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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2004

OR

For the transition period from             to             

Commission file number 1-10578

VINTAGE PETROLEUM, INC.

(Exact name of registrant as specified in its charter)

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

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

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.

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VINTAGE PETROLEUM, INC.

FORM 10-K

YEAR ENDED DECEMBER 31, 2004

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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:

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:

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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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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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:

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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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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:

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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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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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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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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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.

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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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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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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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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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:

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:

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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:

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):

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 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.

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:

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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:

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:

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

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:

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: