Form 10-K
Table of Contents
Index to Financial Statements

 

 

 

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, 2010

 

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 National Market on June 30, 2010) the last business day of the registrant’s most recently completed second fiscal quarter was approximately $319 million. The number of shares of the registrant’s common stock outstanding as of February 14, 2011 was 37,672,853.

 

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, 2010, are incorporated by reference in Part III of this Form 10-K.

 

 

 


Table of Contents
Index to Financial Statements

GOODRICH PETROLEUM CORPORATION

 

ANNUAL REPORT ON FORM 10-K

FOR THE FISCAL YEAR ENDED

December 31, 2010

 

     Page  
PART I   

Items 1. and 2. Business and Properties

     3   

Item 1A. Risk Factors

     16   

Item 1B. Unresolved Staff Comments

     27   

Item 3. Legal Proceedings

     27   
PART II   

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

     28   

Item 6. Selected Financial Data

     30   

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

     31   

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

     49   

Item 8. Financial Statements and Supplementary Data

     51   

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

     87   

Item 9A. Controls and Procedures

     87   

Item 9B. Other Information

     87   
PART III   

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

     88   

Item 11. Executive Compensation

     90   

Item 12. Security Ownership of Certain Beneficial Owners and Management

     90   

Item 13. Certain Relationships and Related Transactions and Director Independence

     90   

Item 14. Principal Accounting Fees and Services

     90   
PART IV   

Item 15. Exhibits and Financial Statement Schedules

     91   

 

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Index to Financial Statements

PART I

 

Items 1. and 2.    Business and Properties

 

General

 

Goodrich Petroleum Corporation (together with its subsidiary, “we,” “our,” or “the Company”) is an independent oil and gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in Northwest Louisiana, East Texas and South Texas. The geological formations we target are the Haynesville Shale and Cotton Valley Taylor sand in Northwest Louisiana and East Texas and the Eagle Ford Shale in South Texas. In the current natural gas price environment we are concentrating a majority of our development efforts on existing leased acreage with formations that are prospective for oil. In addition, we continue to aggressively pursue the evaluation and acquisition of prospective acreage and oil and gas drilling opportunities outside of our existing leased acreage. We own working interests in 382 producing oil and gas wells located in 32 fields in 7 states. At December 31, 2010, we had estimated proved reserves of approximately 454.2 Bcf of natural gas and 1.6 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 and related information.

 

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, annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports 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.

 

Oil and Gas Operations and Properties

 

Overview.    As of December 31, 2010, nearly all of our proved oil and gas reserves were located in Northwest Louisiana, East Texas and South Texas. We spent nearly all of our 2010 capital expenditures of $283.7 million in these areas, with $175.1 million or 62% spent on the Haynesville Shale trend and $72.9 million or 26% spent on the Eagle Ford Shale trend. Our total capital expenditures, including accrued costs for services performed during 2010, consist of $247.5 million for drilling and completion costs, $33.6 million for leasehold acquisition, $0.6 million for facilities and infrastructure, $1.2 million for geological and geophysical costs and $0.8 million for furniture, fixtures and equipment.

 

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LOGO

 

Eagle Ford Shale Trend

 

During 2010, we acquired or farmed-in leases totaling approximately 67,036 gross (37,794 net) lease acres and began development and production activity in the Eagle Ford Shale trend in La Salle and Frio Counties located in South Texas. During 2010, we drilled and completed 6 gross (4.1 net) oil wells all of which were successful.

 

Haynesville Shale Trend

 

As of December 31, 2010, we have acquired or farmed-in leases totaling approximately 158,749 gross (88,722 net) acres and are continually attempting to acquire additional acreage prospective for the Haynesville Shale. During 2010, we drilled and completed 36 gross Haynesville Shale wells with a 100% success rate. Our Haynesville Shale drilling activities are located in five primary leasehold areas in East Texas and Northwest Louisiana.

 

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In those fields or areas where we have made the determination that it is prospective for the Haynesville Shale, the table below details our acreage positions, average working interest and wells drilled and completed in the Haynesville Shale.

 

     Haynesville Acreage
As of  December 31, 2010
     Average
Working
Interest
    Wells Drilled and  Completed
As of December 31, 2010
 

Field or Area

       Gross              Net            Successful      Unsuccessful  

North Minden

     31,506         25,890         100     6           

Beckville

     14,925         11,081         100     6           

Shelby Trough/Angelina River

     48,386         27,374         66     2           

Bethany Longstreet

     25,124         11,956         35     50           

Greenwood Waskom/Metcalf

     4,978         3,796         58     6           

Other

     33,830         8,625         47     15           
                                     

Total Haynesville Shale Trend

     158,749         88,722         49     85           
                                     

 

In December, 2010, we sold a significant amount of our shallow rights in several 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 $65.2 million, after normal closing adjustments.

 

As of December 31, 2010, we maintain ownership interests in acreage and/or wells in several additional fields including: the Midway field in San Patricio County, Texas and the Garfield Unit in Kalkaska County, Michigan.

 

See Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations in this report for additional information on our recent operations in the Haynesville Shale and Eagle Ford Shale trends.

 

Oil and Natural Gas Reserves

 

In December 2008, the SEC adopted new rules related to modernizing reserves definitions and disclosure requirements for oil and natural gas companies, which became effective prospectively for annual reporting periods ending on or after December 31, 2009. The new rules expand the definition of oil and gas producing activities to include the extraction of saleable hydrocarbons from oil sands, shale, coal beds or other nonrenewable natural resources that are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. The use of new technologies is now permitted in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Other definitions and terms were revised, including the definition of proved reserves, which was revised to indicate that entities must use the average of beginning-of-the-month commodity prices over the preceding 12-month period, rather than the end-of-period price, when estimating whether reserve quantities are economical to produce. Likewise, the 12-month average price is now used to estimate reserves utilized to compute depreciation, depletion and amortization. Another significant provision of the new rules is a requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of initial booking.

 

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The following tables set forth summary information with respect to our proved reserves as of December 31, 2010 and 2009, as estimated by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers. A copy of their summary reserve report for 2010 is included as an exhibit to this Annual Report on Form 10-K. See Note 15 “Oil and Gas Producing Activities (Unaudited)” to our consolidated financial statements for additional information.

 

     Proved Reserves at December 31, 2010  
     Developed
Producing
     Developed
Non-Producing
     Undeveloped      Total  
     (dollars in thousands)  

Net Proved Reserves:

           

Oil (MBbls) (1)

     703         43         872         1,618   

Natural Gas (MMcf)

     161,051         26,366         266,772         454,189   

Natural Gas Equivalent (MMcfe) (2)

     165,269         26,623         272,007         463,899   
                                   

Estimated Future Net Cash Flows

            $ 897,989   
                 

PV-10 (3)

            $ 362,126   

Discounted Future Income Taxes

              (3,448
                 

Standardized Measure of Discounted Net Cash Flows (3)

            $ 358,678   
                 
     Proved Reserves at December 31, 2009  
     Developed
Producing
     Developed
Non-Producing
     Undeveloped      Total  
     (dollars in thousands)  

Net Proved Reserves:

           

Oil (MBbls)(1)

     368         63         446         877   

Natural Gas (MMcf)

     142,134         20,801         252,366         415,301   

Natural Gas Equivalent (MMcfe) (2)

     144,343         21,176         255,042         420,561   
                                   

Estimated Future Net Cash Flows

            $ 424,983   
                 

PV-10 (3)

            $ 148,165   

Discounted Future Income Taxes

              (941
                 

Standardized Measure of Discounted Net Cash Flows (3)

            $ 147,224   
                 

 

(1) Includes condensate.
(2) Based on ratio of six Mcf of natural gas per Bbl of oil.
(3) PV-10 represents the discounted future net cash flows attributable to our proved oil and 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 standard measure of discounted future net cash flows of proved reserves, or standardized measure, as of December 31, 2010 was $358.7 million. See the reconciliation of our PV-10 to the standardized measure of discounted future net cash flows in the table above.

 

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

 

     December 31, 2010  

Area

   Proved
Developed
     Proved
Undeveloped
     Proved
Reserves
     % of
Total
 

Haynesville Shale Trend

     79,089         151,168         230,257         50

Cotton Valley Taylor Sand

     23,718         117,643         141,361         30

Eagle Ford Shale Trend

     2,855                 2,855         1

Other

     86,230         3,196         89,426         19
                                   

Total

     191,892         272,007         463,899         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 January 2010 through December 2010, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The average oil and natural gas prices used in such estimates as of December 31, 2010 were $4.38 per Mmbtu, of natural gas and $75.96 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, 2010 included in this Annual Report on Form 10-K was estimated wholly 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 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 Gas Reserves Information promulgated by the Society of Petroleum Engineers.

 

The Company’s principal engineer has over 30 years of experience in the oil and 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 wholly by Netherland, Sewell & Associates, Inc. (NSAI), as the Company’s 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.

 

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The Company considers the best control to ensure compliance with Rule 4-10 of Regulation S-X for reserve estimates is providing independent fully engineered third-party estimate of reserves from a nationally reputable petroleum engineering firm.

 

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 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 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. 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 proved undeveloped reserves at December 31, 2010, as estimated by NSAI, were 272.0 Bcfe, consisting of 266.8 Bcf of natural gas and 0.9 MMBbls of oil and condensate. In 2010 we added approximately 40 Bcfe related to the Haynesville and Cotton Valley Taylor Sand formations, we had revisions of approximately 7 Bcfe and we developed approximately 16 Bcfe or 6.2% of our total proved undeveloped reserves booked as of December 31, 2009 through the drilling of 6 gross (3.5 net) development wells at an aggregate capital cost of approximately $25.4 million. During 2010, we sold oil and natural gas properties which included 32.5 Bcfe of natural gas of proved developed reserves. None of our proved undeveloped reserves at December 31, 2010 have remained undeveloped for more than five years since the date of initial booking as proved undeveloped reserves, or are scheduled for commencement of development in our December 31, 2010 reserve report on a date more than five years from the date the reserves were initially booked as proved undeveloped.

 

Productive Wells

 

The following table sets forth the number of productive wells in which we maintain ownership interests as of December 31, 2010:

 

     Oil      Natural Gas      Total  
     Gross (1)      Net (2)      Gross (1)      Net (2)      Gross (1)      Net (2)  

South Texas

     6         4.1                         6         4.1   

East Texas

     2         1.1         250         238.2         252         239.3   

Northwest Louisiana

                     101         42.5         101         42.5   

Other

     8         3.3         15         0.2         23         3.5   
                                                     

Total Productive Wells

     16         8.5         366         280.9         382         289.4   
                                                     

 

(1) We only engineer royalty and overriding interest wells that have PV-10 large enough to include in the reserve report consequently only 4 wells with royalty and overriding interest are included.
(2) Net working interest.

 

Productive wells consist of producing wells and wells capable of production, including 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, 46 wells had completions in multiple producing horizons.

