10-K 1 d10k.htm FORM 10-K Form 10-K
Table of Contents
Index to Financial Statements

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-K

 


 

(Mark One)

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

 

For the fiscal year ended December 31, 2004

 

OR

 

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

 

For the transition period from             to             

 

Commission file number 1-10578

 


 

VINTAGE PETROLEUM, INC.

(Exact name of registrant as specified in its charter)

 


 

Delaware   73-1182669

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

110 West Seventh Street Tulsa, Oklahoma   74119-1029
(Address of principal executive offices)   (Zip Code)

 

Registrant’s telephone number, including area code: (918) 592-0101

 

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

 

Title of each class


 

Name of each exchange

on which registered


Common Stock, $0.005 Par Value

  New York Stock Exchange

Preferred Share Purchase Rights

  New York Stock Exchange

 

Securities registered pursuant to Section 12(g) of the Act: None

 


 

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 the 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.  x

 

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

 

As of June 30, 2004, the aggregate market value of the Registrant’s Common Stock held by non-affiliates was approximately $912,505,000.

 

As of February 28, 2005, 66,072,702 shares of the Registrant’s Common Stock were outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Registrant’s Proxy Statement for the Annual Meeting of Stockholders to be held May 10, 2005, are incorporated by reference into Part III of this Form 10-K.

 



Table of Contents
Index to Financial Statements

VINTAGE PETROLEUM, INC.

FORM 10-K

YEAR ENDED DECEMBER 31, 2004

TABLE OF CONTENTS

 

          Page

PART I

Items 1 and 2.

   Business and Properties    1

Item 3.

   Legal Proceedings    28

Item 4.

   Submission of Matters to a Vote of Security Holders    28

Item 4A.

   Executive Officers of the Registrant    29
PART II

Item 5.

   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities    32

Item 6.

   Selected Financial Data    33

Item 7.

   Management’s Discussion and Analysis of Financial Condition and Results of Operations    35

Item 7A.

   Quantitative and Qualitative Disclosure About Market Risk    58

Item 8.

   Financial Statements and Supplementary Data    65

Item 9.

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure    66

Item 9A.

   Controls and Procedures    66

Item 9B.

   Other Information    66
PART III

Item 10.

   Directors and Executive Officers of the Registrant    66

Item 11.

   Executive Compensation    66

Item 12.

   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters    67

Item 13.

   Certain Relationships and Related Transactions    67

Item 14.

   Principal Accountant Fees and Services    67
PART IV

Item 15.

   Exhibits and Financial Statement Schedules    68

Signatures

   71

Index to Financial Statements

   72

 

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Index to Financial Statements

Certain Definitions

 

As used in this Form 10-K:

 

Unless the context requires otherwise, all references to “Vintage,” “Company,” “we,” “our,” “ours,” and “us” refer to Vintage Petroleum, Inc., its consolidated subsidiaries and its proportionately consolidated general partner and limited partner interests in various joint ventures.

 

“Oil” means crude oil, condensate and natural gas liquids. “Condensate” means hydrocarbons which are in a gaseous state under reservoir conditions but which become liquid at the surface and may be recovered by conventional separators. “Natural gas liquids” means hydrocarbons found in natural gas which may be extracted as liquified petroleum gas and natural gasoline. “Gas” means natural gas.

 

“Mcf” means thousand cubic feet, “MMcf” means million cubic feet, and “Bcf” means billion cubic feet. “Btu” means British thermal units, the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit, and “MMBtu” means million British thermal units. “Bbl” means barrel, or 42 U.S. gallons liquid volume, “MBbls” means thousand barrels and “MMBbls” means million barrels. “BOE” means equivalent barrels of oil, “MBOE” means thousand equivalent barrels of oil and “MMBOE” means million equivalent barrels of oil. Unless otherwise indicated in this Form 10-K, gas volumes are stated at the legal pressure base of the state or area in which the reserves are located and at 60° Fahrenheit. BOE are determined using the ratio of six Mcf of gas to one Bbl of oil.

 

“Working interest” means the operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith. “Royalty interest” means an interest in an oil and gas property entitling the owner to a share of oil and gas production free of cost of production.

 

The term “gross” refers to the total acres or wells in which Vintage has a working interest, and “net” refers to gross acres or wells multiplied by the percentage working interest owned by Vintage. “Net production” means production that is owned by Vintage less royalties and production due others.

 

“Development well” means a well drilled within the proved area of an oil or gas reservoir, as indicated by reasonable interpretation of available data, to the depth of a stratigraphic horizon known to be productive. “Exploratory well” means a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend the proved limits of a known reservoir. “Dry hole” means a well found to be incapable of producing either oil or gas in sufficient quantities to justify completion of the well. “Productive well” means a well that is producing oil or gas or that is capable of production including gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

 

“Infill drilling” means drilling of an additional well or wells provided for by an existing spacing order to more adequately drain a reservoir. “Recompletion” means the completion for production of an existing wellbore in a different formation or producing horizon, either deeper or shallower, from that in which the well was previously completed. “Workover” means remedial operations on a well with the intention of restoring or increasing production from the same zone, including plugging back, squeeze cementing, reperforating, cleanout and acidizing.

 

“Proved oil and gas reserves” are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. “Proved developed oil and gas reserves” are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. “Proved undeveloped oil and gas reserves” are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

 

“Developed acreage” means the number of acres which are allocated or assignable to producing wells or wells capable of production. “Undeveloped acreage” means the number of acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved oil and gas reserves.

 

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Forward-Looking Statements

 

This Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this Form 10-K which address activities, events or developments which we expect, believe or anticipate will or may occur in the future are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts” and similar expressions are also intended to identify forward-looking statements.

 

These forward-looking statements include, among others, such things as:

 

    amounts and nature of future capital expenditures;

 

    wells to be drilled or reworked;

 

    oil and gas prices and demand;

 

    exploitation and exploration prospects;

 

    estimates of proved oil and gas reserves;

 

    reserve potential;

 

    development and infill drilling potential;

 

    expansion and other development trends of the oil and gas industry;

 

    business strategy;

 

    production of oil and gas reserves;

 

    expansion and growth of our business and operations; and

 

    events or developments in foreign countries, including estimates of oil export levels.

 

These statements are based on certain assumptions and analyses we made in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties which could cause actual results to differ materially from our expectations, including:

 

    risk factors discussed in this Form 10-K and listed from time to time in our filings with the Securities and Exchange Commission;

 

    oil and gas prices;

 

    exploitation and exploration successes;

 

    actions taken and to be taken by the foreign governments as a result of economic conditions;

 

    continued availability of capital and financing;

 

    general economic, market or business conditions;

 

    acquisitions and other business opportunities (or lack thereof) that may be presented to and pursued by us;

 

    changes in laws or regulations; and

 

    other factors, most of which are beyond our control.

 

Consequently, all of the forward-looking statements made in this Form 10-K are qualified by these cautionary statements and there can be no assurance that the actual results or developments anticipated by us will be realized or, even if substantially realized, that they will have the expected consequences to or effects on us or our business or operations. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events or otherwise.

 

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Index to Financial Statements

PART I

 

Items 1 and 2. Business and Properties.

 

Website Access to Reports

 

Our public internet site is http://www.vintagepetroleum.com. We make available free of charge through our internet site, via a link to the EDGAR database of the Securities and Exchange Commission (“SEC”), our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

 

In addition, we make available on http://www.vintagepetroleum.com our annual report to stockholders. You will need the Adobe Acrobat Reader software installed on your computer to view this document, which is in PDF format. If you do not have Adobe Acrobat Reader installed, a link to Adobe Systems Incorporated’s internet site, where you can download the software, is provided.

 

General

 

We are an independent energy company with operations primarily in the exploration and production and gas marketing segments of the oil and gas industry. We are focused on the acquisition of oil and gas properties which contain the potential for increased value through exploitation and exploration. Through our experienced management and technical staff, we have been successful in realizing such potential on prior acquisitions through workovers, recompletions, secondary recovery operations, operating cost reductions and the drilling of development or exploratory wells. In addition to our exploration and development activities associated with acquisitions, we continue to build an inventory of exploration prospects in the United States that may impact production in the near term as well as high potential frontier prospects that may impact production in the longer term.

 

At December 31, 2004, we owned and operated producing properties in nine states in the U.S., with our proved reserves in the U.S. located primarily in four core areas: West Coast, Gulf Coast, East Texas and Mid-Continent. Additionally, we have international core areas located in Argentina, Yemen and Bolivia. In Argentina, we have 22 concessions, 19 of which we operate. Fourteen of these operated concessions are located in the south flank of the San Jorge Basin in southern Argentina. We also have four concessions (two are operated) in the Cuyo Basin in western Argentina acquired through various acquisitions in 2000 and 2001. In September 2004, we made our initial entry into the northern flank of the San Jorge Basin in Argentina with our purchase of Petrolera Rio Alto S.A. whose principal asset is the producing Bella Vista Oeste concession. This acquisition gave us 100 percent working interest in the Bella Vista Oeste concession which we operate. (See “Acquisitions.”) In Bolivia, we own and operate three concessions in the Chaco Plains area of southern Bolivia and the Naranjillos concession located in the Santa Cruz Province. We operate the S-1 Damis block in Yemen, where initial production began during the second quarter of 2004. We also continue to pursue exploration opportunities in Yemen and we have ongoing exploration activities in Bulgaria. In 2003, we sold our operations in Ecuador, where we operated three block in the Oriente Basin, and in 2004 we sold our Canadian operations. (See “Divestitures.”)

 

As of December 31, 2004, we owned interests in 2,810 gross (2,436 net) productive wells in the U.S., of which approximately 92 percent are operated by us, 1,623 gross (1,470 net) productive wells in Argentina, of which approximately 85 percent are operated by us, 15 gross (14 net) productive wells in Bolivia, all of which are operated by us and 10 gross (8 net) productive wells in Yemen, all of which are operated by us. As of December 31, 2004, our properties had proved reserves of 437.2 MMBOE, comprised of 297.2 MMBbls of oil and 840 Bcf of gas, with a present value of estimated future net revenues before income taxes (utilizing a 10 percent discount rate) of $3.7 billion and a standardized measure of discounted future net cash flows of $2.5 billion. Our net daily production from continuing operations for the fourth quarter of 2004 averaged 47.5 MBbls of oil and 143.7 MMcf of gas.

 

Financial information relating to our industry segments is set forth in Note 9 “Segment Information” to our consolidated financial statements included elsewhere in this Form 10-K.

 

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Index to Financial Statements

We were incorporated in Delaware on May 31, 1983. Our principal office is located at 110 West Seventh Street, Tulsa, Oklahoma 74119-1029, and our telephone number is (918) 592-0101.

 

Business Strategy

 

Our overall goal is to maximize value through profitable growth in oil and gas reserves and production. We have been successful at achieving this goal through an ongoing strategy of (a) acquiring producing oil and gas properties with significant upside potential at favorable prices, (b) focusing on exploitation, development and exploration activities to maximize production and ultimate reserve recovery on existing properties and undeveloped properties, (c) maintaining efficient operations and (d) maintaining financial flexibility. Key elements of our strategy include:

 

    Acquisitions of Producing Properties. We have an experienced management and technical team which focuses on acquisitions of operated producing properties that meet our selection criteria. These criteria include (a) significant potential for increasing reserves and production through exploitation, development and exploration, (b) favorable purchase price and (c) opportunities for improved operating efficiency. Our emphasis on property acquisitions reflects our belief that continuing consolidation and restructuring activities on the part of major integrated, large independent and national oil companies has afforded in the past, and should afford in the future, favorable opportunities to purchase domestic and international properties. This acquisition strategy has allowed us to rapidly grow our reserves at favorable acquisition prices. From January 1, 2000, through December 31, 2004, we spent $809.7 million acquiring 112.3 MMBOE of proved oil and gas reserves at an average acquisition cost of $7.21 per BOE. We replaced, through acquisitions, approximately 74 percent of our production of 151.4 MMBOE during the same period. For additional information, see “Acquisitions.” We are continually identifying and evaluating acquisition opportunities, including acquisitions that would be significantly larger than many of those we have consummated to date. No assurance can be given that any such acquisitions will be successfully consummated.

 

    Exploration and Development. We pursue workovers, recompletions, secondary recovery operations and other production optimization techniques on our properties, as well as development and infill drilling, with the goals of offsetting normal production declines and replacing our annual production. Our overall exploration strategy balances high potential international prospects with lower risk drilling in known formations in the United States and Argentina. We make extensive use of geophysical studies, including 3-D seismic data, which reduces the cost of our exploration and development programs by increasing our success rate. From January 1, 2000, through December 31, 2004, we spent approximately $962.6 million on exploration and development activities. As a result of all of these activities, including the impact of reserve revisions, during the five-year period ended December 31, 2004, we succeeded in adding 100.9 MMBOE to proved reserves, replacing approximately 67 percent of production during the same period at a cost of $9.54 per BOE. During 2004, we spent $254.7 million on exploration and development activities and added 15.0 MMBOE to proved reserves (including Canadian additions and revisions), replacing approximately 54 percent of 2004 production at a cost of $16.96 per BOE. For additional information, see “Exploration and Development.” We continue to maintain an extensive inventory of exploration and development opportunities. The total 2005 non-acquisition capital budget has been set at $250 million. The exploration portion of the 2005 capital budget of approximately $72 million will focus primarily on the United States, with other projects planned for Yemen and Bulgaria.

 

    Efficient Operations. We believe we are an efficient operator and capitalize on our lower cost structure in evaluating acquisition opportunities. We have generally achieved substantial reductions in labor and other field level costs from those experienced by the previous operators. In addition, we target acquisition candidates that are located in our core areas and provide opportunities for cost efficiencies through consolidation with our other operations. The lower cost structure has generally allowed us to substantially improve the cash flows of newly acquired properties.

 

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Index to Financial Statements
    Financial Flexibility. We are committed to maintaining financial flexibility, which we believe is important for the successful execution of our acquisition, exploitation and exploration strategy. Since 1990, we have completed five public equity offerings, two public debt offerings and three Rule 144A private debt offerings, all of which have provided us with aggregate net proceeds of approximately $1.2 billion. Our debt, less cash on hand, at December 31, 2004, was $425.7 million. Cash on hand, internally generated cash flows, the borrowing capacity under our revolving credit facility and our ability to adjust our level of capital expenditures are our major sources of liquidity. In addition, we may use other sources of capital, including the issuance of additional debt securities or equity securities, to fund any major acquisitions we might secure in the future and maintain our financial flexibility. For further information, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity” included elsewhere in this Form 10-K.

 

Acquisitions

 

Historically, we have allocated a substantial portion of our capital expenditures to the acquisition of producing oil and gas properties. Our continuing emphasis on reserve additions through property acquisitions reflects our belief that consolidation and restructuring activities on the part of major integrated, large independent and national oil companies have afforded in recent years, and should afford in the future, favorable opportunities to purchase domestic and international producing properties.

 

Since our incorporation in May 1983, we have been actively engaged in the acquisition of producing oil and gas properties, primarily in the West Coast, Gulf Coast, East Texas and Mid-Continent areas of the U.S. In 1995, we made a series of acquisitions that established a core area in the San Jorge Basin in southern Argentina. In late 1996, we expanded our South American operations into Bolivia and, in 1998, into Ecuador. In 1998, we entered into a farm-in agreement for the S-1 Damis exploration block in Yemen and in December 2000, we made our initial entrance into Canada and Trinidad with the purchase of 100 percent of Cometra Energy (Canada), Ltd. (“Cometra”), a privately-held Canadian company. We significantly expanded our Canadian operations in 2001 with the purchase of 100 percent of Genesis Exploration, Ltd. (“Genesis”), a publicly-traded Canadian company. We also extended our Argentine operations in 2000 with our acquisition of two concessions from Perez Companc, in 2001 with our purchase of the La Ventana and Rio Tunuyan concessions from Shell C.A.P.S.A., a wholly-owned affiliate of Royal Dutch Shell and most recently in September 2004 with our purchase of Petrolera Rio Alto S.A. (“PRASA”), a subsidiary of Rio Alto Resources International, Inc. In December 2004, we expanded our ownership in Alabama with the $77.2 million acquisition of Exxon Mobil Corporation’s interest in the Big Escambia Creek field and gas processing facility adjacent to our Flomaton and Fanny Church fields and plant. This acquisition is consistent with our historical philosophy of improving cash flow by reducing operating costs on newly acquired properties through economies of scale due to existing operations in the area. We are constantly identifying and evaluating additional acquisition opportunities which may lead to our expansion into new domestic core areas or other countries which we believe are politically and economically stable.

 

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Index to Financial Statements

From January 1, 2000, through December 31, 2004, we made oil and gas reserve acquisitions with costs totaling approximately $809.7 million. As a result of these acquisitions, we acquired approximately 112.3 MMBOE of proved oil and gas reserves. The following table summarizes our acquisition experience during the periods indicated:

 

          Proved Reserves When Acquired

  

Cost

Per BOE

When

Acquired


    

Acquisition

Costs


  

Oil

(MBbls)


  

Gas

(MMcf)


   MBOE

  
     (In thousands)                    

North America Acquisitions:

                            

2000

   $ 53,962    2,854    41,166    9,715    $ 5.55

2001

     564,950    27,493    207,701    62,110      9.10

2002

     —      —      —      —        —  

2003

     463    90    258    133      3.48

2004

     75,599    5,690    17,381    8,587      8.80
    

  
  
  
      

Total North America Acquisitions

     694,974    36,127    266,506    80,545      8.63
    

  
  
  
      

South America Acquisitions:

                            

2000

     37,486    11,970    2,278    12,350      3.04

2001

     42,267    11,724    1,636    11,997      3.52

2002

     —      —      —      —        —  

2003

     —      —      —      —        —  

2004

     34,948    7,411    —      7,411      4.72
    

  
  
  
      

Total South America Acquisitions

     114,701    31,105    3,914    31,758      3.61
    

  
  
  
      

Total Acquisitions

   $ 809,675    67,232    270,420    112,303      7.21
    

  
  
  
      

 

The following is a brief discussion of the significant acquisitions in 2004:

 

Gulf Coast Area of Alabama. In December 2004, we acquired 100 percent of Exxon Mobil Corporation’s interest in the Big Escambia Creek field and processing facility for $77.2 million cash. Approximately $73.9 million of the purchase price was allocated to oil and gas reserves.

 

The field produces condensate, gas and liquids from the Smackover formation and current net production is approximately 1,920 BOE per day. The field consists of 13 operated and two non-operated wells, and is adjacent to our existing operated Flomaton and Fanny Church fields and plant. We believe that this expansion of our existing operating area will enable us to increase production and profitability through a series of planned facility modifications, drilling and increased operational efficiencies.

 

The acquired property and facilities are a logical extension to our existing property base, have producing characteristics similar to our adjacent fields and have well established, predictable production decline rates. These properties provide us with the type of operational and work program opportunities in which we have been successful in the past. Funds for this acquisition were provided primarily from cash on hand resulting from the sale of our interests in Canada. (See “Divestitures.”)

 

Northern Flank of San Jorge Basin (Argentina). In September 2004, we acquired 100 percent of PRASA, the wholly-owned Argentine subsidiary of Rio Alto Resources International, Inc. for total consideration of $34.9 million in cash. The acquired company’s principal asset is the operated Bella Vista Oeste producing concession which covers approximately 54,000 acres in the northern flank of the San Jorge Basin of Argentina.

 

Net production attributable to the producing Bella Vista Oeste concession at the time of our acquisition was estimated at 1.9 MBbls of oil per day from 52 active producing wells. We estimate that we acquired approximately 7.4 MMBbls of proved oil reserves in the transaction, with proved undeveloped reserves accounting for approximately 20 percent of the total proved reserves added. In addition, we believe that there is additional upside potential which may be realized through our future work programs.

 

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We believe the properties contain significant drilling, workover and waterflood potential which we plan to pursue along with the implementation of operational efficiencies. Drilling plans include development wells along with extensional and exploration opportunities. We anticipate that one drilling rig will be exclusively utilized for drilling activities in the Bella Vista Oeste concession during 2005. We have identified a number of workover opportunities at this time, with the work program assuming one dedicated workover rig during 2005. We have also identified a number of secondary recovery projects, including the expansion of an existing waterflood. Our 2005 plans also include a dedicated workover rig for secondary recovery activities. Funds for this acquisition were provided with cash on hand.

 

Divestitures

 

We have historically sold properties that were either marginally economical or non-strategic to our areas of operations. In 2001 and early 2002, we received proceeds of $47.1 million for properties sold primarily through public auctions in the U.S. These sales resulted in gains of $26.9 million ($16.7 million net of tax). Through these sales of 780 wells and over 600 leases in 85 fields, we significantly reduced our domestic well and lease count while reducing net U.S. production by only six percent and total net production by three percent.

 

In 2002, we determined that the level of investment and time horizon required to continue the development of our interests in Ecuador and Trinidad were inconsistent with the timing of our desire to reduce leverage. These assets, along with our remaining heavy oil properties in the Santa Maria area of southern California, were identified for sale. Our heavy oil properties in the Santa Maria area were sold in June 2002 for $9.5 million in cash and a note receivable for $6 million bearing monthly payments of $360,000, plus interest, with final maturity in June 2003. We received a cash payment as final settlement of this note in October 2002. On July 30, 2002, we completed the sale of our operations in Trinidad. We received $40 million in cash and recorded a gain of approximately $31.9 million ($14.9 million after income taxes).

 

On January 31, 2003, we completed the sale of our operations in Ecuador. We received $137.4 million in cash and recorded a gain of approximately $47.3 million ($9.5 million after income taxes). Also in 2003, we sold certain U.S. Mid-Continent gas properties for $30.0 million and certain non-strategic oil and gas assets in Saskatchewan and West Central Alberta, Canada for $27.9 million. We recorded losses of $1.7 million ($1.0 million after income taxes) on these sales. Combined, we estimate that the properties we sold in North America in 2003 accounted for proved reserves of 1.0 MMBbls of oil and 53.1 Bcf of gas as of the closing date of the sales and the Ecuador properties accounted for 45.3 MMBbls of oil. In total, these sales represented approximately 10 percent of our total proved reserves at the beginning of 2003.

 

In order to further reduce leverage and improve our financial flexibility to fund future production growth and recognizing the strong demand for producing oil and gas properties in Canada created by the acquisitive energy income trust sector, we sold all of our operations in Canada during 2004. On November 30, 2004, we completed the sale of our wholly-owned Canadian subsidiary for total consideration of $274.7 million ($241.5 million net of cash sold) and recorded an after-tax gain of $198.5 million. We estimate that at November 30, 2004, there were proved reserves of approximately 13.2 MMBOE associated with these properties. Proceeds from this sale were used to reduce debt outstanding under our revolving credit facility and fund a producing property acquisition in the U.S. (See “Acquisitions.”)

 

Exploration and Development

 

We concentrate our acquisition efforts on proved producing properties that demonstrate a potential for significant additional development through workovers, recompletions, secondary recovery operations, the drilling of development, infill or exploratory wells and other exploitation opportunities. We have pursued an active workover, recompletion and development drilling program on the properties we have acquired and intend to continue these activities in the future. Our exploitation staff focuses on maximizing the value of the properties within our reserve base and striving to offset normal production declines and our annual production.

 

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Our exploration program is designed to contribute significantly to our growth. We divide the strategic objectives of our exploration program into two parts. First, in the U.S., our exploration focus is in our core areas where our geological and engineering expertise and experience are greatest. We use state-of-the-art technology, including 3-D seismic data, to identify prospects. Exploration in the U.S. is designed to generate reserve growth in combination with our development activities. In recent years, we have increased the magnitude of this program and we plan to continue this effort in the future with a goal of achieving yearly production replacement through core area exploration. Such exploration is characterized by numerous individual projects with medium to low risk. Secondly, international exploration targets significant long-term reserve growth and value creation. Our international exploration projects currently underway in Yemen and Bulgaria are characterized by higher potential and higher risk.

 

In 2004, we spent $57.1 million on workovers and recompletions. A measure of the overall success of our recompletion and workover operations during 2004 (excluding minor equipment repair and replacement) was that improved production or operating efficiencies were achieved from approximately 81 percent of such operations, which is consistent with the average of 80 percent for the last three years.

 

Development drilling activity is generated both through our exploration efforts and as a result of obtaining undeveloped acreage in connection with producing property acquisitions. In addition, there are many opportunities for infill drilling on our leases currently producing oil and gas. We intend to continue to pursue development drilling opportunities which offer us potentially significant returns.

 

During 2004, we participated in the drilling of 142 gross (118 net) development wells, of which 133 gross (11 net) were productive. At December 31, 2004, our proved reserves included approximately 100 development or infill drilling locations on our U.S. acreage, 490 locations on our Argentine acreage, 20 locations on our Bolivian acreage and two locations on our acreage in Yemen. In addition, we have an extensive inventory of drilling locations on our existing properties that is not included in proved reserves. Included in our 2004 development drilling spending of $128.6 million was approximately $38.8 million in the U.S., $64.1 million in Argentina, $15.2 million in Yemen and $10.5 million in Canada. We also spent approximately $2.0 million on the acquisition of development seismic data and other development activities in 2004.

 

We spent approximately $51.7 million on exploration activities in 2004, participating in the drilling of 21 gross (13 net) exploratory wells, of which seven gross (four net) were productive. Exploration spending for 2004 included $34.6 million in the U.S., $4.1 million in Canada, $4.1 million in Argentina, $3.6 million in Yemen, $1.2 million in Bulgaria and $4.1 million in Italy. We also spent approximately $11.5 million on the acquisition of unproved acreage in 2004, primarily in the U.S.

 

Our total 2005 non-acquisition capital budget has been set at $250 million, which is comparable to our 2004 exploration and development spending. Planned development expenditures for 2005 are $178 million, consisting of $40 million in the U.S., $113 million in Argentina and $25 million in Yemen. The exploration portion of the 2005 capital budget of approximately $72 million includes $64 million in the U.S. and $8 million on various international projects.

 

Exploration and development activities for 2004 were concentrated mainly in our Argentina and U.S. core areas. The following is a brief description of significant developments in our recent exploration and development activities:

 

United States. We increased our U.S. oil and gas capital expenditures, excluding producing property acquisitions, in 2004, spending a total of $104.8 million, compared to $74.0 million in 2003. A significant portion of the 2004 exploration and development spending was aimed at converting proved undeveloped reserves to a proved developed producing status and other activities expected to contribute to production and reserves beyond 2004. As a result of these expenditures, including the impact of reserve revisions, we added 4.9 MMBOE to proved reserves in the U.S., replacing approximately 43 percent of 2004 U.S. production.

 

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Index to Financial Statements

Our U.S. development program for 2004 included the drilling of 31 gross (26 net) development wells, of which 28 gross (23 net) were successful, representing a 90 percent net success rate. Development drilling plus other exploration activities in the Luling, Darst Creek and West Ranch fields of South Central Texas contributed to a doubling of the daily production rate in these fields over the last two years. Also, drilling and workover activity at our Main Pass 116 complex resulted in an increase in net daily production to 13.1 MMcf in December 2004 from 1.1 MMcf in January 2004. Production from these fields was a significant contributor to the revitalization of domestic production volumes in 2004.

 

Our 2004 U.S. development program also included 87 gross (76 net) workovers and recompletions (excluding minor equipment repair and replacement), of which 67 gross (66 net) resulted in improved production or operating efficiencies, for an 87 percent success rate.

 

For 2005, a capital budget of $40 million has been allocated to U.S. exploitation activities. A total of 20 net development wells is initially planned to be drilled and workovers are also planned on approximately 45 wells during the year, principally in California, Louisiana and Texas. Activity in 2005 targets the continuation of an infill drilling program at the Gilmer South field in East Texas, expanded drilling programs and workover activity in the Luling, Darst Creek and West Ranch fields in South Central Texas and workover activity at our South Pass and Main Pass complexes in South Louisiana and the federal waters in the Gulf of Mexico, respectively.

 

To date in the first quarter of 2005, we have returned to production approximately 4,250 net BOE per day of the total 6,100 net BOE per day of production which was temporarily shut-in due to the mudslides in California during January. We currently estimate that we will complete the remaining repair of the mudslide damage for a total cost of approximately $8.5 million early in the second quarter of 2005.

 

During late 2003 and the first half of 2004 we drilled four exploration wells on two offshore Texas blocks (High Island 55-L and High Island 56-L), based on a Miocene gas exploration target coupled with the redevelopment of additional Miocene oil and gas sands. Facility and pipeline construction was completed in mid-2004 with an initial net daily production rate of approximately 10 MMcf contributing to a growth in our gas production during the third quarter of 2004.

 

In total for 2004, we drilled 10 exploration wells and recorded a success rate of 40 percent. Two Miocene prospects were drilled at Matagorda Island 639 and 640 during the second half of 2004 with both encountering apparent pay sands. We hold a 25 percent working interest in this offshore Texas prospect and expect these wells to be brought on line with the installation of production facilities anticipated in mid-2005.

 

Also during 2004, we initiated an exploration program focused on the longer-term development and production of natural gas from unconventional resources in the U.S., such as gas produced from shale, gas produced from coal and basin-centered gas produced from unusually tight sands. Unlike conventional exploration plays, the presence of hydrocarbons is not the highest element of risk. Rather, often the existence of hydrocarbons is known from wells drilled in prior years but the design of a cost effective method of economic development and extraction represent the greatest risk. Advances in fracture stimulation techniques coupled with the prospect of a continued elevated price for domestic natural gas have combined to make these resources economically viable to produce. However, much remains to be understood industry-wide regarding the factors which control the economic development of unconventional gas resources. The potential reward of pursuing an unconventional gas resource program is that if a play concept can be commercially produced, it has the capacity to be repeated multiple times over a large area with relatively low risk similar to mining. Throughout the year, we evaluated numerous unproven unconventional resource plays and selected a minimum of four plays to test during 2005.

 

We began 2005 with an inventory of 13 domestic exploration prospects and a capital budget of $64 million. The focus of our domestic exploration activity is split between conventional exploration targeting the Texas Gulf Coast and onshore unconventional gas resource plays. Twenty-six million dollars has been allocated to the unconventional gas resource exploration program to drill 10 wells during 2005 to test a minimum of four play concepts identified during 2004. In one of these plays, located in the Palo Duro basin of Texas, we have secured a substantial leased and optioned position in excess of 128,000 acres. The first of two planned exploratory wells to evaluate the commercial potential of the play has been drilled and is being evaluated. The second well is currently being drilled. We own working interests in this venture which range between 65 and 75 percent.

 

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Index to Financial Statements

An additional $38 million has been allocated to conventional exploration activities primarily targeting natural gas that can be brought to production quickly. This endeavor anticipates drilling 10 exploration wells to test prospects primarily located in the onshore and offshore Texas Gulf Coast. These projects are similar geologically to plays in which we were successful during 2004. We also control a 53 percent working interest in an opportunity to redevelop a Frio gas field with exploration upside in the onshore Texas Gulf Coast. A 3-D seismic survey of the area is scheduled to be completed during the second quarter of 2005 with drilling anticipated to commence in the third quarter.

 

Argentina. During 2004, we continued our successful growth program in Argentina. Non-acquisition capital spending of $93.2 million focused on drilling to convert proved undeveloped reserves to proved developed producing reserves and on secondary recovery activities, which we expect to contribute to production and reserves in the future. Reserve additions excluding purchases of reserves, net of reserve revisions, were 7.6 MMBOE replacing 67 percent of 2004 Argentina production.

 

A total of 81 gross (79 net) development wells was drilled at a success rate of 96 percent. A fifth drilling rig was added during the fourth quarter, reflecting the highest number of drilling rigs working since we began operations in Argentina. As a result of the revitalized drilling campaign and the acquisition in September of nearby properties with net oil production of 1.9 MBbls per day, net daily oil production now exceeds 31.0 MBbls. This is an all-time high level of oil production for us in Argentina.

 

We expect the business outlook for Argentina in 2005 to continue to be favorable and as a result, we anticipate additional production growth from Argentina in 2005. This expectation is supported by a capital budget of $113 million, which is a 21 percent increase over 2004 actual spending. Our 2005 budget includes drilling 110 development wells and performing 89 workovers. Our budget also includes the implementation of four waterflood projects which are targeted to contribute to production in 2005 and beyond.

 

Additionally, since our drilling program relies heavily on the interpretation of 3-D seismic data to aid in the optimum placement of wells, we plan to continue our program of recording 3-D seismic data during 2005. We believe this will allow us to continue to select drilling locations with higher initial production rates and higher ultimate oil recoveries than could otherwise be achieved. During 2004, additional 3-D surveys in Cerro Overo, Canadon Leon, Tres Picos and Cerro Wenseslao were completed with an additional 198,000 acres of data recorded.

 

The 3-D seismic activity planned in the 2005 budget will add approximately 90,000 acres in the San Jorge Basin of additional coverage. Once these programs are completed, approximately 64 percent of our total acreage in the San Jorge Basin will be covered by 3-D seismic data. We also have areas in the Cuyo Basin with 29 percent 3-D seismic coverage and the Neuquen Basin with no 3-D seismic coverage to date. Upon completion of the 2005 activity in progress, we will have 3-D data covering approximately 58 percent of all of our operated acreage in Argentina.

 

The number of development drilling locations in Argentina has increased substantially in recent years, from 331 at December 31, 2001, to 490 at December 31, 2004, due to a combination of development drilling and workover results integrated with interpretation of 3-D seismic data.

 

Bolivia. The focus for our operations in Bolivia continues to be on maximizing gas sales to existing markets and the development of new gas markets. During 2004, we saw a significant increase in gas production as we were able to support the additional demand for imported gas by Argentina. We did not have any capital expenditures during 2004 and do not anticipate any significant capital expenditures in Bolivia during 2005.

 

Yemen. On October 15, 2003, the Republic of Yemen’s Ministry of Oil and Minerals approved our S-1 Damis block development plan covering 285,000 acres for a term of 20 years. This plan follows the Lam sand discovery made by the An Nagyah #2 well in December 2002, which was further delineated in 2003 with the drilling of the An Nagyah #3 and #4 wells. We increased our Yemen oil and gas capital expenditures in 2004, spending a total of $33.7 million compared to $12.5 million in 2003.

 

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Index to Financial Statements

During 2004, we successfully drilled and completed eight consecutive development and appraisal wells in our An Nagyah field contributing to a 90 percent overall success rate for the year. Productive capacity from the An Nagyah wells is now approximately 12,000 Bbls (6,250 Bbls net) of oil per day. Oil production in Yemen made its initial contributions in the second quarter of 2004 and due to the successful development program in 2004, our daily production for the fourth quarter of 2004 averaged approximately 5,800 Bbls (3,028 Bbls net) before the impact of changes in inventories. Currently, production is trucked to a nearby existing pipeline and sent to an export facility. Work began in late 2004 on the construction of a permanent pipeline and central processing facility that is slated to have initial gross daily capacity of 10,000 Bbls of oil and is expected to be completed mid-2005.

 

We anticipate spending $31 million in Yemen during 2005 on development and exploration activities. Approximately $25 million of this spending will be for the completion of our production facilities and the drilling of four additional wells in the An Nagyah field in order to complete the development of the field. We will also continue to pursue our exploration program in Block S-1 and have allocated approximately $6 million for 2005. The Malaki exploration prospect was drilled in early 2005 but was unsuccessful. We anticipate the drilling of one additional exploration well and to continue assessing further development of our Harmel discovery.

 

Canada. In 2004, we significantly curtailed our capital spending as the result of disappointing operational results in 2003. Our total capital expenditures in Canada during 2004 were $17.7 million of which $11.8 million was for development projects and $5.9 million was spent on exploration activities. We drilled 29 gross (12 net) wells during 2004, 21 gross (seven net) of which were productive. For 2004, we added 1.8 MMBOE of reserves as a result of our activities replacing 56 percent of the production in Canada for 2004. On November 30, 2004, we sold all of our interests in Canada for total consideration of $274.7 million. (See “Divestitures.”)

 

Bulgaria. We have been awarded an exploration permit for the Bourgas-Deep Sea block in the exclusive economic zone of the Republic of Bulgaria in the western Black Sea. The permit’s initial exploration period expires in December 2005 and has provisions for extension. We have a 100 percent working interest and are the operator of this unexplored block that encompasses nearly 1.3 million acres (5,110 square kilometers). We acquired 1,575 kilometers of 2-D seismic data in 2003, and during 2004 completed detailed mapping of an identified large structural lead. During 2005, we expect to secure participation by an industry partner with deep water experience to drill and operate this prospect.

 

Oil and Gas Properties

 

At December 31, 2004, we owned and operated domestic producing properties in nine states, with our U.S. proved reserves located primarily in four core areas: West Coast, Gulf Coast, East Texas and Mid-Continent. In addition, we established core areas in Argentina during 1995, Bolivia during 1996 and Yemen during 2004. As of December 31, 2004, we operated 3,972 gross (3,804 net) productive wells and also owned non-operating interests in 486 gross (124 net) productive wells. We continuously evaluate the profitability of our oil, gas and related activities and we have a policy of divesting ourselves of unprofitable leases or areas of operations that are not consistent with our operating philosophy. (See “Divestitures.”)

 

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Index to Financial Statements

The following table sets forth estimates of our proved oil and gas reserves at December 31, 2004. The reserves are primarily estimated by the independent petroleum consultants of Netherland, Sewell & Associates, Inc. for the U.S., Argentina and Yemen and DeGolyer and MacNaughton for Bolivia. Fields comprising a total of 15.3 MMBOE, or four percent of our total proved reserves, are estimated by us.

 

     Oil (MBbls)

   Gas (MMcf)

  

MBOE

Total


     Developed

   Undeveloped

   Total

   Developed

   Undeveloped

   Total

  

West Coast

   48,514    3,923    52,437    83,435    3,821    87,256    66,980

Gulf Coast

   27,473    4,308    31,781    88,043    26,360    114,403    50,848

East Texas

   5,406    439    5,845    53,300    9,657    62,957    16,338

Mid-Continent

   748    63    811    14,851    1,861    16,712    3,596
    
  
  
  
  
  
  

Total U.S.

   82,141    8,733    90,874    239,629    41,699    281,328    137,762

Argentina

   108,692    86,280    194,972    42,371    88,470    130,841    216,779

Bolivia

   3,723    1,868    5,591    281,167    146,694    427,861    76,901

Yemen

   4,786    1,011    5,797    —      —      —      5,797
    
  
  
  
  
  
  

Total Company

   199,342    97,892    297,234    563,167    276,863    840,030    437,239
    
  
  
  
  
  
  

 

Estimates of our 2004 proved reserves set forth above have not been filed with, or included in reports to, any federal authority or agency, other than the Securities and Exchange Commission.

 

Proved reserves at December 31, 2004, include 49.2 MMBbls of oil and 9.9 Bcf of gas (50.9 MMBOE) related to the 10 year extension periods contained in our Argentina concession agreements. Proved developed reserves at December 31, 2004, include 25.6 MMBbls of oil and 0.4 Bcf of gas (25.6 MMBOE) related to these extension periods. Upon approval by the government, the extension periods begin in 2015 through 2017, depending on the effective date each concession agreement was granted. We believe, based on historical precedent, that such extensions will be obtained as a matter of course.

 

Our proved developed non-producing reserves are largely concentrated behind-pipe in fields which we operate. Proved undeveloped reserves are predominantly concentrated in development drilling locations and secondary recovery projects, most of which we operate.

 

The following is a brief discussion of our oil and gas operations in our core areas:

 

West Coast Area. The West Coast area includes oil and gas properties located primarily in Kern and Ventura counties and the Sacramento Basin of California. The Stevens, Forbes and Grubb formations are the dominant producing reservoirs on our acreage in California with well depths ranging from 800 feet to 14,300 feet. As of December 31, 2004, the area comprised 15 percent of our total proved reserves and 49 percent of our U.S. proved reserves. We currently operate 1,213 gross (1,182 net) productive wells in this area and we own an interest in 103 gross (eight net) productive wells operated by others. During 2004, net daily production for this area averaged approximately 11,700 BOE, or 38 percent of our total net daily U.S. production. Numerous workovers and recompletion opportunities exist in the San Miguelito and Rincon fields. Additional infill drilling locations are available in the San Miguelito, Pleito Ranch, and Tejon fields. The San Miguelito field also has waterflood potential that may add significant reserves and the Antelope Hills field has oil reserves that may be added through expansions of our steamflood project.

 

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Index to Financial Statements

Gulf Coast Area. The Gulf Coast area includes properties located in southern Texas, the southern half of Louisiana, Alabama, Mississippi and wells located in shallow state and federal waters. The reservoirs in the coastal waters and federal waters range in age from Pliocene to middle and upper Miocene and Oligocene. Reservoirs further onshore are predominantly from Eocene and Cretaceous ages. The depths of the producing reservoirs range from 1,200 feet to 14,500 feet. At December 31, 2004, the Gulf Coast area comprised approximately 12 percent of our total proved reserves and 37 percent of our U.S. proved reserves. We currently operate 759 gross (734 net) productive wells in this area and we own an additional interest in 31 gross (seven net) productive wells operated by others. During 2004, net daily production from this area averaged approximately 14,500 BOE, or 47 percent of our total net daily U.S. production. A significant inventory of workovers and recompletions exists in Gulf Coast fields from Alabama to south Texas. Development drilling potential is also available in various fields in Texas and Louisiana.

 

East Texas Area. The East Texas area includes properties located in the northeastern portion of Texas and the northern half of Louisiana. The Cotton Valley, Smackover and Travis Peak formations are the dominant producing reservoirs on our acreage in this area with wells ranging in depth from 1,300 feet to 14,800 feet. The East Texas area comprised approximately four percent of our December 31, 2004, total proved reserves and 12 percent of our U.S. proved reserves. We currently operate 537 gross (462 net) productive wells in this area and we own an interest in an additional 36 gross (five net) productive wells operated by others. During 2004, net daily production for this area averaged approximately 3,700 BOE, or 12 percent of our total net daily U.S. production. Significant infill drilling potential exists on our acreage in the South Gilmer and Southern Pine fields.

 

Mid-Continent Area. The Mid-Continent area extends from the Arkoma Basin of eastern Oklahoma to the Texas panhandle and north to include Kansas. The Red Fork, Morrow, Skinner and Hoxbar formations are the dominant producing reservoirs on our acreage in this area with well depths ranging from 1,560 feet to 17,260 feet. This area comprised one percent of our December 31, 2004, total proved reserves and three percent of our U.S. proved reserves. We currently operate 64 gross (30 net) productive wells in this area and we own an interest in an additional 67 gross (eight net) productive wells operated by others. During 2004, net daily production for this area averaged approximately 900 BOE, or three percent of our total net daily U.S. production. Projects to improve the ultimate reserve recovery exist in the Shawnee Townsite waterflood. Significant production response was observed in our Missouri Flats waterflood project during 2004 as we anticipated.

 

Argentina. Our Argentine properties consist primarily of 14 mature producing concessions located on the south flank of the San Jorge Basin, all of which we operate, four concessions located in the Cuyo Basin in western Argentina, two of which we operate, three concessions in the Neuquen Basin, two of which we operate and one concession in the northern flank of the San Jorge Basin which we operate. These concessions comprised approximately 50 percent of our December 31, 2004, total proved reserves. During 2004, net daily production averaged approximately 27,050 Bbls of oil, including the impact of changes in inventories, and 23.7 MMcf of gas. We currently operate 1,374 gross (1,374 net) productive wells. In addition, we own an interest in 249 gross (96 net) productive wells operated by others. At December 31, 2004, our proved reserves included approximately 490 development drilling locations on our Argentine acreage. In addition, we have an extensive inventory of workovers and development drilling locations on our Argentine properties which are not included in proved reserves.

 

Yemen. On October 15, 2003, the Republic of Yemen’s Ministry of Oil and Minerals approved our S-1 Damis block development plan covering 285,000 acres for a period of 20 years. We have a 75 percent working interest in this block which we operate. At year-end 2004, we have 10 gross (eight net) wells capable of production from the Lam Sand in the An Nagyah field. The current productive capacity of these wells is 6,250 Bbls net (12,000 Bbls gross) per day. We produced at a curtailed average of 3,028 net Bbls per day during the fourth quarter of 2004, as the production has to be temporarily trucked to a nearby existing pipeline for export. We expect to complete the construction of permanent pipeline and processing facilities by mid-2005 which will also allow us to produce at our productive capacity. At December 31, 2004, our proved reserves were 5.8 MMBbls of oil representing one percent of our December 31, 2004, total proved reserves. Included in proved reserves are two development drilling locations in the An Nagyah field.

 

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Index to Financial Statements

Bolivia. Our Bolivian properties consist of four producing concessions located in the Chaco Basin of Bolivia. We have a 100 percent working interest in the Naranjillos, Chaco Sur and Porvenir producing concessions. In the other producing concession, Nupuco, we have a 50 percent working interest. We operate all four producing concessions. These concessions comprise approximately 18 percent of our December 31, 2004, total proved reserves and include 15 gross (14 net) productive wells. Net daily production during 2004 averaged approximately 22.2 MMcf of gas and 243 Bbls of condensate. Current net daily productive capacity of our properties in Bolivia is approximately 28 MMcf of gas and 375 Bbls of condensate. We are working to develop additional gas markets, both domestic and export, to increase the level of production from our concessions.

 

Marketing

 

Generally, our U.S. oil production is sold under short-term contracts at posted prices, plus a premium in some cases, or at NYMEX prices less a specified differential. Our Argentine oil production is currently sold to Esso S.A.P.A. (the Argentine affiliate of Exxon Mobil Corporation), ENAP (the Chilean government-owned oil company) and Repsol YPF, S.A. at the spot price for West Texas Intermediate crude oil as quoted on the Platt’s Crude Oil Marketwire (“West Texas Intermediate”) (approximately equal to the NYMEX reference price) less a specified differential. During 2004, approximately 21 percent of our total revenues related to oil sales to ENAP and approximately 15 percent of our total revenues related to oil sales to Exxon Mobil Corporation and its affiliated companies.

 

In January 2002, the Argentine government devalued the Argentine peso (“peso”) and enacted an emergency law that, in part, required certain contracts that were previously payable in U.S. dollars to be payable in pesos. Subsequently, on February 13, 2002, the Argentine government announced a 20 percent tax on oil exports, effective March 1, 2002. In May 2004, the Argentine government increased the export tax from 20 percent to 25 percent. This tax is applied on the sales value after the tax, thus, the net effect of the 20 percent and 25 percent rates is 16.7 percent and 20 percent, respectively. In August 2004, the Argentine government further increased the export tax rates for oil exports. The export tax now escalates from 25 percent (20 percent effective rate) to a maximum rate of 45 percent (31 percent effective rate) of the realized value for exported barrels as West Texas Intermediate posted prices per Bbl increase from less than $32.00 to $45.00 and above. The export tax is deducted for income tax purposes but is not deducted in the calculation of royalty payments. The export tax expires in February 2007. Domestic Argentine oil sales, while valued in U.S. dollars, are now being paid in equivalent pesos. Export oil sales continue to be valued and paid in U.S. dollars.

 

We currently export approximately 35 percent of our Argentine oil production; however, in 2004 we exported approximately 48 percent. The U.S. dollar equivalent value for domestic Argentine oil sales (now paid in pesos) has generally moved toward parity with the U.S. dollar denominated export values, net of the export tax. The adverse impact of this tax has been partially offset by the net cost savings resulting from the devaluation of the peso on peso denominated costs and is further reduced by the Argentine income tax savings related to deducting the impact of the export tax.

 

On January 2, 2003, at the Argentine government’s request, crude oil producers and refiners agreed to limit amounts payable for certain domestic sales occurring during the first quarter 2003 to a maximum $28.50 per Bbl. The producers and refiners further agreed that the difference between the West Texas Intermediate posted price and the maximum price would be payable once the West Texas Intermediate posted price fell below the maximum. The debt payable under the original agreement accrues interest at eight percent. The total debt will be collected by invoicing future deliveries at $28.50 per Bbl after the West Texas Intermediate posted price falls below the maximum price. Additionally, the agreement allowed for renegotiation if the West Texas Intermediate reference price exceeded $35.00 per Bbl for 10 consecutive days, which occurred on February 24, 2003.

 

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Index to Financial Statements

On February 25, 2003, the agreement between the producers and the refiners was modified to limit the amount payable from refiners to producers for deliveries occurring between February 26, 2003, and March 31, 2003. While the $28.50 per Bbl payable maximum was maintained, under the modified terms refiners have no obligation to pay producers for sales values that exceed $36.00 per Bbl. Furthermore, interest for debts established during this period was reduced to seven percent. This agreement expired on April 30, 2004. Through December 31, 2004, the accumulated balance of amounts which we may charge to domestic oil purchasers in Argentina, if the West Texas Intermediate posted price decreases below the established maximum price in the future, was approximately $6.8 million, excluding interest. We do not have the right to invoice for such amounts until such time as the West Texas Intermediate posted price declines below the established maximum price of $28.50. Accordingly, we have adopted a revenue recognition accounting policy for this potential revenue in which we will record such revenue only upon the receipt of payment for this additional billing due to the uncertainty of recovery of such amounts and the timing thereof. During 2004, we did not record any revenue under this agreement. During 2003, we collected and recorded revenue of approximately $251,000. Such amounts represented all amounts we were entitled to invoice under the agreement. We sold approximately 0.6 MMBbls of our net Argentine oil production (approximately six percent) under this agreement in 2004.

 

Given the number of governmental changes during 2004 affecting the realized price we receive for our oil sales, no specific predictions can be made about the future of oil prices in Argentina; however, in the short term, we expect Argentine oil realizations to be less than oil realizations in the United States. For additional information, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Foreign Currency and Operations Risk” included elsewhere in this From 10-K.

 

Our U.S. gas production and gathered gas are generally sold on the spot market or under market-sensitive, long-term agreements with a variety of purchasers, including intrastate and interstate pipelines, their marketing affiliates, independent marketing companies and other purchasers who have the ability to move the gas under firm transportation agreements. Because very little of our U.S. gas is committed to long-term fixed-price contracts, we are positioned to take advantage of future strong gas price environments, but we are also subject to any future gas price declines. Most of our Bolivian gas production is sold at average gas prices tied to a long-term contract under which the base price is adjusted for changes in specified fuel oil indexes. Our Argentine gas is sold under spot contracts of varying lengths and, as a result of the emergency law enacted in January 2002, these contracts are now paid in pesos. This has resulted in a decrease in sales revenue value when converted to U.S. dollars due to the devaluation of the peso and current market conditions. This value is improving over time as domestic Argentine gas drilling declines and market conditions improve. Although no specific predictions can be made about future gas prices in Argentina, we expect our Argentine realized gas prices to continue to be less than U.S. realized gas prices.

 

Our U.S. gas marketing activities are handled by Vintage Gas, Inc., our wholly-owned gas marketing affiliate. This marketing affiliate generates a margin through the purchase and resale of both Company-produced and third party-produced gas volumes. Generally, the marketing affiliate purchases this gas on a month-to-month basis at a percentage of resale prices.

 

We have entered into certain firm gas transportation and compression agreements in Bolivia whereby we have committed to transport and compress certain volumes of gas at established government-regulated fees. While these fees are not fixed, they are government-regulated and therefore, we believe the risk of significant fluctuations is minimal. We entered into these arrangements to ensure our access to gas markets and we currently expect to produce sufficient volumes to utilize all of the contracted transportation and compression capacity under these arrangements. Based on the current fee level, these commitments total approximately $1.2 million in 2005, $1.3 million in 2006 and $0.3 million in each of the years 2007, 2008 and 2009.

 

We have also entered into “deliver-or-pay” arrangements where we have committed to deliver certain volumes of gas to third parties in Bolivia and Argentina for a specified period of time. These volumes will be sold at market prices. If the required volumes are not delivered, we must pay for the undelivered volumes at the then-current market price. Similar to the firm transportation and compression agreements, we entered into these arrangements to ensure our access to gas markets and we currently expect to produce sufficient volumes to satisfy all of our deliver-or-pay obligations. The volumes contracted under the agreement in Bolivia are 7.1 Bcf in 2005, 7.0 Bcf in 2006, 6.0 Bcf in 2007, 6.9 Bcf in 2008 and 6.9 Bcf in 2009. The volumes contracted under the agreement in Argentina are 6.1 Bcf in 2005, 3.3 Bcf in 2006, 3.6 Bcf in 2007 and 4.0 Bcf in 2008.

 

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Index to Financial Statements

We have previously entered into oil and gas derivative transactions and we intend to continue to consider various derivative transactions to realize commodity prices which we consider favorable. Derivative instruments that we consider using include swaps, options (including caps, floors and collars), futures and forward contracts. The counterparties to our current derivative transactions are commercial or investment banks.

 

We have entered into various oil price swap agreements covering approximately 7.2 MMBbls at a weighted average NYMEX reference price of $36.31 per Bbl for various periods of 2005, 2006 and 2007. The following table reflects the barrels covered by these oil price swaps and the corresponding weighted average NYMEX reference prices by quarter:

 

Quarter Ending


   Bbls

  

NYMEX

Reference Price

Per Bbl


March 31, 2005

   1,242,000    $ 37.77

June 30, 2005

   1,255,800      36.49

September 30, 2005

   1,269,600      35.57

December 31, 2005

   1,269,600      34.88

March 31, 2006

   427,500      37.39

June 30, 2006

   432,250      36.80

September 30, 2006

   437,000      36.32

December 31, 2006

   437,000      35.93

March 31, 2007

   189,000      34.26

June 30, 2007

   63,700      39.66

September 30, 2007

   64,400      39.38

December 31, 2007

   64,400      39.10

 

We have entered into various gas price swap agreements for various periods of 2005, 2006 and 2007 covering approximately 6.6 million MMBtu at a weighted average NYMEX reference price of $6.31 per MMBtu. The following table reflects the MMBtu covered by these gas price swaps and the corresponding weighted average NYMEX reference prices by quarter:

 

Quarter Ending


   MMBtu

  

NYMEX
Reference Price

Per MMBtu


March 31, 2005

   1,161,000    $ 6.65

June 30, 2005

   1,173,900      6.15

September 30, 2005

   1,186,800      6.17

December 31, 2005

   1,186,800      6.37

March 31, 2006

   243,000      6.47

June 30, 2006

   245,700      6.47

September 30, 2006

   248,400      6.47

December 31, 2006

   248,400      6.47

March 31, 2007

   225,000      6.00

June 30, 2007

   227,500      6.00

September 30, 2007

   230,000      6.00

December 31, 2007

   230,000      6.00

 

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Index to Financial Statements

We have also entered into various gas price collars for 2005 covering approximately 11.0 million MMBtu. The following table reflects the MMBtu covered by these gas price collars and the corresponding NYMEX floor and cap reference prices:

 

MMBtu For

      2005


  

NYMEX Floor

Reference

Price

Per MMBtu


  

NYMEX Cap

Reference
Price

Per MMBtu


1,825,000

   $ 6.00    $ 6.80

3,650,000

     6.00      8.02

1,825,000

     6.00      8.73

3,650,000

     6.00      9.21

 

We have entered into basis swap agreements for all of the gas volumes covered by price swaps and price collars. These basis swaps establish a differential between the NYMEX reference price and the various delivery points at levels that are comparable to the historical differentials we have received.

 

Reserves

 

At December 31, 2004, we had proved reserves of 437.2 MMBOE, comprised of 297.2 MMBbls of oil and 840.0 Bcf of gas. Fields comprising a total of 15.4 MMBOE or four percent of our total proved reserves are estimated by us and the remainder are estimated by the independent petroleum consultants of Netherland, Sewell & Associates, Inc. for the U.S., Argentina and Yemen and DeGolyer and MacNaughton for Bolivia. No reserve estimates have been filed with any federal authority or agency other than the SEC. For additional information on our oil and gas reserves, see “Oil and Gas Properties.” The following table sets forth, at December 31, 2004, the present value of future net revenues (revenues less production, development and abandonment costs) before income taxes attributable to our proved reserves at such date (in thousands):

 

Proved Reserves:

      

Future net revenues before income taxes

   $ 6,978,023

Present value of future net revenues before income taxes, discounted at 10 percent

     3,739,195

Standardized measure of discounted future net cash flows

     2,475,570

Proved Developed Reserves:

      

Future net revenues before income taxes

   $ 4,687,112

Present value of future net revenues before income taxes, discounted at 10 percent

     2,756,753

 

In computing this data, assumptions and estimates have been utilized, and we caution against viewing this information as a forecast of future economic conditions. The estimated future net revenues are determined by using estimated quantities of proved reserves and the periods in which they are expected to be developed and produced based on December 31, 2004, economic conditions. The estimated future production is valued at prices prevailing at December 31, 2004. The resulting estimated future gross revenues are reduced by estimated future costs to develop and produce the proved reserves based on December 31, 2004, cost levels, but such costs do not include debt service and general corporate overhead expenses.

 

Our proved reserves include amounts related to the 10 year extension periods contained in our Argentina concession agreements. Upon approval by the government, the extension periods begin in 2015 through 2017, depending on the effective date each concession agreement was granted. We believe, based on historical precedent, that such extensions will be obtained as a matter of course. The extension period reserves at December 31, 2004, consisted of 49.2 MMBbls of oil and 9.9 Bcf of gas (50.9 MMBOE). The proved reserves related to the extension periods represented $827.5 million of our future net revenues before income taxes, $208.7 million of our present value of future net revenues before income taxes, discounted at 10 percent and $117.1 million of our standardized measure of discounted future net cash flows. The proved developed reserves related to the extension periods represented $386.6 million of our future net revenues before income taxes and $125.2 million of our present value of future net revenues before income taxes, discounted at 10 percent.

 

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For additional information concerning the historical discounted future net revenues to be derived from these reserves and the disclosure of the Standardized Measure information in accordance with the provisions of Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities, see Note 11 “Supplementary Financial Information for Oil and Gas Producing Activities” to our consolidated financial statements included elsewhere in this Form 10-K.

 

The reserve data set forth in this Form 10-K represent estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. 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 of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and gas that are ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based.

 

For further information on reserves, costs relating to oil and gas activities and results of operations from producing activities, see Note 11 “Supplementary Financial Information for Oil and Gas Producing Activities” to our consolidated financial statements included elsewhere in this Form 10-K.

 

Productive Wells; Developed Acreage

 

The following table sets forth our productive wells and developed acreage assignable to such wells at December 31, 2004:

 

               Productive Wells

     Developed Acreage

   Oil

   Gas

   Total

     Gross

   Net

   Gross

   Net

   Gross

   Net

   Gross

   Net

U.S.

   443,390    302,186    2,229    2,048    581    388    2,810    2,436

Argentina

   241,776    205,226    1,606    1,453    17    17    1,623    1,470

Bolivia

   67,336    56,216    —      —      15    14    15    14

Yemen

   285,654    214,240    10    8    —      —      10    8
    
  
  
  
  
  
  
  

Total

   1,038,156    777,868    3,845    3,509    613    419    4,458    3,928
    
  
  
  
  
  
  
  

 

Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Wells which are completed in more than one producing horizon are counted as one well. All of our Yemen acreage is listed as developed since the entire acreage is now held by production under the terms of the concession agreement.

 

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Undeveloped Acreage

 

At December 31, 2004, we held the following undeveloped acres located in the U.S., Argentina, Italy and Bulgaria.

 

State/Country


  

Gross

Acres


  

Net

Acres


Alabama

   30,724    24,629

California

   15,836    9,425

Kansas

   1,140    1,140

Kentucky

   1,112    1,112

Louisiana

   16,286    3,779

New Mexico

   3,238    2,611

North Dakota

   1,000    269

Oklahoma

   3,879    2,405

Texas

   157,342    113,850
    
  

Total U.S.

   230,557    159,220
    
  

Argentina

   1,296,957    1,095,857

Italy

   275,107    275,107

Bulgaria

   1,262,707    1,262,707
    
  

Total Company

   3,065,328    2,792,891
    
  

 

With respect to such U.S. acreage held under leases, 229,925 gross (158,853 net) acres are held under leases with primary terms that expire at varying dates through December 31, 2009, unless commercial production has commenced. The remaining 632 gross (367 net) acres expire at various times from 2011 through 2014. We have the option to relinquish portions of our undeveloped acreage in Argentina at various dates through 2007 or pay increased lease rentals. Our acreage in Italy is held under exploration concessions that expire on March 31, 2007, unless commercial quantities of hydrocarbons are found and the concessions are converted to production concessions, which have a 30-year term. We can extend the term of the exploration concessions two times for a period of three years each time. However, each time an exploration concession is extended, we must relinquish 25 percent of its area. As a result of our unsuccessful exploration efforts in 2004, we are currently evaluating our future plans for this acreage. Our acreage in Bulgaria is held under our exploration permit, which expires in December 2005, with provisions for extension.

 

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Production; Unit Prices; Costs

 

The following table sets forth information with respect to production, average unit prices and costs for the periods indicated:

 

    Years Ended December 31,

 
    2004

    2003

    2002

 

Production:

                       

Oil (MBbls) -

                       

U.S.

    6,153       6,199       6,796  

Argentina (a)

    9,900 (b)     10,388       10,942  

Bolivia (a)

    89       83       118  

Yemen (a)

    514       —         —    

Continuing operations

    16,656       16,670       17,856  

Canada

    830       1,248       1,829  

Ecuador (a)

    —         114       1,174  

Total

    17,486       18,032       20,859  

Gas (MMcf) -

                       

U.S.

    30,459       23,097       24,841  

Argentina

    8,659 (b)     9,838       8,630  

Bolivia

    8,097       6,252       6,424  

Continuing operations

    47,215       39,187       39,895  

Canada

    14,077       19,153       29,951  

Total

    61,292       58,340       69,846  

MBOE from continuing operations

    24,525       23,201       24,505  

Total MBOE

    27,701       27,755       32,500  

Average Sales Price (including impact of hedges):

                       

Oil (per Bbl) -

                       

U.S.

  $ 29.29 (d)   $ 24.98     $ 21.78  

Argentina

    31.74       26.14       20.98 (c)

Bolivia

    23.42       23.04       20.73  

Yemen

    39.35       —         —    

Continuing operations

    31.02 (d)     25.70       21.28 (c)

Canada

    29.27       28.18       21.62  

Ecuador

    —         26.87       20.46  

Gas (per Mcf) -

                       

U.S.

  $ 5.55     $ 4.20     $ 2.85  

Argentina

    0.67 (e)     0.46 (e)     0.37 (e)

Bolivia

    1.71       2.01       1.54  

Continuing operations

    3.99       2.91       2.10  

Canada

    4.85       4.35       2.48  

 

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    Years Ended December 31,

 
    2004

    2003

    2002

 

Average Sales Price (excluding impact of hedges):

                       

Oil (per Bbl) -

                       

U.S.

  $ 36.97     $ 28.23     $ 22.66  

Argentina

    31.74       26.14       21.06 (c)

Bolivia

    23.42       23.04       20.73  

Yemen

    39.35       —         —    

Continuing operations

    33.86       26.91       21.66 (c)

Canada

    35.48       27.90       21.62  

Ecuador

    —         26.87       20.46  

Gas (per Mcf) -

                       

U.S.

  $ 5.54     $ 4.81     $ 2.94  

Argentina

    0.67 (e)     0.46 (e)     0.37 (e)

Bolivia

    1.71       2.01       1.54  

Continuing operations

    3.98       3.27       2.16  

Canada

    4.85       4.67       2.49  

Production Costs (per BOE):

                       

U.S.

  $ 9.43     $ 9.16     $ 8.05  

Argentina

    9.13       6.96       5.40  

Bolivia

    3.20       4.01       3.64  

Yemen

    8.13       —         —    

Continuing operations

    8.90       7.77       6.52  

Canada

    12.49       8.91       6.61  

Ecuador

    —         6.50       7.68  

(a) Oil production (in MBbls) before the impact of changes in inventories:

 

     Years Ended December 31,

     2004

    2003

   2002

Argentina

   10,347 (b)   10,273    10,771

Bolivia

   94     83    95

Yemen

   561     —      —  

Ecuador

   —       114    1,191

 

(b) Argentina production for the year ended December 31, 2004, is estimated to have been reduced by 527 MBbls of oil and 429 MMcf of gas, or 598 MBOE, as the result of a labor strike and problems at a major oil loading facility.
(c) Reflects the impact of the one-time government-mandated forced settlement of domestic Argentine oil sales which decreased the amounts for Argentina and total continuing operations average oil prices per Bbl for the year ended December 31, 2002, by $0.73 and $0.41, respectively.
(d) The average oil sales price per Bbl for the U.S. for the year ended December 31, 2004, does not reflect a realized loss of $1.78 per Bbl. The average oil sales price per Bbl for continuing operations for the year ended December 31, 2004, does not reflect a realized loss of $0.66 per Bbl. These losses have been reflected in non-operating expense as they relate to settlements on economic hedges. Economic hedges are derivative financial instruments, intended to hedge a specific exposure, that do not qualify or ceased to qualify for hedge accounting under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended, “SFAS 133”).
(e) Gas sales in Argentina during 2004, 2003 and 2002 were primarily billed and collected in Argentine pesos. The amount presented above represents the U.S. dollar equivalent price based on the average exchange rate for the period. Significant devaluation of the Argentine peso occurred during 2002. Although such sales are now substantially billed in U.S. dollar terms, the market price for gas continues to be less than 2001 levels.

 

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The components of production costs may vary substantially among wells depending on the methods of recovery employed and other factors, but generally include export taxes, production taxes, ad valorem taxes, transportation and storage costs, maintenance and repairs, labor and utilities.

 

Drilling Activity

 

During the periods indicated, we drilled or participated in the drilling of the following exploratory and development wells:

 

     Years Ended December 31,

     2004

   2003

   2002

     Gross

   Net

   Gross

   Net

   Gross

   Net

Development:

                             

United States -

                             

Productive

   28    23.31    26    22.71    2    1.42

Non-Productive

   3    2.50    5    3.64    —      —  

Argentina -

                             

Productive

   78    75.60    67    65.80    20    18.00

Non-Productive

   3    3.00    1    1.00    —      —  

Yemen

                             

Productive

   8    6.00    —      —      —      —  

Non-Productive

   —      —      —      —      —      —  

Canada -

                             

Productive

   19    5.60    24    13.40    39    28.70

Non-Productive

   3    1.80    1    1.00    10    8.40

Ecuador -

                             

Productive

   —      —      —      —      3    2.15

Non-Productive

   —      —      —      —      —      —  
    
  
  
  
  
  

Total

   142    117.81    124    107.55    74    58.67
    
  
  
  
  
  

Exploratory:

                             

United States -

                             

Productive

   4    2.15    1    0.33    1    0.35

Non-Productive

   6    3.26    1    0.42    1    0.25

Argentina

                             

Productive

   —      —      —      —      —      —  

Non-Productive

   1    0.40    —      —      —      —  

Yemen -

                             

Productive

   1    0.75    3    2.25    1    0.75

Non-Productive

   1    0.75    —      —      1    0.75

Italy -

                             

Productive

   —      —      —      —      —      —  

Non-Productive

   1    1.00    —      —      —      —  

Canada -

                             

Productive

   2    1.10    2    0.70    17    13.60

Non-Productive

   5    3.40    5    4.00    19    18.20
    
  
  
  
  
  

Total

   21    12.81    12    7.70    40    33.90
    
  
  
  
  
  

Total:

                             

Productive

   140    114.51    123    105.19    83    64.97

Non-Productive

   23    16.11    13    10.06    31    27.60
    
  
  
  
  
  

Total

   163    130.62    136    115.25    114    92.57
    
  
  
  
  
  

 

The above well information excludes wells in which we have only a royalty interest.

 

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At December 31, 2004, we were a participant in the drilling, completion or evaluation of 34 gross (29 net) wells. All of our drilling activities are conducted with independent contractors. We do not own any drilling equipment.

 

Seasonality

 

Historically, our results of operations are somewhat seasonal due to seasonal fluctuations in the price for gas with gas prices having been generally higher in the winter months. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of results which may be realized on an annual basis. The production of natural gas is generally not directly affected by seasonal swings in demand, except in Argentina and Bolivia. However, we may decide during periods of low commodity prices to decrease development activity, which can result in decreased gas production volumes. Production of oil usually is not affected by seasonal swings in demand or in market prices.

 

Competition

 

Competition in the oil and gas industry is intense. In seeking to acquire desirable producing properties, new leases and exploration prospects and in marketing oil and gas, we face competition from both major and independent oil and gas companies, as well as from numerous individuals and drilling programs. Many of these competitors have financial and other resources substantially in excess of those available to us. Alternative fuel sources also present competition.

 

Exploration for and production of oil and gas are affected by the availability of pipe, casing and other tubular goods and certain other oilfield equipment, including drilling rigs and tools. We are dependent upon independent drilling contractors to furnish rigs, equipment and tools to drill the wells we operate. The current environment of higher prices for oil and gas production is causing increased oilfield activity. Increased competition for these items as well as for drilling and workover rigs, in particular, has resulted in increased costs of operations and may impact the timing of our planned projects.

 

Regulation

 

Domestic Operations. The domestic oil and gas industry is extensively regulated by federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, have issued rules and regulations affecting the oil and gas industry and its individual members, some of which carry substantial penalties for non-compliance. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. Inasmuch as such laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such regulations.

 

Our exploration and production are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandoning of wells. Our operations are also subject to various conservation regulations, including regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of land and leases to facilitate exploration, while other states rely on voluntary pooling of land and leases. In addition, state conservation laws establish maximum, quarterly and/or daily allowable rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.

 

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Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect our exploration, development and production operations. For example, the discharge or substantial threat of a discharge of oil by us into U.S. waters or onto an adjoining shoreline may subject us to liability under the Oil Pollution Act of 1990 and similar state laws. While liability under the Oil Pollution Act of 1990 is limited under certain circumstances, such limits are so high that the maximum liability would likely have a significant adverse effect on us. Our operations generally will be covered by insurance which we believe is adequate for these purposes. However, there can be no assurance that such insurance coverage will always be in force or that, if in force, it will adequately cover any losses or liabilities we may incur. We are also subject to laws and regulations concerning occupational safety and health. It is not anticipated that we will be required in the near future to expend any amounts that are material in the aggregate to our overall operations by reason of environmental or occupational safety and health laws and regulations, but because such laws and regulations are frequently changed, we are unable to predict the ultimate cost of compliance.

 

Certain of our oil and gas leases are granted by the federal government and administered by various federal agencies. Such leases require compliance with detailed federal regulations and orders which regulate, among other matters, drilling and operations on these leases and calculation of royalty payments to the federal government. The Mineral Lands Leasing Act of 1920 places limitations on the number of acres under federal leases that may be owned in any one state. While subject to this law, we do not have a substantial federal lease acreage position in any state or in the aggregate. The Mineral Lands Leasing Act of 1920 and related regulations also may restrict a corporation from holding a federal onshore oil and gas lease if stock of such corporation is owned by citizens of foreign countries which are not deemed reciprocal under such Act. Reciprocity depends, in large part, on whether the laws of the foreign jurisdiction discriminate against a U.S. person’s ownership of rights to minerals in such jurisdiction. The purchase of our shares by citizens of foreign countries who are not deemed to be reciprocal under such Act could have an impact on our ownership of federal leases.

 

Federal legislation and regulatory controls have historically affected the price of the gas we produce and sell and the manner in which our production is marketed. Historically, the transportation and sale for resale of gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (the “NGA”), the Natural Gas Policy Act of 1978 (the “NGPA”) and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (the “FERC”). The Natural Gas Wellhead Decontrol Act of 1989 amended the NGPA to remove, as of January 1, 1993, the remaining natural gas wellhead pricing, sales, certificate and abandonment regulation of first sales that had been regulated by the FERC.

 

Commencing in 1985, the FERC, through Order Nos. 436, 500, 636 and 637, promulgated changes that significantly affect the transportation and marketing of gas. These changes have been intended to foster competition in the gas industry by, among other things, inducing or mandating that interstate pipeline companies provide nondiscriminatory transportation services to producers, distributors, buyers and sellers of gas and other shippers (so-called “open access” requirements). The FERC has also sought to expedite the certification process for new services, facilities, and operations of those pipeline companies providing “open access” services.

 

In 1992, the FERC issued Order 636. Among other things, Order 636 required each interstate pipeline company to “unbundle” its traditional wholesale services and create and make available on an open and nondiscriminatory basis numerous constituent services (such as gathering services, storage services, firm and interruptible transportation services, and stand-by sales services) and to adopt a new rate-making methodology to determine appropriate rates for those services. Each pipeline company was required to develop the specific terms of service in individual proceedings. Although the regulations do not directly regulate gas producers such as us, the availability of non-discriminatory transportation services and the ability of pipeline customers to modify or terminate their existing purchase obligations under these regulations have greatly enhanced the ability of producers to market their gas directly to end users and local distribution companies. In this regard, access to markets through interstate gas pipelines is critical to our marketing activities.

 

In 2000, the FERC issued Order 637 to make short-term capacity release more viable and to foster a more competitive and transparent market in which prices are more efficient. Among other things, Order 637 removes the price cap on short-term capacity releases, allows peak/off peak rates for short-term services to better reflect seasonal market demands and permits pipelines to propose term-differentiated rates to better reflect the underlying contracting risks of both pipelines and shippers.

 

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The FERC has issued a new policy regarding the use of nontraditional methods of setting rates for interstate gas pipelines in certain circumstances as alternatives to cost-of-service based rates. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative.

 

Under the NGA, gas gathering facilities are generally exempt from FERC jurisdiction. On the other hand, interstate transmission facilities are subject to FERC jurisdiction. The FERC has historically distinguished between these types of activities on a very fact-specific basis which makes it difficult to predict with certainty the status of our gathering facilities. While the FERC has not issued any order or opinion declaring our facilities as gathering rather than transmission facilities, we believe that these systems meet the traditional tests that the FERC has used to establish a pipeline’s status as a gatherer. As a result of the FERC’s decision to allow a number of interstate pipelines to spin-off gathering systems and thereby exempt them from federal regulation, some states enacted and others continually consider statutory and/or regulatory provisions to regulate gathering systems. Our gathering systems could be adversely affected should they be subjected in the future to the application of such state regulation.

 

With respect to oil pipeline rates subject to the FERC’s jurisdiction, in October 1993, the FERC issued Order 561 to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992. Order 561 established an indexing system, effective January 1, 1995, under which most oil pipelines will be able to readily change their rates to track changes in the Producer Price Index for Finished Goods (PPI-FG), minus one percent. This index established ceiling levels for rates. Order 561 also permits cost-of-service proceedings to establish just and reasonable rates. The order does not alter the right of a pipeline to seek FERC authorization to charge market-based rates. However, until the FERC makes the finding that the pipeline does not exercise significant market power, the pipeline’s rates cannot exceed the applicable index ceiling level or a level justified by the pipeline’s cost of service.

 

Foreign Operations. Our operations in Argentina are subject to the laws and regulations of the country. Beginning in December 2001, new measures have been enacted by law and executive order that may materially impact, among other items, (i) the realized prices we receive for oil and gas we produce and sell; (ii) the timing and amount of repatriations of cash to the U.S.; (iii) the amount of permitted export sales; (iv) the Argentine banking system; (v) our asset valuations; and (vi) peso-denominated monetary assets and liabilities. (See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency and Operations Risk.”)

 

Our operations in Bolivia, Yemen and Bulgaria are subject to various laws and regulations in those countries. Those laws and regulations, as currently imposed, are not anticipated to have a material adverse effect upon our operations.

 

Risk Factors

 

The nature of our business activities and operations subjects us to a number of risks and uncertainties. If any of the events described below were to occur, they could have a material adverse effect on our business, financial condition and operating results.

 

Oil and gas prices fluctuate widely, and low oil and gas prices could adversely affect, and in the past have adversely affected, our financial results.

 

Our revenues, operating results, cash flows and future rate of growth depend substantially upon prevailing prices for oil and gas. Historically, oil and gas prices and markets have been volatile and are likely to continue to be volatile in the future. The average prices that we currently receive for our production are higher than historical averages. However, a future significant decrease in oil and gas prices, such as that experienced in 1998 and the first half of 1999, could have a material adverse effect on our cash flows and profitability. The substantial and extended decline in oil and gas prices during 1998 and 1999 adversely affected our financial condition and results of operations. A sustained period of low prices could have a material adverse effect on our earnings and financial condition.

 

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Prices for oil and gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond our control, including:

 

    political conditions in oil producing regions, including the Middle East;

 

    domestic and foreign supplies of oil and gas;

 

    levels of consumer demand;

 

    weather conditions;

 

    domestic and foreign government regulations;

 

    prices and availability of alternative fuels; and

 

    overall economic conditions.

 

In addition, various factors may adversely affect our ability to market our oil and gas production, including:

 

    capacity and availability of oil and gas gathering systems and pipelines;

 

    effects of foreign, federal and state regulation of production and transportation;

 

    general economic conditions;

 

    changes in supply due to drilling by other producers;

 

    availability of drilling rigs; and

 

    changes in demand.

 

Lower oil and gas prices may adversely affect our level of capital expenditures, reserve estimates and borrowing capacity.

 

Lower oil and gas prices, such as those we experienced in 1998 and the first half of 1999, have various adverse effects on our business, including reducing cash flows which, among other things, have caused us in the past, and may cause us in the future, to decrease our capital expenditures. A smaller capital expenditure program may adversely affect our ability to increase or maintain our reserve and production levels. Lower prices may also result in reduced reserve estimates, write-offs of impaired assets and decreased earnings or losses due to lower reserves and higher depreciation, depletion and amortization expense. For example, in the fourth quarter of 1998 we recorded a significant non-cash charge for the impairment of oil and gas properties due to lower oil and gas prices.

 

The amount we can borrow under our revolving credit facility is subject to periodic redetermination based, in part, on expectations of future oil and gas prices applied to our oil and gas reserve estimates. Lower oil and gas prices could result in future reductions in the borrowing base under our revolving credit facility because lower oil and gas reserve values would reduce our liquidity and possibly trigger mandatory loan repayments. Furthermore, reduction in our liquidity could impede our ability to fund future acquisitions. Lower prices may also cause us to not be in compliance with maintenance covenants under our revolving credit facility and may negatively affect our credit statistics and coverage ratios.

 

Our future performance depends on our ability to find or acquire additional oil and gas reserves that are economically recoverable.

 

Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in oil and gas production and lower revenues and cash flows from operations. We have historically succeeded in substantially replacing reserves through acquisitions, exploration and development. We have conducted such activities on our existing oil and gas properties as well as on newly acquired properties. We may not be able to continue to replace reserves from such activities at acceptable costs. Lower oil and gas prices may further limit the types of reserves that can be developed at acceptable costs. Lower prices also decrease our cash flows and may cause us to reduce capital expenditures. The business of exploring for, developing or acquiring reserves is capital intensive. We may not be able to make the necessary capital investments to maintain or expand our oil and gas reserves if cash flows from operations are reduced and external sources of capital become limited or unavailable. In addition, exploration and development activities involve numerous risks that may result in dry holes, the failure to produce oil and gas in commercial quantities and the inability to fully produce discovered reserves.

 

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We are continually identifying and evaluating acquisition opportunities, including acquisitions that would be significantly larger than those we have consummated to date. We cannot ensure that we will successfully consummate any acquisition, that we will be able to acquire producing oil and gas properties that contain economically recoverable reserves or that any acquisition will be profitably integrated into our operations.

 

Acquisitions carry unknown risks including the potential for environmental problems.

 

Our focus on acquiring producing oil and gas properties may increase our potential exposure to liabilities and costs for environmental and other problems existing on such properties. We expect to continue to focus, as we have done in the past, on acquiring producing oil and gas properties to replace reserves. Although we perform reviews of the acquired properties that we believe are consistent with industry practice, such reviews are inherently incomplete. In general, it is not feasible to perform an in-depth review of each individual property being acquired. Ordinarily, we focus our review efforts on the higher-valued properties and sample the remainder. However, even an in-depth review of all properties and records may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on each well included in an acquisition, and environmental problems, such as ground water contamination and surface and subsurface damages from leakage, spills, disposal or other releases of hazardous substances on such properties or from adjoining properties that have migrated to such properties, are not necessarily observable even when an inspection is performed.

 

Estimating reserves and future net revenues involves uncertainties and negative revisions to reserve estimates and oil and gas price declines may lead to impairment of oil and gas assets.

 

Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The process relies on interpretations of available geological, geophysical, engineering and production data. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of developmental expenditures, including many factors beyond the control of the producer. The reserve data included in this Form 10-K represent estimates. In addition, the estimates of future net revenues from our proved reserves and the present value of such estimates are based on certain assumptions about future production levels, prices and costs that may not prove to be correct over time.

 

Quantities of proved reserves are estimated based on economic conditions in existence during the period of assessment. Lower oil and gas prices may have the impact of shortening the economic lives of certain fields because it becomes uneconomical to produce all recoverable reserves on such fields, which reduces proved property reserve estimates.

 

If negative revisions in the estimated quantities of proved reserves were to occur, it would have the effect of increasing the rates of depreciation, depletion and amortization on the affected properties, which would decrease earnings or result in losses through higher depreciation, depletion and amortization expense. The revisions may also be sufficient to trigger impairment losses on certain properties which would result in a further non-cash charge to earnings. For example, we recorded a significant non-cash charge for the impairment of proved oil and gas properties in the fourth quarter of 1998 due to lower oil and gas prices and we recorded significant non-cash charges for the impairment of proved oil and gas properties in the fourth quarter of 2002, in the second, third and fourth quarters of 2003 and in the fourth quarter of 2004 due to reserve revisions that resulted from additional geological, geophysical and engineering information and from revised production projections.

 

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Our international operations may be adversely affected by political and economic instability, changes in the legal and regulatory environment and other factors.

 

International investments represent, and are expected to continue to represent, a significant portion of our total assets. We have international operations in Argentina, Bolivia, Yemen and Bulgaria. For 2004, our operations in Argentina accounted for approximately 41 percent of our revenues from continuing operations and 38 percent of our total assets. During 2004, our operations in Argentina represented our only foreign operation accounting for more than 10 percent of our revenues from continuing operations or total assets. We continue to identify and evaluate international opportunities, but currently have no binding agreements or commitments to make any material international investment. As a result of such significant foreign operations, our financial results could be affected by factors such as changes in foreign currency exchange rates, weak economic conditions or changes in the political climate in these foreign countries.

 

Our foreign properties, operations or investments in Argentina, Bolivia, Yemen and Bulgaria may be adversely affected by political and economic instability, changes in the legal and regulatory environment and other factors. For example:

 

    local political and economic developments could restrict or increase the cost of our foreign operations;

 

    exchange controls and currency fluctuations could result in financial losses;

 

    royalty and tax increases and retroactive tax claims could increase costs of our foreign operations;

 

    expropriation of our property could result in loss of revenue, property and equipment;

 

    civil uprisings, riots, terrorist attacks and wars could make it impractical to continue operations, adversely affect both budgets and schedules and expose us to losses;

 

    import and export regulations and other foreign laws or policies could result in loss of revenues;

 

    repatriation levels for export revenues could restrict the availability of cash to fund operations outside a particular foreign country; and

 

    laws and policies of the U.S. affecting foreign trade, taxation and investment could restrict our ability to fund foreign operations or may make foreign operations more costly.

 

Particularly, our Bolivian projects are dependent, in part, on the continued operation of the Bolivia-to-Brazil gas pipeline and the further development of gas markets in South America. The operation of this pipeline and the development of markets are subject to various factors outside of our control. In addition, in the event of a dispute arising from foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts in the U.S. We may also be hindered or prevented from enforcing our rights with respect to actions taken by a foreign government or its agencies.

 

The Argentine economic and political situation continues to evolve and the Argentine government may enact future regulations or policies that, when finalized and adopted, may materially impact, among other items:

 

    the realized prices we receive for oil and gas that we produce and sell;

 

    the timing of repatriations of cash to the U.S.;

 

    the amount of permitted export sales;

 

    the Argentine banking system;

 

    our asset valuations; and

 

    peso-denominated monetary assets and liabilities.

 

See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Foreign Currency and Operations Risk” included elsewhere in this Form 10-K.

 

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Our derivative transactions may expose us to the risk of financial loss in certain circumstances.

 

We have previously entered into oil and gas derivative transactions and intend to continue to consider various derivative transactions to realize commodity prices which we consider favorable. The impact of changes in market prices for oil and gas on the average oil and gas prices we receive may be reduced based on the level of our derivative transactions that qualify for hedge accounting treatment. These derivative transactions may limit our potential gains if the market prices for oil and gas were to rise substantially over the price established by the derivative instrument. In addition, our derivative transactions expose us to the risk of financial loss in certain circumstances, including instances in which:

 

    production is less than expected;

 

    there is a widening of price differentials between delivery points for our production and the delivery point assumed in the accounting hedge arrangement; or

 

    the counterparties to our derivative transactions fail to honor their financial commitments.

 

We currently have price swap agreements covering 7.2 MMBbls of oil for various periods in 2005, 2006 and 2007 at a weighted average NYMEX reference price of $36.31 per Bbl and 6.6 million MMBtu of gas for various periods of 2005, 2006 and 2007 at a weighted average NYMEX reference price of $6.31 per MMBtu. We also have gas price collars covering approximately 11.0 million MMBtu with NYMEX floor reference prices of $6.00 per MMBtu and NYMEX cap reference prices ranging from $6.80 to $9.21 per MMBtu.

 

Uninsured risks associated with our operations could result in a substantial financial loss.

 

Our operations are subject to all of the risks and hazards typically associated with the exploitation, development and exploration for, and the production and transportation of oil and gas. These operating risks include, but are not limited to:

 

    blowouts, cratering and explosions;

 

    uncontrollable flows of oil, natural gas or well fluids;

 

    fires;

 

    formations with abnormal pressures;

 

    pollution and other environmental risks; and

 

    natural disasters.

 

Any of these events could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of such risks and losses. The occurrence of such an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

 

Governmental and environmental regulations could adversely affect our business.

 

Our business is subject to certain foreign, federal, state and local laws and regulations. These laws and regulations involve the exploration for, development, production and marketing of oil and gas, as well as taxation, environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste and other matters. Such laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning our oil and gas wells and other facilities. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could decrease our revenues.

 

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Our operations are subject to complex environmental laws and regulations adopted by the various jurisdictions where we operate. We could incur liabilities to governments or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water, including responsibility for remedial costs. We could potentially discharge such materials into the environment in any of the following ways:

 

    from a well or drilling equipment at a drill site;

 

    leakage from gathering systems, pipelines, transportation facilities and storage tanks;

 

    damage to oil and natural gas wells resulting from accidents during normal operations; and

 

    blowouts, cratering and explosions.

 

Because the requirements imposed by such laws and regulations are frequently changed, we cannot ensure that laws and regulations enacted in the future, including changes to existing laws and regulations, will not adversely affect our business. In addition, because we acquire interests in properties that have been previously operated by others, we may be liable for environmental damage caused by such former operators.

 

Industry competition may impede our growth.

