outstanding—diluted		38,098					38,098

For the Year Ended December 31, 2012

(In Thousands, Except Per Share Amounts)

	As Reported			Adjustments		As Adjusted
Total revenues	$	180,845		$	10,223	$	191,068
Operating expenses		244,530			1,657		246,187
Operating loss		(63,685	)		8,566		(55,119	)
Net loss		(84,202	)		8,566		(75,636	)
Net loss applicable to common stock	$	(90,249	)	$	8,566	$	(81,683	)
Per Common Share
Net Loss applicable to common stock—basic	$	(2.48	)			$	(2.24	)
Net loss applicable to common stock—diluted	$	(2.48	)			$	(2.24	)
Weighted average common shares outstanding—basic		36,390					36,390
Weighted average common shares outstanding—diluted		36,390					36,390

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Derivative Contracts (Detail)	12 Months Ended
	Dec. 31, 2013 bbl
Oil Swap (BBL) | Strike Price 92.95 | Oil Swap Contract Date January 1, 2014 - Contract Termination December 31, 2014
Derivative [Line Items]
Daily Volume	1,000
Strike Price	92.95
Contract Start Date	Jan. 01, 2014
Contract Termination	Dec. 31, 2014
Oil Swap (BBL) | Strike Price $98.02 | Oil Swap Contract Date November 1, 2013 - Contract Termination December 31, 2014
Derivative [Line Items]
Daily Volume	500
Strike Price	98.02
Contract Start Date	Nov. 01, 2013
Contract Termination	Dec. 31, 2014
Oil Swap (BBL) | Strike Price 94.55 | Oil Swap Contract Date January 1, 2014 - Contract Termination December 31, 2014
Derivative [Line Items]
Daily Volume	1,300	[1]
Strike Price	94.55	[1]
Contract Start Date	Jan. 01, 2014	[1]
Contract Termination	Dec. 31, 2014	[1]
Oil Swap (BBL) | Strike Price 94.55 | Oil Swap Contract Date January 1, 2015 - Contract Termination December 31, 2015
Derivative [Line Items]
Daily Volume	1,300	[1]
Strike Price	94.55	[1]
Contract Start Date	Jan. 01, 2015	[1]
Contract Termination	Dec. 31, 2015	[1]
Natural Gas Swaps (MMBtu) | Strike Price 4.1825 | Natural Gas Swap Contract Date October 1, 2013 - Contract Termination December 31, 2014
Derivative [Line Items]
Daily Volume	10,000
Strike Price	4.1825
Contract Start Date	Oct. 01, 2013
Contract Termination	Dec. 31, 2014
Natural Gas Swaps (MMBtu) | Strike Price 5.05 - 5.06 | Natural Gas Swap Contract Date January 1, 2014 - Contract Termination December 31, 2014
Derivative [Line Items]
Daily Volume	20,000
Contract Start Date	Jan. 01, 2014
Contract Termination	Dec. 31, 2014
Natural Gas calls (MMBtu) | Strike Price 5.05 - 5.06 | Natural Gas Calls Contract Date January 1, 2015 - Contract Termination December 31, 2016
Derivative [Line Items]
Daily Volume	20,000
Contract Start Date	Jan. 01, 2015
Contract Termination	Dec. 31, 2016
Minimum | Natural Gas Swaps (MMBtu) | Strike Price 5.05 - 5.06 | Natural Gas Swap Contract Date January 1, 2014 - Contract Termination December 31, 2014
Derivative [Line Items]
Strike Price	5.05
Minimum | Natural Gas calls (MMBtu) | Strike Price 5.05 - 5.06 | Natural Gas Calls Contract Date January 1, 2015 - Contract Termination December 31, 2016
Derivative [Line Items]
Strike Price	5.05
Maximum | Natural Gas Swaps (MMBtu) | Strike Price 5.05 - 5.06 | Natural Gas Swap Contract Date January 1, 2014 - Contract Termination December 31, 2014
Derivative [Line Items]
Strike Price	5.06
Maximum | Natural Gas calls (MMBtu) | Strike Price 5.05 - 5.06 | Natural Gas Calls Contract Date January 1, 2015 - Contract Termination December 31, 2016
Derivative [Line Items]
Strike Price	5.06

[1] Commodity contract pricing based on Louisiana Light Sweet crude (Argus) trade month swap.

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Summary of Total Interest Expense and Effective Interest Rate on Debt (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Interest Expense	$ 87,053
Senior Credit Facility
Debt Instrument [Line Items]
Interest Expense	3,936	5,114	3,180
Effective Interest Rate	5.30%	3.70%
3.25% Convertible Senior Notes due 2026
Debt Instrument [Line Items]
Interest Expense	14	14	4,305
Effective Interest Rate	3.30%	3.30%	9.00%
5.0% Convertible Senior Notes due 2029
Debt Instrument [Line Items]
Interest Expense	17,400	21,968	20,948
Effective Interest Rate	11.40%	11.40%	10.50%
5% Convertible Senior Notes due 2032
Debt Instrument [Line Items]
Interest Expense	4,529
Effective Interest Rate	8.80%
8.875% Senior Notes due 2019
Debt Instrument [Line Items]
Interest Expense	$ 25,308	$ 25,308	$ 20,910
Effective Interest Rate	9.20%	9.20%	8.90%

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Description of Business and Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended					12 Months Ended					12 Months Ended				12 Months Ended			12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 3.25% Convertible Senior Notes due 2026	Dec. 31, 2012 3.25% Convertible Senior Notes due 2026	Dec. 31, 2013 5.0% Convertible Senior Notes due 2029		Dec. 31, 2012 5.0% Convertible Senior Notes due 2029		Sep. 30, 2009 5.0% Convertible Senior Notes due 2029	Dec. 31, 2013 5% Convertible Senior Notes due 2032		Sep. 30, 2013 5% Convertible Senior Notes due 2032	Aug. 26, 2013 5% Convertible Senior Notes due 2032	Dec. 31, 2013 8.875% Senior Notes due 2019	Dec. 31, 2012 8.875% Senior Notes due 2019	Mar. 02, 2011 8.875% Senior Notes due 2019	Dec. 31, 2013 Minimum	Dec. 31, 2013 Maximum	Dec. 31, 2013 Maximum Wholly-owned subsidiary
Description Of Company And Significant Accounting Policies [Line Items]
Cash held in escrow	$ 51,800,000					$ 51,800,000
Interests in oil and gas properties, net of accumulated depletion	821,800,000
Impairment of oil and gas properties	0	47,818,000	8,111,000
Estimated fair value of oil and natural gas properties		3,300,000
Furniture, fixtures and equipment estimated useful lives																		3 years	5 years
Natural gas gathering agreement period	10 years
Percentage of compensation paid to service provider	110.00%
Percentage of accumulated capital costs charged annually	20.00%
Debt instrument interest rate				3.25%		5.00%					5.00%				8.875%		8.875%
Debt instruments maturity date				2026		2029					2032				2019
Preferred stock, dividend rate, percentage	5.375%
Dividend yield	0.00%
Debt instrument, principal amount	$ 494,650,000	$ 588,929,000		$ 429,000	$ 429,000	$ 51,816,000	[1]	$ 218,500,000	[1]	$ 218,500,000	$ 167,405,000	[2]	$ 57,000,000	$ 109,250,000	$ 275,000,000	$ 275,000,000	$ 275,000,000
Percentage of restricted assets that may not be transferred to the parent company																				25.00%

[1] The debt discount is amortized using the effective interest rate method based upon an original five year term through October 1, 2014. The debt discount was $2.1 million and $20.3 million as of December 31, 2013 and December 31, 2012, respectively.

[2] 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 $7.0 million as of December 31, 2013.

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Revenues from Top Customers as Percentage of Total Revenues (Detail)	12 Months Ended
	Dec. 31, 2013 BP Energy Company	Dec. 31, 2012 BP Energy Company	Dec. 31, 2013 Genesis Crude Oil LP	Dec. 31, 2012 Flint Hill Resources, LLC	Dec. 31, 2011 Shell Energy Resources LP	Dec. 31, 2011 Regency Field Services LLC
Percentage of Revenues Generated from Overseas Customers [Line Items]
Receipt compared to total receipts	64.00%	34.00%	7.00%	15.00%	11.00%	10.00%

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Share-Based Compensation Plans

12 Months Ended

Dec. 31, 2013

Share-Based Compensation Plans

NOTE 2—Share-Based Compensation Plans

Overview

At our annual meeting of stockholders in May 2006, our shareholders approved our 2006 Long-Term Incentive Plan (the “2006 Plan”). The 2006 Plan provides for grants to officers, employees and non-employee directors. Under the 2006 Plan as amended in 2011, a maximum of 4.0 million shares are authorized for issuance as awards of restricted stock and stock options. We had 1.6 million shares of granted but unvested restricted stock and 0.2 million shares were available for future grants as of December 31, 2013.

The 2006 Plan is intended to promote the interests of the Company by providing a means by which employees, consultants and directors may acquire or increase their equity interest in the Company and may develop a sense of proprietorship and personal involvement in the development and financial success of the Company, and to encourage them to remain with and devote their best efforts to the business of the Company, thereby advancing the interests of the Company and its stockholders. The 2006 Plan is also intended to enhance the ability of the Company and its Subsidiary to attract and retain the services of individuals who are essential for the growth and profitability of the Company.

The 2006 Plan provides that the Compensation Committee shall have the authority to determine the participants to whom stock options, restricted stock, performance awards, phantom shares and stock appreciation rights may be granted.

We measure the cost of stock based compensation granted, including stock options and restricted stock, based on the fair value of the award as of the grant date, net of estimated forfeitures. Awards granted are valued at fair value and recognized on a straight-line basis over the service periods (or the vesting periods) of each award. We estimate forfeiture rates for all unvested awards based on our historical experience.

The following table summarizes the pretax components of our share-based compensation programs recorded, recognized as a component of general and administrative expenses in the Consolidated Statement of Operations (in thousands):

	Year Ended December 31,
	2013		2012		2011
Restricted stock expense	$	7,586	$	6,670	$	6,194
Stock option expense		94		233		301
Director stock expense		568		585		525
Total share-based compensation:	$	8,248	$	7,488	$	7,020

Stock Options

The 2006 Plan provides that the option price of shares issued be equal to the market price on the date of grant. With the exception of option grants to non-employee directors, which vest immediately, options vest ratably on the anniversary of the date of grant over a period of time, typically three years. Our stock options expire in seven or ten years after the date of grant.

Option activity under our stock option plans as of December 31, 2013, and changes during the year ended December 31, 2013 were as follows:

	Shares		Weighted Average Exercise Price		Remaining Contractual Term		Aggregate Intrinsic Value
					(years)		(thousands)
Outstanding at January 1, 2013		900,984	$	21.57		2.92	$	18
Granted		—		—		—		—
Exercised		40,500		19.94		—		—
Forfeited		5,850		21.59		—		—
Outstanding at December 31, 2013		854,634	$	21.64		1.84	$	88
Exercisable at December 31, 2013		854,634	$	21.64		1.84	$	88

The aggregate intrinsic value in the preceding table represents the total pre-tax intrinsic value (the difference between our closing stock price on the last trading day of the fourth quarter of 2013 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2013. The amount of aggregate intrinsic value will change based on the fair market value of our stock. The total intrinsic value of options exercised during the years ended December 31, 2013, and 2012 was less than $0.1 million in both years. There were no exercises in 2011.