 

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Acreage

 

The following table summarizes our gross and net developed and undeveloped acreage under lease as of December 31, 2010. 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

     1,240         902         65,796         36,892         67,036         37,794   

East Texas

     94,584         55,788         50,213         31,827         144,797         87,615   

Northwest Louisiana

     53,611         24,383         11,624         6,993         65,235         31,376   

Other

                     1,920         19         1,920         19   
                                                     

Total

     149,435         81,073         129,553         75,731         278,988         156,804   
                                                     

 

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 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 natural gas and oil 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 acreage, including optioned acreage, expires during the next four years at the rate of 13,238 net acres in 2011 and 14,683 net acres in 2012, 4,107 net acres in 2013 and 448 net acres in 2014, unless included in producing units or extended prior to lease expiration. Substantially all of the 2011 lease expirations are within the Cotton and Cotton South fields where the Company recently sold all of its shallow rights and where it has no current plans to drill any deep wells.

 

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 under our joint development agreement and drill Haynesville Shale wells on our jointly-owned North Louisiana acreage.

 

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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,  
     2010      2009      2008  
     Gross      Net      Gross      Net      Gross      Net  

Development Wells:

                 

Productive

     44         18.9         43         23.6         107         65.9   

Non-Productive

                                     2         1.1   
                                                     

Total

     44         18.9         43         23.6         109         67.0   
                                                     

Exploratory Wells:

                 

Productive

     3         2.3         2         1.0         17         8.4   

Non-Productive

                                               
                                                     

Total

     3         2.3         2         1.0         17         8.4   
                                                     

Total Wells:

                 

Productive

     47         21.2         45         24.6         124         74.3   

Non-Productive

                                     2         1.1   
                                                     

Total

     47         21.2         45         24.6         126         75.4   
                                                     

 

At December 31, 2010, the Company had 4 gross (2.2 net) development wells in process of being drilled.

 

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Net Production, Unit Prices and Costs

 

The following table presents certain information with respect to natural gas and oil production attributable to our interests in all of our properties (including each of the two fields which are attributed more than 15% of our total proved reserves as of December 31, 2010), 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, 2010.

 

     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 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   
                                                              

For Year 2009

                    

Haynesville Shale Trend

     7,960         1         7,966       $ 2.13       $ 55.00       $ 2.14       $ 0.19   

Cotton Valley Taylor Sand

     926         3         945         2.68         54.33         2.79         0.18   

Eagle Ford Shale Trend

                                                       

Other

     20,005         147         20,885         4.16         53.63         4.37         1.37   
                                                              

Total

     28,891         151         29,796       $ 3.55       $ 53.65       $ 3.72       $ 1.01   
                                                              

For Year 2008

                    

Haynesville Shale Trend

     157                 157         8.11                 8.11         0.78   

Cotton Valley Taylor Sand

                                                       

Eagle Ford Shale Trend

                                                       

Other

     23,017         167         24,019         8.59         97.70         8.92         1.32   
                                                              

Total

     23,174         167         24,176       $ 8.59       $ 97.70       $ 8.91       $ 1.32   
                                                              

 

(1) Excludes the impact of commodity derivatives.
(2) Excludes ad valorem and severance taxes.

 

In addition, two of our fields, the Bethany Longstreet and Beckville fields each account for more than 15% of our estimated proved reserves as of December 31, 2010. 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 2010

        

Bethany Longstreet

     10,398         2         10,412   

Beckville

     6,259         37         6,483   

For Year 2009

        

Bethany Longstreet

     6,538         5         6,567   

Beckville

     4,946         47         5,225   

For Year 2008

        

Bethany Longstreet

     2,884         5         2,914   

Beckville

     4,176         39         4,413   

For Year 2007

        

Bethany Longstreet

     2,875         7         2,914   

Beckville

     4,340         37         4,560   

 

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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, 2010, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Results of Operations”.

 

Oil and Gas Marketing and Major Customers

 

Marketing.    Essentially all of our natural gas production is sold under spot or market-sensitive contracts to various gas purchasers on short-term contracts. Our condensate and crude 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 gas revenues for the year ended December 31, 2010 was as follows:

 

     2010  

Louis Dreyfus Corporation

     29

Shell Energy

     17

 

Competition

 

The oil and gas industry is highly competitive. Major and independent oil and gas companies, drilling and production acquisition programs and individual producers and operators are active bidders for desirable oil and 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 17, 2011, we had 116 full-time employees in our two administrative offices and one field office, 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 natural gas and oil production depends upon numerous factors beyond our control. These factors include regulation of natural gas and oil 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 natural gas and oil 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 natural gas and oil, protect rights to produce natural gas and oil between owners in a common reservoir, control the amount of natural gas and oil 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 Matters

 

General

 

Our operations are subject to stringent and complex federal, state and local laws and regulations governing 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 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 and require remedial measures to mitigate pollution from former and ongoing 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.

 

The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations that result in more stringent and costly 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 this trend will continue in the future.

 

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 the 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 which impose requirements related to the handling and disposal of solid and hazardous wastes. While there exists an exclusion under RCRA from the definition of hazardous wastes for certain materials generated in the exploration, development or production of oil and gas, these wastes may be regulated by the U.S. Environmental Protection Agency (the “EPA”) and state environmental agencies as non-hazardous “solid” wastes. Moreover, we generate petroleum product wastes and ordinary industrial wastes that may be regulated as solid and hazardous wastes. The EPA and state agencies have imposed stringent requirements for the disposal of hazardous and solid wastes.

 

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

 

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petroleum hydrocarbons was 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

 

The Federal Water Pollution Control Act, as amended, (“Clean Water Act”), and analogous state law, 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. 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 (“OPA”) imposes a variety of requirements related to the prevention of oil spills into navigable waters. OPA subjects owners of facilities to strict, joint and several liabilities for specified oil removal costs and certain other damages including natural reservoir damages arising from a spill.

 

The disposal of oil and gas wastes into underground injection wells are subject to the Safe Drinking Water Act as well as analogous state laws. Under Part C of the Safe Drinking Water Act, 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. In addition to the underground injection operations, our activities include the performance of hydraulic fracturing services to enhance any production of natural gas from formations with low permeability, such as shales. Hydraulic fracturing is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injunction Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012, and a committee of the U.S. House of Representatives is conducting an investigation of hydraulic fracturing practices. In addition, legislation was proposed in the recently completed session of Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process, and such legislation could be introduced in the current session of Congress. Moreover, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could increase our costs of compliance, impose operational delays, and make it more difficult to perform hydraulic fracturing, resulting in reduced amounts of oil and natural gas being produced.

 

Air Emissions

 

The Federal Clean Air Act, as amended, and comparable state laws, regulates emissions of various air pollutants from many sources in the United States, including crude oil and natural gas production activities. 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 air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations.

 

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Climate Change.    In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gasses are contributing to the warming of the earth’s atmosphere and other climate changes, the EPA has adopted regulations under existing provisions of the CAA that require a reduction in emissions of GHGs from motor vehicles and also trigger construction and operating permit review for GHG emissions from certain stationary sources, effective January 2, 2011. The EPA has published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs, pursuant to which these permitting programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing or requiring state environmental agencies to implement the rules. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage, and distribution activities, which may include certain of our operations, beginning in 2012 for emissions occurring in 2011.

 

In addition, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to 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 and analogous state laws restrict activities that could have an adverse effect on threatened or endangered species or their habitats. While 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. 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 (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires 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.

 

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Other Laws and Regulations

 

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

 

Item 1A. Risk Factors

 

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

 

The Company has made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with Company management, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company’s operations, economic performance and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and 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 Company’s 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;

 

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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 the Company or its subsidiary are doing business;

 

   

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

 

   

the creditworthiness of the Company’s financial counterparties and operation partners;

 

   

the securities, capital or credit markets;

 

   

the Company’s ability to repay its debt, including its convertible senior notes due 2026 that it may be required to repurchase in December 2011; and

 

   

other factors discussed below and elsewhere in this Form 10-K and in the Company’s other public filings, press releases and discussions with Company 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 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 gas prices in 2010. These prices will change and may be lower at the time of production than those prices that prevailed during 2010. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and 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 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 gas that are ultimately recovered;

 

   

the production and operating costs incurred;

 

   

the amount and timing of future development expenditures; and

 

   

future oil and 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 gas reserves

 

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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 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 gas industry in general.

 

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

 

Our domestic 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, 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.

 

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

 

The United States Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the Act, the CFTC has proposed regulations to set 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 would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new 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 that 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 legislation and regulations, our results of operations may become more volatile

 

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and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation 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 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 operations are subject to environmental and operational 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, 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, air emissions and wastewater discharges related to our operations, and 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 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.

 

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Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas we produce.

 

In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that require a reduction in emissions of GHGs from motor vehicles and also may trigger Prevention of Significant Deterioration (“PSD”) and Title V permit requirements for GHG emissions from certain stationary sources when the motor vehicle standards took effect on January 2, 2011. The EPA rules have tailored the PSD and Title V permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. The EPA also published a final rule on November 30, 2010 expanding its existing GHG emissions reporting rule to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage, and distribution activities, which may include certain of our operations, beginning in 2012 for emissions occurring in 2011. In addition, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce.

 

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely demand for the oil and natural gas we produce.

 

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 formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012, and a committee of the U.S. House of Representatives is conducting an investigation of hydraulic fracturing practices. In addition, legislation was proposed in the recently completed session of Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process, and such legislation could be introduced in the current session of Congress. Moreover, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could increase our costs of compliance, impose operational delays, and make it more difficult to perform hydraulic fracturing, resulting in reduced amounts of oil and natural gas being produced.

 

Our estimates of proved reserves have been prepared under SEC rules which went into effect for fiscal years ending on or after December 31, 2009, which may make comparisons to prior periods difficult and could limit our ability to book additional proved undeveloped reserves in the future.

 

This report presents estimates of our proved reserves as of December 31, 2010, which have been prepared and presented under SEC rules. These rules are effective for fiscal years ending on or after December 31, 2009, and require SEC reporting companies to prepare their reserves estimates using revised reserve definitions and revised pricing based on twelve-month unweighted first-day-of-the-month average pricing. The previous rules required that reserve estimates be calculated using last-day-of-the-year pricing. The pricing that was used for estimates of our reserves as of December 31, 2010 and 2009 was based on an unweighted average twelve month

 

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West Texas Intermediate (“WTI”) posted price of $75.96 per Bbl for oil and a Henry Hub Spot price of $4.38 per MMBtu for natural gas, as compared to $57.65 per Bbl for oil and $3.87 per MMBtu for natural gas as of December 31, 2009. As a result of these changes, direct comparisons of our reserves amounts under the rules may be more difficult.

 

Another impact of the SEC rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This rule has limited and may continue to limit our potential to book additional proved undeveloped reserves as we pursue our drilling program, particularly as we develop our significant acreage in shale plays in East Texas, Northwest Louisiana and South Texas. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill on those reserves within the required five-year timeframe.

 

The SEC has released only limited interpretive guidance regarding reporting of reserve estimates under the rules and may not issue further interpretive guidance on the rules. Accordingly, while the estimates of our proved reserves at December 31, 2010 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the SEC rules, those estimates could differ materially from any estimates we might prepare applying more specific future SEC interpretive guidance.

 

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 gas prices;

 

   

limitations in the market for oil and gas;

 

   

title problems;

 

   

compliance with governmental regulations;

 

   

mechanical difficulties; and

 

   

risks associated with horizontal drilling.

 

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

 

In addition, while lower oil and gas prices may reduce the amount of oil and natural gas that we can produce economically, higher oil and gas prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, such drilling equipment, services and personnel. Such shortages

 

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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.

 

Natural gas and oil prices are volatile; a sustained decrease in the price of natural gas or oil 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 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 natural gas and oil 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. Prices for natural gas increased slightly in 2010 but still have remained low 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 natural gas and oil 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 natural gas and oil 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.

 

Our use of gas and oil 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 natural gas and oil 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 43% of our total production volumes for the year ended December 31, 2010.

 

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 natural gas and oil. For the years ended December 31, 2010 and 2009, we realized a gain on settled natural gas derivatives of $24.6 million and $98.0 million, respectively. For the year ended December 31, 2008, we realized a loss on settled commodity derivatives of $1.8 million.

 

For the year ended December 31, 2010, we recognized in earnings an unrealized gain on commodity derivative instruments not designated as hedges of $30.7 million. For financial reporting purposes, this unrealized gain was combined with a $24.6 million realized gain resulting in a total gain on commodity derivative instruments not designated as hedges of $55.3 million for 2010.

 

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For the year ended December 31, 2009, we recognized in earnings an unrealized loss on commodity derivative instruments not designated as hedges of $50.2 million. For financial reporting purposes, this unrealized loss was combined with a $98.0 million realized gain resulting in a total gain on commodity derivative instruments not designated as hedges of $47.8 million for 2009.

 

For the year ended December 31, 2008, we recognized in earnings an unrealized gain on commodity derivative instruments not designated as hedges of $55.4 million. For financial reporting purposes, this unrealized gain was combined with a $1.8 million realized loss resulting in a total gain on commodity derivative instruments not designated as hedges of $53.6 million for 2008.

 

We account for our natural gas and oil 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 collars 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” to our consolidated financial statements for further discussion.

 

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 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, develop or acquire additional oil and 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 58.5% of our total estimated proved reserves by volume at December 31, 2010, 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 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 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, 2010, 2009 and 2008, we recorded impairments related to oil and gas properties of $234.9 million, $208.9 million and $28.6 million, respectively.

 

Management’s assumptions used in calculating oil and 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, 2010, and all our production during 2010 were associated with our Northwest Louisiana, East Texas and South Texas properties which include the Haynesville Shale and Eagle Ford Shale, respectfully. 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 and Matador Resources Company operate 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 gas may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions.

 

We operate primarily in the Northwest Louisiana, East Texas and South Texas areas. Northwest Louisiana and East Texas is in the same geographic region as the Haynesville Shale. A number of companies are currently operating in the Haynesville Shale. If drilling in the Haynesville Shale and Eagle Ford Shale 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 the 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 gas to interstate pipelines. In such 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 NYMEX or that we currently project, which would adversely affect our results of operations.

 

A portion of our natural gas and oil 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.

 

On February 4, 2011, we entered into a third amendment to our senior credit facility revising our interest coverage ratio from 3.0x to 2.5x to take into consideration additional non-cash interest related to the adoption of APB 14-1 in December 2009.

 

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, 2010, 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. In addition, our current senior credit facility matures in August 2011. Any replacement credit facility may have more restrictive covenants or provide us with less borrowing capacity.

 

We will need to obtain additional borrowings or other funding in the event holders of our $175 million 3.25% Convertible Senior Notes Due 2026 require us to purchase some or all of the notes on December 1, 2011.

 

Holders of our $175 million principal amount 3.25% Convertible Senior Notes Due 2026 have the right to require us to purchase some or all of such notes at par on December 1, 2011. Because the conversion price of those notes is substantially above recent trading price of our common stock, it is more likely that notes will be put to us for repurchase on such date. Accordingly, we must incur additional borrowings or seek other sources of funding to repay any such notes that are required to be repurchased. These additional borrowings may be on terms less favorable than our current indebtedness or may be subject to more restrictive covenants. Obtaining funding from other sources, such as the sale or participation of some of our properties or assets, could have an adverse impact on our capital spending for exploration and development.

 

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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 in exact 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, platform or pipeline. We cannot necessarily observe structural and environmental problems, such as pipeline corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities relating to the acquired assets and indemnities are unlikely to cover liabilities relating to the time periods after closing. We may be required to assume any risk relating to the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. The incurrence of an unexpected liability could have a material adverse effect on our financial position and results of operations.

 

Competition in the oil and 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 gas 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 gas business involves certain operating hazards such as well blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, formations with abnormal pressures, pollution, releases of toxic gas and other environmental hazards and risks. Any of these operating hazards could result in substantial losses to us. As a result, substantial liabilities to third parties or governmental entities may be incurred. The payment of these amounts could reduce or eliminate the funds available for exploration, development or acquisitions. These reductions in funds could result in a loss of our properties. Additionally, some of our oil and 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. In accordance with customary industry practices, we maintain insurance against some, but not all, of such risks and losses. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

 

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

 

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

 

   

personal injury;

 

   

bodily injury;

 

   

third party property damage;

 

   

medical expenses;

 

   

legal defense costs;

 

   

pollution in some cases;

 

   

well blowouts in some cases; and

 

   

workers compensation.

 

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

 

Terrorist attacks or similar hostilities may adversely impact our results of operations.

 

The impact that future terrorist attacks or regional hostilities (particularly in the Middle East) may have on the energy industry in general, and on us in particular, is unknown. Uncertainty surrounding military strikes or a sustained military campaign may affect our operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. Moreover, we have incurred additional costs since the terrorist attacks of September 11, 2001 to safeguard certain of our assets and we may be required to incur significant additional costs in the future.

 

The terrorist attacks on September 11, 2001, and the changes in the insurance markets attributable to such attacks have made certain types of insurance more difficult for us to obtain. There can be no assurance that insurance will be available to us without significant additional costs. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

 

Item 1B. Unresolved Staff Comments

 

None.

 

Item 3. Legal Proceedings

 

A discussion of current legal proceedings is set forth in Part II, Item 8 Financial Statements, under Note 9—Commitments and Contingencies to our Consolidated Financial Statements in this Form 10-K.

 

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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 under the symbol “GDP”.

 

At February 14, 2011, the number of holders of record of our common stock without determination of the number of individual participants in security positions was 1,332 and 37,672,853 shares outstanding. High and low sales prices for our common stock for each quarter during 2010 and 2009 were as follows:

 

     2010      2009  
     High      Low      High      Low  

First Quarter

   $ 25.83       $ 15.52       $ 34.07       $ 14.93   

Second Quarter

     19.19         11.26         30.03         19.27   

Third Quarter

     14.81         11.16         27.56         21.43   

Fourth Quarter

     17.71         12.51         30.38         20.38   

 

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, 2010. 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 2010, we withheld 65,589 shares of common stock from issuance in this manner and paid $1.1 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 S&P Small-Cap Index. An investment of $100 is assumed to have been made in the Company’s common stock and the indexes on December 31, 2005 and its relative performance is tracked through December 31, 2010.

 

LOGO

 

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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  
     2010     2009     2008     2007     2006  
     (In thousands, except per share amounts)  

Revenues:

          

Oil and gas revenues

   $ 148,031      $ 110,784      $ 215,369      $ 110,691      $ 73,933   

Other

     302        (358     682        614        838   
                                        
     148,333        110,426        216,051        111,305        74,771   
                                        

Operating Expenses:

          

Lease operating expense

     26,306        30,188        31,950        22,465        12,688   

Production and other taxes

     3,627        4,317        7,542        2,272        3,345   

Transportation

     9,856        9,459        8,645        5,964        3,791   

Depreciation, depletion and amortization

     105,913        160,361        107,123        79,766        37,225   

Exploration

     10,152        9,292        8,404        7,346        5,888   

Impairment of oil and gas properties

     234,887        208,905        28,582        7,696        9,886   

General and administrative

     30,918        27,923        24,254        20,888        17,223   

Loss (gain) on sale of assets

     2,824        (297     (145,876     (42     (23

Other

     4,268                      109          
                                        
     428,751        450,148        70,624        146,464        90,023   
                                        

Operating income (loss)

     (280,418     (339,722     145,427        (35,159     (15,252
                                        

Other income (expense):

          

Interest expense

     (37,179     (26,148     (22,410     (17,878     (8,343

Interest income and other

     117        458        1,682        11,469        (7,660

Gain (loss) on derivatives not designated as hedges

     55,275        47,115        51,547        (6,439     38,128   

Loss on early extinguishment of debt

                                 (612
                                        
     18,213        21,425        30,819        (12,848     21,513   
                                        

Income (loss) before income taxes

     (262,205     (318,297     176,246        (48,007     6,261   

Income tax (expense) benefit

     85        67,311        (54,472     9,294        (4,940
                                        

Net income (loss)

     (262,120     (250,986     121,774        (38,713     1,321   

Preferred stock dividends

     6,047        6,047        6,047        6,047        6,016   

Preferred stock redemption premium

                                 1,545   
                                        

Net income (loss) applicable to common stock

   $ (268,167   $ (257,033   $ 115,727      $ (44,760   $ (6,240
                                        

PER COMMON SHARE

          

Net income (loss) applicable to common stock—basic

   $ (7.47   $ (7.17   $ 3.42      $ (1.75   $ (0.25

Net income (loss) applicable to common stock—diluted

   $ (7.47   $ (7.17   $ 3.23      $ (1.75   $ (0.25

Weighted average common shares outstanding—basic

     35,921        35,866        33,806        25,578        24,948   

Weighted average common shares outstanding—diluted

     35,921        35,866        40,397        25,578        25,412   

Balance Sheet Data:

  

Total assets

   $ 664,577      $ 860,274      $ 1,038,287      $ 589,233      $ 478,573   

Total long-term debt

     179,171        330,147        226,723        185,449        165,216   

Stockholders’ equity

     183,972        445,385        665,348        312,781        228,026   

 

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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 report in Item 8, and the information set forth in Risk Factors under Item 1A.

 

Overview

 

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

 

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

 

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

 

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

 

Our revenues and operating cash flow are dependent on the successful development of our inventory of capital projects with available capital, the volume and timing of our production, as well as commodity prices for oil and gas. 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 adding reserve value through the development of our Haynesville Shale and Eagle Ford Shale acreage and the timely development of our large relatively low risk development program in the East Texas and North Louisiana and South Texas area. We regularly evaluate possible acquisitions of prospective acreage and oil and gas drilling opportunities.

 

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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 production and reserve growth potential. We intend to concentrate on developing our multi-year inventory of drilling locations in the Eagle Ford Shale, Haynesville Shale and Cotton Valley Taylor sand on our acreage in order to develop our natural gas and oil reserves. We estimate that our Eagle Ford Shale acreage currently includes over 400 gross unrisked, non-proved drilling locations. Our Haynesville Shale acreage currently includes more than 1,200 gross unrisked, non-proved drilling locations based on anticipated well spacing and our Cotton Valley Taylor sand inventory includes more than 200 gross unrisked, non-proved drilling locations based on anticipated well spacing.

 

   

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

 

   

Expand acreage position in the Haynesville and Eagle Ford shale plays. We have increased our acreage position in the Haynesville Shale to 158,749 gross (88,722 net) lease acres and own approximately 67,000 gross (38,000 net) of lease acres in the Eagle Ford Shale as of December 31, 2010. 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 within our existing areas of operation that exhibit similar characteristics to our existing properties. We continually strive to rationalize our portfolio of properties by selling marginal properties in an effort to redeploy capital to exploitation, development and exploration projects that offer a potentially higher overall return.

 

   

Focus on maximizing cash flow margins. We intend to maximize cash flow margins by focusing on higher-margin oil development in the Eagle Ford Shale trend and lowering our overall operating costs in our natural gas properties. In the current commodity price environment, our Eagle Ford Shale assets offer more attractive cash flow margins than our natural gas assets. From 2008 to 2010, we lowered our lease operating costs on a consolidated basis from $1.32 per Mcfe to $0.78 per Mcfe by focusing on lower cost Haynesville Shale potential and divesting higher cost mature assets. We expect this trend to continue as it relates to our natural gas properties.

 

   

Maintain financial flexibility. As of December 31, 2010, we had a borrowing base of $225 million under our senior credit facility, of which none was outstanding. We have historically funded growth through cash flow from operations, 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, typically fixed price swaps and costless collars. The level of our hedging activity and the duration of the instruments employed depend upon our view of market conditions, available hedge prices and our operating strategy.

 

2010 Overview

 

   

We achieved annual production volume growth of 13% with production volume growing from 29.8 Bcfe in 2009 to 33.7 Bcfe in 2010.

 

   

We ended the year with estimated proved reserves of approximately 463.9 Bcfe (approximately 454.2 Bcf of natural gas and 1.6 MMBbls of oil and condensate), with a PV-10 of $362.1 million and a standardized measure of $358.7 million, approximately 41% of which is proved developed.

 

   

We conducted drilling operations on 36 gross wells (12.7 net) in the Haynesville Shale trend and added 23 gross (8.8 net) wells to production in 2010. As of December 31, 2010, we had 13 gross (4.0 net) wells drilled but awaiting completion.

 

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We acquired lease acreage in the Eagle Ford Shale trend where we conducted drilling operation on 6 gross (4.1 net wells) all of which were added to production in 2010.

 

   

We sold our shallow rights in our non-core high cost properties for approximately $70 million before normal closing adjustments recognizing a loss on sale of assets of $2.8 million.

 

   

We reduced our lease operating expense per Mcfe by 23% from $1.01 in 2009 to $0.78 per Mcfe in 2010.

 

   

We recorded an impairment expense of $234.9 million on our non-core properties

 

   

We decreased our depletion expense by 42% from $5.38 per Mcfe in 2009 to $3.14 per Mcfe in 2010.

 

Eagle Ford Shale Trend

 

During the second half of 2010, the Company commenced drilling operations on its acreage in the Eagle Ford Shale Trend. The Company’s leasehold position is located in both La Salle and Frio counties, Texas. During 2010, the Company conducted drilling operations on approximately 8 gross (6 net) operated Eagle Ford Shale Trend wells. During December 2010, the Company commenced drilling operations with a second rig on its Eagle Ford Shale Trend acreage. In 2011, the Company plans to spend approximately $145 million on 20 to 24 gross wells.

 

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 continue to build our acreage position in this trend and hold 158,749 gross acres as of December 31, 2010 producing from and prospective for the Haynesville Shale. As of year- end 2010, we drilled and completed a cumulative total of 85 wells in the trend with a 100% success rate. Our net production volumes from our Haynesville Shale wells aggregated approximately 47,000 Mcfe per day in 2010, or approximately 51% of our total oil and gas production for the year. Our 2011 capital expenditure budget includes plans to utilize approximately 1 to 3 rigs to conduct drilling operations on approximately 7 to 9 gross additional Haynesville Shale horizontal wells.

 

Core Haynesville Shale

 

The Company’s core Haynesville shale drilling program is primarily concentrated in the Bethany-Longstreet and Greenwood-Waskom fields in Caddo and DeSoto Parishes in northwest Louisiana. The Company’s core Haynesville Shale drilling activity includes both operated and non-operated drilling in and around its core acreage positions in northwest Louisiana. The Company continues to build its acreage position in the trend and currently holds approximately 30,000 gross (16,000 net) acres as of December 31, 2010. The Company’s net production volumes from its core Haynesville Shale wells totaled approximately 37,000 Mcfe per day in 2010, or approximately 40% of the Company’s total production for the year. In 2011, the Company estimates that it will spend approximately $25 to 30 million on 5 to 7 gross wells.

 

Shelby Trough / Angelina River Trend

 

During the second half of 2010, the Company spud its first Haynesville & Bossier Shale wells in the Shelby Trough / Angelina River Trend area. The Company operates all of its drilling activities, which are primarily located in Nacogdoches, Angelina and Shelby counties, Texas. The Company continues to build its acreage position in the trend and currently holds approximately 48,500 gross (27,000 net) acres as of December 31, 2010. The Company’s net production volumes from its Shelby Trough wells totaled approximately 1,300 Mcfe per day in 2010, or approximately 1% of the Company’s total production for the year. In 2011, the Company estimates that it will spend approximately $20 to 30 million on 2 to 3 gross wells.

 

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Cotton Valley Taylor Sand

 

During 2010, the Company conducted drilling operations on four horizontal Cotton Valley Taylor Sand wells throughout its acreage position in the Minden, Beckville and South Henderson fields of East Texas. In the South Henderson field, the Company’s Travis Crow 1H well reached initial production of over 12.0 MMcfe/day, which included approximately 380 Bbls of oil per day. In 2011, the Company plans to spend approximately $20 – 25 million to drill three offset wells in its South Henderson field. The Company has approximately 56,000 gross (49,000) net acres prospective for the Cotton Valley Taylor Sand. The Company’s net production volumes from its Cotton Valley Taylor Sand wells totaled approximately 7,000 Mcfe per day in 2010, or approximately 8% of the Company’s total oil and gas production for the year.

 

During 2010, we drilled and completed 4 gross (4 net) oil wells with a 100% success rate in the play. Our 2011 capital expenditure budget includes plans to utilize approximately 1 rig to conduct drilling operations on approximately 3 gross (3 net) additional Cotton Valley horizontal wells.

 

Results of Operations

 

For the year ended December 31, 2010, we reported net loss applicable to common stock of $268.2 million, or $7.47 per share (basic and diluted), on operating revenues of $148.3 million. This compares to net loss applicable to common stock of $257.0 million, or $7.17 per share (basic and diluted, for the year ended December 31, 2009 and a net income applicable to common stock of $115.7 million, or $3.42 per share (basic) and $3.23 per share (diluted) for the year ended December 31, 2008.

 

The following table reflects our summary operating information for the periods presented in thousands except for price and volume data.

 

Summary Operating Information:

  Year End December 31,     Year End December 31,  
  2010     2009     Variance     2009     2008     Variance  

Revenues:

               

Natural gas

  $ 136,527      $ 102,692      $ 33,835        33   $ 102,692      $ 199,057      $ (96,365     (48 %) 

Oil and condensate

    11,504        8,092        3,412        42     8,092        16,312        (8,220     (50 %) 

Natural gas, oil and condensate

    148,031        110,784        37,247        33     110,784        215,369        (104,585     (49 %) 

Operating revenues

    148,333        110,426        37,907        34     110,426        216,051        (105,625     (49 %) 

Operating expenses

    428,751        450,148        (21,397     (5 %)      450,148        70,624        379,524        537

Operating income (loss)

    (280,418     (339,722     (59,304     (17 %)      (339,722     145,427        (485,149     (334 %) 

Net income (loss) applicable to common stock

    (268,167     (257,033     (11,134     4     (257,033     115,727        (372,760     (322 %) 

Net Production:

             

Natural gas (MMcf)

    32,815        28,891        3,924        14     28,891        23,174        5,717        25

Oil and condensate (MBbls)

    150        151        (1     (1 %)      151        167        (16     (10 %) 

Total (MMcfe)

    33,716        29,796        3,920        13     29,796        24,176        5,620        23

Average daily production (Mcfe/d)

    92,373        81,632        10,741        13     81,632        66,054        15,578        24

Average Realized Sales Price Per Unit:

             

Natural gas (per Mcf)

  $ 4.16      $ 3.55      $ 0.61        17   $ 3.55      $ 8.59      $ (5.04     (59 %) 

Oil and condensate (per Bbl)

    76.59        53.65        22.94        43     53.65        97.70        (44.05     (45 %) 

Average realized price (per Mcfe)

    4.39        3.72        0.67        18     3.72        8.91        (5.19     (58 %) 

 

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Oil and Gas Revenue

 

Oil and gas revenues increased $37.2 million or 33% to $148.0 million in 2010 compared to $110.8 million in 2009. The 18% increase in average sales price compared to 2009 contributed approximately $22.7 million to the increase in oil and gas revenue while the net production increase of 13% compared to 2009 contributed approximately $15.5 million to the increase in oil and gas revenue. Our average realized sales price was $4.39 per Mcfe in 2010 compared to $3.72 per Mcfe in 2009. Sales prices are dictated by the market. We increased production by the continued development of our Haynesville Shale assets. The drilling and completion of 40 wells in our Northwest Louisiana and East Texas, 36 of which were in the Haynesville Shale, resulted in the continued trend of annual natural gas production growth for the Company.

 

Oil and gas revenues decreased $104.6 million to $110.8 million in 2009, a decrease of 49% from 2008. The oil and gas revenue reduction attributable to the realized price decrease was $125.5 million while the increase in production offset that decrease by $20.9 million. We did increase our daily production average to 81.6 MMcfe per day in 2009 from 66.1 Mmcfe per day in 2008, or 24%. The drilling and completion of 45 wells in our Northwest Louisiana and East Texas area, 32 of which were in the Haynesville Shale, resulted in the continued trend of annual natural gas production growth for the Company.

 

Operating Expenses

 

Operating expenses of $428.8 million in 2010 included a $234.9 million asset impairment, a $2.8 million loss on sale of assets and other expense of $4.3 million. Eliminating these non-comparable items from the operating expenses in both 2010 and 2009, the adjusted operating expense of $186.8 million in 2010 decreased 23% or $54.7 million from adjusted operating expense of $241.5 million in 2009. This decrease is primarily attributed to lower lease operating expense on our Haynesville Shale wells and decreased depreciation, depletion and amortization (“DD&A”) expense because of a lower DD&A rate. The DD&A rate reduction was primarily due to the impairment writedown of the carrying value of our oil and gas properties and the addition of the Haynesville Shale reserves with its relatively lower pending costs.

 

Operating expenses totaled $450.1 million for the year ended December 31, 2009. Operating expenses of $70.6 million in 2008 included a $145.9 million gain on sale of assets. Excluding the gain on sales of assets and impairment expense for both 2009 and 2008, operating expense of $241.5 million in 2009 increased 29% or $53.6 million over operating expense of $187.9 million in 2008. This increase is primarily attributed to increased DD&A expense because of a higher DD&A rate and increased production in 2009. Our operating loss of $339.7 million in 2009 is primarily attributed to the previously mentioned impairment charge totaling $208.9 million, a substantial reduction in revenues in 2009 versus 2008 and the increased DD&A expense.

 

     Year Ended December 31,     Year Ended December 31,  
(in thousands)    2010      2009      Variance     2009      2008      Variance  

Lease operating expenses

   $ 26,306       $ 30,188       $ (3,882     (13 %)    $ 30,188       $ 31,950       $ (1,762     (6 %) 

Production and other taxes

     3,627         4,317         (690     (16 %)    $ 4,317         7,542         (3,225     (43 %) 

Transportation

     9,856         9,459         397        4   $ 9,459         8,645         814        9

Exploration

     10,152         9,292         860        9   $ 9,292         8,404         888        11
     Year Ended December 31,     Year Ended December 31,  
Per Mcfe    2010      2009      Variance     2009      2008      Variance        

Lease operating expenses

   $ 0.78       $ 1.01       $ (0.23     (23 %)    $ 1.01       $ 1.32       $ (0.31     (23 %) 

Production and other taxes

     0.11         0.14         (0.03     (21 %)      0.14         0.31         (0.17     (55 %) 

Transportation

     0.29         0.32         (0.03     (9 %)      0.32         0.36         (0.04     (11 %) 

Exploration

     0.30         0.31         (0.01     (3 %)      0.31         0.35         (0.04     (11 %) 

 

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Lease Operating Expense

 

Lease operating expense (“LOE”) for the year 2010 was $26.3 million, a decrease of $3.9 million or 13% from the $30.2 million for the year 2009. On a per unit basis, LOE decreased 23% from $1.01 to $0.78 per Mcfe for the year 2010 compared to 2009. The overall cost decrease is attributable to lower saltwater disposal cost as we realized a $2.1 million savings from the continued impact of a series of saltwater disposal systems installed in 2009 and a $1.8 million savings in compression costs as a result of more favorable rental contract rates. On a per unit basis, LOE decreased for the year 2010 compared to the year 2009 as a result of cost reductions, a 13% increase in production volumes and an increasing portion of our production coming from the lower production cost Haynesville Shale wells. We expect the LOE per unit of production to continue to decrease as a result of the lower cost Haynesville Shale making up a larger portion of our total production and having sold our higher cost non-core properties in December 2010.

 

LOE for the year 2009 was $30.2 million, a decrease of $1.8 million or 6% from the $32.0 million for the year 2008. On a per unit basis, LOE decreased 23% from $1.32 to $1.01 per Mcfe for the year 2009 compared to 2008. The overall cost decrease is attributable to lower saltwater disposal cost as we realized the continued impact of a new series of saltwater disposal system installations in 2009 and lower compressor rental costs negotiated in conjunction with current market conditions. The decrease in the unit cost between the years is attributable to the absolute dollar cost reduction, a 23% increase in production volumes and an increasing portion of our production coming from the Haynesville Shale, which carries lower production costs.

 

Production and Other Taxes

 

Production and other taxes for the year 2010 were $3.6 million which includes 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 Tight Gas Sands (“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. During the year 2009, production and other taxes were $4.3 million, which included production tax of $1.3 million and ad valorem tax of $3.0 million. Production tax in 2009 is net of $1.6 million of tax credits attributed to TGS credits for our wells in the State of Texas and $0.2 million severance tax relief related to the horizontal wells we have drilled in the State of Louisiana. The lower production tax for 2010 compared to 2009 is attributable to the increasing portion of our production coming from the Haynesville Shale horizontal wells, which are exempt for two years from State of Louisiana production tax.

 

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. We anticipate that we will incur a gradually lower production tax rate in the future as we add additional Texas qualifying wells to our production base and as reduced rates are approved.

 

The Louisiana horizontal wells are eligible for a two year severance tax exemption from the date of first production or until payout of qualified costs, whichever is first.

 

Ad valorem taxes decreased $0.5 million to $2.5 million in 2010 from $3.0 million in 2009. 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. Though the number of properties we owned increased from January 1, 2009 to January 1, 2010, the assessed values for our properties were lower year-to-year driven by decreased commodity prices.

 

During the year 2008, production and other taxes were $7.5 million, which included production tax of $5.5 million and ad valorem tax of $2.0 million. Production tax for 2008 is net of $3.2 million of TGS credits for our wells in the State of Texas. The lower production tax for 2009 compared to 2008 is attributable to decreased gas prices year- to- year. Also, an increasing portion of our production is attributable to Haynesville Shale horizontal wells, which are exempt for two years from State of Louisiana production tax.

 

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Ad valorem taxes increased $1.0 million to $3.0 million in 2009 from $2.0 million in 2008. The number of properties we owned increased from January 1, 2008 to January 1, 2009 and the assessed values for our existing properties were higher year-to-year. The combination of these two factors led to the increase in ad valorem taxes.

 

Transportation

 

Transportation expense increased 4% to $9.9 million ($0.29 per Mcfe) in 2010 compared to $9.5 million ($0.32 per Mcfe) in 2009. The increase in expense is primarily due to our higher production volumes and also up slightly due to a contractual annual volume deficiency charge related to non-core properties while the lower unit costs are a function of our changing geographic production mix, as well as a greater percentage of sales coming from non-operated properties from which the operator nets the transportation cost from revenues.

 

Transportation expense increased 9% to $9.5 million ($0.32 per Mcfe) in 2009 compared to $8.6 million ($0.36 per Mcfe) in 2008. The increase in expense is primarily due to our higher production volumes while the lower unit costs are a function of our changing geographic production mix, as well as a greater percentage of sales coming from non-operated properties from which the operator nets the transportation cost from revenues.

 

Exploration

 

Exploration expenses for 2010 increased $0.9 million to $10.2 million from $9.3 million for 2009, including a $6.0 million and $4.7 million for amortization of leasehold cost in 2010 and 2009, respectively.2010 exploration expenses include $1.3 million in seismic costs including exploratory seismic costs for our Angelina River area 3-D seismic program, slightly higher undeveloped leasehold cost amortization offset by a decrease in exploration labor cost as compared to 2009.

 

Exploration expenses for 2009 increased $0.9 million to $9.3 million from $8.4 million for 2008. 2009 exploration expenses include drilling contract early termination charges of $1.2 million.

 

    Year Ended December 31,     Year Ended December 31,  

(in thousands)

  2010     2009     Variance     2009     2008     Variance  

Depreciation, depletion & amortization

  $ 105,913      $ 160,361      $ (54,448     (34 %)    $ 160,361      $ 107,123      $ 53,238        50

Impairment

    234,887        208,905        25,982        12     208,905        28,582        180,323        631

General & administrative

    30,918        27,923        2,995        11     27,923        24,254        3,669        15

Loss (gain) on sale of assets

    2,824        (297     3,121        1,051     (297     (145,876     145,579        100

Other

    4,268               4,268        100                            
    Year Ended December 31,     Year Ended December 31,  

Per Mcfe

  2010     2009     Variance     2009     2008     Variance  

Depreciation, depletion & amortization

  $ 3.14      $ 5.38      $ (2.24     (42 %)    $ 5.38      $ 4.43      $ 0.95        21

Impairment

    6.97        7.01        (0.04     (1 %)      7.01        1.18        5.83        494

General & administrative

    0.92        0.94        (0.02     (2 %)      0.94        1.00        (0.06     (6 %) 

Loss (gain) on sale of assets

    0.08        (0.01     0.09        900     (0.01     (6.03     6.02        (100 %) 

Other

    0.13               0.13        100                            

 

Depreciation, Depletion & Amortization

 

Our DD&A expense decreased $54.5 million to $105.9 million in 2010 from $160.4 million in 2009 as a result of a lower DD&A rate. The average DD&A rate decreased 42% while production increased 13% year-to-year. The decrease in the average depletion rate contributed $75.5 million to the decrease in DD&A expense offset by $21.0 million attributed to the higher production in 2010.

 

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We calculated the first six months of 2010 DD&A rates using the December 31, 2009 fully engineered reserves prepared by NSAI. Proved developed reserves increased 9% from 152.5 Bcfe at December 31, 2008 to 165.5 Bcfe at December 31, 2009. We calculated third quarter 2010 DD&A rates using the June 30, 2010 mid-year reserves prepared by internal reserve engineers. Proved developed reserves at June 30, 2010 were 205.8 Bcfe, a 24% increase over the reserves at December 31, 2009. We adjusted our DD&A rates in the fourth quarter of 2010 to reflect the impact of the impairment recorded in the third quarter of 2010.

 

The decrease in the 2010 DD&A rate was also impacted by the impairment recorded in the fourth quarter of 2009 and the addition of Haynesville Shale proved reserves, which carry more attractive finding and development costs per unit of proved reserves. The 2009 impairment was the result of the write down of our legacy vertical Cotton Valley and Travis Peak proved reserves which reduced the book value of the oil and gas properties to be depleted.

 

DD&A expense increased $53.3 million to $160.4 million in 2009 from $107.1 million in 2008 due to an average depletion rate increase of 21% and a 23% increase in production year-to-year. The increase in the average depletion rate contributed $28.3 million to the increase. The remaining $25.0 million increase in DD&A year-to-year is related to higher production in 2009. The DD&A rate increased to $5.38 per Mcfe for 2009 from $4.43 per Mcfe for 2008. We calculated DD&A rates for the first half of 2009 using the December 31, 2008 reserves. We calculated the DD&A rate for the second half of 2009 using an internally generated reserve report dated June 30, 2009, with a NYMEX gas price of $3.88 per MMbtu. The reserve estimates from the report as of June 30, 2009, resulted in a decrease in proved developed reserves from year end 2008, due primarily to a reduction in the price used for purposes of evaluating the reserves, from $5.71 per MMbtu at December 31, 2008 to $3.88 per MMbtu at June 30, 2009. As a result, the DD&A rate utilized for the second half of the year 2009, increased to $5.81 per Mcfe versus $4.91 per Mcfe in the first half of 2009. The higher DD&A rate of $5.81 mainly results from a decrease in our proved developed reserves as of June 30, 2009 due to the impact of lower prices on our traditional Cotton Valley and Travis Peak vertical reserves, which represented a majority of our proved developed reserves at June 30, 2009. Similarly, the higher rate for the second half of the year increased the DD&A rate for the entire year 2009 to $5.38 per Mcfe, a 21% increase from 2008.

 

While our internal, mid-year reserve reports were prepared in accordance with existing SEC guidelines, they should not be construed as a fully independent engineering reserve report similar to what we have used in the past and what we used at year end.

 

Impairment

 

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, core Haynesville Shale in North Louisiana and the Angelina River Trend of the Shelby Trough.

 

We recorded an impairment of $208.9 million in 2009 related to the Bethany Longstreet, Bethune/East Gates, Loco Bayou, Cotton South/Raintree and a collection of other fields as a result of the decrease in natural gas prices in 2009 from 2008 which lowered economical proved reserves. Proved and probable reserves were also lowered due to our strategic decision to decrease using vertical wellbores to develop our existing properties because this method was deemed no longer the most economic avenue to pursue. The impairment charge in 2009 was also driven by the removal of the previously scheduled vertical proved and probable drilling locations and was partially offset by the addition of horizontal undeveloped locations in fields where such locations were deemed appropriate.

 

We recorded an impairment of $28.6 million in 2008 related to assets located in non-core areas of Northwest Louisiana and East Texas.

