Form 10-K for Year Ending December 31, 2004
Table of Contents

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-K

 

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

 

For Fiscal Year Ended December 31, 2004

Commission file number 1-7940

 

GOODRICH PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

 

Delaware   76-0466193
(State of incorporation)   (I.R.S. Employer Identification No.)
808 Travis St., Suite 1320    
Houston, Texas   77002
(Address of principal executive offices)   (Zip Code)

 

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

 

Title of each class


 

Name of each exchange

on which registered


 

Securities registered pursuant to Section 12(b) of the Act:

 

Common Stock, $0.20 par value   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 whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x        No ¨

 

Indicate by check mark 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. ¨

 

At March 24, 2005, there were 21,050,430 shares of Goodrich Petroleum Corporation common stock outstanding. The aggregate market value of shares of common stock held by non-affiliates of the registrant as of March 24, 2005, was approximately $168,534,600 based on a closing price of $19.53 per share on the New York Stock Exchange on such date.

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes ¨        No x

 

At June 30, 2004, the aggregate market value of Goodrich Petroleum Corporation common stock held by non-affiliates was $71,198,700.

 

Documents Incorporated By Reference

 

Portions of the registrant’s annual proxy statement, to be filed within 120 days after December 31, 2004, are incorporated by reference into Part III of this Form 10-K.

 



Table of Contents

GOODRICH PETROLEUM CORPORATION

 

FORM 10-K

 

December 31, 2004

 

INDEX

 

     Page
No.


PART I     

Items 1 and 2. Business and Properties

   3

Item 3. Legal Proceedings

   17

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

   18
PART II     

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

   30

Item 8. Financial Statements and Supplementary Data

   32

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

   57

Item 9A. Controls and Procedures

   57

Item 9B. Other Information

   57
PART III     

Item 10. Directors and Executive Officers of the Registrant

   58

Item 11. Executive Compensation

   60

Item 12. Security Ownership of Certain Beneficial Owners and Management

   60

Item 13. Certain Relationships and Related Transactions

   61

Item 14. Principal Accounting Fees and Services

   61
PART IV     

Item 15. Exhibits, Financial Statement Schedules

   62

 

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Table of Contents

PART I

 

Items 1 and 2.    Business and Properties.

 

General

 

Goodrich Petroleum Corporation and subsidiaries (“Goodrich” 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. The Company owns working interests in 89 active oil and gas wells located in 18 fields in four states. At December 31, 2004, Goodrich had estimated proved reserves of approximately 5.6 million barrels of oil and condensate and 67.7 billion cubic feet (“Bcf”) of natural gas, or an aggregate of 101.21 Bcf equivalent (“Bcfe”) with a pre-tax present value of future net revenues, discounted at 10%, of $241.5 million and an after-tax present value of future net revenues of $180.7 million.

 

The Company’s principal executive offices are located at 808 Travis Street, Suite 1320, Houston, Texas 77002. The Company also has an office in Shreveport, Louisiana. At March 24, 2005, the Company had 52 employees.

 

Business Strategy

 

The Company’s business strategy is to provide long term growth in net asset value per share, through the growth and expansion of its oil and gas reserves and production. The Company focuses on adding reserve value through the careful evaluation and aggressive pursuit of oil and gas drilling and acquisition opportunities. Economic analyses are prepared on each drilling and acquisition opportunity with criteria of adding net present value for every dollar invested. In addition, the Company implements an active hedging program designed to partially reduce commodity price risks in an effort to realize the desired economic returns.

 

Several of the key elements of Goodrich’s business strategy are the following:

 

    Exploit and Develop Existing Property Base.    The Company seeks to maximize the value of its existing assets by developing and exploiting its properties with the highest production and reserve growth potential. Goodrich performs continuous field studies of its existing properties using advanced technologies. The Company seeks to minimize costs by controlling operations to the extent possible.

 

    Pursue Strategic Acquisitions.    To leverage its extensive regional knowledge base, the Company seeks to acquire leasehold acreage and producing or non-producing properties in areas, such as East Texas and South Louisiana, which are in mature fields that have multiple reservoirs and existing infrastructure.

 

    Selectively Grow Through Exploration.    The Company conducts an active exploration program that is designed to complement its lower risk exploitation and development efforts with moderate risk exploration projects offering greater reserve potential. Goodrich utilizes 3-D seismic data and other technical applications, as appropriate, to manage its exploration risks. The Company also attempts to reduce its risks through the judicious use of cost sharing arrangements with outside drilling partners.

 

    Rationalize Property Portfolio.    The Company continually strives to rationalize its 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.

 

The Company maintains a website at http://www.goodrichpetroleum.com. However, the information on the website does not constitute part of this Annual Report.

 

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Oil and Gas Operations and Properties

 

Cotton Valley Drilling Program

 

Overview.    In the first quarter of 2004, the Company commenced a major new initiative which is focused on a relatively low risk development drilling program in the Cotton Valley trend of East Texas and Northwest Louisiana. The Company spent approximately two-thirds of its total 2004 capital expenditures of $47 million on this drilling and leasehold program and has preliminarily committed a similar percentage of its total 2005 capital expenditure budget of approximately $75 million to the program. As of December 31, 2004, the Company had acquired or farmed in leases totaling approximately 45,000 gross acres, with an average working interest of approximately 85%, and is attempting to acquire additional acreage in the area. As of December 31, 2004, the Company had successfully drilled 14 operated wells targeting the Cotton Valley formation. Subsequent to December 31, 2004, the Company had successfully drilled and/or completed an additional four Cotton Valley wells. As of March 24, 2005, the Company was in the process of drilling another four Cotton Valley wells. The Company’s current Cotton Valley drilling activities are centered about three primary leasehold areas in East Texas and one field in Northwest Louisiana as further described below.

 

Dirgin-Beckville.    The Dirgin-Beckville area is located in Panola County, Texas. The Company has acquired leases totaling approximately 5,000 gross acres with an average working interest of approximately 90%. As of December 31, 2004, the Company had successfully completed four Cotton Valley wells in the Dirgin-Beckville area.

 

North Minden.    The North Minden area is located in Rusk County, Texas. The Company has acquired leases totaling approximately 18,000 gross acres with a working interest of 100%. As of December 31, 2004, the Company had successfully completed seven Cotton Valley wells in the North Minden area.

 

South Henderson.    The South Henderson area is located in Rusk County, Texas. The Company has acquired leases totaling approximately 4,000 gross acres with a working interest of nearly 100%. As of December 31, 2004, the Company had one Cotton Valley well drilling in the South Henderson area.

 

Bethany-Longstreet.    The Bethany-Longstreet field is located in Caddo and DeSoto Parishes in Northwest Louisiana. The Company commenced a drilling program targeting the Cotton Valley formation in the first quarter of 2004 and had successfully completed three Cotton Valley wells as of December 31, 2004. The Company’s initiative in this area began in the third quarter of 2003, when it obtained, via farmout, exploration rights to approximately 18,000 gross acres in the field. The Company retains continuous drilling rights to the entire block so long as it drills at least one well within 120 days from previous operations. For each productive well drilled under the agreement, the Company earns an assignment to 160 acres. The Company began exploration and development drilling activities in the field and completed three successful wells in a shallower formation in the fourth quarter of 2003. The Company has a 70% working interest in the Bethany-Longstreet field.

 

Production and Reserves.    For all Cotton Valley wells completed to date, the Company estimates that the initial average gross production rate per well is approximately 1,350 Mcf equivalent (“Mcfe”) of gas per day. This estimated average gross production rate is consistent with the range originally projected by the Company prior to commencing its drilling activities in the Cotton Valley trend. Initial production from the Cotton Valley wells commenced in June 2004, and taking into account the expected decline following the initial production period, the current gross production from the successfully completed wells is approximately 8,500 Mcfe of gas per day, or 5,300 Mcfe per day net to the Company. The Company’s independent reserve engineering firm has estimated that the average gross ultimate reserve of the Cotton Valley wells drilled and completed to date is approximately 1.0 Bcf equivalent (“Bcfe”) per well. The estimated ultimate gross reserve of the most recent nine wells, using a refined completion technique, is approximately 1.25 Bcfe per well.

 

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The following is a summary description of the Company’s other oil and gas properties.

 

Louisiana

 

The majority of the Company’s proved oil and natural gas reserves are in the transition zone of the south Louisiana producing region. 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. The region generally contains sedimentary sandstones, which are of high qualities of porosity and permeabilities. There is a myriad of types of reservoir traps found in the region. These traps are generally formed by faulting, folding and subsurface salt movement, or a combination of one or more of these conditions.

 

The formations found in the southern Louisiana producing region range in depth from 1,000 feet to 20,000 feet below the surface. These formations range from the Sparta and Frio formations in the northern part of the region to Miocene and Pleistocene in the southern part of the region. The Company’s production comes predominately from Miocene and Frio age formations.

 

Burrwood and West Delta 83 Fields.    The Burrwood and West Delta 83 fields, located in Plaquemines Parish, Louisiana, were discovered in 1955 by Chevron. The fields lie upthrown to a large down-to-the southeast growth fault system with the structure striking northeast-southwest and dipping northwestward in a counter-regional direction. The fields have collectively produced over 50 million barrels of oil and 150 Bcf of natural gas. The productive sands are Miocene and Pliocene age sands ranging in depth from 6,300 feet to approximately 11,700 feet. There are currently 19 active producing wells in the fields.

 

Goodrich acquired a 95% working interest in approximately 8,600 acres of the Burrwood and West Delta 83 fields through an acquisition that closed on March 2, 2000 with an effective date of January 1, 2000. On March 12, 2002, the Company sold 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 such fields for $12 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 the Company’s Board of Directors at that time, as well as Josiah Austin, who subsequently became a member of the Company’s Board of Directors. Mr. Malloy is currently Chairman of the Company’s Board of Directors and Mr. Appel retired from the Board of Directors in February 2004. For a further discussion of this transaction, see Note C of the Company’s consolidated financial statements in Item 8.

 

Lafitte Field.    The Lafitte field is located in Jefferson Parish, Louisiana and was discovered in 1935 by Texaco. The Lafitte field is a large, north-south elongated salt dome anticline feature. There are currently more than thirty (30) defined productive sands, which have collectively produced in excess of approximately 265 million barrels of oil and 320 Bcf of natural gas. The productive sands are Miocene and Pliocene age sands ranging in depth from 3,000 feet to approximately 12,000 feet. There are currently 25 active producing wells in the field. In September 1999, the Company acquired a non-operated working interest of approximately 49% in the Lafitte field with respect to the field’s leases, surface facilities and equipment and a non-operated working interest of approximately 45% in the active producing wells. In November 1999, the Company acquired additional interests, resulting in a field-wide non-operated working interest of approximately 49%.

 

Second Bayou Field.    The Second Bayou field is located in Cameron Parish, Louisiana and was discovered in 1955 by the Sun Texas Company. Goodrich is the operator of eight producing wells, three of which are dually completed, and has an average working interest of approximately 31% in 1,395 gross acres. To date, the field has produced over 425 Bcf of natural gas and 3.6 million barrels of oil from multiple Miocene aged sands ranging from 4,000 to 15,200 feet.

 

Plumb Bob.    The Plumb Bob field is located in St. Martin Parish in southern Louisiana and was originally discovered by Texaco in 1939. Apache acquired the field from Texaco in a large divesture package in 1995 and did not drill any additional wells in the field prior to the time it was abandoned in 1997. In September 2003, the

 

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Company reached an agreement with a subsequent owner to obtain certain rights in the field. The rights include a 70% working interest in oil and gas leases covering approximately 450 acres and 3-D seismic permits with oil and gas lease options covering approximately 17,000 acres. In the fourth quarter of 2003, the Company began workover drilling activities in the field and restored production capability in three wells, one of which is currently producing. In the fourth quarter of 2003, the Company also commenced a 30 square mile 3-D seismic survey which was completed in the second quarter of 2004. Processing and evaluation of the seismic data was completed in late 2004 and the Company will soon determine the extent of its drilling and remaining workover plans in the field.

 

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, the Company announced that it had acquired a 70% working interest in 3-D seismic permits and oil and gas lease options enabling it to acquire an approximate 30 square mile 3-D seismic survey over the field. The Company commenced shooting the 3-D seismic survey in July 2004 and data acquisition was completed in September 2004. Processing of the data was completed in November 2004 and evaluation of the data is expected to be completed in April 2005.

 

Other.    The Company maintains ownership interests in acreage and wells in several additional fields in Louisiana, including the (i) Ada field, located in Bienville Parish, (ii) Lake Raccourci field, located in Terrebonne Parish and (iii) Pecan Lake field, located in Cameron Parish.

 

Texas

 

In addition to the areas in Texas indicated previously under “Cotton Valley Drilling Program”, the Company presently has production operations in the eastern and southern regions of Texas, as more fully described below.

 

Mary Blevins Field.    The Mary Blevins field is located in Smith County, Texas. It was a new discovery that is fault separated from Hitts Lake field, which was discovered in 1953 by Sun Oil. Currently, there are two producing wells in the field in which Goodrich serves as operator, having an approximate 48% working interest in 782 gross acres. To date, Hitts Lake has produced over 14 million barrels of oil and Mary Blevins has produced over 551,000 barrels of oil from the Paluxy B sands, which occur at a depth of approximately 7,300 feet.

 

Marholl and Sean Andrew Fields.    The Marholl field is a Siluro-Devonian (Fussellman) field in Dawson County, Texas, discovered in 1995 through the use of 3-D seismic. Prior to selling its interest in the field in October 2004, the Company operated two wells in the field with an approximate 23% working interest. The Sean Andrew field in Dawson County, Texas was discovered by the Company in 1994 utilizing the Company’s 375 square mile 3-D seismic database in West Texas. Prior to selling its interest in the field in October 2004, the Company was the operator of two wells in the field and held an approximate 37.5% working interest. In October 2004, the Company sold its operated interests in both the Marholl and Sean Andrew fields, along with its non-operated interests in the Ackerly field, located in Dawson and Howard Counties, to third parties for gross proceeds of $2.1 million and recognized a non-recurring gain of $877,000 on the sale.

 

Other.    The Company maintains ownership interests in acreage and/or wells in several additional fields in Texas including the (i) Midway field, located in San Patricio County and (ii) Mott Slough field, located in Wharton County.

 

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Oil and Natural Gas Reserves

 

The following tables set forth summary information with respect to the Company’s proved reserves as of December 31, 2004 and 2003, as estimated by the Company by compiling reserve information derived from the evaluations performed by Netherland Sewell & Associates, Inc. as of December 31, 2004, and by Coutret and Associates, Inc. as of December 31, 2003.

 

     Net Reserves

   Pre-Tax Present
Value of Future
Net Revenues
(in millions)


  

After-Tax Present
Value of Future
Net Revenues

(in millions)


Category


   Oil (Bbls)

   Gas (Mcf)

   Bcfe (1)

     

December 31, 2004

                            

Proved Developed

   2,228,254    24,361,773    37.73    $ 119.20       

Proved Undeveloped

   3,360,605    43,320,675    63.48      122.30       
    
  
  
  

  

Total Proved

   5,588,859    67,682,448    101.21    $ 241.50    $ 180.68
    
  
  
  

  

December 31, 2003

                            

Proved Developed

   3,600,980    23,429,440    45.04    $ 131.02       

Proved Undeveloped

   4,204,430    7,473,950    32.70      83.60       
    
  
  
  

  

Total Proved

   7,805,410    30,903,390    77.74    $ 214.62    $ 163.97
    
  
  
  

  


(1) Estimated by the Company using a conversion ratio of 1.0 Bbl/6.0 Mcf.

 

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 Present Value of Future Net Revenues amounts shown above should not be construed as the current market value of the oil and natural gas reserves attributable to the Company’s properties.

 

In accordance with the guidelines of the Securities and Exchange Commission (SEC), the engineers’ estimates of future net revenues from the Company’s properties and the pre-tax Present Value of Future Net Revenues 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, 2004, and 2003 used in such estimates averaged $6.14 and $6.42 per Mcf, respectively, of natural gas and $42.72 and $31.75 per Bbl, respectively, of crude oil/condensate.

 

Productive Wells

 

The following table sets forth the number of active well bores in which the Company maintains ownership interests as of December 31, 2004:

 

     Oil

   Gas

   Total

     Gross (1)

   Net (2)

   Gross (1)

   Net (2)

   Gross (1)

   Net (2)

Arkansas

         1.00    0.01    1.00    0.01

Louisiana

   45.00    22.11    24.00    10.28    69.00    32.39

Michigan

         1.00    0.01    1.00    0.01

Texas

   3.00    2.50    15.00    11.98    18.00    14.48
    
  
  
  
  
  

Total Productive Wells

   48.00    24.61    41.00    22.28    89.00    46.89
    
  
  
  
  
  

(1) Does not include royalty or overriding royalty interests.
(2) Net working interest.

