-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Ao4dRdTatXzloAKRJ88YvgN/A0W21ts/gQVfxmc/FlXmyJtZuYVIpYmYxKqruVh4 imm0OLXWiRkQJpbsyRoGiA== 0000930661-00-000532.txt : 20000314 0000930661-00-000532.hdr.sgml : 20000314 ACCESSION NUMBER: 0000930661-00-000532 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000313 FILER: COMPANY DATA: COMPANY CONFORMED NAME: VINTAGE PETROLEUM INC CENTRAL INDEX KEY: 0000809428 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 731182669 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-10578 FILM NUMBER: 568205 BUSINESS ADDRESS: STREET 1: 110 WEST SEVENTH STREET CITY: TULSA STATE: OK ZIP: 74119 BUSINESS PHONE: 9185920101 MAIL ADDRESS: STREET 1: 110 WEST SEVENTH STREET CITY: TULSA STATE: OK ZIP: 74119 10-K405 1 FORM 10-K405 ================================================================================ SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1999 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number 1-10578 VINTAGE PETROLEUM, INC. (Exact name of registrant as specified in its charter) Delaware 73-1182669 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 110 West Seventh Street Tulsa, Oklahoma 74119-1029 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (918) 592-0101 Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on which registered ------------------- ------------------- Common Stock, $.005 Par Value New York Stock Exchange Preferred Share Purchase Rights New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No _____ ----- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] As of February 29, 2000, 62,411,866 shares of the Registrant's Common Stock were outstanding, and the aggregate market value of the Common Stock held by non-affiliates was approximately $725,961,000. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Registrant's Proxy Statement for the Annual Meeting of Stockholders to be held May 9, 2000, are incorporated by reference into Part III of this Form 10-K. ================================================================================ VINTAGE PETROLEUM, INC. FORM 10-K YEAR ENDED DECEMBER 31, 1999 TABLE OF CONTENTS
PART I Page ---- Items 1 and 2. Business and Properties.................................................................... 1 Item 3. Legal Proceedings.......................................................................... 21 Item 4. Submission of Matters to a Vote of Security-Holders........................................ 21 Item 4A. Executive Officers of the Registrant....................................................... 22 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters...................... 25 Item 6. Selected Financial Data.................................................................... 26 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations...... 27 Item 7A. Quantitative and Qualitative Disclosures About Market Risk................................. 36 Item 8. Financial Statements and Supplementary Data................................................ 38 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....... 38 PART III Item 10. Directors and Executive Officers of the Registrant......................................... 38 Item 11. Executive Compensation..................................................................... 38 Item 12. Security Ownership of Certain Beneficial Owners and Management............................. 38 Item 13. Certain Relationships and Related Transactions............................................. 38 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................ 39 Signatures................................................................................................... 42 Index to Financial Statements................................................................................ 43
i Certain Definitions As used in this Form 10-K: Unless the context requires otherwise, all references to the "Company" include Vintage Petroleum, Inc., its consolidated subsidiaries and its proportionately consolidated general partner interests in various joint ventures. "Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf" means billion cubic feet, "BCFE" means billion cubic feet of gas equivalent, "MMbtu" means million British thermal units, "Bbl" means barrel, "MBbls" means thousand barrels, "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/o/ Fahrenheit. Equivalent barrels of oil are determined using the ratio of six Mcf of gas to one Bbl of oil. The term "gross" refers to the total acres or wells in which the Company has a working interest, and "net" refers to gross acres or wells multiplied by the percentage working interest owned by the Company. "Net production" means production that is owned by the Company less royalties and production due others. The terms "net" and "net production" include 100 percent of the Company's subsidiary Cadipsa S.A. and do not reflect reductions for minority interest ownership. The term "oil" includes crude oil, condensate and natural gas liquids. "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. ii 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 the Company expects or anticipates 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: . the amount and nature of future capital expenditures; . wells to be drilled or reworked; . oil and gas prices and demand; . exploitation and exploration prospects; . estimates of proved oil and gas reserves; . reserve potential; . development and infill drilling potential; . expansion and other development trends of the oil and gas industry; . business strategy; . production of oil and gas reserves; . expansion and growth of our business and operations; and . Year 2000 plans and compliance. These statements are based on certain assumptions and analyses made by the Company in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate in the circumstances. However, whether actual results and developments will conform with the Company's expectations and predictions is subject to a number of risks and uncertainties which could cause actual results to differ materially from the Company's expectations, including: . the risk factors discussed in this Form 10-K and listed from time to time in the Company's filings with the Securities and Exchange Commission; . oil and gas prices; . exploitation and exploration successes; . continued availability of capital and financing; . general economic, market or business conditions; . the acquisition and other business opportunities (or lack thereof) that may be presented to and pursued by the Company; . changes in laws or regulations; and . other factors, most of which are beyond the control of the Company. 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 the Company will be realized or, even if substantially realized, that they will have the expected consequences to or effects on the Company or its business or operations. The Company assumes no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events or otherwise. iii PART I Items 1 and 2. Business and Properties. General The Company is an independent oil and gas company focused on the acquisition of oil and gas properties which contain the potential for increased value through exploitation and exploration. The Company, through its experienced management and technical staff, has 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. The Company believes that its primary strengths are its ability to add reserves at attractive prices, its technical expertise and its low cost operating structure. At December 31, 1999, the Company owned and operated producing properties in 13 states in the United States, with its domestic proved reserves located primarily in four core areas: the Gulf Coast, East Texas, Mid-Continent and West Coast areas of the United States. During 1999, the Company acquired additional producing properties in California. See "Acquisition Activities." In addition, the Company has international core areas located in Argentina, Bolivia and Ecuador. In Argentina the Company owns 15 oil concessions, 14 of which are operated by the Company, in the south flank of the San Jorge Basin in southern Argentina. During 1999, the Company expanded this core area with the purchase of the El Huemul concession. See "Acquisition Activities." In Bolivia, the Company owns and operates three blocks covering approximately 570,000 acres in the Chaco Plains area of southern Bolivia and the Naranjillos concession located in the Santa Cruz Province. In November 1998, the Company purchased, through a wholly-owned subsidiary, a subsidiary of Elf Aquitaine which operates through a branch in Ecuador. This subsidiary currently operates producing properties in the Oriente Basin and provides the Company with substantial undeveloped acreage which the Company believes has significant exploration potential. During 1999, the Company increased its ownership in these properties by purchasing an additional interest from one of its partners. See "Acquisition Activities." As of December 31, 1999, the Company owned interests in 3,505 gross (2,712 net) productive wells in the United States, of which approximately 82 percent are operated by the Company, 1,057 gross (1,040 net) productive wells in Argentina, of which approximately 98 percent are operated by the Company, 16 gross (15 net) productive wells in Bolivia, 100 percent of which are operated by the Company, and 8 gross (6 net) productive wells in Ecuador, 100 percent of which are operated by the Company. As of December 31, 1999, the Company's properties had proved reserves of 468.0 MMBOE, comprised of 303.2 MMBbls of oil and 989.0 Bcf of gas, with a present value of estimated future net revenues before income taxes (utilizing a 10 percent discount rate) of $3.0 billion and a standardized measure of discounted future net cash flows of $2.2 billion. From the first quarter of 1997 through the fourth quarter of 1999, the Company increased its average net daily production from 37,325 Bbls of oil to 50,250 Bbls of oil and from 97,700 Mcf of gas to 142,150 Mcf of gas. Financial information relating to the Company's industry segments is set forth in Note 8 "Segment Information" to the Company's consolidated financial statements included elsewhere in this Form 10-K. The Company was incorporated in Delaware on May 31, 1983. The Company's principal office is located at 110 West Seventh Street, Tulsa, Oklahoma 74119- 1029, and its telephone number is (918) 592-0101. 1 Business Strategy The Company's overall goal is to maximize its value through profitable growth in its oil and gas reserves and production. The Company has been successful at achieving this goal through its ongoing strategy of (a) acquiring producing oil and gas properties, at favorable prices, with significant upside potential, (b) focusing on exploitation, development and exploration activities to maximize production and ultimate reserve recovery, (c) exploring non- producing properties, (d) maintaining a low cost operating structure and (e) maintaining financial flexibility. Key elements of the Company's strategy include: . Acquisitions of Producing Properties. The Company has an experienced management and technical team which focuses on acquisitions of operated producing properties that meet its selection criteria which include (a) significant potential for increasing reserves and production through exploitation, development and exploration, (b) attractive purchase price and (c) opportunities for improved operating efficiency. The Company's emphasis on property acquisitions reflects its belief that continuing consolidation and restructuring activities on the part of major integrated and large independent oil companies has afforded in recent years, and should afford in the future, attractive opportunities to purchase domestic and international properties. This acquisition strategy has allowed the Company to rapidly grow its reserves at favorable acquisition prices. From January 1, 1997, through December 31, 1999, the Company acquired 184.3 MMBOE of proved oil and gas reserves at an average acquisition cost of $2.23 per BOE. The Company replaced through acquisitions approximately 260 percent of its production of 71.8 MMBOE during the same period. The Company is continually identifying and evaluating acquisition opportunities, including acquisitions that would be significantly larger than those consummated to date by the Company. No assurance can be given that any such acquisitions will be successfully consummated. . Exploitation and Development. The Company pursues workovers, recompletions, secondary recovery operations and other production optimization techniques on its properties, as well as development and infill drilling, to offset normal production declines and replace the Company's annual production. From January 1, 1997, through December 31, 1999, the Company spent approximately $220.2 million on exploitation and development activities. During this period, the Company's recompletion and workover activities resulted in improved production or operating efficiencies in approximately 72 percent of these operations. As a result of all of its exploitation activities, including development and infill drilling, during the three-year period ended December 31, 1999, the Company succeeded in adding 65.7 MMBOE to proved reserves, replacing approximately 91 percent of production during this period. During 1999, excluding the impact of significantly higher year-end oil and gas prices, the Company added 14.7 MMBOE through exploitation, replacing 59 percent of production even though exploitation capital spending was curtailed for a portion of 1999. The impact of higher year-end oil and gas prices resulted in an additional 75.4 MMBOE of reserve additions in 1999, which more than replaced the 49.0 MMBOE of proved reserves lost at year-end 1998 due to historically low oil and gas prices. The Company continues to maintain an extensive inventory of exploitation and development opportunities. Due to the improved product price environment, the Company anticipates increasing its level of spending to approximately $79 million in 2000 on exploitation and development projects, primarily in the United States and Argentina. 