 

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Index to Financial Statements

General and Administrative Expense

 

General and administrative (“G&A”) expense increased $3.0 million or 11% to $30.9 million in 2010 compared to $27.9 million in 2009. G&A expense in 2010 included compensation costs related to the resignation of an officer of the company. See Note 14 “Resignation of Executive Officer” to our consolidated financial statements in this report for more information. G&A expense for the year 2010 also includes 2009 bonuses approved and paid out in March 2010. Share based compensation expense, which is a non-cash item, amounted to $7.6 million in 2010 compared to $6.8 million in 2009. G&A on a per unit basis decreased to $0.92 per Mcfe from $0.94 per Mcfe as a result of the 13% increase in production volume in 2010 compared to 2009.

 

G&A expense increased $3.7 million or 15% to $27.9 million in 2009 compared to $24.3 million in 2008. The increase results primarily from higher compensation cost resulting from having a larger work force. We had 125 employees as of December 31, 2009 versus 114 employees as of December 31, 2008, an increase of 10%. G&A on a per unit basis decreased to $0.94 per Mcfe from $1.00 per Mcfe as a result of a 23% increase in production volumes in 2009 as compared to 2008. Share based compensation expense, which is a non-cash item, amounted to $6.8 million in 2009 compared to $5.5 million in 2008.

 

Other

 

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

 

On July 9, 2010, the sub-lessee agreed to reimburse us for one half of any sums for which we may be cast in judgment in this lawsuit in any final non-appealable judgment, and further agreed to reimburse us for one half of the cash bond. We reduced our accrual by $4.2 million in the third quarter of 2010 and the remaining $4.3 million as of December 31, 2010 is reflected as “Operating Expenses—Other” in the Consolidated Statement of Operations.

 

Other Income (Expense)

 

     Year Ended December 31,  
     2010     2009     2008  
     (In thousands)  

Other Income (Expense):

      

Interest expense

   $ (37,179   $ (26,148   $ (22,410

Interest income

     117        458        1,682   

Gain (loss) on derivatives not designated as hedges

     55,275        47,115        51,547   

Income tax benefit (expense)

     85        67,311        (54,472

Average funded borrowings adjusted for debt discount

     379,582        268,000        244,401   

Average funded borrowings

     400,405        304,211        271,321   

 

Interest Expense

 

Interest expense increased $11.1 million to $37.2 million for 2010 compared to $26.1 million for 2009 as a result of the higher average level of outstanding debt in the current year. The higher average level of debt is the

 

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result of the issuance of our 5% convertible senior notes in September 2009. Non-cash interest of $19.3 million is included in the $37.2 million interest expense reported in 2010. Non-cash interest of $12.2 million is included in the $26.1 million interest expense reported for the year 2009.

 

Interest expense increased $3.7 million to $26.1 million for 2009 compared to $22.4 million for 2008 as a result of the write off of deferred financing cost and the pre-payment premium on the second lien term loan ($0.8 million) in addition to the interest accrued on the 5% convertible senior notes issued in September, 2009. Interest expense in 2009 included non-cash charges of $12.2 million (mostly related to the amortization of debt discount on our convertible notes) while interest expense in 2008 included non-cash charges of $8.5 million.

 

Interest Income and Other

 

We invested the proceeds from the 5% convertible senior note offering in September 2009 and the net proceeds from our equity offering and the sale of assets, both in July 2008, 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 2010, 2009 and 2008 is reflected in the Interest income line. For more information on our Short Term Investment Policy, please see “Liquidity–Short Term Investments.”

 

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 January 8, 2010 the Henry Hub natural gas spot price reached a high of $7.51 per MMbtu, but the price was down to $3.73 per MMBtu by September 2, 2010 and back up to $4.19 per MMBtu by December 30, 2010. 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.

 

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 natural gas and oil commodity contracts. The unrealized gain reflects the lower average futures strip prices from December 31, 2009 as compared to December 31, 2010.

 

Gain on derivatives not designated as hedges was $47.1 million for 2009, which includes a gain of $47.8 million from our natural gas derivatives offset by a $0.7 million loss on our interest rate derivatives. The gain on our natural gas derivatives includes a realized gain of $98.0 million offset by a $50.2 million unrealized loss for the change in fair value of our natural gas commodity contracts. The unrealized loss resulted from the roll off of existing natural gas derivative contracts during 2009. The loss on interest rate hedges in 2009 includes a realized loss of $1.4 million offset by an unrealized gain of $0.7 million. Our interest rate derivative contracts expired in the first half of 2010.

 

Gain on derivatives not designated as hedges for 2008 was $51.5 million including a realized loss of $2.5 million and an unrealized gain of $54.0 million for the changes in fair value of our derivative contracts.

 

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 (Expense) Benefit

 

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 otherwise recorded no income tax benefit for the year 2010. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2009 after considering all

 

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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, 2010.

 

Income tax benefit from continuing operations of $67.3 million for 2009 includes an increase to our valuation allowance of $54.3 million. Income tax expense was $54.5 million for the year ended December 31, 2008. In 2008, we realized a significant gain on the sale of assets related primarily to our sale of deep rights acreage to Chesapeake which helped generate income before taxes of $176.2 million for 2008. As a result of the significant gain generated by the sale, we released $15.3 million of our previously booked valuation allowance. The impact of this was to reduce income tax expense for 2008.

 

LIQUIDITY AND CAPITAL RESOURCES

 

Overview

 

The Company’s primary sources of cash during 2010 were cash flow from operating activities and proceeds from divestitures. We used cash primarily to fund our capital spending program, and pay preferred stock dividends. The Company’s primary sources of cash during 2009 were cash flow from operating activities and the issuance of debt. In 2009, we used cash primarily to fund our capital spending program, retire debt and pay preferred stock dividends. The Company’s primary sources of cash during 2008 were the issuance of equity securities, sale of assets and cash flow from operating activities. In 2008, the Company used cash primarily to fund our capital spending program and pay preferred stock dividends.

 

The Company has in place a $350 million Senior Credit Facility, entered into with a syndicate of United States and international lenders, and as of December 31, 2010, the Company had a $225 million borrowing base with no outstanding borrowings under its senior credit facility. On February 4, 2011, the Company entered into a Third Amendment to our Senior Credit Facility revising our interest coverage ratio from 3.0x to 2.5x to take into consideration additional non-cash interest recorded due to the adoption on January 1, 2009 of a new accounting standard related to our convertible notes. We were in compliance with existing covenants, as amended and the full amount of the borrowing base of the Senior Credit Facility was available for borrowing at December 31, 2010.

 

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:

 

   

issuance of debt securities,

 

   

sale of non-core assets,

 

   

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

 

   

availability under our Senior Credit Facility.

 

Our Senior Credit Facility matures on August 31, 2011. In addition, holders of our $175 million principal amount 3.25% Convertible Senior Notes Due 2026 have the right to require us to purchase some or all of such notes at par on December 1, 2011. Because the conversion price of those notes is substantially above recent trading price of our common stock, it is more likely than not that notes will be put to us for repurchase on such date. We expect to renew our credit facility and use borrowings from such renewed facility, additional borrowings or other sources of funding to repay any such notes that are required to be repurchased. Should we redeem the 2026 Notes, the maturity date under our Senior Credit Facility will extend to July 1, 2012.

 

The following section discusses significant sources and uses of cash for the three-year period ending December 31, 2010. Forward-looking information related to our liquidity and capital resources are discussed in Outlook that follows.

 

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Capital Resources

 

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

 

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

 

Our primary sources of cash during 2009 were from the issuance of our 5% convertible senior notes of $218.5 million in September 2009, funds generated from operations and bank borrowings. Cash was used primarily to fund exploration and development expenditures. We made aggregate cash payments of $18 million for interest in 2010. The table below summarizes the sources of cash during 2010, 2009 and 2008:

 

     Year Ended December 31,     Year Ended December 31,  

Cash flow statement information:

   2010     2009     Variance     2009     2008     Variance  
     (In thousands)  

Net Cash:

            

Provided by operating activities

   $ 100,432      $ 115,570      $ (15,138   $ 115,570      $ 107,039      $ 8,531   

Used in investing activities

     (200,080     (265,587     65,507        (265,587     (187,786     (77,801

Provided by (used) financing activities

     (7,680     127,585        (135,265     127,585        223,847        (96,262
                                                

Increase (decrease) in cash and cash equivalents

   $ (107,328   $ (22,432   $ (84,896   $ (22,432   $ 143,100      $ (165,532
                                                

 

At December 31, 2010, we had a working capital deficit of $199.5 million and long-term debt, net of debt discount, of $179.2 million. Our working capital deficit position is primarily due to our 3.25% Senior Convertible Notes due 2026 being considered current as of December 31, 2010. The holders of the notes have the right to require us to purchase all or a portion of their notes on December 1, 2011.

 

Cash Flows

 

Year ended December 31, 2010 Compared to Year Ended December 31, 2009

 

Operating activities.    Cash flow from operations is dependent upon production volumes generated from our development, exploration and acquisition activities, the price of oil and natural gas and costs incurred in our operations. Our cash flow from operations is also impacted by changes in working capital. Net cash provided by operating activities was $100.4 million, a decrease of $15.1 million, or 13%, from $115.6 million in 2009. Our operating revenues increased 34% in 2010 with a 18% decrease in commodity prices and an increase in average daily production of 13% as compared to 2009. The cash flow decrease is also the result of receiving $24.6 million in natural gas derivative settlements in 2010 compared to having received $98.0 million for settlements of natural gas derivatives in 2009.

 

Investing activities.    Net cash used in investing activities was $200.1 million for the year ended December 31, 2010, compared to $265.6 million for 2009. While we booked capital expenditures of approximately $283.7 million in 2010, we paid out cash amounts totaling $265.0 million in 2010, with the difference being attributed to approximately $30.0 million in drilling and completion costs which were accrued at December 31, 2010, non-cash asset retirement obligation additions of $1.3 million and geophysical and geological cost of $1.2 million offset by $13.8 million in drilling and completion cost accrued at December 31, 2009 and paid in 2010. In the fourth quarter of 2010, we incurred additional drilling and completion capital expenditures in excess of that which was budgeted from (1) acceleration of completion of Haynesville Shale wells that were scheduled for 2011; (2) incremental drilling and completion costs associated with longer laterals

 

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in our Eagle Ford Shale trend; and (3) reduced drilling cycles thereby incurring additional drilling capital expenditures as a result of drilling more wells. Net cash used in investing activities was offset by the receipt of $64.9 million of cash proceeds from the sale of fixed assets in 2010.

 

We conducted drilling and completion operations on 46 gross wells in 2010 compared to 45 gross wells in 2009. Of the $265.0 million cash spent this year, 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. Of the $265.8 million spent in 2009, approximately $239.5 million was for drilling and completion activities (of which $28.3 million related to 2008 wells), $15.9 million was for leasehold acquisition, $4.1 million for facilities and infrastructure, $3.4 million for capital workovers, $1.9 million on geological and geophysical and $1.0 million for furniture, fixtures and equipment

 

Financing activities.    Net cash used in financing activities was $7.7 million for 2010, a decrease of $135.3 million from net cash provided by financing activities of $127.6 million in 2009. In September 2009, we received $218.5 million from the offering of our 5% convertible senior notes due 2029. With the proceeds from the offering, we paid $8.8 million in offering cost, paid off our $75.0 million second lien term loan and paid off the $5.0 million balance on our senior credit facility. We had zero borrowings outstanding under our Senior Credit Facility as of December 31, 2010.