 

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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 the Company maintains an ownership interest, while a net well is deemed to exist when the sum of the fractional working interests owned by the Company equals one. Wells that are completed in more than one producing horizon are counted as one well. Of the gross wells reported above, eight had multiple completions.

 

Acreage

 

The following table summarizes the Company’s gross and net developed and undeveloped natural gas and oil acreage under lease as of December 31, 2004. Acreage in which the Company’s interest is limited to a royalty or overriding royalty interest is excluded from the table.

 

     Gross

   Net

Developed acreage

         

Louisiana

   12,983    7,652

Michigan

   1,920    19

New Mexico

   640    19

Texas

   2,256    1,899
    
  
     17,799    9,589
    
  

Undeveloped acreage

         

Louisiana

   24,371    15,561

Texas

   25,739    24,849
    
  
     50,110    40,410
    
  

Total

   67,909    49,999
    
  

 

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, the Company can retain its 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 the Company has an interest are for varying primary terms; however, most of the Company’s developed lease acreage is beyond the primary term and is held so long as natural gas or oil is produced.

 

Operator Activities

 

The Company operates a majority in value of its producing properties, and will generally seek to become the operator of record on properties it drills or acquires in the future.

 

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Drilling Activities

 

The following table sets forth the drilling activities of the Company for the last three years. (As denoted in the following table, “Gross” wells refers 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,

     2004

   2003

   2002

     Gross

   Net

   Gross

   Net

   Gross

   Net

Development Wells:

                             

Productive

   15.00    12.44    8.00    4.68      

Non-Productive

   2.00    0.89    1.00    1.00      
    
  
  
  
  
  

Total

   17.00    13.33    9.00    5.68      
    
  
  
  
  
  

Exploratory Wells:

                             

Productive

   3.00    2.55    1.00    0.18    2.00    1.13

Non-Productive

         2.00    0.51      
    
  
  
  
  
  

Total

   3.00    2.55    3.00    0.69    2.00    1.13
    
  
  
  
  
  

Total Wells:

                             

Productive

   18.00    14.99    9.00    4.86    2.00    1.13

Non-Productive

   2.00    0.89    3.00    1.51      
    
  
  
  
  
  

Total

   20.00    15.88    12.00    6.37    2.00    1.13
    
  
  
  
  
  

 

Net Production, Unit Prices and Costs

 

The following table presents certain information with respect to oil, gas and condensate production attributable to the Company’s interests in all of its 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, 2004.

 

     2004

   2003

   2002

Net Production (1):

                    

Natural gas (Mcf)

     4,817,564      3,352,802      2,468,806

Oil (barrels)

     475,251      464,429      432,134

Natural gas equivalents (Mcfe) (2)

     7,669,070      6,139,376      5,061,610

Average Net Daily Production (1):

                    

Natural gas (Mcf)

     13,163      9,186      6,764

Oil (barrels)

     1,299      1,272      1,184

Natural gas equivalents (Mcfe) (2)

     20,957      16,820      13,868

Average Sales Price Per Unit (1):

                    

Natural gas (Mcf)

   $ 6.12    $ 5.34    $ 3.09

Oil (barrels)

   $ 32.35    $ 29.64    $ 25.19

Other Data:

                    

Lease operating expense (per Mcfe)

   $ 0.97    $ 0.99    $ 1.50

Production taxes (per Mcfe)

   $ 0.40    $ 0.37    $ 0.32

DD & A (per Mcfe)

   $ 1.51    $ 1.45    $ 1.40

Exploration (per Mcfe)

   $ 0.58    $ 0.36    $ 0.20

(1) Reflects reclassification of prior year amounts to report the results of operations of non-core properties sold in 2004 as discontinued operations. Does not include unrealized gain from the ineffective portion of gas hedges in fourth quarter of 2004.
(2) Estimated by the Company using a conversion ratio of 1.0 Bbl/6.0 Mcf.

 

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The Company’s acquisition strategy for the Gulf Coast Basin calls for the acquisition of mature oil and gas fields with declining production profiles, established production histories and multiple productive sands that have been overlooked and/or starved of capital. Acquisitions of this type generally require significant lease operation, exploration and capital expenditure cash outlays during initial years of ownership. The Company’s Lafitte and Burrwood/West Delta 83 acquisitions in 1999 and 2000, were strategic acquisitions that fit the aforementioned profile, and account for the majority of the unit costs in the periods presented above. The impact of the Cotton Valley drilling program in East Texas and Northwest Louisiana will begin to affect the Company’s unit costs to a greater extent in 2005 and are expected to result in a gradual decrease in lease operating and exploration expenses and a gradual increase in DD&A expense.

 

Oil and Gas Marketing and Major Customers

 

Marketing.    Goodrich’s natural gas production is sold under spot or market-sensitive contracts to various gas purchasers on short-term contracts. Goodrich’s natural gas condensate is sold under short-term rollover agreements based on current market prices. The Company’s crude oil production is marketed to several purchasers based on short-term contracts.

 

Customers.    Due to the nature of the industry, the Company sells its 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 total revenues for the periods presented were as follows:

 

    

Year Ended

December 31,


 
     2004

    2003

    2002

 

Louis Dreyfus Corporation

   45 %   47 %    

Texon, LP

       25 %    

Reliant Energy

           45 %

Conoco Phillips

   8 %   5 %   17 %

Shell Trading

   5 %       17 %

Genesis Crude Oil L.P.

           5 %

Chevron Texaco

   15 %        

Texla Gas

   6 %        

Enterprise Liquids

   5 %        

 

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 those of the Company, and staffs and facilities substantially larger than those of the Company. The availability of a ready market for the oil and gas production of the Company 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.

 

Regulations

 

The availability of a ready market for any natural gas and oil production depends upon numerous factors beyond the Company’s 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

 

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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 the Company 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

 

The Company’s operations are subject to numerous stringent and complex laws and regulations at the federal, state and local levels governing the discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements, and the imposition of injunctions to force future compliance.

 

The Oil Pollution Act of 1990 (“OPA 90”) and its implementing regulations impose a variety of requirements related to the prevention of oil spills, and liability for damages resulting from such spills in United States waters. OPA 90 imposes strict, joint and several liability on responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operation regulation. If a party fails to report a spill or to cooperate fully in a cleanup, liability limits likewise do not apply. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages. For onshore facilities, the total liability limit is $350 million. OPA 90 also requires a responsible party at an offshore facility to submit proof of its financial ability to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

 

The Comprehensive Environmental Response, Compensation, and Liability Act (“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 parties include the owner or operator of the site where the release occurred, and those that disposed or arranged for the disposal of hazardous substances found at the site. Responsible parties 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. See existing environmental matters discussed in Item 3—Legal Proceedings.

 

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

 

Management believes that the Company is 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 its operations or financial condition.

 

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Risk Factors

 

The Company’s actual production, revenues and expenditures related to its reserves are likely to differ from its estimates of proved reserves. The Company may experience production that is less than estimated and drilling costs that are greater than estimated in its reserve reports. 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 consulting reserve engineers and were calculated using oil and gas prices as of December 31, 2004. These prices will change and may be lower at the time of production than those prices that prevailed at the end of 2004. Petroleum 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. The Company’s 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 its properties. As required by the SEC, the estimated 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

 

    change in governmental regulations or taxation.

 

In addition, the 10% discount factor, which is required by the SEC to be used to calculate discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company 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 the Company’s business.

 

The Company’s success will depend on the market prices of oil and gas. These market prices tend to fluctuate significantly in response to factors beyond the Company’s control. The prices the Company receives for

 

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its crude oil production are based on global market conditions. The general pace of global economic growth, the continued instability in the Middle East 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 gas prices increased substantially from 2002 to 2003 and from 2003 to 2004. The Company expects that commodity prices will continue to fluctuate significantly in the future.

 

Changes in commodity prices significantly affect the Company’s 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 the Company to reinvest in exploration and development activities. Reductions in oil and 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. The Company uses derivative financial instruments to hedge a portion of its exposure to changing commodity prices and the Company has hedged a targeted portion of its anticipated production for 2005.

 

The Company’s use of oil and gas price hedging contracts may limit future revenues from price increases and result in significant fluctuations in its net income.

 

The Company use hedging transactions with respect to a portion of its oil and gas production to achieve more predictable cash flow and to reduce its 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.

 

The Company’s results of operations may be negatively impacted by its financial derivative instruments and fixed price forward sales contracts in the future and these instruments may limit any benefit the Company would receive from increases in the prices for natural gas and oil. For the years ended December 31, 2004, 2003 and 2002, the Company realized a loss on settled financial derivatives of $6.17 million, $2.70 million and $1.01 million, respectively.

 

In the year ended December 31, 2004, the Company recognized in earnings an unrealized gain on derivative instruments in the amount of $2,317,000. This gain was recognized because the Company’s natural gas hedges were deemed to be ineffective for the fourth quarter of 2004, 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 Company’s hedges are not deemed to be effective in the future, the Company will likewise be exposed to volatility in earnings resulting from changes in the fair value of its hedges.

 

Delays in development or production curtailment affecting the Company’s material properties may adversely affect its financial position and results of operations.

 

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

 

Because the Company’s operations require significant capital expenditures, the Company may not have the funds available to replace reserves, maintain production or maintain interests in its properties.

 

The Company must make a substantial amount of capital expenditures for the acquisition, exploration and development of oil and gas reserves. Historically, the Company has paid for these expenditures with cash from

 

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operating activities, proceeds from debt and equity financings and asset sales. The Company’s revenues or cash flows could be reduced because of lower oil and gas prices or for other reasons. If the Company’s revenues or cash flows decrease, it may not have the funds available to replace reserves or maintain production at current levels. If this occurs, the Company’s production will decline over time. Other sources of financing may not be available to the Company if the Company’s cash flows from operations are not sufficient to fund its capital expenditure requirements. Where the Company is not the majority owner or operator of an oil and gas property, such as the Lafitte field, the Company may have no control over the timing or amount of capital expenditures associated with the particular property. If the Company cannot fund such capital expenditures, its interests in some properties may be reduced or forfeited.

 

The Company may have difficulty financing its planned growth.

 

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

 

If the Company is not able to replace reserves, it may not be able to sustain production at present levels.

 

The Company’s future success depends largely upon its ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Unless the Company replaces the reserves it produce through successful development, exploration or acquisition activities, its proved reserves will decline over time. In addition, approximately 63% of the Company’s total estimated proved reserves by volume at December 31, 2004 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. The Company may not be able to successfully find and produce reserves economically in the future. In addition, it may not be able to acquire proved reserves at acceptable costs.

 

The Company may incur substantial impairment writedowns.

 

If management’s estimates of the recoverable reserves on a property are revised downward or if natural gas and oil prices decline, it may be required to record additional non-cash impairment writedowns in the future, which would result in a negative impact to its financial position. The Company reviews its 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, the Company compares the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon the Company’s 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, the Company recognizes 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 the Company’s 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. The Company recorded no impairment in the year ended December 31, 2004, however, it recorded annual impairments of $0.34 million and $0.34 million, respectively, for the years ended December 31, 2003 and 2002.

 

Management’s assumptions used in calculating oil and gas reserves or regarding the future cash flows or fair value of the Company’s properties are subject to change in the future. Any change could cause impairment

 

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expense to be recorded, impacting the Company’s net income or loss and its basis in the related asset. Any change in reserves directly impacts the Company’s 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 the Company’s production, revenue and cash flow from operating activities are derived from assets that are concentrated in a geographic area.

 

Approximately 54% of the Company’s estimated proved reserves at December 31, 2004 and a substantially higher percentage of its production were associated with its core South Louisiana properties (primarily, Burrwood and West Delta 83 fields, Lafitte field, Second Bayou field, Plumb Bob field and Lake Raccourci field). Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on the Company’s overall production level and its revenue.

 

The oil and gas business involves many uncertainties, economic risks and operating risks that can prevent the Company from realizing profits and can cause substantial losses.

 

The Company’s 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 the Company’s exploration, development and production activities to be unsuccessful. This could result in a total loss of the Company’s 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 the Company. 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 the Company’s properties. In accordance with customary industry practices, the Company maintains 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 the Company’s financial position and results of operations.

 

The Company’s debt instruments impose restrictions on the Company that may affect the Company’s ability to successfully operate its business.

 

The Company’s senior credit facility contains customary restrictions, including covenants limiting the Company’s 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. The Company also is required to meet specified financial ratios under the terms of its credit facility. These restrictions may make it difficult for the Company to successfully execute its business strategy or to compete in its industry with companies not similarly restricted.

 

The Company may be unable to identify liabilities associated with the properties that it acquires or obtain protection from sellers against them.

 

The acquisition of properties requires the Company to assess a number of factors, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are

 

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inexact and inherently uncertain. In connection with the assessments, the Company performs a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of the Company’s due diligence, it may not inspect every well, platform or pipeline. The Company cannot necessarily observe structural and environmental problems, such as pipeline corrosion, when an inspection is made. The Company may not be able to obtain contractual indemnities from the seller for liabilities that it created. The Company 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 its expectations.

 

The Company is 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. The Company 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.

 

Under these laws and regulations, it could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of its operations and subject the Company to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase the Company’s costs. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect the Company’s financial condition and results of operations.

 

Competition in the oil and gas industry is intense, and the Company is smaller and has a more limited operating history than some of its competitors.

 

The Company competes with major and independent natural gas and oil companies for property acquisitions. The Company also competes for the equipment and labor required to operate and to develop these properties. Some of the Company’s competitors have substantially greater financial and other resources than the Company. 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 the Company can, which would adversely affect its competitive position. These competitors may be able to pay more for natural gas and oil properties and may be able to define, evaluate, bid for and acquire a greater number of properties than the Company can. The Company’s ability to acquire additional properties and develop new and existing properties in the future will depend on its ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

 

The Company’s success depends on its management team and other key personnel, the loss of any of whom could disrupt its business operations.

 

The Company’s success will depend on its ability to retain and attract experienced engineers, geoscientists and other professional staff. The Company depends to a large extent on the efforts, technical expertise and continued employment of these personnel and members of its 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, the Company’s business operations could be adversely affected.

 

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Some of the Company’s operations are exposed to the additional risk of tropical weather disturbances.

 

Some of the Company’s 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, Hurricane Ivan impacted the Company’s South Louisiana operations in September 2004 causing property damage to certain facilities in the Company’s Burrwood and West Delta 83 fields, a substantial portion of which was covered by insurance. Additionally, oil and gas production in those fields was completely or partially shut-in for approximately 10 days reducing the Company’s overall production volumes in the third quarter of 2004 by approximately 5%. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks.

 

Terrorist attacks or similar hostilities may adversely impact the Company’s 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 the Company in particular, is unknown. Uncertainty surrounding military strikes or a sustained military campaign may affect the Company’s 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. 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 the Company to obtain. There can be no assurance that insurance will be available to the Company without significant additional costs. Instability in the financial markets as a result of terrorism or war could also affect the Company’s ability to raise capital.

 

Item 3.    Legal Proceedings.

 

On February 8, 2000, the Company commenced a suit against the operator and joint owner of the Lafitte field, alleging certain items of misconduct and violations of the agreements associated primarily with the joint acquisition of and unfettered access to a license to 3-D seismic data over the field. The operator counter-claimed against Goodrich on the grounds that Goodrich was obligated to post a bond to secure the plugging and abandonment obligations in the field. On November 1, 2002, the 125th Judicial District Court of Harris County, Texas, ruled in favor of the Company stating (1) The Sale and Assignment between the Company and the operator assigned the same rights to the 3-D seismic data that the operator had pursuant to the operator’s data use license agreement from Texaco Exploration and Production, Inc. (“TEPI”); and (2) Also pursuant to the terms of the Sale and Assignment, Goodrich is required to post 49% of the bond liability to TEPI at such time that TEPI requests it. A jury trial commenced in September 2003. On October 29, 2003, the jury found the operator and joint owner to be in breach of the Sale and Assignment and awarded a wholly-owned subsidiary of the Company monetary damages as well as recovery of attorneys’ fees. On May 28, 2004, the trial court ordered a final judgment which awarded the Company a net sum of approximately $2,065,000 as follows:

 

  1. $538,000 in damages;

 

  2. $1,515,000 in recovery of plaintiff’s attorneys’ fees; and

 

  3. Pre-judgment interest of approximately $115,000, which was calculated on the damages at a rate of 5%, per annum, compounded annually, from the date of the filing of the lawsuit on February 8, 2000 through May 27, 2004, the day preceding the date of the final judgment.

