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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, 2012

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

(Title of Class) (Name of Exchange)

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

Series B Preferred Stock, $1.00 par value

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, 2012, the last business day of the registrant’s most recently completed second fiscal quarter) was approximately

$359.7 million. The number of shares of the registrant’s common stock outstanding as of February 18, 2013 was 36,759,232.

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, 2012, are incorporated by reference in Part III of this Form 10-K.
days of December 31, 2012, are incorporated by reference in Part III of this Form 10-K.
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GOODRICH PETROLEUM CORPORATION

ANNUAL REPORT ON FORM 10-K

FOR THE FISCAL YEAR ENDED

December 31, 2012

 Page

PART I 

Items 1. and 2. Business and Properties 3 

Item 1A. Risk Factors 20 

Item 1B. Unresolved Staff Comments 30 

Item 3. Legal Proceedings 30 

Item 4. Mine Safety Disclosures 30 

PART II 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 31 

Item 6. Selected Financial Data 33 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 34 

Item 7A. Quantitative and Qualitative Disclosures about Market Risk 53 

Item 8. Financial Statements and Supplementary Data 5 5 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 90 

Item 9A. Controls and Procedures 90 

Item 9B. Other Information 90 

PART III 

Item 10. Directors and Executive Officers of the Registrant and Corporate Governance 91 

Item 11. Executive Compensation 93 

Item 12. Security Ownership of Certain Beneficial Owners and Management 93 

Item 13. Certain Relationships and Related Transactions and Director Independence 93 

Item 14. Principal Accounting Fees and Services 93 

PART IV 

Item 15. Exhibits and Financial Statement Schedules 94 

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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. In the current 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. In

addition, we continue to aggressively pursue the evaluation and acquisition of prospective acreage and oil and natural gas drilling opportunities outside of our

existing leased acreage. We own working interests in 392 producing oil and natural gas wells located in 32 fields in eight states. At December 31, 2012, we had

estimated proved reserves of approximately 333.1 Bcfe, comprised of 254.0 Bcf of natural gas, 5.1 MMBbls of natural gas liquids (NGLs) and 8.1 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

SEC United States Securities and Exchange Commission

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 “farmin,” 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). PV10 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, 2012, nearly all of our proved oil and natural gas reserves were located in Louisiana, Texas and Mississippi. We spent

substantially all of our 2012 capital expenditures of $250.7 million in these areas, with $173.5 million, or 69%, spent on the Eagle Ford Shale Trend, $48.7

million, or 19%, on the Tuscaloosa Marine Shale and $26.8 million, or 11%, spent on the Haynesville Shale Trend. Our total capital expenditures, including

accrued costs for services performed during 2012, consist of $221.3 million for drilling and completion costs, $22.3 million for leasehold acquisitions, $5.7

million for facilities, infrastructure and equipment and $1.4 million for geological and geophysical costs.

The table below details our acreage positions, average working interest and producing wells as of December 31, 2012.

Field or Area

 

Acreage

As of December 31, 2012 

Average

Working

Interest

Producing Wells at

 Gross Net December 31, 2012

Eagle Ford Shale Trend 53,515 38,582 72% 51 

Cotton Valley Taylor Sand 43,185 38,339 93% 5 

Haynesville Shale Trend 122,555 78,860 46% 78 

Tuscaloosa Marine Shale 158,214 134,244 84% 2 

Other 32,029 6,831 39% 256 

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Eagle Ford Shale Trend

As of December 31, 2012, we have acquired or farmed-in leases totaling approximately 53,500 gross (38,600 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 2012, we drilled 33 gross (22 net) oil wells.

Tuscaloosa Marine Shale

As of December 31, 2012, we have acquired approximately 158,200 gross (134,200 net) lease acres in the Tuscaloosa Marine Shale Trend, an emerging

oil shale play in East Feliciana, West Feliciana, St. Helena, Concordia and Washington parishes in Southeast Louisiana and Wilkinson, Pike and Amite

Counties in Southwest Mississippi. During 2012, we conducted drilling operations on six gross (two net) and added to production two gross (0.5 net)

Tuscaloosa Marine Shale wells. One gross (0.8 net) drilling well resulted in a mechanical failure in which operations have been suspended.

Haynesville Shale Trend

As of December 31, 2012, we have acquired or farmed-in leases totaling approximately 122,600 gross (78,900 net) acres in the Haynesville Shale.

During 2012, we drilled and completed six gross (three net) successful Haynesville Shale wells. Our Haynesville Shale drilling activities are located in five

primary leasehold areas in East Texas and Northwest Louisiana.

In December 2010, we sold a significant amount of our shallow rights in fields in East Texas and Northwest Louisiana, but retained ownership of all the

deep rights including the Haynesville and Bossier Shale formations. The sale resulted in net proceeds of $64.9 million, after normal closing adjustments.

Cotton Valley Taylor Sand

As of December 31, 2012, we have acquired or farmed-in leases totaling approximately 43,200 gross (38,300 net) lease acres in the Cotton Valley Taylor

Sand Trend. During 2012, we drilled and completed one gross (0.5 net) well, with a 100% success rate.

Other

As of December 31, 2012, 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.

On September 28, 2012, we closed the sale of certain non-core natural gas properties in the South Henderson field in the Cotton Valley Taylor Sand

Trend to Memorial Resource Development, L.L.C. The total consideration paid for these assets was $95 million and we recognized a gain on the sale of assets

of $44.0 million. The sale was effective as of July 1, 2012.

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 2013 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 and 2011, as estimated by

Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers. A copy of their summary reserve report for 2012 is included as an exhibit

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, 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) (5) (6) 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 

 Proved Reserves at December 31, 2011

 

Developed

Producing 

Developed

Non-Producing Undeveloped Total

 (dollars in thousands)

Net Proved Reserves: 

Oil (MBbls) (1) 2,329 222 3,151 5,702 

NGL (MBbls) (4) (6) 3,854 127 3,833 7,814 

Natural Gas (Mmcf) (4) 152,066 17,277 239,364 408,707 

Natural Gas Equivalent (Mmcfe) (2) 189,161 19,377 281,267 489,805 

Estimated Future Net Cash Flows $1,049,967 

PV-10 (3) $ 452,009 

Discounted Future Income Taxes (4,039) 

Standardized Measure of Discounted Net Cash Flows (3) $ 447,970 

(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 reserves, or

standardized measure, as of December 31, 2012 was $357.4 million. See the reconciliation of our PV-10 to the standardized measure of discounted

future net cash flows in the table above.

(4) Reserves were recast for 2011 to break out NGLs from our natural gas in our Eagle Ford Shale Trend, West Brachfield, South Henderson, Minden and

Beckville fields.

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(5) NGL reserves for 2012 include our Eagle Ford Shale Trend, West Brachfield, Minden and Beckville fields but not South Henderson as it was sold in

September 2012.

(6) 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, 2012

Area 

Proved

Developed 

Proved

Undeveloped 

Proved

Reserves 

% of

Total

Haynesville Shale Trend 84,231 65,812 150,043 45% 

Cotton Valley Taylor Sand Trend 8,609 87,989 96,598 29% 

Eagle Ford Shale Trend 30,991 20,434 51,425 16% 

Tuscaloosa Marine Shale Trend 516 529 1,045 — 

Other 34,005 — 34,005 10% 

Total 158,352 174,764 333,116 100% 

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 2012

through December 2012, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. For

reserves at December 31, 2012, the average twelve month prices used were $2.76 per MMBtu of natural gas and $91.21 per Bbl of crude oil/condensate.

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, 2012 included in this Annual Report on Form 10-K was estimated by our independent petroleum

consultant, NSAI, 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 Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum

Engineers.

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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, 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 estimate of reserves from a nationally reputable petroleum engineering firm, such as

NSAI, 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 reserve report is reviewed by our senior management with representatives of NSAI 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 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, 2012, as estimated by NSAI, were 333.1 Bcfe, consisting of 254.0 Bcf of natural gas, 5.1 MMBbls of

NGLs and 8.1 MMBbls of oil and condensate. In 2012 we added approximately 2.1 Bcfe related to the Haynesville Shale Trend and Cotton Valley Taylor

Sand Trend, 29.1 Bcfe related to the Eagle Ford Shale Trend and 1.2 Bcfe in other areas. We had negative revisions of approximately 120.8 Bcfe, sale of

minerals of 36.1 Bcfe and produced 32.2 Bcfe in 2012. The vast majority of our negative revisions related to the loss of proved undeveloped natural gas

reserves reflecting low natural gas prices for the year ended December 31, 2012 at an average Henry Hub spot price of $2.76 per MMBtu.

Our proved undeveloped reserves at December 31, 2012 were 174.8 Bcfe or 52% of our total proved reserves, consisting of 134.3 Bcf of natural gas, 3.3

MMBbls of NGLs and 3.5 MMBbls of oil and condensate. In 2012 we added approximately 14.0 Bcfe related to the Eagle Ford Shale Trend and 0.5 Bcfe

related to the Tuscaloosa Marine Shale Trend. We had negative revisions of 103.7 Bcfe and we developed approximately 17.4 Bcfe, or 6% of our total proved

undeveloped reserves booked as of December 31, 2011 through the drilling of 16 gross (10 net) development wells at an aggregate capital cost of approximately

$73.2 million. Of the proved undeveloped reserves in our December 31, 2012 reserve report, none have remained undeveloped for more than five years since

the date of initial booking as proved undeveloped reserves and none are scheduled for commencement of development on a date more than five years from the

date the reserves were initially booked as proved undeveloped.

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Productive Wells

The following table sets forth the number of productive wells in which we maintain ownership interests as of December 31, 2012:

 Oil Natural Gas Total

 Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2)

South Texas 51 34 — — 51 34 

East Texas 1 — 207 194 208 194 

Northwest Louisiana — — 105 44 105 44 

Other 14 4 14 — 28 4 

Total Productive Wells 6 6 38 326 238 392 276 

(1) Royalty and overriding interest wells that have immaterial values are excluded from the above table. As of December 31, 2012, only three wells with

royalty-only and overriding interests-only are included.

(2) Net working interest.

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, 51 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, 2012. 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 14,199 10,460 39,316 28,123 53,515 38,583 

East Texas 80,556 50,832 32,471 22,948 113,027 73,780 

Northwest Louisiana 38,412 22,167 3,025 1,752 41,437 23,919 

Southeast Louisiana — — 72,050 71,880 72,050 71,880 

Southwest Mississippi 490 387 85,674 61,977 86,164 62,364 

Other 2,135 227 9 9 2,144 236 

Total 135,792 84,073 232,545 186,689 368,337 270,762 

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, 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.

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The following table sets forth the lease expirations as of December 31, 2012:

Year 

Net

Acreage

2013 10,847 

2014 38,252 

2015 14,008 

2016 6,119 

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,

 2012 2011 2010

 Gross Net Gross Net Gross Net

Development Wells: 

Productive 40 25.3 46 24.1 44 18.9 

Non-Productive — — — — — — 

Total 40 25.3 46 24.1 44 18.9 

Exploratory Wells: 

Productive 5 1.0 1 0.7 3 2.3 

Non-Productive 1 0.8 — — — — 

Total 6 1.8 1 0.7 3 2.3 

Total Wells: 

Productive 45 26.3 47 24.8 47 21.2 

Non-Productive 1 0.8 — — — — 

Total 46 27.1 47 24.8 47 21.2 

At December 31, 2012, we had 20 gross (10 net) development wells and two gross (0.6 net) exploration wells in progress of being drilled or completed.

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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 our total proved reserves as of December 31, 2012), 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, 2012.

 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 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 6 6 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 

For Year 2010 

Haynesville Shale Trend 17,295 1 17,300 $ 3.83 $ 64.00 $ 3.83 $ 0.15 

Cotton Valley Taylor Sand 2,386 24 2,529 4.38 62.17 4.72 0.16 

Eagle Ford Shale Trend 131 39 368 3.53 68.26 8.49 0.62 

Other 13,003 86 13,519 4.56 84.53 4.93 1.70 

Total 32,815 150 33,716 $ 4.16 $76.59 $ 4.39 $ 0.78 

(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, 2012. 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 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 

For Year 2010 

Bethany Longstreet 10,398 2 10,412 

Beckville 6,259 37 6,483 

Eagle Ford Shale Trend 131 39 368 

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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, 2012, 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, 2012 were as follows:

 2012

BP Energy Company 34% 

Flint Hill Resources, LLC 15% 

OGO Marketing LLC 5% 

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, 2013, we had 112 full-time employees in our two administrative offices and two field offices, none of whom is represented by any

labor union. 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 costs 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 solid wastes. While 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 as hazardous wastes and

therefore subject to more rigorous RCRA standards. Notwithstanding the continued effectiveness of this RCRA exclusion, these exploration, development and

production wastes remain subject to regulation by the EPA and state environmental agencies as non-hazardous “solid” 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 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.

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 published draft permitting guidance in May 2012 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 that would seek public input on the design and scope of such disclosure regulations. In addition, congress has from time to time considered

legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to

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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 first progress report outlining

work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic

fracturing on drinking water resources expected to be available for public comment and peer review by 2014. Moreover, the EPA has announced that it will

develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies,

including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic

fracturing. These ongoing or proposed 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 regulations. 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 emissionsrelated issues. For example, on August 16, 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 after

October 15, 2012. 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, effective October 15, 2012 and from pneumatic controllers and storage vessels, effective October 15, 2013. Compliance with these

requirements could increase our costs of development and production, which costs could be significant

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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 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. The EPA has 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.

While Congress has from time to time considered legislation to reduce emissions of GHGs 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. 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 more than 250 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.

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.

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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;

• 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;

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• 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, our

independent reserve engineers, and were calculated using the unweighted average of first-day-of-the-month oil and natural gas prices in 2012. These prices will

change and may be lower at the time of production than those prices that prevailed during 2012. 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 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.

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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, and any changes that 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 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

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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 final report

by 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic

fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated

or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed 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;

• 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.

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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. Realized prices for natural gas

decreased slightly in 2012 and are lower when compared with average prices in prior years. 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 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.

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, establishes federal oversight and regulation of the

over-the-counter derivatives market and entities, such as us,

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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. In its rulemaking under the Dodd-Frank Act, the CFTC issued a final rule on position limits for certain futures

and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions are

exempt from these position limits. The position-limits rule was vacated by the U.S. District Court for the District of Colombia in September 2012 and the

CFTC recently stated that it will appeal the District Court’s decision. The CFTC also finalized other regulations, including critical rulemakings on the

definition of “swap,” “swap dealer,” and “major swap participant.” Some regulations, however, remain to be finalized and it is not possible at this time to

predict when this will be accomplished. Depending on our classification and the particular nature of our derivative activities, the Dodd-Frank Act and

regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with certain derivative

activities. 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 Dodd-Frank Act and regulations could significantly increase the cost

of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), 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, and 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 91% (approximately 88% of natural gas production and approximately 100% of oil production) of our total

production volumes for the year ended December 31, 2012.

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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) 2012 2011 2010

Realized gain on oil and natural gas derivatives $ 73,160 $31,305 $ 24,590 

Unrealized gain (loss) on oil and natural gas derivatives (41,278) 3,234 30,706 

Total gain on oil and natural gas derivatives $ 31,882 $34,539 $55,296 

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 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 52% of our total estimated proved reserves by volume at December 31, 2012, 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.

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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 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, 2011 and

2010, we recorded impairments related to oil and natural gas properties of $47.8 million, $8.1 million and $234.9 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, 2012, and all our production during 2012 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.

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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 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, 2012, 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 July 1, 2014, which maturity is subject to automatic extension to

February 25, 2016, if, prior to maturity, we prepay or escrow certain proceeds sufficient to prepay our $218.5 million 5% Convertible Senior Notes due

2029. 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.

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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 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;

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

• encountering naturally occuring 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

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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.

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 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, 2013, the number of holders of record of our common stock was 1,268 and 36,759,232 shares outstanding. High and low closing

sales prices for our common stock for each quarter during 2012 and 2011 as reported on the NYSE were as follows:

 2012 2011

 High Low High Low

First Quarter

 $ 20.04 $ 14.06 $ 23.04 $18.17 

Second Quarter 19.49 12.29 22.47 17.54 

Third Quarter 15.12 10.86 20.73 11.82 

Fourth Quarter 13.68 7.95 17.52 10.77 

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, 2012. When an employee’s restricted stock shares vest, the

company (at the option of the employee) generally withholds an amount of shares necessary to cover that employees’ minimum payroll tax withholding

obligation. The company then remits the withholding amount to the appropriate tax authority and subsequently retires the shares. During 2012, we withheld

99,827 shares of common stock from issuance in this manner and paid $0.9 million to the appropriate tax authority as minimum withholding.

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

Owners and Management.”

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, 2007

and its relative performance is tracked through December 31, 2012.

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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

 2012 2011 2010 2009 2008

 (In thousands, except per share amounts)

Revenues: 

Oil and natural gas revenues $ 180,543 $ 200,456 $ 148,031 $ 110,784 $ 215,369 

Other 302 613 302 (358) 682 

 180,845 201,069 148,333 110,426 216,051 

Operating Expenses: 

Lease operating expense 25,938 21,490 26,306 30,188 31,950 

Production and other taxes 8,115 5,450 3,627 4,317 7,542 

Transportation and processing 13,900 12,974 9,856 9,459 8,645 

Depreciation, depletion and amortization 141,222 131,811 105,913 160,361 107,123 

Exploration 23,122 8,289 10,152 9,292 8,404 

Impairment 47,818 8,111 234,887 208,905 28,582 

General and administrative 28,930 29,799 30,918 27,923 24,254 

Loss (gain) on sale of assets (44,606) (236) 2,824 (297) (145,876) 

Other 91 448 4,268 — — 

 244,530 218,136 428,751 450,148 70,624 

Operating income (loss) (63,685) (17,067) (280,418) (339,722) 145,427 

Other income (expense): 

Interest expense (52,403) (49,351) (37,179) (26,148) (22,410) 

Interest income and other 4 5 9 117 458 1,682 

Gain on derivatives not designated as hedges 31,882 34,539 55,275 47,115 51,547 

Gain on early extinguishment of debt — 62 — — — 

 (20,517) (14,691) 18,213 21,425 30,819 

Income (loss) before income taxes (84,202) (31,758) (262,205) (318,297) 176,246 

Income tax (expense) benefit — — 85 67,311 (54,472) 

Net income (loss) (84,202) (31,758) (262,120) (250,986) 121,774 

Preferred stock dividends 6,047 6,047 6,047 6,047 6,047 

Net income (loss) applicable to common stock $ (90,249) $ (37,805) $(268,167) $ (257,033) $ 115,727 

PER COMMON SHARE 

Net income (loss) applicable to common stock—basic $ (2.48) $ (1.05) $ (7.47) $ (7.17) $ 3.42 

Net income (loss) applicable to common stock—diluted $ (2.48) $ (1.05) $ (7.47) $ (7.17) $ 3.23 

Weighted average common shares outstanding—basic 36,390 36,124 35,921 35,866 33,806 

Weighted average common shares outstanding—diluted 36,390 36,124 35,921 35,866 40,397 

Balance Sheet Data: 

Total assets $ 768,385 $ 862,103 $ 664,577 $ 860,274 $1,038,287 

Total long-term debt 568,671 566,126 179,171 330,147 226,723 

Stockholders’ equity 60,245 143,700 183,972 445,385 665,348 

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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.

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 on a cost-effective basis. We focus on maximizing our return on capital employed and

adding reserve value through the timely development of our Eagle Ford Shale Trend, Haynesville Shale, Cotton Valley Taylor Sand and Tuscaloosa Marine

Shale acreage. We regularly evaluate possible acquisitions of prospective acreage and oil and natural gas drilling opportunities.

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

• Develop existing property base. We seek to maximize the value of our existing assets by developing and exploiting our properties with the lowest

risk and the highest potential rate of return. We intend to develop our multi-year inventory of drilling locations on our acreage in the Eagle Ford

Shale Trend, Haynesville Shale, Cotton Valley Taylor Sands and Tuscaloosa Marine Shale in order to develop our oil and natural gas reserves.

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• Increase our oil production. During the past several years we have changed our strategy by concentrating on increasing our crude oil production

and reserves rather than natural gas by investing and drilling in the Eagle Ford Shale Trend and, more recently, Tuscaloosa Marine Shale. We

intend to take advantage of the current favorable sales price of oil compared to the relative sales price of natural gas, and continue to grow our oil

production as a percentage of total production.

• Expand acreage position in emerging shale plays. As of December 31, 2012, we have acquired approximately 135,000 net acres in the

Tuscaloosa Marine Shale Trend in Southeastern Louisiana and Southwestern Mississippi. We continue to concentrate our efforts in areas where we

can apply our technical expertise and where we have significant operational control or experience. To leverage our extensive regional knowledge base,

we seek to acquire leasehold acreage with significant drilling potential in areas that exhibit similar characteristics to our existing properties. We

continually strive to rationalize our portfolio of properties by selling marginal non-core properties in an effort to redeploy capital to exploitation,

development and exploration projects that offer a potentially higher overall return.

• Focus on maximizing cash flow margins. We intend to maximize operating cash flow by focusing on higher-margin oil development in the Eagle

Ford Shale Trend and the Tuscaloosa Marine Shale. In the current commodity price environment, our Eagle Ford Shale Trend and the Tuscaloosa

Marine Shale assets offer more attractive cash flow margins than our natural gas assets.

• Maintain financial flexibility. As of December 31, 2012, we had a borrowing base of $210 million under our $600 million Senior Credit Facility,

of which $95 million was outstanding. We have historically funded growth through cash flow from operations, 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

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.

2012 Overview

• We increased our annual oil production from 10% in 2011 to 21% of our equivalent production in 2012 and achieved average daily oil production

volume growth of 70% for the year, with production volumes growing from an average of 1,763 barrels of oil per day in 2011 to 2,992 barrels of

oil per day in 2012.

• We ended the year with estimated proved reserves of approximately 333.1 Bcfe (approximately 254.0 Bcf of natural gas, 5.1 MMBbls of NGL and

8.1 MMBbls of oil and condensate), with a PV-10 of $359.1 million and a standardized measure of $357.4 million, approximately 48% of which

is proved developed.

• We conducted drilling operations on 33 gross (22 net) wells in the Eagle Ford Shale Trend and added 26 gross (17 net) wells to production in 2012.

• We conducted drilling operations on six gross (three net) wells in the Haynesville Shale Trend. Two gross (0.5 net) wells were added to production

in 2012. As of December 31, 2012, we had 13 gross (six net) wells drilled but awaiting completion in the Haynesville Shale Trend.

• We conducted drilling operations on six gross (two net) wells, in the Tuscaloosa Marine Shale Trend and added two gross (0.5 net) wells to

production in 2012.

Eagle Ford Shale Trend

During 2012, we continued drilling operations on our acreage in the 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 hold approximately 53,500 gross (38,600 net) acres as of December 31, 2012, all

of which are either

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producing from or prospective for the Eagle Ford Shale Trend. During 2012, we conducted drilling operations on approximately 33 gross (22 net) Eagle Ford

Shale Trend wells. In 2013, we plan to spend approximately $115-137 million, representing approximately 58-78% of our 2013 capital budget, on 24-28

gross wells in the Eagle Ford Shale Trend.

Tuscaloosa Marine Shale Trend

We hold approximately 158,200 gross (134,200 net) acres in the Tuscaloosa Marine Shale Trend as of December 31, 2012. Our acreage is located in

East Feliciana, West Feliciana, St Helena, Concordia and Washington Parishes in Southeastern Louisiana and Wilkinson, Pike and Amite counties in

Southwestern Mississippi. Since December 31, 2011, we have added approximately 56,400 gross (54,000 net) acres in the trend. In December 2011, we

participated in our first non-operated drilling well in the Tuscaloosa Marine Shale. During 2012, we conducted drilling operations on approximately six gross

(two net) Tuscaloosa Marine Shale wells. One gross (0.8 net) drilling well resulted in a mechanical failure in which operations have been suspended.

On February 6, 2013, we announced results of our first operated well, the Crosby 12H-1 well in which we own a 50% working interest. The well had

an initial 24-hour production rate of approximately 1,130 BOE per day, comprised of 1,050 barrels of oil and 469 Mcf of gas per day. In 2013, we plan to

spend approximately $50 million, representing 28.5% of our 2013 capital budget, on six to ten gross wells in the Tuscaloosa Marine Shale Trend.

Haynesville Shale Trend

Our relatively low risk development drilling program 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 122,600 gross (78,900 net) acres as of December 31, 2012 producing

from or prospective for the Haynesville Shale. As of year-end 2012, we conducted drilling operations on a cumulative total of six gross (three net) wells in the

trend with a 100% success rate. Two gross (0.5 net) wells were added to production. Our net production volumes from our Haynesville Shale wells aggregated

approximately 42,000 Mcfe per day in 2012, or approximately 49% of our total oil and natural gas production for the year. Our 2013 capital expenditure

budget includes plans to conduct completion operations on 13 gross (six net) Haynesville Shale horizontal wells which were previously drilled.

Core Haynesville Shale

Our core Haynesville Shale drilling program is primarily concentrated in the Bethany-Longstreet and Greenwood-Waskom fields in Caddo and DeSoto

Parishes in Northwest Louisiana. Our core Haynesville Shale drilling activity includes both operated and non-operated drilling in and around our core acreage

positions in Northwest Louisiana. We currently hold approximately 32,000 gross (15,600 net) acres as of December 31, 2012. Our net production volumes

from our core Haynesville Shale wells totaled approximately 34,200 Mcfe per day in 2012, or approximately 40% of our total production for the year. In 2013,

we estimate that we will spend approximately $18 million of completion costs associated with previously drilled wells in our core Haynesville Shale area.

Shelby Trough / Angelina River Trend

During the second half of 2010, we spud our first Haynesville and Bossier Shale wells in the Shelby Trough/Angelina River Trend area. We operate all

of our drilling activities in this area, which is primarily located in Nacogdoches, Angelina and Shelby counties, Texas. We currently hold approximately

39,200 gross (28,300 net) acres as of December 31, 2012. Our net production volumes from our Shelby Trough wells totaled approximately 4,300 Mcfe per

day in 2012, or approximately 5% of our total production for the year. In 2013, we estimate that we will spend approximately $4 million on completion costs

associated with a previously drilled well in the Shelby Trough/Angelina River Trend area.

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Results of Operations

For the year ended December 31, 2012, we reported net loss applicable to common stock of $90.2 million, or $2.48 per share (basic and diluted), on

operating revenues of $180.8 million. This compares to 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 and net loss applicable to common stock of $268.2 million, or $7.47 per share (basic and diluted), for the year ended

December 31, 2010.

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,

2012 2011 Variance 2011 2010 Variance

Revenues:

Natural gas $ 71,136 $141,665 $(70,529) (50%) $141,665 $ 136,527 $ 5,138 4% 

Oil and condensate 109,407 58,791 50,616 86% 58,791 11,504 47,287 411% 

Natural gas, oil and condensate 180,543 200,456 (19,913) (10%) 200,456 148,031 52,425 35% 

Operating revenues 180,845 201,069 (20,224) 10% 201,069 148,333 52,736 36% 

Operating expenses 244,530 218,136 26,394 12% 218,136 428,751 (210,615) (49%) 

Operating loss (63,685) (17,067) (46,618) (273%) (17,067) (280,418) 263,351 94% 

Net loss applicable to common stock (90,249) (37,805) (52,444) (139%) (37,805) (268,167) 230,362 86% 

Net Production:

Natural gas (Mmcf) 24,844 36,167 (11,323) (31%) 36,167 32,815 3,352 10% 

Oil and condensate (MBbls) 1,095 644 451 70% 644 150 494 329% 

Total (Mmcfe) 31,415 40,029 (8,614) (22%) 40,029 33,716 6,313 19% 

Average daily production (Mcfe/d) 85,832 109,669 (23,837) (22%) 109,669 92,373 17,296 19% 

Average Realized Sales Price Per Unit:

Natural gas (per Mcf) $ 2.86 $ 3.92 $ (1.06) (27%) $ 3.92 $ 4.16 $ (0.24) (6%) 

Natural gas (per Mcf) including the effect of

realized gains/losses on derivatives 5.50 4.70 0.80 17% 4.70 4.91 (0.21) (4%) 

Oil and condensate (per Bbl) 99.91 91.34 8.57 9% 91.34 76.59 14.75 19% 

Oil and condensate (per Bbl) including the effect of

realized gains/losses on derivatives 106.98 96.23 10.75 11% 96.23 76.59 19.64 26% 

Average realized price (per Mcfe) 5.75 5.01 0.74 15% 5.01 4.39 0.62 14% 

Oil and Natural Gas Revenue

Our oil and natural gas revenues decreased in 2012 compared to 2011 reflecting a decrease in production, partially offset by a net increase in average

realized sales price. 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 continued to focus 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. In response to depressed natural gas prices, we will continue to focus our resources on increasing oil production, which we are currently able to

sell at a more favorable relative price. During 2012, 61% of our oil and natural gas revenue was attributable to oil revenue compared to 29% in 2011.

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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.

Our oil and natural gas revenues increased in 2011 compared to 2010. The increase in average realized sales price compared to 2010 contributed

approximately $20.8 million to the increase in oil and natural gas revenue while the net production increase compared to 2010 contributed approximately $31.6

million to the increase in oil and natural gas revenue. Our average realized sales price was $5.01 per Mcfe in 2011 compared to $4.39 per Mcfe in 2010. Sales

prices are dictated by the market. We increased production by the continued development of our Haynesville Shale and Eagle Ford Shale Trend assets. The

drilling and completion of 28 wells in Northwest Louisiana and East Texas, 20 of which were in the Haynesville Shale, resulted in the continued trend of

annual natural gas production growth for us. The drilling of 20 South Texas wells, all of which were in the Eagle Ford Shale Trend, increased our oil

production.

The difference between our average realized prices inclusive of the hedge realizations in the year ended December 31, 2011 and 2010 periods relates to our

natural gas collars and basis swap contracts. During 2011, we had 40,000 MMBtus per day hedged at a floor price of $6.00 per MMBtu and during 2010 we

had 50,000 MMBtus per day hedged at a floor price of $6.00 per MMBtu and 50,000 MMBtus per day hedged in our basis swaps. During 2011, we had

2,500 Bbls per day hedged at an average fixed price of $100.20 per Bbl and we did not have any oil hedges during 2010.

Operating Expenses

Our operating expenses in 2012 include 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. 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 is driven by

increased depreciation, depletion and amortization (“DD&A”) expense.

Our operating expenses in 2011 include an $8.1 million asset impairment, other expense of $0.4 million and a gain on the sale of assets of $0.2 million.

Eliminating these items from the operating expenses in both 2011 and 2010, the adjusted operating expense of $209.8 million in 2011 increased 12%, or $23.8

million, from adjusted operating expense of $186.8 million in 2010. This increase in operating expenses is driven by increased DD&A expense.

 Year Ended December 31, Year Ended December 31,

(in thousands) 2012 2011 Variance 2011 2010 Variance

Lease operating expenses $25,938 $21,490 $ 4,448 21% $21,490 $26,306 $(4,816) (18%) 

Production and other taxes 8,115 5,450 2,665 49% 5,450 3,627 1,823 50% 

Transportation and processing 13,900 12,974 926 7% 12,974 9,856 3,118 32% 

Exploration 23,122 8,289 14,833 179% 8,289 10,152 (1,863) (18%) 

 Year Ended December 31, Year Ended December 31,

Per Mcfe 2012 2011 Variance 2011 2010 Variance

Lease operating expenses $ 0.83 $ 0.54 $ 0.29 54% $ 0.54 $ 0.78 $ (0.24) (31%) 

Production and other taxes 0.26 0.14 0.12 86% 0.14 0.11 0.03 27% 

Transportation and processing 0.44 0.32 0.12 38% 0.32 0.29 0.03 10% 

Exploration 0.74 0.21 0.53 252% 0.21 0.30 (0.09) (30%) 

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Lease Operating Expense

Our lease operating expense (“LOE”) during 2012 included an expense of $4.3 million in workover costs which added $0.13 per Mcfe to unit expense.

Our LOE is trending higher as we add more oil wells to our well count which carry higher operating costs than natural gas wells. Oil contributed 21% to our

production volumes in 2012 compared to only 10% in 2011.

Our LOE for the year 2011 decreased overall and on a per unit basis from 2010. The overall cost decrease is a result of our sale in December 2010 of

certain of our high cost non-core natural gas properties and a greater percentage of our production volumes coming from our Haynesville Shale wells which

carry a lower LOE per unit of production. On a per unit basis, LOE decreased for the year 2011 compared to the year 2010 as a result of cost reductions, an

increase in production volumes and an increasing portion of our production coming from the lower production cost Haynesville Shale wells.

Production and Other Taxes

Our 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 Tight Gas Sands (“TGS”) credits for our wells in the State of Texas. 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 $1.4 million of tax credits attributed to TGS

credits for our wells in the State of Texas. The higher production tax for 2012 compared to 2011 is attributable to the increasing portion of our production

coming from the 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.

Our ad valorem taxes increased $0.9 million to $2.5 million in 2012 from $1.6 million in 2011. Ad valorem tax is assessed on the value of properties

as of the first day of the year and is highly influenced by commodity prices for the prior several months. The increase is attributed to the assessment of our

new Eagle Ford Shale oil wells.

Our 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 $1.4 million of tax credits attributed to TGS credits for our wells in the State of Texas. During the year 2010, production and other taxes included

production tax of $1.1 million and ad valorem tax of $2.5 million. Production tax in 2010 is net of $1.6 million of tax credits attributed to TGS credits for

our wells in the State of Texas and $0.4 million severance tax relief related to the horizontal wells we have drilled in the State of Louisiana. The higher

production tax for 2011 compared to 2010 is attributable to the increasing portion of our production coming from the Eagle Ford Shale oil wells which are not

exempt from Texas severance tax.

Our ad valorem taxes decreased $0.9 million to $1.6 million in 2011 from $2.5 million in 2010. Ad valorem tax is assessed on the value of properties

as of the first day of the year and is highly influenced by commodity prices for the prior several months. The number of properties we owned decreased from

January 1, 2010 to January 1, 2011 and the assessed values for our properties were lower year-to-year driven by decreased commodity prices.

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Transportation and Processing

Our transportation and processing expense increased in 2012 compared to 2011. The increase in expense is 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. In return for paying higher gathering and processing fees, as compared to gas production from our Haynesville Shale wells, we are

receiving higher pricing due to the existence of natural gas liquids in our natural gas thereby increasing our revenues.

Our transportation and processing expense increased in 2011 compared to 2010. The increase in expense is primarily a result of higher transportation

costs related to our new natural gas production from the Eagle Ford Shale Trend wells offset by the cost savings from the sale of non-core properties in

December 2010.

Exploration

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 Tuscaloosa Marine Shale acreage. Drilling operations on the well have been suspended due to mechanical failure. Exploration expense

for 2012 also includes $5.9 million of amortization of leasehold costs.

The decrease in exploration expenses in 2011 compared to 2010 is attributable primarily to a $0.8 million decrease in exploration labor costs and a $0.6

million decrease in seismic costs. Exploration expense for 2011 includes $5.5 million of amortization of leasehold costs.

Year Ended December 31, Year Ended December 31,

(in thousands) 2012 2011 Variance 2011 2010 Variance

Depreciation, depletion & amortization $141,222 $131,811 $ 9,411 7% $131,811 $105,913 $ 25,898 24% 

Impairment 47,818 8,111 39,707 490% 8,111 234,887 (226,776) (97%) 

General & administrative 28,930 29,799 (869) (3%) 29,799 30,918 (1,119) (4%) 

Loss (gain) on sale of assets (44,606) (236) (44,370) NM (236) 2,824 (3,060) (108%) 

Other 91 448 (357) (80%) 448 4,268 (3,820) (90%) 

Year Ended December 31, Year Ended December 31,

Per Mcfe 2012 2011 Variance 2011 2010 Variance

Depreciation, depletion & amortization $ 4.50 $ 3.29 $ 1.21 37% $ 3.29 $ 3.14 $ 0.15 5% 

Impairment 1.52 0.20 1.32 660% 0.20 6.97 (6.77) (97%) 

General & administrative 0.92 0.74 0.18 24% 0.74 0.92 (0.18) (20%) 

Loss (gain) on sale of assets (1.42) (0.01) (1.41) NM (0.01) 0.08 (0.09) (113%) 

Other — 0.01 (0.01) (100%) 0.01 0.13 (0.12) (92%) 

NM—Not meaningful.

Depreciation, Depletion & Amortization

Our DD&A expense increased in 2012 from 2011 as a result of higher production and more production coming from operating areas with higher DD&A

rates, such as our Eagle Ford Shale Trend oil properties. The average DD&A rate increased 37% while production decreased 22% year-to-year.

We calculated the first six months of 2012 DD&A rates using the December 31, 2011 reserves prepared by NSAI. Proved developed reserves increased

9% from 191.9 Bcfe at December 31, 2010 to 208.5 Bcfe at December 31, 2011. We calculated the last six months of 2012 DD&A rates using the June 30,

2012 mid-year reserves prepared by internal reserve engineers. Proved developed reserves at June 30, 2012 were 191.9 Bcfe, an 8% decrease from the reserves

at December 31, 2011.

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Our DD&A expense increased in 2011 from 2010 as a result of higher production and more production coming from operating areas with higher DD&A

rates, such as our Eagle Ford Shale Trend oil properties. The average DD&A rate increased 5% while production increased 19% year-to-year.

We calculated the first six months of 2011 DD&A rates using the December 31, 2010 reserves prepared by NSAI. Proved developed reserves increased

16% from 165.5 Bcfe at December 31, 2009 to 191.9 Bcfe at December 31, 2010. We calculated the last six months of 2011 DD&A rates using the June 30,

2011 mid-year reserves prepared by internal reserve engineers. Proved developed reserves at June 30, 2011 were 216.8 Bcfe, a 13% increase over the reserves at

December 31, 2010.

While our internal, mid-year reserve reports were prepared in accordance with existing SEC guidelines, they should not be construed as a fully

independent reserve report.

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. If natural gas prices decline further we expect to have further impairments.

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

field due to falling natural gas prices.

We recorded impairment expense of $234.9 million on several fields for the year ended December 31, 2010, related primarily to a decreasing projected

natural gas price environment resulting in the write down of the carrying values of certain non-core assets. In addition to lower commodity prices, the

impairment was a result of our change in forward looking development plans, which will focus on the Eagle Ford Shale Trend, core Haynesville Shale in

Northwest Louisiana and the Angelina River Trend of the Shelby Trough.

General and Administrative Expense

Our general and administrative (“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 key personnel. 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. G&A on a per unit basis increased to $0.92 per Mcfe from $0.74 per

Mcfe as a result of the 22% decrease in production volume in 2012 compared to 2011.

Our G&A expense decreased in 2011 compared to 2010. The decrease relates primarily to the partial refund and final settlement of a Louisiana franchise

tax payment made under protest in 2007, decreases in stock based compensation and consulting cost. Share based compensation expense, which is a non-cash

item, amounted to $6.5 million in 2011 compared to $7.6 million in 2010. G&A on a per unit basis decreased to $0.74 per Mcfe from $0.92 per Mcfe as a

result of the 19% increase in production volume in 2011 compared to 2010.

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.

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We recorded a gain of $0.2 million on the sale on non-core oil and natural gas properties in the year ended December 31, 2011 and a loss of $2.8 million

on the sale of assets in the year ended December, 31, 2010.

Other

We recorded a $4.3 million expense in 2010 related to a lawsuit concerning additional oil and natural gas bonus payments. In 2011, a money judgment

of $4.4 million, including interest, was paid to the opposing party in the lawsuit consequently another $0.1 million was recorded in 2011 as a result of the

settlement. We accrued an additional $0.3 million in 2011 representing potential settlements on two other minor litigation actions for a total of $0.4 million as of

December 31, 2011.

A discussion of these legal proceedings is set forth in Note 9—“Commitment and Contingencies” in the Notes to the Consolidated Financial

Statements in Part II Item 8 of this Annual Report on Form 10-K .

Other Income (Expense)

 Year Ended December 31,

 2012 2011 2010

 (In thousands)

Other Income (Expense): 

Interest expense $ (52,403) $ (49,351) $ (37,179) 

Interest income and other 4 5 9 117 

Gain on derivatives not designated as hedges 31,882 34,539 55,275 

Gain on extinguishment of debt — 62 — 

Income tax benefit (expense) — — 85 

Average funded borrowings adjusted for debt discount 606,801 508,323 379,582 

Average funded borrowings 631,129 543,688 400,405 

Interest Expense

Our interest expense increased in 2012 compared to 2011 as a result of the higher average level of outstanding debt in the current year. 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.

Our interest expense increased in 2011 compared to 2010 as a result of the higher average level of outstanding debt in 2011. The higher average level of

debt resulted from the issuance of our $275 million 8.875% Senior Notes due 2019 (the “2019 Notes”). Non-cash interest of $14.4 million is included in the

interest expense reported in 2011.

Interest Income and Other

We invested the proceeds from the 5% convertible senior note offering in September 2009 in money market funds and time deposits with certain

acceptable institutions, subject to our Short Term Investment Policy. We used the invested proceeds throughout 2010 and 2009 to fund our capital program.

The income earned on these investments during 2011 and 2010 is reflected in the Interest income line.

Gain on Derivatives Not Designated as Hedges

We produce and sell oil and natural gas into a market where selling prices are historically volatile. For example, on November 7, 2012 the Henry Hub

natural gas spot price reached a high of $3.77 per MMBtu, but the price was down to $1.82 per MMBtu at April 20, 2012. 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.

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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.

Gain on derivatives not designated as hedges was $55.3 million for 2010. The gain includes a realized gain of $24.6 million on our natural gas

derivatives and an unrealized gain of $30.7 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, 2009 as compared to December 31, 2010.

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 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 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,

2012.

We recorded a small tax benefit of less than $0.1 million in 2010, which reflects the monetization of our alternative minimum tax credit. We recorded no

income tax benefit for 2010.

Adjusted EBITDAX (1)

 Year Ended December 31,

 2012 2011 2010

 (In thousands)

Net Income (GAAP) $ (84,202) $ (31,758) $(262,120) 

Exploration Expense 23,122 8,289 10,152 

Depreciation, depletion and amortization 141,222 131,811 105,913 

Impairment 47,818 8,111 234,887 

Stock compensation expense 6,903 6,495 7,554 

Interest expense 52,403 49,351 37,179 

Unrealized (gain)/loss on derivatives not designated as hedges 41,278 (3,234) (31,794) 

Other items (2) (44,519) 91 6,890 

Adjusted EBITDAX $184,025 $169,156 $ 108,661 

(1) Adjusted EBITDAX is earnings before interest expense, income tax, DD&A, exploration expense and impairment of oil and gas properties. In

calculating EBITDAX for this purpose, earnings include realized gains (losses) from derivatives but exclude unrealized gains (losses) from derivatives.

Other excluded items include Interest income and other, Gain on sale of assets, Gain on early extinguishment of debt and other expense. As defined in our

Senior Credit Facility.

(2) Other items include interest income and other, (gain) loss on sale of assets, gain on extinguishment of debt, income taxes and other expense.

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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

Outlook

Our total capital expenditures for 2013 are expected to be between $175 million and $200 million, exclusive of acquisitions other than lease acreage

additions in our core areas. We plan on spending between $160 million and $175 million on drilling and completion cost and $15 million on leasehold and

infrastructure costs. We will concentrate on developing our oil assets in 2013 by allocating approximately 85% of our drilling and completion budget to oil

directed activity. Oil directed activity will be concentrated in the Eagle Ford Shale and the Tuscaloosa Marine Shale trends. We plan on spending $22 million

in 2013 on gas directed activity in the completion of 13 gross (6 net) Haynesville Shale wells that have been previously drilled. Our primary emphasis will be

on managing near-term growth opportunities. We believe that our expected level of operating cash flows, cash on hand as of December 31, 2012, and our

borrowing base will be sufficient to fund our projected operational and capital programs for 2013. However, if capital expenditures exceed operating cash flow

and cash on hand, funds would likely be supplemented as needed through short-term borrowings under senior credit facility or through the issuance of debt or

equity.

As we continue to increase our oil production in 2013, we expect that our overall operating expenses will increase as a result of the higher DD&A rates

associated with oil wells compared to our natural gas wells.

In addition, to support 2013 cash flows, we entered into strategic derivative positions as of December 31, 2012, covering approximately 75% of our

anticipated oil and condensate sales volumes for 2013. 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 Tuscaloosa Marine Shale, Eagle Ford Shale Trend, and/or core Haynesville Shale acreage;

• availability under our Senior Credit Facility; and

• issuance of debt or equity securities.

Our next borrowing base redetermination is currently scheduled for April 2013. At December 31, 2012, our borrowing base under our Senior Credit

Facility is $210 million with $95 million outstanding. 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, 2012.

On January 22, 2013 we filed a universal shelf registration statement that, once declared effective by the SEC, will provide us with the ability to make

registered offerings of various equity or debt securities to the public of up to an aggregate amount of $500 million. We anticipate conducting a public offering

before our $218.5 million 5% senior convertible notes due 2029 become putable on October 1, 2014, however, we can make no assurances that we would be

able to access the capital market on terms that are acceptable to us. Any amounts outstanding on the 2029 notes will be characterized as a current liability in

the fourth quarter of 2013. Similarly, if the 2029 notes are not redeemed prior to June 30, 2013, any amount outstanding under the Senior Credit facility with a

maturity date of July 1, 2014 will be characterized as a current liability in the third quarter of 2013.

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Overview

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. We primarily used cash to fund our capital spending program, pay down debt, 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, available borrowings under

our Senior Credit Facility and our issuance in March 2011 of $275 million of our 2019 Notes. We primarily used cash to fund our capital spending

program, retire debt and pay preferred stock dividends. Our primary sources of cash during 2010 were from cash on hand, cash flow from operating

activities and proceeds from divestitures. In 2010, we primarily used cash to fund our capital spending program, 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, 2012, we

had a $210 million borrowing base with $95 million outstanding. On February 25, 2011, we entered into a Fourth Amendment to the Senior Credit Facility.

The Fourth Amendment became effective upon the closing of the issuance and sale of our 2019 Notes, which occurred on March 2, 2011, and the placement

of $175 million of net proceeds in an escrow account which was used for the redemption of $174.6 million of our $3.25% Convertible Senior Notes due

2026 (the “2026 Notes”). We were in compliance with existing covenants, as amended, at December 31, 2012. The Senior Credit Facility matures on July 1,

2014 subject to automatic extension to February 25, 2016, if, prior to maturity, we prepay or escrow certain proceeds sufficient to prepay our $218.5 million

5% Convertible Senior Notes due 2029 (the “2029 Notes”).

The following section discusses significant sources and uses of cash for the three-year period ending December 31, 2012. Forward-looking information

related to our liquidity and capital resources are discussed in Outlook that follows.

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 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 our issuance of the 2019 Notes.

Primary sources of cash during 2010 were cash flow from operating activities and the sale of assets.

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The table below summarizes the sources of cash during 2012, 2011 and 2010:

Year Ended December 31, Year Ended December 31,

Cash flow statement information: 2012 2011 Variance 2011 2010 Variance

(In thousands)

Net Cash:

Provided by operating activities $ 173,789 $ 136,340 $ 37,449 $ 136,340 $ 100,432 $ 35,908 

Used in investing activities (161,494) (335,064) 173,570 (335,064) (200,080) (134,984) 

Provided by (used) financing activities (14,454) 184,283 (198,737) 184,283 (7,680) 191,963 

Increase (decrease) in cash and cash equivalents $ (2,159) $ (14,441) $ 12,282 $ (14,441) $(107,328) $ 92,887 

At December 31, 2012, we had a working capital deficit of $79.3 million and long-term debt, net of debt discount, of $568.7 million.

Cash Flows

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 $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.

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Year ended December 31, 2011 Compared to Year Ended December 31, 2010

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 $35.9 million in 2011. Cash

received related to oil and natural gas revenue increased $47.2 million year over year with (i) a 19% increase in total production, (ii) growth in oil volumes as a

percentage of total volumes from 3% in 2010 to 10% in 2011, and (iii) a 14% increase in the average realized sales price from $4.39 to $5.01 per Mcfe.

Operating costs savings of $7.9 million in 2011 as compared to 2010 and $7.9 million in additional realized cash settlements on our derivative contracts were

also additive to cash flow from operations. Offsetting decreases to cash flow in 2011 include (i) $17.2 million in additional cash interest paid in 2011 as we

replaced $175 million of our 3.25% Convertible Senior Notes due 2026 with $275 million of our 8.875% 2019 Notes and (ii) $9.9 million in working

capital changes.

Net cash used in investing activities was $335.1 million for the year ended December 31, 2011, compared to $200.1 million for 2010. While we booked

capital expenditures of approximately $330.2 million in 2011, we paid out cash amounts totaling $335.2 million in 2011, with the difference being attributed

to approximately $22.3 million in drilling and completion costs which were accrued at December 31, 2011, non-cash asset retirement obligation additions of

$2.1 million and geophysical and geological cost of $0.6 million offset by $30.0 million in drilling and completion cost accrued at December 31, 2010 and

paid in 2011. Net cash used in investing activities was offset by the receipt of $0.2 million of cash proceeds from the sale of fixed assets in 2011.

We drilled 47 gross wells in 2011 compared to 46 gross wells in 2010. 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. Of the $265.0 million cash spent in 2010,

approximately $227.6 million was for drilling and completion activities (of which $13.8 million related to 2009 wells); $33.7 million was for leasehold

acquisition, $0.6 million for facilities and infrastructure, $2.3 million for capital workovers, and $0.8 million for furniture, fixtures and equipment.

Financing activities. The net cash provided by financing activities for 2011 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, partially offset by the redemption of a portion of our 2026 Notes totaling

$176.4 million, financing cost on the issuance of the 2019 Notes of $9.3 million and preferred stock dividends of $6.0 million. We had $102.5 million

borrowings outstanding under our Senior Credit Facility as of December 31, 2011. In 2010 we had no issuances of debt or equity and the cash used in

financing activities was primarily the dividend paid on preferred stock.

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

December 31, 2012 December 31, 2011

Principal

Carrying

Amount

Fair

Value (1) Principal

Carrying

Amount

Fair

Value (1)

Senior Credit Facility $ 95,000 $ 95,000 $ 95,000 $ 102,500 $ 102,500 $ 102,500 

3.25% Convertible Senior Notes due 2026 429 429 429 429 429 429 

5.0% Convertible Senior Notes due 2029 (2) 218,500 198,242 204,975 218,500 188,197 201,785 

8.875% Senior Notes due 2019 275,000 275,000 261,250 275,000 275,000 243,898 

Total debt $588,929 $568,671 $561,654 $596,429 $566,126 $548,612 

(1) The carrying amount for the Senior Credit Facility represents fair value because the variable interest rates are reflective of current market conditions and

the carrying amount of the 3.25% Convertible Senior Notes due 2026 represents fair value because the last transacted activity was at par; otherwise, fair

value was obtained by direct market quotes within Level 1 of the fair value hierarchy.

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(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 $20.3 million and $30.3 million as of December 31, 2012 and December 31, 2011, respectively.

The following table summarizes the total interest expense (contractual interest expense, amortization of debt discount and financing costs) and the

effective interest rate on the liability component of the debt (amounts in thousands, except effective interest rates):

 December 31, 2012 December 31, 2011 December 31, 2010

 

Interest

Expense 

Effective

Interest

Rate

Interest

Expense 

Effective

Interest

Rate

Interest

Expense 

Effective

Interest

Rate

Senior Credit Facility 5,114 3.7% 3,180 —* 2,611 —* 

3.25% Convertible Senior Notes due 2026 14 3.3% 4,305 9.0% 14,537 9.0% 

5.0% Convertible Senior Notes due 2029 21,968 11.4% 20,948 10.5% 20,031 11.2% 

8.875% Senior Notes due 2019 25,308 9.2% 20,910 8.9% — — 

* An Effective Interest Rate Calculation is not meaningful for the December 31, 2011 and 2010 since there were only minimal average amounts borrowed

under the Senior Credit Facility during those periods.

Total lender commitments under the Senior Credit Facility are $600 million subject to borrowing base limitations as of December 31, 2012 of $210

million. The Senior Credit Facility matures on July 1, 2014 (subject to automatic extension to February 25, 2016, if, prior to maturity, we prepay or escrow

certain proceeds sufficient to prepay our $218.5 million 2029 Notes). Revolving borrowings under the Senior Credit Facility are limited to, and subject to,

periodic redeterminations of the borrowing base. Interest on revolving borrowings under the Senior Credit Facility accrues at a rate calculated, at our option, at

the bank base rate plus 1.00% to 1.75%, or LIBOR plus 2.00% to 2.75%, depending on borrowing base utilization. Pursuant to the terms of the Senior Credit

Facility, borrowing base redeterminations occur on a semi-annual basis on April 1 and October 1. As of December 31, 2012, we had $95 million outstanding

under the Senior Credit Facility. Substantially all our assets are pledged as collateral to secure the Senior Credit Facility. Availability under the Senior Credit

Facility as of December 31, 2012 was $115 million.

The terms of the Senior Credit Facility require us to maintain certain covenants. Capitalized terms used herein, but not defined, have the meanings

assigned to them in the Senior Credit Facility. In February 2012, we entered into a Sixth Amendment to the Senior Credit Facility which amended the

EBITDAX annualized calculation and increased the borrowing base to $210 million. The primary financial covenants include:

• Current Ratio of 1.0/1.0; 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 assets related to our derivatives, accrued capital expenditures and current maturities under the Senior Credit Facility);

• Interest Coverage Ratio of EBITDAX 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 defined in the Senior Credit Facility EBITDAX is earnings before interest expense, income tax, DD&A, 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, 2012.

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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 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 5% convertible senior notes due in October 2029 (the “2029 Notes”). The notes mature on October 1,

2029, unless earlier converted, redeemed or repurchased. The notes are senior unsecured obligations and rank equally in right of payment to all of our other

existing and future indebtedness. The notes accrue interest at a rate of 5% annually, and interest is paid semi-annually in arrears on April 1 and October 1 of

each year, beginning in 2010.

Before October 1, 2014, we may not redeem the notes. 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. 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 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) commencing after December 31, 2009, if the last

reported sale price of our common stock is greater than or equal to 135% of the conversion price of the notes (as defined in this prospectus supplement) 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 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 notes have been called for redemption; or (4) upon the occurrence of one of the specified corporate transactions

described in this prospectus supplement. Investors may also convert their 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 notes are convertible into shares of our common stock at a rate equal to 28.8534 shares per $1,000 principal amount of 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 5% convertible senior notes due 2029 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

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convertible debt instruments that may be settled in cash upon conversion, we recorded a debt discount of $49.4 million, thereby reducing the carrying the

value of $218.5 million notes on the December 31, 2009 balance sheet to $171.1 million and recorded an equity component net of tax of $32.1 million. The

debt discount is amortized using the effective interest rate method based upon an original five year term through October 1, 2014. At December 31, 2012,

$20.3 million debt discount remains to be amortized on the 2029 notes.

3.25% Convertible Senior Notes Due 2026

During the year ended December 31, 2011, we repurchased $174.6 million of our 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, 2012, $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

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.

Preferred Stock

Our Series B Convertible Preferred Stock (the “Series B Convertible 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 Convertible 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 Convertible 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.

For additional information on our debt instruments, see Note 7—“Stockholder’s 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 nonperformance 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, 2012 (in

thousands). In addition to the contractual obligations presented in the table below, our Consolidated Balance Sheet at December 31, 2012 reflects accrued

interest on our bank debt of $10 million payable in the first half of 2013. For additional information see Note 4—“Long-Term Debt” and Note

10—“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

 Note Total 2013 2014 2015 2016 

2017

and After

Contractual Obligations 

Long term debt (1) 4 $493,929 $ — $218,500 $ — $275,429 $ — 

Interest on notes 4 97,477 35,345 32,614 24,420 5,098 — 

Office space leases 9 7,220 1,202 1,104 983 1,020 2,911 

Office equipment leases 9 706 357 253 9 6 — — 

Drilling rigs & operations contracts 9 12,126 11,825 230 6 5 6 — 

Transportation contracts 9 7,269 1,809 1,092 1,092 1,092 2,184 

Total contractual obligations (2) $618,727 $50,538 $253,793 $26,656 $282,645 $5,095 

(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

$218.5 million 5.0% convertible senior 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 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 $18.3

million. We record a separate liability for the fair value of this asset retirement obligation. See Note 3—“Asset Retirement Obligation” 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 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

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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, 2012 included in this report have been prepared based on what we and our independent

reserve engineers believe to be reasonable interpretations of the new 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.

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

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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 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.

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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 and Interest Expense” 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 noncash 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 2013 of approximately 3,500 MBbls per day of crude oil

as of December 31, 2012. At December 31, 2012, we had a net liability derivative position of $2.2 million related to these derivative instruments. Utilizing

actual derivative contractual volumes, a 10% increase in underlying commodity prices would have reduced the fair value of these instruments by

approximately $15.1 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by

approximately $14.0 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, 2012, we had $95 million outstanding variable-rate debt and $473.7 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, 2012, we have 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 5 5 

Report of Independent Registered Public Accounting Firm—Internal Controls over Financial Reporting 5 6 

Report of Independent Registered Public Accounting Firm—Consolidated Financial Statements for the years ended December 31, 2012, 2011 and

2010 57 

Consolidated Balance Sheets as of December 31, 2012 and 2011 58 

Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010 5 9 

Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010 60 

Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2012, 2011 and 2010. 61 

Notes to the Consolidated Financial Statements 62 

5 5
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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 (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, 2012. The effectiveness of our

internal control over financial reporting as of December 31, 2012 has been audited by Ernst & Young LLP, an independent registered public accounting firm,

as stated in their report which is included on page 57.

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, 2012, based on criteria

established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (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, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2012 consolidated

financial statements of Goodrich Petroleum Corporation and subsidiary and our report dated February 22, 2013, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 22, 2013

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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, 2012 and 2011,

and the related consolidated statements of operations, cash flows, and stockholders’ equity, for each of the three years in the period ended December 31, 2012.

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, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three years in

the period ended December 31, 2012, 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, 2012, based on criteria established in Internal Control-Integrated Framework issued

by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2013 expressed an unqualified opinion

thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 22, 2013

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In Thousands)

 December 31,

 2012 2011

ASSETS 

CURRENT ASSETS: 

Cash and cash equivalents $ 1,188 $ 3,347 

Accounts receivable, trade and other, net of allowance 7,078 7,934 

Accrued oil and natural gas revenue 19,054 20,420 

Fair value of oil and natural gas derivatives 2,125 56,486 

Inventory 2,202 8,627 

Prepaid expenses and other 926 4,315 

Total current assets 32,573 101,129 

PROPERTY AND EQUIPMENT: 

Oil and natural gas properties (successful efforts method) 1,619,914 1,542,406 

Furniture, fixtures and equipment 6,212 5,654 

 1,626,126 1,548,060 

Less: Accumulated depletion, depreciation and amortization (906,377) (824,894) 

Net property and equipment 719,749 723,166 

Deferred tax assets 636 19,720 

Deferred financing cost and other 15,427 18,088 

TOTAL ASSETS $ 768,385 $ 862,103 

LIABILITIES AND STOCKHOLDERS’ EQUITY 

CURRENT LIABILITIES: 

Accounts payable $ 73,094 $ 46,095 

Accrued liabilities 37,634 43,874 

Accrued abandonment costs 168 5,176 

Deferred tax liabilities current 636 19,720 

Fair value of oil and natural gas derivatives 351 — 

Total current liabilities 111,883 114,865 

Long term debt 568,671 566,126 

Accrued abandonment costs 18,138 12,249 

Fair value of oil and natural gas derivatives 3,987 17,420 

Transportation obligation 5,461 7,743 

Total liabilities 708,140 718,403 

Commitments and contingencies (See Note 9) 

STOCKHOLDERS’ EQUITY: 

Preferred stock: 10,000,000 shares authorized: 

Series B convertible preferred stock, $1.00 par value, issued and outstanding 2,250,000 2,250 2,250 

Common stock: $0.20 par value, 100,000,000 shares authorized, issued and outstanding 36,758,141 and

36,378,508 shares, respectively 7,352 7,276 

Treasury stock (77,142 and 44,826 shares, respectively) (639) (689) 

Additional paid in capital 648,458 641,790 

Retained earnings (accumulated deficit) (597,176) (506,927) 

Total stockholders’ equity 60,245 143,700 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY $ 768,385 $ 862,103 

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,

 2012 2011 2010

REVENUES: 

Oil and natural gas revenues $180,543 $200,456 $ 148,031 

Other 302 613 302 

 180,845 201,069 148,333 

OPERATING EXPENSES: 

Lease operating expense 25,938 21,490 26,306 

Production and other taxes 8,115 5,450 3,627 

Transportation and processing 13,900 12,974 9,856 

Depreciation, depletion and amortization 141,222 131,811 105,913 

Exploration 23,122 8,289 10,152 

Impairment 47,818 8,111 234,887 

General and administrative 28,930 29,799 30,918 

(Gain) loss on sale of assets (44,606) (236) 2,824 

Other 91 448 4,268 

 244,530 218,136 428,751 

Operating loss (63,685) (17,067) (280,418) 

OTHER INCOME (EXPENSE): 

Interest expense (52,403) (49,351) (37,179) 

Interest income and other 4 5 9 117 

Gain on derivatives not designated as hedges 31,882 34,539 55,275 

Gain on extinguishment of debt — 62 — 

 (20,517) (14,691) 18,213 

Loss before income taxes (84,202) (31,758) (262,205) 

Income tax benefit — — 85 

Net loss (84,202) (31,758) (262,120) 

Preferred stock dividends 6,047 6,047 6,047 

Net loss applicable to common stock $ (90,249) $ (37,805) $(268,167) 

PER COMMON SHARE 

Net loss applicable to common stock—basic $ (2.48) $ (1.05) $ (7.47) 

Net loss applicable to common stock—diluted $ (2.48) $ (1.05) $ (7.47) 

Weighted average common shares outstanding—basic 36,390 36,124 35,921 

Weighted average common shares outstanding—diluted 36,390 36,124 35,921 

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,

 2012 2011 2010

CASH FLOWS FROM OPERATING ACTIVITIES: 

Net loss $ (84,202) $ (31,758) $ (262,120) 

Adjustments to reconcile net loss to net cash provided by operating activities—Depletion,

depreciation and amortization 141,222 131,811 105,913 

Unrealized (gain) loss on derivatives not designated as hedges 41,278 (3,234) (31,794) 

Impairment 47,818 8,111 234,887 

Exploration costs 12,848 — — 

Amortization of leasehold costs 5,948 5,487 5,963 

Share based compensation (non-cash) 6,903 6,495 7,554 

(Gain) loss on sale of assets (44,606) (236) 2,824 

Gain on extinguishment of debt — (62) — 

Amortization of finance cost and debt discount 12,819 14,351 19,256 

Amortization of transportation obligation 1,457 2,873 — 

Change in assets and liabilities: 

Restricted cash — 4,232 (4,232) 

Accounts receivable, trade and other, net of allowance 580 355 (343) 

Income taxes receivable/payable 277 3,995 11,103 

Accrued oil and natural gas revenue 1,399 (5,500) 403 

Inventory 6,415 (796) (7,169) 

Prepaid expenses and other 3,356 (2,953) (1,285) 

Accounts payable 26,999 (1,079) 14,571 

Accrued liabilities (6,722) 4,248 4,901 

Net cash provided by operating activities 173,789 136,340 100,432 

CASH FLOWS FROM INVESTING ACTIVITIES: 

Capital expenditures (252,416) (335,236) (264,967) 

Proceeds from sale of assets 90,922 172 64,887 

Net cash used in investing activities (161,494) (335,064) (200,080) 

CASH FLOWS FROM FINANCING ACTIVITIES: 

Principal payments of bank borrowings (132,000) (42,000) (54,500) 

Proceeds from bank borrowings 124,500 144,500 54,500 

Proceeds from high yield offering — 275,000 — 

Repurchase of convertible notes — (176,422) — 

Debt issuance costs (66) (9,341) (492) 

Preferred stock dividends (6,047) (6,047) (6,047) 

Exercise of stock options and warrants 16 — 10 

Other (857) (1,407) (1,151) 

Net cash provided by (used in) financing activities (14,454) 184,283 (7,680) 

Decrease in cash and cash equivalents (2,159) (14,441) (107,328) 

Cash and cash equivalents, beginning of period 3,347 17,788 125,116 

Cash and cash equivalents, end of period $ 1,188 $ 3,347 $ 17,788 

Supplemental disclosures of cash flow information: 

Cash paid during the year for interest $ 39,516 $ 35,000 $ 18,014 

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’

Shares Value Shares Value Shares Value Equity

Balance at January 1, 2010 2,250 $ 2,250 37,452 $ 7,166 $ 637,335 (20) $ (411) $ (200,955) $ 445,385 

Net loss — — — — — — — (262,120) (262,120) 

Employee stock plans — — 282 52 7,502 — — — 7,554 

Employee stock option exercise — — — 1 9 — — — 10 

Director stock grants — — 24 5 301 — — — 306 

Repurchases of stock — — — 3 (1) (65) (1,113) — (1,111) 

Retirement of stock — — (73) (15) (1,313) 73 1,328 — — 

Dividends — — — — — — — (6,047) (6,047) 

Other — — — — (5) — — — (5) 

Balance at December 31, 2010 2,250 $ 2,250 37,685 $ 7,212 $ 643,828 (12) $ (196) $ (469,122) $ 183,972 

Net loss — — — — — — — (31,758) (31,758) 

Equity portion of convertible notes redeemed — — — — (7,944) — — — (7,944) 

Employee stock plans — — 350 70 6,425 — — — 6,495 

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 

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.

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 held in escrow at December 31, 2010 totaling $4.2 million was paid out in 2011 for the posting of the suspensive

appeal bond relating to the Hoover Tree Farm, LLC v. Goodrich Petroleum Company, LLC, et al. litigation. None of the cash was restricted as of

December 31, 2011 or December 31, 2012. See Note 9.

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, 2012 and 2011, 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 Balance Sheet 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

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2012 and 2011, 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.

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As of December 31, 2012, we had interests in oil and natural gas properties totaling $718.3 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 estimated 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 determined during 2012 that the carrying amount of certain of our oil and natural gas properties were not recoverable from future cash flows and,

therefore, we recorded an impairment of $47.8 million for the year ended December 31, 2012. These impairment charges reduced the fields’ carrying value to

an estimated fair value of $3.3 million as of December 31, 2012.

Total impairment associated with our oil and natural gas properties for the years ended December 31, 2011 and 2010 was $8.1 million and $234.9

million, respectively.

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” 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 acquisition, construction 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

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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, 2012 and 2011, 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 Series B Convertible Preferred Stock, 3.25% Convertible Senior Notes due 2026 (the “2026 Notes”) and 5% Convertible Senior Notes

due 2029 (the “2029 Notes”).

Commitments and Contingencies—Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments,

litigation, fines and penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or

remediation can be reasonably estimated. Recoveries from third parties, when probable of realization, are separately recorded and are not offset against the

related environmental liability.

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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, 2012, 2011 and 2010 are as follows:

 Year Ended December 31,

 2012 2011 2010

BP Energy Company 34% — — 

Flint Hill Resources, LLC 15% — — 

Shell Energy Resources LP — 11% 17% 

Regency Field Services LLC — 10% — 

Louis Dreyfus Corporation — — 29% 

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 $275,000,000 aggregate principal amount of our 8.875% Senior Notes due 2019 (the “2019

Notes”). The 2019 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, and 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.

New Accounting Pronouncements

ASU 2011-04 “Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S.

GAAP and IFRS.”—In May 2011, the Financial Accounting Standards Board (the “FASB”) issued additional guidance intended to result in convergence

between US GAAP and International Financial Reporting Standards (“IFRS”) requirements for measurement of and disclosures about fair value. The

amendments are not expected to have a significant impact on companies applying US GAAP. Principal provisions of the amendments include: (i) application

of the ‘highest and best use’ is relevant only when measuring fair value for non-financial assets and liabilities; (ii) a prohibition on grouping financial

instruments for purposes of determining fair value, except when an entity manages market and credit risks on the basis of the entity’s net exposure to the

group; (iii) an extension of the prohibition against the use of a blockage factor to all fair value measurements (that prohibition currently applies only to

financial instruments with quoted prices in active markets); (iv) guidance that fair value measurement of equity instruments should be made from the

perspective of a market participant that holds that instrument as an asset; and (v) a requirement that for recurring Level 3 fair value measurements, entities

disclose quantitative information about unobservable inputs, a

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description of the valuation process used and qualitative details about the sensitivity of the measurements. In addition, for Balance Sheet items not carried at

fair value but for which fair value is disclosed, entities will be required to disclose the Level within the fair value hierarchy that applies to the fair value

measurement disclosed. This guidance is effective for interim and annual periods beginning after December 15, 2011. We have adopted this guidance effective

January 1, 2012. The adoption of this guidance did not have an impact on the Company’s fair value measurements, financial condition, results of operations

or cash flows.

ASU 2011-05 “Comprehensive Income: Presentation of Comprehensive Income”—In June 2011, the FASB issued guidance intended to eliminate

the option to report other comprehensive income and its components in the statement of changes in equity. ASU 2011-05 requires that all non-owner changes in

stockholders’ equity be presented in either a single continuous statement of comprehensive income or in two separate but consecutive statements. This new

guidance is to be applied retrospectively for interim and annual periods beginning after December 15, 2011. The adoption of this guidance does not have an

impact on the Company’s financial condition, results of operations or cash flows.

ASU 2011-11 “Balance Sheet: Disclosures about Offsetting Assets and Liabilities.”—In December 2011, the FASB issued guidance intended to

result in convergence between US GAAP and 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 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 will adopt this guidance effective January 1, 2013. The adoption of

this guidance is not expected to have an impact on the Company’s financial condition, results of operations or cash flows.

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 employees and non-employee directors. Under the 2006 Plan, a maximum of 2.0 million new shares are reserved for issuance as awards

of share options to officers, employees and non-employee directors. In May 2011, our shareholders amended the 2006 Plan to increase the maximum number

of new shares reserved for issuance as awards of share options to officers, employees and non-employee directors by 2.0 million. As of December 31, 2012, a

total of 855,142 shares were available for future grants under the 2006 Plan.

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,

 2012 2011 2010

Restricted stock expense $6,670 $6,194 $5,944 

Stock option expense 233 301 1,609 

Director stock expense 585 525 502 

Total share-based compensation: $ 7,488 $ 7,020 $8,055 

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. All

options expire ten years after the date of grant.

Option activity under our stock option plans as of December 31, 2012, and changes during the year ended December 31, 2012 were as follows:

 Shares 

Weighted

Average

Exercise

Price 

Remaining

Contractual

Term 

Aggregate

Intrinsic

Value

 (years) (thousands)

Outstanding at January 1, 2012 914,134 $ 21.49 3.95 $ 74 

Granted — — — — 

Exercised 4,000 4.11 — — 

Forfeited 9,150 21.59 — — 

Outstanding at December 31, 2012 900,984 $21.57 2.92 $ 18 

Exercisable at December 31, 2012 864,849 $21.56 2.83 $ 18 

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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 2012 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, 2012. 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, 2012, and 2010 was less than $0.1 million in both

years. There were not any exercised in 2011.

 Options Outstanding Options Exercisable

Range of Exercise Prices 

Number

Outstanding at

December 31,

2012 

Weighted

Average

Remaining

Contractual Life 

Weighted

Average

Exercise

Price 

Number

Exercisable at

December 31,

2012 

Weighted

Average

Exercise

Price

 (years) 

$4.85 4,000 0.42 $ 4.85 4,000 $ 4.85 

$16.46 and $19.78 307,300 2.11 18.08 307,300 18.08 

$21.59 to $27.81 589,684 3.40 23.50 553,549 23.62 

 900,984 2.92 $21.57 864,849 $21.56 

No options were granted in 2012 or 2011. During 2010 we modified 60,000 stock options under the plan valued at an aggregate of $0.4 million. The

estimated fair value of the options modified during 2010 and prior years was calculated using a Black-Scholes Merton option pricing model (“BlackScholes”).

The following schedule reflects the various assumptions included in the Black-Scholes model as it relates to the valuation of our options of the options

modified in 2010:

 2010

Risk-free interest rate (1)

 2.55% 

Expected volatility (2) 64% 

Expected dividend yield (3) 0% 

Expected term (4) (in years) 6 

(1) Risk-free interest rate—is based on a zero-coupon U.S. government instrument over the expected term.

(2) Expected volatility—is based on the weighted average historical volatility of our common stock.

(3) Expected dividend yield—we do not pay dividends on our common stock.

(4) Expected term—we use the midpoint of the vesting period and the life of the grant to estimate employee option exercise timing.

As of December 31, 2012, total unrecognized compensation cost related to options is as follows:

 

Unrecognized

compensation

costs 

Weighted

Average

years to

recognition

 (thousands) (years)

December 31, 2012 $ 93  0.12 

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.

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Restricted stock activity and values under our plan for the years ended December 31, 2012, 2011 and 2010 were as follows:

 

Number of

Shares

Granted 

Value of

Shares

Granted 

Fair Value of

Stock Vested

 (thousands) (thousands)

2012 1,073,727 $ 9,533 $ 3,335 

2011 561,714 7,921 5,764 

2010 471,845 7,432 4,342 

Restricted stock activity under our plan for the year ended December 31, 2012, 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, 2012 931,809 $ 15.42 $ 14,373 

Vested (386,640) 16.51 (6,384) 

Granted 1,073,727 8.88 9,533 

Forfeited (77,246) 15.23 (1,177) 

Unvested at December 31, 2012 1,541,650 $ 10.60 $16,345 

As of December 31, 2012, total unrecognized compensation cost related to restricted stock is as follows:

 

Unrecognized

compensation

costs 

Weighted

Average

years to

recognition

 (thousands) (years)

December 31, 2012 $ 15,526  2.27 

NOTE 3—Asset Retirement Obligations

The reconciliation of the beginning and ending asset retirement obligation for the periods ending December 31, 2012 and 2011 is as follows (in

thousands):

 December 31,

 2012 2011

Beginning balance $17,425 $16,075 

Liabilities incurred 693 566 

Revisions in estimated liabilities (1) 2,005 1,525 

Liabilities settled (767) (1,904) 

Accretion expense 1,111 1,286 

Dispositions (2,161) (123) 

Ending balance $18,306 $17,425 

Current liability $ 168 $ 5,176 

Long term liability $18,138 $12,249 

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(1) We increased our estimated liability by over $2.0 million as a result of a change in timing from the well useful life to the overall field useful life, while

the plug and abandonment costs remained relatively flat with only slight increases.

NOTE 4—Debt

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

December 31, 2012 December 31, 2011

Principal

Carrying

Amount

Fair

Value (1) Principal

Carrying

Amount

Fair

Value (1)

Senior Credit Facility $ 95,000 $ 95,000 $ 95,000 $ 102,500 $ 102,500 $ 102,500 

3.25% Convertible Senior Notes due 2026 429 429 429 429 429 429 

5.0% Convertible Senior Notes due 2029 (2) 218,500 198,242 204,975 218,500 188,197 201,785 

8.875% Senior Notes due 2019 275,000 275,000 261,250 275,000 275,000 243,898 

Total debt $588,929 $568,671 $561,654 $596,429 $566,126 $548,612 

(1) The carrying amount for the Senior Credit Facility represents fair value because the variable interest rates are reflective of current market conditions and

the carrying amount of the 3.25% Convertible Senior Notes due 2026 represents fair value because the last transacted activity was at par; otherwise, fair

value was obtained by direct market quotes within Level 1 of the fair value hierarchy.

(2) The debt discount is amortized using the effective interest rate method based upon an original five year term through October 1, 2014. The debt discount

was $20.3 million and $30.3 million as of December 31, 2012 and December 31, 2011, respectively.

The following table summarizes the total interest expense (contractual interest expense, amortization of debt discount and financing costs) and the

effective interest rate on the liability component of the debt (amounts in thousands, except effective interest rates):

 December 31, 2012 December 31, 2011 December 31, 2010

 

Interest

Expense 

Effective

Interest

Rate

Interest

Expense 

Effective

Interest

Rate

Interest

Expense 

Effective

Interest

Rate

Senior Credit Facility 5,114 3.7% 3,180 —* 2,611 —* 

3.25% Convertible Senior Notes due 2026 14 3.3% 4,305 9.% 14,537 9.0% 

5.0% Convertible Senior Notes due 2029 21,968 11.4% 20,948 10.5% 20,031 11.2% 

8.875% Senior Notes due 2019 25,308 9.2% 20,910 8.9% — — 

* An Effective Interest Rate Calculation is not meaningful for the years ended December 31, 2011 and December 31, 2010 since there were only minimal

average amounts borrowed under the Senior Credit Facility during the period.

Senior Credit Facility

On May 5, 2009, we entered into a Second Amended and Restated Credit Agreement (including all amendments, the “Senior Credit Facility”) that

replaced our previous facility. On February 25, 2011, we entered into a Fourth Amendment to the Senior Credit Facility. The primary conditions for the

effectiveness of the Fourth Amendment were (i) the closing of the issuance and sale of our 8.875% Notes due 2019 (the “2019 Notes”), and (ii) the placement

of not less than $175 million of net proceeds from the sale of the 2019 Notes in an escrow account with the lenders to be used for the redemption or earlier

repurchase of all our outstanding 3.25% Convertible Senior Notes due 2026 (the “2026 Notes”), both of which occurred on March 2, 2011.

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Total lender commitments under the Senior Credit Facility are $600 million subject to borrowing base limitations as of December 31, 2012 of

$210 million. The Senior Credit Facility matures on July 1, 2014 subject to automatic extension to February 25, 2016, if, prior to maturity, we prepay or

escrow certain proceeds sufficient to prepay our $218.5 million 5% Convertible Senior Notes due 2029 (the “2029 Notes”). Revolving borrowings under the

Senior Credit Facility are limited to, and subject to, periodic redeterminations of the borrowing base. Interest on revolving borrowings under the Senior Credit

Facility accrues at a rate calculated, at our option, at the bank base rate plus 1.00% to 1.75%, or LIBOR plus 2.00% to 2.75%, depending on borrowing base

utilization. Pursuant to the terms of the Senior Credit Facility, borrowing base redeterminations occur on a semi-annual basis on April 1 and October 1. As of

December 31, 2012, we had $95 million outstanding under the Senior Credit Facility. Substantially all our assets are pledged as collateral to secure the Senior

Credit Facility.

The terms of the Senior Credit Facility require us to maintain certain covenants. Capitalized terms used here, but not defined, have the meanings

assigned to them in the Senior Credit Facility. In October 2011, we entered into a Sixth Amendment to the Senior Credit Facility which amended the EBITDAX

annualized calculation and increased the borrowing base to $210 million. 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 assets related to our derivatives,

accrued capital expenditures and current maturities under the Senior Credit Facility).

As defined in the credit agreement EBITDAX is earnings before interest expense, income tax, DD&A, 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, 2012.

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

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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 2029 Notes. The notes mature on October 1, 2029, unless earlier converted, redeemed or repurchased.

The notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The notes accrue

interest at a rate of 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 notes on September 28, 2009.

Before October 1, 2014, we may not redeem the notes. 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. 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 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) commencing after December 31, 2009, if the last

reported sale price of our common stock is greater than or equal to 135% of the conversion price of the notes (as defined in this prospectus supplement) 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 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 notes have been called for redemption; or (4) upon the occurrence of one of the specified corporate transactions

described in this prospectus supplement. Investors may also convert their 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 notes are convertible into shares of our common stock at a rate equal to 28.8534 shares per $1,000 principal amount of notes (equal to an “initial

conversion price” of approximately $34.66 per share of common stock per share).

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

corporate purposes.

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We separately account for the liability and equity components of our 2029 Notes in a manner that reflects our nonconvertible debt borrowing rate when

interest is recognized in subsequent periods. Upon issuance of the notes in September 2009, in accordance with accounting standards related to convertible

debt instruments that may be settled in cash upon conversion, we recorded a debt discount of $49.4 million, thereby reducing the carrying the value of

$218.5 million notes on the December 31, 2009 balance sheet to $171.1 million and recorded an equity component net of tax of $32.1 million. The debt

discount is amortized using the effective interest rate method based upon an original five year term through October 1, 2014. At December 31, 2012, $20.3

million debt discount remains to be amortized on the 2029 notes.

3.25% Convertible Senior Notes Due 2026

During the year ended December 31, 2011, we repurchased $174.6 million of our 2026 Notes 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, 2011, $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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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, 2012, 2011 and 2010. The following table sets forth information related to the computations of basic and diluted loss per share.

 Year Ended December 31,

 2012 2011 2010 

 (Amounts in thousands, except per share data)

Basic loss per share: 

Loss applicable to common stock $ (90,249) $ (37,805) $ (268,167) 

Weighted-average shares of common stock outstanding (1) 36,390 36,124 35,921 

Basic loss per share $ (2.48) $ (1.05) $ (7.47) 

Diluted loss per share: 

Loss applicable to common stock $ (90,249) $ (37,805) $ (268,167) 

Dividends on convertible preferred stock (2) — — — 

Interest and amortization of loan cost on convertible senior notes, net of tax (3) — — — 

Diluted loss $ (90,249) $ (37,805) $ (268,167) 

Weighted-average shares of common stock outstanding (1) 36,390 36,124 35,921 

Assumed conversion of convertible preferred stock (2) — — — 

Assumed conversion of convertible senior notes (3) — — — 

Stock options and restricted stock (4) — — — 

Weighted-average diluted shares outstanding 36,390 36,124 35,921 

Diluted loss per share $ (2.48) $ (1.05) $ (7.47) 

(1) Shares of common stock outstanding under the Share Lending Agreement not

included in the shares outstanding. See Note 7.

 — — 1,624,300 

(2) Common shares issuable upon assumed conversion of convertible preferred stock

were not presented as they would have been anti-dilutive. 3,587,850 3,587,850 3,587,850 

(3) Common shares issuable upon assumed conversion of the 2026 Notes and the 2029

Notes were not presented as they would have been anti-dilutive. 6,310,974 7,067,065 8,958,395 

(4) 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. 238,222 171,177 53,144 

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NOTE 6—Income Taxes

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

 Year Ended December 31,

 2012 2011 2010

Current: 

Federal $— $ — $ 85 

State — — — 

 — — 85 

Deferred: 

Federal — — — 

State — — — 

 — — — 

Total $— $ — $ 85 

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,

 2012 2011 2010

Income tax (expense) benefit 

Tax at U.S. statutory income tax $ 29,471 $11,115 $ 91,772 

Valuation allowance (29,952) (9,909) (93,497) 

State income taxes-net of federal benefit 1,618 (762) 1,860 

Nondeductible expenses and other (1,137) (444) (50) 

Total tax (expense) benefit $ — $ — $ 85 

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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,

 2012 2011

Current deferred tax assets: 

Accrued liabilities $ 375 $ 849 

Contingent liabilities and other 134 44 

Less valuation allowance (498) (750) 

Total current deferred tax assets 11 143 

Current deferred tax liabilities: 

Derivative financial instruments (621) (19,770) 

Accrued liabilities (26) (93) 

Total current deferred tax liabilities (647) (19,863) 

Net current deferred tax liability $ (636) $ (19,720) 

Noncurrent deferred tax assets: 

Operating loss carry-forwards $ 156,723 $ 132,442 

Texas Margin Credit 575 607 

Louisiana NOL 3,217 998 

Mississippi NOL 75 — 

Statutory depletion carry-forward 7,035 7,035 

AMT tax credit carry-forward 1,324 1,245 

Derivative financial instruments 1,395 6,097 

Compensation 3,364 3,795 

Contingent liabilities and other 512 — 

Property and equipment 26,848 42,733 

Total gross noncurrent deferred tax assets 201,068 194,952 

Less valuation allowance (193,459) (163,875) 

Net noncurrent deferred tax assets 7,609 31,077 

Noncurrent deferred tax liabilities: 

Bond discount (61) (49) 

Contingent liabilities and other — (982) 

Debt discount (6,912) (10,326) 

Total non-current deferred tax liabilities (6,973) (11,357) 

Net non-current deferred tax asset $ 636 $ 19,720 

The valuation allowance for deferred tax assets increased by $29.3 million in 2012. 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 2012 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 $29.3

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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As of December 31, 2012, we have federal NOL carry-forwards of approximately $450.1 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 $1.3 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.

The amount of unrecognized tax benefits did not materially change as of December 31, 2012. 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, 2013.

NOTE 7—Stockholders’ Equity

Share Lending Agreement

In connection with the offering of our 2026 Notes in December 2006, we lent an affiliate of Bear, Stearns & Co. (“BSC”) a total of 3,122,263 shares of

our common stock under the Share Lending Agreement. On March 20, 2008, BSC returned 1,497,963 shares of the 3,122,263 originally borrowed shares

and fully collateralized the remaining 1,624,300 borrowed shares with a cash collateral deposit of approximately $41.3 million.

In conjunction with the partial repurchase of our 2026 Notes in March 2011, the Share Lending Agreement was terminated and JP Morgan Chase & Co.

(successor to BSC) returned the remaining 1,624,300 shares. The shares returned to us were recorded as treasury shares and retired in March 2011.

Capped Call Option Transactions

On December 10, 2007, we closed the public offering of 6,430,750 shares of our common stock at a price of $23.50 per share. Net proceeds from the

offering were approximately $145.4 million after deducting the underwriters’ discount and estimated offering expenses. We used approximately $123.8 million

of the net proceeds to pay off outstanding borrowings under our senior credit facility, and approximately $21.6 million of the net proceeds to purchase capped

call options on shares of our common stock from affiliates of BSC and J.P. Morgan Securities Inc.

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

common stock. The capped call option transactions covered, subject to customary anti-dilution adjustments, approximately 5.8 million shares of our common

stock, and each of them was divided into a number of tranches with differing expiration dates. Approximately 77,333 options per trading day expired over

each of three separate 25 consecutive trading day settlement periods. During 2009, two-thirds of the options expired. The remaining one-third of the options

subject to the capped call expired in May and June 2010 and did not result in our receipt of any shares of common stock.

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Preferred Stock

Our Series B Convertible Preferred Stock (the “Series B Convertible 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 Convertible 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 Convertible 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 Convertible 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 Convertible 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 Convertible

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 Convertible 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 Convertible Preferred Stock. The

Series B Convertible Preferred Stock is non-redeemable by us. There have been no redemptions or conversions in any periods.

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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 Statement 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, 2012, 2011 and 2010.

 December 31,

Oil and Natural Gas Derivatives (in thousands) 2012 2011 2010

Realized gain on oil and natural gas derivatives $ 73,160 $31,305 $ 24,590 

Unrealized gain (loss) on oil and natural gas derivatives (41,278) 3,234 30,706 

Total gain on oil and natural gas derivatives $ 31,882 $34,539 $55,296 

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 entire Board of

Directors. As of December 31, 2012, the commodity derivatives we used were in the form of:

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

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

price.

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 $2.4 million had our counterparties as a group been unable to fulfill their obligations as of December 31, 2012.

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As of December 31, 2012, our open forward positions on our outstanding commodity derivative contracts, all of which were with BNP Paribas, Royal

Bank of Canada, JPMorgan Chase Bank, N.A., Merrill Lynch Commodities, Inc. and Wells Fargo Bank, N.A. , were as follows:

Contract Type 

Daily

Volume 

Total

Volume Fixed Price 

Fair Value at

December 31, 2012

(in thousands)

Natural gas swaptions (MMBtu) 

2014 20,000 7,300,000 $5.35 $ (659) 

Oil swaps (BBL) 

2013 3,500 1,277,500 $92.25 – $103.15 

2013 (1) 500 15,500 $101.50 1,774 

Oil swaptions (BBL) 

2014 1,500 547,500 $97.30 – $101.00 (3,328) 

 Total $ (2,213) 

(1) Swap is only for the month of January.

During 2012, we entered into the following derivative contracts.

Contract Type 

Daily

Volume Strike Price Contract Start Date Contract Termination

Oil swap (BBL)

 500 $ 102.00 January 1, 2012 December 31, 2012 

Oil swap (BBL) 500 $104.25 May 1, 2012 December 31, 2012 

Oil swap (BBL) 500 $103.15 January 1, 2013 December 31, 2013 

Oil swap (BBL) 500 $ 92.50 August 1, 2012 December 31, 2013 

Oil swap (BBL) 500 $ 95.85 January 1, 2013 December 31, 2013 

Oil swap (BBL) 500 $ 92.25 January 1, 2013 December 31, 2013 

Oil swap (BBL) 500 $ 92.50 January 1, 2013 December 31, 2013 

Oil swap (BBL) 500 $ 92.64 January 1, 2013 December 31, 2013 

Oil swap (BBL) 500 $ 92.55 January 1, 2013 December 31, 2013 

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, 2012 and 2011 (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.

 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) 

 2011 Fair Value Measurements Using

Description Level 1 Level 2 Level 3 Total

Current Assets Commodity Derivatives $ — $56,486 $ — $56,486 

Non-current Liabilities Commodity Derivatives — (17,420) — (17,420) 

Total $ — $39,066 $ — $39,066 

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Interest Rate Swap

We have variable-rate debt obligations that expose us to the effects of changes in interest rates. To partially reduce our exposure to interest rate risk, from

time to time we enter into interest rate swap agreements. Our last interest rate swap contract ended April 2010. At December 31, 2012 and 2011, we did not

have any interest rate swaps in place.

NOTE 9—Commitments and Contingencies

Hoover Tree Farm, LLC v. Goodrich Petroleum Company, LLC et al. On April 29, 2010 a state court in Caddo Parish, Louisiana, granted a

judgment holding us solely responsible for the payment of $8.5 million in additional oil and natural gas lease bonus payments and related interest in an

ongoing lawsuit involving the interpretation of a unique oil and natural gas lease provision. We satisfied the requirements for posting a suspensive appeal bond

by depositing $8.5 million in July 2010 with Iberia Bank in Shreveport, Louisiana for the account of the Clerk of Caddo Parish Court.

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

and the remaining $4.3 million as of December 31, 2010 is reflected as “Operating Expenses—Other” in the Consolidated Statement of Operations.

On March 23, 2011, the State of Louisiana Second Circuit Court of Appeals issued an opinion which affirmed the trial court’s judgment against us

and amended the judgment to make both us and the sub-lessee responsible for the money judgment. On June 10, 2011, we filed an application for writ of

certiorari with the Supreme Court of Louisiana which was denied on September 23, 2011. On October 13, 2011, the money judgment of $4.4 million,

including interest, was paid to the plaintiffs.

In addition, we are party to other 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, 2012 (in

thousands).

 Payment due by Period

 Note Total 2013 2014 2015 2016 

2017

and After

Long term debt (1)

 4 $493,929 $ — $218,500 $ — $275,429 $ — 

Interest on notes 4 97,477 35,345 32,614 24,420 5,098 — 

Office space leases 7,220 1,202 1,104 983 1,020 2,911 

Office equipment leases 706 357 253 9 6 — — 

Drilling rigs & operations contracts 12,126 11,825 230 6 5 6 — 

Transportation contracts 7,269 1,809 1,092 1,092 1,092 2,184 

(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

$218.5 million 5.0% convertible

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senior 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 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 $18.3

million. 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, 2012, 2011, and 2010, was approximately $1.2 million, $1.1 million and $1.1 million.

Drilling Contracts—We have one drilling rig under contract as of December 31, 2012 which is scheduled to expire in 2013.

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 $0.6 million for 2012, 2011 and 2010, respectively.

Transportation Contracts—We have commitments under a transportation contract for our Eagle Ford Shale Trend properties. See Footnote 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, 2012 and 2011, 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, 2012 and 2011, the amounts billed and outstanding to the affiliate 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 the

affiliate to us in the month after billing and the affiliate is current on payment of its billings.

On May 25, 2010, we entered into a participation agreement with Turnham Interests, Inc., a private company owned by Robert C. Turnham, Jr. (the

“Turnham Participation Agreement”). Mr. Turnham is our President and Chief Operating Officer and is a member of our Board of Directors. Pursuant to the

Turnham Participation Agreement, we purchased from Turnham Interests, Inc., at a cash price of $1,250 per net acre, a 95% working interest in

approximately 813 net acres in the Eagle Ford Shale oil play in Frio County, Texas. In addition, we agreed to pay for and carry the costs associated with the

drilling and completion of an initial well on the acreage, to the extent such costs are attributable to the 5% working interest in such acreage retained by

Turnham Interests, Inc. The total cash consideration received by Turnham Interests, Inc. was approximately $1 million. The term of the Turnham

Participation Agreement is three years, or for so long as there is commercial production from the acreage.

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The terms of the Turnham Participation Agreement are substantially identical to the terms of a previously announced participation agreement entered into

between us and an unrelated third party, concerning approximately 6,000 net acres adjacent to the acreage covered by the Turnham Participation Agreement.

Turnham Interests, Inc. had owned the leasehold interest subject to the Turnham Participation Agreement since 1999.

NOTE 11—Acquisitions and Divestitures

Acquisitions

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.

During 2011, we had acquired approximately 80,200 net acres in leases in the Tuscaloosa Marine Shale, an oil-rich formation that straddles

Southeastern Louisiana and Southwestern Mississippi. We paid approximately $15.5 million in cash for the acreage.

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.

We also recognized an aggregate gain of $0.6 million on other divestures of non-operated properties in 2012.

On December 30, 2010, we sold the shallow rights in certain of our non-core properties located in Northwest Louisiana and East Texas for approximately

$65 million with an effective date of July 1, 2010. We have retained all of the deep drilling rights on these divested properties, including the rights to both the

Haynesville Shale and Bossier Shale formations.

NOTE 12—Resignation of Executive Officer

In March 2010, our Executive Vice President and Chief Financial Officer of the Company resigned. The provisions of the Resignation Agreement dated

March 24, 2010 among the Company and this officer consisted primarily of the following:

• Term life of 60,000 fully vested options was modified;

• Accelerated vesting of 25,000 shares of restricted stock; and

• Execution of a consulting agreement for six months through September 2010.

We recognized additional expense related to the Resignation Agreement of approximately $0.9 million during the year ended December 31, 2010.

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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”), our independent reserve engineers consulting firm, as of December 31, 2012, 2011 and

2010. A copy of NSAI’s summary reserve report for 2012 is furnished as exhibit 99.1 to this Annual Report on Form 10-K. All of the subject reserves are

located in the continental United States, primarily in Texas and Louisiana.

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 2012. For oil volumes, the average WTI spot price of $91.21 per barrel is adjusted by lease for quality, transportation fees, and

regional price differentials. For natural gas volumes, the average Henry Hub spot price of $2.76 per MMBtu is adjusted by lease for energy content,

transportation fees, and regional price differentials.

Capitalized Costs

The table below reflects our capitalized costs related to our oil and natural gas producing activities at December 31, 2012, and 2011 (in thousands):

 2012 2011

Proved properties $1,532,199 $1,471,898 

Unproved properties 87,715 70,508 

 1,619,914 1,542,406 

Less accumulated depreciation, depletion and amortization (901,621) (820,950) 

Net oil and natural gas properties $ 718,293 $ 721,456 

We have $9.7 million of capitalized exploratory well costs that are pending the determination of proved reserves as of December 31, 2012 and had none

as of December 31, 2011.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

SUPPLEMENTAL INFORMATION

(Unaudited)

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,

 2012 2011 2010

Property Acquisition 

Unproved $ 22,325 $ 22,698 $ 33,456 

Proved — — — 

Exploration 34,529 4,815 33,580 

Development (1) 198,918 304,215 218,342 

 $255,772 $331,728 $285,378 

(1) Includes asset retirement costs of $2.7 million in 2012, $2.1 million in 2011 and $1.3 million in 2010.

The following table sets forth our net proved oil and natural gas reserves at December 31, 2012, 2011 and 2010 and the changes in net proved oil and

natural gas reserves during such years:

 Natural Gas (Mmcf) (5)

Oil, Condensate and NGLs

(MBbls) (5)

 2012 2011 (4) 2010 2012 2011 (4) 2010

Proved reserves at beginning of period 408,707 454,189 415,301 13,516 1,618 877 

Revisions of previous estimates (1) (112,601) (78,859) 1,383 (1,372) 6,485 88 

Extensions, discoveries and improved recovery (2) 4,420 69,643 102,751 4,661 6,059 820 

Purchases of minerals in place — — — — — — 

Sales of minerals in place (20,919) (99) (32,431) (2,524) (3) (17) 

Production (25,626) (36,167) (32,815) (1,092) (643) (150) 

Proved reserves at end of period 253,981 408,707 454,189 13,189 13,516 1,618 

Proved developed reserves: 

Beginning of period 169,344 187,417 162,935 6,532 746 431 

End of period 119,671 169,344 187,417 6,447 6,532 746 

 Natural Gas Equivalents (Mmcfe) (5)

 2012 2011 (4) 2010 

Proved reserves at beginning of period 489,805 463,899 420,561 

Revisions of previous estimates (1) (120,832) (39,949) 1,916 

Extensions, discoveries and improved recovery (2) 32,387 106,000 107,670 

Purchases of minerals in place — — — 

Sales of minerals in place (3) (36,063) (116) (32,532) 

Production (32,181) (40,029) (33,716) 

Proved reserves at end of period 333,116 489,805 463,899 

Proved developed reserves: 

Beginning of period 208,538 191,893 165,519 

End of period 158,352 208,538 191,893 

(1) Revisions of previous estimates in 2012 were negative reflecting significant natural gas pricing decreases which caused a number of our vertical proved

undeveloped natural gas locations, primarily in Northwest Louisiana and East Texas areas, to become uneconomic at those lower price levels.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

SUPPLEMENTAL INFORMATION

(Unaudited)

(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 32.4 Bcfe in 2012 related

to extensions and discoveries, of which approximately 2.1 Bcfe is attributed to the Haynesville Shale Trend and Cotton Valley Taylor Sand,

approximately 29.1 Bcfe is attributed to the Eagle Ford Shale Trend and 1.2 Bcfe in other areas.

