Form 10-K
Table of Contents
Index to Financial Statements
 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

þ        ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2005

Commission file number: 001-7940

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.)

808 Travis, Suite 1320

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

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

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

 

Title of each class

 

Name of exchange on which registered

Common Stock, par value $0.20 per share

  New York Stock Exchange

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

 

Series A Preferred Stock, $1.00 par value   NASDAQ Small Cap

Indicate by check mark if the Registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act).

Yes            No    ü  

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    ü  

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    ü    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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer                               Accelerated filer    ü                           Non-accelerated filer          

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

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the Registrant as of June 30, 2005 (the last business day of the Registrant’s most recently completed second fiscal quarter) was approximately $258,852,976. The number of shares of the Registrant’s common stock outstanding as of March 10, 2006 was 24,904,941.

DOCUMENTS INCORPORATED BY REFERENCE: Portions of Goodrich Petroleum Corporation’s definitive Proxy Statement are incorporated by reference in Part III of this Form 10-K.

 

 


Table of Contents
Index to Financial Statements

GOODRICH PETROLEUM CORPORATION

2005 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

 

           Page

Part I

     3

Items 1. and 2. Business and Properties

     3

Item 1A.

   Risk Factors    12

Item 1B.

   Unresolved Staff Comments    18

Item 3.

   Legal Proceedings    18

Item 4.

   Submission of Matters to a Vote of Security Holders    18

Part II

      19

Item 5.

   Market for Registrant’s Common Equity, Related Stockholder Matters   
   and Issuer Purchases of Equity Securities    19

Item 6.

   Selected Financial Data    20

Item 7.

   Management’s Discussion and Analysis of Financial Condition   
   and Results of Operations    21

Item 7A.

   Quantitative and Qualitative Disclosures about Market Risk    31

Item 8.

   Financial Statements and Supplementary Data    32

Item 9.

   Changes in and Disagreements with Accountants on Accounting and   
   Financial Disclosure    33

Item 9A.

   Controls and Procedures    33

Item 9B.

   Other Information    33

Part III

      34

Item 10.

   Directors and Executive Officers of Registrant    34

Item 11.

   Executive Compensation    36

Item 12.

   Security Ownership of Certain Beneficial Owners and Management and   
   Related Stockholder Matters    36

Item 13.

   Certain Relationships and Related Transactions    36

Item 14.

   Principal Accounting Fees and Services    36

Part IV

      37

Item 15.

   Exhibits and Financial Statement Schedules    37

 

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Index to Financial Statements

PART I

Items 1 and 2.    Business and Properties.

General

Goodrich Petroleum Corporation and subsidiaries (“we” or “the Company”) is an independent oil and gas company engaged in the exploration, exploitation, development and production of oil and natural gas properties primarily in the Cotton Valley Trend of East Texas and Northwest Louisiana and in the transition zone of South Louisiana. We own working interests in 139 active oil and gas wells located in 19 fields in three states. At December 31, 2005, Goodrich had estimated proved reserves of approximately 5.0 MMBbls of oil and condensate and 143.0 Bcf of natural gas, or an aggregate of 172.8 Bcfe with a pre-tax present value of future net cash flows, discounted at 10%, of $587.7 million and an after-tax present value of discounted future net cash flows of $410.6 million, which is also referred to as the standardized measure of discounted future net cash flows. See “Oil and Natural Gas Reserves” for a reconciliation to the standardized measure of discounted future net cash flows.

Our principal executive offices are located at 808 Travis Street, Suite 1320, Houston, Texas 77002. We also have an administrative office in Shreveport, Louisiana.

Business Strategy

Our business strategy is to provide long term growth in net asset value per share, through the growth and expansion of our oil and gas reserves and production. We focus on adding reserve value through the development of our relatively low risk development drilling program in the Cotton Valley Trend, while maintaining our drilling activities in select high impact well locations in South Louisiana. We continue to aggressively pursue the acquisition and evaluation of prospective acreage, oil and gas drilling opportunities and potential property acquisitions.

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

 

   

Exploit and 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 Cotton Valley Trend while selectively pursuing exploitation and development opportunities on our South Louisiana transition zone properties. Our Cotton Valley Trend inventory is currently estimated to include approximately 1,900 drilling locations, based on an anticipated 40 acre spacing. We are continually performing field studies of our existing properties and reevaluating exploration and development opportunities using advanced technologies.

 

   

Expand Acreage Position in the Cotton Valley Trend. We have increased our acreage position from approximately 45,000 gross acres at December 31, 2004 to 129,000 gross acres as of February 28, 2006. We concentrate our efforts in areas where we can apply our technical expertise and where we have significant operational control or experience. To leverage our extensive regional knowledge base, we seek to acquire leasehold acreage with significant drilling potential in areas, such as the Cotton Valley Trend and South Louisiana, which 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 which offer a potentially higher overall return.

 

   

Focus on Low Operating Costs. We continually seek ways to minimize lease operating expenses and overhead expenses. We will continue to seek to control costs to the greatest extent possible by controlling our operations. As we continue to develop our Cotton Valley Trend properties, our overall operating costs per Mcfe are expected to decrease due to the lower cost nature of our Cotton Valley Trend operations.

 

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Selectively Grow Through Exploration. We conduct an active exploration program, both within and outside our existing properties, that is designed to complement our lower risk exploitation and development efforts with moderate risk exploration projects offering greater production and reserve growth potential. We utilize 3-D seismic data and other technical applications, as appropriate, to manage our exploration risk. We will also attempt to reduce our risk on exploration projects when appropriate through the sale of working interests to outside drilling partners on a promoted basis.

 

   

Maintain an Active Hedging Program. 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. For 2006, we currently have an average of 14,750 MMbtu per day of gas hedged at an average price of $6.98 per MMbtu and 775 Bbls per day of oil hedged at an average price of $50.58 per Bbl.

Oil and Gas Operations and Properties

Cotton Valley Trend

Overview. As of December 31, 2005, approximately 71% of our proved oil and gas reserves were in the Cotton Valley Trend of East Texas and Northwest Louisiana. We spent approximately 85% of our 2005 capital expenditures of $164.6 million in the Cotton Valley Trend. As of February 28, 2006, we have acquired or farmed in leases totaling approximately 129,000 gross acres and are continually attempting to acquire additional acreage in the area. Our total 129,000 gross acres includes company operated acreage comprising 84,000 gross acres (with an average working interest of 89%) and non-operated acreage comprising 45,000 gross acres (with an average working interest of 40%). As of the same date, we have drilled and/or completed 80 Cotton Valley wells with a 100% success rate. Our current Cotton Valley Trend drilling activities are centered about six primary leasehold areas in East Texas and Northwest Louisiana as further described below:

Dirgin-Beckville. The Dirgin-Beckville area is located in Panola County, Texas. We have acquired leases totaling approximately 12,000 gross acres with an average working interest of approximately 90%. As of February 28, 2006, we had successfully completed 32 Cotton Valley Trend wells in the Dirgin-Beckville area.

North Minden. The North Minden area is located in Rusk County, Texas. We have acquired leases totaling approximately 27,500 gross acres with a working interest of 100%. As of February 28, 2006, we had successfully drilled 31 Cotton Valley Trend wells in the North Minden area.

South Henderson. The South Henderson area is located in Rusk County, Texas. We have acquired leases totaling approximately 13,000 gross acres with an average working interest of approximately 80%. As of February 28, 2006, we had successfully completed five Cotton Valley Trend wells in the South Henderson area.

Bethany-Longstreet. The Bethany-Longstreet field is located in Caddo and DeSoto Parishes in Northwest Louisiana. As of February 28, 2006, we had successfully drilled seven Cotton Valley Trend wells in the field. Our initiative in this area began in the third quarter of 2003, when we obtained, via farmout, exploration rights to approximately 20,000 gross acres in the field. We have an average 70% working interest in the Bethany-Longstreet field.

Cotton, South. The Cotton South field is located in Angelina and Nacogdoches Counties, Texas. We had acquired approximately 25,000 gross acres in the field as of February 28, 2006 and had successfully drilled and logged two wells and recompleted two additional wells in the field which were drilled prior to the acquisition of our 40% working interest.

 

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Index to Financial Statements

Cotton. The Cotton field is located in Angelina and Nacogdoches Counties, Texas. We have acquired approximately 20,000 gross acres in the field with a 40% working interest and drilled our initial test well which has been tested in several Travis Peak intervals at initial rates ranging from 500 Mcf/day to 1,600 Mcf/day. Several additional Travis Peak intervals are currently being tested prior to the wells being placed on production. We have plans to drill a second well later in 2006.

Other Cotton Valley Trend. We also own 11,500 gross acres in four separate areas of the Cotton Valley Trend in Harrison, Smith and Upshur Counties, Texas, with an average working interest of 98%.

Production and Reserves. For the wells completed to date in the Cotton Valley Trend, the average initial gross production rate per well was approximately 1,500 Mcfe per day. This average initial gross production rate is consistent with the range we originally projected prior to commencing our drilling activities in the Cotton Valley Trend. Initial production from the Cotton Valley Trend wells commenced in June 2004 and for the quarter ended December 31, 2005, gross production from the initial and subsequently drilled wells was approximately 24,100 Mcfe of gas per day. As of December 31, 2005, our independent reserve engineering firm estimated that the average gross ultimate reserves for the Cotton Valley Trend were approximately 1.0 Bcfe per well on 40 acres spacing.

South Louisiana

Overview. As of December 31, 2005, approximately 26% of our proved oil and natural gas reserves were in the transition zone of South Louisiana. This region refers to the geographic area that covers the onshore and in-land waters of South Louisiana lying in the southern half of Louisiana, which is one of the most prolific oil and natural gas producing sedimentary basins. Our production in this region comes predominately from Miocene and Frio age formations in the following areas:

Burrwood and West Delta 83 Fields. The Burrwood/West Delta 83 fields, located in Plaquemines Parish, Louisiana, were discovered in 1955 by Chevron. We currently have interests in 28 active wells in the fields, with 18 currently producing and 10 shut-in from Hurricane Katrina. We have restored approximately 90% of our production from the fields relative to pre-hurricane levels. We have an average 55% working interest in the production and a 65% working interest in the leasehold in the field.

Lafitte Field. The Lafitte field is located in Jefferson Parish, Louisiana and was discovered in 1935 by Texaco. We own a non-operated, 49% working interest in the Lafitte field and currently have interests in 29 active producing wells in the field.

Second Bayou Field. The Second Bayou field is located in Cameron Parish, Louisiana and was discovered in 1955 by the Sun Texas Company. We serve as the operator of eight active wells, all of which have been restored to production levels prior to Hurricane Rita. We have an average working interest of approximately 31% in 1,395 gross acres.

St.Gabriel. The St. Gabriel field is located in Ascension and Iberville Parishes in southern Louisiana and was originally discovered by Shell Oil Company in 1939. In July 2004, we announced that we had acquired a 70% working interest in 3-D seismic permits and oil and gas lease options enabling us to acquire an approximate 30 square mile 3-D seismic survey over the field. We commenced shooting the 3-D seismic survey in July 2004 and data acquisition was completed in September 2004. As of February 28, 2006, we had successfully drilled and set pipe on our initial test well in the field. We anticipate drilling one additional well in the field later in 2006.

Other Fields. We maintain ownership interests in acreage and/or wells in several additional fields in Louisiana, including the (i) Ada field, located in Bienville Parish, (ii) Lake Raccourci field, located in Terrebonne Parish, (iii) Pecan Lake field, located in Cameron Parish and (iv) Plumb Bob field, located in St. Martin Parish.

 

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Index to Financial Statements

Other Properties

We maintain ownership interests in acreage and/or wells in several additional fields including the (i) Mary Blevins field, located in Smith County, Texas, (ii) Midway field, located in San Patricio County, Texas, (iii) Mott Slough field, located in Wharton County, Texas and (iv) the Garfield Unit, located in Kalkaska County, Michigan.

Oil and Natural Gas Reserves

The following tables set forth summary information with respect to our proved reserves as of December 31, 2005 and 2004, as estimated by us by compiling reserve information derived from the evaluations performed by Netherland, Sewell & Associates, Inc.

 

     Oil    Gas    Total    PV10
Value (1)
 
     (MBbls)    (MMcf)    (MMcfe)    (000s)  

December 31, 2005

           

Proved Developed

       1,796    56,700    67,474    $     328,058  

Proved Undeveloped

   3,177    86,263    105,325      259,618  
                       

Total Proved

   4,973        142,963        172,799      587,676  
                 

Discounted Future Income Taxes

              (177,056 )
                 

Standardized Measure of Discounted Future

           

Net Cash Flows (1)

            $ 410,620  
                 

December 31, 2004

           

Proved Developed

   2,228    24,362    37,732    $ 119,186  

Proved Undeveloped

   3,361    43,320    63,484      122,297  
                       

Total Proved

   5,589    67,682    101,216      241,483  
                 

Discounted Future Income Taxes

              (60,805 )
                 

Standardized Measure of Discounted Future

           

Net Cash Flows (1)

            $ 180,678  
                 

(1)

The PV10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. PV10 may be considered a non-GAAP measure as defined by the SEC. We believe that the presentation of the PV10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We further believe investors and creditors utilize our PV10 as a basis for comparison of the relative size and value of our reserves to other companies. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after estimated future income tax, discounted at 10%. Neither PV10 Value nor standardized measure of discounted future net cash flows reflects the impact of hedging transactions.

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 pre-tax PV10 Value 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, the engineers’ estimates of future net revenues from our properties and the pre-tax PV10 Value thereof are made using oil and natural gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The prices as of December 31, 2005 and 2004 used in such estimates averaged $10.54 and $6.14 per Mcf, respectively, of natural gas and $58.80 and $42.72 per Bbl, respectively, of crude oil/condensate. These prices do not include the impact of hedging transactions.

 

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Productive Wells

The following table sets forth the number of active well bores in which we maintain ownership interests as of December 31, 2005:

 

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

Louisiana

       52.00        25.47        16.00    8.37    68.00        33.84

Michigan

   –      –      1.00    0.01    1.00    0.01

Texas

   4.00    2.59    66.00        60.49    70.00    63.08
                             

Total Productive Wells

   56.00    28.06    83.00    68.87        139.00    96.93
                             

(1)

Does not include royalty or overriding royalty interests.

(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, 11 had multiple completions.

Acreage

The following table summarizes our gross and net developed and undeveloped natural gas and oil acreage under lease as of December 31, 2005. 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

Louisiana

       16,183    9,892    21,171    13,481    37,354        23,373

Michigan

   1,920    19    –      –      1,920    19

Texas

   43,856        39,032        68,360        34,774        112,216    73,806
                             

Total

   61,959    48,943    89,531    48,255    151,490    97,198
                             

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.

Operator Activities

We operate a majority in value of our producing properties, and will generally seek to become the operator of record on properties we drill or acquire in the future.

 

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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 fractional ownership working interests in gross wells equals one.

 

     Year Ended December 31,
     2005    2004    2003
     Gross    Net    Gross    Net    Gross    Net

Development Wells:

                 

Productive

       57.00        51.72        15.00        12.44    8.00        4.68

Non-Productive

   1.0    0.42    2.00    0.89    1.00    1.00
                             

Total

   58.00    52.14    17.0    13.33    9.00    5.68
                             

Exploratory Wells:

                 

Productive

   5.00    3.00    3.00    2.55    1.00    0.18

Non-Productive

   1.00    0.49    –      –      2.00    0.51
                             

Total

   6.00    3.49    3.00    2.55    3.00    0.69
                             

Total Wells:

                 

Productive

   62.00    54.72    18.00    14.99    9.00    4.86

Non-Productive

   2.00    0.91    2.00    0.89    3.00    1.51
                             

Total

   64.00    55.63    20.00    15.88        12.00    6.37
                             

At December 31, 2005, we had six development wells (5.4 net) and one exploratory well (0.70 net) that were in the process of being drilled.

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 fields, 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, 2005.

 

     2005     2004     2003  

Net Production:

      

Natural gas (MMcf)

     6,237       4,818       3,353  

Oil (MBbls)

     408       475       464  

Total (MMcfe)

     8,686       7,669       6,139  

Average Net Daily Production:

      

Natural gas (Mcf)

     17,087       13,163       9,186  

Oil (Bbls)

     1,118       1,299       1,272  

Natural gas equivalents (Mcfe)

         23,797           20,957           16,820  

Revenues (in thousands):

      

Natural gas

   $ 53,367     $ 31,315     $ 20,302  

Effect of settled derivatives (1) (2)

     –         (1,830 )     (2,403 )
                        

Total

   $ 53,367     $ 29,485     $ 17,899  
                        

Oil and condensate (Bbl)

   $ 21,885     $ 19,714     $ 14,253  

Effect of settled derivatives (Bbl) (2)

     (7,244 )     (4,338 )     (489 )
                        

Total

   $ 14,641     $ 15,376     $ 13,764  
                        

Natural gas and oil

   $ 75,252     $ 51,029     $ 34,555  

Effect of settled derivatives (Bbl) (1) (2)

     (7,244 )     (6,168 )     (2,892 )
                        

Total

   $ 68,008     $ 44,861     $ 31,663  
                        

Table and footnotes continued on following page

 

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     2005     2004     2003  

Average Realized Sales Price Per Unit:

      

Natural gas (Mcf)

   $ 8.56     $ 6.50     $ 6.06  

Effect of settled derivatives (Mcf) (1)(2)

     –         (0.38 )     (0.72 )
                        

Average realized price (Mcf)

   $ 8.56     $ 6.12     $ 5.34  
                        

Oil and condensate (Bbl)

   $     53.62     $     41.48     $     30.69  

Effect of settled derivatives (Bbl) (2)

     (17.75 )     (9.13 )     (1.05 )
                        

Average realized price (Bbl)

   $ 35.87     $ 32.35     $ 29.64  
                        

Natural gas and oil (Mcfe)

   $ 8.66     $ 6.65     $ 5.63  

Effect of settled derivatives (Mcfe) (1) (2)

     (0.83 )     (0.80 )     (0.47 )
                        

Average realized price (Mcfe)

   $ 7.83     $ 5.85     $ 5.16  
                        

Other Data:

      

Lease operating expense (per Mcfe) (3)

   $ 1.14     $ 0.97     $ 0.99  

Production taxes (per Mcfe)

     0.47       0.40       0.37  

DD&A (per Mcfe)

     2.94       1.51       1.45  

Exploration (per Mcfe)

     0.79       0.58       0.36  

(1)

Effect of settled derivatives on ineffective gas hedges in 2005 in the amount of $10,720,000 ($1.72 per Mcf) is reflected in “Gain (Loss) on Derivatives Not Qualifying for Hedge Accounting” on the Consolidated Statement of Operations.