 

The trial court also ordered the Company to pay $103,000 to the operator in recovery of defendant’s attorneys’ fees and provided for post-judgment interest to accrue on the awarded damages and both parties’ attorneys’ fees through the date of ultimate payment. Either party could have appealed the final judgment or filed a motion for a new trial within ninety days from the date of the final judgment. In September 2004, the time period for either party to appeal the judgment elapsed, therefore, the Company accrued a non-recurring gain in the quarter ended September 30, 2004 in the amount of $2,050,000, reflecting the anticipated payment of the

 

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final judgment by the operator less the Company’s estimated expenses of the final judgment. In October 2004, the operator remitted a total of $2,118,000 to the Company in full satisfaction of the judgment, including the net amount of post-judgment interest.

 

The Company is party to additional lawsuits arising in the normal course of business. The Company intends to defend these actions vigorously and believes, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to its 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.

 

The Company’s common stock is traded on the New York Stock Exchange under the symbol “GDP”.

 

At March 24, 2005, the number of holders of record of the Company’s common stock without determination of the number of individual participants in security positions was 1,681 with 21,050,430 shares outstanding. High and low sales prices for the Company’s common stock for each quarter during the calendar years 2004 and 2003 are as follows:

 

     2004

   2003

Quarter Ended


   High

   Low

   High

   Low

March 31

   $ 10.20    $ 5.07    $ 4.27    $ 2.39

June 30

   $ 8.83    $ 6.20    $ 4.93    $ 3.11

September 30

   $ 14.08    $ 8.27    $ 5.14    $ 4.22

December 31

   $ 16.46    $ 11.91    $ 5.60    $ 4.60

 

Dividends

 

The Company has neither declared nor paid any cash dividends on its common stock and does not anticipate declaring any dividends in the foreseeable future. The Company expects to retain its cash for the operation and expansion of its business, including exploration, development and production activities. In addition, the Company’s 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

 

The Company made no repurchases of its common stock in the year ended December 31, 2004.

 

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Item 6.    Selected Financial Data.

 

Selected Statement of Operations Data:

 

The following table sets forth selected financial data of the Company for each of the years in the five-year period ended December 31, 2004, which information has been derived from the Company’s audited financial statements. This information should be read in connection with and is qualified in its entirety by the more detailed information in the Company’s financial statements under Item 8 below and in “Item 7. Management’s Discussion And Analysis Of Financial Condition And Results Of Operations.”

 

    Year Ended December 31,

 
    2004

    2003

    2002

    2001

    2000

 

Revenues

                                       

Oil and gas revenues

  $ 44,861,110     $ 31,663,345     $ 18,502,426     $ 28,342,397     $ 26,961,411  

Unrealized gain on derivatives

    2,317,295                          

Other

    151,192       476,879       130,702       353,117       475,146  
   


 


 


 


 


Total revenues

    47,329,597       32,140,224       18,633,128       28,695,514       27,436,557  
   


 


 


 


 


Expenses

                                       

Lease operating expense

    7,402,353       6,098,673       7,523,425       6,299,308       4,429,995  

Production taxes

    3,105,426       2,287,648       1,641,549       1,807,825       2,168,570  

Depletion, depreciation and amortization

    11,562,234       8,995,632       7,023,462       7,157,774       6,284,388  

Exploration

    4,426,010       2,248,802       1,019,180       4,284,111       2,813,332  

Impairment of oil and gas properties

          335,558       342,079       1,800,536       1,834,654  

General and administrative

    5,820,920       5,314,487       4,467,641       3,134,865       2,518,228  

Interest expense and other

    1,109,902       1,051,198       985,185       1,290,681       4,678,695  
   


 


 


 


 


Total costs and expenses

    33,426,845       26,331,998       23,002,521       25,775,100       24,727,862  
   


 


 


 


 


Gain (Loss) on sale of assets and litigation judgment

    2,168,440       (66,116 )     2,941,062       26,779       307,299  
   


 


 


 


 


Income (Loss) from continuing operations

                                       

Before income taxes

    16,071,192       5,742,110       (1,428,331 )     2,947,193       3,015,994  

Income taxes

    (1,706,626 )     2,015,464       (496,498 )     1,036,577       (2,028,894 )
   


 


 


 


 


Net Income (Loss) from continuing operations

    17,777,818       3,726,646       (931,833 )     1,910,616       5,044,888  

Discontinued operations including gain on sale, net of income taxes (1)

    749,533       196,144       (18,884 )     323,991       299,483  
   


 


 


 


 


Net Income (Loss) before cumulative effect

    18,527,351       3,922,790       (950,717 )     2,234,607       5,344,371  

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

          (205,293 )                  
   


 


 


 


 


Net Income (Loss)

    18,527,351       3,717,497       (950,717 )     2,234,607       5,344,371  

Preferred stock dividends

    632,971       633,463       639,753       3,002,872       1,193,768  
   


 


 


 


 


Net Income (Loss) applicable to common stock

  $ 17,894,380     $ 3,084,034     $ (1,590,470 )   $ (768,265 )   $ 4,150,603  
   


 


 


 


 


Net Income (Loss) from continuing operations

                                       

Per common share—Basic

  $ 0.91     $ 0.21     $ (0.05 )   $ 0.11     $ 0.51  
   


 


 


 


 


Per common share—Diluted

  $ 0.87     $ 0.18     $ (0.05 )   $ 0.11     $ 0.38  
   


 


 


 


 


Average common shares outstanding—Basic

    19,551,516       18,064,329       17,908,182       17,351,375       9,903,248  

Average common shares outstanding—Diluted

    20,346,985       20,481,800       17,908,182       17,351,375       13,116,641  

(1) Reflects reclassification of prior year results to report the results of operations of non-core properties sold in 2004 as discontinued operations.

 

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    As of December 31,

    2004

  2003

  2002

  2001

   2000

Selected Balance Sheet Data

                              

Total assets

  $ 127,977,080   $ 89,182,568   $ 78,566,897   $ 81,150,438    $ 64,762,740

Total long term debt

    27,000,000     20,000,000     18,500,000     24,500,000      22,965,000

Stockholders’ equity

    65,307,304     48,058,994     44,607,039     46,827,054      32,024,362

 

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

 

General

 

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. The Company owns working interests in 89 active oil and gas wells located in 18 fields in four states. At December 31, 2004, Goodrich had estimated proved reserves of approximately 5.6 million barrels of oil and condensate and 67.7 billion cubic feet (“Bcf”) of natural gas, or an aggregate of 101.21 Bcf equivalent (“Bcfe”) with a pre-tax present value of future net revenues, discounted at 10%, of $241.5 million and an after-tax present value of future net revenues of $180.7 million.

 

The Company seeks to increase shareholder value by growing its oil and gas reserves, production revenues and operating cash flow. In the Company’s 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 Goodrich.

 

Management strives to increase the Company’s oil and gas reserves, production and cash flow through a balanced program of capital expenditures involving acquisition, exploitation and exploration activities. The Company generally does not make capital commitments beyond one year. Goodrich develops an annual capital expenditure budget which is reviewed and approved by its board of directors on a quarterly basis and revised throughout the year as circumstances warrant. The Company takes into consideration its projected operating cash flow and externally available sources of financing, such as bank debt, when establishing its capital expenditure budget.

 

The Company places primary emphasis on its internally generated operating cash flow in managing its business. For this purpose, operating cash flow is defined as cash flow from operating activities as reflected in the Company’s Statement of Cash Flows. Management considers operating cash flow a more important indicator of its financial success than other traditional performance measures such as net income.

 

The Company’s revenues and operating cash flow are dependent on the successful development of its inventory of capital projects, the volume and timing of its production, as well as commodity prices for oil and gas. Such pricing factors are largely beyond the Company’s control, however, Goodrich employs commodity hedging techniques in an attempt to minimize the volatility of short term commodity price fluctuations on its earnings and operating cash flow.

 

As further described under “Results of Operations” below, the Company achieved significant increases in oil and gas production volumes and operating cash flows in the years ended December 31, 2003 and 2004. These trends largely reflect the results of Goodrich’s successful drilling program as the Company increased its capital expenditures from $8.1 million in 2002, to $19.9 million in 2003 and $47.5 million in 2004. The Company also benefited from a strong commodity pricing environment in both 2003 and 2004.

 

Results of Operations

 

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 $47,330,000 compared to $32,140,000 for the year ended December 31, 2003. Oil and gas sales for the year ended December 31, 2004 were $44,861,000

 

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compared to $31,663,000 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, with the average oil and gas prices including realized gains and losses on the Company’s commodity hedging program as further described under “Quantitative and Qualitative Disclosures About Market Risk—Commodity Hedging Activity.”

 

     2004

   2003

          Average         Average
     Production

   Sales Price

   Production

   Sales Price

Gas (Mcf)

   4,817,564    $ 6.12    3,352,802    $ 5.34

Oil (Bbls)

   475,251    $ 32.35    464,429    $ 29.64

 

Unrealized gain on derivatives, which is not reflected in the above calculation of average prices, amounted to $2,317,000 in the year ended December 31, 2004, compared to zero in the year ended December 31, 2003. The 2004 amount arose because the Company’s natural gas hedges were deemed to be ineffective for the fourth quarter of 2004, which resulted in the changes in fair value of such hedges being reflected in earnings rather than in other comprehensive income, a component of stockholders’ equity. To the extent that the Company’s hedges are not deemed to be effective in the future, the Company will likewise be exposed to volatility in earnings resulting from changes in the fair value of its hedges.

 

Other revenues for the year ended December 31, 2004 were $151,000 compared to $477,000 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 $7,402,000 for the year ended December 31, 2004 versus $6,099,000 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 $3,105,000 in the year ended December 31, 2004 compared to $2,288,000 in the year ended December 31, 2003, due to an increase in production volumes. Depletion, depreciation and amortization expense from continuing operations was $11,562,000 for the year ended December 31, 2004 versus $8,995,000 for the year ended December 31, 2003, with the increase due to higher production volumes and depletion rates. Exploration expense in the year ended December 31, 2004 was $4,426,000 versus $2,249,000 in 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.

 

The Company recorded no impairment in the recorded value of its oil and gas properties in the year ended December 31, 2004 whereas in the year ended December 31, 2003, it recorded an impairment in the amount of $336,000 due primarily to a sooner than anticipated depletion of reserves in certain fields.

 

General and administrative expenses amounted to $5,821,000 in the year ended December 31, 2004 versus $5,314,000 in the year ended December 31, 2003. The most significant factor in this variance resulted from an increase in the Company’s payroll and employee benefits expense to $2,200,000 in the year ended December 31, 2004 from $1,637,000 in the year ended December 31, 2003, primarily due to an increase in the number of employees. Partially offsetting this increase were decreases in legal fees and certain other administrative expenses.

 

Interest expense was $1,110,000 in the year ended December 31, 2004 compared to $1,051,000 in the year ended December 31, 2003, with the increase primarily attributable to a higher level of borrowings in the 2004 period.

 

Gains and losses on asset sales and litigation judgment were a net gain of $2,168,000 in the year ended December 31, 2004 compared to a net loss of $66,000 in the year ended December 31, 2003, with the increase

 

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primarily due to a non-recurring gain resulting from the final judgment ordered by the trial judge in favor of the Company in its litigation against the operator of the Lafitte field.

 

Income taxes attributable to continuing operations were a benefit of $1,707,000 in the year ended December 31, 2004 compared to an expense of $2,015,000 in the year ended December 31, 2003. The Company revised its deferred tax valuation allowance in the year ended December 31, 2004, based on the anticipated utilization of tax operating loss carryforwards and projected reversal of temporary differences, whereas in 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 $750,000 in the year ended December 31, 2004 consisting largely of the pre-tax gain realized on the sale of the Company’s operated interests in the Marholl and Sean Andrew fields, along with its 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 $877,000 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.

 

Year ended December 31, 2003 versus year ended December 31, 2002—Total revenues from continuing operations for the year ended December 31, 2003 amounted to $32,140,000 compared to $18,633,000 for the year ended December 31, 2002. Oil and gas sales for the year ended December 31, 2003 were $31,663,000 compared to $18,502,000 for the year ended December 31, 2002. This increase resulted from a 21% increase in oil and gas production volumes, due to several successful well completions from late 2002 and into 2003, as well as higher average prices for oil and gas. The following table presents the production volumes and pricing information for the comparative periods, with the average oil and gas prices including realized gains and losses on the results of the Company’s commodity hedging program as further described under “Quantitative and Qualitative Disclosures About Market Risk—Commodity Hedging Activity.”

 

     2003

   2002

     Production

   Average
Sales Price


   Production

   Average
Sales Price


Gas (Mcf)

   3,352,802    $ 5.34    2,468,806    $ 3.09

Oil (Bbls)

   464,429    $ 29.64    432,134    $ 25.19

 

Other revenues for the year ended December 31, 2003 were $477,000 compared to $131,000 for the year ended December 31, 2002, with the increase primarily due to prospect fees received by the Company in the first quarter of 2003 on the sale of interests in its Spyglass II and Tunney drilling prospects.

 

Lease operating expense from continuing operations was $6,099,000 for the year ended December 31, 2003 versus $7,523,000 for the year ended December 31, 2002, with the decrease due primarily to the Company’s ongoing efforts to reduce costs on its operated properties since replacing a contract operator in June 2002. Production taxes from continuing operations were $2,288,000 in the year ended December 31, 2003 compared to $1,642,000 in the year ended December 31, 2002, due to an increase in production volumes as well as an increase in tax rates. Depletion, depreciation and amortization expense from continuing operations was $8,995,000 for the year ended December 31, 2003 versus $7,023,000 for the year ended December 31, 2002, with the increase substantially due to higher production volumes and rates. Exploration expense in the year ended December 31, 2003 was $2,249,000 versus $1,019,000 in the year ended December 31, 2002, due primarily to the Company recognizing dry hole costs during 2003 in the amounts of $675,000 and $141,000, respectively, related to non-operated exploratory wells drilled in offshore Australia and Calcasieu Parish, Louisiana, as well as an increase in seismic costs.

 

The Company recorded an impairment in the recorded value of certain oil and gas properties in the year ended December 31, 2003 in the amount of $336,000 due primarily to a sooner than anticipated depletion of reserves in non-core fields. This compares to an impairment of $342,000 recorded in the year ended December 31, 2002.

 

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General and administrative expenses amounted to $5,314,000 in the year ended December 31, 2003 versus $4,468,000 in the year ended December 31, 2002. The most significant factors in this variance were non-cash charges of $403,000 related to the February 2003 issuance of 125,157 shares of common stock in lieu of 1,016,500 cancelled stock options, $155,000 related to the initial vesting of employee stock awards of 161,500 shares of restricted stock made primarily in February 2003 and increased legal expenses of $82,000, associated with the Company’s litigation against the operator of the Lafitte field, as well as higher insurance, payroll and other administrative expenses.

 

Interest expense was $1,051,000 in the year ended December 31, 2003 compared to $985,000 in the year ended December 31, 2002, with the decrease in interest rates being virtually offset by an increase in borrowings.

 

The Company recorded deferred tax expense (not requiring cash payment) of $2,015,000 in the year ended December 31, 2003 compared to a deferred tax benefit of $496,000 in the year ended December 31, 2002, with the increase attributable to achieving pre-tax income in 2003. The Company’s effective tax rate was 35.1% in 2003 and 34.7% in 2002. The Company has established a deferred tax valuation allowance for those deferred tax assets that it does not expect to realize based on estimates of future taxable income and the impact of the Company’s tax attributes.

 

Liquidity and Capital Resources

 

Net cash provided by operating activities was $41,028,000 in the year ended December 31, 2004, compared to $17,048,000 in the year ended December 31, 2003 and $5,349,000 in the year ended December 31, 2002. The increase in the 2004 period reflects higher oil and gas revenues, partially offset by increases in lease operating expenses, production taxes and exploration expenses. The increase in the 2003 period reflects higher oil and gas revenues and lower lease operating expenses, partially offset by an increase in general and administrative expenses. The operating cash flow amounts reflect changes in current assets and current liabilities, which resulted in an increase in operating cash flow of $14,119,000 in the year ended December 31, 2004, a decrease of $519,000 in the year ended December 31, 2003, and an increase of $1,589,000 in the year ended December 31, 2002.