	Options Outstanding						Options Exercisable
Range of Exercise Prices	Number Outstanding at December 31, 2013		Weighted Average Remaining Contractual Life		Weighted Average Exercise Price		Number Exercisable at December 31, 2013		Weighted Average Exercise Price
			(years)
$16.46 and $19.78		307,300		1.11		18.08		307,300		18.08
$21.59 to $27.81		547,334		2.26		23.64		547,334		23.64
		854,634		1.84	$	21.64		854,634	$	21.64

As of December 31, 2013, all compensation cost related to the stock options has been recognized in earnings. No stock options were granted in 2013, 2012 or 2011.

Restricted Stock

In 2003, we began granting a series of restricted stock awards. Restricted stock awarded under the 2006 Plan typically has a vesting period of three years. During the vesting period, ownership of the shares cannot be transferred and the shares are subject to forfeiture if employment ends before the end of the vesting period. Certain restricted stock awards provide for accelerated vesting. Restricted shares are not considered to be currently issued and outstanding until the restrictions lapse and/or they vest.

Restricted stock activity and values under our plan for the years ended December 31, 2013, 2012 and 2011 were as follows:

	Number of Shares Granted		Value of Shares Granted		Fair Value of Stock Vested
			(thousands)		(thousands)
2013		746,163	$	13,194	$	9,960
2012		1,073,727		9,533		3,335
2011		561,714		7,921		5,764

Restricted stock activity under our plan for the year ended December 31, 2013, and changes during the year then ended were as follows:

	Number of Shares			Weighted Average Grant-Date Fair Value		Total Value
						(thousands)
Unvested at January 1, 2013		1,541,650		$	10.60	$	16,345
Vested		(594,301	)		11.57		(6,863	)
Granted		746,163			17.68		13,194
Forfeited		(112,305	)		10.69		(1,200	)
Unvested at December 31, 2013		1,581,207		$	13.58	$	21,476

As of December 31, 2013, total unrecognized compensation cost related to restricted stock is as follows:

	Unrecognized compensation costs		Weighted Average years to recognition
	(thousands)		(years)
December 31, 2013	$	19,938		2.44

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Reconciliation of Gross Amounts to Amounts as Presented on Statement of Financial Position (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Derivative Current Asset	$ 6,187	$ 2,125
Derivative Non-current Asset	1,396
Derivative Current Liability	(4,341)	(351)
Derivative Non-current Liability	(2,371)	(3,987)
Total	871	(2,213)
Gross Amount
Derivative [Line Items]
Derivative Current Asset	6,658	2,410
Derivative Non-current Asset	1,396
Derivative Current Liability	(4,812)	(636)
Derivative Non-current Liability	(2,371)	(3,987)
Total	871	(2,213)
Amount Offset
Derivative [Line Items]
Derivative Current Asset	(471)	(285)
Derivative Current Liability	$ 471	$ 285

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Reconciliation of Asset Retirement Obligations (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Asset Retirement Obligations [Line Items]
Beginning balance	$ 18,306		$ 17,425
Liabilities incurred	471		693
Revisions in estimated liabilities	1,290	[1]	2,005	[1]
Liabilities settled	(82)		(767)
Accretion expense	1,243		1,111
Dispositions	(372)		(2,161)
Ending balance	20,856		18,306
Current liability	99		168
Long term liability	$ 20,757		$ 18,138

[1] We increased our estimated liability in 2013 by $1.3 million as a result of a change in estimated plugging and abandonment cost on several of our fields.

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Summary of Realized and Unrealized Gains and Losses on Derivatives (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative [Line Items]
Realized gain (loss) on oil and natural gas derivatives	$ (3,786)	$ 73,160	$ 31,305
Unrealized gain (loss) on oil and natural gas derivatives	3,084	(41,278)	3,234
Total gain (loss) on oil and natural gas derivatives	$ (702)	$ 31,882	$ 34,539

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
CURRENT ASSETS:
Cash and cash equivalents	$ 49,220	$ 1,188
Restricted cash	51,816
Accounts receivable, trade and other, net of allowance	3,113	7,078
Accrued oil and natural gas revenue	19,455	19,054
Fair value of oil and natural gas derivatives	6,187	2,125
Inventory	2,076	2,202
Prepaid expenses and other	1,278	926
Total current assets	133,145	32,573
PROPERTY AND EQUIPMENT:
Oil and natural gas properties (successful efforts method)	1,838,220	1,619,914
Furniture, fixtures and equipment	6,960	6,212
Property, Plant and Equipment, Gross, Total	1,845,180	1,626,126
Less: Accumulated depletion, depreciation and amortization	(1,021,863)	(906,377)
Net property and equipment	823,317	719,749
Fair value of oil and natural gas derivatives	1,396
Deferred tax assets	665	636
Deferred financing cost and other	15,690	15,427
TOTAL ASSETS	974,213	768,385
CURRENT LIABILITIES:
Accounts payable	50,551	73,094
Accrued liabilities	48,603	37,634
Accrued abandonment costs	99	168
Deferred tax liabilities current	665	636
Fair value of oil and natural gas derivatives	4,341	351
Current portion of debt	49,663
Total current liabilities	153,922	111,883
Long term debt	435,866	568,671
Accrued abandonment costs	20,757	18,138
Fair value of oil and natural gas derivatives	2,371	3,987
Transportation obligation	4,774	5,461
Total liabilities	617,690	708,140
Commitments and contingencies (See Note 9)
STOCKHOLDERS' EQUITY:
Common stock: $0.20 par value, 100,000,000 shares authorized, issued and outstanding 44,258,824 and 36,758,141 shares, respectively	8,852	7,352
Treasury stock (zero and 77,142 shares, respectively)		(639)
Additional paid in capital	1,056,378	648,458
Retained earnings (accumulated deficit)	(710,966)	(597,176)
Total stockholders' equity	356,523	60,245
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	974,213	768,385
Series B Convertible Preferred Stock
STOCKHOLDERS' EQUITY:
Preferred stock	2,250	2,250
Series C Cumulative Preferred Stock
STOCKHOLDERS' EQUITY:
Preferred stock	4
Series D Cumulative Preferred Stock
STOCKHOLDERS' EQUITY:
Preferred stock	$ 5

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Debt - Additional Information (Detail) (USD $)	12 Months Ended					12 Months Ended						12 Months Ended						12 Months Ended									12 Months Ended			12 Months Ended				12 Months Ended
	Dec. 31, 2013		Dec. 31, 2011	Dec. 31, 2012		Dec. 31, 2013 Minimum	Dec. 31, 2013 8.875% Senior Notes due 2019		Dec. 31, 2012 8.875% Senior Notes due 2019		Mar. 02, 2011 8.875% Senior Notes due 2019	Dec. 31, 2013 8.875% Senior Notes due 2019 Scenario 1	Dec. 31, 2013 8.875% Senior Notes due 2019 Scenario 2	Dec. 31, 2013 8.875% Senior Notes due 2019 Scenario 3	Dec. 31, 2013 Senior Credit Facility	Dec. 31, 2012 Senior Credit Facility		Dec. 31, 2013 Bank Base Rate	Dec. 31, 2013 Libor	Dec. 31, 2013 5.0% Convertible Senior Notes due 2029		Dec. 31, 2012 5.0% Convertible Senior Notes due 2029		Dec. 31, 2011 5.0% Convertible Senior Notes due 2029	Dec. 31, 2009 5.0% Convertible Senior Notes due 2029	Sep. 30, 2009 5.0% Convertible Senior Notes due 2029	Dec. 31, 2013 5.0% Convertible Senior Notes due 2029 Extinguishment of Debt	Dec. 31, 2013 5.0% Convertible Senior Notes due 2029 Minimum	Dec. 31, 2013 5.0% Convertible Senior Notes due 2029 Maximum	Dec. 31, 2013 5% Convertible Senior Notes due 2032		Sep. 30, 2013 5% Convertible Senior Notes due 2032	Aug. 26, 2013 5% Convertible Senior Notes due 2032	Dec. 31, 2013 5% Convertible Senior Notes due 2032 Extinguishment of Debt	Dec. 31, 2013 5% Convertible Senior Notes due 2032 Option One	Dec. 31, 2013 5% Convertible Senior Notes due 2032 Option Two	Dec. 31, 2013 5% Convertible Senior Notes due 2032 Option Three	Dec. 31, 2013 5% Convertible Senior Notes due 2032 Minimum	Dec. 31, 2013 3.25% Convertible Senior Notes due 2026		Dec. 31, 2011 3.25% Convertible Senior Notes due 2026	Dec. 31, 2012 3.25% Convertible Senior Notes due 2026
Debt [Line Items]
Total lender commitments under the Senior Credit Facility borrowing base															$ 600,000,000
Senior credit facility, current borrowing capacity															270,000,000
Debt instrument rate minimum																		1.00%	2.00%
Debt instrument rate maximum																		1.75%	2.75%
Amount outstanding under the senior credit facility															0
Liquidation value of any new series of preferred stock	250,000,000
Escrow deposit for repurchase of the remaining outstanding principal amount	51,800,000																			51,800,000
Debt instrument maturity date							Mar. 15, 2019								Feb. 25, 2016					Oct. 01, 2029										Oct. 01, 2032
Adjusted current ratio current assets	1.0
Adjusted current ratio current liabilities	1.0
Interest rate ratio EBITDAX						2.5
Interest rate ratio cash interest expense	1.0
Debt no greater than EBITDAX	4.0
Debt instrument, principal amount	494,650,000			588,929,000			275,000,000		275,000,000		275,000,000					95,000,000	[1]			51,816,000	[2]	218,500,000	[2]			218,500,000				167,405,000	[3]	57,000,000	109,250,000						429,000			429,000
Debt instrument interest rate							8.875%				8.875%									5.00%										5.00%									3.25%
Redemption price, percentage							35.00%																							100.00%
Redeemable redemption price, percentage of principal amount							108.875%					104.438%	102.219%	100.00%
Debt instrument, redemption date												Mar. 15, 2015	Mar. 15, 2016	Mar. 15, 2017																					Oct. 01, 2017	Oct. 01, 2022	Oct. 01, 2027	Oct. 01, 2016
Aggregate principal amount retired																				166,700,000
Conversion price, percentage																				135.00%
Number of trading days in the period																												20 days	30 days
Principal amount of notes																				1,000										1,000									1,000
Percentage on sale price of common stock																				97.00%
Notes to shares converted																				28.8534										28.8534									15.1653
Base conversion price per share																				$ 34.66										$ 34.6580									$ 65.94
Debt discount																				2,100,000		20,300,000				49,400,000				7,500,000
Aggregate carrying amount	485,529,000			568,671,000			275,000,000		275,000,000							95,000,000	[1]			49,663,000	[2]	198,242,000	[2]		171,100,000		156,900,000			160,437,000	[3]								429,000			429,000
Equity component, net of tax																									32,100,000
Period of amortization on debt instrument																				5 years										4 years
Accretion rate																																	2.00%
Debt instrument, accretion start date																														Aug. 26, 2013
Debt instrument, accretion end date																														Oct. 01, 2017
Accretion amount																														1,200,000
Common stock trading price cap before conversion																																						$ 45.06
Conversion price percentage before conversion																																						130.00%
Unamortized debt issuance cost written off																											800,000
Fair value of equity portion																											20,000,000
Debt Instrument, Fair Value	512,041,000	[1]		561,654,000	[1]		288,063,000	[1]	261,250,000	[1]						95,000,000	[1]			51,686,000	[1],[2]	204,975,000	[1],[2]							171,863,000	[1],[3]			183,200,000					429,000	[1]		429,000	[1]
Gain (loss) on extinguishment of debt	(7,088,000)		62,000																															7,100,000
Effective interest rate, debt instrument															5.30%	3.70%				11.40%		11.40%		10.50%						8.80%									3.30%		9.00%	3.30%
Fair value of debt portion																														158,800,000
Debt discount amortization beginning date																														Oct. 01, 2017
Equity component of debt																														24,400,000
Unamortized debt discount																														7,000,000
Repurchase of senior notes																																									$ 174,600,000
Debt instrument maturity year																																							2026
Incremental share factor																																							2.6762

[1] The carrying amount for the Senior Credit Facility represents fair value as the variable interest rates are reflective of current market conditions. The fair value of the notes 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 debt discount was $2.1 million and $20.3 million as of December 31, 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 $7.0 million as of December 31, 2013.