2 . Exploration. The Company's overall exploration strategy balances high potential international prospects with lower risk drilling in known formations in the United States and Argentina. This prospect mix and the Company's practice of risk-sharing with industry partners is intended to lower the incidence and costs of dry holes. The Company makes extensive use of geophysical studies, including 3-D seismic, which further reduces the cost by increasing the success of its exploration program. From January 1, 1997, through December 31, 1999, the Company spent approximately $150.8 million on exploration activities, including the drilling of 72 gross (42.28 net) exploration wells, of which approximately 56 percent gross (68 percent net) were productive. As a result of all of the Company's exploration activities during the three-year period ending December 31, 1999, the Company succeeded in adding 55.7 MMBOE to proved reserves, replacing approximately 78 percent of production during this period. The Company's exploration activities in 1999 were focused on its core areas in the United States and Bolivia. The Company anticipates spending approximately $67 million during 2000 on exploration projects, primarily in the United States, Bolivia, Yemen and Ecuador. . Low Cost Structure. The Company is an efficient operator and capitalizes on its low cost structure in evaluating acquisition opportunities. The Company generally achieves substantial reductions in labor and other field level costs from those experienced by the previous operators. In addition, the Company targets acquisition candidates which are located in its core areas and provide opportunities for cost efficiencies through consolidation with other Company operations. The lower cost structure has generally allowed the Company to substantially improve the cash flow of newly acquired properties. . Financial Flexibility. The Company is committed to maintaining financial flexibility, which management believes is important for the successful execution of its acquisition, exploitation and exploration strategy. In conjunction with the purchase of substantial oil and gas assets in 1990, 1992, 1995 and 1999, the Company completed four public equity offerings, as well as a public debt offering in 1995. The Company also successfully completed simultaneous public debt and equity offerings in February 1997, and a private debt offering in January 1999, under Rule 144A. These eight offerings provided the Company with aggregate net proceeds of approximately $643 million. The unused portion of the Company's revolving credit facility as of February 29, 2000, was approximately $363 million. Acquisition Activities Historically, the Company has allocated a substantial portion of its capital expenditures to the acquisition of producing oil and gas properties. The Company's continuing emphasis on reserve additions through property acquisitions reflects its belief that consolidation and restructuring activities on the part of major integrated and large independent oil companies has afforded in recent years, and should afford in the future, attractive opportunities to purchase domestic and international producing properties. Since the Company's incorporation in May 1983, it has been actively engaged in the acquisition of producing oil and gas properties primarily in the Gulf Coast, East Texas and Mid-Continent areas of the United States, and in California since April 1992. In 1995, a series of acquisitions made by the Company established a new core area in the San Jorge Basin in southern Argentina. In late 1996, the Company expanded its South American operations into Bolivia and in 1998 into Ecuador. The Company is constantly identifying and evaluating additional acquisition opportunities which may lead to expansion into new domestic core areas or other countries which the Company believes are politically and economically stable. 3 From January 1, 1997, through December 31, 1999, the Company made oil and gas property acquisitions involving total costs of approximately $411.6 million. As a result of these acquisitions, the Company acquired approximately 184.3 MMBOE of proved oil and gas reserves. The following table summarizes the Company's acquisition experience during the periods indicated:
Proved Reserves When Acquired Cost ----------------------------------- Per Boe Acquisition Oil Gas When Costs (MBbls) (MMcf) MBOE Acquired -------------- --------- -------- -------- ---------- (In thousands) U.S. Acquisitions: 1997........................................ $ 133,548 24,653 62,253 35,029 $3.81 1998........................................ 70,805 5,452 53,027 14,290 4.96 1999........................................ 31,662 10,343 14,947 12,834 2.47 ---------- ------- ------- ------- Total U.S. Acquisitions................ 236,015 40,448 130,227 62,153 3.80 ---------- ------- ------- ------- International Acquisitions: 1997........................................ 6,201 758 111,212 19,293 0.32 1998........................................ 34,218 21,577 - 21,577 1.59 1999........................................ 135,125 67,734 81,072 81,246 1.66 ---------- ------- ------- ------- Total International Acquisitions....... 175,544 90,069 192,284 122,116 1.44 ---------- ------- ------- ------- Total U.S. and International Acquisitions...... $ 411,559 130,517 322,511 184,269 $2.23 ========== ======= ======= =======
The Company estimates that 94.1 MMBOE of proved reserves, as of the various acquisition dates, were acquired in 1999 for an aggregate cost attributable to oil and gas assets of $166.8 million, resulting in an average cost of $1.77 per BOE. This average cost per BOE is substantially lower than the Company's average acquisition cost over the three-year period ended December 31, 1999, of $2.23 per BOE and the average acquisition cost since the Company's inception of $2.63 per BOE. The following is a brief discussion of the significant acquisitions in 1999: Nuevo Energy Company (West Coast). In December 1999, the Company purchased from Nuevo Energy Company and its affiliate certain oil and gas producing properties and facilities located in the Ventura basin of Southern California for $29.6 million in cash (the "Nuevo Acquisition"). This acquisition increases the Company's significant producing presence in the Ventura basin and is expected to allow the Company to achieve operating cost efficiencies with minimal requirements for additional overhead or infrastructure costs. The properties acquired consist of 13 mature onshore fields in which the Company has an average working interest of 94 percent and a 100 percent operating interest in the Santa Clara Valley gas plant which processes all of the gas from these properties as well as other third party gas. The Company now operates 90 percent of the wells, which have total current net daily production averaging approximately 2,190 Bbls of mid-gravity crude oil and natural gas liquids and 3,000 Mcf of gas. In addition to the expected operating cost efficiencies, the properties contain various recompletion and infill drilling opportunities. Total and Repsol S.A.- El Huemul concession (Argentina). In July 1999, the Company acquired from Total Austral S.A. and Repsol S.A. their undivided 100 percent operating interest (effective 88 percent net revenue interest) in the El Huemul-Koluel Kaike concession (the "El Huemul Properties") located in Santa Cruz Province, Argentina, which Total previously operated (the "El Huemul Acquisition"). The purchase price for the El Huemul Acquisition was $121.0 million in cash. 4 The El Huemul Properties cover approximately 150,000 gross acres and are located adjacent to the Company's existing operated concessions in the Santa Cruz Province. The El Huemul Properties are similar to the Company's existing properties in this basin and are characterized by mature fields having stable production decline trends, similar geological formations and production zones, established waterflood potential and exploration and exploitation upside potential. Because of these similarities, the Company believes that the exploitation and exploration success it has experienced in its current Argentina operations, including development drilling, workovers and recompletions, secondary recovery projects and exploratory drilling, will be available in the El Huemul Properties as well. The Company estimates that the El Huemul Properties have proved exploitation potential through adding new non-producing behind pipe zones in 107 wells, expanding upon the 13 waterflood areas and infill or extensional drilling of up to 66 new wells. In addition, the Company has identified non-proved opportunities within the concession that include behind pipe zones in 117 wells, installing up to 18 additional waterflood areas and 50 additional drilling locations. There is also exploration potential that the Company identified from a review of 3-D seismic provided during the evaluation process. Proved reserves for the El Huemul Properties as of July 1, 1999, as estimated by Netherland, Sewell & Associates, Inc., using a NYMEX reference oil price of $17.32 per Bbl and an average gas price of $1.02 per Mcf, were 44.7 MMBbls of oil and 81.1 Bcf of gas, or 58.2 MMBOE, with a present value of the estimated future net revenues before income taxes (utilizing a 10 percent discount rate) of $233.3 million. Daily production at the time of acquisition, net of royalties, was approximately 9,400 Bbls of oil and 19,000 Mcf of gas, or 12,567 BOE, from 462 active producing wells. The Company was able to reduce operating costs on the El Huemul Properties to a level consistent with its historical operating costs in Argentina by combining certain aspects of the operations with those of its nearby existing properties. The Company experienced no significant additions to its overhead costs as a result of this acquisition. Petrobras International (Ecuador). In December 1999, the Company, through its wholly-owned subsidiary Vintage Oil Ecuador S.A., purchased from Petrobras Internacional S.A. - Braspetro additional working interests in Block 14, Block 17 and the Shiripuno concession located in the Oriente Basin of Ecuador for $14.1 million in cash. The Company acquired an additional 35 percent working interest in the Block 14 producing concession increasing its interest to 75 percent, an additional 40 percent interest in the Block 17 producing concession increasing its interest to 70 percent and an additional 47 percent in the Shiripuno exploration concession increasing its interest to 100 percent. As a result of this transaction, the Company's net daily production increased 87 percent from 1,925 Bbls to 3,600 Bbls. 5 Divestiture Activities During 1999, the Company instituted a divestiture program designed to sell Company properties that are either marginally economical or non-strategic to the Company's areas of operation. As part of this program, the Company sold approximately 227 leases, primarily non-operated, for cash proceeds of approximately $9.5 million resulting in gains of $7.7 million ($4.7 million after tax). The Company estimates the properties sold accounted for proved reserves of approximately 2.6 Bcf of gas and 577 MBbls of oil as of the closing dates for these sales. The Company's divestiture program is expected to continue during 2000 with targeted additional estimated proceeds to be raised of $30 to $55 million. During December 1999, the Company sold its interest in certain oil and gas properties located in northern California's Sacramento basin to Calpine Corporation for $70.0 million, subject to consents and customary post-closing adjustments. In a separate transaction with an undisclosed buyer, the Company sold certain royalty interests in Los Angeles county, California for $8.2 million. Combined, the Company estimates the properties sold accounted for proved reserves of approximately 32.1 Bcf of gas and 682 MBbls of oil as of the closing dates for these sales. Net daily production from the properties sold totals approximately 250 Bbls of oil and 14.3 MMcf of gas, or approximately 3.5 percent of the Company's net average daily production rate on a BOE basis for the fourth quarter of 1999. The Company does not expect that the sale of these properties will have a material impact on its continuing operations. A portion of the proceeds from these property sales were used to fund the Nuevo Acquisition and the proceeds in excess of the Nuevo Acquisition costs were used to reduce a portion of the Company's outstanding debt. The sales resulted in $47.3 million in gains ($28.9 million after tax) which were included in the Company's 1999 operating results. Exploitation and Development Activities The Company concentrates its acquisition efforts on proved producing properties which 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. The Company has pursued an active workover, recompletion and development drilling program on the properties it has acquired and intends to continue these activities in the future. The Company's exploitation staff focuses on maximizing the value of the properties within its reserve base striving to offset normal production declines and to replace the Company's annual production. The results of their efforts are reflected in revisions to reserves. Net revisions to reserves for 1999 (before the impact of higher oil and gas prices) totaled 14.7 MMBOE, or 59 percent of the Company's production of 24.9 MMBOE. The impact of higher year-end 1999 oil and gas prices on year-end 1998 proved reserves and the reserves acquired in mid-1999 added another 75.4 MMBOE to the Company's year-end 1999 proved reserves, more than replacing the reserves lost to the historically low oil price environment of last year. As a result of a restricted capital budget due to low oil and gas prices, the Company only spent $10.8 million on workover and recompletion operations during 1999, significantly lower than in prior years. A measure of the overall success of the Company's recompletion and workover operations during 1999 (excluding minor equipment repair and replacement) was that improved production or operating efficiencies were achieved from approximately 71 percent of such operations consistent with the average for the last three years of 72 percent. Development drilling activity is generated both through the Company's 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 Company leases currently producing oil and gas. The Company intends to continue to pursue development drilling opportunities which offer potentially significant returns to the Company. 