 

The oil and gas industry is highly competitive, and we may not be able to compete successfully or grow our business. We compete in the areas of property acquisitions and the development, production and marketing of, and exploration for, oil and gas with major oil companies, other independent oil and gas concerns and individual producers and operators. We also compete with major and independent oil and gas concerns in recruiting and retaining qualified employees. Many of these competitors have substantially greater financial and other resources than us. We may not be able to successfully expand our business or attract or retain qualified employees.

 

Employees

 

We employ approximately 230 full-time people in our Tulsa office whose functions are associated with management, engineering, geology, land, legal, accounting, financial planning and administration. In addition, approximately 165 full-time employees are responsible for the supervision and operation of our U.S. field activities. We also employ approximately 290 people for the management and operation of our properties in Argentina, Bolivia and Yemen. We believe our relations with our employees are excellent.

 

Item 3. Legal Proceedings.

 

We are a named defendant in lawsuits and are a party in governmental proceedings from time to time arising in the ordinary course of business. While the outcome of such lawsuits or proceedings against us cannot be predicted with certainty, we believe the likelihood of a material adverse effect on our financial position or results of operations resulting from the resolution of such legal proceedings is remote.

 

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

 

There were no matters submitted to our stockholders during the fourth quarter of the fiscal year ended December 31, 2004.

 

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Item 4A. Executive Officers of the Registrant.

 

The following table sets forth as of the date hereof certain information regarding our executive officers. Officers are elected annually by the Board of Directors and serve at its discretion.

 

Name


  

Age


    

Position


Charles C. Stephenson, Jr.

   68     

Director, Chairman of the Board of Directors, President and Chief Executive Officer

William L. Abernathy

   53      Director, Executive Vice President and Chief Operating Officer

William C. Barnes

   50     

Director, Executive Vice President, Chief Financial Officer, Secretary and Treasurer

Larry W. Sheppard

   50      Senior Vice President - New Ventures

Kellam Colquitt

   57      Vice President - Exploration

Robert W. Cox

   59      Vice President - General Counsel

Murphy B. Herrington

   46      Vice President - Acquisitions

J. Chris Jacobsen

   49      Vice President - U.S. Operations

Andy R. Lowe

   53      Vice President - Marketing

Michael F. Meimerstorf

   48      Vice President and Controller

Robert E. Phaneuf

   58      Vice President - Corporate Development

Gary A. Watson

   47      Vice President - International

 

Mr. Stephenson, our co-founder, has been a Director since June 1983 and Chairman of our Board of Directors since April 1987. He assumed the position of President and Chief Executive Officer on February 18, 2004. He was previously our Chief Executive Officer from April 1987 to March 1994 and our President from June 1983 to May 1990. From October 1974 to March 1983, he was President of Santa Fe-Andover Oil Company (formerly Andover Oil Company), an independent oil and gas company (“Andover”), and from January 1973 to October 1974, he was Vice President of Andover. Mr. Stephenson has a B.S. Degree in Petroleum Engineering from the University of Oklahoma and has approximately 44 years of oil and gas experience.

 

Mr. Abernathy has been a Director since October 1999, and an Executive Vice President and our Chief Operating Officer since December 1997. He was our Senior Vice President—Acquisitions from March 1994 to December 1997, our Vice President—Acquisitions from May 1990 to March 1994 and our Manager—Acquisitions from June 1987 to May 1990. From June 1976 to June 1987, Mr. Abernathy was employed by Exxon Company USA, where he served at various times as Senior Staff Engineer, Senior Supervising Engineer and in other engineering capacities, with assignments in drilling, production and reservoir engineering in the Gulf Coast and offshore. He has B.S. and M.S. Degrees in Mechanical Engineering from Auburn University.

 

Mr. Barnes, a certified public accountant, has been a Director, and our Treasurer and Secretary since April 1987, an Executive Vice President since March 1994 and our Chief Financial Officer since May 1990. He was also a Senior Vice President from May 1990 to March 1994 and our Vice President—Finance from January 1984 to May 1990. From November 1982 to December 1983, Mr. Barnes was an audit manager for Arthur Andersen & Co., an independent public accounting firm, where he dealt primarily with clients in the oil and gas industry. He was Assistant Controller—Finance of Andover from December 1980 to November 1982. From June 1976 to December 1980, he was an auditor with Arthur Andersen & Co., where he dealt primarily with clients in the oil and gas industry. Mr. Barnes has a B.S. Degree in Business Administration from Oklahoma State University.

 

Mr. Sheppard has been our Senior Vice President—New Ventures since July 2003. He was our Vice President—New Ventures from May 2001 to July 2003. From November 1994 to May 2001, he was our Vice President—International. From June 1984 to August 1994, he was employed by Santa Fe Minerals serving as Manager—Acquisitions & Special Projects, Manager—International Operations, and in various other management and supervisory capacities. From August 1977 to June 1984, he was employed by Amoco Production Company serving in various engineering and supervisory capacities. He has a B.S. Degree in Petroleum Engineering from Texas Tech University.

 

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Index to Financial Statements

Mr. Colquitt has been our Vice President—Exploration since May 2001. From April 2000 to May 2001, he was our General Manager—North American Exploration. He was employed by Ranger Oil Company, an independent oil and gas company, from August 1995 to January 2000 where he served as Vice President, International Exploration—Western Hemisphere and Vice President, U.S. Operations. From December 1983 to July 1995 he was employed by Santa Fe Minerals serving as Manager—International Exploitation, Exploration and Production, and in various other management and supervisory capacities. He was President of Colquitt Exploration, Inc. from 1978 to December 1983, providing contract exploration services. From 1971 to 1978, he served in various geology and supervisory capacities for Placid Oil Company. He has a B.S. Degree in Geology from Texas A&M University.

 

Mr. Cox has been our Vice President—General Counsel since March 1988. From August 1982 to March 1988, he was employed by Santa Fe Minerals and its subsidiary, Andover, where he served at various times as Vice President—Law and Regional Attorney. From April 1982 to August 1982, he was employed as Corporate Attorney by Andover. Prior to that time, Mr. Cox was employed by Amerada Hess Corporation, a major oil company, served as General Counsel and Secretary of Kissinger Petroleum Corporation, an independent oil and gas company, and served on the legal staff of Champlin Petroleum Company, an independent oil and gas company. He has a B.S. Degree in Business Administration with a major in Petroleum Marketing from the University of Tulsa, and a Juris Doctor from the University of Michigan Law School.

 

Mr. Herrington has been our Vice President—Acquisitions since June 2003. He was our Acquisitions Technical Manager from May 1998 to June 2003 and an Acquisitions Engineer with us from March 1993 to May 1998. From December 1980 to March 1993, he was employed by Exxon Company USA, serving as a Reservoir Engineer. He has a B.S. Degree in Chemical Engineering from Mississippi State University.

 

Mr. Jacobsen has been our Vice President—U.S. Operations since November 2002. Mr. Jacobsen was Senior Vice President of various exploitation and exploration staffs for KCS Energy, Inc. and Medallion Production Company, independent oil and gas companies, from 1994 to 2002. He was Senior Vice President at Netherland, Sewell & Associates, Inc., an independent petroleum engineering firm, where he managed engineering and geological teams from 1982 to 1994. From 1977 to 1982, he held various engineering and supervisory assignments with Exxon Company USA in Lafayette and New Orleans, Louisiana. He has a B.S. Degree in Chemical Engineering from Rose Hulman Institute of Technology.

 

Mr. Lowe has been our Vice President—Marketing since December 1997. He was our General Manager—Marketing from July 1992 to December 1997. He was President of Quasar Energy, Inc. from November 1990 to July 1992, providing downstream natural gas marketing services. From September 1983 to November 1990, he was employed by Maxus Energy Corporation, formerly Diamond Shamrock Exploration Company, serving as Manager—Marketing and in various other management and supervisory capacities. From 1981 to September 1983, he was employed by American Quasar Exploration Company as Manager—Oil and Gas Marketing. From 1978 to 1981, he was employed by Texas Pacific Oil Company serving in various positions in production and marketing. He has a B.S. Degree in Education from Texas Tech University.

 

Mr. Meimerstorf, a certified public accountant, has been our Controller since January 1988 and a Vice President since May 1990. He was our Accounting Manager from February 1984 to January 1988. From April 1981 to February 1984, he was the Financial Reporting Supervisor for Andover. From June 1979 to April 1981, he was an auditor with Arthur Andersen & Co. He has a B.S. Degree in Accounting from Arkansas Tech University and an M.B.A. Degree from the University of Arkansas.

 

Mr. Phaneuf has been our Vice President—Corporate Development since October 1995. From June 1995 to October 1995, he was employed in the Corporate Finance Group of Arthur Andersen LLP, specializing in energy industry corporate finance activities. From April 1993 to August 1994, he was Senior Vice President and head of the Energy Research Group at Kemper Securities, an investment banking firm. From 1988 until April 1993, he was employed by Rauscher, Pierce Refsnes, Inc., an investment banking firm, as a Senior Vice President, serving as an energy analyst involved in equity research. From 1978 to 1988, Mr. Phaneuf was Vice President of Kidder, Peabody, & Co., an investment banking firm, serving as an energy analyst in the Research Department. From 1976 to 1978, he was employed by Schneider, Bernet, and Hickman, serving as an energy analyst in the Research Department. From 1972 to 1976, he held the position of Investment Advisor for First International Investment Management, a subsidiary of NationsBank. He holds a B.A. Degree in Psychology and an M.B.A. Degree from the University of Texas.

 

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Index to Financial Statements

Mr. Watson has been our Vice President—International since January 2005. From June 2001 to January 2005, he was our Vice President—Canadian Operations. He was our General Manager—Latin American Operations from February 1998 to June 2001 and General Manager—Vintage Oil Argentina, Inc. from August 1995 to February 1998. From March 1987 to July 1995, he was employed by Santa Fe Minerals where he held various engineering and management positions serving most recently as Manager of Project Development. From August 1985 to January 1987, he was employed by Williams Exploration Company as an engineer, with assignments in operations and reservoir engineering. From September 1984 to July 1985, he was Bank Representative in the Energy Group of Texas Commerce Bank. From May 1979 to August 1984, he was employed by Texaco, Inc. as an engineer in the New Orleans Division. He has a B.S. Degree in Chemical Engineering (Petroleum Option) from the University of Pittsburgh.

 

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PART II

 

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

 

Our common stock commenced trading on the New York Stock Exchange on August 3, 1990, under the symbol “VPI.” The following table sets forth the high and low sales prices per share of our common stock, as reported in the New York Stock Exchange composite transactions, and the cash dividends paid per share of our common stock for the periods indicated:

 

     High

   Low

  

Dividends

Paid


2004

                    

First Quarter

   $ 15.60    $ 11.52    $ 0.045

Second Quarter

     17.58      13.61      0.045

Third Quarter

     20.53      15.11      0.050

Fourth Quarter

     24.50      19.10      0.050

2003

                    

First Quarter

   $ 11.46    $ 9.00    $ 0.040

Second Quarter

     12.34      9.10      0.040

Third Quarter

     12.10      10.51      0.045

Fourth Quarter

     12.93      10.14      0.045

 

Substantially all of our stockholders maintain their shares in “street name” accounts and are not, individually, stockholders of record. As of December 31, 2004, our common stock was held by 199 holders of record and approximately 12,250 beneficial owners.

 

We began paying a quarterly cash dividend in the fourth quarter of 1992 and we continued paying a regular quarterly cash dividend through the first quarter of 1999. Due to the historically low oil and gas price environment during the first quarter of 1999, we suspended our regular quarterly cash dividend for the remainder of 1999. We re-instituted the payment of dividends beginning in the first quarter of 2000 with a $0.025 per share cash dividend and we expect to continue paying a regular quarterly cash dividend.

 

Our credit arrangements (including the indentures for our outstanding senior and senior subordinated indebtedness) contain certain restrictions on distributions to common stockholders, including the payment of cash dividends. However, none of these restrictions materially limit our ability to pay dividends at this time. Subject to these restrictions in our credit arrangements, the determination of the amount of future cash dividends, if any, to be declared or paid, will depend on, among other things, our financial condition, funds from operations, the level of our capital expenditures and our future business prospects.

 

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Item 6. Selected Financial Data.

 

SELECTED FINANCIAL AND OPERATING DATA

 

     Years Ended December 31,

     2004

   2003

    2002

    2001

    2000

     (In thousands, except per share amounts and operating data)

Statement of Operations Data:

                                     

Oil, condensate and NGL sales

   $ 516,756    $ 428,350     $ 380,032     $ 426,067     $ 476,278

Gas sales

     188,582      114,049       83,902       194,108       171,177

Gas marketing revenues

     71,476      70,633       54,391       103,087       128,836

Total revenues

     778,180      614,747       518,978       723,535       778,014

Operating and administrative costs

     349,876      300,483       251,380       313,285       316,436

Exploration costs

     31,993      21,607       22,942       15,942       22,486

Depreciation, depletion and amortization

     103,202      87,814       104,872       113,541       97,444

Impairment of proved oil and gas properties

     6,049      6,050       16,972       10,155       225

Accretion

     6,626      5,980       —         —         —  

Interest

     51,815      69,834       77,314       64,181       48,412

Loss on early extinguishment of debt

     9,903      6,909       8,154       —         —  

Income from continuing operations before cumulative effect of changes in accounting principles

     125,441      59,494       34,971       159,572       170,974

Income (loss) from discontinued operations, net of income taxes

     207,151      (307,520 )     (118,088 )     (26,065 )     25,933

Income (loss) before cumulative effect of changes in accounting principles

     332,592      (248,026 )     (83,117 )     133,507       196,907

Net income (loss)

     332,592      (240,907 )     (143,664 )     133,507       195,893

Income per share from continuing operations before cumulative effect of changes in accounting principles:

                                     

Basic

     1.93      0.93       0.55       2.53       2.73

Diluted

     1.91      0.92       0.55       2.49       2.67

Income (loss) per share before cumulative effect of changes in accounting principles:

                                     

Basic

     5.11      (3.87 )     (1.31 )     2.12       3.15

Diluted

     5.06      (3.85 )     (1.31 )     2.09       3.08

Income (loss) per share:

                                     

Basic

     5.11      (3.76 )     (2.27 )     2.12       3.13

Diluted

     5.06      (3.74 )     (2.26 )     2.09       3.06

Dividends declared per share

     0.20      0.18       0.16       0.14       0.14
    

  


 


 


 

Balance Sheet Data (end of year):

                                     

Total assets

   $ 1,644,892    $ 1,454,259     $ 1,775,804     $ 2,107,902     $ 1,352,002

Long-term debt

     549,949      699,943       883,180       1,010,673       464,229

Stockholders’ equity

     683,678      422,486       570,992       729,443       624,857
    

  


 


 


 

 

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     Years Ended December 31,

     2004

   2003

   2002

   2001

   2000

     (In thousands, except per share amounts and operating data)

Operating Data:

                                  

Production:

                                  

Oil (MBbls)

     17,486      18,032      20,859      21,974      19,861

Gas (MMcf)

     61,292      58,340      69,846      75,641      53,729

BOE

     27,701      27,755      32,500      34,581      28,816
    

  

  

  

  

Average Sales Prices:

                                  

Oil (per Bbl)

   $ 30.94    $ 25.88    $ 21.27    $ 21.93    $ 25.55

Gas (per Mcf)

     4.19      3.38      2.26      3.30      3.22
    

  

  

  

  

Proved Reserves (end of year):

                                  

Oil (MBbls)

     297,234      292,798      348,697      332,261      318,560

Gas (MMcf)

     840,030      926,038      1,083,546      1,216,724      1,023,208

Total proved reserves (MBOE)

     437,239      447,138      529,288      535,048      489,095

Present value of estimated future net revenues before income taxes discounted at 10 percent (in thousands)

   $ 3,739,195    $ 3,506,125    $ 4,009,322    $ 1,914,073    $ 4,338,616

Standardized measure of discounted future net cash flows (in thousands)

     2,475,570      2,382,528      2,746,257      1,438,141      2,951,121
    

  

  

  

  

 

Significant acquisitions of producing oil and gas properties during 2004 and 2001 and significant dispositions of oil and gas properties during 2004, 2003, 2002 and 2001 affect the comparability between the Financial and Operating Data for the years presented above. The statement of operations data reflect the presentation of our operations in Trinidad, Canada and Ecuador as discontinued operations for all periods. (See Note 7 to our consolidated financial statements included elsewhere in this Form 10-K.) The operating data include the results from discontinued operations for all periods.

 

The amounts in the “Proved Reserves (end of year)” section above include amounts related to the 10 year extension periods contained in our Argentina concession agreements. See Note 11 to our consolidated financial statements included elsewhere in this Form 10-K.

 

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

 

Overview

 

We are an independent energy company with operations primarily in the exploration and production and gas marketing segments of the oil and gas industry. We have operations or exploration activities in the U.S., South America, Yemen, and Bulgaria. We are focused on the acquisition of oil and gas properties which contain the potential for increased value through exploitation and exploration. In addition, we are focused on continuing to build an inventory of exploration prospects in the U.S. that may impact production in the near term as well as high potential frontier prospects that may impact production in the longer term.

 

During 2002 and 2003, we focused on managing our financial leverage, maintaining liquidity and positioning ourselves for long-term growth. As a result of the acquisitions in Canada and Argentina in 2001, we ended 2001 with $1.0 billion of long-term debt. Since that time, we have improved our balance sheet and leverage position by reducing long-term debt to $550 million. In addition, we have $124 million of cash at December 31, 2004. We funded this reduction in debt with proceeds from property sales and cash provided by operating activities and by reducing our capital expenditures. In addition to cash on hand, as of February 28, 2005, we have unused availability under our revolving credit facility of $296.6 million (considering outstanding letters of credit of approximately $3.4 million).

 

Beginning in 2003 and continuing through 2004, after achieving our goal of debt reduction, we focused on our core objectives of acquisitions, exploitation and exploration and significantly increased our capital expenditure budget. We were able to complete two acquisitions of producing properties, one in September 2004 in Argentina at a total cost of $34.9 million and one in the United States in December 2004 at a total cost of $77.2 million. This increased focus on our core objectives resulted in a significant improvement in our production levels and our operating results.

 

We reported net income of $332.6 million in 2004 versus a net loss of $240.9 million in 2003. Our 2004 profitability was significantly impacted by a $198.5 million after tax gain from the sale of our Canadian operations plus strong production levels in our continuing operations and higher oil and gas prices. The loss in 2003 was driven by non-cash charges for impairments of our Canadian oil and gas properties and goodwill as a result of negative revisions to our Canadian reserves. While the 2003 results were disappointing, our liquidity and financial position remained strong as these non-cash charges had no material adverse impact on our financial covenants under our debt instruments.

 

Our cash provided by continuing operations for 2004 was $337.6 million, which was 59 percent greater than 2003, as a result of significantly higher oil and gas prices and a six percent increase in production on a BOE basis. In addition, during 2004 we sold all of our Canadian operations generating $241.5 million of proceeds, net of cash sold, which we used to fund acquisitions and eliminate our outstanding advances under our revolving credit facility and provide available cash for future activities.

 

We have 437.2 MMBOE of oil and gas reserves as of December 31, 2004, reflecting the sale of 13.2 MMBOE of reserves and production of 27.7 MMBOE in 2004. Excluding the additions and revisions to our Canadian reserves, we added 29.2 MMBOE to our reserves, at a cost of $11.90 per BOE, replacing 119 percent of our production. During 2004, we increased our acquisition, exploration and development activities and we made oil and gas capital expenditures of $365.2 million, spending 108 percent of our cash provided by continuing operations.

 

Our focus for 2005 is to continue profitability with increased production and reserve growth from a balance of acquisitions, exploitation and exploration. We have established our 2005 non-acquisition oil and gas capital expenditure budget at $250 million, which is consistent with our spending in 2004. We expect to have sufficient internally generated cash flows to fund our non-acquisition capital expenditures. In the event we successfully secure acquisitions of oil and gas properties, we will seek appropriate levels of oil and gas price risk management and equity capital in order to maintain or improve our capital structure.

 

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Our future financial results depend on a number of factors, including, in particular, oil and gas prices, our ability to find or acquire oil and gas reserves, access to capital, our ability to control costs and both domestic and foreign regulatory developments. Commodity prices are impacted by many factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain volatile. Oil and gas prices are affected by changes in market demands, overall economic activity, political events, weather, inventory storage levels, basis differentials and other factors. As a result, we can not accurately predict future oil and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital programs, production volumes, future revenues or our ability to acquire oil and gas properties. In addition to production volumes and commodity prices, acquiring, finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success.

 

Results of Operations

 

Our results of operations have been significantly affected by our success in acquiring oil and gas properties and our ability to maintain or increase production through our exploitation and exploration activities. Acquisitions of producing oil and gas properties during 2004 and significant dispositions of producing properties during 2004, 2003 and 2002 affect the comparability of operating data for the periods presented in the tables below. Fluctuations in oil and gas prices have also significantly affected our results. The following tables reflect our oil and gas production and our average oil and gas prices for the periods presented:

 

     Years Ended December 31,

     2004

    2003

   2002

Production:

               

Oil (MBbls) -

               

U.S.

   6,153     6,199    6,796

Argentina (a)

   9,900 (b)   10,388    10,942

Bolivia (a)

   89     83    118

Yemen (a)

   514     —      —  
    

 
  

Continuing operations

   16,656     16,670    17,856

Canada

   830     1,248    1,829

Ecuador (a)

   —       114    1,174

Total

   17,486     18,032    20,859

Gas (MMcf) -

               

U.S.

   30,459     23,097    24,841

Argentina

   8,659 (b)   9,838    8,630

Bolivia

   8,097     6,252    6,424
    

 
  

Continuing operations

   47,215     39,187    39,895

Canada

   14,077     19,153    29,951

Total

   61,292     58,340    69,846

MBOE from continuing operations

   24,525     23,201    24,505

Total MBOE

   27,701     27,755    32,500

(a) Oil production (in MBbls) before the impact of changes in inventories:

 

     Years Ended December 31,

     2004

    2003

   2002

Argentina

   10,347 (b)   10,273    10,771

Bolivia

   94     83    95

Yemen

   561     —      —  

Ecuador

   —       114    1,191

 

(b) Argentina production for the year ended December 31, 2004, is estimated to have been reduced by 527 MBbls of oil and 429 MMcf of gas, or 598 MBOE, as the result of a labor strike and problems at a major oil loading facility.

 

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     Years Ended December 31,

 
     2004

    2003

    2002

 

Average Sales Price (including impact of hedges):

                        

Oil (per Bbl) -

                        

U.S.

   $ 29.29 (b)   $ 24.98     $ 21.78  

Argentina

     31.74       26.14       20.98 (a)

Bolivia

     23.42       23.04       20.73  

Yemen

     39.35       —         —    

Continuing operations

     31.02 (b)     25.70       21.28 (a)

Canada

     29.27       28.18       21.62  

Ecuador

     —         26.87       20.46  

Gas (per Mcf) -

                        

U.S.

   $ 5.55     $ 4.20     $ 2.85  

Argentina

     0.67 (c)     0.46 (c)     0.37 (c)

Bolivia

     1.71       2.01       1.54  

Continuing operations

     3.99       2.91       2.10  

Canada

     4.85       4.35       2.48  

Average Sales Price (excluding impact of hedges):

                        

Oil (per Bbl) -

                        

U.S.

   $ 36.97     $ 28.23     $ 22.66  

Argentina

     31.74       26.14       21.06 (a)

Bolivia

     23.42       23.04       20.73  

Yemen

     39.35       —         —    

Continuing operations

     33.86       26.91       21.66 (a)

Canada

     35.48       27.90       21.62  

Ecuador

     —         26.87       20.46  

Gas (per Mcf) -

                        

U.S.

   $ 5.54     $ 4.81     $ 2.94  

Argentina

     0.67 (c)     0.46 (c)     0.37 (c)

Bolivia

     1.71       2.01       1.54  

Continuing operations

     3.98       3.27       2.16  

Canada

     4.85       4.67       2.49  

(a) Reflects the impact of the one-time government-mandated forced settlement of domestic Argentine oil sales which decreased the amounts for Argentina and continuing operations average oil prices per Bbl for the year ended December 31, 2002, by $0.73 and $0.41, respectively.
(b) The average oil sales price per Bbl for the U.S. for the year ended December 31, 2004 does not reflect a realized loss of $1.78 per Bbl. The average oil sales price per Bbl for continuing operations for the year ended December 31, 2004, does not reflect a realized loss of $0.66 per Bbl. These losses have been reflected in non-operating expense as they relate to settlements on economic hedges. Economic hedges are derivative financial instruments, intended to hedge a specific exposure, that do not qualify or ceased to qualify for hedge accounting under SFAS 133.
(c) Gas sales in Argentina during 2002 and 2003 were primarily billed and collected in Argentine pesos. The amount presented above represents the U.S. dollar equivalent price based on the average exchange rate for the period. Significant devaluation of the Argentine peso occurred during 2002. Although such sales are now substantially billed in U.S. dollar terms, the market price for gas continues to be less than 2001 levels.

 

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Oil Prices

 

Average U.S. oil prices we receive generally fluctuate with changes in the NYMEX reference price for oil. Our oil production in Argentina is sold at West Texas Intermediate spot prices as quoted on the Platt’s Crude Oil Marketwire (approximately equal to the NYMEX reference price) less a specified differential. Our Yemen oil production is sold at Dated Brent prices as quoted in Platt’s Crude Oil Marketwire less a specified differential. In 2004, we experienced a 21 percent increase in our average oil price from continuing operations, including the impact of hedging activities (26 percent increase excluding hedging activities), compared to 2003. We experienced a 21 percent increase in our average oil price from continuing operations, including the impact of hedging activities (24 percent increase excluding hedging activities) in 2003 compared to 2002. Our realized average oil price from continuing operations for 2004 (before hedges) was approximately 82 percent of the NYMEX reference price, compared to 87 percent in 2003 and 83 percent in 2002.

 

During late 2004 and early in 2005 when the NYMEX reference price for crude oil was at or above $45 per barrel, our contract differentials on our California and Argentina properties increased, thus lowering our average realized oil prices as a percent of NYMEX. If future NYMEX reference prices stay at or above this level our realized price as a percentage of NYMEX may be lower than our previous historical relationships.

 

As discussed in Note 1 to our consolidated financial statements included elsewhere in this Form 10-K, the Argentine government took actions which, in effect, caused the devaluation of the peso in early December 2001 and, in February 2002, enacted an emergency law that, in part, required certain contracts that were previously payable in U.S. dollars to be payable in pesos. Subsequently, on February 13, 2002, the Argentine government announced a 20 percent tax on oil exports, effective March 1, 2002. In May 2004, the Argentine government increased the export tax from 20 percent to 25 percent. This tax is applied on the sales value after the tax, thus, the net effect of the 20 percent and 25 percent rates is 16.7 percent and 20 percent, respectively. In August 2004, the Argentine government further increased the export tax rates for oil exports. The export tax now escalates from 25 percent (20 percent effective rate) to a maximum rate of 45 percent (31 percent effective rate) of the realized value for exported barrels as West Texas Intermediate posted prices per Bbl increase from less than $32.00 to $45.00 and above. The export tax is deducted for income tax purposes but is not deducted in the calculation of royalty payments. The export tax expires in February 2007. Given the number of governmental changes during 2004 affecting the realized price we receive for our oil sales, no specific predictions can be made about the future of oil prices in Argentina; however, in the short term, we expect Argentine oil realizations to be less than oil realizations in the United States. Export oil sales continue to be valued and paid in U.S. dollars. For additional information, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Foreign Currency and Operations Risk” included elsewhere in this Form 10-K. Domestic Argentine oil sales, while valued in U.S. dollars, are now being paid in equivalent pesos.

 

We currently export approximately 35 percent of our Argentine oil production; however, in 2004 we exported approximately 48 percent. The U.S. dollar equivalent value for domestic Argentine oil sales (now paid in pesos) has generally moved toward parity with the U.S. dollar-denominated export values, net of the export tax. The adverse impact of this tax has been partially offset by the net cost savings from the devaluation of the peso on peso-denominated costs and is further reduced by the Argentine income tax savings related to deducting the impact of the export tax.

 

On January 2, 2003, at the Argentine government’s request, crude oil producers and refiners agreed to limit amounts payable for certain domestic sales occurring during the first quarter of 2003 to a maximum $28.50 per Bbl. The producers and refiners further agreed that the difference between the West Texas Intermediate posed price and the maximum price would be payable once the West Texas Intermediate posted price fell below the maximum. The debt payable under the original agreement accrues interest at eight percent. The total debt will be collected by invoicing future deliveries at $28.50 per Bbl after the West Texas Intermediate posted price falls below the maximum price. Additionally, the agreement allowed for renegotiation if the West Texas Intermediate reference price exceeded $35.00 per Bbl for 10 consecutive days, which occurred on February 24, 2003.