 

Year ended December 31, 2009 Compared to Year Ended December 31, 2008

 

Operating activities.    Net cash provided by operating activities for 2009 was $115.6 million, an increase of $8.6 million, or 8%, from $107.0 million in 2008. Our operating revenues decreased 49% in 2009 with a 58% decrease in commodity prices offset by an increase in average daily production of 24% as compared to 2008. The favorable cash flow increase is also the result of receiving $98.0 million in natural gas derivative settlements in 2009 compared to having expended $1.8 million for settlements of natural gas derivatives in 2008.

 

Investing activities.    Net cash used in investing activities was $265.6 million for the year ended December 31, 2009, compared to $187.8 million for 2008 (which was reduced in 2008 by the $175.1 million in asset sales mentioned previously). While we booked capital expenditures of approximately $237.5 million in 2009, we paid out cash amounts totaling $265.8 million in 2009, with the difference being attributed to approximately $28.3 million in drilling and completion costs which were accrued at December 31, 2008 but not paid until early in fiscal year 2009. We conducted drilling and completion operations on 45 gross wells in 2009 compared to 126 gross wells in 2008, a decrease of 64%. Of the $265.8 million spent this year, approximately $239.5 million was for drilling and completion activities (of which $28.3 million related to 2008 wells), $15.9 million was for leasehold acquisition, $4.1 million for facilities and infrastructure, $3.4 million for capital workovers, $1.9 million on geological and geophysical and $1.0 million for furniture, fixtures and equipment. Of the $362.8 million invested in 2008, we spent $328.8 million for drilling and completion activities, $28.6 million for leasehold acquisition, $4.2 million for facilities and infrastructure and $1.2 million for furniture, fixtures and equipment.

 

Financing activities.    Net cash provided by financing activities was $127.6 million for 2009, a decrease of $96.2 million from $223.8 million in 2008.

 

In 2008, we borrowed $75.0 million on our Second Lien Term Loan and used $53.5 million of the borrowings to pay-off the balance on our senior credit facility. We also received net proceeds of $191.3 million from an equity offering. We used these proceeds to pay the full outstanding balance on our existing bank credit facility. We had no borrowings outstanding under our Senior Credit Facility as of December 31, 2008.

 

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Senior Credit Facility

 

On May 5, 2009, we entered into a Second Amended and Restated Credit Agreement (“Senior Credit Facility”) that replaced our previous facility. Total lender commitments under the Senior Credit Facility are $350 million. The Senior Credit Facility matures on August 31, 2011. The Senior Credit Facility can be further extended to July 1, 2012 upon receipt of proceeds from a refinancing sufficient to prepay the 3.25% convertible senior notes due 2026, which the holders have the option to put to the Company on December 1, 2011. Revolving borrowings under the Senior Credit Facility are limited to, and subject to periodic redeterminations of, the borrowing base. 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 0.75% to 1.50%, or LIBOR plus 2.25% to 3.00%, depending on borrowing base utilization. Pursuant to the terms of the Senior Credit Facility, borrowing base redeterminations will be on a semi-annual basis on April 1 and October 1 beginning on October 1, 2009. In connection with the offering of the $218.5 million 5% convertible senior notes due 2029, we entered into an amendment of our Senior Credit Facility to permit the issuance of the notes and required payments made on the notes thereafter and to exclude up to $175 million of our 3.25% convertible senior notes due 2026 or our 5% convertible senior notes due 2029 from the definition of Total Debt used in our financial covenants under the Senior Credit Facility. As of December 31, 2010, we had no amounts outstanding under the credit facility which has a borrowing base of $225.0 million.

 

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, but not defined, here have the meanings assigned to them in the Senior Credit Facility. The primary financial covenants include:

 

   

Current Ratio of 1.0/1.0;

 

   

Interest Coverage Ratio of not less than 2.5/1.0 for the trailing four quarters; and

 

   

Total Debt no greater than 3.0 times EBITDAX for the trailing four quarters (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. Up to $175 million of our convertible senior notes are excluded from the calculation of Total Debt for the purpose of computing this ratio).

 

On February 4, 2011, we entered into a third amendment to our senior credit facility revising our interest coverage ratio from 3.0x to 2.5x to take into consideration additional non-cash interest recorded due to the adoption on January 1, 2009 of a new accounting standard related to our convertible notes. We are in compliance with all the financial covenants as amended of the Senior Credit Facility as of December 31, 2010.

 

Second Lien Term Loan

 

On September 29, 2009, we fully paid off the second lien term loan with proceeds received from the issuance of our 5% convertible senior notes due 2029.

 

3.25% Convertible Senior Notes Due 2026

 

In December 2006, we sold $175.0 million of 3.25% convertible senior notes (the “2026 Notes”) due in December 2026. The notes mature on December 1, 2026, unless earlier converted, redeemed or repurchased. The notes accrue interest at a rate of 3.25% annually, and interest is paid semi-annually on June 1 and December 1.

 

On or after December 1, 2011, 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 December 1, 2011, 2016 and 2021.

 

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Interest expense relating to the contractual interest rate and amortization of both financing cost and debt discount relating to these notes for the years ended December 31, 2010, 2009 and 2008 was $14.5 million, $13.9 million and $13.3 million, respectively. The effective interest rate on the liability component of the notes was 9% for each of the years 2010, 2009 and 2008.

 

5% Convertible Senior Notes Due 2029

 

In September 2009, we sold $218.5 million of 5% convertible senior notes (the “2029 Notes”) due in October 2029. The notes mature on October 1, 2029, unless earlier converted, redeemed or repurchased. 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. 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. Interest expense recognized relating to the contractual interest rate and amortization of both financing cost and debt discount for the year ended December 31, 2010 was $20.0million. The effective rate on the liability component of the notes was 11.2% in the year 2010.

 

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

 

Equity Offering

 

On July 14, 2008, we closed the public offering of 3,121,300 shares of our common stock at a price of $64.00 per share. Net proceeds from the offering were approximately $191.3 million after deducting the underwriters’ discount and estimated offering expenses. We used approximately $96.0 million of the net proceeds to pay off outstanding borrowings under our Senior Credit Facility. We used the remaining net proceeds for general corporate purposes, including funding a portion of our remaining 2008 drilling program, other capital expenditures and working capital requirements.

 

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 under Item 8 of this Form 10-K.

 

Outlook

 

The Company’s capital budgeting process is ongoing. Our total budget for capital expenditures for 2011 is expected to be $235 million, exclusive of acquisitions other than leases acreage additions in our core areas. We expect capital spending by area to be approximately 62% for Eagle Ford Shale Trend, 22% for Haynesville Shale Trend, 10% for CVTS and 6% for Other. The Company’s 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, 2010, and our borrowing base will be sufficient to fund our projected operational and capital

 

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programs for 2011. However, if capital expenditures exceed operating cash flow and cash on hand, funds would likely be supplemented as needed through short-term borrowings under our fully available $225.0 million senior credit facility or through the issuance of debt or equity.

 

We will operate approximately 85% of wells drilled as part of our 2011 planned capital expenditures. Additionally, we operate over 67% of our proved reserves and 52% of our acreage is held by production. We have no drilling commitments and the ability to go non-consent on all wells proposed by partners.

 

In addition, to support 2011 and 2012 cash flows, we entered into strategic derivative positions as of January 1, 2011, on approximately 41% of our anticipated natural gas sales volumes and approximately 42% of our anticipated oil and condensate sales volumes for 2011. In addition, the Company has entered into commodity-price-risk management derivative positions for the year 2012. See Note 8—Derivative Activities in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

We may choose to refinance certain portions of our short-term borrowings by issuing long-term debt or equity, or both. We continuously monitor our leverage position and coordinate our capital expenditure program with our expected cash flows and projected debt-repayment schedule. We will continue to evaluate funding alternatives as needed, including property divestitures or borrowings under our senior credit facility and the issuance of debt or equity securities. We are currently considering options to refinance the 3.25% Convertible Senior Notes due 2026. Included in those options are the issuance of debt securities or bringing in joint venture partners in core Haynesville and/or Eagle Ford Shale acreage. To the extent additional borrowings were not available to us, we believe we could satisfy the obligation of the 2026 Notes through a combination of our Senior Credit Facility availability and cash flow from operations while reducing our 2011 capital expenditures.

 

Credit Risks

 

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

 

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, 2010 (in thousands). In addition to the contractual obligations presented in the table below, our Consolidated Balance Sheet at December 31, 2010 reflects accrued interest on our bank debt of $3.2 million payable in the first half of 2011. See Note 4 “Long-Term Debt” and Note 10 “Commitments and Contingencies” to our consolidated financial statements for additional information.

 

     Payment due by Period  
     Note      Total      2011      2012      2013      2014      2015
and After
 

Contractual Obligations

                    

Long term debt (1)

     4       $ 393,500       $ 175,000       $       $       $ 218,500       $   

Interest on convertible senior notes

     4         46,182         16,138         10,925         10,925         8,194           

Office space leases

     10         9,246         1,042         1,044         1,142         1,104         4,914   

Office equipment leases

     10         793         496         114         100         56         27   

Drilling rigs & operations contracts

     10         27,179         18,744         7,702         583         150           
                                                        

Total contractual obligations (2)

      $ 476,900       $ 211,420       $ 19,785       $ 12,750       $ 228,004       $ 4,941   
                                                        

 

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(1) The $175.0 million 3.25% Convertible Senior Notes due 2026 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 is December 1, 2011. The $218.5 million 5.0% Convertible Senior Notes due 2029 have a provision by which on or after October 1, 2014, the Company may redeem all or a portion of the notes for cash, and the investors may require the Company to repurchase the notes on each of October 1, 2014, 2019 and 2024.
(2) This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and gas properties of $16.1 million. The Company records 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 under 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 under Item 8 of this Form 10-K.

 

Proved Oil and Natural Gas Reserves

 

Proved reserves are defined by the SEC as 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 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 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, 2010 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 any estimates we might prepare applying more specific SEC interpretive guidance.

 

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. Certain costs related to new fields or areas that are not fully developed are charged to expense using the units of production method based on total proved oil and natural gas reserves.

 

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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. We carry our derivative instruments at fair value and measure their fair value by applying the income approach, 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 gas properties held for use and for sale at historical cost. We use level 3 inputs which are unobservable data such as discounted cash flow models or valuations, based on the Company’s various assumptions and future commodity prices to determine the fair value of our oil and 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.

 

Impairment of Properties

 

We monitor our long-lived assets recorded in oil and 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 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 are required to make estimates of the future costs of the retirement obligations of our producing oil and gas properties in order to ensure that they are presented at fair value. This requirement necessitates us to make estimates of our property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.

 

Income Taxes

 

We are subject to income and other related taxes in areas in which we operate. When recording income tax expense, certain estimates are required by management due to timing and the impact of future events on when income tax expenses and benefits are recognized by us. We periodically evaluate our tax operating loss and other carryforwards 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” to our consolidated financial statements.

 

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

 

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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” to our consolidated financial statements.

 

Off-Balance Sheet Arrangements

 

We do not currently use any off-balance sheet arrangements to enhance our liquidity and capital resource positions, or for any other purpose.