6 During 1999, the Company participated in the drilling of 18 gross (13.94 net) development wells, of which 17 gross (12.94 net) were productive. At December 31, 1999, the Company's proved reserves included approximately 126 development or infill drilling locations on its U.S. acreage and 186 locations on its Argentine acreage. In addition, the Company has an extensive inventory of development and infill drilling locations on its existing properties which are not included in proved reserves. As a result of low oil and gas prices, the Company significantly reduced its capital expenditure budget for 1999 and only spent approximately $3.6 million in the U.S. and $7.9 million in South America on development/infill drilling during 1999. The Company also spent approximately $2.3 million on the acquisition of development seismic data and other development costs in 1999. With the return of higher commodity prices, the Company has increased its 2000 capital budget for development and exploitation work to $79 million with spending primarily aimed at U.S. and Argentina reserves. In connection with its exploitation focus, the Company actively pursues operating cost reductions on the properties it acquires. The Company believes that its cost structure and operating practices generally result in improved operating economics. Although each situation is unique, the Company generally has achieved reductions in labor and other field level costs from those experienced by the previous operators, particularly in its acquisitions from major oil companies. The following is a brief discussion of significant developments in the Company's recent exploitation and development activities: United States. Compared to previous years, 1999 exploitation efforts were severely curtailed due to low oil and gas prices. Recompletions and workover activities were limited in 1999 and produced a 64 percent success rate. Most of this work was to repair artificial lift equipment or install lift on wells that had ceased to flow naturally. Recompletions to new zones were attempted in 14 wellbores, 10 of which were successful. The State Tract 65-2, a 1999 development well drilled as the result of the successful exploratory State Tract 65-1 well which was a part of the Galveston Bay-Umbrella Point exploration program, is currently producing from the Text II formation at gross daily rates of 170 Bbls of oil and 17.9 MMcf of gas. The Company has a 50 percent working interest in this well. The Company expects to spend $38 million in 2000 for various U.S. exploitation projects including recompletions, sidetracks and development drilling with approximately 50 percent budgeted to be spent in the Gulf Coast area, primarily in the Company's South Pass Blk 24 and Main Pass Blk 116 fields. South America. The Company's international exploitation budget of $41 million is heavily weighted toward projects in three of its concessions in Argentina: El Huemul, Meseta Espinosa and Canadon Seco. Development and extensional drilling along with the implementation and optimization of secondary recovery projects have been the focus of the Company's historical exploitation efforts on its Argentina properties. Drilling activity commenced during February 1996, and continued through 1998, with 154 wells having been completed. In January 1999, the Company suspended its Argentina drilling program due to historic low oil prices. Following the recovery in oil prices, the Company re- initiated drilling operations in August 1999. The three focus areas for drilling activity to date have been Canadon Minerales with 56 wells, Canadon Seco with 43 wells and Meseta Espinosa with 45 wells. The Company's successful exploitation program has resulted in a gross daily production increase from 10,200 Bbls of oil in January 1996, to over 19,180 Bbls of oil in January 1999. The Company is currently drilling with one rig and plans call for adding a second rig during the year. The addition of the El Huemul concession during 1999 has provided significant additional drilling opportunities which the Company plans to pursue during 2000 and beyond. To aid in the optimum placement of drilling locations in Argentina, the Company has acquired a total of 204 square miles (527 square kilometers) of 2-D and 3-D seismic since 1996. The Company believes that substantial upside potential can continue to be economically exploited with the aid of this 3-D seismic. Additionally, with only approximately 15 percent of the Company's acreage covered by 3-D seismic, the Company believes that significant additional drilling potential will continue to be identified though the acquisition of future 3-D seismic surveys. 7 The Company has also continued its endeavor to optimize existing secondary recovery projects and to initiate new waterfloods in Argentina. Only a small portion of the producing areas of the concessions controlled by the Company have been subject to secondary recovery operations. The Company believes that numerous other areas presently under primary recovery are amenable to waterflooding. The Company also believes that the utilization of 3-D seismic will enhance the ultimate recovery derived from these new waterflood projects and be a valuable tool in identifying new secondary recovery project areas that previously would have gone undeveloped. The addition of the El Huemul concession during 1999 provides substantial additional existing waterflood projects and affords extensive areas amenable to future waterflood expansion projects. The Company has focused its exploitation work in Bolivia on its Naranjillos concession in conjunction with the ongoing exploration work required to fulfill the work commitment for this concession. As a result of additional geological and petrophysical information gained from the wells drilled during 1999, the year-end proven reserves for the previous known shallow reservoirs were revised upward to 284 BCFE, a 21 percent increase over year-end 1998. Other activity involved facility improvement required to allow gas to flow from the Naranjillos concession into the Bolivia-to-Brazil pipeline. Although currently curtailed due to demand restrictions, the work to date has positioned the Company to be able to take immediate advantage of the increasing gas market opportunities through the Bolivia-to-Brazil pipeline and other developing market opportunities in Brazil and Bolivia. The Company has focused its exploitation work in Ecuador on upgrading the production facilities to increase the oil handling capacity from 3,500 Bbls of oil per day to approximately 10,000 Bbls of oil per day commensurate with the Block 14 and Block 17 development plans approved by the Ecuadorian government during December 1998. During late 1999, high-capacity artificial lift equipment was installed on two producing wells, which increased the combined productive capacity of the Block 14 and Block 17 concessions from 3,500 Bbls of oil per day to 5,800 Bbls of oil per day. This is the present production allocation for these concessions. Additional infill drilling on Block 14 and Block 17 will be dependent on the timing of the Ecuadorian government's approval and the construction of an additional pipeline for transportation of oil. Exploration Activities The Company's exploration program is designed to contribute significantly to its growth. Management divides the strategic objectives of its exploration program into two parts. First, in the U.S. and in Argentina, the Company's exploration focus is in its core areas where its geological and engineering expertise and experience are greatest. State-of-the-art technology, including 3-D seismic, is employed to identify prospects. Exploration in the U.S. and Argentina is designed to generate reserve growth in the Company's core areas in combination with its exploitation activities. The Company's longer-term plans are to increase the magnitude of this program 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. International exploration projects in Bolivia, Yemen and Ecuador are characterized by higher potential and higher risk. The Company spent approximately $46.1 million on exploration activities during 1999, approximately $38.7 million in the U.S. and Bolivia and approximately $7.4 million in other international areas. The following is a brief discussion of the primary areas of exploration activity for the Company: United States. Since the initial discovery in 1996, the Company has made successful completions on nine of 12 wells drilled in its Galveston Bay-Umbrella Point exploration program in its Gulf Coast area. Gross oil and gas production from these wells reached a peak of approximately 76 MMcf of gas per day and 1,600 Bbls of oil per day and are currently producing at gross daily rates of 37 MMcf of gas and 1,120 Bbls of oil. The Company plans to drill two additional wells in the Umbrella Point field during the first half of 2000. 8 During 1999, the Company extended its exploration activities in the Galveston Bay area to the Cedar Point field. The recently completed USX Hematite Unit #1 was the most significant well drilled in 1999. The Company has a 47 percent working interest in this well. This Lower Vicksburg discovery is currently producing at gross rates of 600 Bbls of oil per day and 11.3 MMcf of gas per day. The Company plans to drill two more exploration wells during 2000 in this field. The Company's $17 million domestic exploration budget for 2000 is targeted primarily toward gas prospects and includes activities in three of its four U.S. core areas. Along with the two Gulf Coast Cedar Point wells, the Company plans to drill up to eight wells in its Stagecoach prospect and three wells in its Western Oklahoma Alliance, both areas of which are located in the Company's Mid- Continent core area. The Company also has three gas properties in its West Coast Sacramento basin it plans to drill during 2000. Bolivia. The Company believes that its existing projects in Bolivia have the potential to continue to significantly increase reserves. Activity in Bolivia during 1999 included the drilling of five wells targeting the Devonian Iquiri and Los Monos formations. These wells resulted in the addition of 99 BCFE of newly discovered reserves. The Company believes that significant exploration potential remains to be tested. During 2000, the Company will drill three deep wells that will test the potential of the deeper Devonian Huamampampa and Santa Rosa formations. Exploration results of other operators in Bolivia during 1999 demonstrated the significant potential of these reservoirs. Additional potential drilling locations targeting the shallow Carboniferous and deep Devonian Iquiri, Huamampampa and Santa Rosa reservoirs also have been identified on the Company's Chaco Block. Yemen. The Company entered into a farm-in agreement during 1998 with TransGlobe Energy to explore on the S-1 Damis Block in central Yemen. The block covers approximately one million acres (4,484 square kilometers). The Company earned a 75 percent interest in the S-1 Damis Block for its commitment to fulfill 100 percent of the initial phase exploration work program consisting of 3-D seismic and drilling three exploration wells. The Company completed a 175 square kilometer (68 square mile) 3-D seismic survey in early 1999 and subsequently selected the three drilling locations. The first prospect, An Naeem, is an offset to the adjacent Halewah field which is currently producing approximately 25,000 Bbls of oil per day. Drilling of these three wells is scheduled for the first half of 2000. Ecuador. The Company originally joined in a project to explore Block 19 in the Oriente Basin in Ecuador with a 30 percent working interest. Numerous commercially productive fields have been discovered in this basin. Primary targets are the Hollin, Napo "U" and Napo "T" sands that are productive in other significant fields in this basin. The first of two obligatory exploration wells was drilled and abandoned during 1997 after testing at sub-commercial rates. During 1999, the Company assumed its partners' working interests in this concession and is proceeding with plans to drill its Rio Cotapino prospect during 2000. Oil and Gas Properties At December 31, 1999, the Company owned and operated producing properties in 13 states, with its U.S. proved reserves located primarily in four core areas: the Gulf Coast, East Texas, Mid-Continent and West Coast areas. In addition, the Company established new core areas in the San Jorge Basin of Argentina during 1995, Bolivia during 1996 and Ecuador in 1998. As of December 31, 1999, the Company operated approximately 3,942 productive wells and also owned non-operating interests in 644 productive wells. The Company continuously evaluates the profitability of its oil, gas and related activities and has a policy of divesting itself of unprofitable leases or areas of operations that are not consistent with its operating philosophy. See "Divestiture Activities." 9 The following table sets forth estimates of the proved oil and gas reserves of the Company at December 31, 1999, as estimated by the independent petroleum consultants of Netherland, Sewell & Associates, Inc. ("Netherland, Sewell") for the United States, Argentina and Ecuador and as estimated by the independent petroleum consultants of DeGolyer and MacNaughton for Bolivia:
Oil (MBbls) Gas (MMcf) MBOE -------------------------------- -------------------------------- Developed Undeveloped Total Developed Undeveloped Total Total --------- ----------- ----- --------- ----------- ----- ------- West Coast............. 53,196 6,706 59,902 104,515 8,212 112,727 78,690 Gulf Coast............. 29,754 7,495 37,249 75,602 20,718 96,320 53,302 East Texas............. 8,098 502 8,600 75,960 12,884 88,844 23,407 Mid-Continent.......... 3,674 1,017 4,691 46,367 16,767 63,134 15,213 ------- ------- ------- ------- ------- ------- ------- Total U.S........... 94,722 15,720 110,442 302,444 58,581 361,025 170,612 ------- ------- ------- ------- ------- ------- ------- Argentina.............. 90,125 46,346 136,471 92,696 20,940 113,636 155,412 Bolivia................ 6,414 1,667 8,081 415,743 98,585 514,328 93,802 Ecuador................ 5,524 42,672 48,196 - - - 48,196 ------- ------- ------- ------- ------- ------- ------- Total Company....... 196,785 106,405 303,190 810,883 178,106 988,989 468,022 ======= ======= ======= ======= ======= ======= =======