(2)

Effect of settled derivatives on effective gas hedges in years 2004 and 2003 and on effective oil hedges in all years presented are included as a component of “Oil and Gas Revenues” on the Consolidated Statement of Operations.

(3)

Lease operating expenses increased on a per unit basis in 2005 due to non-recurring hurricane related expenses and other operating cost increases related to our South Louisiana properties. In future years, as we continue to develop our Cotton Valley Trend properties in East Texas and Northwest Louisiana, we expect our lease operating expenses to decrease on a per unit basis due to the lower cost nature of our Cotton Valley operations.

For a discussion of other comparative changes in our production volumes, revenues, and operating expenses for the three years ended December 31, 2005, 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. Our natural gas production is sold under spot or market-sensitive contracts to various gas purchasers on short-term contracts. Our natural gas condensate is sold under short-term rollover agreements based on current market prices. Our crude oil production is marketed to several purchasers based on short-term contracts.

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 these sources as a percent of oil and gas revenues for the periods presented were as follows:

 

     Year Ended December 31,
     2005    2004    2003

Louis Dreyfus Corporation

       34%        45%        47%

Shell Trading

   18%    5%    –      

Tristar Producer Services

   13%    –          –      

Chevron Texaco

   –          15%    –      

Texon LP

   –          –          25%

 

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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. The availability of a ready market for our oil and gas production will depend in part on the cost and availability of alternative fuels, the level of consumer demand, the extent of domestic production of oil and gas, the extent of importation of foreign oil and gas, the cost of and proximity to pipelines and other transportation facilities, regulations by state and federal authorities and the cost of complying with applicable environmental regulations.

Employees

At December 31, 2005 we had 64 full-time employees in our two administrative offices and our two field offices, none of whom is represented by any labor union. Nine of such full-time employees are field personnel involved in oil and natural gas producing activities. 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.

Available Information

Our website address is www.goodrichpetroleum.com. We make available, free of charge through the Investor Relations portion of this 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 1934 Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Reports of beneficial ownership filed pursuant to Section 16(a) of the 1934 Act are also available on our website. Information contained on our website is not part of this report.

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.

Environmental Matters

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. These laws and regulations may require the acquisition of various 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 activities on certain lands lying within wilderness, wetlands and other protected areas and require remedial measures to mitigate pollution from former and

 

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ongoing operations. Failure to comply with these laws and regulations may result in the issuance of administrative, civil and criminal penalties, the assessment of remedial obligations, and the imposition of injunctions to force future compliance.

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 Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and analogous state laws impose strict, joint and several liability 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 those that disposed or arranged for the disposal of hazardous substances released at the site. Persons who are responsible for releases under CERCLA may be subject to joint and several liability for remediation costs at the site, and may also be liable for natural resource damages. 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”), which imposes requirements related to the handling and disposal of solid and hazardous wastes. The U.S. Environmental Protection Agency (“EPA”) and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. While there exists an exclusion from the definition of hazardous wastes for certain materials generated in the exploration, development or production of oil and gas, we generate petroleum product wastes and ordinary industrial wastes that may be regulated as solid and hazardous wastes.

The Federal Water Pollution Control Act (“Clean Water Act”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. 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 liability for specified oil removal costs and certain other damages arising from a spill. We believe our operations are in substantial compliance with the Clean Water Act and OPA requirements.

The Federal Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. 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. We believe our operations are in substantial compliance with applicable air permitting and control technology requirements.

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

 

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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.

Management believes 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.

Item 1A.    Risk Factors

Our financial and operating results are subject to a number of factors, many of which are not within our control. These factors include the following:

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 independent reserve engineers and were calculated using oil and gas prices as of December 31, 2005. These prices will change and may be lower at the time of production than those prices that prevailed at the end of 2005. 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 areas;

  ·  

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 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 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.

 

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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 calculation our pre-tax PV10 Value, 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.

Natural gas and oil prices are volatile, and low prices have had in the past and could have in the future a material adverse impact on 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, or OPEC, 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.

Average oil and natural gas prices increased substantially from 2002 to 2003, from 2003 to 2004 and during 2005. 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. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of funds available to us to reinvest in exploration and development activities. Reductions in oil and natural gas prices not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable. Significant declines in prices could result in non-cash charges to earnings due to impairment. We use derivative financial instruments to hedge a portion of our exposure to changing commodity prices and we have hedged a targeted portion of our anticipated production for 2006 through 2007.

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

We use hedging transactions with respect to a portion of our oil and natural gas production to achieve more predictable cash flow and to reduce our exposure to price fluctuations. While the use of hedging transactions limits the downside risk of price declines, their use may also limit future revenues from price increases.

Our results of operations may be negatively impacted by our financial derivative instruments and fixed price forward sales contracts in the future and these instruments may limit any benefit we would receive from increases in the prices for oil and natural gas. For the years ended December 31, 2005, 2004 and 2003, we realized a loss on settled financial derivatives of $18.0 million, $6.2 million and $2.9 million, respectively.

For the year ended December 31, 2005, we recognized in earnings an unrealized loss on derivative instruments not qualifying for hedge accounting in the amount of $27.0 million For financial reporting purposes, this unrealized loss was combined with a $10.7 million realized loss in 2005 resulting in a total unrealized and realized loss on derivative instruments not qualifying for hedge accounting in the amount of $37.7 million in 2005. For the year ended December 31, 2004, we recognized in earnings an unrealized gain on derivative instruments in the amount of $2.3 million. This loss and gain were recognized because the natural gas hedges were deemed to be ineffective for 2005 and for the fourth quarter of 2004, and accordingly, the changes in fair value of such hedges could no longer be reflected in other comprehensive income, a component of stockholders’ equity. To the extent that the hedges are not deemed to be effective in the future, we will likewise be exposed to volatility in earnings resulting from changes in the fair value of our hedges.

 

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Delays in development or production curtailment affecting our material properties may adversely affect our financial position and results of operations.

The size of our operations and our capital expenditure budget limits the number of wells that we can develop in any given year. Complications in the development of any single material well may result in a material adverse affect on our financial condition and results of operations. In addition, a relatively small number of wells contribute a substantial portion of our production. If we were to experience operational problems resulting in the curtailment of production in any of these wells, our total production levels would be adversely affected, which would have a material adverse affect on our financial condition and results of operations.

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. Where we are not the majority owner or operator of an oil and gas property, such as the Lafitte field, 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.

We may have difficulty financing our planned growth.

We have experienced and expect to continue to experience substantial capital expenditure and working capital needs, particularly as a result of our drilling program. In the future, we expect that we will require additional financing, in addition to cash generated from operations, to fund planned growth. We cannot be certain that additional financing will be available on acceptable terms or at all. In the event additional capital resources are unavailable, we may curtail drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.

If we are not able 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 61% of our total estimated proved reserves by volume at December 31, 2005 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. We may not be able to successfully find and produce reserves economically in the future. In addition, we may not be able to acquire proved reserves at acceptable costs.

We may incur substantial impairment writedowns.

If management’s estimates of the recoverable reserves on a property are revised downward or if oil and natural gas prices decline, it may be required to record additional non-cash impairment writedowns in the future, which would result in a negative impact to our financial position. 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

 

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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, impairment 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, 2005, 2004 and 2003, we recorded impairments of $0.3 million, $0 and $0.3 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 geographic area.

Approximately 97% of our estimated proved reserves at December 31, 2005 and a similar percentage of our production during 2005 were associated with our Cotton Valley Trend and South Louisiana properties. Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue.

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.

Our oil and gas operations are subject to the economic risks typically associated with exploration, development and production activities, including the necessity of significant expenditures to locate and acquire properties and to drill exploratory wells. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause our exploration, development and production activities to be unsuccessful. This could result in a total loss of our investment in a particular property. If exploration efforts are unsuccessful in establishing proved reserves and exploration activities cease, the amounts accumulated as unproved costs would be charged against earnings as impairments. In addition, the cost and timing of drilling, completing and operating wells is often uncertain.

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

Our senior credit facility and our second lien term loan contain 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 credit facility and term loan. As of December 31, 2005, we were in compliance with all the financial covenants of our credit facility and term loan. 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.

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

The acquisition of properties requires us to assess a number of factors, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well, 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 that we created. We may be required to assume the risk of 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.

We are subject to complex laws and regulations, including environmental regulations that can adversely affect the cost, manner or feasibility of doing business.

Development, production and sale of natural gas and oil in the U.S. are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:

 

  ·  

discharge permits for drilling operations;

  ·  

bonds for ownership, development and production of oil and gas properties;

  ·  

reports concerning operations; and

  ·  

taxation.

In addition, our operations are subject to stringent federal, state and local environmental laws and regulations governing the discharge of materials into the environment and environmental protection. Governmental authorities enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or prohibiting some or all of our operations. There is inherent risk of incurring significant environmental costs and liabilities in our business. Joint and several strict liability may be incurred in connection with discharges or releases of petroleum hydrocarbons and wastes on, under or from our properties and from facilities where our wastes have been taken for disposal. Private parties affected by such discharges or releases may also have the right to pursue legal actions to enforce compliance as well as seek damages for personal injury or property damage. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly requirements could have a material adverse effect on our business.

 

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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.

Some of our operations are exposed to the additional risk of tropical weather disturbances.

Some of our production and reserves are located in South Louisiana. Operations in this area are subject to tropical weather disturbances. Some of these disturbances can be severe enough to cause substantial damage to facilities and possibly interrupt production. For example, Hurricanes Katrina and Rita impacted our South Louisiana operations in the third quarter of 2005 causing the shut-in of our Burrwood/West Delta 83 and Lafitte fields in late August and the shut-in of our Second Bayou field in late September. We estimate that approximately 6,000 and 4,000 Mcfe per day of net production for the third and fourth quarters of 2005, respectively, was shut-in as a result of the hurricanes. The fourth quarter amount represents 25% of pre-hurricane South Louisiana production volumes. As of December 31, 2005, we had restored approximately 90% of our pre-hurricane volumes in South Louisiana, with the remaining pre-hurricane production volumes being temporarily shut-in awaiting completion of facility and well repairs. Damage to our facilities due to the two hurricanes was substantially covered by insurance. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks. For more information on the impact of Hurricanes Katrina and Rita on our operations, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot assure you that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. An event that is not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

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.

 

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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

In the third quarter of 2004, we recognized a non-recurring gain in the amount of $2.1 million, reflecting the proceeds of a successful litigation judgment. We commenced the litigation as plaintiff in February 2000 against the operator of a South Louisiana property which was jointly acquired by us and the defendant in September 1999. The judgment provided for recovery of our damages and a portion of our attorneys’ fees as well as interest calculated on our damages.

We are party to additional lawsuits arising in the normal course of business. We intend to defend these actions vigorously and believe, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our financial position or results of operations.

Item 4.    Submission of Matters to a Vote of Security Holders

None.

 

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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 March 10, 2006, the number of holders of record of our common stock without determination of the number of individual participants in security positions was 1,594 with 24,904,941 shares outstanding. High and low sales prices for our common stock for each quarter during the calendar years 2005 and 2004 are as follows:

 

     2005    2004
     High    Low    High    Low

March 31

   $     25.39    $     14.61    $     10.20    $ 5.07

June 30

     23.36      14.74      8.83      6.20

September 30

     24.80      19.00      14.08      8.27

December 31

     26.29      19.25      16.46          11.91

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 repurchases of our common stock for the year ended December 31, 2005.

 

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Item 6.    Selected Financial Data

(In thousands, except per share data)

The following table sets forth our selected 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.

 

     Year Ended December 31,  
     2005     2004     2003     2002     2001  

Statement of Operations Data:

          

Revenues

          

Oil and gas revenues

   $      68,008     $     44,861     $     31,663     $     18,502     $     28,342  

Other

     325       151       477       131       353  
                                        
     68,333       45,012       32,140       18,633       28,695  
                                        

Operating Expenses

          

Lease operating expense

     9,931       7,402       6,099       7,523       6,299  

Production taxes

     4,053       3,105       2,288       1,642       1,808  

Depletion, depreciation and amortization

     25,563       11,562       8,996       7,023       7,158  

Exploration

     6,867       4,426       2,249       1,019       4,284  

Impairment of oil and gas properties

     340       –         335       342       1,800  

General and administrative

     8,702       5,821       5,314       4,468       3,135  

(Gain) loss on sale of assets

     (235 )     (50 )     66       (2,941 )     (27 )
                                        
     55,221       32,266       25,347       19,076       24,457  
                                        

Operating income (loss)

     13,112       12,746       6,793       (443 )     4,238  
                                        

Other income (expense):

          

Interest expense

     (2,279 )     (1,110 )     (1,051 )     (985 )     (1,291 )

Gain (loss) on derivatives not
qualifying for hedge accounting

     (37,680 )     2,317       –         –         –    

Gain on litigation judgment

     –         2,118       –         –         –    
                                        
     (39,959 )     3,325       (1,051 )     (985 )     (1,291 )
                                        

Income (loss) from continuing operations
before income taxes

     (26,847 )     16,071       5,742       (1,428 )     2,947  

Income tax (expense) benefit

     9,397       1,707       (2,016 )     496       (1,036 )
                                        

Income (loss) from continuing operations

     (17,450 )     17,778       3,726       (932 )     1,911  

Discontinued operations including gain on
sale, net of income taxes

     –         749       196       (19 )     324  
                                        

Income (loss) before cumulative effect of
change in accounting principle

     (17,450 )     18,527       3,922       (951 )     2,235  

Cumulative effect of change in
accounting principle, net of income taxes

     –         –         (205 )     –         –    
                                        

Net income (loss)

     (17,450 )     18,527       3,717       (951 )     2,235  

Preferred stock dividends

     755       633       633       640       3,003  
                                        

Net income (loss) applicable to common stock

   $ (18,205 )   $ 17,894     $ 3,084     $ (1,591 )   $ (768 )
                                        

Net income (loss) per common share
from continuing operations

          

Basic

   $ (0.75 )   $ 0.91     $ 0.21     $ (0.05 )   $ 0.11  

Diluted

   $ (0.75 )   $ 0.87     $ 0.18     $ (0.05 )   $ 0.11  

Weighted average number of common
shares outstanding:

          

Basic

     23,333       19,552       18,064       17,908       17,351  

Diluted

     23,333       20,347       20,482       17,908       17,351  

 

     December 31,
     2005      2004      2003      2002      2001

Balance Sheet Data:

                      

Total assets

   $   296,526      $   127,977      $     89,182      $     78,567      $     81,150

Total long–term debt

     30,000        27,000        20,000        18,500        24,500

Stockholders’ equity

     181,589        65,307        48,059        44,607        46,827

 

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

General

We are an independent oil and gas company engaged in the exploration, exploitation, development and production of oil and natural gas properties primarily in the Cotton Valley Trend of East Texas and Northwest Louisiana and in the transition zone of South Louisiana. We operate as one segment as each of our operating areas have similar economic characteristics and each meet the criteria for aggregation as defined in the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

We own working interests in 139 active oil and gas wells located in 19 fields in three states. At December 31, 2005, we had estimated proved reserves of approximately 5.0 MMBbls of oil and condensate and 143.0 Bcf of natural gas, or an aggregate of 172.8 Bcfe with a pre-tax present value of future net cash flows, discounted at 10%, of $587.7 million and an after-tax present value of discounted future net cash flows of $410.6 million. See Items 1. and 2. – “Business and Properties – Oil and Natural Gas Reserves” for a reconciliation to the standardized measure of discounted future net cash flows.

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 such as us.

Management strives to increase our oil and gas reserves, production and cash flow through a balanced program of capital expenditures involving acquisition, exploitation and exploration activities. We generally do not make capital commitments beyond one year. 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.

Our revenues and operating cash flow are dependent on the successful development of our inventory of capital projects, 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.

As further described under “Results of Operations” below, we achieved significant increases in oil and gas production volumes and operating cash flows in the years ended December 31, 2005 and 2004. These trends largely reflect the results of our successful drilling program as we increased our capital expenditures from $19.9 million in 2003 to $47.5 million in 2004 and $164.6 million in 2005. We also benefited from strong commodity pricing environments in 2003, 2004 and 2005.