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

 

The Company’s 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. The Company’s risk-management policies provide for the use of derivative instruments to manage these risks. The types of derivative instruments utilized by the Company include futures, swaps, options and fixed-price physical-delivery contracts. The volume of commodity derivative instruments utilized by the Company 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 the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or its counterparties in order to satisfy these margin requirements.

 

For information regarding the Company’s accounting policies and additional information related to the Company’s 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 under Item 8 of this Form 10-K.

 

Commodity Price Risk

 

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

 

The Company had derivative instruments in place to reduce the price risk associated with future equity production of approximately 29.2 Bcf of natural gas and 0.9 MMBbls of crude oil as of December 31, 2010. At December 31, 2010, the Company had a net asset derivative position of $35.8 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 $14.4 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately $9.8 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.

 

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Interest Rate Risk

 

As of December 31, 2010, we had no outstanding variable-rate debt and $393.5 million of 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.

 

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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

     52   

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

     53   

Report of Independent Registered Public Accounting Firm—Consolidated Financial Statements for the years ended December 31, 2010 , 2009 and 2008

     54   

Consolidated Balance Sheets as of December 31, 2010 and 2009

     55   

Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008

     56   

Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008

     57   

Consolidated Statements of Stockholders’ Equity for the years ended December  31, 2010, 2009 and 2008.

     58   

Notes to the Consolidated Financial Statements

     59   

 

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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, 2010. The effectiveness of our internal control over financial reporting as of December 31, 2010 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included on page 53.

 

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 internal control over financial reporting as of December 31, 2010, 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 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, 2010, based on the COSO criteria.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2010 consolidated financial statements of Goodrich Petroleum Corporation and subsidiary and our report dated February 21, 2011, expressed an unqualified opinion thereon.

 

/s/ Ernst & Young LLP

 

Houston, Texas

February 21, 2011

 

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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 (“the Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, cash flows, and stockholders’ equity, for each of the three years in the period ended December 31, 2010. 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, 2010 and 2009, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

 

As discussed in Note 15 to the consolidated financial statements, the Company changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements as of December 31, 2009.

 

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, 2010, 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 21, 2011 expressed an unqualified opinion thereon.

 

/s/ Ernst & Young LLP

 

Houston, Texas

February 21, 2011

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARY

 

CONSOLIDATED BALANCE SHEET

(In Thousands)

 

     December 31,  
     2010     2009  
ASSETS     

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 17,788      $ 125,116   

Restricted cash

     4,232          

Accounts receivable, trade and other, net of allowance

     9,231        7,944   

Income taxes receivable

     4,335        15,438   

Accrued oil and gas revenue

     14,920        17,206   

Fair value of oil and gas derivatives

     24,467        5,403   

Inventory

     7,831        662   

Prepaid expenses and other

     3,045        1,609   
                

Total current assets

     85,849        173,378   
                

PROPERTY AND EQUIPMENT:

    

Oil and gas properties (successful efforts method)

     1,217,891        1,339,462   

Furniture, fixtures and equipment

     4,962        3,985   
                
     1,222,853        1,343,447   

Less: Accumulated depletion, depreciation and amortization

     (685,110     (669,463
                

Net property and equipment

     537,743        673,984   

Fair value of oil and gas derivatives

     15,732          

Deferred tax asset

     19,695        4,700   

Deferred financing cost

     5,558        8,212   
                

TOTAL ASSETS

   $ 664,577      $ 860,274   
                
LIABILITIES AND STOCKHOLDERS’ EQUITY     

CURRENT LIABILITIES:

    

Accounts payable

   $ 47,106      $ 35,079   

Accrued liabilities

     47,105        25,308   

Accrued abandonment costs

     4,392        4,574   

Deferred tax liability current

     19,695        4,700   

Fair value of interest rate derivatives

            1,087   

Current portion of debt

     167,086          
                

Total current liabilities

     285,384        70,748   

LONG-TERM DEBT

     179,171        330,147   

Accrued abandonment costs

     11,683        13,716   

Fair value of oil and gas derivatives

     4,367        278   
                

Total liabilities

     480,605        414,889   
                

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 37,685,378 and 37,452,023 shares, respectively

     7,212        7,166   

Treasury stock (12,377 and 19,915 shares, respectively)

     (196     (411

Additional paid in capital

     643,828        637,335   

Retained earnings (accumulated deficit)

     (469,122     (200,955
                

Total stockholders’ equity

     183,972        445,385   
                

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

   $ 664,577      $ 860,274   
                

 

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,  
     2010     2009     2008  

REVENUES:

      

Oil and gas revenues

   $ 148,031      $ 110,784      $ 215,369   

Other

     302        (358     682   
                        
     148,333        110,426        216,051   
                        

OPERATING EXPENSES:

      

Lease operating expense

     26,306        30,188        31,950   

Production and other taxes

     3,627        4,317        7,542   

Transportation

     9,856        9,459        8,645   

Depreciation, depletion and amortization

     105,913        160,361        107,123   

Exploration

     10,152        9,292        8,404   

Impairment of oil and gas properties

     234,887        208,905        28,582   

General and administrative

     30,918        27,923        24,254   

Loss (gain) on sale of assets

     2,824        (297     (145,876

Other

     4,268                 
                        
     428,751        450,148        70,624   
                        

Operating income (loss)

     (280,418     (339,722     145,427   
                        

OTHER INCOME (EXPENSE):

      

Interest expense

     (37,179     (26,148     (22,410

Interest income and other

     117        458        1,682   

Gain on derivatives not designated as hedges

     55,275        47,115        51,547   
                        
     18,213        21,425        30,819   
                        

Income (loss) before income taxes

     (262,205     (318,297     176,246   

Income tax benefit (expense)

     85        67,311        (54,472
                        

Net income (loss)

     (262,120     (250,986     121,774   

Preferred stock dividends

     6,047        6,047        6,047   
                        

Net income (loss) applicable to common stock

   $ (268,167   $ (257,033   $ 115,727   
                        

PER COMMON SHARE

      

Net income (loss) applicable to common stock—basic

   $ (7.47   $ (7.17   $ 3.42   

Net income (loss) applicable to common stock—diluted

   $ (7.47   $ (7.17   $ 3.23   

Weighted average common shares outstanding—basic

     35,921        35,866        33,806   

Weighted average common shares outstanding—diluted

     35,921        35,866        40,397   

 

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,  
     2010     2009     2008  

CASH FLOWS FROM OPERATING ACTIVITIES:

      

Net income (loss)

   $ (262,120   $ (250,986   $ 121,774   

Adjustments to reconcile net income (loss) to net cash provided by operating activities—Depletion, depreciation, and amortization

     105,913        160,361        107,123   

Unrealized (gain) loss on derivatives not designated for hedge accounting

     (31,794     49,434        (53,995

Deferred income taxes

            (51,845     34,835   

Exploration costs

            219        312   

Amortization of leasehold costs

     5,963        4,927        5,838   

Impairment of oil and gas properties

     234,887        208,905        29,751   

Share based compensation (non-cash)

     7,554        6,751        5,493   

Loss (gain) on sale of assets

     2,824        (297     (145,876

Amortization of finance cost and debt discount

     19,256        12,221        8,465   

Other non-cash items

            282        53   

Change in assets and liabilities:

      

Restricted cash

     (4,232              

Accounts receivable, trade and other, net of allowance

     (343     (925     1,467   

Inventory

     (7,169     102        (1,376

Income taxes receivable

            (15,438       

Deferred revenue

                   (12,500

Accrued oil and gas revenue

     403        (1,611     (3,395

Accounts payable

     14,571        (6,338     4,495   

Income taxes payable

     11,103        (1,320     1,383   

Accrued liabilities

     4,901        976        3,184   

Prepaid expenses and other

     (1,285     152        8   
                        

Net cash provided by operating activities

     100,432        115,570        107,039   
                        

CASH FLOWS FROM INVESTING ACTIVITIES:

      

Capital expenditures

     (264,967     (265,825     (362,847

Proceeds from sale of assets

     64,887        238        175,061   
                        

Net cash used in investing activities

     (200,080     (265,587     (187,786
                        

CASH FLOWS FROM FINANCING ACTIVITIES:

      

Proceeds from convertible note offering

            218,500          

Principal payments of bank borrowings

     (54,500     (80,000     (155,500

Proceeds from bank borrowings

     54,500        5,000        190,000   

Exercise of stock options and warrants

     10        26        2,819   

Deferred financing costs

     (492     (8,755     (1,498

Preferred stock dividends

     (6,047     (6,047     (6,047

Net proceeds from common stock offering

                   191,340   

Excess tax benefit from stock based compensation

                   3,222   

Other

     (1,151     (1,139     (489
                        

Net cash provided by (used in) financing activities

     (7,680     127,585        223,847   
                        

Increase (decrease) in cash and cash equivalents

     (107,328     (22,432     143,100   

Cash and cash equivalents, beginning of period

     125,116        147,548        4,448   
                        

Cash and cash equivalents, end of period

   $ 17,788      $ 125,116      $ 147,548   
                        

Supplemental disclosures of cash flow information:

      

Cash paid during the year for interest

   $ 18,014      $ 12,446      $ 12,981   

Cash paid during the year for taxes

   $      $ 1,352      $ 14,778   
                        

 

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
Stockholder’s
Equity
 
    Shares     Value     Shares     Value       Shares     Value      

Balance at January 1, 2008

    2,250      $ 2,250        34,821      $ 6,340      $ 364,262        (16   $ (422   $ (59,649     312,781   

Net income

                                                     121,774        121,774   

Offering of common stock

                  4,030        806        224,405                             225,211   

Employee stock plans

                  194        39        10,879                             10,918   

Director stock grants

                  16        3        579                             582   

Shares issued pursuant to share lending agreement

                  (1,498                                          

Repurchases of stock

                                       (16     (485            (485

Retirement of stock

                                       22        614               614   

Dividends

                                                     (6,047     (6,047
                                                                       

Balance at December 31, 2008

    2,250        2,250        37,563        7,188        600,125        (10     (293     56,078        665,348   

Net loss

                                                     (250,986     (250,986

Capped call option redemption

                  (266     (53                                 (53

Equity portion of convertible notes

                                31,165                             31,165   

Employee stock plans

                  139        28        5,991                             6,019   

Director stock grants

                  16        3        54                             57   

Repurchases of stock

                                       (44     (1,132            (1,132

Retirement of stock

                                       34        1,014               1,014   

Dividends

                                                     (6,047     (6,047
                                                                       

Balance at December 31, 2009

    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                 

Other

                                (5                          (5

Dividends

                                                     (6,047     (6,047
                                                                       

Balance at December 31, 2010

    2,250      $ 2,250        37,685      $ 7,212      $ 643,828        (12   $ (196   $ (469,122   $ 183,972   
                                                                       

 

See accompanying notes to consolidated financial statements.

 

58


Table of Contents
Index to Financial Statements

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 gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in Northwest Louisiana, East Texas and South Texas.

 

Principles of Consolidation—The consolidated financial statements of Goodrich Petroleum Corporation (“Goodrich,” “the Company” or “we”) 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.

 

Presentation Change—The Consolidated Statement of Operations includes a category of expense titled “Interest income and other” which includes immaterial effects of discontinued operations from the prior periods. The net effect of discontinued operations is added to this account for the comparative years of 2009 and 2008.

 

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.

 

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