Estimates of the Company's 1999 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. The Company's non-producing proved reserves are largely behind-pipe in fields which it operates. Undeveloped proved reserves are predominantly infill drilling locations and secondary recovery projects. The following is a brief discussion of the Company's oil and gas operations in its core areas: West Coast Area. The West Coast area includes oil and gas properties located primarily in Kern, Ventura, Santa Barbara and Sacramento counties of California. The Stevens, Forbes, Grubb and Sisquoc formations are the dominant producing reservoirs on the Company's acreage in California with well depths ranging from 800 feet to 14,300 feet. As of December 31, 1999, the area comprised 17 percent of the Company's total proved reserves and 46 percent of the Company's U.S. proved reserves. The Company currently operates 1,335 active wells and owns an interest in 174 productive wells operated by others. During 1999, total net daily production averaged approximately 16,500 BOE, or 40 percent of total U.S. production. Numerous workovers and recompletion opportunities exist in the San Miguelito, Rio Vista, Buena Vista and Rincon fields. Additional infill drilling locations are available in the San Miguelito and Buena Vista fields. The San Miguelito field also has significant waterflood potential that may add significant reserves. Gulf Coast Area. The Gulf Coast area includes properties located in south Texas, the south half of Louisiana, Alabama, Mississippi and wells located in state and federal waters in the Gulf of Mexico. Production in this area is predominantly from structural accumulations in reservoirs of Miocene age. The depths of the producing reservoirs range from 1,200 feet to 14,500 feet. At December 31, 1999, the Gulf Coast area comprised approximately 11 percent of the Company's total proved reserves and 31 percent of its U.S. proved reserves. The Company currently operates 754 productive wells in this area and owns an additional interest in 140 productive wells. Total net daily production from this area during 1999 averaged approximately 15,800 BOE, or 38 percent of total U.S. production. A significant inventory of workovers and recompletions exist in eight major Gulf Coast fields from Alabama to South Texas. Development drilling potential is also available in six fields in Texas and Louisiana. 10 East Texas Area. The East Texas area includes properties located in the northeastern portion of Texas and the north half of Louisiana. The Cotton Valley, Smackover, Travis Peak and Wilcox formations are the dominant producing reservoirs on the Company's acreage in this area from wells ranging in depth from 1,300 feet to 14,800 feet. The East Texas area comprised approximately five percent of the Company's December 31, 1999, total proved reserves and 14 percent of its U.S. proved reserves. The Company currently operates 542 productive wells in this area and owns an interest in an additional 116 productive wells. During 1999, net daily production averaged approximately 5,500 BOE, or 13 percent of total U.S. production. Significant infill drilling potential exists on the Company's acreage in the South Gilmer, Southern Pine, Rosewood, Bethany Longstreet and Bear Grass 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 the Company's acreage in this area with well depths ranging from 1,560 feet to 17,260 feet. This area comprised three percent of the Company's December 31, 1999, total proved reserves and nine percent of its U.S. proved reserves. The Company currently operates 252 productive wells in this area and owns an interest in an additional 192 productive wells. During 1999, net daily production averaged approximately 3,750 BOE, or nine percent of total U.S. production. Significant development drilling and recompletion opportunities exist in the Marlow/Velma field plus additional projects to improve the ultimate reserve recovery in the Shawnee Townsite waterflood. Argentina Concessions. The Argentina properties consist primarily of 15 mature producing concessions, 14 of which are operated by the Company, located on the south flank of the San Jorge Basin. These concessions comprised approximately 33 percent of the Company's December 31, 1999, total proved reserves. During 1999, net daily production averaged approximately 20,700 Bbls of oil and 12,825 Mcf of gas including six months of production from the El Huemul concession interest acquired in July 1999. The Company currently operates 1,035 productive wells (100 percent working interest) with net daily production of 24,200 Bbls of oil and 16,900 Mcf of gas. In addition, the Company owns an interest in 22 productive wells operated by others. At December 31, 1999, the Company's proved reserves included approximately 186 development or infill drilling locations and 388 workovers on its Argentina acreage. In addition, the Company has an extensive inventory of workovers and development or infill drilling locations on its Argentina properties which are not included in proved reserves. For additional information, see "Exploitation and Development Activities - South America." Bolivia Concessions. The Bolivia properties consist of two producing concessions and two exploration concessions located in the Chaco Basin of Bolivia. The Company has 100 percent working interests in the Chaco and Naranjillos exploration concessions as well as in the producing Porvenir concession. In the other producing concession, Nupuco, the Company has a 50 percent working interest. The Company operates all four concessions. These concessions comprise approximately 20 percent of the Company's December 31, 1999, total proved reserves and include 6 gross (5 net) active producing wells, all of which are operated by the Company. The Company also has 10 gross (10 net) productive wells in its operated Naranjillos concession which were shut-in at year end due to the current limited gas demand in Brazil. Current net daily production is restricted to approximately 10,400 Mcf of gas and 175 Bbls of condensate. The Company is working to develop additional gas markets, both inside and outside of Bolivia, to increase the level of production from its concessions. For additional information, see "Exploitation and Development Activities - South America." 11 Ecuador Concessions. The Ecuador properties consist of two producing concessions and two exploration concessions. The Company has a 70 percent working interest in the producing Block 17 concession and a 75 percent working interest in the producing Block 14 concession. The Company also has a 100 percent interest in both the Shiripuno and Block 19 exploration concessions. The Company currently operates 8 gross (6 net) productive wells with current gross daily production of 5,800 Bbls of oil (3,740 Bbls net). These concessions comprised 10 percent of the Company's December 31, 1999, total proved reserves. During the fourth quarter of 1999, the production facilities were upgraded to increase the oil handling capacity from 3,500 Bbls of oil per day to approximately 10,000 Bbls of oil per day, commensurate with the Block 14 and Block 17 development plans approved during December 1998, by the Ecuadorian government. During the last half of 1999, high-capacity artificial lift equipment was installed on two of the producing wells to increase the combined productive capacity of the Block 14 and Block 17 concessions from 3,500 Bbls of oil per day to 5,800 Bbls of oil per day. Additional infill drilling on Block 14 and Block 17 will be dependent on the timing of the Ecuadorian government's approval and the construction of an additional pipeline for transportation of oil. Marketing The Company's U.S. gas production and gathered gas are 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 none of the Company's gas in the U.S. is committed to long-term fixed-price contracts, the Company is positioned to take advantage of rising prices for gas but it is also subject to gas price declines. The Company's Bolivia average gas price is tied to a long-term contract under which the base price is adjusted for changes in specified fuel oil indexes. During 1999, these fuel oil indexes have increased in conjunction with the current higher oil price environment. In Argentina, the Company's average gas price is primarily determined by the realized price of oil from the El Huemul concession. The Company's domestic gas marketing activities are handled by Vintage Gas, Inc., its wholly-owned gas marketing affiliate. This marketing affiliate earns fees through the marketing of Company produced gas as well as purchases of gas on the spot market from third parties. Generally, the marketing affiliate purchases this gas on a month-to-month basis at a percentage of resale prices. Generally, the Company's domestic oil production is sold under short-term contracts at posted prices plus a premium in some cases. The Company's Argentina oil production is currently sold at port to Esso S.A.P.A., ARCO, ENAP and Shell C.A.P.S.A. at West Texas Intermediate spot prices less a specified differential. The Company's Ecuador Block 14 oil production is sold to various third party purchasers at West Texas Intermediate spot prices less a specified differential. The Company's Ecuador Block 17 oil production is delivered under a risk-service contract to Petroecuador and revenue is received based on the average price of oil sales realized by Petroecuador during each month. During 1999, approximately 14 percent and 11 percent of the Company's normal operating revenues related to oil sales to Esso S.A.P.A. and Shell C.A.P.S.A., respectively. 12 The Company has previously engaged in oil and gas hedging activities and intends to continue to consider various hedging arrangements to realize commodity prices which it considers favorable. In 1999, the Company entered into various oil hedges (swap agreements) covering 1.8 MMBbls at a weighted average price of $22.43 per Bbl (NYMEX reference price) for the calendar year 2000. During the first quarter of 2000, the Company entered into additional oil hedging contracts through December 31, 2000, covering an additional 3.6 MMBbls of oil at a weighted average NYMEX reference price of $25.77 per Bbl. The Company continues to monitor oil and gas prices and may enter into additional oil and gas hedges or swaps in the future. The following table reflects the Bbls hedged and the corresponding weighted average NYMEX reference prices by quarter: NYMEX Bbls Reference Price Quarter Ending (In Thousands) Per Bbl -------------------- ---------------- ----------------- March 31, 2000 1,310 $27.49 June 30, 2000 1,365 25.19 September 30, 2000 1,380 23.61 December 31, 2000 1,380 22.44 Gathering Systems and Plant The Company owns 100 percent interests in two oil and gas gathering systems located in Pottawatomie County, Oklahoma and Harris and Chambers Counties, Texas. In addition, the Company owns 100 percent interests in 17 gas gathering systems located in active producing areas of California, Kansas, Texas and Oklahoma. All of these gathering systems are operated by the Company. Together, these systems comprise approximately 325 miles of varying diameter pipe with a combined capacity in excess of 190 MMcf of gas per day. At December 31, 1999, there were 71 wells (49 wells (69 percent) which are operated by the Company) connected to these systems. Generally, the gathering systems buy gas at the wellhead on the basis of a percentage of the resale price under contracts containing terms of one to 10 years. As part of the Nuevo Acquisition, the Company obtained ownership and operatorship of the Santa Clara Valley Gas Plant located in Ventura county, California. The plant is a 1980-vintage Randall skid-mounted cryogenic expander plant designed for 17,000 Mcf per day of inlet gas and is complete with inlet gas compression, mole sieve dehydration facilities, propane refrigeration, NGL product storage and truck loading. There are two inlet gas systems feeding the compressor units, one is a 30 pound system and the other is an 80 pound system. Sales line pressure is at 220 pounds and that pressure is obtained from the process with a turbo-expander compressor. The plant is currently processing about 10,000 Mcf of gas per day and producing about 24,000 gallons per day of products (butane/propane). The products are trucked from the plant for sale and the approximate split is 30 percent gasoline and 70 percent butane/propane mix. Gas is purchased from various third parties, as well as the Company, primarily as wet gas purchase agreements. 13 Reserves At December 31, 1999, the Company had proved reserves of 468.0 MMBOE, comprised of 303.2 MMBbls of oil and 989.0 Bcf of gas as estimated by the independent petroleum consultants of Netherland, Sewell for the United States, Argentina and Ecuador and as estimated by the independent petroleum consultants of DeGolyer and MacNaughton for Bolivia. For additional information on the Company's oil and gas reserves, see "Oil and Gas Properties." The following table sets forth, at December 31, 1999, the present value of future net revenues (revenues less production and development costs) before income taxes attributable to the Company's proved reserves at such date (in thousands): Proved Reserves: Future net revenues...................................................................... $5,267,960 Present value of future net revenues before income taxes, discounted at 10 percent....... 2,989,626 Standardized measure of discounted future net cash flows................................. 2,247,237 Proved Developed Reserves: Future net revenues...................................................................... $3,500,578 Present value of future net revenues before income taxes, discounted at 10 percent....... 2,117,259
In computing this data, assumptions and estimates have been utilized, and the Company cautions against viewing this information as a forecast of future economic conditions. The historical 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, 1999, economic conditions. The estimated future production is priced at prices prevailing at December 31, 1999. The resulting estimated future gross revenues are reduced by estimated future costs to develop and produce the proved reserves and abandonment costs, based on December 31, 1999, cost levels, but such costs do not include debt service, general and administrative expenses and income taxes. 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 the Company's consolidated financial statements included elsewhere in this Form 10-K. The reserve data set forth in this Form 10-K represent only 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 the Company's consolidated financial statements included elsewhere in this Form 10-K. 14 Productive Wells; Developed Acreage The following table sets forth the Company's productive wells and developed acreage assignable to such wells at December 31, 1999:
Productive Wells ------------------------------------------------- Developed Acreage Oil Gas Total ---------------------- -------------- ------------- -------------- Gross Net Gross Net Gross Net Gross Net --------- --------- ----- ----- ----- --- ----- ----- U.S.......... 667,855 429,152 2,596 2,263 909 449 3,505 2,712 Argentina.... 1,158,339 994,372 1,057 1,040 - - 1,057 1,040 Bolivia...... 99,458 88,339 - - 16 15 16 15 Ecuador...... 33,623 24,889 8 6 - - 8 6 --------- --------- ----- ----- ---- --- ----- ----- Total...... 1,959,275 1,536,752 3,661 3,309 925 464 4,586 3,773 ========= ========= ===== ===== ==== === ===== =====
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. Undeveloped Acreage At December 31, 1999, the Company held the following undeveloped acres located in the United States, Bolivia, Ecuador and Yemen. With respect to such United States acreage held under leases, 174,690 gross (48,477 net) acres are held under leases with primary terms that expire at varying dates through December 31, 2003, unless commercial production is commenced. The Bolivia, Ecuador and Yemen acreage are held under concessions with primary terms that expire at varying dates in 2000 and 2002. Although substantial undeveloped acreage exists in the Company's concessions in Argentina, the concessions in their entirety are held by production. Gross Net State/Country Acres Acres ------------------------------ --------- --------- California................... 9,505 9,082 Colorado..................... 1,248 468 Kansas....................... 480 239 Louisiana.................... 52 52 Montana...................... 1,036 149 New Mexico................... 160 40 Oklahoma..................... 49,936 24,182 Texas........................ 113,523 16,785 Wyoming...................... 10,239 3,618 --------- --------- Total U.S.............. 186,179 54,615 Bolivia...................... 485,552 485,552 Ecuador...................... 1,276,254 1,073,693 Yemen........................ 1,108,019 831,014 --------- --------- Total Company.......... 3,056,004 2,444,874 ========= ========= 15 Production; Unit Prices; Costs The following table sets forth information with respect to production and average unit prices and costs for the periods indicated:
Years Ended December 31, ------------------------------ Production: 1999 1998 1997 ------- ------- ------- Oil (MBbls) - U.S. ................. 8,643 9,912 9,692 Argentina............. 7,560 6,322 5,630 Ecuador............... 597 78 - Bolivia............... 77 122 135 Total............. 16,877 16,434 15,457 Gas (MMcf) - U.S. ................. 39,150 42,176 36,623 Argentina............. 4,682 - - Bolivia............... 4,522 5,062 6,068 Total............. 48,354 47,238 42,691 Total MBOE................ 24,936 24,307 22,573 Average Sales Prices: Oil (Per Bbl) - U.S. ................. $ 15.92(a) $ 11.20 $ 17.23 Argentina............. 17.48 10.41 16.67(b) Ecuador............... 15.67 5.77 - Bolivia............... 17.03 11.31 16.52 Total............. 16.62(a) 10.87 17.02(b) Gas (Per Mcf) - U.S. ................. $ 2.06 $ 1.97 $ 2.31 Argentina............. 1.34 - - Bolivia............... .71 .78 1.10 Total............. 1.87 1.85 2.14 Production Costs (Per BOE): U.S....................... $ 5.31 $ 5.57 $ 5.64 Argentina................. 3.82 4.23 4.29 Bolivia................... 2.12 1.47 1.00 Ecuador................... 2.20 3.00 - Total................. 4.63 5.05 5.07
____________________ (a) Reflects the impact of oil hedges which reduced the Company's 1999 U.S. and total average oil prices per Bbl by 11 cents and six cents, respectively. (b) Reflects the impact of oil hedges which reduced the Company's 1997 Argentina and total average oil prices per Bbl by 66 cents and 24 cents, respectively. The components of production costs may vary substantially among wells depending on the methods of recovery employed and other factors, but generally include production taxes, maintenance and repairs, labor and utilities. 16 Drilling Activity During the periods indicated, the Company drilled or participated in the drilling of the following exploratory and development wells:
Years Ended December 31, ----------------------------------------- 1999 1998 1997 ------------ ------------- ------------ Gross Net Gross Net Gross Net ----- ----- ----- ------ ----- ----- Development: United States - Productive........ 6 1.94 34 24.94 30 15.74 Non-Productive.... - - 4 1.78 3 0.80 Argentina - Productive........ 10 10.00 54 54.00 55 55.00 Non-Productive.... 1 1.00 2 2.00 2 2.00 Bolivia - Productive........ 1 1.00 - - - - Non-Productive.... - - - - - - ----- ----- ----- ------ ----- ----- Total........... 18 13.94 94 82.72 90 73.54 ===== ===== ===== ====== ===== ===== Exploratory: United States - Productive........ 1 0.47 22 15.17 7 3.01 Non-Productive.... 11 5.56 13 3.78 6 2.87 Argentina - Productive........ - - 2 2.00 - - Non-Productive.... - - - - 1 1.00 Bolivia - Productive........ 7 7.00 1 1.00 - - Non-Productive.... - - - - 1 0.42 ----- ----- ----- ------ ----- ----- Total........... 19 13.03 38 21.95 15 7.30 ===== ===== ===== ====== ===== ===== Total: Productive............ 25 20.41 113 97.11 92 73.75 Non-Productive........ 12 6.56 19 7.56 13 7.09 ----- ----- ----- ------ ----- ----- Total............. 37 26.97 132 104.67 105 80.84 ===== ===== ===== ====== ===== =====
The above well information excludes wells in which the Company has only a royalty interest. At December 31, 1999, the Company was a participant in the drilling or completion of 13 gross (9.25 net) wells. All of the Company's drilling activities are conducted with independent contractors. The Company owns no drilling equipment. 17 Seasonality The results of operations of the Company are somewhat seasonal due to seasonal fluctuations in the price for gas. Gas prices have been generally higher in the fourth and first quarters. 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. Competition Competition in the oil and gas industry is intense. Both in seeking to acquire desirable producing properties, new leases and exploration prospects and in marketing oil and gas, the Company faces 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 the Company. Alternative fuel sources, including heating oil and other fossil fuels, 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 oil field equipment, including drilling rigs and tools. The Company is dependent upon independent drilling contractors to furnish rigs, equipment and tools to drill the wells it operates. The Company has not experienced and does not anticipate difficulty in obtaining supplies, materials, drilling rigs, equipment or tools. Higher prices for oil and gas production, however, may cause competition for these items to increase and may result in increased costs of operations. Regulation 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 the failure to comply. 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, the Company is unable to predict the future cost or impact of complying with such regulations. Exploration and Production. Exploration and production operations of the Company 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. The Company's 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 lands and leases to facilitate exploration, while other states rely on voluntary pooling of lands 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 the Company can produce from its wells and the number of wells or the locations at which the Company can drill. 18 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 exploration, development and production operations of the Company. For example, the discharge or substantial threat of a discharge of oil by the Company into United States waters or onto an adjoining shoreline may subject the Company 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 the Company. The Company's operations generally will be covered by insurance which the Company believes 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 liability the Company may incur. The Company is also subject to laws and regulations concerning occupational safety and health. It is not anticipated that the Company will be required in the near future to expend any amounts that are material in the aggregate to the Company's overall operations by reason of environmental or occupational safety and health laws and regulations, but because such laws and regulations are frequently changed, the Company is unable to predict the ultimate cost of compliance. Certain of the Company's 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, the Company does 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 the holding of 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 United States person's ownership of rights to minerals in such jurisdiction. The purchase of such shares in the Company by citizens of foreign countries who are not deemed to be reciprocal under such Act could have an impact on the Company's ownership of federal leases. Marketing, Gathering and Transportation. Federal legislation and regulatory controls have historically affected the price of the gas produced and sold by the Company and the manner in which such 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 ("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 and 636 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. 19 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 had to develop the specific terms of service in individual proceedings. Some of the individual pipeline company restructurings are still the subject of appeals and resulting remand proceedings concerning certain issues. Although the new regulations do not directly regulate gas producers such as the Company, 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 the marketing activities of the Company. 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. Interstate transmission facilities are, on the other hand, 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 the Company's gathering facilities. While the FERC has not issued any order or opinion declaring the Company's facilities as gathering rather than transmission facilities, the Company believes 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 FERC's allowing a number of interstate pipelines to spin-off gathering systems and thereby exempt them from Federal regulation, states are now enacting or considering statutory and/or regulatory provisions to regulate gathering systems. The Company's 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 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. The Company's operations in Argentina, Bolivia, Ecuador and Yemen are subject to various laws and regulations in those countries. These laws and regulations as currently imposed are not anticipated to have a material adverse effect upon the Company's operations. The Company's Bolivian projects are dependent, in part, on the continued market development of the Bolivia-to-Brazil gas pipeline. Employees The Company employs approximately 220 people in its Tulsa office whose functions are associated with management, engineering, geology, land and legal, accounting, financial planning, and administration. In addition, approximately 175 full time employees are responsible for the supervision and operation of its U.S. field activities. The Company also has approximately 250 employees for the management and operation of its properties in Argentina, Bolivia, Ecuador and Yemen. The Company believes its relations with its employees are excellent. 20 Item 3. Legal Proceedings. On November 5, 1996, the Province of Santa Cruz, Argentina brought suit against the Company's subsidiary Cadipsa S.A. in the Corte Suprema de Justicia de la Nacion (the Supreme Court of Justice of the Argentine Republic, Buenos Aires, Argentina), Dossier No. s-1451, seeking to recover approximately $10.6 million (which sum includes interest) allegedly due as additional royalties on four concessions granted in 1990 in which the Company currently owns a 100 percent working interest. The Company and its predecessors in title have been paying royalties at an eight percent rate; the Province of Santa Cruz claims the rate should be 12 percent. The amount of such claim will increase at the differential of these royalty rates until this claim is resolved. With respect to the 50 percent interest in the two concessions that the Company acquired from British Gas, plc, the Company believes that it is entitled to indemnification by British Gas, plc for any loss sustained by the Company as a result of this claim. Such indemnification equals approximately $5.2 million of the current $21.4 million claim. The Company has no indemnification from its predecessors in title with respect to the payment of royalties on the other two concessions. The Company expects the outcome of this litigation to be decided during 2000 and although the Company cannot predict the outcome, based upon the advice of counsel, the Company does not expect this claim to have a material adverse impact on the Company's financial position, results of operations, or total proved reserves. The Company is also a named defendant in other lawsuits and is a party in governmental proceedings from time to time arising in the ordinary course of business. While the outcome of such other lawsuits or proceedings against the Company cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the Company's financial position or results of operations. Item 4. Submission of Matters to a Vote of Security-Holders. There were no matters submitted to the Company's stockholders during the fourth quarter of the fiscal year ended December 31, 1999. 21 Item 4A. Executive Officers of the Registrant. The following table sets forth as of the date hereof certain information regarding the executive officers of the Company. Officers are elected annually by the Board of Directors and serve at its discretion.