 

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Impact of Hurricanes Katrina and Rita

On August 29, 2005, Hurricane Katrina struck the Gulf Coast region of the United States passing directly over our Burrwood/West Delta 83 field causing damage to one producing well (Norton) and our onshore and offshore facilities in the field. As of December 31, 2005, we estimated that the gross damage costs to the Norton well were approximately $3.5 million and that the gross damage costs to the various facilities were approximately $3.9 million. These amounts are current estimates and are subject to change as we complete our damage assessment and complete our insurance claims. The net book value of the Norton well at such time was treated as a partial abandonment and removed from the amortization base with no gain or loss being recognized. We have an approximate 65% working interest in most of the Burrwood/West Delta 83 field and two other working interest owners own the remaining 35% (our interest in certain wells is less than 65% due to additional working interest owners). All working interest owners participate jointly with us in the insurance coverage. Therefore, we and the other working interest owners will share proportionately in the allocation of the deductible amount as well as in the allocation of the insurance proceeds that are ultimately received. We anticipate all but approximately 10% of the costs incurred and remaining to be incurred from Hurricane Katrina to be reimbursed from insurance proceeds. This amount represents a net exposure to us of approximately $0.5 million.

On September 24, 2005, Hurricane Rita also struck the Gulf Coast, passing over our Second Bayou field in Southwest Louisiana, causing damage to some facilities but to none of the producing wells. As of December 31, 2005, we estimated that the gross damage costs to the facilities were approximately $0.7 million. We have an average 26% working interest in the Second Bayou field. Our other working interest owners, who own the remaining 74% working interest, also participate jointly with us in the insurance coverage and will therefore share proportionately in the allocation of the deductible amount as well as in the allocation of the insurance proceeds that are ultimately received. We anticipate approximately 20% of the costs incurred and remaining to be incurred from Hurricane Rita to be reimbursed from insurance proceeds. This amount represents a net exposure to us of approximately $0.2 million.

At December 31, 2005, we had incurred capital costs of $3.3 million to remediate the damage, net of amounts due from other working interest owners of $2.0 million and exclusive of any potential insurance recoveries, which will increase the capitalized value of the facilities. Based on preliminary evaluations of all damages, we have recorded a loss of $0.2 million representing amounts incurred from Hurricane Rita that will not ultimately be covered by insurance. This loss is included in lease operating expense in the Consolidated Statement of Operations. Negotiations with our insurance carrier are expected to be completed during 2006.

We estimate that approximately 6,000 and 4,000 Mcfe per day of net production for the third and fourth quarters of 2005, respectively, was shut-in as a result of the hurricanes. The fourth quarter amount represents 25% of pre-hurricane South Louisiana volumes. As of December 31, 2005, we had restored approximately 90% of our pre-hurricane volumes in South Louisiana, with the remaining pre-hurricane production volumes being temporarily shut-in awaiting completion of facility and well repairs.

Results of Operations

Year ended December 31, 2005 versus year ended December 31, 2004—Total revenues from continuing operations for the year ended December 31, 2005 were $68.3 million compared to $45.0 million for the year ended December 31, 2004. Oil and gas sales for the year ended December 31, 2005 were $68.0 million compared to $44.9 million for the year ended December 31, 2004. This increase resulted from a 13% increase in oil and gas production volumes, due to a substantial increase in Cotton Valley Trend production, as well as higher average oil and gas prices. Partially offsetting this increase was a decline in South Louisiana production, due to natural decline and the effects of shut-ins due to the hurricanes.

 

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The following table presents the production volumes and pricing information for the comparative periods, which excludes the realized losses on our ineffective gas derivatives for 2005 (see Items 1. and 2. “Business and Properties – Net Production, Unit Prices and Costs”).

 

     2005    2004
     Production    Average
Sales Price
   Production    Average
Sales Price

Gas (MMcf)

   6,237    $ 8.56    4,818    $ 6.12

Oil (MBbl)

   408          35.87    475          32.35

Lease operating expense was $9.9 million for the year ended December 31, 2005 versus $7.4 million for the year ended December 31, 2004, with the increase due to an increase in production volumes as well as an increase in hurricane related operating expenses in South Louisiana. Production taxes were $4.1 million for the year ended December 31, 2005 compared to $3.1 million for the year ended December 31, 2004, due to an increase in production volumes and product prices.

Depletion, depreciation and amortization expense (“DD&A”) was $25.6 million for the year ended December 31, 2005 versus $11.6 million for the year ended December 31, 2004, with the increase due to higher production volumes and higher DD&A rates. The higher rates are a result of an increase in capitalized development costs. Exploration expense for the year ended December 31, 2005 was $6.9 million versus $4.4 million for the year ended December 31, 2004, primarily due to increased dry hole costs from an exploratory well drilled in East Baton Rouge Parish, Louisiana, and higher non-producing leasehold amortization expense associated with the expansion of our Cotton Valley Trend acreage position. We recorded an impairment of $0.3 million in the recorded value of one property for the year ended December 31, 2005 due to sooner than anticipated depletion of reserves.

General and administrative (“G&A”) expenses increased to $8.7 million for the year ended December 31, 2005 from $5.8 million for the year ended December 31, 2004. This increase was primarily due to higher compensation related costs due to an approximate 25% increase in the number of employees in 2005 and professional fees related to the implementation of the requirements of Section 404 of the Sarbanes-Oxley Act of 2002. Stock-based compensation, which consists of the amortization of restricted stock awards and is included in G&A expenses, increased to $1.1 million for the year ended December 31, 2005 compared to $0.6 million for the comparable period in 2004 due to the vesting of awards previously granted.

Interest expense was $2.3 million for the year ended December 31, 2005 compared to $1.1 million for the year ended December 31, 2004, with the increase primarily attributable to a higher level of average borrowings in 2005.

Loss on derivatives not qualifying for hedge accounting relates to our ineffective gas hedges and amounted to $37.7 million for the year ended December 31, 2005, compared to a gain of $2.3 million for the year ended December 31, 2004. The loss in 2005 includes a realized loss of $10.7 million for the effect of settled derivatives on our ineffective gas hedges and an unrealized loss of $27.0 million for the changes in fair value of our ineffective gas hedges. Since our natural gas hedges were deemed ineffective, beginning in the fourth quarter of 2004, we have been required to reflect the changes in the fair value of our natural gas hedges in earnings rather than in accumulated other comprehensive loss, a component of stockholders’ equity. As applied to our hedging program, there must be a high degree of correlation between the actual prices received and the hedge prices in order to justify treatment as cash flow hedges pursuant to SFAS 133. We perform historical correlation analyses of the actual and hedged prices over an extended period of time. In the fourth quarter of 2004, we initially determined that our gas hedges fell short of the effectiveness guidelines to be accounted for as cash flow hedges and, likewise, made the same determination in each of the four quarters of 2005. To the extent that our hedges are deemed to be ineffective in the future, we will likewise be exposed to volatility in earnings resulting from changes in the fair value of our hedges.

 

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Gain on litigation judgment of $2.1 million for the year ended December 31, 2004 resulted from the final judgment ordered by the trial judge in our favor our litigation against the operator of the Lafitte field. See Item 3. “Legal Proceedings.”

Income taxes from continuing operations were benefits of $9.4 million and $1.7 million for the years ended December 31, 2005 and 2004, respectively, representing 35% of the pre-tax loss in 2005. In the prior year, a revision in the deferred tax valuation allowance of $7.3 million was recorded based on the anticipated reversal of temporary differences in 2004. The net deferred tax asset as of December 31, 2005 is expected to be realized based upon expected utilization of tax net operating loss carryforwards and the projected reversal of temporary differences.

Income from discontinued operations, net of income taxes, was $0.7 million for the year ended December 31, 2004 consisted largely of the pre-tax gain realized on the sale of our operated interests in the Marholl and Sean Andrew fields, along with our non-operated interests in the Ackerly field, all of which were located in West Texas.

Year ended December 31, 2004 versus year ended December 31, 2003 — Total revenues from continuing operations for the year ended December 31, 2004 amounted to $45.0 million compared to $32.1 million for the year ended December 31, 2003. Oil and gas sales for the year ended December 31, 2004 were $44.9 million compared to $31.7 million for the year ended December 31, 2003. This increase resulted from a 25% increase in oil and gas production volumes, due to several successful well completions since the first quarter of 2003, as well as increase in average oil and gas prices. The following table presents the production volumes and pricing information for the comparative periods, which includes realized gains and losses on the effective portion of our oil and gas derivatives (see Items 1. and 2. “Business and Properties – Net Production, Unit Prices and Costs”).

 

     2004    2003
     Production    Average
Sales Price
   Production    Average
Sales Price

Gas (MMcf)

   4,818    $ 6.12    3,353    $ 5.34

Oil (MBbl)

   475          32.35    464          29.64

Other revenues for the year ended December 31, 2004 were $0.2 million compared to $0.5 million for the year ended December 31, 2003, with the decrease primarily due to the absence of prospect fees received on two drilling prospects in the first quarter of 2003.

Lease operating expense from continuing operations was $7.4 million for the year ended December 31, 2004 versus $6.1 million for the year ended December 31, 2003, with the increase largely resulting from an increase in the number of producing wells. Production taxes from continuing operations were $3.1 million for the year ended December 31, 2004 compared to $2.3 million for the year ended December 31, 2003, due to an increase in production volumes.

Depletion, depreciation and amortization expense from continuing operations was $11.6 million for the year ended December 31, 2004 versus $9.0 million for the year ended December 31, 2003, with the increase due to higher production volumes and depletion rates. Exploration expense for the year ended December 31, 2004 was $4.4 million versus $2.2 million for the year ended December 31, 2003, with the increase primarily due to seismic costs in the Plumb Bob and St. Gabriel fields and higher non-producing leasehold amortization expense, partially offset by a decrease in exploratory dry hole costs. We recorded no impairment in the recorded value of our oil and gas properties for the year ended December 31, 2004 whereas for the year ended December 31, 2003, it recorded an impairment in the amount of $0.3 million due primarily to a sooner than anticipated depletion of reserves in certain fields.

 

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G&A expenses were $5.8 million for the year ended December 31, 2004 as compared to $5.3 million for the comparable period in 2004. Our payroll and employee benefits expense increased to $2.2 million for the year ended December 31, 2004 from $1.6 million for the year ended December 31, 2003, primarily due to an increase in the number of employees. Stock-based compensation, which consists of the amortization of restricted stock awards, increased to $0.6 million for the year ended December 31, 2004 compared to $0.2 million for the comparable period in 2003 due to the vesting of awards previously granted. Partially offsetting these increases were decreases in legal fees and certain other administrative expenses.

Gain on derivatives not qualifying for hedge accounting was $2.3 million for the year ended December 31, 2004. The gain was the result of our natural gas hedges being deemed ineffective in the fourth quarter of 2004. This designation resulted in the changes in the fair value of such hedges being reflected in earnings rather than in accumulated other comprehensive income. As applied to our hedging program, there must be a high degree of correlation between the actual prices received and the hedge prices in order to justify treatment as cash flow hedges pursuant to SFAS 133. We perform historical correlation analyses of the actual and hedged prices over an extended period of time. To the extent that our hedge are deemed to be ineffective in the future, we will likewise be exposed to volatility in earnings resulting from changes in the fair value of our hedges.

Gain on litigation judgment of $2.1 million for the year ended December 31, 2004 resulted from the final judgment ordered by the trial judge in our favor in our litigation against the operator of the Lafitte field.

Income taxes attributable to continuing operations were a benefit of $1.7 million for the year ended December 31, 2004 compared to an expense of $2.0 million for the year ended December 31, 2003. We revised our deferred tax valuation allowance for the year ended December 31, 2004, based on the anticipated utilization of tax operating loss carryforwards and projected reversal of temporary differences, whereas for the year ended December 31, 2003 income tax expense represented 35% of pre-tax income attributable to continuing operations.

Income from discontinued operations, net of income taxes, was $0.8 million for the year ended December 31, 2004 consisting largely of the pre-tax gain realized on the sale of our operated interests in the Marholl and Sean Andrew fields, along with our non-operated interests in the Ackerly field, all of which were located in West Texas. The results of operations of these non-core properties, including the pre-tax gain of $0.9 million realized on the sale, have been classified as discontinued operations in the consolidated statement of operations, net of income tax expense at a 35% rate.

Liquidity and Capital Resources

Cash Flows

Operating activities. Cash flow from operations is dependent upon our ability to increase production through development, exploration and acquisition activities and the price of oil and natural gas. Our cash flow from operations also is impacted by changes in working capital. Net cash provided by operating activities increased to $45.6 million, up 11% from $41.0 million in 2004 and up 165% from $17.2 million in 2003. The increases in 2005 and 2004 were a result of the increases in natural gas and crude oil prices and production levels in 2005 compared to 2004 and 2003, partially offset by increases in lease operating expenses, exploration expenses and general and administrative expenses. Including the effect of settled derivatives, sales of oil and gas increased $12.4 million in 2005 compared to 2004, with realized crude oil and natural gas prices and production volumes both increasing 13% in 2005 compared to 2004. Operating cash flow amounts are net of changes in our current assets and current liabilities, which resulted in adjustments to our operating cash flow in the amounts of $13.3 million and $14.1 million, respectively, in the years ended December 31, 2005 and 2004, primarily reflecting increased revenue and expenditure activity associated with our Cotton Valley Trend wells.

 

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Investing activities. Net cash used in investing activities was $163.6 million for the year ended December 31, 2005 compared to $45.4 million and $19.5 million for the years ended December 31, 2004 and 2003, respectively. For the year ended December 31, 2005, capital expenditures totaled $164.6 million primarily due to development on our Cotton Valley Trend wells, which accounted for 85% of the capital costs incurred in 2005. For the year ended December 31, 2004, capital expenditures totaled $47.5 million, as we incurred substantial drilling and leasehold acquisition costs in East Texas and Northwest Louisiana and participated in the drilling of two successful exploratory wells and one successful sidetrack well in the Burrwood/West Delta 83 field. Offsetting these capital expenditures were sales of non-core properties in West Texas and another minor property in the total amount of $2.1 million. For the year ended December 31, 2003, capital expenditures totaled $19.9 million as we participated in the drilling of nine new wells in our Burrwood/West Delta 83, Lafitte and Bethany-Longstreet fields (eight of which were successfully completed).

Financing activities. Net cash provided by financing activities was $134.4 million for the year ended December 31, 2005 compared to $6.4 million and $0.5 million for the years ended December 31, 2004 and 2003, respectively. In May 2005, we completed a public offering of 3,710,000 shares of our common stock resulting in net proceeds of $53.1 million which was used to repay all then outstanding indebtedness to BNP under a senior credit facility. On December 21, 2005, we issued and sold 1,650,000 shares of our Series B Convertible Preferred Stock for net proceeds of approximately $79.8 million through a private placement. Net borrowings under our senior credit facility and term loan both before and after the May 2005 public equity offering and Series B Convertible Preferred Stock offering provided cash of $3.0 million for the year ended December 31, 2005. (see “Senior Credit Facility and Term Loan”). For the year ended December 31, 2004, net proceeds under our senior credit facility provided cash of $7.0 million and $1.5 million for the years ended December 31, 2004 and 2003, respectively.

For the year 2006, we have preliminarily budgeted total capital expenditures of approximately $195.0 million, of which approximately 85% is expected to be focused on the relatively low risk development drilling program in the Cotton Valley Trend of East Texas and Northwest Louisiana and the remainder on our existing properties and new exploration programs. Subject to current economics and financial resources, we expect to finance our 2006 capital expenditures through a combination of cash flow from operations, borrowings under our existing bank credit facility (see “Senior Credit Facility and Term Loan”) and remaining proceeds from our December 2005 Series B Convertible Preferred Stock offering. In the future, we may issue additional debt or equity securities to provide additional financial resources for our capital expenditures and other general corporate purposes. Our senior credit facility and term loan include certain financial covenants with which we were in compliance as of December 31, 2005. We do not anticipate a lack of borrowing capacity under our senior credit facility or term loan in the foreseeable future due to an inability to meet any such financial covenants nor a reduction in our borrowing base.

Series B Convertible Preferred Stock

On December 21, 2005, we completed a private placement with a group of institutional investors raising net proceeds of $79.8 million (after offering costs of $2.7 million). In the private placement, we issued and sold 1,650,000 shares of our Series B Convertible Preferred Stock. The purchase price of each share of Series B Convertible Preferred Stock was equal to the liquidation preference of $50 per share. The issuance of shares in this transaction was exempt from registration under the Securities Act of 1933 pursuant to Section 4(2) of the Securities Act.

Each share is convertible at the option of the holder into our common stock, par value $0.20 per share (the ”Common Stock”) at any time at an initial conversion rate of 1.5946 shares of Common Stock per share, which is equivalent to an initial conversion price of approximately $31.36 per share of Common Stock. Upon conversion of the Series B Convertible Preferred Stock (pursuant to a voluntary conversion or the Company Conversion Option (as defined in the Certificate of Designation of the Series B Convertible Preferred Stock (the “Certificate of Designation”), we may choose to deliver the conversion value to holders in cash, shares of Common Stock, or a combination of cash and shares of Common Stock. If a Fundamental Change (as defined in the Certificate of Designation) occurs, holders may require us in specified circumstances to repurchase all or

 

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part of the Series B Convertible Preferred Stock. In addition, upon the occurrence of a Fundamental Change or Specified Corporate Events (as defined in the Certificate of Designation), we will under certain circumstances increase the conversion rate by a number of additional shares of Common Stock.