 

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On February 25, 2003, the agreement between the producers and the refiners was modified to limit the amount payable from refiners to producers for deliveries occurring between February 26, 2003, and March 31, 2003. While the $28.50 per Bbl payable maximum was maintained, under the modified terms refiners have no obligation to pay producers for sales values that exceed $36.00 per Bbl. Through December 31, 2004, the accumulated balance of amounts which we may charge to domestic oil purchasers in Argentina, if the West Texas Intermediate posted price decreases below the established maximum price in the future, was approximately $6.8 million, excluding interest. We do not have the right to invoice for such amounts until such time as the West Texas Intermediate posted price declines below the established price cap of $28.50. Accordingly, we have adopted a revenue recognition accounting policy for this potential revenue in which we will record such revenue only upon the receipt of payment for this additional billing due to the uncertainty of recovery of such amounts and the timing thereof. During 2004, we did not record any revenue under this agreement. During 2003, we collected and recorded revenue of approximately $251,000. Such amounts represented all amounts we were entitled to invoice under the agreement. We sold approximately 0.6 MMBbls of our net Argentine oil production (approximately six percent) under this agreement in 2004.

 

To the extent that derivative financial instruments qualify for accounting treatment as cash flow hedges, we record the cash settlements as an adjustment to oil and gas sales. We participated in oil price swaps covering 5.6 MMBbls, 4.9 MMBbls and 4.9 MMBbls in 2004, 2003 and 2002, respectively. We accounted for all of the 2002 and 2003 oil price swaps as cash flow hedges and we accounted for 5.0 MMBbls of the 2004 oil price swaps as cash flow hedges. The impact of the cash settlements under oil price swaps accounted for as cash flow hedges are reflected in the preceding tables. The impact of the 0.6 MMBbls under the 2004 oil price swaps not accounted for as cash flow hedges did not impact reported oil sales, as these cash settlements were recorded in non-operating income or expense.

 

Gas Prices

 

Average U.S. gas prices we receive generally fluctuate with changes in spot market prices, which may vary significantly by region. Most of our Bolivian gas production is sold at average gas prices tied to a long-term contract under which the base price is adjusted for changes in specified fuel oil indexes. Our Argentine gas is sold under spot contracts of varying lengths, which, as a result of the emergency law enacted in January 2002, are now paid in pesos. This has initially resulted in a decrease in sales revenue value when converted to U.S. dollars due to the devaluation of the peso and current market conditions. Market prices for gas in Argentina have historically been significantly less than developed countries, such as the U.S. This is due primarily to limited gas markets and gas infrastructure in the region whose developed supplies have been sufficient to meet both internal demand and allow for exports to Chile. Pursuant to an emergency law passed on January 10, 2002, utility tariffs were converted to Argentine pesos and then frozen by the Argentine government. As a result, we experienced a further reduction in the prices offered for our gas production subsequent to 2001. This value may improve over time as domestic Argentine gas drilling declines and market conditions improve. Our total average gas price from continuing operations for 2004 was 37 percent higher than 2003, including the impact of hedging activities (22 percent higher excluding hedging activities), and for 2003 was 39 percent higher than for 2002, including the impact of hedging activities (51 percent higher excluding hedging activities).

 

We participated in gas price swaps covering 3.7 million MMBtu, 20.1 million MMBtu and 13.5 million MMBtu in 2004, 2003 and 2002, respectively. All of these gas price swaps were accounted for as cash flow hedges. The impacts of the cash settlements under these cash flow hedges on our average gas prices are reflected in the preceding tables.

 

Future Period Hedges

 

We have previously entered into oil and gas derivative transactions and we intend to continue to consider various derivative transactions to realize commodity prices which we consider favorable. We have entered into various oil price swap agreements covering approximately 7.2 MMBbls at a weighted average NYMEX reference price of $36.31 per Bbl for various periods in 2005, 2006 and 2007. We have entered into various gas price swap agreements for various periods of 2005, 2006 and 2007 covering approximately 6.6 million MMBtu at a weighted average NYMEX reference price of $6.31 per MMBtu. We have also entered into various gas price collars for 2005 covering approximately 11.0 million MMBtu with NYMEX floor reference prices of $6.00 per MMBtu and NYMEX cap reference prices ranging from $6.80 to $9.21 per MMBtu. For additional information, see “Items 1 and 2. Business and Properties - Marketing” included elsewhere in this Form 10-K. The counterparties to our current hedging arrangements are commercial or investment banks.

 

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Relatively modest changes in either oil or gas prices significantly impact our results of operations and cash flows. However, the impact of changes in the market prices for oil and gas on our average realized prices may be reduced from time to time based on the level of our derivative transactions that qualify for hedge accounting treatment. Based on 2004 oil production from continuing operations, a change in the average oil price we realize, before hedges, of $1.00 per Bbl would result in a change in net income and revenues less production and export taxes on an annual basis of approximately $9.6 million and $15.1 million, respectively. A $0.10 per Mcf change in the average gas price we realize, before hedges, would result in a change in net income and revenues less production and export taxes on an annual basis of approximately $3.0 million and $4.6 million, respectively, based on 2004 gas production from continuing operations.

 

Period to Period Comparisons

 

The period to period comparisons presented below are significantly affected by acquisitions and dispositions we made during the periods. On July 30, 2002, we completed the sale of our operations in Trinidad. We received $40 million in cash and recorded a gain of $31.9 million ($14.9 million after income taxes). On January 31, 2003, we completed the sale of our operations in Ecuador. We received $137.4 million in cash and recorded a gain of $47.3 million ($9.5 million after income taxes). On November 30, 2004, we completed the sale of our Canadian operations. We received $274.7 million in cash and recorded a gain of $167.8 million ($198.5 million after income taxes).

 

Our Canadian operations began during 2000 with the acquisition of Cometra for $52 million. In May 2001, we purchased Genesis for $617 million (based on the exchange rate at date of payment). We also recognized goodwill of $175 million in the Genesis acquisition. After the Genesis acquisition, we merged Cometra into Genesis and the combined operation became our only Canadian reporting unit.

 

As a result of lower than planned realized gas prices in Canada and the disappointing results we experienced in our exploration and development activities, primarily in 2003, we were unable to achieve the results we anticipated when we made the acquisitions of Cometra and Genesis. As a result, we recorded impairments of all of the goodwill recorded in the Genesis acquisition and a substantial portion of our Canadian proved and unproved properties during the period of 2001 through 2003, as discussed further in Note 1 to the accompanying consolidated financial statements.

 

Due to the poor results of our Canadian exploration and development activities during the last half of 2003, we decided to substantially curtail exploration and development activities for our Canadian operations, which resulted in a significant reduction of our estimate of proved reserves. We had not made a decision to sell such operations at that time as we were still evaluating the best course of action to take related to such operations. During 2004, we determined that we would sell all of our Canadian operations. As a result of the improved commodity price outlook and what we believed to be a very attractive divestiture market at the time, which was being fueled by the acquisition activities of the Canadian income trusts, we recognized a gain on sale of such assets.

 

In accordance with the rules established by Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”), our operations in Trinidad, Ecuador and Canada, along with the gains on the sales, are accounted for as discontinued operations in our consolidated financial statements. Accordingly, the revenues and expenses discussed below exclude the results related to our operations in Trinidad, Ecuador and Canada for all periods.

 

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We reported net income of $332.6 million for the year ended December 31, 2004, a net loss of $240.9 million for the year ended December 31, 2003, and a net loss of $143.7 million for the year ended December 31, 2002. Net income for the year ended December 31, 2004, included:

 

    income from discontinued operations of $207.0 million which includes an after tax gain on sale of our Canadian operations of approximately $198.5 million;

 

    a loss on early extinguishment of debt of $9.9 million ($6.0 million net of tax);

 

    derivative losses of $21.7 million ($13.3 million net of tax); and

 

    increased export taxes on export sales of Argentine crude oil of $12.0 million resulting primarily from increased export sales revenue and an increase in the export sales tax rate.

 

The net loss for the year ended December 31, 2003, included:

 

    a loss from discontinued operations of $307.5 million due primarily to a non-cash charge of $364.1 million ($210.8 million net of tax) for the impairment of Canadian proved oil and gas properties and a non-cash charge of $25.7 million for the impairment of Canadian goodwill;

 

    a gain of $11.2 million ($7.1 million net of tax) for the cumulative effect of a change in an accounting principle for the adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, (“SFAS 143”);

 

    a loss on early extinguishment of debt of $6.9 million ($4.2 million net of tax);

 

    a loss on disposition of assets of $1.2 million ($0.7 million net of tax); and

 

    a loss from foreign currency translations of $6.7 million.

 

The net loss for the year ended December 31, 2002, included:

 

    a loss from discontinued operations of $118.1 million due primarily to a non-cash charge of $81.7 million ($60.4 million net of tax) for the impairment of Canadian proved oil and gas properties and a non-cash charge of $76.4 million for the impairment of Canadian goodwill;

 

    a loss of $60.5 million for the cumulative effect of a change in an accounting principle for the adoption of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (“SFAS 142”);

 

    a loss on early extinguishment of debt of $8.2 million ($5.0 million net of tax); and

 

    a net gain on disposition of assets of $16.6 million ($10.1 million net of tax).

 

Oil, condensate and NGL sales. Oil, condensate and NGL sales increased $88.4 million, 21 percent, to $516.7 million for 2004 from $428.3 million for 2003 due to a 21 percent increase in our average oil price during 2004. Oil volumes sold during 2004 were essentially flat compared to 2003. Increased volumes from our Yemen operations were more than offset by reduced sales volumes in Argentina of approximately 0.5 MMBbls resulting from a labor strike and problems at a major oil loading facility. In addition, weather delays in late December, which affected shipping, resulted in an increase in Argentine crude oil inventories at December 31, 2004 of 0.4 MMBbls.

 

Oil, condensate and NGL sales increased $48.3 million, 13 percent, to $428.3 million for 2003 from $380.0 million for 2002 due to the offsetting effects of a 21 percent increase in our average oil price during 2003 and a seven percent decrease in our oil production. The production decline was primarily due to the sale of non-strategic U.S. oil and gas properties in June 2002 and March 2003, natural production declines and the effects of substantially curtailed capital expenditures in 2002, which resulted in significantly lower production levels at the beginning of 2003. Capital expenditures were reduced significantly as a result of our decision to use a portion of our cash flow and proceeds from asset sales to execute our debt reduction program in 2002.

 

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Gas sales. Gas sales increased $74.6 million, 65 percent, to $188.6 million for 2004 from $114.0 million for 2003. The increase is the result of a 37 percent increase in our average gas price along with a 20 percent increase in gas production during 2004 compared to 2003. Gas production in the U.S. increased primarily as a result of exploitation successes, the most significant of which resulted from the gas recompletion and drilling activities in Texas. Bolivia gas production has also increased primarily as a result of Argentina’s increased demand for imported gas. These increases were slightly offset by the production decreases of 429 MMcf of gas in Argentina related to the labor strike and major oil loading facility problems discussed above. There were no similar disruptions in 2003.

 

Gas sales increased $30.1 million, 36 percent, to $114.0 million for 2003 from $83.9 million for 2002 due to the offsetting effects of a 39 percent increase in our average gas price and a two percent decrease in gas production during 2003 compared to 2002. The decline in production was due primarily to the sale of non-strategic U.S. oil and gas properties in June 2002 and March 2003, natural production declines and the effects of substantially curtailed capital expenditures in 2002, as discussed above.

 

Production costs. Production costs increased $16.6 million, 13 percent, to $141.0 million for 2004 from $124.4 million for 2003. On an equivalent barrel basis, production costs increased by seven percent to $5.75 for 2004 from $5.36 for 2003. These increases are primarily due to costs incurred in 2004 to repair damage resulting from the October 2003 fires in California, significantly increased workover activity and higher U.S. power costs.

 

Production costs increased $12.5 million, 11 percent, to $124.4 million for 2003 from $111.9 million for 2002. On an equivalent barrel basis, production costs increased by 17 percent to $5.36 for 2003 from $4.57 for 2002. The increase was primarily the result of higher costs (expressed in U.S. dollars) in Argentina resulting from peso inflation and strengthening of the peso relative to the U.S. dollar. The increase was partially offset by reductions in expenses due to property sales in the U.S. during 2002 and 2003. The increase on an equivalent barrel basis was also impacted by a five percent decline in production from 2002 to 2003.

 

Transportation and storage costs. Transportation and storage costs increased $3.7 million, 50 percent, to $11.1 million for 2004 from $7.4 million for 2003. These increases are primarily the result of trucking costs associated with our new Yemen production area. We began incurring these costs in 2004 to deliver our product to a nearby processing facility. There was no equivalent charge in 2003. Our processing facility and pipeline is currently in the design and fabrication stage and completion of the 10,000 gross barrels per day facility is scheduled for mid-2005. Our transportation and storage costs per BOE increased from $0.32 in 2003 to $0.45 in 2004.

 

Transportation and storage costs increased $0.4 million, six percent, to $7.4 million for 2003 from $7.0 million for 2002. These increases are primarily due to the strengthening of the Argentine peso relative to the U.S. dollar.

 

Production and ad valorem taxes. Production and ad valorem taxes increased $5.5 million, 32 percent, to $23.0 million for 2004 from $17.5 million for 2003. These increases are primarily the result of higher U.S. oil and gas prices and an increase in U.S. production on an equivalent barrel basis of 12 percent during 2004.

 

Production and ad valorem taxes increased $2.0 million, 13 percent, to $17.5 million for 2003 from $15.4 million for 2002. These increases are primarily the result of higher U.S. oil and gas prices during 2003.

 

Export taxes. Export taxes in Argentina increased $12.0 million, 39 percent, to $43.0 million for 2004 from $31.0 million for 2003. While our Argentine domestic sales volumes as a percent of our total sales volumes have increased in 2004 compared to 2003, the impact of higher oil prices and the increased export tax rates in 2004 offset the decreases in export volumes. The export tax rate increased from 20 percent to 25 percent in May 2004 and was further increased in August 2004. The average effective export tax rate for 2004 on our exported volumes was 22.6 percent.

 

Export taxes in Argentina increased $6.2 million, 25 percent, to $31.0 million for 2003 from $24.8 million for 2002. The increase is due primarily to higher oil prices in 2003 and to the fact that export taxes were only in effect for 10 months in 2002.

 

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Index to Financial Statements

Exploration costs. Exploration costs increased $10.4 million, 48 percent, to $32.0 million for 2004 from $21.6 million for 2003. Exploration costs for 2004 consisted of $10.8 million for seismic and other geological and geophysical costs, $16.5 million for unsuccessful exploratory drilling and $4.7 million for impairment of unproved leaseholds. During 2003, our exploration costs included $10.0 million for seismic and other geological and geophysical costs, $7.3 million for unsuccessful exploratory drilling and $4.3 million for impairment of unproved leaseholds.

 

Exploration costs decreased $1.3 million, six percent, to $21.6 million for 2003 from $22.9 million for 2002. During 2002, our exploration costs included $5.0 million for seismic and other geological and geophysical costs, $13.9 million for unsuccessful exploratory drilling and $4.0 million for impairment of unproved leaseholds.

 

General and administrative expenses. General and administrative expenses increased $9.6 million, 20 percent, to $56.5 million for 2004 from $46.9 million for 2003. The increase is due primarily to higher employee bonus expenses and severance benefits for a former executive in 2004 with no corresponding amounts in 2003. As a result of these compensation-related expenses, our general and administrative expenses per BOE increased from $2.02 in 2003 to $2.30 in 2004.

 

General and administrative expenses increased $8.3 million, 22 percent, to $46.9 million for 2003 from $38.6 million for 2002. The increase is due primarily to Argentine asset taxes and cash bonuses in 2003 with no comparable amounts in 2002. These increases, along with a five percent decline in production from 2002 to 2003, increased our general and administrative expenses per BOE to $2.02 in 2003 from $1.57 in 2002.

 

Stock compensation. Stock compensation increased $2.3 million, 45 percent, to $7.6 million in 2004 from $5.3 million in 2003. In March 2004, we entered into a separation agreement with a former executive under which we extended the period in which he could exercise his outstanding vested stock options to the end of the term of the options. Under the terms of the non-vested stock award agreements with the former executive, all of the non-vested shares granted to him under these agreements became fully vested as of his termination date. As a result of these events, we recorded additional non-cash stock compensation expense of approximately $2.2 million in 2004. In June 2004, we recorded stock compensation expense of $1.1 million related to the vesting of certain performance-based non-vested stock grants. There were no comparable charges in 2003.

 

Stock compensation increased $4.4 million, 522 percent, to $5.3 million in 2003 from $0.9 million in 2002. Stock compensation expense relates primarily to non-vested stock awards. We granted approximately 1.2 million and 417,000 non-vested stock awards in 2003 and 2002, respectively. These awards generally vest over a one to three year period and the compensation expense is amortized over the vesting period. The 2003 grants included 563,000 non-vested stock awards that were issued in exchange for options to purchase 2.1 million shares of our common stock. Also, in 2003, we began expensing stock options on a prospective basis and recorded expense of $0.1 million in 2003 with no corresponding amount in 2002.

 

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased $15.4 million, 18 percent, to $103.2 million for 2004 from $87.8 million for 2003. Our average oil and gas amortization rate per BOE increased to $4.08 for 2004 from $3.63 for 2003 due to increases in our finding costs during 2003 and 2004. A production increase of six percent on an equivalent barrel basis led to the increase in total depreciation, depletion and amortization during 2004.

 

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Depreciation, depletion and amortization decreased $17.1 million, 16 percent, to $87.8 million for 2003 from $104.9 million for 2002. Our average oil and gas amortization rate per BOE decreased to $3.63 for 2003 from $4.09 for 2002. The decrease primarily resulted from the impact that substantially higher product prices in 2003 had in increasing proved reserves used to determine the amortization rate and, to a lesser extent, our mandated adoption of SFAS 143. Previously, we accrued an undiscounted estimate of future abandonment costs of wells and related facilities through our depreciation calculation in accordance with the provisions of Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, (“SFAS 19”) and industry practice. With the adoption of SFAS 143, we have now recorded a discounted fair value of the future retirement obligation as a liability with a corresponding amount capitalized as part of the related property’s carrying amount. The discounted capitalized asset retirement cost is amortized to expense through the depreciation calculation over the estimated useful life of the asset based on proved developed reserves. The liability accretes over time with a charge to accretion expense, which was $6.0 million for 2003. As a result of the implementation of SFAS 143, we recorded a non-cash gain of $11.2 million ($7.1 million net of tax) as a cumulative effect of change in accounting principle.

 

Impairment of proved oil and gas properties. We recorded expense for the impairment of certain U.S. proved oil and gas properties of $6.0 million in 2004, $6.1 million in 2003 and $17.0 million in 2002. These impairments in all three years resulted from a downward revision of our estimate of those properties’ proved oil and gas reserves based on production performance. See Note 1 to the accompanying consolidated financial statements for a discussion of our policy for recording impairments of proved oil and gas properties. Due to the volatility of oil and gas prices, it is possible that our assumptions regarding oil and gas prices may change in the future. If in the future price expectations are reduced or estimated proved reserves are revised downward, it is possible that additional significant impairment provisions for proved oil and gas properties would be required.

 

Other operating costs. Other operating costs decreased $3.8 million, 62 percent, to $2.3 million in 2004 from $6.1 million in 2003. This decrease is due to a $6.0 million gain recorded from a settlement of a certain contract claim that we had against a third party. Other operating costs were essentially unchanged from 2002 to 2003.

 

Interest expense. Interest expense decreased $18.0 million, 26 percent, to $51.8 million for 2004 from $69.8 million for 2003 due to a 12 percent reduction in our average debt outstanding and a 13 percent decrease in our average interest rate during 2004. During the first quarter of 2004, we advanced funds under our revolving credit facility to redeem the entire $150 million principal balance of our 9 3/4% senior subordinated notes due 2009. In December 2004, we used a portion of the proceeds from the sale of our Canadian operations to reduce all borrowings under our revolving credit facility. At December 31, 2004, our average interest rate on our then outstanding debt was 8.1 percent.

 

Interest expense decreased $7.5 million, 10 percent, to $69.8 million for 2003 from $77.3 million for 2002 due to a 21 percent reduction in our average debt outstanding.

 

Loss on early extinguishment of debt. In connection with the redemption of our senior subordinated notes during 2004, as discussed above, we were required to pay call premiums on the notes and expense certain associated deferred financing costs and discounts related to the notes, resulting in losses on early extinguishment of debt of $9.9 million ($6.0 million after tax) in 2004. This compares to losses on early extinguishment of debt of $6.9 million ($4.2 million after tax) in 2003 and $8.2 million ($5.0 million after tax) in 2002, as discussed below.

 

In 2003, we redeemed the remainder of our 9% senior subordinated notes and the entire balance of our 8 5/8% senior subordinated notes using advances under our revolving credit facility. As a result, we were required to expense the remaining associated deferred financing costs and discounts. This $3.0 million non-cash charge and a $3.9 million cash charge for the call premium on the redemption of these notes resulted in a charge of $6.9 million in 2003.

 

In 2002, in conjunction with the issuance of our 8 1/4% senior notes, we redeemed a portion of our 9% senior subordinated notes and entered into a new $300 million revolving credit facility. We were required to expense certain associated deferred financing costs and discounts. This $5.2 million non-cash charge, along with a $3.0 million cash charge for the call premium on the 9% senior subordinated notes, resulted in a charge of $8.2 million in 2002.

 

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Index to Financial Statements

Gain or loss on disposition of assets. A net loss on disposition of assets of $1.2 million ($0.7 million net of tax) was reflected in 2003 related to sales of certain U.S. Mid-Continent gas properties. Total proceeds from these sales were $30.0 million. In 2002, we recorded a net gain on disposition of assets of $16.6 million ($10.1 million net of tax) primarily related to the sale of our heavy oil properties in the Santa Maria area of Southern California. The 2002 gain included the reversal of our accrual for future abandonment costs related to the sold properties.

 

Foreign currency exchange (gain) loss. We recorded foreign currency exchange gains of $0.8 million in 2004, foreign currency exchange losses of $6.7 million in 2003 and a foreign currency exchange gain of $0.3 million in 2002. These gains and losses are primarily related to our operations in Argentina. Foreign currency exchange gains and losses in other countries were not significant in either period.

 

During 2004, the Argentine peso was relatively unchanged against the U.S. dollar, with an exchange rate of 2.98 pesos to one U.S. dollar at December 31, 2004, compared to a rate of 2.94 pesos to one U.S. dollar at December 31, 2003. The Argentine peso strengthened significantly against the U.S. dollar during 2003, with an exchange rate of 2.94 pesos to one U.S. dollar at December 31, 2003, compared to a rate of 3.38 pesos to one U.S. dollar at December 31, 2002.

 

As discussed in Note 1 to our consolidated financial statements included elsewhere in this Form 10-K, the Argentine government took actions which, in effect, caused the devaluation of the peso in early December 2001. During 2002, the peso declined in value, falling from a rate of 1.65 pesos to one U.S. dollar at January 11, 2002, to 3.38 pesos to one U.S. dollar at December 31, 2002. Included in “Foreign currency (gain) loss” for 2002 was a gain of $0.9 million related to the Argentine government-mandated negotiated settlement of U.S. dollar-denominated receivables and payables in existence at January 6, 2002.

 

Derivative losses. We recorded total derivative losses of $21.7 million during 2004 related to settlements and market value adjustments of derivative commodity instruments that did not qualify or ceased to qualify for hedge accounting, compared to derivative losses of $1.5 million during 2003 and $0.5 million in 2002. Beginning in September 2004 and continuing through year-end, the differential between the NYMEX index price for crude oil and West Coast and other U.S. crude oil postings widened. Although the NYMEX crude oil index prices increased, many crude oil postings under which we sell our oil did not increase at the same rate. This market fluctuation caused us to conclude that most of our crude oil hedges were no longer highly effective in achieving offsetting changes in the cash flows of the physical transactions. In accordance with SFAS 133, we discontinued hedge accounting for these contracts beginning in September and recorded the changes in the fair value of these contracts as a charge to “Derivative losses.” The fair value of these contracts, which ceased to qualify for hedge accounting at December 31, 2004, was a liability of $14.2 million. As of March 1, 2005, the Company has determined that the correlation indicates that its existing oil price swap agreements will again be highly effective in achieving offsetting changes in the cash flows of the physical transactions and, accordingly, has redesignated all of the oil price swap contracts as cash flow hedges and will resume hedge accounting for these contracts as of March 1, 2005. Derivative losses in 2003 primarily relate to certain cash flow hedges for which the future physical transaction was no longer deemed probable as a result of the shut-in of certain producing oil wells in California due to the October 2003 fires.

 

Cumulative effect of change in accounting principle. We implemented SFAS 143 effective January 1, 2003. Previously, we accrued an undiscounted estimate of future abandonment costs of wells and related facilities through our depreciation calculation. With the implementation of SFAS 143, we now record a discounted fair value of the future retirement obligation as a liability with a corresponding amount capitalized as part of the related property’s carrying amount at acquisition date of a producing property or at the completion of drilling. We amortize the discounted capitalized asset retirement cost to expense through our depreciation calculation over the estimated useful life of the asset. We accrete the liability over time with a charge to accretion expense. As a result of the implementation of SFAS 143, we recorded a cumulative effect of change in accounting principle of $7.1 million, net of taxes of $4.1 million, in the first quarter of 2003.

 

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Effective January 1, 2002, we adopted the provisions of SFAS 142. SFAS 142 changed the accounting for goodwill from an amortization method to an impairment-only method. Our goodwill related to our Canadian operations which were sold in November 2004. We tested goodwill for impairment in conjunction with a transitional goodwill impairment test in 2002. As a result of the transitional impairment test, we recorded a $60.5 million charge as a cumulative effect of change in accounting principle retroactive to January 1, 2002, in accordance with the provisions of SFAS 142. Decreases in oil and gas price expectations from the May 2, 2001, acquisition of Genesis to January 1, 2002, and certain downward revisions recorded to our Canadian oil and gas reserves at December 31, 2001, were the primary factors that led to the goodwill impairment at January 1, 2002. The annual impairment tests as of December 31, 2003 and 2002, resulted in additional charges of $25.7 million and $76.4 million in 2003 and 2002, respectively, which are now reflected in losses from discontinued operations. Certain downward revisions recorded to our Canadian oil and gas reserves in the fourth quarters of 2002 and 2003 were the primary reason for the additional goodwill impairments. As of December 31, 2003, we had no remaining goodwill recorded on our balance sheet.

 

Cash Flows

 

Our primary sources of cash during 2004 were funds generated from operations and proceeds from the sale of our Canadian operations. The cash was primarily used to reduce long-term debt, fund capital expenditures and pay dividends, with the remainder increasing our cash position by $92.0 million. See below for additional discussion of our cash flows from operating activities.

 

     Years Ended December 31,

   

Change


 
   2004

    2003

   
     (in thousands)        

Cash provided (used) by:

                        

Operating activities - continuing operations

   $ 337.6     $ 212.5     $ 125.1  

Operating activities - discontinued operations

     14.7       21.3       (6.6 )

Investing activities - continuing operations

     (105.6 )     4.8       (110.4 )

Investing activities - discontinued operations

     7.8       (13.3 )     21.1  

Financing activities

     (163.1 )     (201.9 )     38.8  

 

Cash provided by continuing operations increased 59 percent to $337.6 million in 2004 versus $212.5 million in 2003 primarily as a result of significantly higher oil and gas prices and a six percent increase in production. The impact of higher prices and production was partially offset by higher operating costs. See “Results of Operations” and “Period to Period Comparisons” for further discussions. We did not see a significant difference between years in cash provided or used by changes in total working capital amounts. Cash provided by operating activities—discontinued operations for both years represents the cash provided from our discontinued Canadian operations and, in 2003, is partially offset by the payment of current taxes associated with the sale of our operations in Ecuador.

 

Cash provided or used by investing activities in 2004 and 2003 has been significantly impacted by our decision to reduce debt with proceeds from the sale of oil and gas properties. Investing activities in 2004 include $241.5 million for proceeds from the sale of our operations in Canada, net of cash sold. Investing activities in 2003 include $146.1 million for proceeds from the sales of our operations in Ecuador and certain properties in the U.S. Capital spending by continuing operations was $309.8 million, or 92 percent of cash provided by continuing operations, in 2004 and $144.8 million, or 68 percent of cash provided by continuing operations in 2003. We do not anticipate significant proceeds from property sales in 2005 and we have established our 2005 non-acquisition capital budget at $250 million, which is below our 2005 expected cash flows.

 

Cash used by financing activities in 2004 and 2003 reflects the results of our debt reduction program as we have redeemed our 9 3/4% senior subordinated notes due 2009 in 2004 and our 9% senior subordinated notes due 2005 and 8 5/8% senior subordinated notes due 2009 in 2003 and reduced our outstanding balance under our revolving credit facility to zero at December 31, 2004.

 

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Capital Expenditures

 

During 2004, our total oil and gas capital expenditures were $365.2 million ($347.6 million related to continuing operations). In the U.S., our oil and gas capital expenditures totaled $180.4 million. Development activities accounted for $60.6 million of our U.S. capital expenditures with exploration activities contributing $34.6 million. We also spent $75.6 million on acquisitions of producing properties in the United States and $9.6 million on the acquisition of U.S. unproved acreage in 2004. During 2004, our international oil and gas capital expenditures totaled $184.8 million ($167.1 million on continuing operations). This continuing operations amount consists of acquisitions in Argentina of $34.9 million, development activities of $89.1 million in Argentina and $30.1 million in Yemen and exploration activities of $3.6 million in Yemen, $4.1 million in Argentina, $1.2 million in Bulgaria and $4.1 million in Italy.

 

As of December 31, 2004, we had total unproved oil and gas property costs of approximately $25.4 million consisting of undeveloped leasehold costs of $14.3 million and unevaluated exploratory drilling of $11.1 million. Approximately $14.6 million of the total unproved costs are associated with our drilling program in Yemen. Future exploration expense and earnings may be impacted to the extent our future exploration activities are unsuccessful in discovering commercial oil and gas reserves in sufficient quantities to recover our costs.

 

In December 2004, we acquired all of Exxon Mobil Corporation’s interest in the Big Escambia Creek field and gas processing facility in Alabama. We paid $77.2 million, subject to post-closing adjustments. The 13 operated and two non-operated wells in this field are adjacent to our existing Flomaton and Fanny Church fields and plant and they produce condensate, gas and liquids of approximately 1,920 BOE per day.

 

In September 2004, we acquired 100 percent of an Argentine company whose principal asset is an operated producing concession which covers approximately 54,000 acres in the north flank of the San Jorge basin of Argentina. We paid total consideration of $34.9 million in cash. We estimate that the current net production attributable to the producing Bella Vista Oeste concession is 1.9 MBbls of oil and natural gas liquids per day from approximately 50 active producing wells. We believe that the properties contain significant workover, drilling and secondary production potential which we plan to pursue along with the implementation of operational efficiencies.

 

On May 2, 2001, we completed the acquisition of Genesis for total consideration of $617 million, including transaction costs and the assumption of the net indebtedness of Genesis at closing. In connection with our acquisition of Genesis, we financed the acquisition price of approximately $617 million with cash on hand of approximately $26 million and debt or assumed net obligations of approximately $591 million. The total acquisition amount includes cash paid at closing of $463 million, assumed debt of $88 million (which was immediately refinanced) and the assumption of a negative working capital position of approximately $66 million. The cash paid at closing in excess of the $26 million of cash on hand and the refinancing of the assumed debt were funded by advances from our revolving credit facility.

 

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The timing of most of our capital expenditures is discretionary with no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant. We use internally-generated cash flows to fund our capital expenditures other than significant acquisitions. Our capital expenditure budget for 2005 is currently set at $250 million, exclusive of acquisitions. We do not have a specific acquisition budget since the timing and size of acquisitions are difficult to forecast. We are actively pursuing additional acquisitions of oil and gas properties. In addition to internally-generated cash flows and advances under our revolving credit facility, we may seek additional sources of capital to fund any future significant acquisitions (see “Liquidity”), however, no assurance can be given that sufficient funds will be available to fund our desired acquisitions. Our recent capital expenditure history (including capital expenditures of discontinued operations) is as follows:

 

     Years Ended December 31,

(In thousands)

 

   2004

   2003

   2002

Acquisition of oil and gas reserves

   $ 110,547    $ 463    $ —  

Drilling

     169,353      133,208      82,664

Acquisition of undeveloped acreage and seismic

     24,418      21,537      19,592

Workovers and recompletions

     57,129      22,592      24,673

Other

     3,817      3,972      2,777
    

  

  

Oil and gas capital expenditures

     365,264      181,772      129,706

Gathering system and plant projects

     582      2,484      4,554
    

  

  

Total

   $ 365,846    $ 184,256    $ 134,260
    

  

  

 

Capital Resources and Liquidity

 

Cash on hand, internally generated cash flows and the borrowing capacity under our revolving credit facility are our major sources of liquidity. We also have the ability to adjust our level of capital expenditures. We may use other sources of capital, including the issuance of additional debt securities or equity securities, to fund any major acquisitions we might secure in the future and to maintain our financial flexibility.

 

In the past, we have accessed the public markets to finance significant acquisitions and provide liquidity for our future activities. Since 1990, we have completed five public equity offerings as well as two public debt offerings and three Rule 144A private debt offerings, all of which have provided us with aggregate net proceeds of approximately $1.2 billion.

 

On May 30, 2001, we issued $200 million of our 7 7/8% Senior Subordinated Notes due 2011 (the “7 7/8% Notes”). The 7 7/8% Notes are redeemable at our option, in whole or in part, at any time on or after May 15, 2006. The 7 7/8% Notes mature on May 15, 2011, with interest payable semi-annually on May 15 and November 15 of each year. All of our net proceeds from the sale of the 7 7/8% Notes (approximately $199.9 million) were used to repay a portion of the existing indebtedness under our revolving credit facility.

 

On May 2, 2002, we issued, through a Rule 144A offering, $350 million of our 8 1/4% Senior Notes due 2012 (the “8 1/4% Notes”). All of the net proceeds were used to repay a portion of the outstanding balance under our revolving credit facility and to redeem $100 million of our outstanding 9% Senior Subordinated Notes due 2005 (the “9% Notes”). The 8 1/4% Notes are redeemable at our option, in whole or in part, at any time on or after May 1, 2007. In addition, prior to May 1, 2005, we may redeem up to 35 percent of the 8 1/4% Notes with the proceeds of certain underwritten public offerings of our common stock. The 8 1/4% Notes mature on May 1, 2012, with interest payable semi-annually on May 1 and November 1 of each year.

 

In conjunction with the offering of the 8 1/4% Notes, we entered into a new $300 million revolving credit facility (as amended, the “Bank Facility”), which was used to refinance our previously existing credit facility and to provide funds for ongoing operating and general corporate needs. We also redeemed a portion of the 9% Notes. As a result, we were required to expense certain associated deferred financing costs and discounts. This $5.2 million non-cash charge, along with a $3.0 million cash charge for the call premium on the 9% Notes, resulted in a one-time charge of approximately $8.2 million ($5.0 million net of tax) recorded in the second quarter of 2002.

 

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Index to Financial Statements

During the first quarter of 2003, we advanced funds under the Bank Facility to redeem the remainder of the 9% Notes. As a result, we were required to expense certain associated deferred financing costs and discounts. This $0.7 million non-cash charge and a $0.7 million cash charge for the call premium on the redemption of the remaining 9% Notes in 2003 resulted in a one-time charge of approximately $1.4 million ($1.0 million net of tax) recorded in the first quarter of 2003.

 

In October 2003, we redeemed the entire $100 million principal balance of our 8 5/8% senior subordinated notes due 2009 with cash provided by advances under the Bank Facility. As a result, we were required to expense certain associated deferred financing costs and discounts. This $2.3 million non-cash charge and a $3.2 million cash charge for the call premium resulted in a one-time charge of approximately $5.5 million ($3.4 million net of tax) in the fourth quarter of 2003.

 

In February 2004, we redeemed the entire $150 million principal balance of our 9 3/4% senior subordinated notes due 2009 with cash provided by advances under the Bank Facility. As a result, we were required to expense certain associated deferred financing costs. The $2.6 million non-cash charge and a $7.3 million cash charge for the call premium resulted in a one-time charge of approximately $9.9 million ($6.0 million net of tax) that we recorded in the first quarter of 2004.

 

The Bank Facility consists of a senior secured credit facility maturing in May 2008 with availability governed by a borrowing base determination. Our availability under the Bank Facility is reduced by our outstanding letters of credit. The borrowing base (currently $325 million) is based on the banks’ evaluation of our oil and gas reserves. The amount available to be borrowed under the Bank Facility is limited to the lesser of the borrowing base or the facility size, which is currently set at $300 million. The next borrowing base redetermination will be in April 2005. The Bank Facility is secured by a first priority lien on our oil and gas properties constituting at least 80 percent of the present value of our U.S. proved reserves owned now or in the future. The Bank Facility will be guaranteed by any of our existing and future U.S. subsidiaries that grant a lien on oil and gas properties under the Bank Facility.

 

Outstanding advances under the Bank Facility bear interest payable quarterly at a floating rate based on Bank of Montreal’s alternate base rate (as defined therein) or, at our option, at a fixed rate for up to six months based on the Eurodollar market rate (“LIBOR”). Our interest rate increments above the alternate base rate and LIBOR vary based on the level of outstanding senior secured debt to the borrowing base. In addition, we must pay a commitment fee ranging from 0.375 to 0.50 percent per annum (based on the ratio of the outstanding senior secured debt to the borrowing base) on the unused portion of the banks’ commitment. As of February 28, 2005, we have unused availability under our revolving credit facility of $296.6 million (considering outstanding letters of credit of approximately $3.4 million).

 

The terms of the Bank Facility require the maintenance of a minimum current ratio (as defined therein) and a minimum tangible net worth (as defined therein). The indentures for our senior notes and our senior subordinated notes contain limitations on, among other things, additional indebtedness and liens, the payments of dividends and other distributions, certain investments and transfers or sales of assets.

 

The significant non-cash charges for impairments of our U.S. and Canadian oil and gas properties that we recorded in 2003 had no material adverse impact on the financial covenants under the Bank Facility or our existing bond indentures. Our current borrowing base under the Bank Facility is based primarily on our U.S. reserves.

 

The significant impairments related to our Canadian operations we recorded in 2002 and 2003 indicated that the expected cash flows from such operations were expected to be substantially reduced in the future. During 2004, we sold all of our Canadian operations for proceeds of approximately $274.7 million, a portion of which were used to eliminate all advances then outstanding under the Bank Facility. We believe that due to our substantial remaining assets, the impact of such Canadian impairments and the subsequent sale of our Canadian operations did not result in our inability to satisfy all of our debt and other obligations as they come due.

 

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Our internally generated cash flows, results of operations and financing for our operations are dependent on oil and gas prices. Realized oil and gas prices for the year increased by 21 percent and 37 percent, respectively, as compared to 2003. For 2004, approximately 68 percent of our production on a BOE basis from continuing operations was oil. We believe that our cash flows and unused availability under the Bank Facility are sufficient to fund our planned capital expenditures for the foreseeable future. To the extent oil and gas prices decline, our earnings and cash flows from operations may be adversely impacted. Prolonged periods of substantially lower oil and gas prices could cause us to not be in compliance with maintenance covenants under our Bank Facility and could negatively affect our credit statistics and coverage ratios and thereby affect our liquidity.

 

Consistent with our stated goal of maintaining financial flexibility and optimizing our portfolio of assets, we announced in early 2002 plans to reduce debt by $200 million through a combination of asset sales and cash flows in excess of planned capital expenditures. We determined that the level of investment and time horizon required to continue the development of our interests in Ecuador and Trinidad were inconsistent with the timing of our desire to reduce leverage. These assets, along with our remaining heavy oil properties in the Santa Maria area of southern California, were identified for sale. Our heavy oil properties in the Santa Maria area of southern California were sold in June 2002 for $9.5 million in cash and a note receivable for $6 million, bearing monthly payments of $360,000, plus interest, with final maturity in June 2003. We received a cash payment as final settlement of this note in October 2002. Our interest in Trinidad was sold in July 2002 for $40 million in cash; our interest in Ecuador was sold in January 2003 for $137.4 million in cash. The closing of the sale of our interest in Ecuador, along with the sales of certain U.S. Mid-Continent gas properties and certain non-strategic oil and gas assets in Saskatchewan and West Central Alberta, Canada for a total of $57.9 million, allowed us to exceed our $200 million debt reduction goal. Subsequently, we sold our Canadian operations in November 2004 for $274.7 million in cash. Our debt, less cash on hand, at December 31, 2004, was $425.7 million, compared to approximately $1.0 billion at December 31, 2001.

 

Off Balance Sheet Arrangements and Contractual Obligations

 

We have no off balance sheet arrangements, as defined by SEC rules. A summary of our contractual obligations as of December 31, 2004, is as follows (in thousands):

 

     Payments Due By Year

     Total

   2005

   2006

   2007

   2008

   2009

   Thereafter

Long-term debt (a)

   $ 550,000    $ —      $ —      $ —      $ —      $ —      $ 550,000

Operating leases (b)

     8,467      2,370      2,338      3,759      —        —        —  

Firm transportation and compression agreements (b)

     3,323      1,187      1,269      269      299      299      —  

Argentina electric power agreement (b)

     12,067      3,574      3,574      4,919      —        —        —  

Purchase commitments

     8,204      8,204      —        —        —        —        —  

Yemen concession agreement (b)

     6,415      338      338      338      338      338      4,725
    

  

  

  

  

  

  

     $ 588,476    $ 15,673    $ 7,519    $ 9,285    $ 637    $ 637    $ 554,725
    

  

  

  

  

  

  


(a) See Note 2 “Long-term Debt” to our consolidated financial statements included elsewhere in this Form 10-K.
(b) See Note 4 “Commitments and Contingencies” to our consolidated financial statements included elsewhere in this Form 10-K.

 

We have no capital leases. The table above does not include $3.6 million of letters of credit that have been issued by commercial banks on our behalf which, if funded, would become borrowings under our revolving credit facility. The $550 million of long-term debt shown in the table excludes approximately $51,000 of discounts, which are included in the amount shown on our December 31, 2004, balance sheet. The table above also does not include payments that we have agreed to make in the Argentine province of Santa Cruz to improve employment rates, social development and education resources. These payments are estimated to be 3.8 million pesos ($1.3 million) for 2005, 3.8 million pesos ($1.3 million) for 2006 and 1.7 million pesos ($0.6 million) for 2007.

 

Material contractual cash obligations for which the ultimate settlement amounts are not fixed and determinable include derivative contracts that are sensitive to future changes in commodity prices. See “Item 7A. Quantitative and Qualitative Disclosure about Market Risk - Commodity Price Risk” included elsewhere in this Form 10-K.

 

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Inflation

 

During 2004, the Argentine inflation rate amounted to 6.1 percent for the year. In recent years, inflation outside of Argentina has not had a significant impact on our operations or financial condition and is not currently expected to have a significant impact on future periods.

 

Income Taxes

 

We recorded a current provision for income taxes from continuing operations of $57.9 million, $40.1 million and $16.0 million for 2004, 2003 and 2002, respectively. The total provision for U.S. income taxes is based on the federal corporate statutory income tax rate plus an estimated average rate for state income taxes. Earnings of our foreign subsidiaries are subject to foreign income taxes. At December 31, 2004, unremitted earnings of subsidiaries outside of the U.S. were approximately $425 million, on which no U.S. taxes had been provided as it is our intention, generally, to invest such earnings permanently or to repatriate the earnings only when possible to do so at minimal additional tax cost. We have paid or accrued foreign income taxes of approximately $230 million related to these earnings which may be available as a credit against U.S. federal income taxes on such income, if distributed. It is not practicable to estimate the amount of additional tax that might be payable on this foreign income if distributed because the amount of foreign taxes eligible for credit against U.S. federal income taxes on any such distribution will be determined based on facts and circumstances at the time of any actual distribution. We expect that foreign income taxes will constitute a substantial portion of our overall tax burden in the foreseeable future.

 

The American Jobs Creation Act of 2004 (the “Jobs Act”) introduced a special one-time dividends-received deduction on the repatriation of certain foreign earnings to the U.S., provided certain conditions are met. If certain conditions are met, a 5.25 percent effective income tax rate would apply to eligible repatriations of certain foreign earnings. We are currently evaluating these provisions under the Jobs Act and we are also awaiting interpretive guidance relating to these regulations from either Congress or the Treasury Department. At the current date, we have not determined that we will repatriate any unremitted foreign earnings under the special one-time repatriation provisions of the Jobs Act. However, we continue to evaluate the special one-time repatriation provisions of the Jobs Act and that evaluation could result in us repatriating certain unremitted foreign earnings. The amount of unremitted foreign earnings that we are evaluating for repatriation, including projected 2005 earnings, ranges from zero to $500 million. We expect to complete our evaluation of the amount of repatriation, if any, during 2005. If we were to repatriate certain unremitted foreign earnings under the special one-time repatriation provisions of the Jobs Act in the range noted in the preceding sentence, the income tax effects of such repatriation could range from zero to approximately $26 million.

 

We have various state net operating loss carryforwards which have varying lengths of allowable carryforward periods ranging from five to 20 years and can be used to offset future state taxable income. We have a Bolivian income tax NOL carryforward of approximately $39 million that does not expire. We have also incurred approximately $80 million related to our Yemen operations that we expect to recover under the cost recovery provisions of our production sharing agreement with the government of Yemen. These provisions allow us to annually offset a portion of our revenues that would otherwise be taxable with costs we previously incurred in Yemen until such costs have been fully recovered. We expect to recover this amount over the next five years.

 

Changes in our income tax provision (benefit) are a function of our consolidated effective tax rate and our pre-tax income (loss). The increase in our income tax expense for 2004 as compared to 2003 is primarily due to higher pre-tax earnings resulting from higher product prices and production. Our overall effective tax rate on continuing operations was 35.7 percent and 41.3 percent for 2004 and 2003, respectively.

 

As part of our results from discontinued operations for 2004, we recorded a U.S. income tax benefit of $30.7 million related to prior year taxes to be refunded as a result of our intent to carry back a portion of the capital loss for tax purposes generated by the disposal of our Canadian operations, bringing the 2004 effective tax rate on discontinued operations to 14.8 percent, compared to 24.4 percent for 2003, which primarily related to the sale of our Ecuador subsidiary. As part of our results from discontinued operations for 2003, we recorded additional U.S. income taxes of $19.4 million related to the repatriation of previously untaxed foreign earnings as a result of the sale of our Ecuador subsidiary in January 2003.

 

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Critical Accounting Policies and Estimates

 

Management’s discussion and analysis of our financial condition and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). GAAP represents a comprehensive set of accounting and disclosure rules and requirements, the application of which requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The preparation of these consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates under different assumptions or conditions. Note 1 to our consolidated financial statements included elsewhere in this Form 10-K, contains a comprehensive summary of our significant accounting policies. The following is a discussion of our most critical accounting policies, judgments and uncertainties that are inherent in our application of GAAP:

 

Accounting for Oil and Gas Properties. Under the successful efforts method of accounting, we capitalize all costs related to property acquisitions and successful exploratory wells, all development costs and the costs of support equipment and facilities. Certain costs of exploratory wells are capitalized pending determination that proved reserves have been found. Such determination is dependent upon the results of planned additional wells and the cost of required capital expenditures to produce the reserves found. All costs related to unsuccessful exploratory wells are expensed when we determine that such wells have not found proved reserves; other exploration costs, including geological and geophysical costs, are expensed as incurred. We recognize gains or losses on the sale of properties on a field basis.

 

The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. The evaluation of oil and gas leasehold acquisition costs requires management’s judgment to estimate the fair value of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

 

The successful efforts method of accounting can have a significant impact on the operational results reported when we enter a new exploratory area in hopes of finding oil and gas reserves. Seismic costs can be substantial which will result in additional exploration expenses when incurred. The initial exploratory wells may be unsuccessful and the associated costs will then be expensed as dry hole costs and any associated leasehold costs may be impaired.

 

Development Seismic Costs. We expense all exploration seismic costs as incurred. Delineation seismic costs incurred to select development locations within a productive oil and gas field are typically treated as development costs and capitalized. Judgment is required to determine when the seismic programs are not within proved areas and therefore would be charged to expense as exploratory costs.

 

We capitalized approximately $2.0 million, $1.9 million and $1.7 million of 3-D seismic costs incurred in our development activities in the years ended December 31, 2004, 2003 and 2002, respectively. As of December 31, 2004, a total of approximately $22.0 million (net of accumulated amortization of approximately $6.4 million) of development seismic costs are included in net property, plant and equipment in our balance sheet.

 

In connection with a routine review of our 2003 Form 10-K, the SEC has evaluated the appropriateness of our accounting policy for development seismic costs. On March 11, 2005, the SEC provided us with guidance regarding the application of this accounting policy. Based on a preliminary review of the impact this guidance may have on previously capitalized costs, we believe that the impact of any potential adjustment would not be material to our consolidated financial statements for the years ended December 31, 2004, 2003 and 2002.

 

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Exploration Drilling Costs. Costs of drilling exploratory wells are capitalized as part of our unproved costs, pending management’s determination of whether the wells have found proved reserves. Management makes this determination as soon as possible after completion of drilling considering the guidance provided in SFAS 19. SFAS 19 provides that such costs should not be carried as an asset for more than one year following completion of drilling, unless the well has found oil and gas reserves in an area requiring a major capital expenditure before production could begin. In that case, the costs of such exploration well continue to be carried as an asset pending determination of whether proved reserves have been found only as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and drilling of the additional exploratory wells is under way or firmly planned for the near future. If both those conditions are not met, the well costs are charged to expense. Management performs this evaluation on a quarterly basis. See Note 1 to the consolidated financial statements for additional information.

 

The Financial Accounting Standards Board (“FASB”) has recently issued Proposed FASB Staff Position No 19-A, Accounting for Suspended Well Costs (“FSP 19-A”). If adopted as proposed, FSP 19-A will amend SFAS 19 to provide that in those situations where exploration drilling has been completed and oil and gas reserves have been found, but such reserves cannot be classified as proved when drilling is complete, the drilling costs may be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either of the criteria is not met, the well is assumed to be impaired and the costs charged to expense. Any well which has not found reserves is charged to expense. Management believes that no adjustment would have been required as of the beginning of and for each of the three years in the period ended December 31, 2004, from the application of the proposed FSP 19-A.

 

Proved reserve estimates. Estimates of our proved reserves included in our consolidated financial statements and elsewhere in this Form 10-K are prepared in accordance with guidelines established by GAAP and by the SEC. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The process relies on interpretations of available geological, geophysical, engineering and production data. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions; and (iv) the judgment of the persons preparing the estimate.

 

Our proved reserve information is based primarily on estimates prepared by our independent petroleum consultants. As of December 31, 2004, fields comprising approximately four percent of our total proved reserves were estimated by us. Estimates prepared by others may be higher or lower than these estimates. Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

 

The present value of future net cash flows should not be assumed to be the current market value of our estimated proved reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves were based on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

 

The estimates of proved reserves materially impact depletion, depreciation and amortization expense. If the estimates of proved reserves decline, the rate at which we record depletion, depreciation and amortization expense increases, reducing net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost reserves, or from volume revisions resulting from actual production rates, drilling results in nearby areas or other factors. In addition, the decline in proved reserve estimates may impact the outcome of our assessment of our oil and gas producing properties for impairment.

 

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Impairment of proved oil and gas properties. We review our proved oil and gas properties for impairment on a field basis. For each field, an impairment provision is recorded whenever events or circumstances indicate that the carrying value of those properties may not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future net revenues from production of total proved and risk-adjusted probable and possible oil and gas reserves over the economic life of the reserves, based on our expectations of future oil and gas prices and costs, consistent with methods used for acquisition evaluations. Oil and gas reserve estimates may change in future periods and oil and gas prices are historically volatile. Events may arise that will require us to record an impairment of our oil and gas properties and there can be no assurance that such impairments will not be required in the future.

 

Impairment of unproved oil and gas properties. Unproved leasehold costs and exploratory drilling in progress are capitalized and are reviewed periodically for impairment. Costs related to impaired prospects or unsuccessful exploratory drilling are charged to expense. Our assessment of the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such leaseholds impacts the amount and timing of impairment provisions. An impairment expense could result if oil and gas prices decline in the future as it may not be economic to develop some of these unproved properties. As of December 31, 2004, we had total unproved oil and gas property costs of approximately $25.4 million consisting of undeveloped leasehold costs of $14.3 million and unevaluated exploratory drilling costs of $11.1 million. Approximately $14.6 million of the total unevaluated costs are associated with our drilling program in Yemen.

 

Estimates of future dismantlement, restoration, and abandonment costs. Through December 31, 2002, we had accrued future abandonment costs of wells and related facilities through our depreciation calculation in accordance with the provisions of SFAS 19 and industry practice. The accounting for future development and abandonment costs changed on January 1, 2003, with the adoption of SFAS 143. Under both methods of accounting, the accrual is based on estimates of these costs for each of our properties based upon the type of production structure, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based on numerous factors, including changing technology, the political and regulatory environment and, beginning in 2003, estimates as to the proper discount rate to use and timing of abandonment.

 

Accounting for Derivative Financial Instruments. We periodically use derivative financial instruments as hedges to reduce the impact of oil and natural gas price fluctuations and we generally attempt to qualify such derivatives as hedges for accounting purposes. We account for our derivative activities under the provisions of SFAS 133, which requires us to record the fair value of our derivative financial instruments as either an asset or liability on our balance sheet. We utilize market-based quotes from our counterparties to value our open positions. Future market price volatility for oil and gas could result in significant changes to the amounts recorded on our balance sheet.

 

We must formally designate each cash flow hedge as such at its inception, documenting the nature of the risk being hedged, the specific hedged item and its volume, the hedging instrument and our basis for selecting that instrument, and the methodologies we will use to assess and measure the hedge’s effectiveness or ineffectiveness. To the extent that the derivative financial instruments qualify as effective cash flow hedges, we record any gains or losses on the open position in other comprehensive income. We record the results of settled oil or gas hedges as an adjustment to oil and gas sales in the period that the hedged forecasted transaction is recorded. Both at its inception and on an ongoing basis, we must use judgment to assess whether the hedging instrument has been and will continue to be highly effective in offsetting the changes in cash flows of the hedged transaction. If a derivative financial instrument does not qualify or ceases to qualify as an effective cash flow hedge, we record all settlements and changes in its fair value currently in our results of operations as non-operating income or expense. Any amounts previously recorded in accumulated other comprehensive income (loss) will then be recognized into earnings in the period that the forecasted transaction affects earnings.

 

SFAS 133 also requires us to continually assess whether occurrence of the forecasted transaction is probable. If we determine that the forecasted transaction in a cash flow hedge is no longer probable, we must discontinue hedge accounting for that derivative financial instrument, reclassify any amounts in other comprehensive income into our results of operations and record any changes in that instrument’s fair value in our results of operations from that point forward unless it is redesignated in a new qualifying hedge relationship.

 

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Income taxes. We provide deferred income taxes on transactions which are recognized in different periods for financial and tax reporting purposes. We have not recognized a U.S. deferred tax liability related to the unremitted earnings of any of our foreign subsidiaries as it is our intention, generally, to reinvest such earnings permanently. Management periodically assesses the need to utilize these unremitted earnings to finance our operations. This assessment is based on cash flow projections that are the result of estimates of future production, commodity pricing and expenditures by tax jurisdiction for our operations. Such estimates are inherently imprecise since many assumptions utilized in the cash flow projections are subject to revision in the future.

 

We have also recorded deferred tax assets related to operating loss and tax credit carryforwards. We periodically assess the probability of recovery of recorded deferred tax assets based on our assessment of future earnings outlooks by tax jurisdiction and record valuation allowances when this assessment results in a determination that recoverability is not likely. Such estimates and determinations are inherently imprecise because many assumptions are utilized in the assessments that may prove to be incorrect in the future.

 

Assessments of functional currencies. All of our subsidiaries use the U.S. dollar as their functional currency. Prior to the sale of our Canadian operations in November 2004, our Canadian subsidiary used the Canadian dollar as its functional currency. Management determines the functional currencies of our subsidiaries based on an assessment of the currency of the economic environment in which a subsidiary primarily realizes and expends its operating revenues, costs and expenses. The assessment of functional currencies can have a significant impact on periodic results of operations and financial position.

 

Argentina economic and currency measures. The accounting for and translation of the financial statements of our operations in Argentina reflect management’s assumptions regarding uncertainties unique to Argentina’s current economic situation. See Note 1 to our consolidated financial statements included elsewhere in this Form 10-K, for a description of the assumptions utilized in the preparation of these consolidated financial statements. Argentina’s economic and political situation evolves continuously and the Argentine government has adopted numerous decrees, is considering implementing various alternatives and may enact future regulations or policies that may materially impact, among other items, (i) the realized prices we receive for oil and gas we produce and sell; (ii) the timing and amount of repatriations of cash to the U.S.; (iii) the amount of permitted export sales; (iv) the Argentine banking system; (v) our asset valuations; and (vi) peso-denominated monetary assets and liabilities. For further information, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency and Operations Risk” included elsewhere in this Form 10-K.

 

Changes in Accounting Principles

 

On July 20, 2001, the FASB issued Statement of Financial Accounting Standards No. 141, Business Combinations (“SFAS 141”), and SFAS 142. SFAS 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method of accounting. Under SFAS 142, goodwill is no longer subject to amortization. Rather, goodwill will be subject to at least an annual assessment for impairment by applying a fair-value based test. Additionally, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.

 

We adopted SFAS 141 and SFAS 142 effective January 1, 2002, resulting in the elimination of goodwill amortization from statements of operations in future periods. As discussed in Note 7 to our consolidated financial statements included elsewhere in this Form 10-K, we recorded an impairment charge of $60.5 million related to the goodwill of our Canadian operations as a cumulative effect of a change in accounting principle in our statement of operations.

 

On January 1, 2002, we adopted the provisions of SFAS 144. SFAS 144 creates accounting and reporting standards to establish a single accounting model, based on the framework established in Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, for long-lived assets to be disposed of by sale. The adoption of SFAS 144 did not have a material impact on our financial position or results of operations.

 

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On April 30, 2002, the FASB issued Statement of Financial Accounting Standards No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections (“SFAS 145”). SFAS 145 updates, clarifies and simplifies existing accounting pronouncements. Among other items, it rescinds previous accounting rules which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. We have adopted the provisions of SFAS 145 in 2002 and, accordingly, have classified losses on the early extinguishment of debt of $9.9 million ($6.0 million net of tax) in 2004, $6.9 million ($4.2 million net of tax) in 2003 and $8.2 million ($5.0 million net of tax) in 2002 (see Note 2 to our consolidated financial statements included elsewhere in this Form 10-K) as non-operating expenses in our statements of operations. The adoption of SFAS 145 did not have any other material impact on our financial position or results of operations.

 

In August 2001, the FASB issued SFAS 143. We were required to adopt this new standard beginning January 1, 2003. Through December 31, 2002, we accrued future abandonment costs of wells and related facilities through our depreciation calculation and included the cumulative accrual in accumulated depreciation in accordance with the provisions of SFAS 19 and industry practice. At December 31, 2002, approximately $54.6 million of accrued future abandonment costs were included in our accumulated depreciation. The new standard requires that we record the discounted fair value of the retirement obligation as a liability at the time a well is drilled or acquired. The asset retirement obligations consist primarily of costs associated with the plugging and abandonment of oil and gas wells, site reclamation and facilities dismantlement. However, future abandonment liabilities are also recorded for other assets such as pipelines, processing plants and compressors. A corresponding amount is capitalized as part of the related property’s carrying amount. The discounted capitalized asset retirement cost is amortized to expense through the depreciation calculation over the estimated useful life of the asset based on proved reserves. The liability accretes over time with a charge to accretion expense. We adopted the new standard effective January 1, 2003, and recorded an increase in property, plant and equipment of approximately $50.3 million, a decrease in accumulated depreciation, depletion and amortization of approximately $43.9 million, an increase in current asset retirement liabilities of approximately $4.5 million, an increase in long-term asset retirement liabilities of approximately $78.5 million, a $4.1 million increase in deferred income tax liabilities and a gain as a result of the cumulative effect of change in accounting principle, net of tax, of approximately $7.1 million.

 

On July 30, 2002, the FASB issued Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities. The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The provisions of this statement are to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The adoption of this standard had no impact on our financial position or results of operations.

 

On December 31, 2002, the FASB issued Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure (“SFAS 148”). SFAS 148 amends Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (“SFAS 123”), to provide alternative methods of transition to SFAS 123’s fair value method of accounting for stock-based employee compensation. SFAS 148 also amends the disclosure provisions of SFAS 123 and APB Opinion No. 28, Interim Financial Reporting, to require disclosure in the summary of significant accounting policies of the effects of an entity’s accounting policy with respect to stock-based employee compensation on reported net income and earnings per share in annual and interim financial statements. We adopted the disclosure provision of SFAS 148 in our consolidated financial statements included elsewhere in this Form 10-K as of December 31, 2002. Effective January 1, 2003, we adopted the fair value recognition provisions of SFAS 123. We adopted these provisions prospectively to all employee and director awards granted, modified or settled after January 1, 2003. The impact of adopting this standard was not significant to our results of operations.

 

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51 and revised this interpretation in December 2003 (“FIN 46”). FIN 46 requires the consolidation of variable interest entities by their primary beneficiary if the variable interest entities do not effectively disperse risks among the parties involved. Previously, entities were generally consolidated by an enterprise when it had a controlling financial interest through ownership of a majority of voting interest in the entity. The adoption of FIN 46 had no impact on our financial position or results of operations.

 

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On April 30, 2003, the FASB issued Statement of Financial Accounting Standards No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS 149”). SFAS 149 is intended to result in more consistent reporting of contracts as either freestanding derivative instruments subject to SFAS 133 in its entirety, or as hybrid instruments with debt host contracts and embedded derivative features. SFAS 149 was effective for contracts entered into or modified after June 30, 2003, and hedging relationships designated after June 30, 2003. The adoption of SFAS 149 had no impact on our financial position or results of operations.

 

On May 15, 2003, the FASB issued Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (“SFAS 150”). SFAS 150 establishes standards for classifying and measuring as liabilities certain financial instruments that embody obligations of the issuer and have characteristics of both liabilities and equity. SFAS 150 must be applied immediately to instruments entered into or modified after May 31, 2003, and to all other instruments that exist as of the beginning of the first interim financial reporting period beginning after June 15, 2003. Early adoption of SFAS 150 was not permitted. The adoption of SFAS 150 had no impact on our financial position or results of operations.

 

On December 16, 2004, the FASB issued Statement of Financial Accounting Standards No. 153, Exchanges of Nonmonetary Assets - An Amendment of APB Opinion No. 29 (“SFAS 153”). SFAS 153 amends APB Opinion No. 29 (“APB 29”), Accounting for Monetary Transactions, that was issued in 1973. The amendments are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, the amendments eliminate the narrow exception for nonmonetary exchanges of similar productive assets and replace it with a broader exception for exchanges of nonmonetary assets that do not have “commercial substance.” Previously, APB 29 required that the accounting for an exchange of a productive asset for a similar productive asset or an equivalent interest in the same or similar productive asset should be based on the recorded amount of the asset relinquished. The provisions in SFAS 153 are effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Companies must apply the standard prospectively. We do not believe the adoption of SFAS 153 will have a significant impact on our financial position or results of operations.

 

The FASB has issued Statement of Financial Accounting Standards No. 123 (Revised 2004), Share-Based Payment (“SFAS 123R”). SFAS 123R requires that the compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. We will be required to apply SFAS 123R as of the first interim reporting period that begins after June 15, 2005. We are presently evaluating the impact of SFAS 123R but we do not believe the adoption of SFAS 123R will have a significant impact on our financial position or results of operations.

 

The FASB has issued FASB Staff Position (“FSP”) 109-1 and FSP 109-2 that provide accounting guidance on how companies should account for the effects of the American Jobs Creation Act of 2004 that was signed into law on October 22, 2004. The result of this legislation could affect how companies report their deferred income tax balances. The guidance in these FSP statements is effective December 21, 2004. In FSP 109-1, the FASB concludes that the tax relief (special tax deduction for domestic manufacturing) from this legislation should be accounted for as a “special deduction” instead of a tax rate reduction. We are evaluating the impact of FSP 109-1. FSP 109-2 gives a company additional time to evaluate the effects of the legislation on any plan for reinvestment or repatriation of foreign earnings for purposes of applying Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes.

 

The FASB issued FSP FAS 141-1 and FAS 142-1 as a result of the March 17-18, 2004, Emerging Issues Task Force (“EITF”) meeting, after the EITF reached a consensus on EITF Issue No. 04-2, “Whether Mineral Rights Are Tangible or Intangible Assets,” and concluded that mineral rights, as defined in the issue, are tangible assets. There was an inconsistency between this consensus and the characterization of mineral rights as intangible assets in SFAS 141 and SFAS 142. Accordingly, this FSP amended SFAS 141 and SFAS 142 in order to address that inconsistency. The guidance in this FSP was applicable to the first reporting period beginning after April 29, 2004. The adoption of this FSP had no impact on the Company’s financial position.

 

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On occasion, we utilize buy/sell arrangements with third parties to enhance the value of our oil or gas production. These agreements involve the sale of oil or gas to a third party at one location and the re-purchase of the same volume of oil or gas at another location from the same third party. We then sell the oil or gas to another company at a negotiated price. We recognize in the financial statements only the ultimate sale of oil or gas as revenue at the net realized price, adjusted for any costs incurred in the buy/sell arrangement. The EITF is considering buy/sell arrangements and related matters in EITF Issue 04-13, including how buy/sell arrangements should be reported in the statements of operations. We believe that the effect of our historical buy/sell arrangements has not been significant and do not expect the resolution of EITF Issue 04-13 to have a significant effect on our financial position or results of operations.

 

Foreign Operations

 

For information on our foreign operations, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency and Operations Risk” included elsewhere in this Form 10-K.

 

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

 

Our operations are exposed to market risks primarily as a result of changes in commodity prices, interest rates and foreign currency exchange rates. We do not use derivative financial instruments for speculative or trading purposes.

 

Commodity Price Risk

 

We produce, purchase and sell crude oil, natural gas, condensate, natural gas liquids and sulfur. As a result, our financial results can be significantly impacted as these commodity prices fluctuate widely in response to changing market forces. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Future Period Hedges” for a discussion of the impact of commodity price changes based on 2004 production levels. We have previously entered into oil and gas derivative transactions and we intend to continue to consider various derivative transactions to realize commodity prices which we consider favorable.

 

During 2002, we participated in oil price swap agreements covering 4.9 MMBbls of 2002 oil production at a weighted average NYMEX reference price of $25.16 per Bbl and gas price swap agreements covering 11.3 million MMBtu of 2002 gas production. The U.S. portion of the gas price swap agreements (5.2 million MMBtu) was at a NYMEX reference price of $2.72 per MMBtu. The Canadian portion of the gas price swap agreements (6.1 million MMBtu) was at the AECO gas price index reference price of 3.67 Canadian dollars per MMBtu and was settled in Canadian dollars. Additionally, we entered into gas price collar arrangements for 2.2 million MMBtu of our U.S. gas production in 2002 with floor NYMEX reference prices of $3.50 per MMBtu and cap NYMEX reference prices ranging from $4.00 to $5.10 per MMBtu. In conjunction with each of the 2002 U.S. gas price swap agreements and gas price collar agreements, we entered into basis swap agreements covering identical periods of time and volumes. These basis swaps established a differential between the NYMEX reference price and the various delivery points at levels that are comparable to the historical differentials we have received.

 

At December 31, 2002, we had entered into oil price swap agreements for a total of 3.0 MMBbls of 2003 oil production and gas price swap agreements for a total of 20.1 million MMBtu of 2003 gas production. Additionally, we had entered into basis swap agreements for approximately 8.4 million MMBtu of our 2003 U.S. gas production covered by the gas price swap agreements. At December 31, 2002, we would have been required to pay approximately $17.1 million to terminate our swap agreements then in place.

 

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During 2003, we participated in oil price swap agreements covering 4.9 MMBbls of 2003 oil production and gas price swap agreements covering 20.1 million MMBtu of 2003 gas production. The U.S. portion of the oil price swap agreements (4.7 MMBbls) was at a weighted average NYMEX reference price of $26.79 per Bbl. The Canadian portion of the oil price swap agreements (0.2 MMBbls) was at a weighted average NYMEX reference price of 43.19 Canadian dollars per Bbl and was settled in Canadian dollars. The U.S. portion of the gas price swap agreements (11.0 million MMBtu) was at a weighted average NYMEX reference price of $4.00 per MMBtu. The Canadian portion of the gas price swap agreements (9.1 million MMBtu) was at a weighted average NYMEX reference price of 6.63 Canadian dollars per MMBtu and was settled in Canadian dollars. Additionally, we entered into basis swap agreements for approximately 8.4 million MMBtu of our 2003 U.S. gas production covered by the gas price swap agreements. These basis swaps established a differential between the NYMEX reference price and the various delivery points at levels that were comparable to the historical differentials we have received.

 

At December 31, 2003, we had entered into oil price swap agreements for a total of 5.0 MMBbls of 2004 and 2005 oil production. At that date, we would have been required to pay approximately $7.9 million to terminate our swap agreements then in place.

 

During 2004, we participated in oil price swap agreements covering 5.6 MMBbls of 2004 oil production and at a weighted average NYMEX reference price of $30.10 per Bbl and gas price swap agreements covering 21.8 million MMBtu of 2004 gas production at a weighted average NYMEX reference price of $5.92 per MMBtu. In conjunction with each of the 2004 U.S. gas price swap agreements, we entered into basis swap agreements covering identical periods of time and volumes. These basis swaps established a differential between the NYMEX reference price and the various delivery points at levels that are comparable to the historical differentials we have received.

 

At December 31, 2004, we had entered into oil price swap agreements for a total of 7.2 MMBbls of 2005, 2006 and 2007 oil production, gas price swap agreements for a total of 6.6 million MMBtu of 2005, 2006 and 2007 gas production at a weighted average NYMEX reference price of $6.31 per MMBtu, and gas price collar agreements for a total of 11.0 million MMBtu of 2005 gas production with NYMEX floor reference prices of $6.00 per MMBtu and NYMEX cap reference prices ranging from $6.80 to $9.21 per MMBtu. Additionally, we have entered into basis swap agreements for volumes and periods of time that coincide with each of the gas price swap agreements and gas price collar agreements for 2005, 2006 and 2007. At December 31, 2004, we would have been required to pay approximately $34.4 million to terminate our swap and collar agreements then in place.

 

The following table reflects the barrels covered by oil price swap agreements and the corresponding weighted average NYMEX reference prices by quarter:

 

Quarter Ending


   Bbls

  

NYMEX

Reference Price

Per Bbl


March 31, 2005

   1,242,000    $ 37.77

June 30, 2005

   1,255,800      36.49

September 30, 2005

   1,269,600      35.57

December 31, 2005

   1,269,600      34.88

March 31, 2006

   427,500      37.39

June 30, 2006

   432,250      36.80

September 30, 2006

   437,000      36.32

December 31, 2006

   437,000      35.93

March 31, 2007

   189,000      34.26

June 30, 2007

   63,700      39.66

September 30, 2007

   64,400      39.38

December 31, 2007

   64,400      39.10

 

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The following table reflects the MMBtu covered by gas price swap agreements and the corresponding weighted average NYMEX reference prices:

 

Quarter Ending


   MMBtu

  

NYMEX

Reference Price

Per MMBtu


March 31, 2005

   1,161,000    $ 6.65

June 30, 2005

   1,173,900      6.15

September 30, 2005

   1,186,800      6.17

December 31, 2005

   1,186,800      6.37

March 31, 2006

   243,000      6.47

June 30, 2006

   245,700      6.47

September 30, 2006

   248,400      6.47

December 31, 2006

   248,400      6.47

March 31, 2007

   225,000      6.00

June 30, 2007

   227,500      6.00

September 30, 2007

   230,000      6.00

December 31, 2007

   230,000      6.00

 

The following table reflects the MMBtu covered by gas price collar agreements and the corresponding NYMEX floor and cap reference prices:

 

MMBtu For

      2005


  

NYMEX Floor

Reference
Price Per
MMBtu


  

NYMEX Cap

Reference Price

Per MMBtu


1,825,000

   $ 6.00    $ 6.80

3,650,000

     6.00      8.02

1,825,000

     6.00      8.73

3,650,000

     6.00      9.21

 

The counterparties to our current hedging agreements are commercial or investment banks. We continue to monitor oil and gas prices and we may enter into additional oil and gas derivative transactions in the future.

 

Interest Rate Risk

 

Our interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based on borrowings from our commercial banks. To reduce the impact of fluctuations in interest rates, we have historically maintained a portion of our total debt portfolio in fixed-rate debt. At December 31, 2004, all of our outstanding debt was at fixed rates. However, we expect that this relationship will not continue and that a portion of our debt in future periods will be at variable rates. In the past, we have not entered into financial instruments such as interest rate swaps or interest rate lock agreements. However, we may consider these instruments to manage our portfolio mix between fixed and floating rate debt and to mitigate the impact of changes in interest rates based on our assessment of future interest rates, volatility of the yield curve and our ability to access the capital markets in a timely manner.

 

Because we had no outstanding borrowings under variable-rate debt instruments as of December 31, 2004, a change in the average interest rate of 100 basis points would result in no change in our net income (loss) and cash flows before income taxes.

 

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The following table provides information about our long-term debt, principal payments and weighted-average interest rates by expected maturity dates as of December 31, 2004:

 

     2005

   2006

   2007

   2008

   2009

   There-
after


    Total

   

Fair

Value at

12/31/04


Long-term Debt:

                                               

Fixed-rate (in thousands)

   —      —      —      —      —      $ 550,000     $ 550,000     $ 598,875

Average interest rate

   —      —      —      —      —        8.1 %     8.1 %     —  

Variable-rate (in thousands)

   —      —      —      —      —        —         —         —  

Average interest rate

   —      —      —      —      —        —         —         —  

 

Foreign Currency and Operations Risk

 

International investments represent, and are expected to continue to represent, a significant portion of our total assets. We currently have international operations in Argentina, Bolivia, Yemen and Bulgaria. For 2004, our operations in Argentina accounted for approximately 41 percent of our revenues from continuing operations and 38 percent of our total assets. During 2004, our operations in Argentina represented our only foreign operation accounting for more than 10 percent of our revenues from continuing operations or total assets. We continue to identify and evaluate international opportunities, but we currently have no binding agreements or commitments to make any material international investment. As a result of such significant foreign operations, our financial results could be affected by factors such as changes in foreign currency exchange rates, weak economic conditions or changes in the political climate in these foreign countries.

 

On September 24, 2004, we entered into a forward sale of C$340 million related to the proceeds that we expected to receive at the closing of the sale of our Canadian operations. We received $266.1 million and we accounted for this transaction as a cash flow hedge. Other than this hedge, we have historically not used derivatives or other financial instruments to hedge the risk associated with the movement in foreign currencies. However, we evaluate currency fluctuations and we will consider the use of derivative financial instruments or employment of other investment alternatives if we believe cash flows or investment returns so warrant.

 

Our international operations may be adversely affected by political and economic instability, changes in the legal and regulatory environment and other factors. For example:

 

    local political and economic developments, as well as labor unrest, could restrict or increase the cost of our foreign operations;

 

    exchange controls and currency fluctuations could result in financial losses;

 

    royalty and tax increases and retroactive tax claims could increase costs of our foreign operations;

 

    expropriation of our property could result in loss of revenue, property and equipment;

 

    civil uprisings, riots, terrorist attacks and wars could make it impractical to continue operations, adversely affect both budgets and schedules and expose us to losses;

 

    import and export regulations and other foreign laws or policies could result in loss of revenues;

 

    repatriation levels for export revenues could restrict the availability of cash to fund operations outside a particular foreign country; and

 

    laws and policies of the U.S. affecting foreign trade, taxation and investment could restrict our ability to fund foreign operations or may make foreign operations more costly.

 

We do not currently maintain political risk insurance. However, we will consider obtaining such coverage in the future if we deem conditions so warrant.

 

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Argentina. As a result of more than three years of economic instability and substantial withdrawals from the banking system, in early December 2001, the Argentine government, under President Fernando de la Rua, instituted restrictions that prohibit certain foreign money transfers without Central Bank approval and limit cash withdrawals from bank accounts to personal transactions in small amounts, with certain limited exceptions. In late December 2001, as a result of political riots and upheaval in response to the banking restrictions, Fernando de la Rua was removed as president and his successor, Adolfo Rodriguez Saa, immediately announced default on Argentina’s $140 billion sovereign debt.

 

In early January 2002, congress conferred power to Eduardo Duhalde, who enacted temporary measures intended to achieve economic stability and avoid default on multilateral debts. On January 6, 2002, the Argentine government abolished its convertibility law that required an exchange of one peso to one U.S. dollar. The exchange rate at December 31, 2004, was 2.98 pesos to one U.S. dollar. The devaluation of the peso reduced our gas revenues and peso-denominated costs. Our oil revenues remain valued on a U.S. dollar basis.

 

Monetary assets and liabilities denominated in pesos at December 31, 2004, were as follows (in thousands):

 

     Peso
Balance


    U.S. Dollar
Equivalent


 

Current assets

   33,337     $ 11,206  

Current liabilities

   (115,574 )     (38,848 )

Non-current liabilities

   (78,720 )     (26,461 )
    

 


Net liabilities

   (160,957 )   $ (54,103 )
    

 


 

On February 13, 2002, the Argentine government announced a 20 percent tax on oil exports, effective March 1, 2002. On May 11, 2004, the Argentine government increased the tax to 25 percent. The tax is applied on the sales value after the tax, thus the net effect of the 20 and 25 percent rates is 16.7 and 20 percent, respectively. On August 6, 2004, the Argentine government further increased the export tax rates for oil exports. The export tax now escalates from 25 percent (20 percent effective rate) to a maximum rate of 45 percent (31 percent effective rate) of the realized value for exported barrels as West Texas Intermediate posted prices per Bbl increase from less than $32.00 to $45.00 and above. This tax is limited by law to a maximum term through February 2007.

 

We currently export approximately 35 percent of our Argentine oil production; however, in 2004, we exported approximately 48 percent. The U.S. dollar equivalent value for domestic Argentine oil sales (now paid in pesos) has generally moved toward parity with the U.S. dollar-denominated export values, net of the export tax. The export tax is deducted for income tax purposes but is not deducted in the calculation of royalty payments.

 

In accordance with Executive Decree 1589/89, companies engaged in oil and gas production activities are granted the right to freely sell and dispose of their hydrocarbons production. Furthermore, companies are entitled to collect export sales proceeds outside of Argentina and maintain up to 70 percent of U.S. dollar collections outside the country. According to the decree, companies should repatriate the remaining 30 percent of export collections through the exchange markets of Argentina. This requirement places no significant limitations on us based upon our cash flow projections.

 

Beginning in December 2001, as a result of the economic crisis in the country, Argentina enacted several emergency decrees, including the reinstatement of foreign exchange controls and the mandatory repatriation of most export proceeds. The emergency decrees created some confusion in relation to the regime established under Executive Decree 1589/89, which allows hydrocarbons producers to retain 70 percent of their export collections outside of Argentina. In order to address this matter, Executive Decree No. 2703/02 was issued on December 27, 2002, which confirmed the right to maintain 70 percent of export proceeds outside the country effective January 1, 2003, and therefore did not address transactions which occurred during 2002 after the emergency decrees. We have collected and maintained as much as 70 percent of export proceeds in U.S. dollar bank accounts under the regime established by Executive Decree No. 1589/89 including transactions which occurred during 2002. Although we believe we have acted in accordance with the emergency measures and Executive Decrees in place during 2002, we are aware that the Argentine Central Bank has inquired about certain transactions made by other producers related to retention of export proceeds outside the country during the period in question.

 

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On November 5, 2004, we received a letter from the Ministry of Economy of the Argentine Province of Santa Cruz requesting that royalty payments made since March 2002 be amended to eliminate the market impact of the Argentine export tax on sales to domestic refiners. We believe this request is made without merit, as royalties are calculated and paid on the actual prices received from third party purchasers.

 

On December 24, 2004 the Secretary of Energy issued Administrative Resolution 1679/2004, in order to alleviate shortages in domestic diesel markets by insuring adequate oil supplies to Argentine refiners. The terms of the resolution require producers to submit evidence to the Secretary of Energy that its oil to be exported has been offered to domestic refiners prior to the government’s issuance of export permission.

 

After a year of negotiations, on January 24, 2003, the International Monetary Fund (“IMF”) executed a transitional $6.8 billion, eight-month stand-by credit arrangement to provide financial stability through the presidential elections. After a successful transition of government, and as a result of restoring a measure of economic stability and growth during 2002, in September 2003, the IMF approved a $13.5 billion stand-by credit arrangement, to be disbursed in stages over a three-year period, to succeed the transitional arrangement that expired on August 31, 2003. The economic program to which the Argentine government and the IMF agreed is based on a fiscal framework to meet growth, employment, and social objectives, while providing a basis for normalizing relations with creditors and ensuring debt sustainability. Additionally, they agreed to a strategy to assure strengthening of the banking system, to facilitate increases in bank lending, and to further institutional and tax reforms to facilitate corporate debt restructuring and fundamental improvements to the investment climate. On January 28, 2004, the IMF completed and approved its first review of Argentina’s performance under the three-year program. On March 22, 2004, the second review and disbursement of the next $3.1 billion tranche was approved. A third review is pending and is expected to be completed during 2005. On January 12, 2005, the Argentine government announced a debt swap offer to external creditors. The offer commenced on January 14, 2005 and concluded on February 25, 2005.

 

On March 3, 2005, the Argentine government announced a successful conclusion to the sovereign debt swap, reporting that 76 percent of bond holders will participate in the exchange. The bonds declared in default in December 2001 have a face value of US$81.8 billion, and including unpaid interest, now amount to approximately US$103 billion. The debt offered in exchange will be issued in April 2005 for approximately US$35.2 billion. After completion of the transaction, total public debt-service costs will be reduced from approximately US$10 billion to approximately US$3 billion per year. Since good faith negotiations with bond holders and public debt restructuring were important steps for continued negotiations with the IMF, it appears more likely that Argentina and the IMF will be able to either modify the stand-by credit arrangement in place or negotiate a new agreement during the near term. It is also likely that other issues outstanding between Argentina and the IMF must still be addressed prior to a new agreement, such as an increase to public utility tariffs, a new loan to govern the fiscal relationship between the federal government and provinces and reform of the banking system.

 

On January 2, 2003, at the Argentine government’s request, crude oil producers and refiners agreed to limit amounts payable for certain domestic sales occurring during the first quarter of 2003 to a maximum $28.50 per Bbl. The producers and refiners further agreed that the difference between the West Texas Intermediate posted price and the maximum price would be payable once the West Texas Intermediate posted price fell below the maximum. The debt payable under the agreement accrues interest at eight percent. The total debt will be collected by invoicing future deliveries at $28.50 per Bbl after the West Texas Intermediate posted price falls below the maximum price. Additionally, the agreement allowed for renegotiation if the West Texas Intermediate reference price exceeded $35.00 per Bbl for 10 consecutive days, which occurred on February 24, 2003.

 

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On February 25, 2003, the agreement between the producers and the refiners was modified to limit the amount payable from refiners to producers for deliveries occurring between February 26, 2003, and March 31, 2003. While the $28.50 per Bbl payable maximum was maintained, under the modified terms refiners have no obligation to pay producers for sales values that exceed $36.00 per Bbl. Furthermore, interest for debts established during this period was reduced to seven percent. This agreement expired on April 30, 2004. Through December 31, 2004, the accumulated balance of amounts which we may charge to domestic oil purchasers in Argentina, if the West Texas Intermediate posted price decreases below the established maximum price in the future, was approximately $6.8 million, excluding interest. We do not have the right to invoice for such amounts until such time as the West Texas Intermediate posted price declines below the established price cap of $28.50. Accordingly, we have adopted a revenue recognition accounting policy for this potential revenue in which we will record such revenue only upon the receipt of payment for this additional billing due to the uncertainty of recovery of such amounts and the timing thereof. During 2004, we did not record any revenue under this agreement. During 2003, we collected and recorded revenue of approximately $251,000. Such amounts represented all amounts we were entitled to invoice under the agreement.

 

We sold approximately 0.6 MMBbls of our net Argentine oil production (approximately six percent) under this agreement during 2004 and cumulatively, we have sold approximately 2.0 MMBbls of net oil production under the agreement. We have not recorded revenue nor a receivable for any amounts above the $28.50 per Bbl maximum that have not yet been received. Repayments received from refiners will be recorded as revenues when received. As of December 31, 2004, we had an unbilled potential recovery of approximately $6.8 million under this agreement, excluding interest. During 2004 and 2003, we collected and recognized in revenue zero and approximately $251,000, respectively, under such agreement.

 

Bolivia. Since replacing former President Gonzalo Sanchez de Lozada, who was forced to resign during October 2003, current President Carlos Mesa has been forced on several occasions to make changes to his cabinet team due to continued political pressure from rival political parties and associated social unrest. After a transportation strike and demonstrations by university students and government pensioners that were held in April 2004, labor unions began threatening to escalate unrest by announcing general strikes during May 2004. On July 18, 2004, voters approved President Mesa’s public referendum on several proposed changes in Bolivia’s Hydrocarbon Law, including the export of Bolivian gas.

 

As a result of the referendum, on July 30, 2004, President Mesa presented his proposed Hydrocarbons Law reform bill to the Bolivian congress for consideration. This proposal includes both increased state control over hydrocarbons commercialization and a new taxation regime. Since then, debate has been ongoing and members of congress and rival political parties have proposed changes to President Mesa’s reform bill. In early March 2005, political tensions escalated as the Bolivian congress voted among rival proposals concerning the bill’s new taxation regime. Leftist opposition groups, led by Evo Morales, have demanded that President Mesa’s taxation reform proposals be abandoned in favor of increasing royalty rates from the current 18 percent level to a new rate of 50 percent. On March 7, 2005, President Mesa submitted his letter of resignation to the Bolivian congress in protest of the proposal and in response to demonstrations and blockades initiated by the opposition groups. On March 8, 2005, in a strong show of support for President Mesa, the congress voted unanimously to reject his resignation. However, the opposition groups led by Morales have not yet agreed to abandon their competing Hydrocarbons Law proposal.

 

In March 2004, the Bolivian government enacted a new tax on all banking transactions, except for payments made to the Bolivian government. The tax is effective for two years beginning July 1, 2004, and will be 0.3 percent for the first year and 0.25 percent the second year. We do not expect this tax to have a significant impact on future periods.

 

During August 2004, in response to protests concerning high oil prices, the Bolivian government issued Decree 27691, which limited the amounts that condensate producers could invoice Bolivian refiners to a maximum price of $27.11 per Bbl. The decree also established a floor price of $24.53 per Bbl.