Name Age Position - -------------------------------- --- --------------------------------------------------------------- Charles C. Stephenson, Jr....... 63 Director and Chairman of the Board of Directors S. Craig George................. 47 Director, President and Chief Executive Officer William L. Abernathy............ 48 Director, Executive Vice President and Chief Operating Officer William C. Barnes............... 45 Director, Executive Vice President, Chief Financial Officer, Secretary and Treasurer William E. Dozier............... 47 Senior Vice President - Operations Robert W. Cox................... 54 Vice President - General Counsel Andy R. Lowe.................... 48 Vice President - Marketing Michael F. Meimerstorf.......... 43 Vice President and Controller Robert E. Phaneuf............... 53 Vice President - Corporate Development Larry W. Sheppard............... 45 Vice President - International Martin L. Thalken............... 39 Vice President - Acquisitions
Mr. Stephenson, a co-founder of the Company, has been a Director since June 1983 and Chairman of the Board of Directors of the Company since April 1987. He was also Chief Executive Officer of the Company from April 1987 to March 1994 and President of the Company from June 1983 to May 1990. From October 1974 to March 1983, he was President of Santa Fe-Andover Oil Company (formerly Andover Oil Company), an independent oil and gas company ("Andover"), and from January 1973 to October 1974, he was Vice President of Andover. Mr. Stephenson has a B.S. Degree in Petroleum Engineering from the University of Oklahoma, and has approximately 40 years of oil and gas experience. Mr. George has been a Director since October 1991, President of the Company since September 1995 and Chief Executive Officer of the Company since December 1997. He was also Chief Operating Officer of the Company from March 1994 to December 1997, an Executive Vice President of the Company from March 1994 to September 1995 and a Senior Vice President of the Company from October 1991 to March 1994. From April 1991 to October 1991, Mr. George was Vice President of Operations and International with Santa Fe Minerals, Inc., an independent oil and gas company ("Santa Fe Minerals"). From May 1981 to March 1991, he served in various other management and executive capacities with Santa Fe Minerals and its subsidiary, Andover. From December 1974 to April 1981, Mr. George held various management and engineering positions with Amoco Production Company. He has a B.S. Degree in Mechanical Engineering from the University of Missouri- Rolla. Mr. Abernathy has been a Director since October 1999, and an Executive Vice President and Chief Operating Officer of the Company since December 1997. He was Senior Vice President--Acquisitions of the Company from March 1994 to December 1997, Vice President--Acquisitions of the Company from May 1990 to March 1994 and Manager--Acquisitions of the Company from June 1987 to May 1990. From June 1976 to June 1987, Mr. Abernathy was employed by Exxon Company USA, where he served at various times as Senior Staff Engineer, Senior Supervising Engineer and in other engineering capacities, with assignments in drilling, production and reservoir engineering in the Gulf Coast and offshore. He has B.S. and M.S. Degrees in Mechanical Engineering from Auburn University. 22 Mr. Barnes, a certified public accountant, has been a Director, Treasurer and Secretary of the Company since April 1987, an Executive Vice President of the Company since March 1994 and Chief Financial Officer of the Company since May 1990. He was also a Senior Vice President of the Company from May 1990 to March 1994 and Vice President--Finance of the Company from January 1984 to May 1990. From November 1982 to December 1983, Mr. Barnes was an audit manager for Arthur Andersen & Co., an independent public accounting firm, where he dealt primarily with clients in the oil and gas industry. He was Assistant Controller--Finance of Andover from December 1980 to November 1982. From June 1976 to December 1980, he was an auditor with Arthur Andersen & Co., where he dealt primarily with clients in the oil and gas industry. Mr. Barnes has a B.S. Degree in Business Administration from Oklahoma State University. Mr. Dozier has been Senior Vice President--Operations of the Company since December 1997. From May 1992 to December 1997, he was Vice President-- Operations of the Company. From June 1983 to April 1992, he was employed by Santa Fe Minerals where he held various engineering and management positions serving most recently as Manager of Operations Engineering. From January 1975 to May 1983, he was employed by Amoco Production Company serving in various positions where he worked all phases of production, reservoir evaluations, drilling and completions in the Mid-Continent and Gulf Coast areas. He has a B.S. Degree in Petroleum Engineering from the University of Texas. Mr. Cox has been Vice President--General Counsel of the Company since March 1988. From August 1982 to March 1988, he was employed by Santa Fe Minerals and its subsidiary, Andover, where he served at various times as Vice President--Law and Regional Attorney. From April 1982 to August 1982, he was employed as Corporate Attorney by Andover. Prior to that time, Mr. Cox was employed by Amerada Hess Corporation, a major oil company, served as General Counsel and Secretary of Kissinger Petroleum Corporation, an independent oil and gas company, and served on the legal staff of Champlin Petroleum Company, an independent oil and gas company. He has a B.S. Degree in Business Administration with a major in Petroleum Marketing from the University of Tulsa, and a Juris Doctor from the University of Michigan Law School. Mr. Lowe has been Vice President--Marketing of the Company since December 1997. He was General Manager--Marketing of the Company from July 1992 to December 1997. From September 1983 to November 1990, he was employed by Maxus Energy Corporation, formerly Diamond Shamrock Exploration Company, serving as Manager--Marketing and in various other management and supervisory capacities. From 1981 to October 1983, he was employed by American Quasar Exploration Company as Manager--Oil and Gas Marketing. From 1978 to 1981, he was employed by Texas Pacific Oil Company serving in various positions in production and marketing. He has a B.S. Degree in Education from Texas Tech University. Mr. Meimerstorf, a certified public accountant, has been Controller of the Company since January 1988 and a Vice President of the Company since May 1990. He was Accounting Manager of the Company from February 1984 to January 1988. From April 1981 to February 1984, he was the Financial Reporting Supervisor for Andover. From June 1979 to April 1981, he was an auditor with Arthur Andersen & Co. He has a B.S. Degree in Accounting from Arkansas Tech University and an M.B.A. Degree from the University of Arkansas. Mr. Phaneuf has been Vice President--Corporate Development of the Company since October 1995. From June 1995 to October 1995, he was employed in the Corporate Finance Group of Arthur Andersen LLP, specializing in energy industry corporate finance activities. From April 1993 to August 1994, he was Senior Vice President and head of the Energy Research Group at Kemper Securities, an investment banking firm. From 1988 until April 1993, he was employed by Rauscher, Pierce Refsnes, Inc., an investment banking firm, as a Senior Vice President, serving as an energy analyst involved in equity research. From 1978 to 1988, Mr. Phaneuf was Vice President of Kidder, Peabody, & Co., an investment banking firm, serving as an energy analyst in the Research Department. From 1976 to 1978, he was employed by Schneider, Bernet, and Hickman, serving as an energy analyst in the Research Department. From 1972 to 1976, he held the position of Investment Advisor for First International Investment Management, a subsidiary of NationsBank. He holds a B.A. Degree in Psychology and an M.B.A Degree from the University of Texas. 23 Mr. Sheppard has been Vice President--International of the Company since November 1994. From June 1984 to August 1994, he was employed by Santa Fe Minerals serving as Manager--Acquisitions & Special Projects, Manager-- International Operations, and in various other management and supervisory capacities. From August 1977 to June 1984, he was employed by Amoco Production Company serving in various engineering and supervisory capacities. He has a B.S. Degree in Petroleum Engineering from Texas Tech University. Mr. Thalken has been Vice President--Acquisitions of the Company since December 1997. He was Acquisitions Technical Manager of the Company from May 1995 to December 1997 and an acquisitions engineer with the Company from January 1992 to May 1996. From October 1990 to December 1991, he was employed by Enron Oil and Gas Company, serving as a production engineer. From May 1983 to September 1990, he was employed by Exxon Company, USA, in various engineering and supervisory capacities. He has a B.S. Degree in Mechanical Engineering from the University of Kansas. 24 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters. The Company's common stock commenced trading on the New York Stock Exchange on August 3, 1990, under the symbol "VPI." The following table sets forth the high and low sale prices per share of the Company's common stock, as reported in the New York Stock Exchange composite transactions, and the cash dividends paid per share of common stock, for the periods indicated: Dividend High Low Paid -------- --------- --------- 1999 ---- First Quarter........ $10 1/16 $ 4 1/16 $.025 Second Quarter....... 12 1/4 8 1/8 - Third Quarter........ 15 1/8 10 1/8 - Fourth Quarter....... 13 3/4 9 1/16 - 1998 ---- First Quarter........ 23 1/8 16 13/16 .02 Second Quarter....... 21 1/2 15 7/8 .02 Third Quarter........ 19 1/2 7 5/16 .02 Fourth Quarter....... 15 1/2 7 1/4 .025 Substantially all of the Company's stockholders maintain their shares in "street name" accounts and are not, individually, stockholders of record. As of December 31, 1999, the common stock was held by 112 holders of record and approximately 9,000 beneficial owners. The Company began paying a quarterly cash dividend in the fourth quarter of 1992. On December 7, 1998, the Company declared a regular quarterly cash dividend of $.025 per share payable on January 6, 1999, to stockholders of record at December 22, 1998. Due to the historically low oil and gas price environment during the first quarter of 1999, the Company suspended its regular quarterly cash dividend for the remainder of 1999. The Company re-instituted the payment of dividends beginning in the first quarter of 2000 with a $.025 per share cash dividend paid on February 3, 2000, to stockholders of record on January 25, 2000. Subject to restrictions under credit arrangements, the determination of the amount of future cash dividends, if any, to be declared and paid, will depend upon, among other things, the Company's financial condition, funds from operations, the level of its capital expenditures and its future business prospects. The Company's credit arrangements (including the indentures for its outstanding senior subordinated indebtedness) contain certain restrictions on the payment of cash dividends, the most restrictive of which prohibits the payment of cash dividends if such payments would reduce Net Worth (as defined in the Company's revolving credit facility) below the sum of $238.6 million plus 75 percent of net proceeds of any future equity offerings. Net Worth was approximately $419.4 million at December 31, 1999. 25 Item 6. Selected Financial Data. SELECTED FINANCIAL AND OPERATING DATA