 

Net cash used in investing activities was $45,414,000 and $19,500,000 in the years ended December 31, 2004 and 2003, respectively, compared to net cash provided by investing activities of $4,743,000 in the year ended December 31, 2002. In the year ended December 31, 2004, capital expenditures totaled $47,501,000, as the Company incurred substantial drilling and leasehold acquisition costs in East Texas and Northwest Louisiana (see “Cotton Valley Drilling Program”) 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 $2,087,000. In the year ended December 31, 2003, capital expenditures totaled $19,898,000 as the Company participated in the drilling of nine new wells in its Burrwood/West Delta 83, Lafitte and Bethany-Longstreet fields (eight of which were successfully completed). In the same period, the Company sold its interests in the South Drew field in Louisiana and two smaller properties in Texas for gross proceeds of $399,000. In the year ended December 31, 2002, capital expenditures totaled $8,079,000 as the Company participated in the drilling of two new wells, however, such expenditures were more than offset by proceeds from property sales of $12,823,000, primarily due to the sale of a 30% interest in the Company’s Burrwood/West Delta 83 fields as further described below (see “Sale of Oil and Gas Properties to Related Party”).

 

Net cash provided by financing activities was $6,346,000 and $589,000 in the years ended December 31, 2004 and 2003, respectively, compared to net cash used in financing activities of $6,989,000 in the year ended December 31, 2002. In the year ended December 31, 2004, net borrowings under the Company’s senior credit facility provided cash of $7,000,000 and exercises of stock options and warrants provided cash of $340,000, while preferred stock dividends and production payments used cash of $994,000. In the year ended December 31, 2003, net borrowings under the Company’s senior credit facility provided cash of $1,500,000 and exercises of

 

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stock options and warrants provided cash of $129,000, while preferred stock dividends and production payments required cash of $1,040,000. In the year ended December 31, 2002, net repayments under the Company’s senior credit facility reduced cash by $6,000,000, while preferred stock dividends and production payments required additional cash of $1,017,000. The cash resources for the net debt repayments in the year ended December 31, 2002 were provided by the sale of an interest in the Company’s Burrwood/West Delta 83 fields as further described below (see “Sale of Oil and Gas Properties to Related Party”).

 

For the year 2005, the Company has preliminarily budgeted total capital expenditures of approximately $75 million, of which approximately two-thirds is expected to be focused on a relatively low risk development drilling program in the Cotton Valley trend of East Texas and Northwest Louisiana (see “Cotton Valley Drilling Program”) and the remainder on the Company’s existing properties and new exploration programs. Subject to current economics and financial resources, the Company expects to finance its 2005 capital expenditures through a combination of cash flow from operations and borrowings under its existing bank credit facility which was expanded in February 2005 (see “Senior Credit Facility”). Additionally, the Company is considering the possible issuance of debt or equity securities to provide additional financial resources for its capital expenditures and other general corporate purposes. The Company’s senior credit facility includes certain financial covenants with which the Company was in compliance as of December 31, 2004. The Company does not anticipate a lack of borrowing capacity under its senior credit facility in the foreseeable future due to an inability to meet any such financial covenants nor a reduction in its borrowing base.

 

Cotton Valley Drilling Program

 

In the first quarter of 2004, the Company commenced what it believes is a relatively low risk drilling program which is focused on the Cotton Valley trend in the East Texas Basin in and around Rusk and Panola Counties, Texas, and DeSoto and Caddo Parishes, Louisiana. As of December 31, 2004, the Company had acquired or farmed in leases totaling approximately 45,000 gross acres, with an average working interest of approximately 85%, and is attempting to acquire additional acreage in the area. As of December 31, 2004, the Company had successfully drilled 14 operated wells targeting the Cotton Valley formation. Subsequent to December 31, 2004, the Company had successfully drilled and/or completed an additional four Cotton Valley wells. As of March 24, 2005, the Company was in the process of drilling another four Cotton Valley wells. For the wells completed to date, the Company estimates that the average initial gross production rate per well is approximately 1,350 Mcfe of gas per day. This estimated average initial gross production rate is consistent with the range originally projected by the Company prior to commencing its drilling activities in the Cotton Valley trend. Initial production from the Cotton Valley wells commenced in June 2004, and taking into account the expected decline following the initial 30 day period, the current gross production from the successfully completed wells is approximately 8,500 Mcfe of gas per day, or 5,300 Mcfe per day net to the Company.

 

In East Texas, the Company began leasing acreage in the first quarter of 2004 and commenced a drilling program in April 2004. As of December 31, 2004, the Company had drilled a total of 11 successful wells on its operated acreage targeting the Cotton Valley formation. The Company has a 100% working interest in seven of the completed wells and an 85% working interest in four of the completed wells. The Company currently has engaged three drilling rigs which are drilling new wells on its operated acreage in East Texas.

 

In Northwest Louisiana, the Company commenced a drilling program targeting the Cotton Valley formation in the first quarter of 2004 and had successfully completed three Cotton Valley wells as of December 31, 2004. The Company’s initiative in this area began in the third quarter of 2003, when it obtained, via farmout, exploration rights to approximately 18,000 gross acres in the Bethany-Longstreet field. The Company retains continuous drilling rights to the entire block so long as it drills at least one well within 120 days from previous operations. For each productive well drilled under the agreement, the Company earns an assignment to 160 acres. The Company began exploration and development drilling activities in the field and completed three successful wells in a shallower formation in the fourth quarter of 2003. The Company has a 70% working interest in the Bethany-Longstreet field.

 

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South Louisiana Operations

 

Burrwood/West Delta 83 Fields—In the second quarter of 2004, the Company successfully completed two exploratory wells in the Burrwood/West Delta 83 fields in Plaquemines Parish, Louisiana. The first well was the Company’s initial Dempsey Prospect well, in which it has a 70% working interest and the second well was the Company’s initial Norton Prospect well, in which it has a 65% working interest. Additionally, in the third quarter of 2004, the Company drilled a successful sidetrack well to one of its other existing producing wells in the field, in which it has a 65% working interest. As of December 31, 2004, the Company’s share of production from these three wells was approximately 1,630 Mcf of gas per day and 245 barrels of oil per day.

 

Plumb Bob Field—In the third quarter of 2003, the Company obtained certain rights in the Plumb Bob field located in St. Martin Parish, Louisiana. The rights include a 70% working interest in oil and gas leases covering approximately 450 acres, 3-D seismic permits with oil and gas lease options covering approximately 17,000 acres. In the fourth quarter of 2003, the Company began workover drilling activities in the field and restored production capability in three wells, one of which is currently producing. In the fourth quarter of 2003, the Company also commenced a 30 square mile 3-D seismic survey which was completed in the second quarter of 2004. Processing and evaluation of the seismic data was completed in late 2004 and the Company will soon determine the extent of its drilling and remaining workover plans in the field.

 

St. Gabriel Field—In July 2004, the Company announced that it had acquired a 70% working interest in 3-D seismic permits and oil and gas lease options enabling it to acquire an approximate 30 square mile 3-D seismic survey over the St. Gabriel field in Ascension and Iberville Parishes, Louisiana. The Company commenced shooting the 3-D seismic survey in July 2004 and data acquisition was completed in September 2004. Processing of the data was completed in November 2004 and evaluation of the data is expected to be completed in April 2005.

 

Senior Credit Facility

 

On November 9, 2001, the Company established a $50,000,000 senior credit facility with BNP Paribas, with an initial borrowing base of $25,000,000 and a three year term. In December 2003, the borrowing base was redetermined to be $28,000,000 and BNP Paribas and the Company agreed to extend the term of the senior credit facility to December 29, 2006, subject to periodic redeterminations of the borrowing base. In August 2004, the borrowing base was redetermined to be $32,000,000. Borrowings outstanding under the senior credit facility were $27,000,000 as of December 31, 2004. Interest on borrowings accrues at a rate calculated, at the option of the Company, at either the BNP Paribas base rate plus 0.00% to 0.50%, or LIBOR plus 1.50%—2.50%, depending on borrowing base utilization. Interest on LIBOR-rate borrowings is due and payable on the last day of its respective interest period. Accrued interest on each base-rate borrowing is due and payable on the last day of each quarter. The credit facility requires that the Company pay a 0.375% per annum commitment fee, payable in quarterly installments based on the Company’s borrowing base utilization. Prior to maturity, no principal payments are required so long as the maximum borrowing base amount exceeds the amounts outstanding under the credit facility. The credit facility precludes the payment of dividends on the Company’s common stock and requires the Company to maintain a working capital ratio (as defined) of not less than 1.0:1.0, an interest coverage ratio for the trailing four quarters of at least 3.0 times, and a tangible net worth of not less than the sum of $53,392,838, plus 50% of the Company’s cumulative net income after September 30, 2004, plus 100% of the net proceeds of any equity issuance by the Company after September 30, 2004. As of December 31, 2004, the Company was in compliance with all such requirements. Substantially all the Company’s assets are pledged to secure the senior credit facility.

 

In February 2005, the borrowing base of the senior credit facility was redetermined to be $44,000,000 and the credit facility was amended to increase its size to $65,000,000 and to extend its term to February 25, 2008. The amended senior credit facility includes a second tranche, which provides for additional term borrowings of up to $15,000,000 to further finance development of the Company’s acreage in the Cotton Valley trend (see “Liquidity and Capital Resources”). On February 25, 2005, $7,500,000 was advanced under the second tranche with the remainder to be advanced in two equal installments of $3,750,000 at the option of the Company and

 

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with the approval of BNP Paribas. Interest on borrowings under the second tranche accrues at a quarterly rate of LIBOR plus 5.0% and principal will be due on February 25, 2008. As of March 24, 2005, the Company’s outstanding borrowings under the senior credit facility were $35,500,000, including $7,500,000 initially advanced under the second tranche.

 

In February 2003, the Company entered into three separate interest rate swaps with BNP Paribas covering a three year period, as further described below, and in February 2004, entered into another interest rate swap with BNP Paribas for an additional one year period (see “Quantitative and Qualitative Disclosures About Market Risk—Debt and debt-related derivatives”).

 

Sale of Oil and Gas Properties to Related Party

 

On March 12, 2002, the Company sold a 30% working interest in the existing production and shallow rights in its Burrwood/West Delta 83 fields, and a 15% working interest in the deep rights below 10,600 feet, in such fields for $12 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 the Company’s Board of Directors at that time, as well as Josiah Austin, who subsequently became a member of the Company’s Board of Directors. Mr. Malloy is currently Chairman of the Company’s Board of Directors and Mr. Appel retired from the Board of Directors in February 2004. The sale price was determined by discounting the present value of the acquired interest in the fields’ proved, probable and possible reserves using prevailing oil and gas prices. The Company retained an approximate 65% working interest in the existing production and shallow rights, and a 32.5% working interest in the deep rights after the close of the transaction. In conjunction with the sale, MEC provided a $7.7 million line of credit which reduced to $5.0 million on January 1, 2003 and expired, according to its terms, on December 31, 2004. MEC was also granted an option to participate on a proportionate cost basis in up to 30% of the Company’s working interests in any acquisitions the Company made in Louisiana on or before December 31, 2004. Pursuant to this option, MEC acquired a 30% working interest in three non-producing field acquisitions made by the Company in Louisiana during 2003 and 2004. Such interests acquired were in the Bethany-Longstreet and Plumb Bob fields in 2003 and in the St. Gabriel field in 2004. In accordance with industry standard joint operating agreements, the Company bills MEC for its share of the capital and operating costs of the three fields on a monthly basis. The Company recorded a non-recurring gain of approximately $2.4 million in the first quarter of 2002 as a result of the MEC sale. The proceeds were used to reduce outstanding debt under its senior credit facility.

 

Contractual Obligations

 

At December 31, 2004, the Company had the following contractual obligations outstanding under its long term debt, production payment and operating lease agreements (as of December 31, 2004, the Company had no material purchase obligations for goods or services that were not incurred in the ordinary course of business):

 

     Total

   2005

   2006-2007

   2008-2009

   After 2009

Long-term debt

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

Production payment

   $ 268,000    $ 268,000    $    $    $

Operating lease obligations

   $ 1,561,000    $ 391,000    $ 730,000    $ 440,000    $

 

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. The Company has prepared its 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

 

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different assumptions or conditions. Application of certain of the Company’s 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 Securities and Exchange Commission (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 the Company’s 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 the Company. The Company cannot predict the types of reserve revisions that will be required in future periods.

 

    Successful efforts accounting—The Company utilizes 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—The Company continually monitors its long-lived assets recorded in Property, Plant and Equipment in the Consolidated Balance Sheet to ensure that they are fairly presented. The Company must evaluate its 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. The Company cannot predict the amount of impairment charges that may be recorded in the future.

 

    Property retirement obligations—The Company is required to make estimates of the future costs of the retirement obligations of its producing oil and gas properties. This requirement necessitates the Company to make estimates of its 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—The Company is subject to income and other related taxes in areas in which it operates. 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 the Company. The Company periodically evaluates its 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 its financial statements. As of December 31, 2004 and in certain prior years, the Company has reported a net deferred tax asset on its 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.

 

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    Derivative Instruments—As discussed in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” the Company periodically utilizes derivative instruments to manage both its commodity price risk and interest rate risk. The Company considers the use of these instruments to be hedging activities. Pursuant to derivative accounting rules, the Company is required to use “mark to market” accounting to reflect the fair value of such derivative instruments on its Consolidated Balance Sheet. To the extent that the Company is able to demonstrate that its 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. To the extent that such derivatives are not deemed to be effective, as was the case in the fourth quarter of 2004 with respect to the Company’s gas hedges, the offsetting entry to the changes in fair value is reflected in earnings.

 

New Accounting Pronouncements

 

Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability must be recorded in the periods in which the obligation meets the definition of a liability, which is generally when the asset is placed in service. As of January 1, 2003, the adoption of SFAS No. 143 resulted in the Company recording a cumulative effect of an accounting change in the amount of $205,000. The estimation of the liability involves the projection of future costs to plug and abandon individual wells. These estimates are based on current costs inflated to the end of the well’s economic life and discounted back to the well’s origination date. The liability will be accreted at the estimated discount rate to the expected cash required to settle the liability. The estimate requires management’s judgment with respect to the future plugging and abandonment costs, the life of the well, and the inflation and discount factors used. Changes in these estimates can significantly impact the amount of the liability.

 

In April 2003, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133, Accounting for Derivatives and Hedging Activities. This statement (1) clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, (2) clarifies when a derivative contains a financing component, and (3) amends the definition of an underlying derivative to conform to Financial Accounting Standards Board Interpretation No. 45. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, with all provisions applied prospectively. The Company adopted SFAS No. 149, effective July 1, 2003, and the adoption had no impact on its financial statements.

 

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify an instrument that is within its scope as a liability. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and is effective at the beginning of the first interim period beginning after June 15, 2003, although in November 2003, the FASB deferred certain provisions of SFAS No. 150. As of December 31, 2003, the Company had no financial instruments within the scope of SFAS No. 150.

 

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment, a revision of SFAS No. 123, Accounting for Stock-Based Compensation. The revised statement is effective for interim or annual reporting periods that begin after June 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 June 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. The Company plans to follow the “modified prospective application” to the adoption of the revised statement and is currently evaluating the potential impact that the adoption of the revised statement will have on its financial statements, beginning in the third quarter of 2005.

 

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Off-Balance Sheet Arrangements

 

The Company does not currently utilize any off-balance sheet arrangements to enhance its liquidity and capital resource positions, or for any other purpose.

 

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk.

 

Commodity Hedging Activity

 

The Company enters into futures contracts or other hedging agreements from time to time to manage the commodity price risk for a portion of its production. The Company considers these to be hedging activities and, as such, monthly settlements on these contracts are reflected in its crude oil and natural gas sales. The Company’s 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 hedge between 30% and 70% of its production. As of December, 31, 2004, all of the commodity hedges utilized by the Company were in the form of fixed price swaps, where the Company receives a fixed price and pays a floating price based on NYMEX quoted prices. As of December 31, 2004, the Company’s open forward position on its outstanding commodity hedging contracts, all of which were with BNP Paribas, was as follows:

 

     1st Qtr 2005

   2nd Qtr 2005

   3rd Qtr 2005

   4th Qtr 2005

     Qty*

   Price

   Qty*

   Price

   Qty*

   Price

   Qty*

   Price

Natural Gas

   6,000    $ 6.27    4,000    $ 6.03    4,000    $ 6.03    4,000    $ 6.03
     2,000      7.70    2,000      6.50    2,000      6.50    2,000      6.70
     2,000      8.14    3,000      6.55    3,000      6.50    3,000      6.75

* Quantity in MMBtu per day.

                                               
     1st Qtr 2005

   2nd Qtr 2005

   3rd Qtr 2005

   4th Qtr 2005

     Qty**

   Price

   Qty**

   Price

   Qty**

   Price

   Qty**

   Price

Crude Oil

   500    $ 33.28    500    $ 35.00    500    $ 34.65    500    $ 34.50
     500      35.73    500      37.18    500      36.18    500      39.20

** Quantity in Barrels per day.

 

The hedging contracts summarized above fall within the Company’s targeted range of 30% to 70% of its 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, 2004 resulted in a liability of $1,834,000. Based on oil and gas pricing in effect at December 31, 2004, a hypothetical 10% increase in oil and gas prices would have increased the liability to $5,519,000 while a hypothetical 10% decrease in oil and gas prices would have decreased the liability to an asset of $1,842,000. Subsequent to December 31, 2004, the Company entered into the following crude oil and natural gas hedging contracts with BNP Paribas:

 

Gas

 

2,000 MMBtu per day “swap” at $6.655 per MMBtu for April 2005 through March 2006

4,000 MMBtu per day “swap” at $7.00 per MMBtu for April 2005 through March 2006

8,000 MMBtu per day “swap” at $7.1825 per MMBtu for January 2006 through March 2006

4,000 MMBtu per day “swap” at $6.665 per MMBtu for April 2005 through December 2006

 

Oil

 

300 barrels per day “swap” at $45.80 per barrel for January 2006 through March 2006

400 barrels per day “swap” at $48.71 per barrel for April 2006 through December 2006

 

30


Table of Contents

Price Fluctuations and the Volatile Nature of Markets

 

Despite the measures taken by the Company to attempt to control price risk, the Company remains 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 the Company’s control. Domestic crude oil and gas prices could have a material adverse effect on the Company’s financial position, results of operations and quantities of reserves recoverable on an economic basis.

 

Debt and Debt-Related Derivatives

 

In February 2003, the Company entered into three separate interest rate swaps with BNP Paribas covering a three year period (two of the contracts have now expired). The first interest rate swap, which had an effective date of February 26, 2003, expired on its maturity date of February 26, 2004, and was for $18,000,000 with a LIBOR swap rate of 1.53%. The second interest rate swap, which had an effective date of February 26, 2004, expired on its maturity date of November 8, 2004, and was for $18,000,000 with a LIBOR swap rate of 2.25%. The third interest rate swap, which has an effective date of November 8, 2004 and a maturity date of February 26, 2006, is for $18,000,000 with a LIBOR swap rate of 3.46%. In February 2004, the Company entered into a fourth interest rate swap contract with BNP Paribas, which has an effective date of February 26, 2006 and a maturity date of February 26, 2007, is for $23,000,000 with a LIBOR swap rate of 4.08%. The fair value of the interest rate swap contracts in place at December 31, 2004 resulted in a liability of $162,000. Based on interest rates at December 31, 2004, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the liability.

 

Disclosure Regarding Forward-Looking Statement

 

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, the Company’s financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. 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 the Company’s 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 the Company or persons acting on its behalf are expressly qualified in their entirety by such factors.

 

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Table of Contents

Item 8.    Financial Statements and Supplementary Data.

 

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, 2004 and 2003, 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, 2004. 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, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, 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.

 

KPMG LLP

 

Shreveport, Louisiana

March 24, 2005

 

 

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Table of Contents

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

 

     December 31,
2004


    December 31,
2003


 
ASSETS             

CURRENT ASSETS

                

Cash and cash equivalents

   $ 3,449,210     $ 1,488,852  

Cash held temporarily for stockholders

           3,886,988  

Accounts receivable

                

Trade and other, net of allowance

     7,183,356       3,500,095  

Accrued oil and gas revenue

     3,121,932       2,829,082  

Prepaid insurance and other

     631,472       351,527  
    


 


Total current assets

     14,385,970       12,056,544  
    


 


PROPERTY AND EQUIPMENT

                

Oil and gas properties (successful efforts method)

     159,903,454       118,682,309  

Furniture, fixtures and equipment

     821,236       661,842  
    


 


       160,724,690       119,344,151  

Less accumulated depletion, depreciation, and amortization

     (51,319,998 )     (44,381,223 )
    


 


Net property equipment

     109,404,692       74,962,928  
    


 


OTHER ASSETS

                

Restricted cash and investments

     2,039,000       2,039,000  

Deferred taxes

     2,070,000        

Other

     77,418       124,096  
    


 


Total other assets

     4,186,418       2,163,096  
    


 


TOTAL ASSETS

   $ 127,977,080     $ 89,182,568  
    


 


LIABILITIES AND STOCKHOLDERS’ EQUITY             

CURRENT LIABILITIES

                

Accounts payable

   $ 23,352,051     $ 6,707,583  

Accrued liabilities

     3,214,103       1,483,329  

Liability for funds held temporarily for stockholders

           3,886,988  

Fair value of oil and gas derivatives

     1,834,195       1,257,442  

Fair value of interest rate derivatives

     144,042       142,515  

Current portion of other non-current liabilities

     91,605       91,600  
    


 


Total current liabilities

     28,635,996       13,569,457  

LONG TERM DEBT

     27,000,000       20,000,000  

OTHER NON-CURRENT LIABILITIES

                

Accrued abandonment costs

     6,718,895       6,509,586  

Production payment payable and other

     296,960       704,643  

Fair value of interest rate derivatives

     17,925       135,423  

Deferred taxes

           204,465  
    


 


Total liabilities

     62,669,776       41,123,574  
    


 


STOCKHOLDERS’ EQUITY

                

Preferred stock; authorized 10,000,000 shares:

                

Series A convertible preferred stock; par value $1.00 per share; issued and outstanding 791,968 shares (liquidation preference $10.00 per share, aggregating to $7,919,680)

     791,968       791,968  

Common stock; authorized 50,000,000 shares; par value $0.20 per share:

                

Issued and outstanding, 20,587,074 and 18,130,011 shares, respectively

     4,117,414       3,626,002  

Additional paid-in capital

     55,408,587       53,359,023  

Retained earnings (deficit)

     9,555,977       (8,338,403 )

Unamortized restricted stock awards

     (1,762,001 )     (381,598 )

Accumulated other comprehensive income (loss)

     (2,804,641 )     (997,998 )
    


 


Total stockholders’ equity

     65,307,304       48,058,994  
    


 


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

   $ 127,977,080     $ 89,182,568  
    


 


 

See notes to consolidated financial statements

 

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Table of Contents

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF OPERATIONS

 

     Year Ended December 31,

 
     2004

    2003

    2002

 

REVENUES

                        

Oil and gas revenues

   $ 44,861,110     $ 31,663,345     $ 18,502,426  

Unrealized gain on derivatives

     2,317,295              

Other

     151,192       476,879       130,702  
    


 


 


Total revenues

     47,329,597       32,140,224       18,633,128  
    


 


 


EXPENSES

                        

Lease operating expense

     7,402,353       6,098,673       7,523,425  

Production taxes

     3,105,426       2,287,648       1,641,549  

Depletion, depreciation and amortization

     11,562,234       8,995,632       7,023,462  

Exploration

     4,426,010       2,248,802       1,019,180  

Impairment of oil and gas properties

           335,558       342,079  

General and administrative

     5,820,920       5,314,487       4,467,641  

Interest expense

     1,109,902       1,051,198       985,185  
    


 


 


Total costs and expenses

     33,426,845       26,331,998       23,002,521  
    


 


 


GAIN (LOSS) ON SALE OF ASSETS AND LITIGATION JUDGMENT

     2,168,440       (66,116 )     2,941,062  
    


 


 


INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

     16,071,192       5,742,110       (1,428,331 )

Income taxes

     (1,706,626 )     2,015,464       (496,498 )
    


 


 


NET INCOME (LOSS) FROM CONTINUING OPERATIONS

     17,777,818       3,726,646       (931,833 )

DISCONTINUED OPERATIONS INCLUDING GAIN ON SALE, NET OF INCOME TAXES

     749,533       196,144       (18,884 )
    


 


 


NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT

     18,527,351       3,922,790       (950,717 )

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF INCOME TAXES

           (205,293 )      
    


 


 


NET INCOME (LOSS)

     18,527,351       3,717,497       (950,717 )

Preferred stock dividends

     632,971       633,463       639,753  
    


 


 


NET INCOME (LOSS) APPLICABLE TO COMMON STOCK

   $ 17,894,380     $ 3,084,034     $ (1,590,470 )
    


 


 


NET INCOME (LOSS) PER COMMON SHARE—BASIC

                        

NET INCOME (LOSS) FROM CONTINUING OPERATIONS

   $ 0.91     $ 0.21     $ (0.05 )

DISCONTINUED OPERATIONS

     0.04       0.01       (0.00 )
    


 


 


NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT

     0.95       0.22       (0.05 )

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING

           (0.01 )      
    


 


 


NET INCOME (LOSS)

     0.95       0.21       (0.05 )
    


 


 


NET INCOME (LOSS) APPLICABLE TO COMMON STOCK

   $ 0.92     $ 0.17     $ (0.09 )
    


 


 


NET INCOME (LOSS) PER COMMON SHARE—DILUTED

                        

NET INCOME (LOSS) FROM CONTINUING OPERATIONS

   $ 0.87     $ 0.18     $ (0.05 )

DISCONTINUED OPERATIONS

     0.04       0.01       (0.00 )
    


 


 


NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT

     0.91       0.19       (0.05 )

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING

           (0.01 )      
    


 


 


NET INCOME (LOSS)

   $ 0.91     $ 0.18     $ (0.05 )
    


 


 


NET INCOME (LOSS) APPLICABLE TO COMMON STOCK

   $ 0.88     $ 0.15     $ (0.09 )
    


 


 


AVERAGE COMMON SHARES OUTSTANDING—BASIC

     19,551,516       18,064,329       17,908,182  

AVERAGE COMMON SHARES OUTSTANDING—DILUTED

     20,346,985       20,481,800       17,908,182  

 

See notes to consolidated financial statements

 

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     Year Ended December 31,

 
     2004

    2003

    2002

 

OPERATING ACTIVITIES

                        

Net income (loss)

   $ 18,527,351     $ 3,717,497     $ (950,717 )

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

                        

Depletion, depreciation and amortization

     11,562,234       8,995,632       7,023,462  

Unrealized gain on derivatives

     (2,317,295 )            

Deferred income taxes

     (1,303,031 )     1,904,922       (496,498 )

Dry hole costs

           815,593        

Amortization of leasehold costs

     1,035,300       473,556       351,719  

Impairment of oil and gas properties

           335,558       342,079  

Non-cash charge for stock issued for cancelled options

           403,006        

Cumulative effect of change in accounting principle

           315,835        

(Gain) Loss on sale of asset

     (814,621 )     66,116       (2,941,062 )

Non-cash effect of discontinued operations, net

     155,392       185,414       229,284  

Other non-cash items

     63,879       353,824       202,008  

Net change in:

                        

Accounts receivable

     (3,976,112 )     (75,969 )     (1,971,405 )

Prepaid insurance and other

     (279,947 )     (142,209 )     (839,678 )

Accounts payable

     16,644,470       (219,575 )     4,528,721  

Accrued liabilities

     1,730,775       (81,254 )     (129,091 )
    


 


 


Net cash provided by operating activities

     41,028,395       17,047,946       5,348,822  
    


 


 


INVESTING ACTIVITIES

                        

Capital expenditures

     (47,501,173 )     (19,898,363 )     (8,079,463 )

Proceeds from sales of assets

     2,087,426       398,599       12,822,591  
    


 


 


Net cash provided by (used in) investing activities

     (45,413,747 )     (19,499,76 )     4,743,128  
    


 


 


FINANCING ACTIVITIES

                        

Principal payments of bank borrowings

     (1,000,000 )     (1,600,000 )     (13,500,000 )

Net proceeds from bank borrowings

     8,000,000       3,100,000       7,500,000  

Exercise of stock options and warrants

     340,087       128,887       28,000  

Production payments

     (361,406 )     (406,134 )     (377,518 )

Preferred stock dividends

     (632,971 )     (633,463 )     (639,753 )
    


 


 


Net cash provided by (used in) financing activities

     6,345,710       589,290       (6,989,271 )
    


 


 


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     1,960,358       (1,862,528 )     3,102,679  

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD

     1,488,852       3,351,380       248,701  
    


 


 


CASH AND CASH EQUIVALENTS AT END OF PERIOD

   $ 3,449,210       1,488,852     $ 3,351,380  
    


 


 


 

See notes to consolidated financial statements

 

 

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Table of Contents

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND OTHER COMPREHENSIVE INCOME

 

Years Ended December 31, 2004, 2003 and 2002

 

   

Series A
Preferred Stock


  Common Stock

  Additional
Paid-In
Capital


    Retained
Earnings
(Deficit)


    Unamortized
Restricted
Stock
Awards


    Accumulated
Other
Comprehensive
Income (Loss)


    Total
Stockholders’
Equity


 
    Shares

  Amount

  Shares

  Amount

         

Balance at January 1, 2002

  791,968   $ 791,968   17,896,356   $ 3,579,271   $ 52,279,331     $ (9,831,967 )   $     $ 8,451     $ 46,827,054  
   
 

 
 

 


 


 


 


 


Net Loss

                                (950,717 )                     (950,717 )

Other Comprehensive Income (Loss)

                                                           

Change in fair value of derivatives; net of tax of $724,642

                                                (1,345,763 )     (1,345,763 )

Reclassification Adjustment, net of tax of $354,425

                                                658,218       658,218  
                                                       


Total Comprehensive Loss

                                                        (1,638,262 )

Preferred Stock Dividends

                                (639,753 )                     (639,753 )

Exercise of Stock Options and Warrants

            10,667     2,133     25,867                               28,000  

Director Stock Grants

            7,302     1,460     28,540                               30,000  
   
 

 
 

 


 


 


 


 


Balance at December 31, 2002

  791,968     791,968   17,914,325     3,582,864     52,333,738       (11,422,437 )           (679,094 )     44,607,039  
   
 

 
 

 


 


 


 


 


Net Income

                                3,717,497                       3,717,497  

Other Comprehensive Income (Loss)

                                                           

Change in fair value of derivatives; net of tax of $1,204,397

                                                (2,236,739 )     (2,236,739 )

Reclassification Adjustment, net of tax of $1,032,680

                                                1,917,835       1,917,835  
                                                       


Total Comprehensive Income

                                                        3,398,593  

Issuance of Common Stock for Cancelled Stock Options

            125,157     25,032     377,974                               403,006  

Issuance and Amortization of Restricted Stock

                        536,530               (381,598 )             154,932  

Preferred Stock Dividends

                                (633,463 )                     (633,463 )

Exercise of Stock Options and Warrants

            90,529     18,106     110,781                               128,887  
   
 

 
 

 


 


 


 


 


Balance at December 31, 2003

  791,968     791,968   18,130,011     3,626,002     53,359,023       (8,338,403 )     (381,598 )     (997,998 )     48,058,994  
   
 

 
 

 


 


 


 


 


Net Income

                                18,527,351                       18,527,351  

Other Comprehensive Income (Loss)

                                                           

Change in fair value of derivatives; net of tax of $3,180,013

                                                (5,908,747 )     (5,908,747 )

Reclassification Adjustment, net of tax of $2,208,825

                                                4,102,104       4,102,104  
                                                       


Total Comprehensive Income

                                                        16,720,708  

Issuance and Amortization of Restricted Stock

            52,343     10,468     1,950,421               (1,380,403 )             580,486  

Preferred Stock Dividends

                                (632,971 )                     (632,971 )

Exercise of Stock Options and Warrants

            2,375,592     475,118     (135,031 )                             340,087  

Director Stock Grants

            29,128     5,826     234,174                               240,000  
   
 

 
 

 


 


 


 


 


Balance at December 31, 2004

  791,968   $ 791,968   20,587,074   $ 4,117,414   $ 55,408,587     $ 9,555,977     $ (1,762,001 )   $ (2,804,641 )   $ 65,307,304  
   
 

 
 

 


 


 


 


 


 

See notes to consolidated financial statements

 

36


Table of Contents

GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

December 31, 2004

 

NOTE A—Description of Business

 

The Company is in the primary business of exploration and production of crude oil and natural gas. The Company’s subsidiaries have interests in such operations in four 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.