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Consolidated Statements of Stockholders' Equity (USD $) In Thousands, except Share data	Total	Preferred Stock Offering	Equity Offering	Preferred Stock	Preferred Stock Preferred Stock Offering	Common Stock	Common Stock Equity Offering	Additional Paid-in Capital	Additional Paid-in Capital Preferred Stock Offering	Additional Paid-in Capital Equity Offering	Treasury Stock	Retained Earnings/ (Deficit)
Balance at Dec. 31, 2010	$ 183,972			$ 2,250		$ 7,212		$ 643,828			$ (196)	$ (469,122)
Balance, Treasury Stock at Dec. 31, 2010											(12,000)
Balance, Common Stock at Dec. 31, 2010						37,685,000
Balance, Preferred Stock at Dec. 31, 2010				2,250,000
Net loss	(31,758)											(31,758)
Employee stock plans (in shares)						350,000
Employee stock plans	6,495					70		6,425
Equity portion of convertible notes redeemed	(7,944)							(7,944)
Director stock grants (in shares)						21,000
Director stock grants	389					4		385
Repurchases of stock (in shares)											(86,000)
Repurchases of stock	(1,407)										(1,407)
Retirement of stock (in shares)						(53,000)					53,000
Retirement of stock						(10)		(904)			914
Shares returned pursuant to Share Lending Agreement						(1,624,000)
Dividends	(6,047)											(6,047)
Balance at Dec. 31, 2011	143,700			2,250		7,276		641,790			(689)	(506,927)
Balance, Preferred Stock at Dec. 31, 2011				2,250,000
Balance, Treasury Stock at Dec. 31, 2011											(45,000)
Balance, Common Stock at Dec. 31, 2011						36,379,000
Net loss	(84,202)											(84,202)
Employee stock plans (in shares)						386,000
Employee stock plans	6,903					77		6,826
Director stock grants (in shares)						57,000
Director stock grants	732					11		721
Repurchases of stock (in shares)											(100,000)
Repurchases of stock	(857)										(857)
Options Exercised (in shares)						4,000
Options Exercised	16					1		15
Retirement of stock (in shares)						(68,000)					68,000
Retirement of stock						(13)		(894)			907
Dividends	(6,047)											(6,047)
Balance at Dec. 31, 2012	60,245			2,250		7,352		648,458			(639)	(597,176)
Balance, Preferred Stock at Dec. 31, 2012				2,250,000
Balance, Treasury Stock at Dec. 31, 2012	(77,142)										(77,000)
Balance, Common Stock at Dec. 31, 2012	36,758,141					36,758,000
Net loss	(95,186)											(95,186)
Employee stock plans (in shares)						594,000
Employee stock plans	7,680					119		7,561
Equity portion of convertible notes redeemed	4,398							4,398
Director stock grants (in shares)						47,000
Director stock grants	646					9		637
Repurchases of stock (in shares)											(3,000)
Repurchases of stock	(74)										(74)
Options Exercised (in shares)	40,500,000					41,000
Options Exercised	807					8		799
Equity Offering (in shares)					9,000		6,900,000
Equity Offering		230,625	166,149		9		1,380		230,616	164,769
Retirement of stock (in shares)						(81,000)					80,000
Retirement of stock						(16)		(697)			713
Other	(163)							(163)
Dividends	(18,604)											(18,604)
Balance at Dec. 31, 2013	$ 356,523			$ 2,259		$ 8,852		$ 1,056,378				$ (710,966)
Balance, Preferred Stock at Dec. 31, 2013				2,259,000
Balance, Treasury Stock at Dec. 31, 2013	0
Balance, Common Stock at Dec. 31, 2013	44,258,824					44,259,000

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Timing of Future Payments Obligations (Parenthetical) (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Commitment And Contingencies [Line Items]
Liability for dismantlement, abandonment and restoration costs of oil and natural gas properties	$ 20,856,000	$ 18,306,000	$ 17,425,000
3.25% Convertible Senior Notes due 2026
Commitment And Contingencies [Line Items]
Amount retained by the company	$ 400,000

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Schedule of Option Activity Under Stock Option Plans (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Number of Shares
Outstanding at January 1, 2013	900,984
Granted
Exercised	40,500
Forfeited	5,850
Outstanding at December 31, 2013	854,634	900,984
Exercisable at December 31, 2013	854,634
Weighted Average Exercise Price
Outstanding at January 1, 2013	$ 21.57
Granted
Exercised	$ 19.94
Forfeited	$ 21.59
Outstanding at December 31, 2013	$ 21.64	$ 21.57
Exercisable at December 31, 2013	$ 21.64
Weighted Average Remaining Contractual Term
Outstanding at December 31	1 year 10 months 2 days	2 years 11 months 1 day
Exercisable at December 31, 2013	1 year 10 months 2 days
Average Intrinsic Value
Outstanding at January 1, 2013	$ 18
Granted
Exercised
Forfeited
Outstanding at December 31, 2013	88	18
Exercisable at December 31, 2013	$ 88

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Share-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2013

Components of Share-Based Compensation

The following table summarizes the pretax components of our share-based compensation programs recorded, recognized as a component of general and administrative expenses in the Consolidated Statement of Operations (in thousands):

	Year Ended December 31,
	2013		2012		2011
Restricted stock expense	$	7,586	$	6,670	$	6,194
Stock option expense		94		233		301
Director stock expense		568		585		525
Total share-based compensation:	$	8,248	$	7,488	$	7,020

Schedule of Option Activity Under Stock Option Plans

Option activity under our stock option plans as of December 31, 2013, and changes during the year ended December 31, 2013 were as follows:

	Shares		Weighted Average Exercise Price		Remaining Contractual Term		Aggregate Intrinsic Value
					(years)		(thousands)
Outstanding at January 1, 2013		900,984	$	21.57		2.92	$	18
Granted		—		—		—		—
Exercised		40,500		19.94		—		—
Forfeited		5,850		21.59		—		—
Outstanding at December 31, 2013		854,634	$	21.64		1.84	$	88
Exercisable at December 31, 2013		854,634	$	21.64		1.84	$	88

Schedule of Share-Based Compensation by Exercise Price Range

	Options Outstanding						Options Exercisable
Range of Exercise Prices	Number Outstanding at December 31, 2013		Weighted Average Remaining Contractual Life		Weighted Average Exercise Price		Number Exercisable at December 31, 2013		Weighted Average Exercise Price
			(years)
$16.46 and $19.78		307,300		1.11		18.08		307,300		18.08
$21.59 to $27.81		547,334		2.26		23.64		547,334		23.64
		854,634		1.84	$	21.64		854,634	$	21.64

Schedule of Restricted Stock Activity And Values

Restricted stock activity and values under our plan for the years ended December 31, 2013, 2012 and 2011 were as follows:

	Number of Shares Granted		Value of Shares Granted		Fair Value of Stock Vested
			(thousands)		(thousands)
2013		746,163	$	13,194	$	9,960
2012		1,073,727		9,533		3,335
2011		561,714		7,921		5,764

Schedule of Restricted Stock Activity

Restricted stock activity under our plan for the year ended December 31, 2013, and changes during the year then ended were as follows:

	Number of Shares			Weighted Average Grant-Date Fair Value		Total Value
						(thousands)
Unvested at January 1, 2013		1,541,650		$	10.60	$	16,345
Vested		(594,301	)		11.57		(6,863	)
Granted		746,163			17.68		13,194
Forfeited		(112,305	)		10.69		(1,200	)
Unvested at December 31, 2013		1,581,207		$	13.58	$	21,476

Restricted Stock

Schedule of Restricted Stock Activity

As of December 31, 2013, total unrecognized compensation cost related to restricted stock is as follows:

	Unrecognized compensation costs		Weighted Average years to recognition
	(thousands)		(years)
December 31, 2013	$	19,938		2.44

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Schedule of Share-Based Compensation by Exercise Price Range (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options Outstanding - Number Outstanding at December 31, 2012	854,634
Options Outstanding - Weighted Average Remaining Contractual Life (years)	1 year 10 months 2 days
Options Outstanding - Weighted Average Exercise Price	$ 21.64
Options Exercisable - Number Exercisable at December 31, 2012	854,634
Options Exercisable - Weighted Average Exercise Price	$ 21.64
$16.46 and $19.78
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices, Lower	$ 16.46
Range of Exercise Prices, Upper	$ 19.78
Options Outstanding - Number Outstanding at December 31, 2012	307,300
Options Outstanding - Weighted Average Remaining Contractual Life (years)	1 year 1 month 10 days
Options Outstanding - Weighted Average Exercise Price	$ 18.08
Options Exercisable - Number Exercisable at December 31, 2012	307,300
Options Exercisable - Weighted Average Exercise Price	$ 18.08
$21.59 to $27.81
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices, Lower	$ 21.59
Range of Exercise Prices, Upper	$ 27.81
Options Outstanding - Number Outstanding at December 31, 2012	547,334
Options Outstanding - Weighted Average Remaining Contractual Life (years)	2 years 3 months 4 days
Options Outstanding - Weighted Average Exercise Price	$ 23.64
Options Exercisable - Number Exercisable at December 31, 2012	547,334
Options Exercisable - Weighted Average Exercise Price	$ 23.64

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Debt (Tables)

12 Months Ended

Dec. 31, 2013

Components of Debt

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

	December 31, 2013						December 31, 2012
	Principal		Carrying Amount		Fair Value (1)		Principal		Carrying Amount		Fair Value (1)
Senior Credit Facility (1)	$	—	$	—	$	—	$	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)		51,816		49,663		51,686		218,500		198,242		204,975
5.0% Convertible Senior Notes due 2032 (3)		167,405		160,437		171,863		—		—		—
8.875% Senior Notes due 2019		275,000		275,000		288,063		275,000		275,000		261,250
Total debt	$	494,650	$	485,529	$	512,041	$	588,929	$	568,671	$	561,654

(1) The carrying amount for the Second Amended and Restated Credit Agreement represents fair value as the variable interest rates are reflective of current market conditions. The fair value of the notes 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 debt discount was $2.1 million and $20.3 million as of December 31, 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 $7.0 million as of December 31, 2013.