Years Ended December 31, ------------------------------------------------------------ 1999 1998 1997 1996 1995 ---------- ---------- --------- --------- --------- (In thousands, except per share amounts and operating data) Income Statement Data: Oil and gas sales........................................ $ 370,731 $ 265,863 $ 354,490 $ 258,368 $160,254 Gas marketing revenues................................... 60,275 54,108 45,981 31,920 20,912 Gathering revenues....................................... 6,955 7,741 18,063 20,508 12,380 Total revenues........................................... 496,735 328,935 416,590 312,147 195,215 Operating expenses....................................... 178,174 180,544 172,676 138,438 95,121 Exploration costs........................................ 14,674 24,056 12,667 10,192 3,834 Impairment of oil and gas properties..................... 3,306 70,913 8,785 - - Depreciation, depletion and amortization................. 107,807 108,975 96,307 66,861 48,336 Interest................................................. 58,665 43,680 36,762 30,109 20,178 Net income (loss)........................................ 73,371 (87,665) 54,954 33,188 9,449 Earnings (loss) per share: Basic................................................. 1.27 (1.69) 1.07 .69 .23 Diluted............................................... 1.24 (1.69) 1.05 .68 .22 Dividends declared per share............................. - .09 .07 .055 .045 ---------- ---------- ---------- ---------- --------- Balance Sheet Data (end of year): Total assets............................................. $1,168,134 $1,014,175 $ 915,394 $ 766,816 $613,397 Long-term debt, less current portion..................... 625,318 672,507 451,096 372,390 315,846 Stockholders' equity..................................... 431,129 273,958 337,578 236,406 203,265 ---------- ---------- ---------- ---------- --------- Operating Data: Production: Oil (MBbls).............................................. 16,877 16,434 15,457 11,939 7,608 Gas (MMcf)............................................... 48,354 47,238 42,691 32,366 30,610 ---------- ---------- ---------- ---------- --------- Average Sales Prices: Oil (per Bbl)............................................ $ 16.62 $ 10.87 $ 17.02 $ 16.73 $ 15.26 Gas (per Mcf)............................................ 1.87 1.85 2.14 1.81 1.46 ---------- ---------- ---------- ---------- --------- Proved Reserves (end of year): Oil (MBbls).............................................. 303,190 164,457 187,768 178,296 147,871 Gas (MMcf)............................................... 988,989 806,833 552,163 382,846 310,762 Total proved reserves (MBOE)............................. 468,022 298,929 279,795 242,104 199,665 ---------- ---------- ---------- ---------- --------- Present value of estimated future net revenues before income taxes discounted at 10 percent (in thousands): Oil and gas properties............................. $2,989,626 $ 703,211 $1,222,560 $1,807,137 $ 894,249 Gathering systems and plant........................ 13,764 4,493 5,940 10,364 10,641 Standardized measure of discounted future net cash flows (in thousands)......................... 2,247,237 648,222 1,016,645 1,392,841 736,546 ---------- ---------- ---------- ---------- ---------
Significant acquisitions of producing oil and gas properties during 1999, 1997 and 1995 and significant dispositions of oil and gas properties during 1999 affect the comparability between the Financial and Operating Data for the years presented above. 26 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Results of Operations The Company's results of operations have been significantly affected by its success in acquiring oil and gas properties and its ability to maintain or increase production through its exploitation and exploration activities. Fluctuations in oil and gas prices have also significantly affected the Company's results. The following table reflects the Company's oil and gas production and its average oil and gas prices for the periods presented:
Years Ended December 31, ------------------------------ 1999 1998 1997 --------- -------- --------- Production: Oil (MBbls) - U.S............................... 8,643 9,912 9,692 Argentina......................... 7,560 6,322 5,630 Ecuador........................... 597 78 - Bolivia........................... 77 122 135 Total........................... 16,877 16,434 15,457 Gas (MMcf) - U.S............................... 39,150 42,176 36,623 Argentina......................... 4,682 - - Bolivia........................... 4,522 5,062 6,068 Total........................... 48,354 47,238 42,691 Total MBOE............................ 24,936 24,307 22,573 Average Sales Prices: Oil (per Bbl) - U.S............................... $ 15.92 $ 11.20 $ 17.23 Argentina......................... 17.48 10.41 16.67 Ecuador........................... 15.67 5.77 - Bolivia........................... 17.03 11.31 16.52 Total........................... 16.62 10.87 17.02 Gas (per Mcf) - U.S............................... $ 2.06 $ 1.97 $ 2.31 Argentina......................... 1.34 - - Bolivia........................... .71 .78 1.10 Total........................... 1.87 1.85 2.14
Average U.S. oil prices received by the Company fluctuate generally with changes in the NYMEX reference price for oil. The Company's Argentina oil production is sold at West Texas Intermediate spot prices as quoted on the Platt's Crude Oil Marketwire (approximately equal to the NYMEX reference price) less a specified differential. The Company experienced a 53 percent increase in its average oil price in 1999 compared to 1998 as a result of OPEC's efforts to reduce the available supply of crude oil in the global markets. The Company participated in oil hedges covering 1.84 MMBbls during 1999. The impact of these hedges reduced the Company's U.S. average oil price by 11 cents to $15.92 per Bbl and its overall average oil price by six cents to $16.62 per Bbl. The Company was not a party to any oil hedges in 1998. During 1997, the impact of Argentina oil hedges reduced the Company's overall average oil price 24 cents to $17.02 per Bbl and its average Argentina oil price was reduced 66 cents to $16.67 per Bbl. Approximately 49 percent of the 1997 Argentina oil production was covered by hedges. 27 The Company's realized average oil price for 1999 (before hedges) was approximately 87 percent of the NYMEX reference price in 1999 compared to 75 percent in 1998 and 84 percent in 1997. Average U.S. gas prices received by the Company fluctuate generally with changes in spot market prices, which may vary significantly by region. The Company's Bolivia average gas price is tied to a long-term contract under which the base price is adjusted for changes in specified fuel oil indexes. During the last half of 1999, these fuel oil indexes increased in conjunction with the current higher oil price environment. In Argentina, the Company's average gas price is primarily determined by the realized price of oil from the El Huemul concession. The Company's total average gas price for 1999 was one percent higher than 1998's. The Company's average gas price for 1998 was 14 percent lower than 1997's. The Company has previously engaged in oil and gas hedging activities and intends to continue to consider various hedging arrangements to realize commodity prices which it considers favorable. During 1999, the Company entered into various oil hedges (swap agreements) for a total of 1.8 MMBbls of oil at a weighted average price of $22.43 per Bbl (NYMEX reference price) for calendar year 2000. During the first quarter of 2000, the Company entered into additional oil hedging contracts through December 31, 2000, covering an additional 3.6 MMBbls of oil and a weighted average NYMEX reference price of $25.77 per Bbl. For additional information, see "Business and Properties - Marketing" included elsewhere in this Form 10-K. The Company continues to monitor oil and gas prices and may enter into additional oil and gas hedges or swaps in the future. Relatively modest changes in either oil or gas prices significantly impact the Company's results of operations and cash flow. However, the impact of changes in the market prices for oil and gas on the Company's average realized prices may be reduced from time to time based on the level of the Company's hedging activities. Based on 1999 oil production, a change in the average oil price realized by the Company of $1.00 per Bbl would result in a change in net income and cash flow before income taxes on an annual basis of approximately $15.6 million and $22.8 million, respectively. A 10 cent per Mcf change in the average price realized by the Company for gas would result in a change in net income and cash flow before income taxes on an annual basis of approximately $3.0 million and $4.7 million, respectively, based on 1999 gas production. Period to Period Comparison Year Ended December 31, 1999, Compared to Year Ended December 31, 1998 The Company reported net income of $73.4 million for the year ended December 31, 1999, compared to a net loss of $87.7 million for the same period in 1998. A 53 percent increase in average oil prices received by the Company was primarily responsible for the significant increase in its net income. The Company also recorded after-tax gains on property sales of $33.6 million in 1999. The Company's net loss recorded in 1998 was primarily the result of historically low oil prices which greatly reduced revenues and led to an oil and gas property impairment of $70.9 million ($43.2 million net of tax). Oil and gas sales increased $104.8 million (39 percent), to $370.7 million for 1999 from $265.9 million for 1998. A 53 percent increase in average oil prices combined with a three percent increase in oil production, accounted for an increase of $101.7 million. A one percent increase in average gas prices, coupled with a two percent increase in gas production, accounted for an additional increase of $3.1 million. The Company experienced a three percent increase in oil production primarily as a result of Argentina production added through the El Huemul Acquisition which offset the decline in the Company's U.S. oil production primarily due to the shutting in of certain high cost properties during the first half of 1999 as a result of historically low oil prices. The Company's gas production rose by two percent due to the gas production attributable to the El Huemul concession acquired in July 1999 which more than offset the decrease in U.S. gas production resulting from the natural decline in the Galveston Bay field and the decrease in Bolivia production due to the limited gas demand from the developing export market in Brazil. 