 

Revenue Recognition—Revenues from the production of crude oil and natural gas properties in which the Company has an interest with other producers are recognized on the entitlements method. The Company records an asset or liability for natural gas balancing when the Company has purchased or sold more than its working interest share of natural gas production, respectively. At December 31, 2004 and 2003, the assets and liabilities for gas balancing were immaterial. Differences between actual production and net working interest volumes are routinely adjusted. These differences are not significant.

 

Property and Equipment—The Company uses 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.

 

The Company recognizes 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. The Company performs this comparison for its oil and gas properties on a field-by-field basis using the Company’s 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. The Company recorded such impairments in 2004, 2003 and 2002 in the amounts of $-0-, $336,000 and $342,000 respectively. The impairments were generally the result of certain non-core fields depleting earlier than anticipated.

 

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 elsewhere in Note B, the Company adopted SFAS No. 143 on January 1, 2003. Under SFAS No. 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 No. 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 the Company’s engineers using existing regulatory requirements and anticipated future inflation rates.

 

37


Table of Contents

GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

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.

 

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.

 

Income Taxes—The Company follows the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes, 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—The Company utilizes derivative instruments such as futures, forwards, options, collars and swaps for purposes of hedging its exposure to fluctuations in the price of crude oil and natural gas and to hedge its exposure to changing interest rates.

 

Effective January 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138. See also Note I for further information about the Company’s derivative instruments. In accordance with the transition provisions of SFAS No. 133, the Company recorded a cumulative adjustment of $2,535,000 (net of $1,365,000 in income taxes) in accumulated other comprehensive income to recognize at fair value all derivatives that were designated as cash flow hedging instruments. There was no cumulative effect on earnings. The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheet. Upon entering into a derivative contract, the Company 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 the contract to market through earnings. The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items, as well as its 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. The Company assesses 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.

 

38


Table of Contents

GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

Ineffective portions of a cash flow hedging derivative’s change in fair value are recognized currently in earnings as oil and gas revenues. 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.

 

Stock Based Compensation—While SFAS No. 123, Accounting for Stock-Based Compensation, 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, 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 No. 123 had been applied. Until the effective date of SFAS No. 123R as noted below (see “New Accounting Pronouncements”), the Company has elected to continue to apply the provisions of APB Opinion No. 25 and provide the disclosure provisions of SFAS No. 123. For stock based compensation that vests on a prorata basis where the award is fixed at the grant date, the Company has elected to amortize those costs using straight line method over the life of the award.

 

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

 

     2004

    2003

    2002

 

Net income (loss)

                        

As reported

   $ 18,527,351     $ 3,717,497     $ (950,717 )

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

     579,433       154,932        

Stock based compensation expense at fair value, net of tax

     (609,794 )     (195,878 )     (947,097 )
    


 


 


Pro forma

   $ 18,496,990     $ 3,676,551     $ (1,897,814 )
    


 


 


Net income (loss) applicable to common stock

                        

As reported

   $ 17,894,380     $ 3,084,034     $ (1,590,470 )

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

     579,433       154,932        

Stock based compensation expense at fair value, net of tax

     (609,794 )     (195,878 )     (947,097 )
    


 


 


Pro forma

   $ 17,864,019     $ 3,043,088     $ (2,537,567 )
    


 


 


Net income (loss) per share

                        

As reported, basic

   $ 0.95     $ 0.17     $ (0.09 )

Pro forma, basic

     0.95       0.17       (0.14 )

As reported, diluted

     0.91       0.15       (0.09 )

Pro forma, diluted

     0.91       0.15       (0.14 )

 

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.

 

39


Table of Contents

GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

Use of Estimates—Management of the Company 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.

 

New Accounting Pronouncements—Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability must be recorded in the periods in which the obligation meets the definition of a liability, which is generally when the asset is placed in service. Prior to the adoption of SFAS No. 143, the Company recorded liabilities for the abandonment of oil and gas properties only in its two largest fields, with such liabilities amounting to $4,881,000 as of December 31, 2002. In accordance with the transition provisions of SFAS No. 143, the Company recorded an adjustment to recognize additional estimated liabilities for the abandonment of oil and gas properties, as of January 1, 2003, in the amount of $1,408,000, and additional oil and gas properties, net of accumulated depletion, depreciation and amortization, in the amount of $1,092,000. To recognize the cumulative effect of this change in accounting principle, the Company recorded a charge to earnings as of January 1, 2003 in the amount of $205,000, reflecting the $316,000 difference between the adjustments to the liability and asset accounts, net of the related income tax effect. Any subsequent difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability will be recognized as a gain or loss in the Company’s earnings. For the years ended December 31, 2004 and 2003, the Company recorded the following activity in the abandonment liability:

 

     Year ended December 31,

 
     2004

    2003

 

Beginning balance

   $ 6,601,186     $ 6,289,065  

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

     326,625       283,992  

Liability for newly added wells

     388,808       452,786  

Abandonment costs incurred or sold

     (506,119 )     (424,657 )
    


 


Ending balance

     6,810,500       6,601,186  

Less: current portion

     (91,605 )     (91,600 )
    


 


     $ 6,718,895     $ 6,509,586  
    


 


 

The pro forma accrued abandonment costs as of January 1, 2002 were $5,933,000. The pro forma net loss for the year ended December 31, 2002, assuming SFAS No. 143 had been applied retroactively, was $1,814,000 ($0.10 per share).

 

In April 2003, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133, Accounting for Derivatives and Hedging Activities. This statement (1) clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, (2) clarifies when a derivative contains a financing component, and (3) amends the definition of an underlying derivative to conform to Financial Accounting Standards Board Interpretation No. 45. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, with all provisions applied prospectively. The Company adopted SFAS No. 149, effective July 1, 2003, and the adoption had no impact on its financial statements.

 

40


Table of Contents

GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify an instrument that is within its scope as a liability. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and is effective at the beginning of the first interim period beginning after June 15, 2003, although in November 2003, the FASB deferred certain provisions of SFAS No. 150. As of December 31, 2004, the Company had no financial instruments within the scope of SFAS No. 150.

 

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment, a revision of SFAS No. 123, Accounting for Stock-Based Compensation. The revised statement is effective for interim or annual reporting periods that begin after June 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 June 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. The Company plans to follow the “modified prospective application” to the adoption of the revised statement and is currently evaluating the potential impact that the adoption of the revised statement will have on its financial statements, beginning in the third quarter of 2005.

 

NOTE C—Sale of Oil and Gas Properties to Related Party

 

On March 12, 2002, the Company sold a 30% working interest in the existing production and shallow rights in its Burrwood and West Delta 83 fields, and a 15% working interest in the deep rights below 10,600 feet, for $12 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 the Company’s Board of Directors at that time, as well as Josiah Austin, who subsequently became a member of the Company’s Board of Directors. Mr. Malloy is now Chairman of the Company’s Board of Directors and Mr. Appel retired from the Board of Directors in February 2004. The sale price was determined by discounting the present value of the acquired interest in the fields’ proved, probable and possible reserves using prevailing oil and gas prices. The Company retained an approximate 65% working interest in the existing production and shallow rights, and a 32.5% working interest in the deep rights after the close of the transaction. In conjunction with the sale, MEC provided a $7.7 million line of credit which reduced to $5.0 million on January 1, 2003 and expired, according to its terms, on December 31, 2004. MEC was also granted an option to participate on a proportionate cost basis in up to 30% of the Company’s working interests in any acquisitions the Company made in Louisiana on or before December 31, 2004. Pursuant to this option, MEC acquired a 30% working interest in three non-producing field acquisitions made by the Company in Louisiana during 2003 and 2004. Such interests acquired were in the Bethany-Longstreet and Plumb Bob fields in 2003 and in the St. Gabriel field in 2004. In accordance with industry standard joint operating agreements, the Company bills MEC for its share of the capital and operating costs of the three fields on a monthly basis (see Note M).

 

The Company recorded a non-recurring gain of approximately $2.4 million in the first quarter of 2002 as a result of the MEC sale. The proceeds were used to reduce outstanding debt under its senior credit facility.

 

41


Table of Contents

GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

NOTE D—Indebtedness

 

Indebtedness at December 31, 2004 and 2003 consists of the following:

 

     2004

   2003

Bank Debt

             

Borrowings under senior credit facility, interest at BNP Paribas prime plus 0.25% or LIBOR plus 2.0% (weighted average rate at December 31, 2004—4.1%).

   $ 27,000,000    $ 20,000,000

Less current portion

         
    

  

Long-term debt excluding current portion

   $ 27,000,000    $ 20,000,000
    

  

 

On November 9, 2001, the Company established a $50,000,000 senior credit facility with BNP Paribas, with an initial borrowing base of $25,000,000 and a three year term. In December 2003, the borrowing base was redetermined to be $28,000,000 and BNP Paribas and the Company agreed to extend the term of the senior credit facility to December 29, 2006, subject to periodic redeterminations of the borrowing base. In August 2004, the borrowing base was redetermined to be $32,000,000. Borrowings outstanding under the senior credit facility were $27,000,000 as of December 31, 2004. Interest on borrowings accrues at a rate calculated, at the option of the Company, as either the BNP Paribas base rate plus 0.00% to 0.50%, or LIBOR plus 1.50%—2.50%, depending on borrowing base utilization. Interest on LIBOR-rate borrowings is due and payable on the last day of its respective interest period. Accrued interest on each base-rate borrowing is due and payable on the last day of each quarter. The credit facility requires that the Company pay a 0.375% per annum commitment fee, payable in quarterly installments based on the Company’s borrowing base utilization. Prior to maturity, no principal payments are required so long as the maximum borrowing base amount exceeds the amounts outstanding under the credit facility. The credit facility precludes the payment of dividends on the Company’s common stock and requires the Company to maintain a working capital ratio (as defined) of not less than 1.0:1.0, an interest coverage ratio for the trailing four quarters of at least 3.0 times, and a tangible net worth of not less than the sum of $53,392,838, plus 50% of the Company’s cumulative net income after September 30, 2004, plus 100% of the net proceeds of any equity issuance by the Company after September 30, 2004. As of December 31, 2004, the Company was in compliance with all such requirements. Substantially all the Company’s assets are pledged to secure the senior credit facility.

 

In February 2005, the borrowing base of the senior credit facility was redetermined to be $44,000,000 and the credit facility was amended to increase its size to $65,000,000 and to extend its term to February 25, 2008. The amended senior credit facility includes a second tranche, which provides for additional term borrowings of up to $15,000,000 to further finance development of the Company’s acreage in the Cotton Valley trend of East Texas and Northwest Louisiana. On February 25, 2005, $7,500,000 was advanced under the second tranche with the remainder to be advanced in two equal installments of $3,750,000 at the option of the Company and with the approval of BNP Paribas. Interest on borrowings under the second tranche accrues at a quarterly rate of LIBOR plus 5.0% and principal will be due on February 25, 2008. As of March 24, 2005, the Company’s outstanding borrowings under the senior credit facility were $35,500,000, including $7,500,000 initially advanced under the second tranche.

 

42


Table of Contents

GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

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, 2004, 2003 and 2002. The following table reconciles the weighted average shares outstanding used for these computations.

 

     Year ended December 31,

     2004

   2003

   2002

Basic Method

   19,551,516    18,064,329    17,908,182

Stock Warrants

   478,617    2,364,049   

Stock Options and Restricted Stock

   316,852    53,422   
    
  
  

Dilutive Method

   20,346,985    20,481,800    17,908,182
    
  
  

 

The computation of earnings per share for the three years ended December 31, 2004 considered exercisable stock warrants, stock options and restricted stock to the extent that the exercise of such securities would have been dilutive under the treasury stock method, however, such computation did not consider preferred stock which is convertible into shares of common stock because the effect of such conversion would have been antidilutive. 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 (see Note H).

 

NOTE F—Income Taxes

 

Income tax expense (benefit) for the years ending December 31, 2004, 2003 and 2002 consists of:

 

     Current

   Deferred

    Total

 

Year ended December 31, 2004

                       

U.S. Federal

   $    $ (1,303,030 )   $ (1,303,030 )

State

                 
    

  


 


     $    $ (1,303,030 )   $ (1,303,030 )
    

  


 


Year ended December 31, 2003

                       

U.S. Federal

   $    $ 2,121,080     $ 2,121,080  

State

                 
    

  


 


     $    $ 2,121,080     $ 2,121,080  
    

  


 


Year ended December 31, 2002

                       

U.S. Federal

   $    $ (506,666 )   $ (506,666 )

State

                 
    

  


 


     $    $ (506,666 )   $ (506,666 )
    

  


 


 

43


Table of Contents

GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

The following is a reconciliation of the U.S. statutory income tax rate at 35% to the Company’s income (loss) before income taxes for the years ended December 31, 2004, 2003 and 2002:

 

     2004

    2003

   2002

 

Income (Loss) from Continuing Operations

                       

Tax at U.S. statutory income tax

   $ 5,624,920     $ 2,009,739    $ (499,916 )

Nondeductible expense

     5,955       5,725      3,418  

Valuation allowance and other

     (7,337,500 )           
    


 

  


       (1,706,625 )     2,015,464      (496,498 )
    


 

  


Income (Loss) from Discontinued Operations

                       

Tax at U.S. statutory income tax

     403,595       105,616      (10,168 )
    


 

  


Total tax (benefit) expense

   $ (1,303,030 )   $ 2,121,080    $ (506,666 )
    


 

  


 

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2004 and 2003 are presented below.

 

     2004

    2003

 

Deferred tax assets:

                

Differences between book and tax basis of:

                

Operating loss carryforwards

   $ 14,188,704     $ 14,045,530  

Statutory depletion carryforward

     7,034,566       7,034,566  

AMT Tax credit carryforward

     1,399,890       1,399,890  

Derivative financial instruments

     698,657       537,383  

Contingent liabilities

     45,566       45,566  

Other

     347,676       347,676  
    


 


Total gross deferred tax assets

     23,715,059       23,410,611  

Less valuation allowance

     (12,648,106 )     (20,351,605 )
    


 


Net deferred tax asset

     11,066,953       3,059,006  
    


 


Deferred tax liabilities:

                

Differences between book and tax basis of:

                

Property and equipment

     (8,996,953 )     (3,263,471 )
    


 


Total gross deferred tax liability

     (8,996,953 )     (3,263,471 )
    


 


Net deferred tax asset (liability)

   $ 2,070,000     $ (204,465 )
    


 


 

The Company revised its deferred tax valuation allowance in the year ended December 31, 2004 based on the anticipated utilization of tax operating loss carryforwards and projected reversal of temporary differences. 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 those 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 the Company will

 

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GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

realize the benefits of these deductible differences, net of the existing valuation allowance at December 31, 2004. The amount of the deferred tax assets considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.

 

The following table summarizes the amounts and expiration dates of operating loss carryforwards:

 

Operating loss carryforwards


Expires


   Amounts

 2006

   $ 3,453,895

 2007

     8,860,622

 2008

     4,285,746

 2009

     3,247,494

 2010

     6,450,859

 2011

     600,706

 2012

     1,939,496

 2018

     4,530,029

 2019

     2,546,445

 2020

     372,409

 2021

     1,750

 2022

     3,699,248

 2024

     550,454
    

     $ 40,539,153
    

 

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 $1,682,797. The IRC (S)382 annual limitation for the ownership change in August 2000 is $3,647,700. 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 $3,647,700 less the annual amount utilized for pre-August 1995 NOLs. It should be noted that the same IRC (S)382 limitations apply to the alternative minimum tax net operating loss carryforwards, depletion carryforwards, and alternative minimum tax credit carryforwards. The minimum tax credit carryforward (MTC) of $1,399,890 as of December 31, 2004, 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

 

A production payment was entered into by the Company to assist in the financing of the Lafitte field acquisition in September 1999. The original amount of the production payment obligation was $2,940,000, which was recorded as a production payment liability of $2,228,000 after a discount to reflect an effective rate of interest of 11.25%. At December 31, 2004 the remaining principal amount was $438,000 and the recorded liability was $268,000. Under the terms of the production payment the Company must make monthly cash payments which approximate 10% of the Company’s 49% working interest share of the monthly gross oil and gas revenue of the Lafitte field.

 

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GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

The Company’s estimate as of December 31, 2004, based on projected production volumes and prices and expected discount amortization, is that projected payments could liquidate the liability in the year ended December 31, 2005, however, the Company has not reflected such a current classification due to the inherent imprecision in its production projections as well as the fact that the source of repayment is a non-current asset.

 

NOTE H—Stockholders’ Equity

 

Common Stock—At December 31, 2004, a total of 1,272,252 unissued shares of Goodrich common stock were reserved for the following: (a) 531,502 shares for the exercise of stock warrants; (b) 410,500 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.