Summary of Total Interest Expense and Effective Interest Rate on Debt

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):

	December 31, 2013					December 31, 2012					December 31, 2011
	Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate
Senior Credit Facility		3,936		5.3	%		5,114		3.7	%		3,180		—	*
3.25% Convertible Senior Notes due 2026		14		3.3	%		14		3.3	%		4,305		9.	%
5.0% Convertible Senior Notes due 2029		17,400		11.4	%		21,968		11.4	%		20,948		10.5	%
5.0% Convertible Senior Notes due 2032		4,529		8.8	%		—		—			—		—
8.875% Senior Notes due 2019		25,308		9.2	%		25,308		9.2	%		20,910		8.9	%

* An Effective Interest Rate Calculation is not meaningful for the years ended December 31, 2011 since there were only minimal average amounts borrowed under the Senior Credit Facility during the period.

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Description of Business and Accounting Policies

12 Months Ended

Dec. 31, 2013

Description of Business and Accounting Policies

NOTE 1—Description of Business and 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, which includes the Eagle Ford Shale Trend, (ii) Northwest Louisiana and East Texas, which includes the Haynesville Shale and Cotton Valley Taylor Sand, and (iii) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale (“TMS”).

Principles of Consolidation—The consolidated financial statements of the Company are included in this Annual Report on Form 10-K have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) and in accordance with accounting principles generally accepted in the United States (“US GAAP”). 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—Restricted cash at December 31, 2013 of $51.8 million is held in escrow for the repurchase of the remaining outstanding principal amount on our 5% Convertible Senior Notes due 2029. See Note 4.

Allowance for Doubtful Accounts—We routinely assess the recoverability of all material trade and other receivables to determine their collectability. Many of our receivables are from a limited number of purchasers. Accordingly, accounts receivable from such purchases could be significant. Generally, our natural gas and crude oil receivables are collected within thirty to sixty days of production. We also have receivables from joint interest owners of properties we operate. We may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.

We accrue a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. As of each of December 31, 2013 and 2012, our allowance for doubtful accounts was immaterial.

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 the 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 discovery. 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.

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.

As of December 31, 2013 and 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.

As of December 31, 2013, we had interests in oil and natural gas properties totaling $821.8 million, net of accumulated depletion, which we account for under the successful efforts method. The expected future cash flows used for impairment reviews and related fair-value calculations are based on judgmental assessments of future production volumes, prices, and costs, considering all available information at the date of review. Due to the uncertainty inherent in these factors, we cannot predict when or if additional future impairment charges will be recorded. We estimate future net cash flows generated from our oil and natural gas properties by using forecasted oil and natural gas prices published by the New York Mercantile Exchange (“NYMEX”).

We had no impairment associated with our oil and natural gas properties for 2013. For the years ended December 31, 2012 and 2011, we recorded impairments on our oil and natural gas properties of $47.8 million and $8.1 million, respectively. The impairment in 2012 reduced the fields’ carrying value to an estimated fair value of $3.3 million.

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 Trend area of South Texas. In compensation for the services, we agreed to pay the service provider 110 percent of the total capital cost incurred by the service provider to construct new pipelines and facilities. The service provider bills us for 20 percent of the accumulated unpaid capital costs annually.

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

Asset Retirement Obligations—We follow the accounting standard related to accounting for asset retirement obligations. These obligations are related to the abandonment and site restoration requirements that result from the exploration and development of our oil and 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 Statement 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 crude 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 December 31, 2013 and 2012, the net liability for natural gas balancing was immaterial. Differences between actual production and net working interest volumes are routinely adjusted.

Derivative Instruments—We use derivative instruments such as futures, forwards, options, collars and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas and to hedge

our exposure to changing interest rates. 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 counterparty 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 and restricted stock calculated using the Treasury Stock method and the potential dilutive effect of the conversion of shares associated with 5.375% Series B Convertible Preferred Stock (“Series B Preferred Stock”), 3.25% Convertible Senior Notes due 2026 (the “2026 Notes”), 5% Convertible Senior Notes due 2029 (the “2029 Notes”) and 5% Convertible Senior Notes due 2032 (the “2032 Notes”).

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

Concentration of Credit Risk—Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. The revenues compared to our total oil and natural gas revenues from the top purchasers for the years ended December 31, 2013, 2012 and 2011 are as follows:

	Year Ended December 31,
	2013			2012			2011
BP Energy Company		64	%		34	%		—
Genesis Crude Oil LP		7	%		—			—
Flint Hill Resources, LLC		—			15	%		—
Shell Energy Resources LP		—			—			11	%
Regency Field Services LLC		—			—			10	%

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.

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 and October 1, 2013, we issued $109.25 million and $57.0 million, respectively, 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, 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 December 31, 2013 and December 31, 2012.

	December 31, 2013									December 31, 2012
Fair Value of Oil and Natural Gas Derivatives	Gross Amount			Amount Offset			As Presented			Gross Amount			Amount Offset			As Presented
	(in thousands)
Derivative Current Asset	$	6,658		$	(471	)	$	6,187		$	2,410		$	(285	)	$	2,125
Derivative Non-current Asset		1,396			—			1,396			—			—			—
Derivative Current Liability		(4,812	)		471			(4,341	)		(636	)		285			(351	)
Derivative Non-current Liability		(2,371	)		—			(2,371	)		(3,987	)		—			(3,987	)
Total	$	871		$	—		$	871		$	(2,213	)	$	—		$	(2,213	)

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Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Series B Convertible Preferred Stock	Dec. 31, 2012 Series B Convertible Preferred Stock	Dec. 31, 2013 Series C Cumulative Preferred Stock	Dec. 31, 2012 Series C Cumulative Preferred Stock	Dec. 31, 2013 Series D Cumulative Preferred Stock	Dec. 31, 2012 Series D Cumulative Preferred Stock
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, par value	$ 1.00	$ 1.00
Preferred stock, shares issued			2,250,000	2,250,000	4,400,000	0	5,200,000	0
Preferred stock, shares outstanding			2,250,000	2,250,000	4,400,000	0	5,200,000	0
Common stock, par value	$ 0.20	$ 0.20
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	44,258,824	36,758,141
Common stock, shares outstanding	44,258,824	36,758,141
Treasury stock	0	77,142

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2013

Acquisitions and Divestitures

NOTE 11—Acquisitions and Divestitures

Acquisitions

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 $24.6 million. The closing price included $2.7 million of lease extensions executed by Devon for the Company after the effective date. The adjusted purchase price net of lease extension costs totaled $21.8 million.

We recorded $21.8 million to oil and gas properties in the purchase price allocation inclusive of $0.1 million in asset retirement obligations for net cash paid of $23.7 million.

For the period, August 21, 2013 through December 31, 2013, the acquired property has generated operating income of $2.5 million on revenues of $2.8 million which is included on our Consolidated Statement of Operations for the year ended December 31, 2013. Expenses associated with the acquisition for the year ended December 31, 2013 were less than $0.1 million and are included in General and Administrative expense. The acquisition was recorded at fair value which was determined using both the market and income approaches. The income approach is based on inputs and natural gas reserves estimates, estimated future commodity prices and estimated future production and development costs. The market approach was based on recent transactions for similar leases.

The following tables present the Unaudited Pro forma Condensed Consolidated Statements of Operations, giving effect to the acquisition as if it had occurred on January 1, 2012:

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

For the Year Ended December 31, 2013

(In Thousands, Except Per Share Amounts)

	As Reported			Adjustments		As Adjusted
Total revenues	$	203,295		$	7,380	$	210,675
Operating expenses		239,605			497		240,102
Operating loss		(36,310	)		6,883		(29,427	)
Net loss		(95,186	)		6,883		(88,303	)
Net loss applicable to common stock	$	(113,790	)	$	6,883	$	(106,907	)
Per Common Share
Net loss applicable to common stock—basic	$	(2.99	)			$	(2.81	)
Net loss applicable to common stock—diluted	$	(2.99	)			$	(2.81	)
Weighted average common shares outstanding—basic		38,098					38,098
Weighted average common shares outstanding—diluted		38,098					38,098

For the Year Ended December 31, 2012

(In Thousands, Except Per Share Amounts)

	As Reported			Adjustments		As Adjusted
Total revenues	$	180,845		$	10,223	$	191,068
Operating expenses		244,530			1,657		246,187
Operating loss		(63,685	)		8,566		(55,119	)
Net loss		(84,202	)		8,566		(75,636	)
Net loss applicable to common stock	$	(90,249	)	$	8,566	$	(81,683	)
Per Common Share
Net Loss applicable to common stock—basic	$	(2.48	)			$	(2.24	)
Net loss applicable to common stock—diluted	$	(2.48	)			$	(2.24	)
Weighted average common shares outstanding—basic		36,390					36,390
Weighted average common shares outstanding—diluted		36,390					36,390

During 2012, we acquired rights to an additional 56,400 gross (54,000 net) acres in undeveloped leases in the Tuscaloosa Marine Shale for a total of $18.4 million.

Divestitures

On September 28, 2012, we sold our interest in certain non-core properties in the South Henderson field located in East Texas for $95 million, realizing a gain on the sale of assets of $44.0 million. The sale was effective on July 1, 2012.

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 18, 2014	Jun. 30, 2013
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Trading Symbol	GDP
Entity Registrant Name	GOODRICH PETROLEUM CORP
Entity Central Index Key	0000943861
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		44,272,621
Entity Public Float			$ 339,100,000

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Summarized Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2013

Summarized Quarterly Financial Data (Unaudited)

Summarized Quarterly Financial Data (Unaudited)

(In Thousands, Except Per Share Amounts)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
2013
Revenues		47,084			48,485			57,161			50,565			203,295
Operating income (loss)		(13,142	)		(14,192	)		(854	)		(8,122	)		(36,310	)
Net income (loss)		(28,463	)		(16,143	)		(27,085	)		(23,495	)		(95,186	)
Net income (loss) applicable to common stock		(29,975	)		(20,099	)		(32,790	)		(30,926	)		(113,790	)
Basic income (loss) per common share		(0.82	)		(0.55	)		(0.89	)		(0.73	)		(2.99	)
Diluted income (loss) per common share		(0.82	)		(0.55	)		(0.89	)		(0.73	)		(2.99	)
2012
Revenues	$	45,308		$	41,346		$	45,960		$	48,231		$	180,845
Operating income (loss)		(14,241	)		(14,157	)		31,854			(67,141	)		(63,685	)
Net income (loss)		(17,729	)		(3,202	)		12,405			(75,676	)		(84,202	)
Net income (loss) applicable to common stock		(19,241	)		(4,714	)		10,894			(77,188	)		(90,249	)
Basic income (loss) per common share		(0.53	)		(0.13	)		0.30			(2.12	)		(2.48	)
Diluted income (loss) per common share		(0.53	)		(0.13	)		0.30			(2.12	)		(2.48	)