(3) In 2012, we sold approximately 36.1 Bcfe attributed to the sale of properties in the South Henderson field located in East Texas. In December 2010, we

sold approximately 33 Bcfe attributed to our shallow rights in several fields in East Texas and Northwest Louisiana retaining ownership of all the deep

rights including the Haynesville Shale Trend formations.

(4) Reserves were recast for 2011 to break out NGLs from our natural gas in our Eagle Ford Shale Trend, West Brachfield, South Henderson, Minden and

Beckville fields. Our production and sales volumes are accounted for and disclosed based on the wet gas stream at the point of sale.

(5) 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.

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):

 2012 2011 2010

Future revenues $1,608,629 $2,242,060 $1,835,800 

Future lease operating expenses and production taxes (467,600) (497,901) (424,560) 

Future development costs (1) (465,500) (694,192) (513,252) 

Future income tax expense (4,149) (11,384) (10,172) 

Future net cash flows 671,380 1,038,583 887,816 

10% annual discount for estimated timing of cash flows (313,931) (590,613) (529,138) 

Standardized measure of discounted future net cash flows $ 357,449 $ 447,970 $ 358,678 

Index price used to calculate reserves (2) 

Natural gas (per Mcf) $ 2.76 $ 4.12 $ 4.38 

Oil (per Bbl) $ 91.21 $ 92.71 $ 75.96 

(1) Includes cumulative asset retirement obligations of $18.1 million, $17.4 million and $16.1 million in 2012, 2011 and 2010, 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.

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.

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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,

 2012 2011 2010

Balance, beginning of year

 $ 447,970 $ 358,678 $ 147,224 

Net changes in prices and production costs related to future production (193,096) (1,607) 113,068 

Sales and transfers of oil and natural gas produced, net of production costs (146,490) (160,543) (108,242) 

Net change due to revisions in quantity estimates (178,468) (47,233) 1,962 

Net change due to extensions, discoveries and improved recovery 197,583 259,967 153,509 

Net change due to purchases and sales of minerals in place (74,633) (127) (12,979) 

Changes in future development costs 208,619 6,709 35,173 

Previously estimated development cost incurred in period 69,688 18,080 21,231 

Net change in income taxes 2,394 (591) (2,507) 

Accretion of discount 45,201 36,213 14,816 

Change in production rates (timing) and other (21,319) (21,576) (4,577) 

Net increase (decrease) in standardized measures (90,521) 89,292 211,454 

Balance, end of year $ 357,449 $ 447,970 $358,678 

Summarized Quarterly Financial Data (Unaudited)

(In Thousands, Except Per Share Amounts)

 

First

Quarter

Second

Quarter

Third

Quarter 

Fourth

Quarter Total

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) 

2011 

Revenues $ 41,231 $ 52,871 $55,542 $ 51,425 $201,069 

Operating income (loss) (2,397) 2,080 176 (16,926) (17,067) 

Net income (loss) (23,168) 82 13,632 (22,304) (31,758) 

Net income (loss) applicable to common stock (24,680) (1,430) 12,121 (23,816) (37,805) 

Basic income (loss) per common share (0.68) (0.04) 0.34 (0.66) (1.05) 

Diluted income (loss) per common share (0.68) (0.04) 0.33 (0.66) (1.05) 

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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 13a15(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, 2011, 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 and Executive Officers of the Registrant and Corporate Governance

Our executive officers and directors and their ages and positions as of February 22, 2013, are as follows:

Name Age Position

Patrick E. Malloy, III

 70 Chairman of the Board of Directors

Walter G. “Gil” Goodrich 54 Vice Chairman, Chief Executive Officer and Director

Robert C. Turnham, Jr. 5 5 President, Chief Operating Officer and Director

Mark E. Ferchau 5 9 Executive Vice President

Jan L. Schott 44 Senior Vice President and Chief Financial Officer

Michael J. Killelea 50 Senior Vice President, General Counsel and Corporate Secretary

Henry Goodrich 82 Chairman—Emeritus and Director

Josiah T. Austin 6 5 Director

Peter D. Goodson 70 Director

Michael J. Perdue 58 Director

Arthur A. Seeligson 54 Director

Stephen M. Straty 57 Director

Gene Washington 6 6 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 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.

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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. She joined the company in 2007 as Vice President and

Controller, serving as the Company’s Principal Accounting Officer. Prior to joining the Company, Ms. Schott served as Senior Manager, Expenditure

Accounting and Systems Support of Apache Corporation since 2001. From 1997 to 2001 she served consecutively in the positions of Manager, Financial

Analysis; Manager, Financial Accounting; and Manager, Expenditure Accounting. Prior to joining Apache Corporation, 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.

Additional information required under Item 10, “Directors and Executive Officers of the Registrant and Corporate Governance,” will be provided in our

Proxy Statement for the 2013 Annual Meeting of Stockholders.

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The information required by this Item is incorporated by reference to the information provided in our definitive proxy statement for the 2013 annual meeting of

stockholders to be filed within 120 days from December 31, 2012. 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 2013 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2012.

Item 12. Security Ownership of Certain Beneficial Owners and Management

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 2013 Annual Meeting of Stockholders to be filed within 120 days from

December 31, 2012.

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 2013 Annual Meeting of Stockholders to

be filed within 120 days from December 31, 2012.

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 2013 Annual Meeting of Stockholders to be filed within 120 days from December 31, 2012.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

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

See “Index to Consolidated Financial Statements” on page 46.

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

 2.1

 

Purchase Agreement by and between Goodrich Petroleum, L.L.C. and SND Operating, L.L.C., dated October 27, 2010 (Incorporated by

reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K (File No. 001-12719) filed on January 4, 2011).

 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).

 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

 

Registration Rights Agreement dated December 21, 2005 among the Company, Bear, Sterns & Co. Inc. and BNP Paribas Securities Corp.

(Incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K (File No. 001-12719) filed on December 22, 2005).

 4.4

 

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).

 4.5

 

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).

 4.6

 

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).

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 4.7 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).

 4.8 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).

 4.9 Registration Rights Agreement dated as of March 2, 2011 among the Company, the Guarantor and J.P. Morgan Securities LLC, as representative

of the several initial purchasers (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (File No. 001-12719)

filed on March 8, 2011).

 4.10* 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.

 4.11* 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.

 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.

 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† Consulting Services Agreement between Patrick E. Malloy and Goodrich Petroleum Corporation dated June 1, 2001 (Incorporated by reference to

Exhibit 10.3 of the Company’s Annual Report filed on Form 10-K for the year ended December 31, 2001 (File No. 001-12719) filed on April 1,

2002).

9 5
Table of Contents

 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

 

Share Lending Agreement, dated November 30, 2006, among Goodrich Petroleum Corporation, Bear Stearns & Co. Inc. and Bear Stearns

International Limited (Incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K (File No. 001-12719) filed on December 4,

2006).

 10.20

 

Resignation Agreement dated as of March 24, 2010 between David R. Looney and Goodrich Petroleum Corporation (incorporated by reference

to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-12719) filed on March 26, 2010).

 10.21

 

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).

 10.22

 

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).

 10.23

 

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).

 10.24

 

Purchase Agreement dated as of February 25, 2011 among Goodrich Petroleum Corporation, Goodrich Petroleum Company, L.L.C. and J.P.

Morgan Securities LLC, as representative of the several initial purchasers (Incorporated by reference to Exhibit 10.1 of the Company’s

Current Report on Form 8-K (File No. 001-12719) filed on March 3, 2011).

 10.25

 

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).

 10.26

 

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).

9 6
Table of Contents

 10.27* 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).

 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.

 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.

 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.

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.

97
Table of Contents

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 22, 2013.

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 22, 2013.

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 Officer)

/s/ DAWN K. SMAJSTRLA 

Dawn K. Smajstrla

 

Vice President and Controller (Principal

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

98
Table of Contents

Signature Title

/s/ ARTHUR A. SEELIGSON 

Arthur A. Seeligson 

Director

/s/ STEPHEN M. STRATY 

Stephen M. Straty 

Director

/s/ GENE WASHINGTON 

Gene Washington 

Director

9 9
Exhibit 4.10

FIRST SUPPLEMENTAL INDENTURE

FIRST SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as of April 1, 2011, is among Goodrich Petroleum Corporation, a

Delaware corporation (herein called the “Company”), and Goodrich Petroleum Company, L.L.C., a Texas limited liability company (the “Subsidiary

Guarantor”), and Wells Fargo Bank, National Association, as Trustee (herein called the “Trustee”) under the indenture, dated as of December 6, 2006,

among the Company and the Trustee (the “Original Indenture,” and as amended and supplemented, including by this Supplemental Indenture, the

“Indenture”) relating to the Company’s 3.25% Convertible Senior Notes due 2026 (the “ Notes”).

RECITALS OF THE COMPANY AND THE SUBSIDIARY GUARANTOR

The Company, the Subsidiary Guarantor and the Trustee entered into an indenture, dated as of March 2, 2011 (the “ Senior Notes Indenture”),

relating to the Company’s 8.875% Senior Notes due 2019 (the “2019 Notes”), and the 2019 Notes.

Section 3.09 of the Original Indenture obligates the Company to cause certain subsidiaries that provide a guarantee with respect to any Public Debt

Securities issued by the Company to guarantee the Notes by executing a supplemental indenture as provided in such Section.

Section 10.01(c) of the Original Indenture provides that the Company and the Trustee are authorized to execute and deliver this Supplemental Indenture

to amend or supplement the Original Indenture without the consent of any Holder to add the Guarantees contemplated hereby.

This Supplemental Indenture is subject to the provisions of the Trust Indenture Act of 1939, as amended, that are required to be a part of this

Supplemental Indenture and shall, to the extent applicable, be governed by such provisions.

All things necessary to make this Supplemental Indenture a valid agreement of each of the Company and the Subsidiary Guarantor, in accordance with

its terms, have been done.

NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE WITNESSETH:

To comply with the provisions of the Original Indenture and in consideration of the foregoing and for other good and valuable consideration, the receipt

of which is hereby acknowledged, the Subsidiary Guarantor, the Company and the Trustee mutually covenant and agree for the equal and ratable benefit of

the Holders of the Notes as follows:

ARTICLE ONE

APPLICATION OF SUPPLEMENTAL INDENTURE

Section 101. Interpretation.

Unless otherwise expressly specified, references in this Supplemental Indenture to specific Article numbers or Section numbers refer to Articles and

Sections contained in this Supplemental Indenture, and not the Original Indenture or any other document. Capitalized terms used, but not defined, herein shall

have the meanings assigned to them in the Original Indenture.
Section 102. Effect of Supplemental Indenture.

The Original Indenture shall be supplemented and amended by replacing Article 13 of the Original Indenture in its entirety with the following:

ARTICLE 13

SUBSIDIARY GUARANTEES

Section 1301. Subsidiary Guarantee.

(a) Subject to this Article 13, the Subsidiary Guarantor fully and unconditionally guarantees, on a senior unsecured basis, to each Holder of a

Note authenticated and delivered by the Trustee and to the Trustee and its successors and assigns, irrespective of the validity and enforceability of this

Indenture, the Notes or the obligations of the Company hereunder or thereunder, that: (i) the principal of, premium, if any, and interest on the Notes will

be promptly paid in full when due, whether at Stated Maturity, by acceleration, redemption or otherwise, and interest on the overdue principal of,

premium, if any, and interest on the Notes, if any, if lawful (subject in all cases to any applicable grace period provided herein), and all other monetary

obligations of the Company to the Holders or the Trustee hereunder or thereunder will be promptly paid in full or performed, all in accordance with the

terms hereof and thereof; and (ii) in case of any extension of time of payment or renewal of any Notes or any of such other obligations, that same will be

promptly paid in full when due or performed in accordance with the terms of the extension or renewal, whether at stated maturity, by acceleration or

otherwise. Failing payment when due of any amount so guaranteed or any performance so guaranteed for whatever reason, the Subsidiary Guarantor

shall be obligated to pay the same immediately. The Subsidiary Guarantor agrees that this is a guarantee of payment and not a guarantee of collection.

(b) The Subsidiary Guarantor agrees that, to the maximum extent permitted under applicable law, their obligations hereunder shall be

unconditional, irrespective of the validity, regularity or enforceability of the Notes or this Indenture, the absence of any action to enforce the same, any

waiver or consent by any Holder of the Notes with respect to any provisions hereof or thereof, the recovery of any judgment against the Company, any

action to enforce the same or any other circumstance which might otherwise constitute a legal or equitable discharge or defense of a Subsidiary

Guarantor. The Subsidiary Guarantor waives diligence, presentment, demand of payment, filing of claims with a court in the event of insolvency or

bankruptcy of the Company, any right to require a proceeding first against the Company, protest, notice and all demands whatsoever and covenant that

this Guarantee shall not be discharged except by complete performance of the obligations contained in the Notes and this Indenture.

(c) If any Holder or the Trustee is required by any court or otherwise to return to the Company, the Subsidiary Guarantor or any custodian,

trustee, liquidator or other similar official acting in relation to either of the Company or the Subsidiary Guarantor, any amount paid by either to the

Trustee or such Holder, this Guarantee, to the extent theretofore discharged, shall be reinstated in full force and effect.

(d) The Subsidiary Guarantor agrees that it shall not be entitled to any right of subrogation in relation to the Holders in respect of any obligations

guaranteed hereby until payment in full of all obligations guaranteed hereby. The Subsidiary Guarantor further agrees that, as between the Subsidiary

Guarantor, on the one hand, and the Holders and the Trustee, on the other hand, (x) the maturity of the obligations guaranteed hereby may be accelerated

as provided in Article 7 of the Indenture for the purposes of this Guarantee, notwithstanding any stay, injunction or other prohibition preventing such

acceleration in respect of the obligations

2
guaranteed hereby, and (y) in the event of any declaration of acceleration of such obligations as provided in Article 7 of the Indenture, such obligations

(whether or not due and payable) shall forthwith become due and payable by the Subsidiary Guarantor for the purpose of this Guarantee.

Section 1302. Limitation on Subsidiary Guarantor Liability.

Each Subsidiary Guarantor hereby confirms that it is the intention of all such parties that the Guarantee of such Subsidiary Guarantor not

constitute a fraudulent transfer or conveyance for purposes of Bankruptcy Law, the Uniform Fraudulent Conveyance Act, the Uniform Fraudulent

Transfer Act or any similar Federal or state law to the extent applicable to any Guarantee. To effectuate the foregoing intention, the Trustee and the

Subsidiary Guarantor hereby irrevocably agree that the obligations of such Subsidiary Guarantor will be limited to the maximum amount which, after

giving effect to all other contingent and fixed liabilities of such Subsidiary Guarantor, and after giving effect to any collections from or payments made

by or on behalf of any other Subsidiary Guarantor in respect of the obligations of such other Subsidiary Guarantor under its Guarantee or pursuant to

its contribution obligations under this Article 13, will result in the obligations of such Subsidiary Guarantor under its Guarantee not constituting a

fraudulent conveyance or fraudulent transfer under Federal or state law. Until such time as the Notes are paid in full, the Subsidiary Guarantor waives

all rights of subrogation or contribution, whether arising by contract or operation of law (including, without limitation, any such right arising under

Federal Bankruptcy Law) or otherwise by reason of any payment by it pursuant to the provisions of this Article 13.

Section 1303. Release of the Subsidiary Guarantor.

The Subsidiary Guarantor will be deemed automatically and unconditionally released and discharged from all of its obligations under its

Guarantee without any further action on the part of the Trustee or any Holder of the Notes:

(a) if the Subsidiary Guarantor ceases to guarantee the 2019 Notes for any reason;

(b) if the Subsidiary Guarantor is no longer the Company’s Subsidiary;

(c) upon the liquidation or dissolution of the Subsidiary Guarantor; or

(d) upon discharge of the Indenture in accordance with Article 9 of the Indenture.