 

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, and is convertible at the option of the holder at any time, unless earlier redeemed, into shares of common stock of the Company at an initial conversion rate of .417 shares of common stock per share of Series A preferred. The Series A preferred stock also will automatically convert to common stock if the closing price for the Series A preferred stock exceeds $15.00 per share for ten consecutive trading days. The Series A preferred stock is redeemable in whole or in part, at $12.00 per share, plus accrued and unpaid dividends. Dividends on the Series A preferred stock accrue at an annual rate of 8% and are cumulative.

 

The Series B convertible preferred stock, which ranked junior to the Series A preferred stock, was entirely converted into common stock in 2001 and no such shares are outstanding.

 

Stock Option and Incentive Programs—Goodrich currently has two plans, which provide for stock option and other incentive awards for the Company’s key employees, consultants and directors. The Goodrich Petroleum Corporation 1995 Stock Option Plan allows the Board of Directors to grant 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. The Goodrich Petroleum Corporation 1997 Director Compensation Plan provides for the grant of stock and options to each director who is not and has never been an employee of the Company.

 

The Goodrich plans authorize grants of options to purchase up to a combined total of 2,300,000 shares of authorized but unissued common stock. Stock options are generally 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 have ten year terms and three year pro rata vesting.

 

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GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

The per share weighted average fair value of stock options granted during the years ended December 31, 2004 and 2002 were $7.96 and $2.43, 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 46% in 2004 and 35% in 2002, and (d) an expected life of 5 years; There were no employee stock options granted in the year ended December 31, 2003. Stock option transactions during 2004, 2003 and 2002 were as follows:

 

     Number of
Options


    Weighted
Average
Exercise
Price


  

Range of
Exercise Price


   Weighted
Average
Remaining
Contractual
Life


Outstanding, January 1, 2002

   1,469,062            $0.75 to $18.00    8.7 yrs
    

               

Granted—1995 Stock Option Plan

   63,000     $ 3.72          

Granted—1997 Director Compensation Plan

   24,000       4.11          

Exercised—1995 Stock Option Plan

   (10,677 )     2.63          

Expiration of Options

   (5,333 )     2.63          
    

               

Outstanding, December 31, 2002

   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          

Expiration of Options

                    
    

               

Outstanding, December 31, 2004

   410,500            $0.75 to $16.46    8.5 yrs
    

               

Exercisable, December 31, 2002

   768,917     $ 5.34          

Exercisable, December 31, 2003

   194,813       3.03          

Exercisable, December 31, 2004

   169,500       3.20          

 

In February 2003, the Company issued 125,157 shares of its 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 the Company’s common stock at the time of the exchange, the Company recorded a non-cash charge to earnings in February 2003 in the amount of $403,000 related to the issuance of shares in lieu of cancelled options. At the same time, the Company commenced granting a series of restricted share awards, with three year vesting periods, to its employees under a stockholder approved equity compensation plan. Based on the value of the Company’s common stock at the time of the grants, those awards resulted in charges to a contra equity account and credits to additional paid-in capital in the following amounts:

 

    $483,000 for 150,000 restricted share awards granted in February 2003;

 

    $54,000 for 11,500 restricted share awards granted in July and October 2003;

 

    $1,147,000 for 166,300 restricted share awards granted in February 2004;

 

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GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

    $209,100 for 19,500 restricted share awards granted in July through September 2004; and

 

    $762,500 for 52,950 restricted share awards granted in December 2004

 

The charges to the contra equity account are being amortized to earnings as non-cash charges to general and administrative expenses over the three year vesting period of each restricted share award and resulted in non-cash charges to earnings of $580,000 and $155,000 in the years ended December 31, 2004 and 2003, respectively. In the year ended December 31, 2004, the Company recorded a credit to the contra equity account and a charge to additional paid-in capital in the amount of $157,000 for the value of 28,918 non-vested restricted share awards that were forfeited by terminated employees. The amortization to earnings of restricted share awards has been adjusted to reflect such forfeitures. Assuming no additional restricted share awards or forfeitures, the Company will be required to record recurring non-cash charges to earnings of approximately $209,000 per quarter, related to the periodic vesting of the restricted share awards that have been issued to date.

 

NOTE I—Hedging Activities

 

Commodity Hedging Activity

 

The Company enters into swap contracts or other hedging agreements from time to time to manage the commodity price risk for a portion of its production. The Company considers these to be hedging activities and, as such, monthly settlements on these contracts are reflected in its crude oil and natural gas sales. The Company’s 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 hedge between 30% and 70% of its production. As of December, 31, 2004, all of the commodity hedges utilized by the Company were in the form of fixed price swaps, where the Company receives a fixed price and pays a floating price based on NYMEX quoted prices. Hedge ineffectiveness results from differences in the NYMEX contract terms and the physical location, grade and quality of the Company’s oil and gas production. As of December 31, 2004, the Company’s open forward position on its outstanding commodity hedging contracts, all of which were with BNP Paribas, was as follows:

 

     1st Qtr 2005

   2nd Qtr 2005

   3rd Qtr 2005

   4th Qtr 2005

     Qty*

   Price

   Qty*

   Price

   Qty*

   Price

   Qty*

   Price

Natural Gas

   6,000    $ 6.27    4,000    $ 6.03    4,000    $ 6.03    4,000    $ 6.03
     2,000      7.70    2,000      6.50    2,000      6.50    2,000      6.70
     2,000      8.14    3,000      6.55    3,000      6.50    3,000      6.75

* Quantity in MMBtu per day

 

                                               
     1st Qtr 2005

   2nd Qtr 2005

   3rd Qtr 2005

   4th Qtr 2005

     Qty**

   Price

   Qty**

   Price

   Qty**

   Price

   Qty**

   Price

Crude Oil

   500    $ 33.28    500    $ 35.00    500    $ 34.65    500    $ 34.50
     500      35.73    500      37.18    500      36.18    500      39.20

** Quantity in Barrels per day.

 

The hedging contracts summarized above are based on floating NYMEX contract prices and fall within the Company’s targeted range of 30% to 70% of its 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, 2004 resulted in a net liability of $1,834,000. As of December 31, 2004, $3,148,000 (net of $1,695,000 in income taxes) of deferred losses on derivative instruments accumulated in other comprehensive income are expected to

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

be reclassified into earnings during the next twelve months. In the year ended December 31, 2004, $4,008,000 of previously deferred losses (net of $2,158,000 in income taxes) was reclassified from accumulated other comprehensive income to oil and gas sales as the cash flow of the hedged items was recognized. In the year ended December 31, 2004, the Company recognized in earnings an unrealized gain on derivative instruments in the amount of $2,317,000. This gain was recognized because the Company’s natural gas hedges were deemed to be ineffective for the fourth quarter of 2004, accordingly, the changes in fair value of such hedges could no longer be reflected in other comprehensive income. For the year ended December 31, 2003, the Company’s earnings were not significantly affected by cash flow hedging ineffectiveness arising from the crude oil and gas hedging contracts. Subsequent to December 31, 2004, the Company entered into the following crude oil and natural gas hedging contracts with BNP Paribas:

 

Gas

 

2,000 MMBtu per day “swap” at $6.655 per MMBtu for April 2005 through March 2006

4,000 MMBtu per day “swap” at $7.00 per MMBtu for April 2005 through March 2006

8,000 MMBtu per day “swap” at $7.1825 per MMBtu for January 2006 through March 2006

4,000 MMBtu per day “swap” at $6.665 per MMBtu for April 2005 through December 2006

 

Oil

 

300 barrels per day “swap” at $45.80 per barrel for January 2006 through March 2006

400 barrels per day “swap” at $48.71 per barrel for April 2006 through December 2006

 

Price Fluctuations and the Volatile Nature of Markets

 

Despite the measures taken by the Company to attempt to control price risk, the Company remains 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 the Company’s control. Domestic crude oil and gas prices could have a material adverse effect on the Company’s financial position, results of operations and quantities of reserves recoverable on an economic basis.

 

Debt and Debt-Related Derivatives

 

In February 2003, the Company entered into three separate interest rate swaps with BNP Paribas, covering a three year period, which are accounted for as cash flow hedges of future variable rate interest payments on the Company’s floating senior secured credit facility (two of the contracts have now expired). The first interest rate swap, which had an effective date of February 26, 2003, expired on its maturity date of February 26, 2004, and was for $18,000,000 with a LIBOR swap rate of 1.53%. The second interest rate swap, which had an effective date of February 26, 2004, expired on its maturity date of November 8, 2004, and was for $18,000,000 with a LIBOR swap rate of 2.25%. The third interest rate swap, which has an effective date of November 8, 2004 and a maturity date of February 26, 2006, is for $18,000,000 with a LIBOR swap rate of 3.46%. In February 2004, the Company entered into a fourth interest rate swap contract with BNP Paribas, which has an effective date of February 26, 2006 and a maturity date of February 26, 2007, is for $23,000,000 with a LIBOR swap rate of 4.08%. The fair value of the interest rate swap contracts in place at December 31, 2004 resulted in a liability of $162,000. As of December 31, 2004, $94,000 (net of $50,000 in income taxes) of deferred losses on derivative instruments accumulated in other comprehensive income are expected to be reclassified into earnings during the

 

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GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

next twelve months. In the year ended December 31, 2004, $94,000 of previously deferred losses (net of $50,000 in income taxes) was reclassified from accumulated other comprehensive income to interest expense as the cash flow of the hedged items was recognized. For the year ended December 31, 2004, the Company’s earnings were not significantly affected by cash flow hedging ineffectiveness of interest rates.

 

NOTE J—Fair Value of Financial Instruments

 

The following presents the carrying amounts and estimated fair values of the Company’s financial instruments at December 31, 2004 and 2003.

 

     2004

    2003

 
     Carrying
Amount


    Fair Value

    Carrying
Amount


    Fair Value

 

Financial instruments

                                

Long-term debt (including current maturities)

   $ 27,000,000     $ 27,000,000     $ 20,000,000     $ 20,000,000  

Production payment liability

   $ 268,000     $ 268,000     $ 609,675     $ 623,375  

Oil and gas derivative assets (liabilities)

                                

Oil

   $ (2,657,490 )   $ (2,657,490 )   $ (634,747 )   $ (634,747 )

Gas

   $ 823,295     $ 823,295     $ (622,695 )   $ (622,695 )

Interest rate derivative assets (liabilities)

   $ (161,967 )   $ (161,967 )   $ (277,938 )   $ (277,938 )

 

The following methods and assumptions were used to estimate the fair value of each class of financial instruments:

 

Long term debt and other noncurrent liabilities:    The fair value is estimated using the discounted cash flow method based on the Company’s borrowing rates for similar types of financing arrangements.

 

Oil and gas derivatives:    The fair value is calculated based on the discounted cash flow expected to be received or paid on the derivative utilizing future posted market prices of the underlying product.

 

Interest rate derivatives:    The fair value is calculated based on the discounted cash flow expected to be received or paid on the derivative utilizing estimated market prices for interest rate futures.

 

Other monetary assets and liabilities:    The carrying amounts approximate fair values, therefore, these instruments were not presented in the table above.

 

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GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

NOTE K—Concentrations of Credit Risk and Significant Customers

 

Due to the nature of the industry the Company sells its 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 total revenues for the periods presented were as follows:

 

     Year Ended December
31,


 
     2004

    2003

    2002

 

Louis Dreyfus Corporation

   45 %   47 %    

Texon, LP

       25 %    

Reliant Energy

           45 %

Conoco Phillips

   8 %   5 %   17 %

Shell Trading

   5 %       17 %

Genesis Crude Oil L.P.

           5 %

Chevron Texaco

   15 %        

Texla Gas

   6 %        

Enterprise Liquids

   5 %        

 

Effective January 1, 2003, the Company contracted with Louis Dreyfus Corporation as its major gas purchaser in lieu of Reliant Energy.

 

NOTE L—Commitments and Contingencies

 

In connection with the acquisition of its Burrwood and West Delta 83 fields, the Company secured a performance bond and established an escrow account to be used for the payment of obligations associated with the plugging and abandonment of the wells, salvage and removal of platforms and related equipment, and the site restoration of the fields. Required escrowed outlays included an initial cash payment of $750,000 and monthly cash payments of $70,000 beginning June 1, 2000 and continuing until June 1, 2005. The escrow agreement was amended in the fourth quarter of 2001 to suspend monthly cash payments and cap the escrow account at its current balance of $2,039,000. In addition, as part of the purchase agreement, the Company agreed to shoot a 3-D seismic survey over the fields which was completed in the fourth quarter of 2001. The cost of the seismic survey was approximately $2,500,000.

 

On February 8, 2000, the Company commenced a suit against the operator and joint owner of the Lafitte field, alleging certain items of misconduct and violations of the agreements associated primarily with the joint acquisition of and unfettered access to a license to 3-D seismic data over the field. The operator counter-claimed against Goodrich on the grounds that Goodrich was obligated to post a bond to secure the plugging and abandonment obligations in the field. On November 1, 2002, the 125th Judicial District Court of Harris County, Texas, ruled in favor of the Company stating (1) The Sale and Assignment between the Company and the operator assigned the same rights to the 3-D seismic data that the operator had pursuant to the operator’s data use license agreement from Texaco Exploration and Production, Inc. (“TEPI”); and (2) Also pursuant to the terms of the Sale and Assignment, Goodrich is required to post 49% of the bond liability to TEPI at such time that TEPI requests it. A jury trial commenced in September 2003. On October 29, 2003, the jury found the operator and joint owner to be in breach of the Sale and Assignment and awarded a wholly-owned subsidiary of the Company monetary damages as well as recovery of attorneys’ fees. On May 28, 2004, the trial court ordered a final judgment which awarded the Company a net sum of approximately $2,065,000 as follows:

 

  1. $538,000 in damages;

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

  2. $1,515,000 in recovery of plaintiff’s attorneys’ fees; and

 

  3. Pre-judgment interest of approximately $115,000, which was calculated on the damages at a rate of 5%, per annum, compounded annually, from the date of the filing of the lawsuit on February 8, 2000 through May 27, 2004, the day preceding the date of the final judgment.

 

The trial court also ordered the Company to pay $103,000 to the operator in recovery of defendant’s attorneys’ fees and provided for post-judgment interest to accrue on the awarded damages and both parties’ attorneys’ fees through the date of ultimate payment. Either party could have appealed the final judgment or filed a motion for a new trial within ninety days from the date of the final judgment. In September 2004, the time period for either party to appeal the judgment elapsed, therefore, the Company accrued a non-recurring gain in the quarter ended September 30, 2004 in the amount of $2,050,000, reflecting the anticipated payment of the final judgment by the operator less the Company’s estimated expenses of the final judgment. In October 2004, the operator remitted a total of $2,118,000 to the Company in full satisfaction of the judgment, including the net amount of post-judgment interest.

 

The Company is party to additional lawsuits arising in the normal course of business. The Company intends to defend these actions vigorously and believes, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to its financial position or results of operations.

 

NOTE M—Related Party Transactions

 

On June 1, 2001, the Company entered into a consulting agreement with Patrick E. Malloy, III, a member of the Company’s Board of Directors, under which Mr. Malloy provided the Company advice on hedging and financial matters. The contract, which expired in May 2003, paid Mr. Malloy $120,000 per year. The Company paid Mr. Malloy $50,000 in 2003 and $120,000 in 2002.

 

On March 12, 2002, the Company 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 its Burrwood and West Delta 83 fields for $12 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 the Company’s Board of Directors at that time, as well as Josiah Austin, who subsequently became a member of the Company’s Board of Directors. Mr. Malloy is now Chairman of the Company’s Board of Directors and Mr. Appel retired from the Board of Directors in February 2004. See Note C for further information regarding the sale.

 

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 operated by the Company in 2003 and 2004. In accordance with industry standard joint operating agreements, the Company bills MEC for its share of the capital and operating costs of the three fields on a monthly basis. As of December 31, 2004 and 2003, the amounts billed and outstanding to MEC for its share of monthly capital and operating costs were $1,376,000 and $1,129,000, 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 the Company in the month subsequent to billing and the affiliate is current on payment of its billings.

 

The Company also serves as the operator for a number of other oil and gas wells owned by an affiliate of MEC in which the Company owns a 7% after payout working interest. In accordance with industry standard joint operating agreements, the Company bills the affiliate for its share of the capital and operating costs of these wells on a monthly basis. As of December 31, 2004 and 2003, the amounts billed and outstanding to the affiliate for its

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

share of monthly capital and operating costs were $1,681,000 and $535,000, 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 the Company in the month subsequent to billing and the affiliate is current on payment of its billings.