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Consolidated Statements Of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
REVENUES:
Oil and natural gas revenues	$ 202,557	$ 180,543	$ 200,456
Other	738	302	613
Total revenues	203,295	180,845	201,069
OPERATING EXPENSES:
Lease operating expense	27,293	25,938	21,490
Production and other taxes	9,812	8,115	5,450
Transportation and processing	10,498	13,900	12,974
Depreciation, depletion and amortization	135,357	141,222	131,811
Exploration	22,774	23,122	8,289
Impairment	0	47,818	8,111
General and administrative	34,069	28,930	29,799
Gain on sale of assets	(107)	(44,606)	(236)
Other	(91)	91	448
Operating Expenses, Total	239,605	244,530	218,136
Operating loss	(36,310)	(63,685)	(17,067)
OTHER INCOME (EXPENSE):
Interest expense	(51,187)	(52,403)	(49,351)
Interest income and other	101	4	59
Gain (loss) on derivatives not designated as hedges	(702)	31,882	34,539
Gain (loss) on extinguishment of debt	(7,088)		62
Nonoperating Income (Expense), Total	(58,876)	(20,517)	(14,691)
Loss before income taxes	(95,186)	(84,202)	(31,758)
Income tax benefit
Net loss	(95,186)	(84,202)	(31,758)
Preferred stock dividends	18,604	6,047	6,047
Net loss applicable to common stock	$ (113,790)	$ (90,249)	$ (37,805)
PER COMMON SHARE
Net loss applicable to common stock-basic	$ (2.99)	$ (2.48)	$ (1.05)
Net loss applicable to common stock-diluted	$ (2.99)	$ (2.48)	$ (1.05)
Weighted average common shares outstanding-basic	38,098	36,390	36,124
Weighted average common shares outstanding-diluted	38,098	36,390	36,124

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Income Taxes

12 Months Ended

Dec. 31, 2013

Income Taxes

NOTE 6—Income Taxes

Income tax (expense) benefit consisted of the following (in thousands):

	Year Ended December 31,
	2013		2012		2011
Current:
Federal	$	—	$	—	$	—
State		—		—		—
		—		—		—
Deferred:
Federal		—		—		—
State		—		—		—
		—		—		—
Total	$	—	$	—	$	—

The following is a reconciliation of the U.S. statutory income tax rate at 35% to our income (loss) before income taxes (in thousands):

	Year Ended December 31,
	2013			2012			2011
Income tax (expense) benefit
Tax at U.S. statutory income tax	$	33,315		$	29,471		$	11,115
Valuation allowance		(30,967	)		(29,952	)		(9,909	)
State income taxes-net of federal benefit		(902	)		1,618			(762	)
Nondeductible expenses and other		(1,446	)		(1,137	)		(444	)
Total tax (expense) benefit	$	—		$	—		$	—

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below (in thousands):

	December 31,
	2013			2012
Current deferred tax assets:
Accrued liabilities	$	133		$	375
Contingent liabilities and other		—			134
Less valuation allowance		(126	)		(498	)
Total current deferred tax assets		7			11
Current deferred tax liabilities:
Derivative financial instruments		(646	)		(621	)
Accrued liabilities		(26	)		(26	)
Total current deferred tax liabilities		(672	)		(647	)
Net current deferred tax liability	$	(665	)	$	(636	)
Noncurrent deferred tax assets:
Operating loss carry-forwards	$	211,589		$	156,723
State Tax NOL and Credits		5,805			3,867
Statutory depletion carry-forward		7,035			7,035
AMT tax credit carry-forward		1,227			1,324
Compensation		3,496			3,364
Contingent liabilities and other		858			1,907
Property and equipment		(3,248	)		26,848
Total gross noncurrent deferred tax assets		226,762			201,068
Less valuation allowance		(217,558	)		(193,459	)
Net noncurrent deferred tax assets		9,204			7,609
Noncurrent deferred tax liabilities:
Bond discount		(74	)		(61	)
Debt discount		(8,465	)		(6,912	)
Total non-current deferred tax liabilities		(8,539	)		(6,973	)
Net non-current deferred tax asset	$	665		$	636

The valuation allowance for deferred tax assets increased by $23.7 million in 2013. In determining the carrying value of a deferred tax asset, accounting standards provide for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. As we have incurred net operating losses in 2013 and prior years, relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are insufficient to overcome a history of such losses. Therefore, with the before-mentioned adjustment of $23.7 million, we have reduced the carrying value of our net deferred tax asset to zero. The valuation allowance has no impact on our net operating loss (“NOL”) position for tax purposes, and if we generate taxable income in future periods, we will be able to use our NOLs to offset taxes due at that time. We will continue to assess the valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.

As of December 31, 2013, we have federal NOL carry-forwards of approximately $608.9 million for tax purposes which begin to expire in 2026. We also have an alternative minimum tax credit carry-forward not subject to expiration of $1.2 million which will not begin to be used until after the available NOLs have been used or expired and when regular tax exceeds the current year alternative minimum tax.

We did not have any unrecognized tax benefits as of December 31, 2013. The amount of unrecognized tax benefits may change in the next twelve months; however we do not expect the change to have a significant impact on our results of operations or our financial position. We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions. With limited exceptions, we are no longer subject to U.S. Federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2006.

Our continuing practice is to recognize estimated interest and penalties related to potential underpayment on any unrecognized tax benefits as a component of income tax expense in the Consolidated Statement of Operations. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations before December 31, 2014.

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Loss Per Common Share

12 Months Ended

Dec. 31, 2013

Loss Per Common Share

NOTE 5—Loss Per Common Share

Net loss applicable to common stock was used as the numerator in computing basic and diluted loss per common share for the years ended December 31, 2013, 2012 and 2011. The following table sets forth information related to the computations of basic and diluted loss per share.

	Year Ended December 31,
	2013			2012			2011
	(Amounts in thousands, except per share data)
Basic loss per share:
Loss applicable to common stock	$	(113,790	)	$	(90,249	)	$	(37,805	)
Weighted-average shares of common stock outstanding		38,098			36,390			36,124
Basic loss per share	$	(2.99	)	$	(2.48	)	$	(1.05	)
Diluted loss per share:
Loss applicable to common stock	$	(113,790	)	$	(90,249	)	$	(37,805	)
Dividends on convertible preferred stock (1)		—			—			—
Interest and amortization of loan cost on convertible senior notes, net of tax (3)		—			—			—
Diluted loss	$	(113,790	)	$	(90,249	)	$	(37,805	)
Weighted-average shares of common stock outstanding		38,098			36,390			36,124
Assumed conversion of convertible preferred stock (1)		—			—			—
Assumed conversion of convertible senior notes (2)		—			—			—
Stock options and restricted stock (3)		—			—			—
Weighted-average diluted shares outstanding		38,098			36,390			36,124
Diluted loss per share	$	(2.99	)	$	(2.48	)	$	(1.05	)
(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
(2)    Common shares issuable upon assumed conversion of the 2026 Notes, the 2029 Notes and 2032 Notes were not presented as they would have been anti-dilutive.		6,307			6,311			7,067
(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.		620			238			171

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Reconciliation of Asset Retirement Obligations

The reconciliation of the beginning and ending asset retirement obligation for the periods ending December 31, 2013 and 2012 is as follows (in thousands):

	December 31,
	2013			2012
Beginning balance	$	18,306		$	17,425
Liabilities incurred		471			693
Revisions in estimated liabilities (1)		1,290			2,005
Liabilities settled		(82	)		(767	)
Accretion expense		1,243			1,111
Dispositions		(372	)		(2,161	)
Ending balance	$	20,856		$	18,306
Current liability	$	99		$	168
Long term liability	$	20,757		$	18,138

(1) We increased our estimated liability in 2013 by $1.3 million as a result of a change in estimated plugging and abandonment cost on several of our fields.

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Description of Business and Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Principles of Consolidation

Principles of Consolidation—The consolidated financial statements of the Company are included in this Annual Report on Form 10-K have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) and in accordance with accounting principles generally accepted in the United States (“US GAAP”). 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

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—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

Restricted Cash—Restricted cash at December 31, 2013 of $51.8 million is held in escrow for the repurchase of the remaining outstanding principal amount on our 5% Convertible Senior Notes due 2029. See Note 4.

Allowance for Doubtful Accounts

Allowance for Doubtful Accounts—We routinely assess the recoverability of all material trade and other receivables to determine their collectability. Many of our receivables are from a limited number of purchasers. Accordingly, accounts receivable from such purchases could be significant. Generally, our natural gas and crude oil receivables are collected within thirty to sixty days of production. We also have receivables from joint interest owners of properties we operate. We may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.

We accrue a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. As of each of December 31, 2013 and 2012, our allowance for doubtful accounts was immaterial.

Inventory

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 the Consolidated Balance Sheets at the lower of cost or market.

Property and Equipment

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—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 discovery. 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 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.

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.

As of December 31, 2013 and 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

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.

As of December 31, 2013, we had interests in oil and natural gas properties totaling $821.8 million, net of accumulated depletion, which we account for under the successful efforts method. The expected future cash flows used for impairment reviews and related fair-value calculations are based on judgmental assessments of future production volumes, prices, and costs, considering all available information at the date of review. Due to the uncertainty inherent in these factors, we cannot predict when or if additional future impairment charges will be recorded. We estimate future net cash flows generated from our oil and natural gas properties by using forecasted oil and natural gas prices published by the New York Mercantile Exchange (“NYMEX”).

We had no impairment associated with our oil and natural gas properties for 2013. For the years ended December 31, 2012 and 2011, we recorded impairments on our oil and natural gas properties of $47.8 million and $8.1 million, respectively. The impairment in 2012 reduced the fields’ carrying value to an estimated fair value of $3.3 million.

Depreciation

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

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 Trend area of South Texas. In compensation for the services, we agreed to pay the service provider 110 percent of the total capital cost incurred by the service provider to construct new pipelines and facilities. The service provider bills us for 20 percent of the accumulated unpaid capital costs annually.

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

Asset Retirement Obligations

Asset Retirement Obligations—We follow the accounting standard related to accounting for asset retirement obligations. These obligations are related to the abandonment and site restoration requirements that result from the exploration and development of our oil and 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 Statement of Operations.

Revenue Recognition

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 crude 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 December 31, 2013 and 2012, the net liability for natural gas balancing was immaterial. Differences between actual production and net working interest volumes are routinely adjusted.

Derivative Instruments

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 counterparty 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

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

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 and restricted stock calculated using the Treasury Stock method and the potential dilutive effect of the conversion of shares associated with 5.375% Series B Convertible Preferred Stock (“Series B Preferred Stock”), 3.25% Convertible Senior Notes due 2026 (the “2026 Notes”), 5% Convertible Senior Notes due 2029 (the “2029 Notes”) and 5% Convertible Senior Notes due 2032 (the “2032 Notes”).

Commitments and Contingencies

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 environmental liability.

Concentration of Credit Risk

Concentration of Credit Risk—Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. The revenues compared to our total oil and natural gas revenues from the top purchasers for the years ended December 31, 2013, 2012 and 2011 are as follows:

	Year Ended December 31,
	2013			2012			2011
BP Energy Company		64	%		34	%		—
Genesis Crude Oil LP		7	%		—			—
Flint Hill Resources, LLC		—			15	%		—
Shell Energy Resources LP		—			—			11	%
Regency Field Services LLC		—			—			10	%

Share-Based Compensation

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.

Guarantee

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 and October 1, 2013, we issued $109.25 million and $57.0 million, respectively, 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, 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

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 December 31, 2013 and December 31, 2012.

	December 31, 2013									December 31, 2012
Fair Value of Oil and Natural Gas Derivatives	Gross Amount			Amount Offset			As Presented			Gross Amount			Amount Offset			As Presented
	(in thousands)
Derivative Current Asset	$	6,658		$	(471	)	$	6,187		$	2,410		$	(285	)	$	2,125
Derivative Non-current Asset		1,396			—			1,396			—			—			—
Derivative Current Liability		(4,812	)		471			(4,341	)		(636	)		285			(351	)
Derivative Non-current Liability		(2,371	)		—			(2,371	)		(3,987	)		—			(3,987	)
Total	$	871		$	—		$	871		$	(2,213	)	$	—		$	(2,213	)

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies

NOTE 9—Commitments and Contingencies

We are party to various lawsuits from time to time arising in the normal course of business, including, but not limited to, royalty, contract, personal injury, and environmental claims. We have established reserves as appropriate for all such proceedings and intend to vigorously defend these actions. Management believes, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our consolidated financial position results of operations or liquidity.

The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2013 (in thousands).

	Payment due by Period
	Note		Total		2014		2015		2016		2017		2018 and After
Debt (1)		4	$	507,620	$	51,816	$	—	$	—	$	180,375	$	275,429
Interest on notes		4		87,053		34,676		32,733		13,410		6,234		—
Office space leases				8,232		1,450		1,332		1,381		1,430		2,639
Office equipment leases				461		298		140		23		—		—
Drilling rigs & operations contracts				14,534		14,353		133		43		5		—
Transportation contracts				6,327		1,552		955		955		955		1,910
Total contractual obligations (2)			$	624,227	$	104,145	$	35,293	$	15,812	$	188,999	$	279,978

(1) The 2026 Notes have a provision at the end of years 5, 10 and 15, for the investors to demand payment on these dates; the first such date was December 1, 2011; all but the remaining $0.4 million were redeemed. The next ‘put’ date for the remaining 2026 Notes is December 1, 2016. The 2029 Notes have a provision by which on or after October 1, 2014, we may redeem all or a portion of the notes for cash and the investors may require us to repurchase the notes on each of October 1, 2014, 2019 and 2024. The 2032 Notes have a provision by which on or after October 1, 2017, we may redeem all or a portion of the notes for cash, and the investors may require us to repurchase the notes on each of October 1, 2017, 2022 and 2027. The balance outstanding under our Senior Credit Facility is not included as it is revolving debt.

(2) This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $20.9 million as of December 31, 2013. We record a separate liability for the asset retirement obligations. See Note 3.

Operating Leases—We have commitments under an operating lease agreement for office space and office equipment leases. Total rent expense for the years ended December 31, 2013, 2012, and 2011, was approximately $1.3 million, $1.2 million and $1.1 million, respectively.

Drilling Contracts—We have two drilling rigs under contract as of December 31, 2013 which are scheduled to expire in 2014.

Defined Contribution Plan—We have a defined contribution plan (“DCP”) which matches a portion of employees’ contributions. Participation in the DCP is voluntary and all regular employees of the Company are eligible to participate. We charged to expense plan contributions of $0.7 million, $0.7 million and $0.7 million for 2013, 2012 and 2011, respectively.

Transportation Contracts—We have commitments under a transportation contract for our Eagle Ford Shale Trend properties. See Note 1 “—Transportation Obligation” for further information.

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Commitments and Contingencies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013 Rigs	Dec. 31, 2012	Dec. 31, 2011
Commitments and Contingencies Disclosure [Line Items]
Rent expense	$ 1.3	$ 1.2	$ 1.1
Number of drilling rigs	2
Drilling contracts expiration year	2014
Charge to expense plan	$ 0.7	$ 0.7	$ 0.7

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Stockholders' Equity

12 Months Ended

Dec. 31, 2013

Stockholders' Equity

NOTE 7—Stockholders’ Equity

5.375% Series B Convertible Preferred Stock

Our 5.375% Series B Convertible Preferred Stock (the “Series B Preferred Stock”) was initially issued on December 21, 2005, in a private placement of 1,650,000 shares for net proceeds of $79.8 million (after offering costs of $2.7 million). Each share of the Series B Preferred Stock has a liquidation preference of $50 per share, aggregating to $82.5 million, and bears a dividend of 5.375% per annum. Dividends are payable quarterly in arrears beginning March 15, 2006. If we fail to pay dividends on our Series B Preferred Stock on any six dividend payment dates, whether or not consecutive, the dividend rate per annum will be increased by 1.0% until we have paid all dividends on our Series B Preferred Stock for all dividend periods up to and including the dividend payment date on which the accumulated and unpaid dividends are paid in full.

On January 23, 2006, the initial purchasers of the Series B Preferred Stock exercised their over-allotment option to purchase an additional 600,000 shares at the same price per share, resulting in net proceeds of $29.0 million, which was used to fund our 2006 capital expenditure program.

Each share is convertible at the option of the holder into our common stock at any time at an initial conversion rate of 1.5946 shares of common stock per share, which is equivalent to an initial conversion price of approximately $31.36 per share of common stock. Upon conversion of the Series B Preferred Stock, we may choose to deliver the conversion value to holders in cash, shares of common stock, or a combination of cash and shares of common stock.

If a fundamental change occurs, holders may require us in specified circumstances to repurchase all or part of the Series B Convertible Preferred Stock. In addition, upon the occurrence of a fundamental change or specified corporate events, we will under certain circumstances increase the conversion rate by a number of additional shares of common stock. A “fundamental change” will be deemed to have occurred if any of the following occurs:

• We consolidate or merge with or into any person or convey, transfer, sell or otherwise dispose of or lease all or substantially all of our assets to any person, or any person consolidates with or merges into us or with us, in any such event pursuant to a transaction in which our outstanding voting shares are changed into or exchanged for cash, securities, or other property; or

• We are liquidated or dissolved or adopt a plan of liquidation or dissolution.

A “fundamental change” will not be deemed to have occurred if at least 90% of the consideration in the case of a merger or consolidation under the first clause above consists of common stock traded on a U.S. national securities exchange and the Series B Preferred Stock becomes convertible solely into such common stock.

On or after December 21, 2010, we may, at our option, cause the Series B Preferred Stock to be automatically converted into the number of shares of common stock that are issuable at the then-prevailing conversion rate, pursuant to the Company Conversion Option. We may exercise our conversion right only if, for 20 trading days within any period of 30 consecutive trading days ending on the trading day before the announcement of our exercise of the option, the closing price of the common stock equals or exceeds 130% of the then-prevailing conversion price of the Series B Preferred Stock. The Series B Preferred Stock is non-redeemable by us. There have been no redemptions or conversions in any periods.

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 $105.4 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.

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 $124.9 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 Series B 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.

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.

Common Stock Offering

On October 21, 2013, we closed an underwritten public offering of 6.9 million shares of our common stock sold at a price to the public of $25.25 per share.

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Derivative Activities

12 Months Ended

Dec. 31, 2013

Derivative Activities

NOTE 8—Derivative Activities

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

The following table summarizes the realized and unrealized gains and losses we recognized on our oil and natural gas derivatives for the years ended December 31, 2013, 2012 and 2011.

	December 31,
Oil and Natural Gas Derivatives (in thousands)	2013			2012			2011
Realized gain (loss) on oil and natural gas derivatives	$	(3,786	)	$	73,160		$	31,305
Unrealized gain (loss) on oil and natural gas derivatives		3,084			(41,278	)		3,234
Total gain (loss) on oil and natural gas derivatives	$	(702	)	$	31,882		$	34,539

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 hedged are approved by the Hedging Committee of our Board of Directors, and reviewed periodically by the Board of Directors. As of December 31, 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, Argus LLS or specific transfer point quoted prices, and

(b) 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 primarily 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 a fair value amount of $3.3 million had our counterparties as a group been unable to fulfill their obligations as of December 31, 2013.

As of December 31, 2013, our open positions on our outstanding commodity derivative contracts, all of which were with 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 Volume		Fixed Price	Fair Value at December 31, 2013 (in thousands)
Natural gas swaps (MMBtu)
2014		30,000		10,950,000	$4.18 – 5.06	$	6,187
Natural gas calls (MMBtu)
2015		20,000		7,300,000	$5.05 – 5.06		(1,125	)
2016		20,000		7,300,000	$5.05 – 5.06		(1,246	)
Oil swaps (BBL)
2014		3,800		1,387,000	$90.95 –$98.02		(4,341	)
2015		1,300		474,500	$94.55		1,396
					Total	$	871

During 2013, we entered into the following derivative contracts. Unless otherwise noted, West Texas Intermediate (“WTI”) quoted on the New York Mercantile Exchange (“NYMEX”) is used for the floating price of oil and Henry Hub as quoted on NYMEX is used for the floating price of natural gas.

Contract Type	Daily Volume		Strike Price		Contract Start Date		Contract Termination
Oil swap (BBL)		1,000	$	92.95		January 1, 2014		December 31, 2014
Oil swap (BBL)		500	$	98.02		November 1, 2013		December 31, 2014
Oil swap (BBL) (1)		1,300	$	94.55		January 1, 2014		December 31, 2014
Oil swap (BBL) (1)		1,300	$	94.55		January 1, 2015		December 31, 2015
Natural Gas swap (MMBtu)		10,000	$	4.1825		October 1, 2013		December 31, 2014
Natural Gas swap (MMBtu)		20,000	$	5.05 – 5.06		January 1, 2014		December 31, 2014
Natural Gas calls (MMBtu)		20,000	$	5.05 – 5.06		January 1, 2015		December 31, 2016

(1) Commodity contract pricing based on Louisiana Light Sweet crude (Argus) trade month swap.

The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each level as of December 31, 2013 and 2012 (in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See Footnote 1 “Fair Value Measurement” for our discussion for inputs used and valuation techniques for determining fair values.

	2013 Fair Value Measurements Using
Description	Level 1		Level 2			Level 3		Total
Current Assets Commodity Derivatives	$	—	$	6,187		$	—	$	6,187
Non-current Assets Commodity Derivatives		—		1,396			—		1,396
Current Liabilities Commodity Derivatives		—		(4,341	)		—		(4,341	)
Non-current Liabilities Commodity Derivatives		—		(2,371	)		—		(2,371	)
Total	$	—	$	871		$	—	$	871
	2012 Fair Value Measurements Using
Description	Level 1		Level 2			Level 3		Total
Current Assets Commodity Derivatives	$	—	$	2,125		$	—	$	2,125
Current Liabilities Commodity Derivatives		—		(351	)		—		(351	)
Non-current Liabilities Commodity Derivatives		—		(3,987	)		—		(3,987	)
Total	$	—	$	(2,213	)	$	—	$	(2,213	)

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Related Party Transactions

12 Months Ended

Dec. 31, 2013

Related Party Transactions

NOTE 10—Related Party Transactions

Patrick E. Malloy, III, Chairman of the Board of Directors of our company is a principal of Malloy Energy Company, LLC (“MEC”). MEC owns various small working interests in the Bethany Longstreet field for which we are the operator. In accordance with industry standard joint operating agreements, we bill MEC for its share of capital and operating cost on a monthly basis. As of December 31, 2013 and 2012, the amounts billed and outstanding to MEC for its share of monthly capital and operating costs were both less than $0.1 million and are included in trade and other accounts receivable at each year-end. Such amounts at each year-end were paid by MEC to us in the month after billing and is current on payment of its billings.

We also serve as the operator for a number of other oil and natural gas wells owned by affiliates of MEC in which we will earn a working interest after payout. In accordance with industry standard joint operating agreements, we bill the affiliates for its share of the capital and operating costs of these wells on a monthly basis. As of December 31, 2013 and 2012, the amounts billed and outstanding to the affiliate for its share of monthly capital and operating costs were both less than $0.3 million and are included in trade and other accounts receivable at each year-end. Such amounts at each year-end were paid by the affiliate to us in the month after billing and the affiliate is current on payment of its billings.