On or after December 21, 2010, we may, at our option, cause the Series B Convertible Preferred Stock to be automatically converted into that number of shares of Common Stock that are issuable at the then-prevailing conversion rate, pursuant to the Company Conversion Option. We may exercise our conversion right only if, for 20 trading days within any period of 30 consecutive trading days ending on the trading day prior to the announcement of our exercise of the option, the closing price of the Common Stock equals or exceeds 130% of the then-prevailing conversion price of the Series B Convertible Preferred Stock. The Series B Convertible Preferred Stock is non-redeemable by us.

We used the net proceeds of the offering of Series B Convertible Preferred Stock to fully repay all outstanding indebtedness under our senior revolving credit facility in the amount of $47.5 million (see “Senior Credit Facility and Term Loan”). The remaining net proceeds of the offering were added to our working capital to fund 2006 capital expenditures and for other general corporate purposes. In February 2006, we fully redeemed all issued and outstanding shares of our Series A Convertible Preferred Stock at a cost of approximately $9.5 million.

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 $29.2 million, which will be used to fund our 2006 capital expenditure program.

Senior Credit Facility and Term Loan

On November 17, 2005, we amended our existing credit agreement and entered into an amended and restated senior credit agreement (the “Amended and Restated Credit Agreement”) and a funded $30.0 million second lien term loan (the “Second Lien Term Loan Agreement”) that expanded our borrowing capabilities and extended our credit facility for an additional two years. Total lender commitments under the Amended and Restated Credit Agreement were increased from $50.0 million to $200.0 million and the maturity was extended from February 25, 2008 to February 25, 2010. Revolving borrowings under the Amended and Restated Credit Agreement are subject to periodic redeterminations of the borrowing base which is currently established at $75.0 million, and is currently scheduled to be redetermined in late March 2006, based upon our 2005 year-end reserve report. With a portion of the net proceeds of the offering of Series B Convertible Preferred Stock in December 2005, we fully repaid all outstanding indebtedness in the amount of $47.5 million leaving a zero balance outstanding as of December 31, 2005 (see “Series B Convertible Preferred Stock”). Interest on revolving borrowings under the Amended and Restated Credit Agreement accrues at a rate calculated, at our option, at either the bank base rate plus 0.00% to 0.50%, or LIBOR plus 1.25% to 2.00%, depending on borrowing base utilization. BNP Paribas (“BNP”) is the lead lender and administrative agent under the amended credit facility with Comerica Bank and Harris Nesbit Financing, Inc. as co-lenders.

The terms of the Amended and Restated Credit Agreement require us to maintain certain covenants. Capitalized terms are defined in the credit agreement. The covenants include:

 

  ·  

Current Ratio of 1.0/1.0;

  ·  

Interest Coverage Ratio which is not less than 3.0/1.0 for the trailing four quarters, and

  ·  

Tangible Net Worth of not less than $53,392,838, plus 50% of cumulative net income after September 30, 2004, plus 100% of the net proceeds of any subsequent equity issuance.

As of December 31, 2005, we were in compliance with all of the financial covenants of the credit agreement.

 

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The Second Lien Term Loan Agreement provides for a 5-year, non-revolving loan of $30.0 million which was funded on November 17, 2005 and is due in a single maturity on November 17, 2010. Optional prepayments of term loan principal can be made in amounts of not less than $5.0 million during the first year at a 1% premium and without premium after the first year. Interest on term loan borrowings accrues at a rate calculated, at our option, at either base rate plus 3.50%, or LIBOR plus 4.50%, and is payable quarterly. BNP is the lead lender and administrative agent under the Second Lien Term Loan Agreement. At December 31, 2005, borrowings outstanding under the term loan were $30.0 million.

The terms of the Second Lien Term Loan Agreement require us to maintain certain covenants. Capitalized terms are defined in the loan agreement. The covenants include:

 

  ·  

Total Debt to EBITDAX Ratio which is not greater than 4.0/1.0 for the most recent period of four fiscal quarters for which financial statements are available and

  ·  

Asset Coverage Ratio to be not less than 1.5/1.0.

As of December 31, 2005, we were in compliance with all of the financial covenants of the Second Lien Term Loan Agreement.

Cotton Valley Trend

In the first quarter of 2004, we commenced what we believe is a relatively low risk drilling program which was initially focused on operated acreage in the Cotton Valley Trend in and around Rusk and Panola Counties, Texas, and DeSoto and Caddo Parishes, Louisiana. We have increased our acreage position from approximately 45,000 gross acres at December 31, 2004 to 129,000 gross acres as of February 28, 2006. This amount reflects a 40% non-operated working interest in approximately 45,000 gross acres in Angelina and Nacogdoches Counties, Texas, which we acquired in August 2005. As of the same date, we have drilled and/or completed 80 Cotton Valley wells with a 100% success rate. Our net production volumes from our Cotton Valley Trend wells aggregated approximately 16,000 Mcfe of gas per day in the fourth quarter of 2005, or approximately 55% of our total oil and gas production in the period.

In East Texas, we began leasing acreage in the first quarter of 2004 and commenced a drilling program in April 2004. As of February 28, 2006, we had drilled and completed a total of 73 successful wells in East Texas on our operated acreage targeting the Cotton Valley formation. We have an average working interest of approximately 95% in the wells drilled and completed on our operated acreage to date. In December 2005, we completed drilling an initial exploratory well on our non-operated acreage in Nacogdoches County, in which we have a 40% working interest.

In Northwest Louisiana, we commenced a drilling program targeting the Cotton Valley formation in the first quarter of 2004 and have completed seven Cotton Valley wells as of February 28, 2006. Our initiative in this area began in the third quarter of 2003, when we obtained, via farmout, exploration rights to approximately 18,000 gross acres in the Bethany-Longstreet field. We retain continuous drilling rights to the entire block so long as we drill at least one well within 120 days from previous operations. For each productive well drilled under the agreement, we earn an assignment to 160 acres. We have a 70% working interest in the Bethany-Longstreet field.

South Louisiana Operations

Burrwood/West Delta 83 Fields — During the first quarter of 2005, the initial well on our Tunney prospect in the Burrwood/West Delta 83 field went off production from the initial zone due to reservoir depletion. This well, in which we own an approximate 40% working interest, was successfully recompleted in two sands in a dual completion in April 2005. In the second quarter of 2005, we commenced drilling of our Leonard and Frazier prospect wells, with the Leonard well being successful and the Frazier well being unsuccessful. On August 24, 2005, the field was shut-in due to Hurricane Katrina and, except for the partial

 

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Index to Financial Statements

restoration of oil production in mid September, remained shut-in for the remainder of the third quarter of 2005, pending resumption of operations by third party pipeline and gas plant operators downstream of the field. We estimate that approximately 6,000 and 4,000 Mcfe per day of net production for the third and fourth quarters of 2005, respectively, was shut-in as a result of the hurricanes. The fourth quarter amount represents 25% of pre-hurricane South Louisiana volumes. As of December 31, 2005, we have restored approximately 90% of our pre-hurricane volumes in South Louisiana, with the remaining pre-hurricane production volumes being temporarily shut-in awaiting completion of facility and well repairs. Damage to our facilities from both hurricanes was substantially covered by insurance.

St. Gabriel Field — In July 2004, we announced that we had acquired a 70% working interest in 3-D seismic permits and oil and gas lease options enabling us to acquire an approximate 30 square mile 3-D seismic survey over the St. Gabriel field in Ascension and Iberville Parishes, Louisiana. We commenced shooting the 3-D seismic survey in July 2004 and data acquisition was completed in September 2004. We have successfully drilled and set pipe on our initial test well in the field and anticipate drilling one additional well in the field later in 2006.

Contractual Obligations

At December 31, 2005, we had the following contractual obligations outstanding under our long term debt, operating lease agreements and non-cancellable drilling rig contracts (in thousands):

 

     Payments Due By Period

Contractual Obligation

   Total    2006    2007-2008    2009-2010    After 2010

Long-term debt

   $     30,000    $ –      $ –      $ 30,000    $ –  

Interest on long-term debt (1)

     11,100      2,664      5,328      3,108      –  

Operating leases for office space

     1,843      495      1,010      338      –  

Drilling rig commitments

     17,875      15,189      2,686      –        –  
                                  

Total contractual obligations

   $ 60,818    $     18,348    $     9,024    $     33,446    $ –  
                                  
 
  (1) Interest is based on rates and principal payments in effect at December 31, 2005.

Critical Accounting Policies and Estimates

Critical accounting policies are defined as those that are reflective of significant judgments and uncertainties and potentially result in materially different results under different assumptions and conditions. We have prepared our consolidated financial statements in conformity with accounting principles generally accepted in the United States, which require management to make estimates and assumptions that affect the reported amounts in these financial statements and accompanying notes. Actual results could differ from those estimates under different assumptions or conditions. Application of certain of our accounting policies requires a significant amount of estimates. These accounting policies are described below.

Proved oil and natural gas reserves

Proved reserves are defined by the SEC as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. 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 utilized by us. We cannot predict the types of reserve revisions that will be required in future periods.

 

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Successful efforts accounting

We utilize the successful efforts method to account for exploration and development expenditures. 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.

Impairment of properties

We continually monitor our long-lived assets recorded in oil and gas properties in the Consolidated Balance Sheets to ensure that they are fairly presented. 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. 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. As of December 31, 2005 and in certain prior years, we have reported a net deferred tax asset on our Consolidated Balance Sheet, after deduction of the related valuation allowance, which has been determined on the basis of management’s estimation of the likelihood of realization of the gross deferred tax asset as a deduction against future taxable income.

Derivative Instruments

As discussed in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk,” we periodically utilize derivative instruments to manage both our commodity price risk and interest rate risk. We consider the use of these instruments to be hedging activities. Pursuant to derivative accounting rules, we are required to use “mark to market” accounting to reflect the fair value of such derivative instruments on our Consolidated Balance Sheet. To the extent that we are able to demonstrate that our use of derivative instruments qualifies as hedging activities, the offsetting entry to the changes in fair value of these instruments is accounted for in Other Comprehensive Income (Loss). To the extent that such derivatives are deemed to be ineffective, as was the case in 2005 and the fourth quarter of 2004 with respect to our gas hedges, the offsetting entry to the changes in fair value is reflected in earnings.

 

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At the inception of each hedge, we document that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. A hedge must be determined to be “highly effective” under accounting rules in order to qualify for hedge accounting treatment. This assessment, which is updated quarterly, includes an evaluation of the most recent historical correlation between the derivative and the item hedged. In this analysis, changes in monthly settlement prices on our oil and gas derivatives are compared with the change in physical daily indexed prices that we receive from the field purchasers for our oil and gas production designated for hedging. Commencing with the fourth quarter of 2004 and during 2005, the analysis demonstrated that the natural gas swaps were not considered highly effective under SFAS 133. As a result, they ceased to qualify for hedge accounting treatment and the changes in fair value of the hedged instrument were recognized in earnings.

Price volatility within a measured month is the primary factor affecting the analysis of effectiveness of our oil and natural gas swaps. Volatility can reduce the correlation between the hedge settlement price and the price received for physical deliveries. Secondary factors contributing to changes in pricing differentials include changes in the basis differential which is the difference in the locally indexed price received for daily physical deliveries of hedged quantities and the index price used in hedge settlement, and changes in grade and quality factors of the hedged oil and natural gas production which would further impact the price received for physical deliveries.

Not withstanding the recent determination that our natural gas swaps were not deemed highly effective for purposes of applicable accounting rules, management continues to believe that our oil and gas price hedge strategy has been effective in satisfying our financial objective of providing cash flow stability.

Our hedge agreements currently consist of (a) swaps, where we receive a fixed price and pay a floating price, based on NYMEX quoted prices; and (b) collars, where we receive the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the ceiling price. The terms of our current hedge agreements are described in Note I to our Consolidated Financial Statements.

Recently Issued Accounting Pronouncements

See Note B, “Recently Issued Accounting Pronouncements,” to the Consolidated Financial Statements.

Off-Balance Sheet Arrangements

We do not currently utilize 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.

Commodity Price Risk

Despite the measures taken by us to attempt to control price risk, we remain subject to price fluctuations for natural gas and crude oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Domestic crude oil and gas prices could have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis.

We enter into futures contracts or other hedging agreements from time to time to manage the commodity price risk for a portion of our production. We consider these agreements to be hedging activities and, as such, monthly settlements on the contracts that qualify for hedge accounting are reflected in our crude oil and natural gas sales. Our strategy, which is administered by the Hedging Committee of the Board of Directors, and reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and 70% of our production. As of December 31, 2005, the commodity hedges we utilized were in the form of: (a) swaps, where we receive a fixed price and pay a floating price, based on NYMEX quoted prices; and (b) collars,

 

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where we receive the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the ceiling price. See Note I to the Consolidated Financial Statements for additional information.

Our hedging contracts fall within our targeted range of 30% to 70% of our estimated net oil and gas production volumes for the applicable periods of 2005. The fair value of the crude oil and natural gas hedging contracts in place at December 31, 2005 resulted in a liability of $29.4 million. Based on oil and gas pricing in effect at December 31, 2005, a hypothetical 10% increase in oil and gas prices would have increased the derivative liability to $39.0 million while a hypothetical 10% decrease in oil and gas prices would have decreased the derivative liability to an asset of $22.6 million.

Interest Rate Risk

We have a variable-rate debt obligation that exposes us to the effects of changes in interest rates. To partially reduce our exposure to interest rate risk, from time to time we enter into interest rate swap agreements. At December 31, 2005 we had the following interest rate swaps in place with BNP (in millions).

 

Effective

Date

  

Maturity

Date

  

LIBOR

Swap Rate

  

Notional

Amount

11/08/04    02/26/06    3.46%    $     18.0
02/27/06    02/26/07    4.08%      23.0
02/27/06    02/26/07    4.85%      17.0
02/27/07    02/26/09    4.86%      40.0

The fair value of the interest rate swap contracts in place at December 31, 2005 resulted in an asset of $0.1 million. Based on interest rates at December 31, 2005, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the asset.

Cautionary Statement Regarding Forward-Looking Statements

This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in this Annual Report on Form 10-K regarding reserve estimates, planned capital expenditures, future oil and gas production and prices, future drilling activity, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimates and such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Additional important factors that could cause actual results to differ materially from our expectations include changes in oil and gas prices, changes in regulatory or environmental policies, production difficulties, transportation difficulties and future drilling results. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by such factors.

Item 8.    Financial Statements and Supplementary Data

The information required here is included in the report as set forth in the “Index to the Consolidated Financial Statements” on page 42.

 

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

None.

Item 9A.    Controls and Procedures

Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this report. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective.

During the fiscal quarter ended December 31, 2005, there has been no change in our internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)) that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 is set forth on page 43 of this Annual Report on Form 10-K and is incorporated by reference herein.

Item 9B.    Other Information.

None.

 

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PART III

Item 10.    Directors and Executive Officers of the Registrant.

Our executive officers and directors and their ages and positions as of March 10, 2006 are as follows:

 

Name

   Age   

Position

Patrick E. Malloy, III

   62    Chairman of the Board of Directors

Walter G. “Gil” Goodrich

   47    Vice Chairman, Chief Executive Officer and Director

Robert C. Turnham, Jr.

   48    President and Chief Operating Officer

Mark E. Ferchau

   51    Executive Vice President

D. Hughes Watler, Jr.

   57    Senior Vice President, Chief Financial Officer and Treasurer

James B. Davis

   43    Senior Vice President, Engineering and Operations

Henry Goodrich

   75    Chairman—Emeritus and Director

Josiah T. Austin

   59    Director

John T. Callaghan

   51    Director

Geraldine A. Ferraro

   70    Director

Michael J. Perdue

   51    Director

Arthur A. Seeligson

   47    Director

Gene Washington

   59    Director

Steven A. Webster

   54    Director

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

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

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

Mark E. Ferchau became Executive Vice President of the Company in April 2004. From February 2003 to April 2004, he served as the Company’s Senior Vice President, Engineering and Operations, after initially joining the Company as Vice President, Engineering and Operations, in September 2001. Mr. Ferchau previously served as Production Manager for Forcenergy Inc from 1997 to 2001 and as Vice President, Engineering of Convest Energy Corporation from 1993 to 1997. Prior thereto, Mr. Ferchau held various positions with Wagner & Brown, Ltd. and other independent oil and gas companies.

D. Hughes Watler, Jr. joined the Company as Senior Vice President, Chief Financial Officer and Treasurer in March 2003. Mr. Watler is a former partner of Price Waterhouse LLP in their Houston and Tulsa offices, and was the Chief Financial Officer of Texoil, Inc, a public exploration & production company from 1992 to 1995, as well as XPRONET Inc., a private international oil & gas exploration company from 1998 to 2002. From 1995 to 1998, Mr. Watler served as the Corporate Controller for TPC Corporation, a NYSE listed midstream natural gas company.

 

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James B. Davis became Senior Vice President, Engineering and Operations, of the Company in January 2005. From February 2003 to December 2004, he served as the Company’s Vice President, Engineering and Operations, after initially joining the Company as Manager, Engineering and Operations, in March 2002. Mr. Davis consulted as an independent drilling engineer from 2001 to 2002 and served as Senior Staff Drilling Engineer for Forcenergy Inc. from 2000 to 2001. Mr. Davis worked for Texaco E&P Inc. from 1987 to 2000 on various production and rig operations assignments.

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

Josiah T. Austin is the managing member of El Coronado Holdings, L.L.C., a privately owned investment holding company. He and his family own and operate agricultural properties in the state of Arizona and Sonora, Mexico through El Coronado Ranch & Cattle Company, L.L.C. and other entities. Mr. Austin previously served on the Board of Directors of Monterey Bay Bancorp of Watsonville, California, and is a prior board member of New York Bancorp, Inc., which merged with North Fork Bancorporation, Inc. (NYSE) in early 1998. He was elected to the Board of Directors of North Fork Bancorporation, Inc. in May 2004. He became one of our directors in August 2002.

John T. Callaghan is the Managing Partner of Callaghan & Nawrocki, L.L.P, an audit, tax and consulting firm with offices in New York City, Melville and Smithtown, New York. He is a Certified Public Accountant and a member of the Association of Certified Fraud Examiners. He was employed by a major accounting firm from 1979 until 1986, at which time he formed his present firm. Mr. Callaghan also serves as a director for Andrea Systems LLC. He was elected to our Board of Directors in June 2003.

Geraldine A. Ferraro is Senior Managing Director and head of the public affairs practice of The Global Consulting Group, a New York-based international investor relations and corporate communications firm providing advisory services to public companies, private firms and governments around the world. Ms. Ferraro serves as a Board member of the National Democratic Institute of International Affairs and a member of the Council on Foreign Relations and was formerly United States Ambassador to the United Nations Human Rights Commission. Ms. Ferraro has been affiliated with numerous public and private sector organizations, including serving as a director of the former New York Bancorp, Inc., a NYSE-listed company. She was elected to our Board of Directors in August 2003.

Michael J. Perdue is the President and Chief Executive Officer of Community Bancorp Inc., a publicly traded bank holding company based in Escondido, California. Prior to assuming his present position in July 2003, Mr. Perdue was Executive Vice President of Entrepreneurial Corporate Group and President of its subsidiary, Entrepreneurial Capital Corporation. From September 1993 to April 1999, Mr. Perdue served in executive positions with Zions Bancorporation and FP Bancorp, Inc., as a result of FP Bancorp’s acquisition by Zions Bancorporation in May 1998. He has also held senior management positions with Ranpac, Inc., a real estate development company, and PacWest Bancorp. He was elected to our Board of Directors in January 2001.

Arthur A. Seeligson is currently engaged in the management of his personal investments in Houston, Texas. From 1991 to 1993, Mr. Seeligson was a Vice President, Energy Corporate Finance, at Schroder Wertheim & Company, Inc. From 1993 to 1995, Mr. Seeligson was a Principal, Corporate Finance, at Wasserstein, Perella & Co. He was primarily engaged in the management of his personal investments from 1995 through 1997. He was a managing director with the investment banking firm of Harris, Webb & Garrison from 1997 to June 2000. He has served as one of our directors since August 1995.

 

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

Steven A. Webster is Co-Managing Partner of Avista Capital Partners, which makes private equity investments in energy, healthcare and media. From 2000 through June 2005, he was Chairman of Global Energy Partners, an affiliate of the Merchant Banking Division of Credit Suisse First Boston, which made private equity investments in the energy industry. He was Chairman and Chief Executive Officer of Falcon Drilling Company, a marine oil and gas drilling contractor from 1988 to 1997, and was President and Chief Executive Officer of its successor, R&B Falcon Corporation from 1998 to 1999. Mr. Webster is Chairman of the Board of Carrizo Oil & Gas, Inc., a NASDAQ traded oil and gas exploration company and Basic Energy Services, a NYSE traded oil service company. He serves on the board of directors of numerous other public and private companies, primarily in the energy industry. He was elected to our Board of Directors in August 2003.

Additional information required under Item 10, “Directors and Executive Officers of the Registrant,” will be provided in our Proxy Statement for the 2006 Annual Meeting of Stockholders. Additional information regarding our corporate governance guidelines as well as the complete texts of its Code of Business Conduct and Ethics and the charters of our Audit Committee and our Compensation Committee may be found on our website at http://www.goodrichpetroleum.com.

Item 11.    Executive Compensation.

The information required by this Item is incorporated by reference to the information provided under the caption “Executive Compensation and Other Information” in our definitive proxy statement for the 2006 annual meeting of stockholders to be filed within 120 days from December 31, 2005.

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

The information required by this Item is incorporated by reference to the information provided under the caption “Security Ownership of Certain Beneficial Owners and Management” in our definitive proxy statement for the 2006 annual meeting of stockholders to be filed within 120 days from December 31, 2005.

Item 13.    Certain Relationships and Related Transactions.

The information required by this Item is incorporated by reference to the information provided under the caption “Certain Relationships and Other Transactions” in our definitive proxy statement for the 2006 annual meeting of stockholders to be filed within 120 days from December 31, 2005.

Item 14.    Principal Accounting Fees and Services.

The information required by this Item is incorporated by reference to the information provided under the caption “Audit and Non-Audit Fees” in our definitive proxy statement for the 2006 annual meeting of stockholders to be filed within 120 days from December 31, 2005.

 

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PART IV

Item 15.    Exhibits and Financial Statement Schedules

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

See “Index to Consolidated Financial Statements” on page 42.

(a) (3) Exhibits

 

1.1   

Purchase Agreement by among Goodrich Petroleum Corporation, Bear, Sterns & Co. Inc. and BNP Paribas Securities Corp. dated December 16, 2005 (Incorporated by reference to Exhibit 1.1 of the Company’s Form 8-K filed on December 16, 2005).

3.1   

Amended and Restated Certificate of Incorporation of Goodrich Petroleum Corporation dated March 12, 1998 (Incorporated by reference to Exhibit 3.1 of the Company’s First Amended Registration Statement on Form S-1 (Registration No. 333-47078) filed November 22, 2000).

3.2   

Bylaws of the Company, as amended and restated (Incorporated by reference to Exhibit 3.3 of the Company’s First Amended Registration Statement on Form S-1 (Registration No. 333-47078) filed November 22, 2000).

3.3   

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

4.1   

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

4.2   

Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas dated November 9, 2001 (Incorporated by reference to Exhibit 4.2 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).

4.3   

Registration Rights Agreement dated December 21, 2005 among the Company, Bear, Sterns & Co. Inc. and BNP Paribas Securities Corp. (Incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed on December 22, 2005).

10.1   

Goodrich Petroleum Corporation 1995 Stock Option Plan (Incorporated by reference to Exhibit 10.21 to the Company’s Registration Statement filed June 13, 1995 on Form S-4 (File No. 33-58631)).

10.2   

Consulting Services Agreement between Patrick E. Malloy and Goodrich Petroleum Corporation dated June 1, 2001 (Incorporated by reference to Exhibit 10.3 of the Company’s Annual Report filed on Form 10-K for the year ended December 31, 2001).

10.3   

Goodrich Petroleum Corporation 1997 Nonemployee Director Compensation Plan (Incorporated by reference to the Company’s Proxy Statement filed April 27, 1998).

10.4   

Form of Subscription Agreement dated September 27, 1999 (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated October 15, 1999).

10.5   

Purchase and Sale Agreement between Goodrich Petroleum Company, LLC and Malloy Energy Company, LLC, dated March 4, 2002 (Incorporated by reference to Exhibit 10.7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).

10.6   

Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas dated February 25, 2005 (Incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed on April 21, 2005).

10.7   

Severance Agreement between the Company and Walter G. Goodrich, dated April 25, 2003 (Incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed on April 21, 2005).

 

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10.8   

Severance Agreement between the Company and Robert C. Turnham, Jr., dated April 25, 2003 (Incorporated by reference to Exhibit 10.3 of the Company’s Form 8-K filed on April 21, 2005).

10.9   

First Amendment to the Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas dated April 29, 2005 (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report Form 10-Q for the quarterly period ended March 31, 2005).

10.10   

Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas dated November 17, 2005 (Incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K filed on November 23, 2005).

10.11   

Second Lien Term Loan Agreement among Goodrich Petroleum Company L.L.C., BNP Paribas and Certain Lenders, dated as of November 17, 2005 (Incorporated by reference to Exhibit 4.3 of the Company’s Form 8-K filed on November 23, 2005).

10.12   

First Amendment to Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas dated as of December 14, 2005 (Incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K filed on December 20, 2005).

10.13   

First Amendment to Second Lien Term Loan Agreement among Goodrich Petroleum Company, L.L.C., BNP Paribas and Certain Lenders, dated as of December 14, 2005 (Incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K filed on December 20, 2005).

*12.1   

Ratio of Earnings to Fixed Charges

*12.2   

Ratio of Earnings to Fixed Charges and Preference Securities Dividends

21   

Subsidiaries of the Registrant

  

Goodrich Petroleum Company LLC— organized in state of Louisiana

  

        Goodrich Petroleum Company—Lafitte, LLC—organized in state of Louisiana

  

        Drilling & Workover Company, Inc.—incorporated in state of Louisiana

  

        LECE, Inc.—incorporated in the state of Texas

*23.1   

Consent of KPMG LLP

*23.2   

Consent of Netherland, Sewell & Associates, Inc.

*31.1   

Certification by Chief Executive Officer Pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2   

Certification by Chief Financial Officer Pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.1   

Certification by Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2   

Certification by Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 
  *

Filed herewith.

 

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GLOSSARY OF CERTAIN OIL AND GAS TERMS

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

 

Bbls      Barrels of crude oil or other liquid hydrocarbons
Bcf      Billion cubic feet
Bcfe      Billion cubic feet equivalent
MBbls      Thousand barrels of crude oil or other liquid hydrocarbons
Mcf      Thousand cubic feet of natural gas
Mcfe      Thousand cubic feet equivalent
MMBbls      Million barrels of crude oil or other liquid hydrocarbons
MMBtu      Million british thermal units
MMcf      Million cubic feet of natural gas
MMcfe      Million cubic feet equivalent
MMBoe      Million barrels of crude oil or other liquid hydrocarbons equivalent
SEC      United States Securities and Exchange Commission
U.S.      United States

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

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

Dry hole is a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploratory well is a well drilled to find and produce oil or natural gas reserves in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.

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

Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

PV-10 is the pre-tax present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by contractual arrangements), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions).

Productive well is a well that is producing or is capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

 

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Proved reserves are the estimated quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, can be recovered in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if shown to be economically producible by either actual production or conclusive formation tests.

Proved developed reserves are the portion of proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved undeveloped reserves are the portion of proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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

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

 

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

Goodrich Petroleum Corporation

By:   /s/ Walter G. Goodrich
 

Walter G. Goodrich

Chief Executive Officer

 

POWER OF ATTORNEY

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

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant in the capacities indicated on March 14, 2006.

 

Signature

  

Title

/s/ Walter G. Goodrich

Walter G. Goodrich

  

Vice Chairman, Chief Executive Officer and Director (Principal Executive Officer)

/s/ D. Hughes Watler, Jr.

D. Hughes Watler, Jr .

  

Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer

/s/ Kirkland H. Parnell

Kirkland H. Parnell

  

Vice President (Principal Accounting Officer)

/s/ Patrick E. Malloy, III

Patrick E. Malloy, III

  

Chairman of Board of Directors

/s/ Josiah T. Austin

Josiah T. Austin

  

Director

/s/ John T. Callaghan

John T. Callaghan

  

Director

/s/ Geraldine A. Ferraro

Geraldine A. Ferraro

  

Director

/s/ Henry Goodrich

Henry Goodrich

  

Director

/s/ Michael J. Perdue

Michael J. Perdue

  

Director

/s/ Arthur A. Seeligson

Arthur A. Seeligson

  

Director

/s/ Gene Washington

Gene Washington

  

Director

/s/ Steven A. Webster

Steven A. Webster

  

Director

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

     Page

Management’s Annual Report on Internal Controls over Financial Reporting

   43

Report of Independent Registered Public Accounting Firm -
Consolidated Financial Statements

   44

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

   45

Consolidated Balance Sheets as of December 31, 2005 and 2004

   47

Consolidated Statements of Operations for the years ended
December 31, 2005, 2004 and 2003

   48

Consolidated Statements of Cash Flows for the years ended
December 31, 2005, 2004 and 2003

   49

Consolidated Statements of Stockholders’ Equity for the years ended
December 31, 2005, 2004 and 2003

   50

Consolidated Statements of Comprehensive Income (Loss)
for the years ended December 31, 2005, 2004 and 2003

   51

Notes to Consolidated Financial Statements

   52

 

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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, 2005. Our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included on pages 45 and 46.

 

Management of Goodrich Petroleum Corporation

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Goodrich Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Goodrich Petroleum Corporation and Subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, cash flows and stockholders’ equity and other comprehensive income for each of the years in the three-year period ended December 31, 2005. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Goodrich Petroleum Corporation and Subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

As discussed in Note B to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Goodrich Petroleum Corporation’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 14, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

 

KPMG LLP

 

Shreveport, Louisiana

March 14, 2006

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Goodrich Petroleum Corporation:

We have audited management’s assessment, included in the accompanying report, “Management’s Annual Report on Internal Controls over Financial Reporting”, that Goodrich Petroleum Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Goodrich Petroleum Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, 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, management’s assessment that Goodrich Petroleum Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Goodrich Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

 

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We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Goodrich Petroleum Corporation and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, changes in stockholders’ equity and comprehensive income or loss, and cash flows for each of the years in the three-year period ended December 31, 2005, and our report dated March 14, 2006 expressed an unqualified opinion on those consolidated financial statements.

 

KPMG LLP

Shreveport, Louisiana

March 14, 2006

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

 

     December 31,  
     2005     2004  
Assets             

Current assets:

    

Cash and cash equivalents

   $ 19,842     $ 3,449  

Accounts receivable, trade and other, net of allowance

     6,397       7,183  

Accrued oil and gas revenue

     11,863       3,122  

Fair value of interest rate derivatives

     107       –    

Prepaid expenses and other

     463       632  
                

Total current assets

     38,672       14,386  
                

Property and equipment:

    

Oil and gas properties (successful efforts method)

     316,286       159,904  

Furniture, fixtures and equipment

     1,075       821  
                
     317,361       160,725  

Less: Accumulated depletion, depreciation and amortization

     (74,229 )     (51,320 )
                

Net property and equipment

     243,132       109,405  
                

Other assets:

    

Restricted cash and investments

     2,039       2,039  

Deferred tax asset

     11,580       2,070  

Other

     1,103       77  
                

Total other assets

     14,722       4,186  
                

Total assets

   $ 296,526     $ 127,977  
                
Liabilities and Stockholders’ Equity             

Current liabilities:

    

Accounts payable

   $ 31,574     $ 23,352  

Accrued liabilities

     15,973       3,214  

Fair value of oil and gas derivatives

     23,271       1,834  

Fair value of interest rate derivatives

     –         144  

Accrued abandonment costs

     92       92  
                

Total current liabilities

     70,910       28,636  

Long-term debt

     30,000       27,000  

Accrued abandonment costs

     7,868       6,719  

Production payment payable

     –         297  

Fair value of oil and gas derivatives

     6,159       –    

Fair value of interest rate derivatives

     –         18  
                

Total liabilities

     114,937       62,670  
                

Stockholders’ equity:

    

Preferred stock: 10,000,000 shares authorized:

    

Series A convertible preferred stock, $1.00 par value,
791,968 shares issued and outstanding

     792       792  

Series B convertible preferred stock, $1.00 par value,
1,650,000 shares issued and outstanding

     1,650       –    

Common stock: $0.20 par value, 50,000,000 shares authorized; issued and
outstanding 24,804,737 and 20,587,074 shares, respectively

     4,961       4,117  

Additional paid in capital

     187,967       55,409  

Retained earnings (deficit)

     (8,649 )     9,556  

Unamortized restricted stock awards

     (2,066 )     (1,762 )

Accumulated other comprehensive loss

     (3,066 )     (2,805 )
                

Total stockholders’ equity

     181,589       65,307  
                

Total liabilities and stockholders’ equity

   $     296,526     $     127,977  
                

See notes to consolidated financial statements

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

 

     Year Ended December 31,  
     2005     2004     2003  

Revenues:

      

Oil and gas revenues

   $ 68,008     $ 44,861     $ 31,663  

Other

     325       151       477  
                        
     68,333       45,012       32,140  
                        

Operating expenses:

      

Lease operating expense

     9,931       7,402       6,099  

Production taxes

     4,053       3,105       2,288  

Depreciation, depletion and amortization

     25,563       11,562       8,996  

Exploration

     6,867       4,426       2,249  

Impairment of oil and gas properties

     340       –         335  

General and administrative

     8,702       5,821       5,314  

(Gain) loss on sale of assets

     (235 )     (50 )     66  
                        
     55,221       32,266       25,347  
                        

Operating income

     13,112       12,746       6,793  
                        

Other income (expense):

      

Interest expense

     (2,279 )     (1,110 )     (1,051 )

Gain (loss) on derivatives not qualifying for hedge accounting

     (37,680 )     2,317       –    

Gain on litigation judgment

     –         2,118       –    
                        
     (39,959 )     3,325       (1,051 )
                        

Income (loss) from continuing operations before income taxes

     (26,847 )     16,071       5,742  

Income tax (expense) benefit

     9,397       1,707       (2,016 )
                        

Income (loss) from continuing operations

     (17,450 )     17,778       3,726  

Discontinued operations including gain on sale of
assets, net of tax

     –         749       196  
                        

Income (loss) before cumulative effect of accounting change

     (17,450 )     18,527       3,922  

Cumulative effect of accounting change, net of tax

     –         –         (205 )
                        

Net income (loss)

     (17,450 )     18,527       3,717  

Preferred stock dividends

     755       633       633  
                        

Net income (loss) applicable to common stock

   $     (18,205 )   $     17,894     $ 3,084  
                        

Net income (loss) per common share - basic

      