 

The Company acted as agent for certain stockholders to facilitate a stock purchase agreement and, in that capacity, the Company temporarily received funds totaling $3,886,988 from the purchasing stockholders, which are reflected on the Company’s December 31, 2003 balance sheet in both cash and current liabilities. In accordance with the terms of the stock purchase agreement, the Company transferred the funds to the selling stockholders in January 2004 upon the sale of the shares. A portion of the shares of common stock sold by the selling stockholders resulted from the cashless exercise of warrants (see Note H, “Common Stock”).

 

NOTE N—Discontinued Operations

 

In October 2004, the Company sold its operated interests in the Marholl and Sean Andrew fields, along with its non-operated interests in the Ackerly field, all of which were located in West Texas, for gross proceeds of approximately $2,100,000. The Company realized a gain of $877,000 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.

 

Prior year results have also been reclassified to report the results of operations of the properties as discontinued operations. Results for these properties reported as discontinued operations were as follows:

 

     Year ended December 31,

 
     2004

    2003

    2002

 

Oil and gas sales

   $ 566,070     $ 557,468     $ 466,801  

Operating expenses

     (290,160 )     (255,708 )     (495,853 )

Gain on sale

     877,218              
    


 


 


Income before taxes

     1,153,128       301,760       (29,052 )

Income tax expense (benefit)

     403,595       105,616       (10,168 )
    


 


 


Income (loss) from discontinued operations

   $ 749,533     $ 196,144     $ (18,884 )
    


 


 


 

NOTE O—Natural Gas and Crude Oil Cost Data

 

The table below reflects the Company’s capitalized costs related to oil and gas producing activities at December 31, 2004, and 2003.

 

     December 31,

 
     2004

    2003

 

Proved properties

   $ 148,496,626     $ 106,394,711  

Unproved properties

     11,406,828       12,287,598  
    


 


       159,903,454       118,682,309  

Less accumulated depreciation, depletion and amortization

     (51,073,606 )     (43,807,020 )
    


 


Net oil and gas properties

   $ 108,829,848     $ 74,875,289  
    


 


 

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GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

As of December 31, 2004, the net book value of unproved properties was $3,945,623. The following table reflects certain data with respect to cost incurred in natural gas and oil property acquisitions, exploration and development activities:

 

     Year ended December 31,

     2004

   2003

   2002

Property acquisition

                    

Proved

   $    $    $

Unproved

     5,528,142      600,839     

Asset retirement costs (1)

     506,119      375,313     

Exploration

     4,873,498      2,248,802      1,128,855

Development

     35,962,201      17,723,628      7,843,730
    

  

  

     $ 46,869,960    $ 20,948,582    $ 8,972,585
    

  

  


(1) Excludes pro forma asset retirement costs, assuming SFAS No. 143 had been applied retroactively, of $29,917 in 2002.

 

NOTE P—Supplemental Oil and Gas Reserve Information (Unaudited)

 

The supplemental oil and gas reserve information that follows is presented in accordance with SFAS No. 69, Disclosures about Oil and Gas Producing Activities. The schedules provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies. Additional background information follows concerning the schedules.

 

Schedules 1 and 2—Estimated Net Proved Oil and Gas Reserves

 

Substantially all of the Company’s 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, 2004, and by Coutret and Associates, Inc. as of December 31, 2003. 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 Securities and Exchange Commission 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.

 

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GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

Schedule 3—Standardized Measure of Discounted Future Net Cash Flows to Proved Oil and Gas Reserves

 

SFAS No. 69 requires calculation of future net cash flows using a ten percent annual discount factor and year end prices, costs, and statutory tax rates, except for known future changes such as contracted prices and legislated tax rates.

 

The calculated value of proved reserves is not necessarily indicative of either fair market value or present value of future cash flows because prices, costs, and governmental policies do not remain static; appropriate discount rates may vary; and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts.

 

Schedule 3 also presents a summary of the principal reasons for change in the standard measure of discounted future net cash flows for each of the three years in the period ended December 31, 2004.

 

Schedule 1—Estimated Net Proved Gas Reserves (Mcf)

 

     Year ended December 31,

 
     2004

    2003

    2002

 

Proved:

                  

Balance, beginning of period

   30,903,390     29,069,550     33,956,250  

Revisions of previous estimates

   (6,666,200 )   648,283     29,807  

Purchase of minerals in place

            

Extensions, discoveries, and other additions

   48,321,793     6,130,098     3,848,920  

Production

   (4,822,819 )   (3,361,041 )   (2,477,790 )

Sale of minerals in place

   (53,716 )   (1,583,500 )   (6,287,637 )
    

 

 

Balance, end of period

   67,682,448     30,903,390     29,069,550  
    

 

 

Proved developed:

                  

Beginning of period

   23,429,440     15,203,255     16,692,390  

End of period

   24,361,773     23,429,440     15,203,255  

 

Schedule 2—Estimated Net Proved Oil Reserves (Barrels)

 

     Year ended December 31,

 
     2004

    2003

    2002

 

Proved:

                  

Balance, beginning of period

   7,805,410     7,441,340     8,750,420  

Revisions of previous estimates

   (3,465,821 )   54,419     28,476  

Purchase of minerals in place

            

Extensions, discoveries, and other additions

   1,986,871     794,095     120,970  

Production

   (488,209 )   (484,444 )   (451,564 )

Sale of minerals in place

   (249,392 )       (1,006,962 )
    

 

 

Balance, end of period

   5,588,859     7,805,410     7,441,340  
    

 

 

Proved developed:

                  

Beginning of period

   3,600,980     2,556,670     3,399,610  

End of period

   2,228,254     3,600,980     2,556,670  

 

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GOODRICH PETROLEUM CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

December 31, 2004

 

The following table summarizes the Company’s combined oil and gas reserve information on a Mcf equivalent basis. Estimates of oil reserves were converted using a conversion ratio of 1.0/6.0 Mcf.

 

     Year ended December 31,

     2004

   2003

   2002

Estimated Net Proved Reserves (Mcfe):

              

Total Proved

   101,215,603    77,735,850    73,717,590

Proved Developed

   37,731,297    45,035,320    30,543,570

 

Schedule 3—Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves

 

     2004

    2003

    2002

 
     (in thousands)  

Future revenues

   $ 654,543     $ 446,165     $ 340,712  

Future lease operating expenses and production taxes

     (151,186 )     (87,929 )     (81,174 )

Future developments costs (1)

     (86,919 )     (33,180 )     (28,953 )

Future income tax expense

     (104,870 )     (77,855 )     (44,292 )
    


 


 


Future net cash flows

     311,568       247,201       186,293  

10% annual discount for estimated timing of cash flows

     (130,890 )     (83,227 )     (62,031 )
    


 


 


Standardized measure of discounted future net cash flows

   $ 180,678     $ 163,974     $ 124,262  
    


 


 


Average year end prices

                        

Natural gas (per MCF)

   $ 6.14     $ 6.42     $ 4.35  

Crude oil (per BBL)

   $ 42.72     $ 31.75     $ 28.80  

(1) Includes asset retirement obligation of $6,719,000 in 2004 and $6,509,000 in 2003.

 

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

 

     Year ended December 31,

 
     2004

    2003

    2002

 
     (in thousands)  

Net changes in prices and production costs related to future production

   $ 84,156     $ 47,406     $ 84,143  

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

     (34,636 )     (24,378 )     (9,548 )

Net change due to revisions in quantity estimates

     (27,462 )     2,693       413  

Net change due to extensions, discoveries and improved recovery

     60,239       30,081       9,393  

Net change due to purchase and sales of minerals-in-place

     (4,278 )     (4,373 )     (25,314 )

Future development costs

     (53,739 )     (4,227 )     6,720  

Net change in income taxes

     (22,640 )     (23,136 )     (21,738 )

Accretion of discount

     21,462       15,136       7,889  

Change in production rates (timing) and other

     (6,398 )     510       (818 )
    


 


 


     $ 16,704     $ 39,712     $ 51,140  
    


 


 


 

 

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GOODRICH PETROLEUM CORPORATION

 

Consolidated Quarterly Income Information

(Unaudited)

 

     First Quarter

    Second Quarter

   Third Quarter

   Fourth Quarter

   Total

2004

                                   

Revenues

   $ 10,764,492     $ 9,190,834    $ 12,013,787    $ 15,360,484    $ 47,329,597

Net income (loss) from continuing operations

   $ 2,077,292     $ 2,830,933    $ 4,287,478    $ 8,582,115    $ 17,777,818

Net income (loss) applicable to Common Stock

   $ 1,966,073     $ 2,731,851    $ 4,179,193    $ 9,017,263    $ 17,894,380

Basic Income (loss) per average Common share

   $ 0.12     $ 0.15    $ 0.22    $ 0.45    $ 0.95

Diluted Income (loss) per average Common share

   $ 0.12     $ 0.14    $ 0.21    $ 0.43    $ 0.91

2003

                                   

Revenues

   $ 6,903,162     $ 7,785,335    $ 7,825,386    $ 9,626,341    $ 32,140,224

Net income (loss) from continuing operations

   $ 157,904     $ 889,294    $ 1,158,228    $ 1,521,219    $ 3,726,645

Net income (loss) applicable to Common Stock

   $ (116,284 )   $ 757,961    $ 1,066,610    $ 1,375,747    $ 3,084,034

Basic Income (loss) per average Common share

   $ 0.00     $ 0.05    $ 0.07    $ 0.08    $ 0.21

Diluted Income (loss) per average Common share

   $ 0.00     $ 0.04    $ 0.06    $ 0.07    $ 0.18

 

The amounts shown above reflect reclassification of amounts for periods prior to the Fourth Quarter of 2004 to report the results of operations of non-core properties sold in October 2004 as discontinued operations. Net income from continuing operations in the Fourth Quarter of 2004 includes an unrealized gain on derivatives in the amount of $2,317,000. Net income applicable to Common Stock in the Fourth Quarter of 2004 includes an unrealized gain on derivatives in the amount of $2,317,000 as well as net income from discontinued operations in the amount of $593,000.

 

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

 

None

 

Item 9A.    Controls and Procedures.

 

The Company, under the direction of its chief executive officer and chief financial officer, has established controls and procedures to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the company’s financial reports and to other members of senior management and the Board of Directors.

 

Based on their evaluation as of December 31, 2004, the chief executive officer and chief financial officer of Goodrich Petroleum Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of December 31, 2004 to ensure that the information required to be disclosed by Goodrich Petroleum Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

 

There were no changes in the Company’s internal controls or in other factors that could significantly affect those controls subsequent to the date of their most recent evaluation.

 

Item 9B.    Other Information.

 

None.

 

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PART III

 

Item 10.    Directors and Executive Officers of the Registrant.

 

The Company’s executive officers and directors and their ages and positions as of March 24, 2005 are as follows:

 

Name


   Age

  

Position


Patrick E. Malloy, III

   61    Chairman of the Board of Directors

Walter G. “Gil” Goodrich

   46    Vice Chairman, Chief Executive Officer and Director

Robert C. Turnham, Jr.

   47    President and Chief Operating Officer

Mark E. Ferchau

   50    Executive Vice President

D. Hughes Watler, Jr.

   56    Senior Vice President, Chief Financial Officer and Treasurer

James B. Davis

   42    Senior Vice President, Engineering and Operations

Henry Goodrich

   74    Chairman—Emeritus and Director

Josiah T. Austin

   58    Director

John T. Callaghan

   50    Director

Geraldine A. Ferraro

   69    Director

Michael J. Perdue

   50    Director

Arthur A. Seeligson

   46    Director

Gene Washington

   58    Director

Steven A. Webster

   53    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, and Malloy Real Estate, Inc. 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 the Company’s 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 the Company’s directors in August 2002.

 

John T. Callaghan is the Managing Partner of Callaghan & Nawrocki, L.L.P, an audit, tax and consulting firm located on Long Island, 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 and chairman of the Finance Committee of both Andrea Systems, Inc. and the Friends of Long Island Heritage. He was elected to the Company’s Board of Directors in June 2003.

 

Geraldine A. Ferraro is an Executive Vice President 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 the Company’s 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., until FP Bancorp’s acquisition by Zions Bancorporation in May 1998. He has also held senior management positions with Rampac, Inc., a real estate development company, and PacWest Bancorp. He was elected to the Company’s 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 &

 

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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 the Company’s directors since August 1995.

 

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 the Company’s Board of Directors in June 2003.

 

Steven A. Webster is the Managing Director of Global Energy Partners, an affiliate of the Merchant Banking Division of Credit Suisse First Boston, which makes 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 serves on the board of directors of numerous other public and private companies, primarily in the energy industry. He was elected to the Company’s Board of Directors in August 2003.

 

Additional information required under Item 10, “Directors and Executive Officers of the Registrant,” will be provided in the Company’s Proxy Statement for the 2005 Annual Meeting of Stockholders. Additional information regarding the Company’s corporate governance guidelines as well as the complete texts of its Code of Business Conduct and Ethics and the charters of its Audit Committee and its Compensation Committee may be found on the Company’s website at http://www.goodrichpetroleum.com.

 

On June 30, 2004, the Company’s Chief Executive Officer submitted to the New York Stock Exchange (“NYSE”) the annual certification required by Section 303A.12(a) of the NYSE Listed Company Manual. In addition, the Company filed with the Securities and Exchange Commission exhibits to its Annual Report on Form 10-K for the year ended December 31, 2003, the certifications, required pursuant to Section 302 of the Sarbanes-Oxley Act, of its Chief Executive Officer and Chief Financial Officer relating to the quality of its public disclosure.

 

Item 11.    Executive Compensation.

 

The information required by Item 11 that relates to compensation of our principal executive officers and our directors is incorporated by reference from the information appearing under the captions “Executive Compensation” and “Election of Directors—Director’s Meetings and Compensation” in our definitive proxy statement that is to be filed with the SEC within 120 days of the end of our fiscal year on December 31, 2004. In addition and in accordance with Item 402(a)(8) of Regulation S-K, the information contained in our definitive proxy statement under the subheading “Report of the Compensation Committee of the Board of Directors” and “Performance Graph” shall not be deemed to be filed as part of, or incorporated by reference into, this Annual Report.

 

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

 

The information required by Item 12 that relates to the ownership of securities by management and others is incorporated by reference from the information appearing under the caption “Securities Authorized for Issuance Under Equity Compensation Plans” and “Security Ownership of Certain Beneficial Owners and Management” in our definitive proxy statement that is to be filed with the SEC within 120 days of the end of our fiscal year on December 31, 2004.

 

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Item 13.    Certain Relationships and Related Transactions.

 

The information required by Item 13 that relates to business relationships and transactions with our management and other related parties is incorporated by reference from the information appearing under the captions “Certain Relationships and Related Party Transactions” and “Compensation Committee Interlocks and Insider Participation” in our definitive proxy statement that is to be filed with the SEC within 120 days of the end of our fiscal year on December 31, 2004.

 

Item 14.    Principal Accounting Fees and Services.

 

The information required by Item 14 that relates to services provided by our Independent Public Accountants and the fees incurred for services provided during 2004 and 2003 is incorporated by reference from the information appearing under the captions “Fees Billed by Independent Public Accountants” in our definitive proxy statement that is to be filed with the SEC within 120 days of the end of our fiscal year on December 31, 2004.

 

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PART IV

 

Item 15.    Exhibits, Financial Statement Schedules.

 

(a)    (1) Financial Statements

 

The following consolidated financial statements of the Company are included in Part II, Item 8:

 

     Page

Report of Independent Registered Public Accounting Firm

   32

Consolidated Balance Sheets—December 31, 2004 and 2003

   33

Consolidated Statements of Operations—Years ended December 31, 2004, 2003 and 2002

   34

Consolidated Statements of Cash Flows—Years ended December 31, 2004, 2003 and 2002

   35

Consolidated Statements of Stockholders’ Equity and Comprehensive Income—Years ended December 31, 2004, 2003 and 2002

   36

Notes to Consolidated Financial Statements—Year ended December 31, 2004

   37-56

Consolidated Quarterly Income Information (Unaudited)

   57

 

(a)    (2) Financial Statement Schedules

 

The schedules for which provision is made in Regulation S-X are not required under the instructions contained therein, are inapplicable, or the information is included in the footnotes to the financial statements.

 

(a)    (3) Exhibits

 

3(i).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(ii).1    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).
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).
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).

 

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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.
*23.3    Consent of Coutret and 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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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     (Registrant)
     By:  

/s/    WALTER G. GOODRICH        


Date: March 25, 2005

      

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 below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:

 

Date: March 25, 2005

 

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   &n