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Summarized Quarterly Financial Data (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information [Line Items]
Revenues	$ 50,565	$ 57,161	$ 48,485	$ 47,084	$ 48,231	$ 45,960	$ 41,346	$ 45,308	$ 203,295	$ 180,845	$ 201,069
Operating income (loss)	(8,122)	(854)	(14,192)	(13,142)	(67,141)	31,854	(14,157)	(14,241)	(36,310)	(63,685)	(17,067)
Net income (loss)	(23,495)	(27,085)	(16,143)	(28,463)	(75,676)	12,405	(3,202)	(17,729)	(95,186)	(84,202)	(31,758)
Net income (loss) applicable to common stock	$ (30,926)	$ (32,790)	$ (20,099)	$ (29,975)	$ (77,188)	$ 10,894	$ (4,714)	$ (19,241)	$ (113,790)	$ (90,249)	$ (37,805)
Basic income (loss) per common share	$ (0.73)	$ (0.89)	$ (0.55)	$ (0.82)	$ (2.12)	$ 0.30	$ (0.13)	$ (0.53)	$ (2.99)	$ (2.48)	$ (1.05)
Diluted income (loss) per common share	$ (0.73)	$ (0.89)	$ (0.55)	$ (0.82)	$ (2.12)	$ 0.30	$ (0.13)	$ (0.53)	$ (2.99)	$ (2.48)	$ (1.05)

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Unaudited Pro forma Condensed Consolidated Statements of Operations (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition, Pro Forma Information [Line Items]
Total revenues	$ 210,675	$ 191,068
Operating expenses	240,102	246,187
Operating loss	(29,427)	(55,119)
Net loss	(88,303)	(75,636)
Net loss applicable to common stock	(106,907)	(81,683)
Per Common Share
Net loss applicable to common stock-basic	$ (2.81)	$ (2.24)
Net loss applicable to common stock-diluted	$ (2.81)	$ (2.24)
Weighted average common shares outstanding-basic	38,098	36,390
Weighted average common shares outstanding-diluted	38,098	36,390
As Reported
Business Acquisition, Pro Forma Information [Line Items]
Total revenues	203,295	180,845
Operating expenses	239,605	244,530
Operating loss	(36,310)	(63,685)
Net loss	(95,186)	(84,202)
Net loss applicable to common stock	(113,790)	(90,249)
Per Common Share
Net loss applicable to common stock-basic	$ (2.99)	$ (2.48)
Net loss applicable to common stock-diluted	$ (2.99)	$ (2.48)
Weighted average common shares outstanding-basic	38,098	36,390
Weighted average common shares outstanding-diluted	38,098	36,390
Adjustments
Business Acquisition, Pro Forma Information [Line Items]
Total revenues	7,380	10,223
Operating expenses	497	1,657
Operating loss	6,883	8,566
Net loss	6,883	8,566
Net loss applicable to common stock	$ 6,883	$ 8,566

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Components of Share-Based Compensation (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Restricted stock expense	$ 7,586	$ 6,670	$ 6,194
Stock option expense	94	233	301
Director stock expense	568	585	525
Total share-based compensation:	$ 8,248	$ 7,488	$ 7,020

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Income Taxes - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Income Tax Expenses [Line Items]
Deferred tax assets valuation allowance increase	$ 23.7
Deferred Tax Assets, Net	23.7
Net operating loss carry-forwards	608.9
Operating loss carryforwards, expiration dates	2026
Tax credit carryforward, amount	$ 1.2

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Derivative Activities (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Assets and Liabilities Recorded at Fair Value

The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each level as of December 31, 2013 and 2012 (in thousands). We measure the fair value of our commodity derivative contracts by applying the income approach. See Footnote 1 “Fair Value Measurement” for our discussion for inputs used and valuation techniques for determining fair values.

	2013 Fair Value Measurements Using
Description	Level 1		Level 2			Level 3		Total
Current Assets Commodity Derivatives	$	—	$	6,187		$	—	$	6,187
Non-current Assets Commodity Derivatives		—		1,396			—		1,396
Current Liabilities Commodity Derivatives		—		(4,341	)		—		(4,341	)
Non-current Liabilities Commodity Derivatives		—		(2,371	)		—		(2,371	)
Total	$	—	$	871		$	—	$	871
	2012 Fair Value Measurements Using
Description	Level 1		Level 2			Level 3		Total
Current Assets Commodity Derivatives	$	—	$	2,125		$	—	$	2,125
Current Liabilities Commodity Derivatives		—		(351	)		—		(351	)
Non-current Liabilities Commodity Derivatives		—		(3,987	)		—		(3,987	)
Total	$	—	$	(2,213	)	$	—	$	(2,213	)

Summary of Realized and Unrealized Gains and Losses on Derivatives

The following table summarizes the realized and unrealized gains and losses we recognized on our oil and natural gas derivatives for the years ended December 31, 2013, 2012 and 2011.

	December 31,
Oil and Natural Gas Derivatives (in thousands)	2013			2012			2011
Realized gain (loss) on oil and natural gas derivatives	$	(3,786	)	$	73,160		$	31,305
Unrealized gain (loss) on oil and natural gas derivatives		3,084			(41,278	)		3,234
Total gain (loss) on oil and natural gas derivatives	$	(702	)	$	31,882		$	34,539

Outstanding Commodity Derivative Contracts

As of December 31, 2013, our open positions on our outstanding commodity derivative contracts, all of which were with 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 Volume		Fixed Price	Fair Value at December 31, 2013 (in thousands)
Natural gas swaps (MMBtu)
2014		30,000		10,950,000	$4.18 – 5.06	$	6,187
Natural gas calls (MMBtu)
2015		20,000		7,300,000	$5.05 – 5.06		(1,125	)
2016		20,000		7,300,000	$5.05 – 5.06		(1,246	)
Oil swaps (BBL)
2014		3,800		1,387,000	$90.95 –$98.02		(4,341	)
2015		1,300		474,500	$94.55		1,396
					Total	$	871

Derivative Contracts

During 2013, we entered into the following derivative contracts. Unless otherwise noted, West Texas Intermediate (“WTI”) quoted on the New York Mercantile Exchange (“NYMEX”) is used for the floating price of oil and Henry Hub as quoted on NYMEX is used for the floating price of natural gas.

Contract Type	Daily Volume		Strike Price		Contract Start Date		Contract Termination
Oil swap (BBL)		1,000	$	92.95		January 1, 2014		December 31, 2014
Oil swap (BBL)		500	$	98.02		November 1, 2013		December 31, 2014
Oil swap (BBL) (1)		1,300	$	94.55		January 1, 2014		December 31, 2014
Oil swap (BBL) (1)		1,300	$	94.55		January 1, 2015		December 31, 2015
Natural Gas swap (MMBtu)		10,000	$	4.1825		October 1, 2013		December 31, 2014
Natural Gas swap (MMBtu)		20,000	$	5.05 – 5.06		January 1, 2014		December 31, 2014
Natural Gas calls (MMBtu)		20,000	$	5.05 – 5.06		January 1, 2015		December 31, 2016

(1) Commodity contract pricing based on Louisiana Light Sweet crude (Argus) trade month swap.

Derivative

Derivative Assets and Liabilities Recorded at Fair Value

The following table discloses and reconciles the gross amounts to the amounts as presented on the Statement of Financial Position for the periods ending December 31, 2013 and December 31, 2012.

	December 31, 2013									December 31, 2012
Fair Value of Oil and Natural Gas Derivatives	Gross Amount			Amount Offset			As Presented			Gross Amount			Amount Offset			As Presented
	(in thousands)
Derivative Current Asset	$	6,658		$	(471	)	$	6,187		$	2,410		$	(285	)	$	2,125
Derivative Non-current Asset		1,396			—			1,396			—			—			—
Derivative Current Liability		(4,812	)		471			(4,341	)		(636	)		285			(351	)
Derivative Non-current Liability		(2,371	)		—			(2,371	)		(3,987	)		—			(3,987	)
Total	$	871		$	—		$	871		$	(2,213	)	$	—		$	(2,213	)

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Components of Income Tax Expense (Benefit)

Income tax (expense) benefit consisted of the following (in thousands):

	Year Ended December 31,
	2013		2012		2011
Current:
Federal	$	—	$	—	$	—
State		—		—		—
		—		—		—
Deferred:
Federal		—		—		—
State		—		—		—
		—		—		—
Total	$	—	$	—	$	—

Reconciliation of Statutory Income Tax Rate to Income Loss Before Income Taxes

The following is a reconciliation of the U.S. statutory income tax rate at 35% to our income (loss) before income taxes (in thousands):

	Year Ended December 31,
	2013			2012			2011
Income tax (expense) benefit
Tax at U.S. statutory income tax	$	33,315		$	29,471		$	11,115
Valuation allowance		(30,967	)		(29,952	)		(9,909	)
State income taxes-net of federal benefit		(902	)		1,618			(762	)
Nondeductible expenses and other		(1,446	)		(1,137	)		(444	)
Total tax (expense) benefit	$	—		$	—		$	—

Schedule Of Deferred Tax (Liabilities) Assets

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below (in thousands):

	December 31,
	2013			2012
Current deferred tax assets:
Accrued liabilities	$	133		$	375
Contingent liabilities and other		—			134
Less valuation allowance		(126	)		(498	)
Total current deferred tax assets		7			11
Current deferred tax liabilities:
Derivative financial instruments		(646	)		(621	)
Accrued liabilities		(26	)		(26	)
Total current deferred tax liabilities		(672	)		(647	)
Net current deferred tax liability	$	(665	)	$	(636	)
Noncurrent deferred tax assets:
Operating loss carry-forwards	$	211,589		$	156,723
State Tax NOL and Credits		5,805			3,867
Statutory depletion carry-forward		7,035			7,035
AMT tax credit carry-forward		1,227			1,324
Compensation		3,496			3,364
Contingent liabilities and other		858			1,907
Property and equipment		(3,248	)		26,848
Total gross noncurrent deferred tax assets		226,762			201,068
Less valuation allowance		(217,558	)		(193,459	)
Net noncurrent deferred tax assets		9,204			7,609
Noncurrent deferred tax liabilities:
Bond discount		(74	)		(61	)
Debt discount		(8,465	)		(6,912	)
Total non-current deferred tax liabilities		(8,539	)		(6,973	)
Net non-current deferred tax asset	$	665		$	636

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Reconciliation of Statutory Income Tax Rate to Income Loss Before Income Taxes (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Statutory Federal Tax Rate [Line Items]
Tax at U.S. statutory income tax	$ 33,315	$ 29,471	$ 11,115
Valuation allowance	(30,967)	(29,952)	(9,909)
State income taxes-net of federal benefit	(902)	1,618	(762)
Nondeductible expenses and other	(1,446)	(1,137)	(444)
Total tax (expense) benefit

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Reconciliation of Asset Retirement Obligations (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations [Line Items]
Increment in estimated liability	$ 1.3