Income (loss) from continuing operations

   $ (0.75 )   $ 0.91     $ 0.21  

Discontinued operations

     –         0.04       0.01  
                        

Before cumulative effect of accounting change

     (0.75 )     0.95       0.22  

Cumulative effect of accounting change

     –         –         (0.01 )
                        

Net income (loss)

   $ (0.75 )   $ 0.95     $ 0.21  
                        

Net income (loss) applicable to common stock

   $ (0.78 )   $ 0.92     $ 0.17  
                        

Net income (loss) per common share - diluted

      

Income (loss) from continuing operations

   $ (0.75 )   $ 0.87     $ 0.18  

Discontinued operations

     –         0.04       0.01  
                        

Before cumulative effect of accounting change

     (0.75 )     0.91       0.19  

Cumulative effect of accounting change

     –         –         (0.01 )
                        

Net income (loss)

   $ (0.75 )   $ 0.91     $ 0.18  
                        

Net income (loss) applicable to common stock

   $ (0.78 )   $ 0.88     $ 0.15  
                        

Weighted average common shares outstanding - basic

     23,333       19,552           18,064  

Weighted average common shares outstanding - diluted

     23,333       20,347       20,482  

See notes to consolidated financial statements

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

 

     Year Ended December 31,  
     2005     2004     2003  

Cash flows from operating activities:

      

Net income (loss)

   $ (17,450 )   $ 18,527     $ 3,717  

Adjustments to reconcile net income (loss) to
net cash provided by operating activities –

      

Depletion, depreciation, and amortization

     25,563       11,562       8,996  

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

     26,960       (2,317 )     –    

Deferred income taxes

     (9,396 )     (1,303 )     1,905  

Dry hole costs

     2,014       –         816  

Amortization of leasehold costs

     3,344       1,035       474  

Impairment of oil and gas properties

     340       –         335  

Stock based compensation (non-cash)

     1,144       580       155  

Stock issued for cancelled options (non-cash)

     –         –         403  

Cumulative effect of change in accounting principle

     –         –         316  

(Gain) loss on sale of assets

     (235 )     (814 )     66  

Non-cash effect of discontinued operations, net

     –         155       185  

Other non-cash items

     (36 )     (516 )     339  

Changes in assets and liabilities –

      

Accounts receivable and other assets

     (7,546 )     (4,256 )     (218 )

Accounts payable and accrued liabilities

     20,860       18,375       (301 )
                        

Net cash provided by operating activities

     45,562       41,028       17,188  
                        

Cash flows from investing activities:

      

Capital expenditures

         (164,551 )         (47,501 )         (19,898 )

Proceeds from sale of assets

     980       2,087       398  
                        

Net cash used in investing activities

     (163,571 )     (45,414 )     (19,500 )
                        

Cash flows from financing activities:

      

Principal payments of bank borrowings

     (118,500 )     (1,000 )     (1,600 )

Proceeds from bank borrowings

     121,500       8,000       3,100  

Net proceeds from common stock offering

     53,112       –         –    

Net proceeds from preferred stock offering

     79,775       –         –    

Exercise of stock options and warrants

     477       340       129  

Production payments

     (297 )     (361 )     (406 )

Deferred financing costs

     (971 )     –         (140 )

Preferred stock dividends

     (634 )     (633 )     (633 )

Other

     (60 )     –         –    
                        

Net cash provided by financing activities

     134,402       6,346       450  
                        

Increase (decrease) in cash and cash equivalents

     16,393       1,960       (1,862 )

Cash and cash equivalents, beginning of period

     3,449       1,489       3,351  
                        

Cash and cash equivalents, end of period

   $ 19,842     $ 3,449     $ 1,489  
                        

Supplemental disclosures of cash flow information:

      

Cash paid during the year for interest

   $ 1,862     $ 865     $ 902  
                        

Cash paid during the year for income taxes

   $ 110     $ 30     $ –    
                        

See notes to consolidated financial statements

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In Thousands)

 

     2005     2004     2003  
     Shares    Amount     Shares    Amount     Shares    Amount  

Series A Preferred Stock

               

Balance, beginning and
end of year

   792    $ 792     792    $ 792     792    $ 792  
                                       

Series B Preferred Stock

               

Balance, beginning of year

   –      $ –       –      $ –       –      $ –    

Offering of preferred stock

   1,650      1,650     –        –       –        –    
                                       

Balance, end of year

   1,650    $ 1,650     –      $ –       –      $ –    
                                       

Common Stock

               

Balance, beginning of year

   20,587    $ 4,117     18,130    $ 3,626     17,914    $ 3,583  

Offering of common stock

   3,710      742     –        –       –        –    

Issuance of common stock
for cancelled stock options

   –        –       –        –       125      25  

Issuance and amortization
of restricted stock

   123      25     52      10     –        –    

Exercise of stock options
and warrants

   371      74     2,376      475     91      18  

Director stock grants

   14      3     29      6     –        –    
                                       

Balance, end of year

       24,805    $ 4,961         20,587    $ 4,117         18,130    $ 3,626  
                                       

Paid-in Capital

               

Balance, beginning of year

      $ 55,409        $ 53,359        $ 52,333  

Offering of common stock

        52,370          –            –    

Offering of preferred stock

        78,125          –            –    

Issuance of common stock
for cancelled stock options

        –            –            378  

Issuance and amortization
of restricted stock

        1,423          1,951          537  

Exercise of stock options
and warrants

        403          (135 )        111  

Director stock grants

        237          234          –    
                                 

Balance, end of year

      $     187,967        $     55,409        $     53,359  
                                 

Retained Earnings (Deficit)

               

Balance, beginning of year

      $ 9,556        $ (8,338 )      $ (11,422 )

Net income (loss)

        (17,450 )        18,527          3,717  

Preferred stock dividends

        (755 )        (633 )        (633 )
                                 

Balance, end of year

      $ (8,649 )      $ 9,556        $ (8,338 )
                                 

Unamortized Restricted
Stock Awards

               

Balance, beginning of year

      $ (1,762 )      $ (382 )      $ –    

Issuance and amortization
of restricted stock

        (304 )        (1,380 )        (382 )
                                 

Balance, end of year

      $ (2,066 )      $ (1,762 )      $ (382 )
                                 

Accumulated Other
Comprehensive Loss

               

Balance, beginning of year

      $ (2,805 )      $ (998 )      $ (679 )

Other comprehensive loss

        (261 )        (1,807 )        (319 )
                                 

Balance, end of year

      $ (3,066 )      $ (2,805 )      $ (998 )
                                 

Total Stockholders’ Equity

      $ 181,589        $ 65,307        $ 48,059  
                                 

See notes to consolidated financial statements

 

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

 

         Year Ended December 31,  
         2005     2004     2003  

Net income (loss)

     $ (17,450 )   $ 18,527     $ 3,717  
                          

Other comprehensive loss:

      

Change in fair value of derivatives (1)

     (6,233 )     (5,909 )     (2,237 )

Reclassification adjustment (2)

             5,972       4,102       1,918  
                          

Other comprehensive loss

     (261 )     (1,807 )     (319 )
                          

Comprehensive income (loss)

   $ (17,711 )   $     16,720     $     3,398  
                          
           

(1) Net of income tax benefit of:

   $         3,356     $       3,180     $     1,204  

(2) Net of income tax expense of:

   $ 3,216     $ 2,209     $ 1,033  

See notes to consolidated financial statements

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE A—Description of Business

We are in the primary business of exploration and production of crude oil and natural gas. Our subsidiaries have interests in such operations in three states, primarily in Louisiana and Texas.

NOTE B—Summary of Significant Accounting Policies

Principles of Consolidation—The consolidated financial statements include the financial statements of Goodrich Petroleum Corporation and its wholly-owned subsidiaries. Significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications have been made to the prior year statements to conform to the current year presentation.

Since the issuance of our Form 10-K for the year ended December 31, 2004, we have changed the presentation of our Statement of Operations by creating a new subtotal called Operating Income, defined as Revenues minus Operating Expenses, and adding a new section following Operating Income called Other Income (Expense). Included in Other Income (Expense) are interest expense, gain (loss) on derivatives not qualifying for hedge accounting, and gain on litigation judgment.

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 accounting principles generally accepted in the United States of America. Actual results could differ from those estimates.

Cash and Cash Equivalents—Cash and cash equivalents include cash on hand, demand deposit accounts and temporary cash investments with maturities of ninety days or less at date of purchase. Restricted cash represents amounts held in escrow for plugging and abandonment obligations which were incurred with the acquisition of our Burrwood and West Delta 83 fields in 2000.

Revenue Recognition—Revenues from the production of crude oil and natural gas properties in which we have an interest with other producers are recognized on the entitlements method. We record an asset or liability for natural gas balancing when we have purchased or sold more than our working interest share of natural gas production, respectively. At December 31, 2005 and 2004, the net assets for gas balancing were $0.7 million and $0.1 million, respectively. Differences between actual production and net working interest volumes are routinely adjusted. These differences are not significant.

Property and Equipment—We use the successful efforts method of accounting for exploration and development expenditures. Leasehold acquisition costs are capitalized. When proved reserves are found on an undeveloped property, leasehold cost is reclassified to proved properties. Significant undeveloped leases are reviewed periodically, and a valuation allowance is provided for any estimated decline in value. Cost of all other undeveloped leases is amortized over the estimated average holding period of the leases.

Costs of exploratory drilling are initially capitalized, but if proved reserves are not found, generally within one year after completion of drilling, the costs are subsequently expensed. All other exploratory costs are charged to expense as incurred. Development costs are capitalized, including the cost of unsuccessful development wells.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

We recognize an impairment when the net of future cash inflows expected to be generated by an identifiable long-lived asset and cash outflows expected to be required to obtain those cash inflows is less than the carrying value of the asset. We perform this comparison for our oil and gas properties on a field-by-field basis using our estimates of future commodity prices and proved and probable reserves. The amount of such loss is measured based on the difference between the discounted value of such net future cash flows and the carrying value of the asset. For the years ended December 31, 2005 and 2003, we recorded impairments of $0.3 million as a result of certain non-core fields depleting earlier than anticipated. There were no impairments in 2004.

Depreciation and depletion of producing oil and gas properties are provided under the unit-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible development costs, and proved reserves are used for unamortized leasehold costs. As described in Note C, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 143 “Accounting for Asset Retirement Obligations (“SFAS 143”) on January 1, 2003. Under SFAS 143, estimated asset retirement costs are generally recognized when the asset is placed in service, and are amortized over proved reserves using the units of production method. Prior to the adoption of SFAS 143, estimated dismantlement, abandonment and site restoration costs, net of salvage value, were generally recognized using the units of production method and were included in depreciation expense. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

Gains and losses on disposals or retirements that are significant or include an entire depreciable or depletable property unit are included in income. All other dispositions, retirements, or abandonments are reflected in accumulated depreciation, depletion, and amortization.

Furniture, fixtures and equipment consists of office furniture, computer hardware and software and leasehold improvements. Depreciation of these assets is computed using the straight-line method over their estimated useful lives, which vary from one to five years.

Income Taxes—We follow the provisions of SFAS No. 109, “Accounting for Income Taxes”, (“SFAS 109”) which requires income taxes be accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Earnings Per Share—Basic income per common share is computed by dividing net income available for common stockholders, for each reporting period by the weighted average number of common shares outstanding during the period. Diluted income per common share is computed by dividing net income available for common stockholders for each reporting period by the weighted average number of common shares outstanding during the period, plus the effects of potentially dilutive common shares.

Derivative Instruments and Hedging Activities—We utilize derivative instruments such as futures, forwards, options, collars and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas and to hedge our exposure to changing interest rates. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, requires that all derivative instruments subject to the requirements of the statement be measured at fair value and recognized as assets or liabilities in the balance sheet. Upon entering into a derivative contract, we may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge, and thenceforth, mark

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

the contract to market through earnings. We document the relationship between the derivative instrument designated as a hedge and the hedged items, as well as our objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. We assess at inception, and on an ongoing basis, whether a derivative instrument used as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. Changes in the fair value of a qualifying fair value hedge are recorded in earnings along with the gain or loss on the hedged item. Changes in the fair value of a qualifying cash flow hedge are recorded in other comprehensive income, until earnings are affected by the cash flows of the hedged item. When the cash flow of the hedged item is recognized in the Statement of Operations, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings.

Ineffective portions of a cash flow hedging derivative’s change in fair value are recognized currently in earnings as other income (expense). If a derivative instrument no longer qualifies as a cash flow hedge, hedge accounting is discontinued and the gain or loss that was recorded in other comprehensive income is recognized over the period anticipated in the original hedge transaction.

Asset Retirement Obligations—Effective January 1, 2003, we adopted SFAS 143 (see Note C). SFAS 143 applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. SFAS 143 requires that we record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset.

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

Concentration of Credit Risk—Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. For the year ended December 31, 2005, revenues from three purchasers accounted for 34%, 18% and 13% of oil and gas revenues. For the year ended December 31, 2004, revenues from two purchasers accounted for 45% and 15%, of oil and gas revenues. For the year ended December 31, 2003, revenues from two purchasers accounted for 47% and 25% of oil and gas revenues.

Stock Based Compensation—While SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”), permits entities to recognize as expense, over the vesting period, the fair value of all stock-based awards on the date of grant, it also allows entities to continue to apply the provisions of APB Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), and provide pro forma net income and pro forma earnings per share and other disclosures for employee stock option grants made in 1995 and future years as if the fair-value-based method defined in SFAS 123 had been applied. We have elected to continue to apply the provisions of APB 25 and provide the disclosure provisions of SFAS 123. For stock based compensation that vests on a prorata basis where the award is fixed at the grant date, we have elected to amortize those costs using straight line method over the life of the award.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

We apply APB 25 in accounting for our plans and, accordingly, no compensation cost has been recognized for our stock options in the financial statements. Had we determined compensation cost based on the fair value at the grant date for our stock options under SFAS 123, our net income (loss) would have been reduced to the pro forma amounts indicated below:

 

     Year Ended December 31,  
     2005     2004     2003  

Net income (loss) as reported

   $ (17,450 )   $ 18,527     $ 3,717  

Add: Restricted stock compensation expense
included in net income, net of tax

     743       579       155  

Deduct: Stock based compensation expense
at fair value, net of tax

     (1,236 )     (609 )     (196 )
                        

Pro forma

   $ (17,943 )   $ 18,497     $ 3,676  
                        

Net income (loss) applicable to common stock as reported

   $ (18,205 )   $ 17,894     $ 3,084  

Add: Restricted stock compensation expense
included in net income, net of tax

                 743                   579                   155  

Deduct: Stock based compensation expense
at fair value, net of tax

     (1,236 )     (609 )     (196 )
                        

Pro forma

   $ (18,698 )   $ 17,864     $ 3,043  
                        

Net income (loss) applicable to common stock per share:

      

Basic – as reported

   $ (0.78 )   $ 0.92     $ 0.17  

Basic – pro forma

   $ (0.80 )   $ 0.91     $ 0.17  

Diluted – as reported

   $ (0.78 )   $ 0.88     $ 0.15  

Diluted – pro forma

   $ (0.80 )   $ 0.88     $ 0.15  

See “New Accounting Pronouncements” below regarding the impact of the adoption of SFAS No. 123R (Revised 2004) “Share-Based Payment” (“SFAS 123R”).

New Accounting Pronouncements—In December 2004, the FASB issued SFAS 123R which is effective for interim or annual reporting periods that begin after December 15, 2005, and requires the expensing of new, modified or repurchased stock-based compensation awards issued after that date. Previously issued stock-based compensation awards, which are unvested as of December 15, 2005, must also be accounted for in accordance with the revised statement. The revised statement provides for the use of either a closed-form model or open-form lattice model for the valuation of stock option awards. We plan to follow the “modified prospective application” to the adoption of the revised statement. The specific magnitude of the impact of adoption of SFAS 123R cannot be predicted at this time because it will depend on levels of share-based incentive awards granted in the future. However, had we adopted SFAS 123R in prior periods, the impact of that standard would have approximated the impact of SFAS 123 as described in the disclosure of pro forma net income and earnings per share in “Stock Based Compensation” above.

In March 2005, the FASB issued FASB Interpretation (“FIN”) 47, an interpretation of SFAS 143. FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS. 143, which we adopted on January 1, 2003. We applied the guidance in this FIN beginning in the third quarter of 2005 resulting in no impact on our financial statements.

In April 2005, the FASB issued FASB Staff Position (“FSP”) 19-1 to provide guidance on the accounting for exploratory well costs and to amend SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies (“SFAS 19”). The guidance in FSP 19-1 applies to companies that use the successful efforts method of accounting as described in SFAS 19. This FSP clarifies that exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress assessing the reserves and the economic and operating

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

viability of the project. We adopted the guidance in this FSP prospectively in April 2005 and the adoption had no impact on our financial statements. We had no capitalized exploratory costs pending determination of reserves as of December 31, 2005.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” (“SFAS 154”) which replaces APB Opinion No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements — An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, and is therefore required to be adopted by us in the first quarter of fiscal 2006. We are currently evaluating the effect that the adoption of SFAS 154 will have on our consolidated results of operations and financial condition, but do not expect it will have a material impact.

In February 2006, the FASB issued SFAS No. 155 “Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and 140” (“SFAS 155”). SFAS 155 clarifies certain issues relating to embedded derivatives and beneficial interests in securitized financial assets. The provisions of SFAS 155 are effective for all financial instruments acquired or issued after fiscal years beginning after September 15, 2006. We are currently assessing the impact that the adoption of SFAS 155 will have on our results of operations and financial position.