 

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On January 7, 2005, the Bolivian government issued Executive Decree 27967, stating that prices in the internal Bolivian gas distribution market could not exceed the average of the last three natural gas purchase agreements registered with the Superintendent of Hydrocarbons. In accordance with the Executive Decree on February 3, 2005, the Superintendent of Hydrocarbons issued Resolution SSDH 124-2005 determining the new maximum price in the Bolivian gas distribution market to be US$0.80 per Mcf, effective February 4, 2005, and its terms are effective until April 30, 2006. All natural gas purchase agreements in place with Bolivian local distribution companies prior to the resolution are required to lower their price in accordance with the terms of the new resolution. In 2005 and 2006, we have contracted volumes of 1.0 Bcf and 0.3 Bcf, respectively which are impacted by the decree. Also, we expect that our 2005 and 2006 revenues will be reduced by approximately $230,000 and $100,000, respectively, as a result of the current resolution.

 

Bolivian gas markets have historically been limited to exports to Brazil via the Bolivia-to-Brazil gas pipeline and to those internal gas sales necessary to meet Bolivian industrial and consumer demand. We are working to increase sales in both of these areas and we currently have capacity to deliver gas volumes in excess of our contracted volumes. The current daily productive capacity of our properties in Bolivia is approximately 45 MMcf of gas, gross and 28 MMcf of gas, net. During the past several years, Bolivian gas reserve growth has exceeded the demand growth in Bolivia’s existing markets. Therefore, we believe substantial competition for gas markets will continue at least until new market areas are established. On April 21, 2004, the Argentine and Bolivian governments agreed to a gas supply arrangement for 141 MMcf per day of gas to Argentina for a six-month period beginning in May 2004, and in July 2004, the government signed a letter of intent to increase those exports by 88 MMcf per day. As a result, our Bolivian sales volumes have increased in the third quarter of 2004. However, it is unclear if these increased sales volumes will continue in future periods. On October 14, the Argentine and Bolivian governments signed a letter of intent for Bolivia to export up to 706 MMcf per day, which is estimated to commence during 2006. This additional quantity is subject to the successful conclusion of a Hydrocarbon Law reform which proves to be acceptable to investors. With the June 2004 approval from the Bolivian public in the referendum on the matter of gas exports, we believe that new projects, such as exports to Mexico and the U.S., as well as additional exports to Argentina, will become feasible in the future, also subject to the successful conclusion of a Hydrocarbon Law reform which proves to be acceptable to investors.

 

In 1987, the Boliviano replaced the peso and became Bolivia’s currency. The exchange rate is set daily by the government’s exchange house, “The Bolsin”, which is under the supervision of the Bolivian Central Bank. Foreign exchange transactions are not subject to any controls. The exchange rate at December 31, 2004, was 8.06 Bolivianos to one U.S. dollar. Since our gas revenues are received in U.S. dollars, we believe that any currency risk associated with our Bolivian operations would not have a material impact on our financial position or results of operations.

 

Yemen. Yemen has been classified as a low-income developing country by the World Bank. Trade and other external economic links have been limited, with the exception of the oil sector, which accounts for more than 25 percent of Yemen’s gross domestic product. The production sharing agreements under which private investors operate are clear and unambiguous, resulting in most of the country’s foreign investment being concentrated in the oil sector. The government has relaxed the broader regulatory environment to encourage additional foreign investments. However, obstacles such as an insufficient infrastructure continue to exist. Necessary economic reforms began during 1995 and were supported by both the IMF and the World Bank. The reforms were targeted to enable a more market-based and private sector driven economy and more integration into world markets, all within the context of broad financial and macro-economic stability. These reforms continue to influence Yemen’s economic policies today.

 

Yemen has taken significant steps to stabilize its political environment since the end of its civil war in 1994. The government is dominated by northern Yemen, located in the capital city of Sana’a and headed by President Ali Abdullah Saleh, who is a member of the General People’s Congress. The General People’s Congress has held power since the mid-1990’s and regime change is considered to be unlikely. Civil society is relatively weak and tribal structures remain powerful. Concerns about terrorism and kidnappings are ongoing security risks. Further concerns about continued implementations of economic reform measures as well as increased government control are ongoing business risks. We have evaluated the risk of operating in Yemen and we believe that the current risks are manageable.

 

Item 8. Financial Statements and Supplementary Data.

 

Our consolidated Financial Statements and notes thereto, the report of our independent auditors and our supplementary financial information are included elsewhere in this Form 10-K.

 

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

 

None.

 

Item 9A. Controls and Procedures.

 

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended) as of December 31, 2004. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in our periodic filings under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. As reported in our Form 10-Q for the three month and nine month period ended September 30, 2004, we identified a material weakness in our internal control over financial reporting as of September 30, 2004. The material weakness was the failure of our monitoring control review to detect a material computation error in a hedge effectiveness worksheet, which error was significant to our consolidated financial statements and was not detected prior to our third quarter earnings press release. The error was detected and corrected prior to the filing of our Form 10-Q. This material weakness was remediated during the fourth quarter through a complete review by management of the hedge analysis process and related worksheets and an improvement in our monitoring control reviews over such computations. During the fourth quarter of 2004, there were no other changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

Management’s report on internal control over financial reporting as of December 31, 2004 is included on page 73 of this Form 10-K. The attestation report of our independent registered public accounting firm is included on page 74 of this Form 10-K.

 

Item 9B. Other Information.

 

None.

 

PART III

 

Item 10. Directors and Executive Officers of the Registrant.

 

The information required by Item 401 of Regulation S-K with respect to our Directors is incorporated by reference from the section of our definitive Proxy Statement for our 2005 Annual Meeting of Stockholders (the “Proxy Statement”) entitled “Election of Directors.” The information required by Item 401 of Regulation S-K with respect to our Executive Officers appears at Item 4A of Part I of this Form 10-K. The information required by Item 405 of Regulation S-K is incorporated by reference from the section of our Proxy Statement entitled “Section 16(a) Beneficial Ownership Reporting Compliance.”

 

Code of Ethics. We have adopted a Code of Ethics for our Chief Executive Officer and senior financial officers. The Code of Ethics is publicly available on our website at http://www.vintagepetroleum.com. If we make any substantive amendments to the Code of Ethics or grant any waiver, including any implicit waiver, from a provision of the Code of Ethics to our Chief Executive Officer, Chief Financial Officer or Corporate Controller, we will disclose the nature of such amendment or waiver on that website.

 

Item 11. Executive Compensation.

 

The information required by this Item is incorporated by reference from the sections of our Proxy Statement entitled “Election of Directors” and “Executive Compensation.”

 

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

 

The information required by this Item, other than the information required by Item 201(d) of Regulation S-K, is incorporated by reference from the section of our Proxy Statement entitled “Principal Stockholders and Security Ownership of Management.” The information required by Item 201(d) of Regulation S-K is set forth below.

 

Equity Compensation Plan Information

 

The following table provides information as of December 31, 2004, concerning shares of our common stock authorized for issuance under our existing equity compensation plans.

 

     (a)

    (b)

    (c)

 

Plan Category


  

Number of Securities

to be Issued Upon

Exercise of Outstanding

Options, Warrants

and Rights


   

Weighted Average Exercise

Price of Outstanding

Options, Warrants

and Rights


   

Number of Securities

Remaining Available for

Future Issuance

Under Equity Compensation

Plans (Excluding Securities

Reflected in Column (a))


 
Equity compensation plans approved by security holders    1,662,967 (1)   $ 11.12 (1)   4,241,851 (2)
Equity compensation plans not approved by security holders    —         —       —    
    

 


 

Total

   1,662,967     $ 11.12     4,241,851  
    

 


 


(1) Includes 149,667 shares subject to non-vested stock rights. The weighted average exercise price does not take these rights into account.
(2) Represents the total number of shares available for issuance under our 1990 Stock Plan pursuant to stock options, stock appreciation rights or non-vested stock or non-vested stock rights. All of the 4,241,851 shares available for issuance under our 1990 Stock Plan may be awarded as non-vested stock or non-vested stock rights. Under the 1990 Stock Plan, 10 percent of the total number of outstanding shares of our common stock, less the total number of shares of our common stock subject to outstanding awards under any other stock-based plan for our employees or our directors, is available for issuance to our key employees and our directors.

 

Item 13. Certain Relationships and Related Transactions.

 

The information required by this Item is incorporated by reference from the section of our Proxy Statement entitled “Certain Transactions.”

 

Item 14. Principal Accountant Fees and Services.

 

The information required by this Item is incorporated by reference from the sections of our Proxy Statement entitled “Fees of Independent Registered Public Accounting Firm” and “Audit Committee Pre-Approval Policy.”

 

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PART IV

 

Item 15. Exhibits and Financial Statement Schedules.

 

(a)

 

(1)

 

Financial Statements:

        Our consolidated financial statements and reports of independent registered public accounting firm listed in the accompanying Index to Financial Statements are filed as a part of this Form 10-K.

   

(2)

 

Financial Statements Schedules:

 

All schedules are omitted because they are inapplicable or because the required information is contained in the financial statements or included in the notes thereto.

 

(3) Exhibits:

 

The following documents are included as exhibits to this Form 10-K. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, such exhibit is filed herewith.

 

3.1    Restated Certificate of Incorporation, as amended, of the Company (Filed as Exhibit 3.2 to the Company’s report on Form 10-Q for the quarter ended June 30, 2000, filed August 11, 2000).
3.2    Restated By-laws of the Company (Filed as Exhibit 3.2 to the Company’s Registration Statement on Form S-1, Registration No. 33-35289 (the “S-1 Registration Statement”)).
4.1    Form of stock certificate for Common Stock, par value $0.005 per share (Filed as Exhibit 4.1 to the S-1 Registration Statement).
4.2    Indenture dated as of May 30, 2001, between JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee, and the Company (Filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-4, Registration No. 333-63896).
4.3    Indenture dated as of May 2, 2002, between JPMorgan Chase Bank, as Trustee, and the Company (Filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-4, Registration No. 333-89182).
4.4    Rights Agreement, dated March 16, 1999, between the Company and Mellon Investor Services LLC (formerly ChaseMellon Shareholder Services, L.L.C.), as Rights Agent (Filed as Exhibit 4.1 to the Company’s Registration Statement on Form 8-A, filed March 22, 1999).
4.5    First Amendment to Rights Agreement, dated as of April 3, 2002, between the Company and Mellon Investor Services LLC (formerly ChaseMellon Shareholder Services, L.L.C.), as Rights Agent (Filed as Exhibit 4.1 to the Company’s Amendment No. 1 to Registration Statement on Form 8-A, filed April 3, 2002).
4.6    Certificate of Designation of Series A Junior Participating Preferred Stock of the Company (Filed as Exhibit 3.3 to the Company’s Registration Statement on Form S-3, Registration No. 333-77619).
10.1*    Form of Indemnification Agreement between the Company and certain of its officers and directors (Filed as Exhibit 10.23 to the S-1 Registration Statement).
10.2*    Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 4(d) to the Company’s Registration Statement on Form S-8, Registration No. 33-37505).
10.3*    Amendment No. 1 to Vintage Petroleum, Inc. 1990 Stock Plan, effective January 1, 1991 (Filed as Exhibit 10.15 to the Company’s report on Form 10-K for the year ended December 31, 1991, filed March 30, 1992).

 

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10.4*    Amendment No. 2 to Vintage Petroleum, Inc. 1990 Stock Plan dated February 24, 1994 (Filed as Exhibit 10.15 to the Company’s report on Form 10-K for the year ended December 31, 1993, filed March 29, 1994).
10.5*    Amendment No. 3 to Vintage Petroleum, Inc. 1990 Stock Plan dated March 15, 1996 (Filed as Exhibit A to the Company’s Proxy Statement for Annual Meeting of Stockholders dated April 1, 1996).
10.6*    Amendment No. 4 to Vintage Petroleum, Inc. 1990 Stock Plan dated March 11, 1998 (Filed as Exhibit A to the Company’s Proxy Statement for Annual Meeting of Stockholders dated March 31, 1998).
10.7*    Amendment No. 5 to Vintage Petroleum, Inc. 1990 Stock Plan dated March 16, 1999 (Filed as Exhibit A to the Company’s Proxy Statement for Annual Meeting of Stockholders dated March 31, 1999).
10.8*    Amendment No. 6 to Vintage Petroleum, Inc. 1990 Stock Plan dated March 17, 2000 (Filed as Exhibit A to the Company’s Proxy Statement for Annual Meeting of Stockholders dated March 30, 2000).
10.9*    Amendment No. 7 to Vintage Petroleum, Inc. 1990 Stock Plan dated January 27, 2005.
10.10*    Vintage Petroleum, Inc. Non-Management Director Stock Option Plan (Filed as Exhibit 10.18 to the Company’s report on Form 10-K for the year ended December 31, 1992, filed March 31, 1993 (the “1992 Form 10-K”)).
10.11*    Form of Incentive Stock Option Agreement under the Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.20 to the Company’s report on Form 10-K for the year ended December 31, 1990, filed April 1, 1991).
10.12*    Form of Non-Qualified Stock Option Agreement under the Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.20 to the 1992 Form 10-K).
10.13*    Form of Non-Qualified Stock Option Agreement for non-employee directors under the Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.13 to the Company’s report on Form 10-K for the year ended December 31, 1999, filed March 13, 2000).
10.14*    Form of Restricted Stock Award Agreement under the Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.3 to the Company’s report on Form 10-Q for the quarter ended June 30, 2002, filed August 9, 2002).
10.15*    Form of Restricted Stock Rights Award Agreement under the Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.1 to the Company’s report on Form 10-Q for the quarter ended September 30, 2002, filed November 14, 2002).
10.16*    Form of Restricted Stock Rights Award Agreement for executive officers under the Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.2 to the Company’s report on Form 10-Q for the quarter ended June 30, 2004, filed August 6, 2004).
10.17*    Form of Restricted Stock Award Agreement under the Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.3 to the Company’s report on Form 10-Q for the quarter ended June 30, 2004, filed August 6, 2004).
10.18*    Form of Restricted Stock Award Agreement for non-employee directors under the Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10 to the Company’s current report on Form 8-K dated November 9, 2004, filed November 10, 2004).
10.19*    Form of Restricted Stock Rights Award Agreement for non-employee directors under the Vintage Petroleum, Inc. 1990 Stock Plan.
10.20*    Vintage Petroleum, Inc. Amended and Restated Discretionary Performance Bonus Program.
10.21*    Vintage Petroleum, Inc. Performance-Based Cash Bonus Program for Chief Executive Officer.

 

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10.22*    Separation Agreement and Release dated March 3, 2004, between the Company and S. Craig George (Filed as Exhibit 10.1 to the Company’s report on Form 10-Q for the quarter ended March 31, 2004, filed May 7, 2004).
10.23    Credit Agreement dated as of May 2, 2002, among the Company, as borrower, and certain commercial lending institutions, as lenders, Bank of Montreal, as agent, and the Syndication Agent and Co-Documentation Agents party thereto (Filed as Exhibit 10.1 to the Company’s report on Form 10-Q for the quarter ended June 30, 2002, filed August 9, 2002).
10.24    First Amendment to Credit Agreement dated as of May 24, 2002, among the Company, as borrower, the lenders party thereto, Bank of Montreal, as administrative agent, Deutsche Bank Trust Company Americas, as syndication agent, and Fleet National Bank, Societe Generale and The Bank of New York, as co-documentation agents (Filed as Exhibit 10.2 to the Company’s report on Form 10-Q for the quarter ended June 30, 2002, filed August 9, 2002).
10.25    Second Amendment to Credit Agreement dated as of May 24, 2002, among the Company, as borrower, the lenders party thereto, Bank of Montreal, as administrative agent, Deutsche Bank Trust Company Americas, as syndication agent, and Fleet National Bank, Societe Generale and The Bank of New York, as co-documentation agents (Filed as Exhibit 10.1 to the Company’s report on Form 10-Q for the quarter ended June 30, 2003, filed August 8, 2003).
10.26    Third Amendment to Credit Agreement dated as of May 12, 2004, among the Company, as borrower, the lenders party thereto, Bank of Montreal, as administrative agent, Deutsche Bank Trust Company, as syndication agent, and Fleet National Bank, Societe Generale and the Bank of New York, as co-documentation agents (Filed as Exhibit 10.1 to the Company’s report on Form 10-Q for the quarter ended June 30, 2004, filed August 6, 2004).
10.27    Stock Purchase Agreement dated September 22, 2004, among Midnight Oil & Gas Ltd., as Purchaser, and Vintage Petroleum Canada Investments ULC, Vintage Canada Oil & Gas ULC, and Vintage South America Holdings, Inc., as Sellers (Filed as Exhibit 2.1 to the Company’s report on Form 10-Q for the quarter ended September 30, 2004, filed November 9, 2004).
10.28    Stock Purchase Amending and Assignment Agreement dated October 20, 2004, among Midnight Oil & Gas Ltd., as Assignor, Vintage Petroleum Canada Investments ULC, Vintage Canada Oil & Gas ULC, and Vintage Petroleum South America Holdings, Inc., as Sellers, and Daylight Acquisition Corp, as Assignee (Filed as Exhibit 2.2 to the Company’s report on Form 10-Q for the quarter ended September 30, 2004, filed November 9, 2004).
21.    Subsidiaries of the Company.
23.1    Consent of Ernst & Young LLP.
23.2    Consent of Netherland, Sewell & Associates, Inc.
23.3    Consent of DeGolyer and MacNaughton.
23.4    Consent of DeGolyer and MacNaughton Canada Limited.
31.1    Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and Section 302 of the Sarbanes-Oxley Act of 2002.
31.2    Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Section 302 of the Sarbanes-Oxley Act of 2002.
32.1    Certification of Chief Executive Officer pursuant to Rule 13a-14(b) and Section 906 of the Sarbanes-Oxley Act of 2002.
32.2    Certification of Chief Financial Officer pursuant to Rule 13a-14(b) and Section 906 of the Sarbanes-Oxley Act of 2002.

* Management contract or compensatory plan or arrangement.

 

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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.

 

   

VINTAGE PETROLEUM, INC.

Date: March 11, 2005

 

By:

 

/s/ C. C. Stephenson, Jr.


       

C. C. Stephenson, Jr.

       

Chairman of the Board, President

and Chief Executive Officer

 

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:

 

Signature


 

Title


 

Date


/s/ C. C. Stephenson, Jr.


C. C. Stephenson, Jr

 

Director, Chairman of the Board,

President and Chief Executive Officer

(Principal Executive Officer)

  March 11, 2005

/s/ William L. Abernathy


William L. Abernathy

 

Director, Executive Vice President

and Chief Operating Officer

  March 11, 2005

/s/ William C. Barnes


William C. Barnes

 

Director, Executive Vice President,

Chief Financial Officer, Secretary and

Treasurer (Principal Financial Officer)

  March 11, 2005

/s/ Rex D. Adams


Rex D. Adams

  Director   March 11, 2005

/s/ Bryan H. Lawrence


Bryan H. Lawrence

  Director   March 11, 2005

/s/ Joseph D. Mahaffey


Joseph D. Mahaffey

  Director   March 11, 2005

/s/ Gerald J. Maier


Gerald J. Maier

  Director   March 11, 2005

/s/ John T. McNabb, II


John T. McNabb, II

  Director   March 11, 2005

/s/ Michael F. Meimerstorf


Michael F. Meimerstorf

 

Vice President and Controller

(Principal Accounting Officer)

  March 11, 2005

 

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INDEX TO FINANCIAL STATEMENTS

 

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

 

     Page

AUDITED FINANCIAL STATEMENTS OF VINTAGE PETROLEUM, INC. AND SUBSIDIARIES:

    

Report of Management on Assessment of Internal Control over Financial Reporting

   73

Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting

   74

Report of Independent Registered Public Accounting Firm

   75

Consolidated Balance Sheets as of December 31, 2004 and 2003

   76

Consolidated Statements of Operations for the years ended December 31, 2004, 2003 and 2002

   78

Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2004, 2003 and 2002

   80

Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002

   81

Notes to Consolidated Financial Statements for the years ended December 31, 2004, 2003 and 2002

   82

 

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REPORT OF MANAGEMENT ON ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING

 

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States. The Company’s internal control over financial reporting includes those policies and procedures that:

 

    pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

 

    provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States, and that receipts and expenditures of the Company are being made only in accordance with authorization of management and directors of the Company; and

 

    provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

 

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

 

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Management’s assessment included evaluation of the design and testing of the operational effectiveness of the Company’s internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of the Company’s Board of Directors.

 

Based on our assessment and those criteria, management believes that, as of December 31, 2004, the Company’s internal control over financial reporting is effective.

 

Ernst & Young LLP, the Company’s independent registered public accounting firm, has issued an attestation report on management’s assessment of the Company’s internal control over financial reporting. That report appears on page 74.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC

ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING

 

To the Board of Directors and Stockholders

of Vintage Petroleum, Inc.:

 

We have audited management’s assessment, included in the accompanying Report of Management on Assessment of Internal Control Over Financial Reporting, that Vintage Petroleum, Inc. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

 

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

 

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

 

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

 

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s consolidated balance sheets as of December 31, 2004 and 2003 and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2004, and our report dated March 11, 2005 expressed an unqualified opinion thereon.

 

 

ERNST & YOUNG LLP

 

Tulsa, Oklahoma

March 11, 2005

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and Stockholders

of Vintage Petroleum, Inc.:

 

We have audited the accompanying consolidated balance sheets of Vintage Petroleum, Inc. and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

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

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Vintage Petroleum, Inc. and subsidiaries as of December 31, 2004 and 2003, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States.

 

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. In addition, as also discussed in Note 1, effective January 1, 2002, the Company adopted the provisions of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets.

 

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Vintage Petroleum, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 11, 2005, expressed an unqualified opinion thereon.

 

 

ERNST & YOUNG LLP

 

Tulsa, Oklahoma

March 11, 2005

 

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except shares and per share amounts)

 

     December 31,

     2004

   2003

ASSETS              

CURRENT ASSETS:

             

Cash and cash equivalents

   $ 124,221    $ 32,264

Accounts receivable -

             

Oil and gas sales

     107,870      78,321

Joint operations

     12,479      7,480

Income taxes receivable

     31,571      7,421

Prepaids and other current assets

     23,648      6,660

Deferred income taxes

     15,364      —  

Assets of discontinued operations

     —        224,321
    

  

Total current assets

     315,153      356,467
    

  

PROPERTY, PLANT AND EQUIPMENT, at cost:

             

Oil and gas properties, successful efforts method

     2,163,176      1,835,588

Oil and gas gathering systems and plants

     23,926      23,344

Other

     31,932      26,334
    

  

       2,219,034      1,885,266

Less accumulated depreciation, depletion and amortization

     942,656      829,055
    

  

Total property, plant and equipment, net

     1,276,378      1,056,211
    

  

DEFERRED INCOME TAXES

     13,200      —  
    

  

OTHER ASSETS, net

     40,161      41,581
    

  

TOTAL ASSETS

   $ 1,644,892    $ 1,454,259
    

  

 

The accompanying notes are an integral part of these statements.

 

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Continued)

(In thousands, except shares and per share amounts)

 

     December 31,

     2004

    2003

LIABILITIES AND STOCKHOLDERS’ EQUITY

              

CURRENT LIABILITIES:

              

Revenue payable

   $ 33,740     $ 22,641

Accounts payable - trade

     50,775       41,893

Current income taxes payable

     23,565       23,545

Derivative financial instrument payable

     27,672       7,551

Other payables and accrued liabilities

     73,748       61,507

Liabilities of discontinued operations

     —         47,286
    


 

Total current liabilities

     209,500       204,423
    


 

LONG-TERM DEBT

     549,949       699,943
    


 

DEFERRED INCOME TAXES

     80,383       41,234
    


 

LONG-TERM LIABILITY FOR ASSET RETIREMENT OBLIGATIONS

     90,707       72,158
    


 

OTHER LONG-TERM LIABILITIES

     30,675       14,015
    


 

COMMITMENTS AND CONTINGENCIES (Note 4)

              

STOCKHOLDERS’ EQUITY, per accompanying statements:

              

Preferred stock, $0.01 par, 5,000,000 shares authorized, zero shares issued and outstanding

     —         —  

Common stock, $0.005 par, 160,000,000 shares authorized, 66,541,984 and 64,720,975 shares issued and 66,012,252 and 64,281,199 outstanding, respectively

     333       324

Capital in excess of par value

     361,120       337,080

Retained earnings

     342,707       22,844

Accumulated other comprehensive income (loss)

     (13,088 )     70,482
    


 

       691,072       430,730

Less treasury stock, at cost, 529,732 and 439,776 shares, respectively

     4,319       3,117

Less unamortized cost of non-vested stock awards

     3,075       5,127
    


 

Total stockholders’ equity

     683,678       422,486
    


 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

   $ 1,644,892     $ 1,454,259
    


 

 

The accompanying notes are an integral part of these statements.

 

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

 

     For the Years Ended December 31,

 
     2004

    2003

    2002

 

REVENUES:

                        

Oil, condensate and NGL sales

   $ 516,756     $ 428,350     $ 380,032  

Gas sales

     188,582       114,049       83,902  

Sulfur sales

     1,366       1,715       653  

Gas marketing

     71,476       70,633       54,391  
    


 


 


Total revenues

     778,180       614,747       518,978  
    


 


 


COSTS AND EXPENSES:

                        

Production costs

     141,040       124,367       111,925  

Transportation and storage costs

     11,086       7,401       7,011  

Production and ad valorem taxes

     23,007       17,469       15,420  

Export taxes

     43,050       31,041       24,824  

Exploration costs

     31,993       21,607       22,942  

Gas marketing

     67,601       68,038       52,781  

General and administrative

     56,473       46,908       38,574  

Stock compensation

     7,619       5,259       845  

Depreciation, depletion and amortization

     103,202       87,814       104,872  

Impairment of proved oil and gas properties

     6,049       6,050       16,972  

Accretion

     6,626       5,980       —    

Other operating expense

     2,327       6,067       6,061  
    


 


 


Total costs and expenses

     500,073       428,001       402,227  
    


 


 


OPERATING INCOME

     278,107       186,746       116,751  
    


 


 


NON-OPERATING (INCOME) EXPENSE:

                        

Interest expense

     51,815       69,834       77,314  

Loss on early extinguishment of debt

     9,903       6,909       8,154  

Derivative losses

     21,745       1,539       465  

(Gain) loss on disposition of assets

     (155 )     1,194       (16,553 )

Foreign currency exchange (gain) loss

     (775 )     6,710       (269 )

Other non-operating (income) expense

     644       (788 )     (2,065 )
    


 


 


Net non-operating expense

     83,177       85,398       67,046  
    


 


 


Income from continuing operations before income taxes and cumulative effect of changes in accounting principles

     194,930       101,348       49,705  
    


 


 


INCOME TAX PROVISION (BENEFIT):

                        

Current

     57,906       40,140       16,008  

Deferred

     11,583       1,714       (1,274 )
    


 


 


Total income tax provision

     69,489       41,854       14,734  
    


 


 


Income from continuing operations before cumulative effect of changes in accounting principles

     125,441       59,494       34,971  

INCOME (LOSS) FROM DISCONTINUED OPERATIONS, net of income tax benefit of $30,722, $112,902 and $47,865, respectively

     207,151       (307,520 )     (118,088 )
    


 


 


Income (loss) before cumulative effect of changes in accounting principles

     332,592       (248,026 )     (83,117 )

CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES, net of income tax provision of zero, $4,104 and zero, respectively

     —         7,119       (60,547 )
    


 


 


NET INCOME (LOSS)

   $ 332,592     $ (240,907 )   $ (143,664 )
    


 


 


 

The accompanying notes are an integral part of these statements.

 

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Continued)

(In thousands, except per share amounts)

 

     For the Years Ended December 31,

 
     2004

   2003

    2002

 

BASIC INCOME (LOSS) PER SHARE:

                       

Income from continuing operations before cumulative effect of changes in accounting principles

   $ 1.93    $ 0.93     $ 0.55  

Income (loss) from discontinued operations

     3.18      (4.80 )     (1.86 )
    

  


 


Income (loss) before cumulative effect of changes in accounting principles

     5.11      (3.87 )     (1.31 )

Cumulative effect of changes in accounting principles

     —        0.11       (0.96 )
    

  


 


Net income (loss)

   $ 5.11    $ (3.76 )   $ (2.27 )
    

  


 


DILUTED INCOME (LOSS) PER SHARE:

                       

Income from continuing operations before cumulative effect of changes in accounting principles

   $ 1.91    $ 0.92     $ 0.55  

Income (loss) from discontinued operations

     3.15      (4.77 )     (1.86 )
    

  


 


Income (loss) before cumulative effect of changes in accounting principles

     5.06      (3.85 )     (1.31 )

Cumulative effect of changes in accounting principles

     —        0.11       (0.95 )
    

  


 


Net income (loss)

   $ 5.06    $ (3.74 )   $ (2.26 )
    

  


 


Weighted average common shares outstanding:

                       

Basic

     65,046      64,022       63,219  
    

  


 


Diluted

     65,784      64,497       63,456  
    

  


 


 

The accompanying notes are an integral part of these statements.

 

79


Table of Contents
Index to Financial Statements

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands, except treasury shares and per share amounts)

 

     Common Stock

   Treasury
Stock


   

Capital

In Excess of
Par Value


   

Unamortized

Non-Vested
Stock
Awards


    Retained
Earnings


   

Accumulated

Other

Comprehensive
Income (Loss)


    Total

 
   Shares

   Amount