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Consolidated Statements Of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (95,186)	$ (84,202)	$ (31,758)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization	135,357	141,222	131,811
Unrealized (gain) loss on derivatives not designated as hedges	(3,084)	41,278	(3,234)
Impairment	0	47,818	8,111
Exploration costs	4,728	12,848
Amortization of leasehold costs	13,675	5,948	5,487
Share based compensation (non-cash)	7,680	6,903	6,495
Gain on sale of assets	(107)	(44,606)	(236)
(Gain) loss on extinguishment of debt	7,088		(62)
Amortization of finance cost and debt discount	12,745	12,819	14,351
Amortization of transportation obligation	1,226	1,457	2,873
Change in assets and liabilities:
Restricted cash			4,232
Accounts receivable, trade and other, net of allowance	3,965	580	355
Income taxes receivable/payable		277	3,995
Accrued oil and natural gas revenue	(401)	1,399	(5,500)
Inventory	126	6,415	(796)
Prepaid expenses and other	386	3,356	(2,953)
Accounts payable	(22,543)	26,999	(1,079)
Accrued liabilities	5,750	(6,722)	4,248
Net cash provided by operating activities	71,405	173,789	136,340
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(251,103)	(252,416)	(335,236)
Proceeds from sale of assets	449	90,922	172
Net cash used in investing activities	(250,654)	(161,494)	(335,064)
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments of bank borrowings	(382,800)	(132,000)	(42,000)
Proceeds from bank borrowings	287,800	124,500	144,500
Proceeds from preferred stock offering	230,625
Proceeds from equity offering	166,149
Proceeds from high yield offering			275,000
Repurchase of convertible notes			(176,422)
Debt issuance costs	(4,636)	(66)	(9,341)
Preferred stock dividends	(18,604)	(6,047)	(6,047)
Cash restricted for repurchase of convertible notes	(51,816)
Exercise of stock options and warrants	807	16
Other	(244)	(857)	(1,407)
Net cash provided by (used in) financing activities	227,281	(14,454)	184,283
Increase (decrease) in cash and cash equivalents	48,032	(2,159)	(14,441)
Cash and cash equivalents, beginning of period	1,188	3,347	17,788
Cash and cash equivalents, end of period	49,220	1,188	3,347
Supplemental disclosures of cash flow information:
Cash paid during the year for interest	38,087	39,516	35,000
Cash paid during the year for taxes

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Debt

12 Months Ended

Dec. 31, 2013

Debt

NOTE 4—Debt

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

	December 31, 2013						December 31, 2012
	Principal		Carrying Amount		Fair Value (1)		Principal		Carrying Amount		Fair Value (1)
Senior Credit Facility (1)	$	—	$	—	$	—	$	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)		51,816		49,663		51,686		218,500		198,242		204,975
5.0% Convertible Senior Notes due 2032 (3)		167,405		160,437		171,863		—		—		—
8.875% Senior Notes due 2019		275,000		275,000		288,063		275,000		275,000		261,250
Total debt	$	494,650	$	485,529	$	512,041	$	588,929	$	568,671	$	561,654

(1) The carrying amount for the Second Amended and Restated Credit Agreement represents fair value as the variable interest rates are reflective of current market conditions. The fair value of the notes 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 debt discount was $2.1 million and $20.3 million as of December 31, 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 $7.0 million as of December 31, 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):

	December 31, 2013					December 31, 2012					December 31, 2011
	Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate			Interest Expense		Effective Interest Rate
Senior Credit Facility		3,936		5.3	%		5,114		3.7	%		3,180		—	*
3.25% Convertible Senior Notes due 2026		14		3.3	%		14		3.3	%		4,305		9.	%
5.0% Convertible Senior Notes due 2029		17,400		11.4	%		21,968		11.4	%		20,948		10.5	%
5.0% Convertible Senior Notes due 2032		4,529		8.8	%		—		—			—		—
8.875% Senior Notes due 2019		25,308		9.2	%		25,308		9.2	%		20,910		8.9	%

* An Effective Interest Rate Calculation is not meaningful for the years ended December 31, 2011 since there were only minimal average amounts borrowed under the Senior Credit Facility during the period.

Senior Credit Facility

Total lender commitments under the Second Amended and Restated Credit Agreement (including all amendments, 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 December 31, 2013, we had no amounts outstanding 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 permitted 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 December 31, 2013, we held $51.8 million in an escrow account to provide for the repurchase of the remaining outstanding principal amount of our 2029 Notes, which is reflected on our financial statements 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 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.

We were in compliance with all the financial covenants of the Senior Credit Facility as of December 31, 2013.

8.875% Senior Notes due 2019

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

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

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

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. During 2013, we entered into separate, privately negotiated exchange agreements under which we retired $166.7 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 principal amount of $166.3 million. The 2032 Notes will mature on October 1, 2032. As of December 31, 2013, $51.8 million in aggregate principal amount of the 2029 Notes remain outstanding with terms unchanged. Please see the 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.

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).

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 2013 exchange transactions, $2.1 million of debt discount remains to be amortized on the 2029 Notes as of December 31, 2013. 2013. Investors can demand repayment on October 1, 2014, accordingly the $49.7 million carrying value of the 2029 Notes is reflected on our financial statements as a current liability.

5% Convertible Senior Notes due 2032

We entered into separate, privately negotiated exchange agreements under which we retired $166.7 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 principal amount of $166.3 million. The 2032 Notes will mature on October 1, 2032.

Many terms of the 2032 Notes 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 accretes 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 $1.2 million of accretion during 2013.

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 $166.7 million of outstanding 2029 Notes with a carrying value of $156.9 million and wrote-off unamortized debt issuance cost of $0.8 million offset by $20.0 million attributable to the fair value of the equity portion of the 2029 Notes. The 2032 Notes had a fair value of $183.2 million which resulted in a loss on the early extinguishment of debt of $7.1 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 $158.8 million of the fair value to the 2032 Note to debt component which compared to the face results in a debt discount of $7.5 million which will be amortized through the first put date of October 1, 2017. Additionally, we recorded $24.4 million within additional paid-in capital representing the equity component of the 2032 Notes. A debt discount of $7.0 million remains to be amortized on the 2032 Notes as of December 31, 2013.

3.25% Convertible Senior Notes Due 2026

During the year ended December 31, 2011, we repurchased $174.6 million of our 2026 Notes for $176.4 million using a portion of the net proceeds from the issuance of our 2019 Notes. We recorded a $0.1 million gain on the early extinguishment of debt related to the repurchase for the year ended December 31, 2011.

At December 31, 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 notes are convertible into shares of our common stock at a rate equal to the sum of:

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

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

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Timing of Future Payments Obligations (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Commitment And Contingencies [Line Items]
Debt, Total	$ 507,620	[1]
Debt, 2014	51,816	[1]
Debt, 2015		[1]
Debt, 2016		[1]
Debt, 2017	180,375	[1]
Debt, 2018 and After	275,429	[1]
Interest Expense, Debt, Total	87,053
Interest on convertible senior notes, 2014	34,676
Interest on convertible senior notes, 2015	32,733
Interest on convertible senior notes, 2016	13,410
Interest on convertible senior notes, 2017	6,234
Interest on convertible senior notes, 2018 and After
Drilling rigs & operations contracts, Total	14,534
Drilling rigs & operations contracts, 2014	14,353
Drilling rigs & operations contracts, 2015	133
Drilling rigs & operations contracts, 2016	43
Drilling rigs & operations contracts, 2017	5
Drilling rigs & operations contracts, 2018 and After
Contractual Obligations, Total	624,227	[2]
Contractual Obligations, 2014	104,145	[2]
Contractual Obligations, 2015	35,293	[2]
Contractual Obligations, 2016	15,812	[2]
Contractual Obligations, 2017	188,999	[2]
Contractual Obligations, 2018 and After	279,978	[2]
Office Space Leases
Commitment And Contingencies [Line Items]
Total Lease future payments	8,232
Leases, 2014	1,450
Leases, 2015	1,332
Leases, 2016	1,381
Leases, 2017	1,430
Leases, 2018 and After	2,639
Office Equipment Leases
Commitment And Contingencies [Line Items]
Total Lease future payments	461
Leases, 2014	298
Leases, 2015	140
Leases, 2016	23
Transportation Contracts
Commitment And Contingencies [Line Items]
Total Lease future payments	6,327
Leases, 2014	1,552
Leases, 2015	955
Leases, 2016	955
Leases, 2017	955
Leases, 2018 and After	$ 1,910

[1] The 2026 Notes have a provision at the end of years 5, 10 and 15, for the investors to demand payment on these dates; the first such date was December 1, 2011; all but the remaining $0.4 million were redeemed. The next 'put' date for the remaining 2026 Notes is December 1, 2016. The 2029 Notes have a provision by which on or after October 1, 2014, we may redeem all or a portion of the notes for cash and the investors may require us to repurchase the notes on each of October 1, 2014, 2019 and 2024. The 2032 Notes have a provision by which on or after October 1, 2017, we may redeem all or a portion of the notes for cash, and the investors may require us to repurchase the notes on each of October 1, 2017, 2022 and 2027. The balance outstanding under our Senior Credit Facility is not included as it is revolving debt.

[2] This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $20.9 million as of December 31, 2013. We record a separate liability for the asset retirement obligations. See Note 3.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Timing of Future Payments Obligations

The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2013 (in thousands).

	Payment due by Period
	Note		Total		2014		2015		2016		2017		2018 and After
Debt (1)		4	$	507,620	$	51,816	$	—	$	—	$	180,375	$	275,429
Interest on notes		4		87,053		34,676		32,733		13,410		6,234		—
Office space leases				8,232		1,450		1,332		1,381		1,430		2,639
Office equipment leases				461		298		140		23		—		—
Drilling rigs & operations contracts				14,534		14,353		133		43		5		—
Transportation contracts				6,327		1,552		955		955		955		1,910
Total contractual obligations (2)			$	624,227	$	104,145	$	35,293	$	15,812	$	188,999	$	279,978

(1) The 2026 Notes have a provision at the end of years 5, 10 and 15, for the investors to demand payment on these dates; the first such date was December 1, 2011; all but the remaining $0.4 million were redeemed. The next ‘put’ date for the remaining 2026 Notes is December 1, 2016. The 2029 Notes have a provision by which on or after October 1, 2014, we may redeem all or a portion of the notes for cash and the investors may require us to repurchase the notes on each of October 1, 2014, 2019 and 2024. The 2032 Notes have a provision by which on or after October 1, 2017, we may redeem all or a portion of the notes for cash, and the investors may require us to repurchase the notes on each of October 1, 2017, 2022 and 2027. The balance outstanding under our Senior Credit Facility is not included as it is revolving debt.

(2) This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $20.9 million as of December 31, 2013. We record a separate liability for the asset retirement obligations. See Note 3.

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Schedule of Restricted Stock Activity (Detail) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Number of Shares
Unvested at January 1, 2013	1,541,650
Vested	(594,301)
Granted	746,163	1,073,727	561,714
Forfeited	(112,305)
Unvested at December 31, 2013	1,581,207	1,541,650
Weighted Average Grant-Date Fair Value	$ 10.60
Vested	$ 11.57
Granted	$ 17.68
Forfeited	$ 10.69
Unvested at December 31, 2013	$ 13.58	$ 10.60
Total Value
Unvested at January 1, 2013	$ 16,345
Vested	(6,863)
Granted	13,194
Forfeited	(1,200)
Unvested at December 31, 2013	$ 21,476	$ 16,345

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Description of Business and Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Revenues from Top Customers as Percentage of Total Revenues

The revenues compared to our total oil and natural gas revenues from the top purchasers for the years ended December 31, 2013, 2012 and 2011 are as follows:

	Year Ended December 31,
	2013			2012			2011
BP Energy Company		64	%		34	%		—
Genesis Crude Oil LP		7	%		—			—
Flint Hill Resources, LLC		—			15	%		—
Shell Energy Resources LP		—			—			11	%
Regency Field Services LLC		—			—			10	%