NOTE C—Asset Retirement Obligations

SFAS 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets and requires that an asset retirement cost should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. We adopted SFAS 143 on January 1, 2003 and recorded an incremental liability for asset retirement obligations of $1.4 million, additional oil and gas properties, net of accumulated depletion, depreciation and amortization, in the amount of $1.1 million and a net of tax cumulative effect of change in accounting principle of $0.2 million.

The reconciliation of the beginning and ending asset retirement obligation for the periods ending December 31, 2005 and 2004 is as follows (in thousands):

 

     December 31,  
     2005     2004  

Beginning balance

   $ 6,811     $ 6,601  

Liabilities incurred

     1,004       389  

Liabilities settled

     (39 )     (506 )

Accretion expense (reflected in depletion, depreciation
and amortization expense)

                 363                   327  

Other

     (179 )     –    
                

Ending balance

     7,960       6,811  

Less: current portion

     (92 )     (92 )
                
   $ 7,868     $ 6,719  
                

 

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NOTE D—Long-Term Debt

Long-term debt consisted of the following balances (in thousands):

 

     December 31,
     2005    2004

Borrowings under senior credit facility, bearing interest at a
weighted average interest rate 4.1% at December 31, 2004

   $ –      $ 27,000

Second lien term loan, bearing interest at a weighted average
interest rate of 8.9% at December 31, 2005

             30,000      –  
             

Total debt

     30,000              27,000

Less current maturities

     –        –  
             

Total long-term debt

   $ 30,000    $ 27,000
             

On November 17, 2005, we amended our existing credit agreement and entered into an amended and restated senior credit agreement (the “Amended and Restated Credit Agreement”) and a funded $30.0 million second lien term loan (the “Second Lien Term Loan Agreement”) that expanded our borrowing capabilities and extended our credit facility for an additional two years. Total lender commitments under the Amended and Restated Credit Agreement were increased from $50.0 million to $200.0 million and the maturity was extended from February 25, 2008 to February 25, 2010. Revolving borrowings under the Amended and Restated Credit Agreement are subject to periodic redeterminations of the borrowing base which is currently established at $75.0 million, and is currently scheduled to be redetermined in March 2006, based upon our 2005 year-end reserve report. With a portion of the net proceeds of the offering of Series B Convertible Preferred Stock in December 2005, we fully repaid all outstanding indebtedness in the amount of $47.5 million leaving a zero balance outstanding as of December 31, 2005 (see Note H). Interest on revolving borrowings under the Amended and Restated Credit Agreement accrues at a rate calculated, at our option, at either the bank base rate plus 0.00% to 0.50%, or LIBOR plus 1.25% to 2.00%, depending on borrowing base utilization. BNP Paribas (“BNP”) is the lead lender and administrative agent under the amended credit facility with Comerica Bank and Harris Nesbit Financing, Inc. as co-lenders.

The terms of the Amended and Restated Credit Agreement require us to maintain certain covenants. Capitalized terms are defined in the credit agreement. The covenants include:

 

  ·  

Current Ratio of 1.0/1.0;

  ·  

Interest Coverage Ratio which is not less than 3.0/1.0 for the trailing four quarters, and

  ·  

Tangible Net Worth of not less than $53,392,838, plus 50% of cumulative net income after September 30, 2004, plus 100% of the net proceeds of any subsequent equity issuance.

As of December 31, 2005, we were in compliance with all of the financial covenants of the Amended and Restated Credit Agreement.

The Second Lien Term Loan Agreement provides for a 5-year, non-revolving loan of $30.0 million which was funded on November 17, 2005 and is due in a single maturity on November 17, 2010. Optional prepayments of term loan principal can be made in amounts of not less than $5.0 million during the first year at a 1% premium and without premium after the first year. Interest on term loan borrowings accrues at a rate calculated, at our option, at either base rate plus 3.50%, or LIBOR plus 4.50%, and is payable quarterly. BNP is the lead lender and administrative agent under the Second Lien Term Loan Agreement. At December 31, 2005, borrowings outstanding under the term loan were $30.0 million.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

The terms of the Second Lien Term Loan Agreement require us to maintain certain covenants. Capitalized terms are defined in the loan agreement. The covenants include:

 

  ·  

Total Debt to EBITDAX Ratio which is not greater than 4.0/1.0 for the most recent period of four fiscal quarters for which financial statements are available and

  ·  

Asset Coverage Ratio to be not less than 1.5/1.0.

As of December 31, 2005, we were in compliance with all of the financial covenants of the Second Lien Term Loan Agreement.

NOTE E—Net Income (Loss) Per Share

Net income (loss) was used as the numerator in computing basic and diluted income (loss) per common share for the years ended December 31, 2005, 2004 and 2003. The following table reconciles the weighted average shares outstanding used for these computations (in thousands):

 

     Year Ended December 31,  
     2005     2004     2003  

Basic method

     23,333       19,552       18,064  

Stock warrants

     –         478       2,364  

Stock options and restricted stock

     –         317       54  
                        

Dilutive method

             23,333               20,347               20,482  
                        

NOTE F—Income Taxes

      

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

 

   
     Year Ended December 31,  
     2005     2004     2003  

Current:

      

Federal

   $ –       $ –       $             –    

State

     –         –         –    
                        
     –         –         –    
                        

Deferred:

      

Federal

     9,397       1,303       (2,121 )

State

     –         –         –    
                        
             9,397               1,303       (2,121 )
                        

Total

   $ 9,397     $ 1,303     $ (2,121 )
                        

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

  

     Year Ended December 31,  
     2005     2004     2003  

Income (loss) from continuing operations

      

Tax at U.S. statutory income tax

   $ 9,397     $ (5,625 )   $ (2,010 )

Nondeductible expenses

     (5 )     (6 )     (6 )

Valuation allowance and other

     5       7,338                   –    
                        
             9,397               1,707       (2,016 )
                        

Income (loss) from discontinued operations

      

Tax at U.S. statutory income tax

     –         (404 )     (105 )
                        
     –         (404 )     (105 )
                        

Total tax (expense) benefit

   $ 9,397     $ 1,303     $ (2,121 )
                        

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2005 and 2004 are presented below (in thousands).

 

     2005     2004  

Deferred tax assets:

    

Differences between book and tax basis of:

    

Operating loss carryforwards

   $ 16,064     $ 14,189  

Statutory depletion carryforward

     7,034       7,034  

AMT tax credit carryforward

     1,480               1,400  

Derivative financial instruments

             10,263       699  

Contingent liabilities

     45       45  

Other

     421       348  
                

Total gross deferred tax assets

     35,307       23,715  

Less valuation allowance

     (13,263 )     (12,648 )
                

Net deferred tax asset

     22,044       11,067  
                

Deferred tax liabilities:

    

Differences between book and tax basis of:

    

Property and equipment

     (10,464 )     (8,997 )
                

Total gross deferred tax liabilities

     (10,464 )     (8,997 )
                

Net deferred tax asset

   $ 11,580     $ 2,070  
                

The valuation allowance for deferred tax assets increased by $0.6 million in 2005. The increase in the allowance was primarily due to the income tax benefits generated from our stock based deferred compensation plans. We recognize the benefits from current and prior years’ stock compensation deductions after the utilization of net operating loss carryforwards generated from operations. These excess tax benefits will be recorded as additional paid in capital when realized. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based primarily upon the level of projections for future taxable income and the reversal of future taxable temporary differences over the periods which the deferred tax assets are deductible, management believes it is more likely than not we will realize the benefits of these deductible differences, net of the existing valuation allowance at December 31, 2005.

We have net operating loss carryforwards totaling $45.9 million which expire in years 2007 through 2025 as follows (in thousands):

 

2006

   $ –  

2007

     7,894

2008

     4,286

2009

     3,247

2010

     6,451

2011 through 2025

     24,018
      

Total

   $     45,896
      

An ownership change in accordance with Internal Revenue Code (IRC) (S)382, occurred in August 1995 and again in August 2000. The net operating losses (NOLs) generated prior to August 1995 are subject to an annual IRC (S)382 limitation of $1.7 million. The IRC (S)382 annual limitation for the ownership change in August 2000 is $3.6 million. The latter IRC (S)382 ownership change limitation is a cumulative limitation and does not eliminate or increase the limitation on the pre-August 1995 NOLs. The NOLs generated after August 1995 and prior to August 2000, are subject to an annual limitation of $3.6 million less the annual amount utilized for pre-August 1995 NOLs. It should be noted that the same IRC (S)382 limitations apply to the

 

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alternative minimum tax net operating loss carryforwards, depletion carryforwards, and alternative minimum tax credit carryforwards. The minimum tax credit carryforward (“MTC”) of $1.5 million as of December 31, 2005, will not begin to be utilized until after the available NOLs have been utilized or expired and when regular tax exceeds the current year alternative minimum tax. The unused annual IRC (S)382 limitations can be carried over to subsequent years.

NOTE G—Production Payment Obligation

We entered into a production payment to assist in the financing of the Lafitte field acquisition in September 1999. The original amount of the production payment obligation was $2.9 million, which was recorded as a production payment liability of $2.2 million after a discount to reflect an effective rate of interest of 11.25%. During 2005, the production payment obligation was fully satisfied.

NOTE H—Stockholders’ Equity

Common Stock

At December 31, 2005, a total of 1,381,252 unissued shares of Goodrich common stock were reserved for the following: (a) 531,502 shares for the exercise of stock warrants; (b) 519,500 shares for the exercise of stock options; and (c) 330,250 shares for the conversion of Series A convertible preferred stock. The stock warrants were issued in connection with a September 1999 private placement of convertible notes and subsidiary securities at exercise prices ranging from $0.9375 to $1.50 per share and expire in September 2006. Each warrant is exercisable into one share of common stock upon payment of the exercise price, however, the holders of the stock warrants may, in certain circumstances, elect a cashless exercise whereby additional “in the money” warrants can be tendered to cover the exercise price of the warrants. Pursuant to a May 2003 stock purchase agreement, the holders of 2,369,527 warrants to purchase common stock elected a cashless exercise of such warrants resulting in the issuance of 2,109,169 shares of common stock in three separate installments which closed in January, April, and July 2004. There are no further exercises of warrants to be made pursuant to the stock purchase agreement; however, in February 2005, the holder of 330,000 warrants to purchase common stock elected to exercise such warrants by paying the exercise price in cash.

In May 2005, we completed a public offering of 3,710,000 shares of our common stock at an offering price of $15.40 per share resulting in net proceeds of $53.1 million, after underwriting discount and offering costs. We used the proceeds to repay all outstanding indebtedness to BNP under our previous senior credit facility in the amount of $39.5 million with the balance being added to working capital to be used primarily to fund an accelerated drilling program in the Cotton Valley Trend of East Texas and Northwest Louisiana.

Preferred Stock

Our Series A Convertible Preferred Stock (the “Series A Convertible Preferred Stock”) has a par value of $1.00 per share with a liquidation preference of $10.00 per share, aggregating to $7.9 million, and is convertible at the option of the holder at any time, unless earlier redeemed, into shares of our common stock at an initial conversion rate of .4167 shares of common stock per share of Series A Convertible Preferred Stock. The Series A Convertible Preferred Stock also will automatically convert to common stock if the closing price for the Series A Convertible Preferred Stock exceeds $15.00 per share for ten consecutive trading days. The Series A Convertible Preferred Stock is redeemable in whole or in part, at $12.00 per share, plus accrued and unpaid dividends. Dividends on the Series A Convertible Preferred Stock accrue at an annual rate of 8% and are cumulative. In February 2006, we fully redeemed all issued and outstanding shares of our Series A Convertible Preferred Stock at a cost of approximately $9.5 million.

 

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

Each share is convertible at the option of the holder into our common stock, par value $0.20 per share (the ”Common Stock”) at any time at an initial conversion rate of 1.5946 shares of Common Stock per share, which is equivalent to an initial conversion price of approximately $31.36 per share of Common Stock. Upon conversion of the Series B Convertible Preferred Stock, we may choose to deliver the conversion value to holders in cash, shares of Common Stock, or a combination of cash and shares of Common Stock.

On or after December 21, 2010, we may, at our option, cause the Series B Convertible Preferred Stock to be automatically converted into that number of shares of Common Stock that are issuable at the then-prevailing conversion rate, pursuant to the Company Conversion Option. We may exercise our conversion right only if, for 20 trading days within any period of 30 consecutive trading days ending on the trading day prior to the announcement of our exercise of the option, the closing price of the Common Stock equals or exceeds 130% of the then-prevailing conversion price of the Series B Convertible Preferred Stock. The Series B Convertible Preferred Stock is non-redeemable by us.

We used the net proceeds of the offering of Series B Convertible Preferred Stock to fully repay all outstanding indebtedness under our senior revolving credit facility in the amount of $47.5 million (see Note D). The remaining net proceeds of the offering were added to our working capital to fund 2006 capital expenditures and for other general corporate purposes.

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 $29.2 million, which will be used to fund our 2006 capital expenditure program.

Stock Option and Incentive Programs

We have historically had two plans, which provide for stock option and other incentive awards for our key employees, consultants and directors: (a) the Goodrich Petroleum Corporation 1995 Stock Option Plan (the “Plan”), which allowed grants of stock options, restricted stock awards, stock appreciation rights, long-term incentive awards and phantom stock awards, or any combination thereof, to key employees and consultants, and (b) the Goodrich Petroleum Corporation 1997 Director Compensation Plan, which allowed grants of stock and options to each director who is not and has never been an employee of the Company. The Goodrich Petroleum Corporation 1995 Stock Option Plan expired according to its original terms in late 2005; however, our Board of Directors approved the extension of the Plan through December 31, 2005 and the granting of a total of 525,000 stock options at an exercise price of $23.39 and 101,129 shares of restricted stock to certain of our employees and officers as of December 6, 2005, subject to approval at our 2006 Annual Meeting of Stockholders. As of February 9, 2006, our directors and executive officers reached a level of more than 50% ownership of our total shares of Common Stock outstanding; therefore, stockholder approval of these actions was no longer contingent. For accounting purposes, we will begin expensing the December 6, 2005 grants based on the grant date value as determined under SFAS 123R, which utilizes the closing price of our Common Stock as of February 9, 2006. At our 2006 Annual Meeting of Stockholders, we expect to put forth to stockholders a proposal to implement a new combined plan to replace both the Goodrich Petroleum Corporation 1995 Stock Option Plan and the Goodrich Petroleum Corporation 1997 Director Compensation Plan.

 

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Prior to the expiration of the Goodrich Petroleum Corporation 1995 Stock Option Plan, the two Goodrich plans had authorized grants of options to purchase up to a combined total of 2,300,000 shares of authorized but unissued common stock. Stock options were granted with an exercise price equal to the stock’s fair market value at the date of grant, and all employee stock options granted under the 1995 Stock Option Plan generally had ten year terms and three year pro rata vesting.

The per share weighted average fair value of stock options granted during the years ended December 31, 2005 and 2004 were $9.69 and $7.96, respectively, on the date of grant using the Black Scholes option-pricing model with the following weighted-average assumptions: (a) expected dividend yield 0%, (b) risk-free interest rate of 6%, (c) volatility of 47% in 2005 and 46% in 2004, and (d) an expected life of 5 years. There were no employee stock options granted in 2003. Stock option transactions during 2005, 2004 and 2003 were as follows:

 

     Number
of Options
    Weighted
Average
Exercise
Price
   Range of
Exercise Price
   Weighted
Average
Remaining
Contractual
Life

Outstanding, January 1, 2003

   1,540,052        $0.75 to $18.00    7.8 yrs

Granted – 1997 director compensation plan

   20,000     $ 4.85      

Cancelled in exchange for common stock

   (1,016,500 )     5.22      

Exercised – 1995 stock option plan

   (24,000 )     2.63      

Expiration of options

   (282,739 )     5.38      
              

Outstanding, December 31, 2003

   236,813        $0.75 to $5.85    7.7 yrs

Granted – 1995 stock option plan

   220,000       16.46      

Exercised – 1995 stock option plan

   (2,750 )     2.90      

Exercised – 1997 director compensation plan

   (43,563 )     3.74      
              

Outstanding, December 31, 2004

   410,500        $0.75 to $16.46    8.5 yrs

Granted – 1997 director compensation plan

   150,000       19.78      

Exercised – 1995 stock option plan

   (25,000 )     2.88      

Exercised – 1997 director compensation plan

   (16,000 )     4.92      
              

Outstanding, December 31, 2005

   519,500        $0.75 to $19.78    8.4 yrs
              

Exercisable, December 31, 2003

   194,813     $ 3.03      

Exercisable, December 31, 2004

   169,500       3.20      

Exercisable, December 31, 2005

   372,100       12.60      

In February 2003, we issued 125,157 shares of our common stock to the holders of 1,016,500 outstanding stock options in exchange for the cancellation of such options (at the time of cancellation, the options were antidilutive). Based on the value of our common stock at the time of the exchange, we recorded a $0.4 million non-cash charge to earnings in 2003 related to the issuance of shares in lieu of cancelled options.

Also in 2003, we commenced granting a series of restricted share awards, with three year vesting periods, to our employees under a stockholder approved equity compensation plan. The cost of the shares of restricted stock award is recorded at fair market value at the date of grant as unearned compensation, a contra equity account. The unearned deferred compensation balance is shown as a reduction to stockholders’ equity and is being amortized to compensation expense ratably over the vesting period of the participants. During 2005, 2004 and 2003, we contributed $1.5 million, $2.1 million and $0.5 million, respectively, under the plan through the issuance of 75,750, 238,750 and 161,500 shares, respectively, of our common stock. During 2005, 2004 and 2003, $1.1 million, $0.6 million and $0.2 million, respectively, were charged to compensation expense related to the awards. During 2005 and 2004, we recorded credits to the contra equity account of $0.1 million and $0.2 million, respectively, for the value of 12,832 shares and 28,918 shares, respectively, of non-vested restricted share awards that were forfeited by terminated employees.