ARTICLE TWO

MISCELLANEOUS

Section 201. Capitalized Terms.

Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

Section 202. NEW YORK LAW TO GOVERN.

THE LAWS OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE AND ENFORCE THIS SUPPLEMENTAL

INDENTURE.

3
Section 203. Counterparts.

The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the

same agreement. This Supplemental Indenture may be executed in multiple counterparts which, when taken together, shall constitute one instrument.

Section 204. Effect of Headings.

The Section headings herein are for convenience only and shall not affect the construction hereof.

Section 205. The Trustee.

Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee

by reason of this Supplemental Indenture. This Supplemental Indenture is executed and accepted by the Trustee subject to all the terms and conditions set

forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with

respect hereto.

[Remainder of Page Intentionally Left Blank. Signature Page Follows.]

4
IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of this 1 day of April

2011.

SUBSIDIARY GUARANTOR:

GOODRICH PETROLEUM COMPANY, L.L.C.

By: /s/ Michael J. Killelea

Name: Michael J. Killelea

Title: Senior Vice President, General Counsel and

Corporate Secretary

COMPANY:

GOODRICH PETROLEUM CORPORATION

By: /s/ Michael J. Killelea

Name: Michael J. Killelea

Title: Senior Vice President, General Counsel and

Corporate Secretary

TRUSTEE:

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as Trustee

By: /s/ John Stohlmann

Authorized Signatory

[Signature Page to Supplemental Indenture]

st
Exhibit 4.11

SECOND SUPPLEMENTAL INDENTURE

SECOND SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as of April 1, 2011, is among Goodrich Petroleum

Corporation, a Delaware corporation (herein called the “ Company”), and Goodrich Petroleum Company, L.L.C., a Texas limited liability company (the

“Subsidiary Guarantor”), and Wells Fargo Bank, National Association, as Trustee (herein called the “Trustee”) under the indenture, dated as of

September 28, 2009, among the Company and the Trustee (the “Base Indenture”) and, as amended and supplemented by a first supplemental indenture of

even date therewith relating to the Company’s 5.00% Convertible Senior Notes due 2029 (the “ Notes”) (the “First Supplemental Indenture”; the Base

Indenture as amended and supplemented by the First Supplemental Indenture, the “ Original Indenture” and as further amended and supplemented by this

Second Supplemental Indenture, the “ Indenture”).

RECITALS OF THE COMPANY AND THE SUBSIDIARY GUARANTOR

The Company, the Subsidiary Guarantor and the Trustee entered into an indenture, dated as of March 2, 2011 (the “ Senior Notes Indenture”),

relating to the Company’s 8.875% Senior Notes due 2019 (the “2019 Notes”), and the 2019 Notes.

Section 4.02 of the First Supplemental Indenture obligates the Company to cause certain subsidiaries that provide a guarantee with respect to any Public

Debt Securities issued by the Company to guarantee the Notes by executing a supplemental indenture as provided in such Section.

Section 901 of the Base Indenture provides that the Company and the Trustee are authorized to execute and deliver this Supplemental Indenture to amend

or supplement the Base Indenture without the consent of any Holder to add the Guarantees contemplated hereby.

This Supplemental Indenture is subject to the provisions of the Trust Indenture Act of 1939, as amended, that are required to be a part of this

Supplemental Indenture and shall, to the extent applicable, be governed by such provisions.

All things necessary to make this Supplemental Indenture a valid agreement of each of the Company and the Subsidiary Guarantor, in accordance with

its terms, have been done.

NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE WITNESSETH:

To comply with the provisions of the First Supplemental Indenture and in consideration of the foregoing and for other good and valuable consideration,

the receipt of which is hereby acknowledged, the Subsidiary Guarantor, the Company and the Trustee mutually covenant and agree for the equal and ratable

benefit of the Holders of the Notes as follows:
ARTICLE ONE

APPLICATION OF SUPPLEMENTAL INDENTURE

Section 101. Interpretation.

Unless otherwise expressly specified, references in this Supplemental Indenture to specific Article numbers or Section numbers refer to Articles and

Sections contained in this Supplemental Indenture, and not the Base Indenture, the First Supplemental Indenture or any other document. Capitalized terms

used, but not defined, herein shall have the meanings assigned to them in the Original Indenture.

Section 102. Effect of Supplemental Indenture.

The Original Indenture shall be supplemented and amended by adding the following as Article 13 of the First Supplemental Indenture:

ARTICLE 13

SUBSIDIARY GUARANTEES

Section 1301. Subsidiary Guarantee.

(a) Subject to this Article 13, the Subsidiary Guarantor fully and unconditionally guarantees, on a senior unsecured basis, to each Holder of a

Note authenticated and delivered by the Trustee and to the Trustee and its successors and assigns, irrespective of the validity and enforceability of this

First Supplemental Indenture, the Notes or the obligations of the Company hereunder or thereunder, that: (i) the principal of, premium, if any, and

interest on the Notes will be promptly paid in full when due, whether at Stated Maturity, by acceleration, redemption or otherwise, and interest on the

overdue principal of, premium, if any, and interest on the Notes, if any, if lawful (subject in all cases to any applicable grace period provided herein),

and all other monetary obligations of the Company to the Holders or the Trustee hereunder or thereunder will be promptly paid in full or performed, all

in accordance with the terms hereof and thereof; and (ii) in case of any extension of time of payment or renewal of any Notes or any of such other

obligations, that same will be promptly paid in full when due or performed in accordance with the terms of the extension or renewal, whether at stated

maturity, by acceleration or otherwise. Failing payment when due of any amount so guaranteed or any performance so guaranteed for whatever reason,

the Subsidiary Guarantor shall be obligated to pay the same immediately. The Subsidiary Guarantor agrees that this is a guarantee of payment and not a

guarantee of collection.

(b) The Subsidiary Guarantor agrees that, to the maximum extent permitted under applicable law, their obligations hereunder shall be

unconditional, irrespective of the validity, regularity or enforceability of the Notes or this First Supplemental Indenture, the absence of any action to

enforce the same, any waiver or consent by any Holder of the Notes with respect to any provisions hereof or thereof, the recovery of any judgment

against the Company, any action to enforce the same or any other circumstance which might otherwise constitute a legal or equitable discharge or defense

of a Subsidiary Guarantor. The Subsidiary Guarantor waives diligence, presentment, demand of payment, filing of claims with a court in the event of

insolvency or bankruptcy of the Company, any right to require a proceeding first against the Company, protest, notice and all demands whatsoever and

covenant that this Guarantee shall not be discharged except by complete performance of the obligations contained in the Notes and this First

Supplemental Indenture.

2
(c) If any Holder or the Trustee is required by any court or otherwise to return to the Company, the Subsidiary Guarantor or any custodian,

trustee, liquidator or other similar official acting in relation to either of the Company or the Subsidiary Guarantor, any amount paid by either to the

Trustee or such Holder, this Guarantee, to the extent theretofore discharged, shall be reinstated in full force and effect.

(d) The Subsidiary Guarantor agrees that it shall not be entitled to any right of subrogation in relation to the Holders in respect of any obligations

guaranteed hereby until payment in full of all obligations guaranteed hereby. The Subsidiary Guarantor further agrees that, as between the Subsidiary

Guarantor, on the one hand, and the Holders and the Trustee, on the other hand, (x) the maturity of the obligations guaranteed hereby may be accelerated

as provided in Article 7 of each of the Base Indenture and the First Supplemental Indenture for the purposes of this Guarantee, notwithstanding any

stay, injunction or other prohibition preventing such acceleration in respect of the obligations guaranteed hereby, and (y) in the event of any declaration

of acceleration of such obligations as provided in Article 7 of each of the Base Indenture and the First Supplemental Indenture, such obligations (whether

or not due and payable) shall forthwith become due and payable by the Subsidiary Guarantor for the purpose of this Guarantee.

Section 1302. Limitation on Subsidiary Guarantor Liability.

Each Subsidiary Guarantor hereby confirms that it is the intention of all such parties that the Guarantee of such Subsidiary Guarantor not

constitute a fraudulent transfer or conveyance for purposes of Bankruptcy Law, the Uniform Fraudulent Conveyance Act, the Uniform Fraudulent

Transfer Act or any similar Federal or state law to the extent applicable to any Guarantee. To effectuate the foregoing intention, the Trustee and the

Subsidiary Guarantor hereby irrevocably agree that the obligations of such Subsidiary Guarantor will be limited to the maximum amount which, after

giving effect to all other contingent and fixed liabilities of such Subsidiary Guarantor, and after giving effect to any collections from or payments made

by or on behalf of any other Subsidiary Guarantor in respect of the obligations of such other Subsidiary Guarantor under its Guarantee or pursuant to

its contribution obligations under this Article 13, will result in the obligations of such Subsidiary Guarantor under its Guarantee not constituting a

fraudulent conveyance or fraudulent transfer under Federal or state law. Until such time as the Notes are paid in full, the Subsidiary Guarantor waives

all rights of subrogation or contribution, whether arising by contract or operation of law (including, without limitation, any such right arising under

Federal Bankruptcy Law) or otherwise by reason of any payment by it pursuant to the provisions of this Article 13.

Section 1303. Release of the Subsidiary Guarantor.

The Subsidiary Guarantor will be deemed automatically and unconditionally released and discharged from all of its obligations under its

Guarantee without any further action on the part of the Trustee or any Holder of the Notes:

(a) if the Subsidiary Guarantor ceases to guarantee the 2019 Notes for any reason;

(b) if the Subsidiary Guarantor is no longer the Company’s Subsidiary;

3
(c) upon the liquidation or dissolution of the Subsidiary Guarantor; or

(d) upon discharge of the Base Indenture in accordance with Article 15 of the Base Indenture.

ARTICLE TWO

MISCELLANEOUS

Section 201. Capitalized Terms.

Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

Section 202. NEW YORK LAW TO GOVERN.

THE LAWS OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE AND ENFORCE THIS SUPPLEMENTAL

INDENTURE.

Section 203. Counterparts.

The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the

same agreement. This Supplemental Indenture may be executed in multiple counterparts which, when taken together, shall constitute one instrument.

Section 204. Effect of Headings.

The Section headings herein are for convenience only and shall not affect the construction hereof.

Section 205. The Trustee.

Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee

by reason of this Supplemental Indenture. This Supplemental Indenture is executed and accepted by the Trustee subject to all the terms and conditions set

forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with

respect hereto.

[Remainder of Page Intentionally Left Blank. Signature Page Follows.]

4
IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of this 1 day of April

2011.

SUBSIDIARY GUARANTOR:

GOODRICH PETROLEUM COMPANY, L.L.C.

By: /s/ Michael J. Killelea

Name: Michael J. Killelea

Title: Senior Vice President, General Counsel and

Corporate Secretary

COMPANY:

GOODRICH PETROLEUM CORPORATION

By: /s/ Michael J. Killelea

Name: Michael J. Killelea

Title: Senior Vice President, General Counsel and

Corporate Secretary

TRUSTEE:

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as Trustee

By: /s/ John Stohlmann

Authorized Signatory

[Signature Page to Supplemental Indenture]

st
Exhibit 12.1

GOODRICH PETROLEUM CORPORATION

RATIO OF EARNINGS TO FIXED CHARGES

(In Thousands, Except Ratios)

 Year ended December 31,

 2012 2011 2010 2009 2008

Earnings: 

Income (loss) before income taxes $ (84,202) $(31,758) $(262,205) $(318,297) $ 176,246 

Plus: fixed charges 52,403 49,351 37,179 26,148 22,410 

Earnings available for fixed charges $(31,799) $ 17,593 $(225,026) $(292,149) $198,656 

Fixed Charges: 

Interest expense $ 52,403 $ 49,351 $ 37,179 $ 26,148 $ 22,410 

Total fixed charges $ 52,403 $ 49,351 $ 37,179 $ 26,148 $ 22,410 

Ratio of Earnings to Fixed Charges (a) (b) (c) (d) 8.86 

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

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

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

(d) Earnings for the year ended December 31, 2009 were inadequate to cover fixed charges. The coverage deficiency was $318.3 million.
Exhibit 12.2

GOODRICH PETROLEUM CORPORATION

RATIO OF EARNINGS TO FIXED CHARGES AND PREFERENCE SECURITIES DIVIDENDS

(In Thousands, Except Ratios)

 Year ended December 31,

 2012 2011 2010 2009 2008

Earnings: 

Income (loss) before income taxes $ (84,202) $(31,758) $(262,205) $(318,297) $ 176,246 

Plus: fixed charges 58,450 55,398 43,226 33,816 31,148 

Preference securities dividends (6,047) (6,047) (6,047) (7,668) (8,738) 

Earnings available for fixed charges $(31,799) $ 17,593 $(225,026) $(292,149) $198,656 

Fixed Charges: 

Interest expense $ 52,403 $ 49,351 $ 37,179 $ 26,148 $ 22,410 

Preference securities dividends 6,047 6,047 6,047 7,668 8,738 

Total fixed charges $ 58,450 $55,398 $ 43,226 $ 33,816 $ 31,148 

Ratio of Earnings to Fixed Charges and Preference Securities Dividends (a) (b) (c) (d) 6.38 

(a) 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.

(b) 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.

(c) 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.

(d) 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.
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, and

3. Registration Statement (Form S-8 No. 333-138156) pertaining to the Employee’s Savings Plan of Goodrich Petroleum Corporation;

of our report dated February 22, 2013, 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, 2012.

/s/ Ernst & Young LLP

Houston, Texas

February 22, 2013
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 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, 2012 and to the inclusion of our report dated February 1, 2013 in Goodrich Petroleum

Corporation’s Annual Report on Form 10-K for the year ended December 31, 2012.

NETHERLAND SEWELL & ASSOCIATES, INC.

By: /s/ J. Carter Henson, Jr.

J. Carter Henson, Jr., P.E.

Senior Vice President

Houston, Texas

February 22, 2013

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.
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 22, 2013

/s/ Walter G. Goodrich

Walter G. Goodrich

Chief Executive Officer
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 22, 2013

/s/ Jan L. Schott

Jan L. Schott

Senior Vice President and Chief Financial Officer
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, 2012 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 22, 2013

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.
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, 2012 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 22, 2013

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.
Exhibit 99.1

February 1, 2013

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, 2012, 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 all 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, 2012, to be:

 Net Reserves Future Net Revenue (M$)

Category 

Oil

(MBBL) 

NGL

(MBBL) 

Gas

(MMCF) Total 

Present Worth

at 10%

Proved Developed Producing 3,548.7 1,673.8 100,949.5 399,857.1 278,545.6 

Proved Developed Non-Producing 1,057.9 166.4 18,721.6 95,334.6 61,067.9 

Proved Undeveloped 3,453.1 3,289.2 134,310.1 180,336.9 19,480.3 

Total Proved 8,059.6 5,129.5 253,981.2 675,528.6 359,093.8 

Totals may not add because of rounding.

The oil reserves 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 2012. For oil and NGL volumes, the average West Texas Intermediate posted price of $91.21 per barrel is adjusted by lease for quality,

transportation fees, and regional price differentials. For gas volumes, the average Henry Hub spot price of $2.757 per MMBTU is adjusted by lease 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 $108.08 per barrel of oil, $35.34 per barrel of NGL, and $2.190 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 held constant throughout the lives of the properties.

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, platforms, and production facilities, net of any salvage value. Capital costs and

abandonment costs are held constant to the date of expenditure.

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 gas 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 gas 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.

(NSAI) and were accepted as accurate. Supporting work data are on file in our office. The titles to the properties have not been examined by NSAI, nor has the

actual degree or type of interest owned been independently confirmed. 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

By:

/s/ C.H. (Scott) Rees III

C.H. (Scott) Rees III, P.E.

Chairman and Chief Executive Officer

By: /s/ J. Carter Henson, Jr. By: /s/ Mike K. Norton By: /s/ Richard B. Talley, Jr.

J. Carter Henson, Jr. Mike K. Norton Richard B. Talley, Jr.

Texas P.E. 73964 Texas P.G. 441 Louisiana P.E. 36998

Senior Vice President Senior Vice President Vice President

Date Signed: February 1, 2013 Date Signed: February 1, 2013 Date Signed: February 1, 2013

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 nonproductive 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