 

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NOTE I—Hedging Activities

Commodity Hedging Activity

We enter into swap contracts, costless collars or other hedging agreements from time to time to manage the commodity price risk for a portion of our production. We consider these to be hedging activities and, as such, monthly settlements on these contracts are reflected in our crude oil and natural gas sales, provided the contracts are deemed to be “effective” hedges under FAS 133. Our strategy, which is administered by the Hedging Committee of the Board of Directors, and reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and 70% of our production. As of December 31, 2005, the commodity hedges we utilized were in the form of: (a) swaps, where we receive a fixed price and pay a floating price, based on NYMEX quoted prices; and (b) collars, where we receive the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the ceiling price. Hedge ineffectiveness results from difference changes in the NYMEX contract terms and the physical location, grade and quality of our oil and gas production. As of December 31, 2005, our open forward position on our outstanding commodity hedging contracts, all of which were with BNP, was as follows:

 

Swaps

   Volume    Average
Price

Natural gas (MMBtu/day)

     

1Q 2006

   14,000    $ 7.06

2Q 2006

   15,000      6.95

3Q 2006

   15,000      6.95

4Q 2006

   15,000      6.95

1Q 2007

   10,000      7.77

Oil (Bbl/day)

     

1Q 2006

   700    $ 49.85

2Q 2006

   800      50.80

3Q 2006

   800      50.80

4Q 2006

   800      50.80

2007

   400      53.35

Collars

   Volume    Floor/Cap

Natural gas (MMBtu/day)

     

1Q 2007

   10,000    $ 7.00 – $16.90

2Q 2007

   15,000      7.00 –   15.90

3Q 2007

   15,000      7.00 –   15.90

4Q 2007

   15,000      7.00 –   15.90

The fair value of the oil and gas hedging contracts in place at December 31, 2005 resulted in a net liability of $29.4 million. As of December 31, 2005, $2.2 million (net of $1.2 million in income taxes) of deferred losses on derivative instruments accumulated in other comprehensive loss are expected to be reclassified into earnings during the next twelve months. For the year ended December 31, 2005, we recognized in earnings a loss on derivatives not qualifying for hedge accounting in the amount of $37.8 million (also included in this loss amount are settlement payments on ineffective gas hedges). This loss was recognized because our gas hedges were deemed to be ineffective for 2005, accordingly, the changes in fair value of such hedges could no longer be reflected in other comprehensive loss. For the year ended December 31, 2005, $6.0 million of previously deferred losses (net of $3.2 million in income taxes) was reclassified from accumulated other comprehensive loss to oil and gas sales as the cash flow of the hedged items was recognized.

 

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In February 2006, we entered into a collar with the Bank of Montreal for 15,000 MMBtu per day with a floor of $7.00 and ceiling of $13.60 for calendar year 2007.

Despite the measures taken by us to attempt to control price risk, we remain subject to price fluctuations for natural gas and crude oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Domestic crude oil and gas prices could have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis.

Interest Rate Swaps

We have a variable-rate debt obligation that exposes us to the effects of changes in interest rates. To partially reduce our exposure to interest rate risk, from time to time we enter into interest rate swap agreements. At December 31, 2005 we had the following interest rate swaps in place with BNP (in millions):

 

Effective

Date

  

Maturity

Date

  

LIBOR

Swap Rate

 

Notional

Amount

11/08/04    02/26/06    3.46%   $ 18.0
02/27/06    02/26/07    4.08%     23.0
02/27/06    02/26/07    4.85%     17.0
02/27/07    02/26/09    4.86%     40.0

The fair value of the interest rate swap contracts in place at December 31, 2005, resulted in an asset of $0.1 million. As of December 31, 2005, $111,000 (net of $60,000 in income taxes) of deferred net gains on derivative instruments accumulated in other comprehensive income are expected to be reclassified into earnings during the next twelve months. During the year ended December 31, 2005, $21,000 of previously deferred losses (net of $12,000 in income taxes) were reclassified from accumulated other comprehensive income to interest expense as the cash flow of the hedged items was recognized. For the years ended December 31, 2005 and 2004, our earnings were not significantly affected by cash flow hedging ineffectiveness of interest rates.

NOTE J—Fair Value of Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS No. 107, “Disclosures About Fair Value of Financial Instruments” (“SFAS 107”). The estimated fair value amounts have been determined using available market information and valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The carrying amounts and fair values of the other financial instruments and derivatives at December 31, 2005 and 2004 are as follows (in thousands):

 

     2005     2004  
     Carrying
Amount
    Fair
Value
    Carrying
Amount
    Fair
Value
 

Long-term debt including current maturities

   $ 30,000     $ 30,000     $ 27,000     $ 27,000  

Production payment liability

     –         –         268       268  

Derivative assets (liabilities)

        

Oil

     (4,810 )     (4,810 )     (2,657 )     (2,657 )

Gas

     (24,620 )     (24,620 )     823       823  

Interest rate

     107       107       (162 )     (162 )

 

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NOTE K—Commitments and Contingencies

Operating Leases

We have commitments under an operating lease agreement for office space. Total rent expense for the years ended December 31, 2005, 2004 and 2003 was approximately $0.4 million, $0.3 million and $0.3 million respectively. At December 31, 2005, the future minimum rental payments due under the lease are as follows (in thousands):

 

2006

   $ 495

2007

     502

2008

     508

2009

     338
      

Total

   $     1,843
      

We also have non-cancellable drilling rig commitments of $15.2 million and $2.7 million for 2006 and 2007, respectively.

Contingencies

In July 2005, we received a Notice of Proposed Tax Due from the State of Louisiana asserting that we underpaid our Louisiana franchise taxes for the years 1998 through 2004 in the amount of $0.5 million. The Notice of Proposed Tax Due includes additional assessments of penalties and interest in the amount of $0.4 million for a total asserted liability of $0.9 million. We believe that we have fully paid our Louisiana franchise taxes for the years in question, therefore, we intend to vigorously contest the Notice of Proposed Tax Due. We have commenced our analysis of this contingency and have not recorded any provision for possible payment of additional Louisiana franchise taxes nor any related penalties and interest.

Litigation

In the third quarter of 2004, we recognized a non-recurring gain in the amount of $2.1 million, reflecting the proceeds of a successful litigation judgment. We commenced the litigation as plaintiff in February 2000 against the operator of a South Louisiana property which was jointly acquired by us and the defendant in September 1999. The judgment provided for recovery of our damages and a portion of our attorneys’ fees as well as interest calculated on our damages.

We are party to additional lawsuits arising in the normal course of business. We intend to defend these actions vigorously and believe, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our financial position or results of operations.

NOTE L—Related Party Transactions

On March 12, 2002, we completed the sale of a 30% working interest in the existing production and shallow rights, and a 15% working interest in the deep rights below 10,600 feet, in our Burrwood and West Delta 83 fields for $12.0 million to Malloy Energy Company, LLC (“MEC”), led by Patrick E. Malloy, III and participated in by Sheldon Appel, each of whom were members of our Board of Directors at that time, as well as Josiah Austin, who subsequently became a member of our Board of Directors. Mr. Malloy is now Chairman of our Board of Directors and Mr. Appel retired from the Board of Directors in February 2004.

 

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Subsequent to the acquisition of a 30% working interest in the Burrwood and West Delta 83 fields in March 2002, MEC acquired an approximate 30% working interest in three other fields we operated in 2003 and 2004. In accordance with industry standard joint operating agreements, we bill MEC for its share of the capital and operating costs of the three fields on a monthly basis. As of December 31, 2005 and 2004, the amounts billed and outstanding to MEC for its share of monthly capital and operating costs were $0.5 million and $1.4 million, respectively, and are included in trade and other accounts receivable at each year-end. Such amounts at each year-end were paid by MEC to us in the month subsequent to billing and the affiliate is current on payment of its billings.

We also serve as the operator for a number of other oil and gas wells owned by an affiliate of MEC in which we own a 7% after payout working interest. In accordance with industry standard joint operating agreements, we bill the affiliate for its share of the capital and operating costs of these wells on a monthly basis. As of December 31, 2005 and 2004, the amounts billed and outstanding to the affiliate for its share of monthly capital and operating costs were $31,000 and $1.7 million, respectively, and are included in trade and other accounts receivable at each year-end. Such amounts at each year-end were paid by the affiliate to us in the month subsequent to billing and the affiliate is current on payment of its billings.

NOTE M—Discontinued Operations

In October 2004, we sold our operated interests in the Marholl and Sean Andrew fields, along with our non-operated interests in the Ackerly field, all of which were located in West Texas, for gross proceeds of approximately $2.1 million. We realized a gain of $0.9 million on the sale of these non-core properties. The results of operations of these sold properties, including the gain on sale, have been presented as discontinued operations in the accompanying consolidated statement of operations.

Results for these properties reported as discontinued operations were as follows (in thousands):

 

         Year Ended December 31,      
         2004     2003      
  Oil and gas sales    $ 566     $ 557    
  Operating expenses      (290 )     (256 )  
  Gain on sale      877       –      
                    
 

Income before income taxes

             1,153                  301    
  Income tax expense      (404 )     (105 )  
                    
  Income from discontinued operations    $ 749     $ 196    
                    

NOTE N—Oil and Gas Producing Activities (Unaudited)

Capitalized Costs Related to Oil and Gas Producing Activities

The table below reflects our capitalized costs related to oil and gas producing activities at December 31, 2005, and 2004 (in thousands):

 

         2005     2004      
 

Proved properties

   $ 301,842     $ 148,497    
 

Unproved properties

     14,444       11,407    
                    
               316,286               159,904    
 

Less accumulated depreciation, depletion and amortization

     (73,291 )     (51,074 )  
                    
 

Net oil and gas properties

   $ 242,995     $ 108,830    
                    

 

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Costs Incurred

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

 

     Year Ended December 31,
     2005    2004    2003

Property Acquisition

        

Unproved

   $ 9,216    $ 5,528    $ 601

Exploration

     14,021      4,874      2,249

Development (1)

     143,574      36,351      18,177
                    
   $     166,811    $     46,753    $     21,027
                    

(1)

Includes asset retirement costs of $1,004 thousand in 2005, $389 thousand in 2004 and $453 thousand in 2003.

Oil and Natural Gas Reserves

All of our reserve information related to crude oil, condensate, and natural gas liquids and natural gas was compiled based on evaluations performed by Netherland, Sewell & Associates, Inc. as of December 31, 2005 and 2004. All of the subject reserves are located in the continental United States.

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

Regulations published by the SEC define proved reserves as those volumes of crude oil, condensate, and natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those volumes expected to be recovered as a result of making additional investments by drilling new wells on acreage offsetting productive units or recompleting existing wells.

The following table sets forth our net proved oil and gas reserves at December 31, 2002, 2003, 2004 and 2005 and the changes in net proved oil and gas reserves for the years ended December 31, 2003, 2004 and 2005:

 

     Natural Gas (MMcf)     Oil (MBbls)  
     2005     2004     2003     2005     2004     2003  

Proved Reserves at

    beginning of period

   67,682     30,903     29,069     5,589     7,805     7,441  

Revisions of previous estimates (1)

   (10,382 )   (6,666 )   648     (648 )   (3,466 )   54  

Extensions, discoveries and

    other additions (2)

   91,900     48,322     6,130     440     1,987     794  

Sales of minerals in place

   –       (54 )   (1,583 )   –       (249 )   –    

Production

   (6,237 )   (4,823 )   (3,361 )   (408 )   (488 )   (484 )
                                    

Proved Reserves at

    end of period

       142,963         67,682         30,903         4,973           5,589         7,805  
                                    

Table continued on following page

 

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     Natural Gas (MMcf)    Oil (MBbls)
     2005    2004    2003    2005    2004    2003

Proved developed:

                 

Beginning of period

       24,362    123,429        15,203        2,228        3,601        2,557

End of period

   56,700    24,362    23,429    1,796    2,228    3,601

(1)

Revisions of previous estimates were negative on an overall basis in 2005 and 2004 primarily related to our South Louisiana properties. The main reasons for this decrease were (a) the premature depletion or decline in production from wells which had larger estimates of producible reserves at the previous reporting period and (b) new and/or revised interpretations of technical data from recently drilled wells, updated production performance from existing and offset wells, and/or the results of enhanced 3-D seismic evaluations.

(2)

Extensions, discoveries and other reserve additions were positive on an overall basis in 2005 and 2004 and primarily related to our newly acquired properties in the Cotton Valley Trend of East Texas and North Louisiana. The main reason for this increase was the commencement of our Cotton Valley drilling program in the first quarter of 2004 which resulted in a substantial volume of both proved developed and proved undeveloped reserves being recorded.

The following table summarizes our combined oil and gas reserve information on a MMcfe basis.

 

     Year Ended December 31,
     2005      2004      2003

Total proved

       172,799          101,216          77,736

Proved developed

   67,474      37,732      45,035

Standardized Measure

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

 

     2005     2004     2003  

Future revenues

   $     1,798,972     $     654,543     $     446,165  

Future lease operating expenses and production taxes

     (379,872 )     (151,186 )     (87,929 )

Future development costs (1)

     (245,868 )     (86,919 )     (33,180 )

Future income tax expense

     (353,472 )     (104,870 )     (77,855 )
                        

Future net cash flows

     819,760       311,568       247,201  

10% annual discount for estimated timing of cash flows

     (409,140 )     (130,890 )     (83,227 )
                        

Standardized measure of discounted future net cash flows

   $ 410,620     $ 180,678     $ 163,974  
                        

Average price used to calculate reserves (2)

      

Natural gas (per Mcf)

   $ 10.54     $ 6.14     $ 6.42  

Oil (per Bbl)

   $ 58.80     $ 42.72     $ 31.75  

(1)

Includes cumulative asset retirement obligations of $8.0 million, $6.8 million and $6.5 million in 2005, 2004 and 2003, respectively.

(2)

These average prices, used to estimate our reserves at these dates, reflect applicable transportation and quality differentials on a well-by-well basis.

Future revenues are computed by applying year-end prices of oil and gas to the year-end estimated future production of proved oil and gas reserves. The base prices used for the PV-10 calculation were public market prices on December 31 adjusted by differentials to those market prices. These price adjustments were done on a property-by-property basis for the quality of the oil and natural gas and for transportation to the appropriate location. Estimates of future development and production costs are based on year-end costs and assume continuation of existing economic conditions and year-end prices. We will incur significant capital in the development of our Cotton Valley Trend properties. We believe with reasonable certainty that we will be able

 

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Table of Contents
Index to Financial Statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

to obtain such capital in the normal course of business. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. The standardized measure of discounted cash flows is the future net cash flows less the computed discount.

Changes in Standardized Measure

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

 

     Year Ended December 31,  
     2005     2004     2003  

Net changes in prices and production costs related

    to future production

   $ 185,709     $ 84,156     $ 47,406  

Sales and transfers of oil and gas produced, net of production costs

     (54,024 )     (34,636 )     (24,378 )

Net change due to revisions in quantity estimates

     (48,540 )     (27,462 )     2,693  

Net change due to extensions, discoveries and improved recovery

     321,529       60,239       30,081  

Net change due to purchases and sales of minerals in place

     –         (4,278 )     (4,373 )

Future development costs

     (79,618 )     (53,739 )     (4,227 )

Net change in income taxes

     (124,526 )     (22,640 )     (23,136 )

Accretion of discount

     24,148       21,462       15,136  

Change in production rates (timing) and other

     5,264       (6,398 )     510  
                        
   $     229,942     $     16,704     $     39,712  
                        

NOTE O—Summarized Quarterly Financial Data (Unaudited)

(In Thousands, Except Per Share Amounts)

 

     First
Quarter
    Second
Quarter
    Third
Quarter
    Fourth
Quarter
    Total  

2005

          

Revenues

   $     12,560     $     13,313     $     17,258     $     25,202     $     68,333  

Operating income

     691       73       3,006       9,342       13,112  

Net income (loss)

     (6,151 )     (445 )     (19,474 )     8,620       (17,450) (2)

Net income applicable to common stock

     (6,309 )     (603 )     (19,632 )     8,339       (18,205) (2)

Basic income per average common share (1)

     (0.30 )     (0.02 )     (0.79 )     0.35       (0.75 )

Diluted income per average common share (1)

     (0.30 )     (0.02 )     (0.79 )     0.34       (0.75 )

2004

          

Revenues

   $ 10,764     $ 9,191     $ 12,014     $ 13,043     $ 45,012  

Operating income

     3,413       2,092       2,533       4,708       12,746  

Income from continuing operations

     2,077       2,831       4,288       8,582 (3)     17,778 (3)

Net income applicable to common stock

     1,966       2,732       4,179       9,017 (3)     17,894 (3)

Basic income per average common share (1)

     0.12       0.15       0.21       0.45       0.95  

Diluted income per average common share (1)

     0.10       0.14       0.21       0.43       0.91  

(1)

The sum of the per share amounts per quarter does not equal the year due to the changes in the average number of common shares outstanding.

(2)

Includes a $27.0 million unrealized loss on derivatives not qualifying for hedge accounting.

(3)

Includes a $2.3 million unrealized gain on derivatives not qualifying for hedge accounting.

 

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