28 Gains on disposition of assets of $55.0 million ($33.6 million net of income taxes) were reflected in 1999 as a result of $87.9 million in proceeds from various oil and gas property divestitures in the United States. Other than the $55.0 million in gains reported, the divestitures did not have a significant impact on the Company's results of operations as the majority of the divestitures occurred during December 1999. The Company also does not expect a significant impact on its continuing operations due to these divestitures as interest savings from the reduction in debt are expected to generally offset any future reduction in earnings. Lease operating expenses, including production taxes, decreased $7.2 million (6 percent), to $115.5 million for 1999 from $122.7 million for 1998. The decrease in lease operating expenses, despite the three percent increase in production, is due primarily to actions taken by the Company to reduce costs including shutting in certain high cost properties, rebidding field service and product contracts and the reorganization of certain field operations. Lease operating expenses per equivalent barrel produced decreased to $4.63 in 1999 from $5.05 for the same period in 1998. Exploration costs decreased $9.4 million (39 percent), to $14.7 million for 1999 from $24.1 million for 1998. During 1998, the Company's exploration costs included $13.9 million for the acquisition of 3-D seismic data primarily in the U.S. Gulf Coast area and Bolivia, $4.8 million for unsuccessful exploratory drilling, and $5.4 million for lease impairments and other geological and geophysical costs. Due to reduced cash flow levels, the Company significantly reduced its capital budget for 1999. As a result, exploration expenses for 1999 consisted of only $5.3 million for seismic data acquisition, $4.4 million for unsuccessful exploratory drilling and $5.0 million for lease impairments and other geological and geophysical costs. Impairments of oil and gas properties of $3.3 million were recognized in 1999, compared to $70.9 million of impairments in 1998, which resulted primarily from the decline in oil prices which took place in the last quarter of 1998. The impairments recorded in 1999 were primarily as a result of mechanical failures which were uneconomic to repair and unsuccessful development projects on various fields in the United States. The Company reviews its proved properties for impairment on a field basis and recognizes an impairment whenever events or circumstances (such as declining oil and gas prices or unsuccessful development projects) indicate that the properties' carrying value may not be recoverable. If an impairment is indicated based on the Company's estimated future net revenues for total proved reserves on a field basis, then a provision is recognized to the extent that the carrying value exceeds the present value of the estimated future net revenues ("fair value"). In estimating the future net revenues, the Company assumed that the current oil price environment would return to more historical levels over a short period of time and thereafter escalate annually. The Company assumed gas prices and operating costs would escalate annually beginning at current levels. Due to the volatility of oil and gas prices, it is possible that the Company's assumptions regarding oil and gas prices may change in the future and may result in future impairment provisions. General and administrative expenses increased $4.4 million (14 percent), to $36.4 million for 1999 from $32.0 million for 1998, due primarily to the accrual of 1999 employee incentive bonuses and approximately $1.0 million in costs associated with the Company's efforts to prepare for Y2K. The Company implemented a bonus program effective for 1999 covering all U.S. employees designed to provide additional incentive to achieve certain corporate goals. The Company's G&A per BOE for 1999 was $1.46 ($1.34 before the 1999 bonus accrual) compared to $1.32 for 1998. Depreciation, depletion and amortization decreased $1.2 million (1 percent), to $107.8 million for 1999 from $109.0 million for 1998, despite the three percent increase in total production due primarily to a lower DD&A rate per equivalent barrel for 1999 versus 1998. The Company's average DD&A rate per equivalent barrel produced decreased from $4.32 in 1998 to $4.15 in 1999 primarily as a result of the impact of the new production from the Company's El Huemul concession which has a substantially lower amortization rate and the effect of the U.S. impairments in 1998. 29 Interest expense increased $15.0 million (34 percent), to $58.7 million for 1999 from $43.7 million for 1998, due primarily to a 25 percent increase in the Company's total average outstanding debt as a result of the Company's 1998 total capital spending, including acquisitions, exceeding 1998's cash flow and an increase in its average interest rate on its outstanding debt. The Company's average interest rate for its outstanding debt for 1999 was 8.14 percent compared to 7.72 percent in 1998. Year Ended December 31, 1998, Compared to Year Ended December 31, 1997 The Company reported a net loss of $87.7 million for the year ended December 31, 1998, compared to net income of $55.0 million in 1997. An increase in the Company's oil and gas production of eight percent on an equivalent barrel basis was more than offset by a 36 percent decrease in average oil prices and a 14 percent decrease in average gas prices. The production increases primarily relate to the exploration activities in the United States, the exploitation activities in Argentina and the acquisition of certain oil and gas properties from Burlington Resources Inc. (the "Burlington Properties") in April 1997. However, a portion of the production increases were reduced by the impact of severe weather in California during the first quarter of 1998 and the Gulf of Mexico in the third quarter of 1998 forcing the Company to temporarily shut in some of its oil and gas properties for portions of 1998 reducing production by approximately 167,000 Bbls of oil and 877,000 Mcf of gas. Oil and gas sales decreased $88.6 million (25 percent), to $265.9 million for 1998 from $354.5 million for 1997. A 36 percent decrease in average oil prices, partially offset by a six percent increase in oil production, accounted for a decrease of $84.4 million. A 14 percent decrease in average gas prices, partially offset by an 11 percent increase in gas production, accounted for an additional decrease of $4.2 million. Oil and gas gathering net margins decreased $1.6 million (52 percent), to $1.5 million for 1998 from $3.1 million for 1997, due primarily to the sale by the Company of its two largest gathering systems in December 1997 and June 1998. Lease operating expenses, including production taxes, increased $8.4 million (7 percent), to $122.7 million for 1998 from $114.3 million for 1997. The increase in lease operating expenses is in line with the eight percent increase in production and is due primarily to operating costs associated with the Burlington Properties and costs in 1998 related to storm damage repair and cleanup as a result of the severe weather in California and the Gulf of Mexico. Lease operating expenses per equivalent barrel produced decreased to $5.05 in 1998 from $5.07 for the same period in 1997. Exploration costs increased $11.4 million (90 percent), to $24.1 million for 1998 from $12.7 million for 1997. During 1998, the Company's exploration costs included $13.9 million for the acquisition of 3-D seismic data primarily in the U.S. Gulf Coast area and Bolivia, $4.8 million for unsuccessful exploratory drilling, $3.0 million for lease impairments and $2.4 million in other geological and geophysical costs. The Company's 1997 exploration costs consisted primarily of $6.6 million for unsuccessful exploratory drilling, $5.6 million in 3-D seismic acquisition costs and $0.5 million in lease impairments. 30 Impairments of oil and gas properties of $70.9 million were recognized in 1998, compared to $8.8 million of impairments in 1997, due primarily to the decline in oil prices which took place in the last quarter of 1998. The Company reviews its proved properties for impairment on a field basis and recognizes an impairment whenever events or circumstances (such as declining oil and gas prices) indicate that the properties' carrying value may not be recoverable. If an impairment is indicated based on the Company's estimated future net revenues for total proved reserves on a field basis, then a provision is recognized to the extent that the carrying value exceeds the present value of the estimated future net revenues ("fair value"). In estimating the future net revenues, the Company assumed future oil and gas prices and costs would escalate annually and that the current low oil and gas price environment would return to more historical levels over a period of time. Due to the volatility of oil and gas prices, it is possible that the Company's assumptions regarding oil and gas prices may change in the future. If future price expectations were to be reduced, it is possible that additional significant impairment provisions for oil and gas properties would be required. General and administrative expenses increased $4.6 million (17 percent), to $32.0 million for 1998 from $27.4 million for 1997, due primarily to the addition of personnel as a result of the acquisition of the Burlington Properties and the Company's increased emphasis on exploration activities and additional costs associated with international acquisition and business development activities and unsuccessful acquisition activities. Depreciation, depletion and amortization increased $12.7 million (13 percent), to $109.0 million for 1998 from $96.3 million for 1997, due primarily to the eight percent increase in production on an equivalent barrel basis and the increase in the Company's DD&A rate. The Company's average DD&A rate per equivalent barrel produced for 1998 was $4.32 compared to $4.14 for the year earlier. Interest expense increased $6.9 million (19 percent), to $43.7 million for 1998 from $36.8 million for 1997, due primarily to a 23 percent increase in the Company's total average outstanding debt as a result of capital spending in the Company's exploitation and exploration programs in excess of 1998's cash flow and the acquisition of the Burlington Properties in April 1997. The increase in interest expense was partially offset by a decrease in the Company's overall average interest rate from 8.01 percent in 1997 to 7.72 percent in 1998. Capital Expenditures During 1999, the Company's total oil and gas capital expenditures were $237.5 million. Domestically, the Company's oil and gas capital expenditures totaled $51.6 million. Exploration activities accounted for $10.8 million of the domestic capital expenditures with exploitation activities contributing $9.1 million. The Company also had domestic capital expenditures in 1999 of $31.7 million for acquisitions of producing oil and gas properties, the largest of which was the $29.6 million acquisition from Nuevo Energy Company in December. During 1999, the Company's international oil and gas capital expenditures excluding acquisitions totaled $50.8 million, consisting of $10.5 million in Argentina on exploitation activities, $30.8 million in Bolivia on exploitation and exploration activities, and $9.5 million in Yemen and Ecuador. International acquisition capital expenditures for 1999 included $121.0 million for the acquisition of the El Huemul concession in Argentina and $14.1 million for additional interests in the Company's Ecuador concessions. The Company committed to perform 17,728 work units related to its concession rights in the Naranjillos field in Santa Cruz Province, Bolivia awarded in late 1997. Through December 31, 1999, the Company has completed a total of 8,977 work units through capital expenditures in 1998 and 1999 of $7.6 million and $24.1 million, respectively. The total remaining work unit commitment is guaranteed by the Company through a $56.4 million letter of credit; however, the Company anticipates that it will fulfill the remaining work unit commitment through approximately $35 to $40 million of various drilling capital expenditures. The Company has budgeted to spend $37 million in 2000 to complete 8,751 work units, fulfilling its Naranjillos field commitment. 31 In addition, the Company's commitment to perform 1,400 work units related to an exploration program within the Chaco Block in Bolivia was fulfilled during 1998 through acquisitions of 3-D seismic and the drilling of two wells. During July 1999, the Company also committed to perform an additional 1,068 work units in its Chaco field location in Bolivia over the next two years. This work commitment is secured by a $5.3 million letter of credit. Under the Company's exploration contract on Block 19 in Ecuador, the Company is required to participate in the drilling of one additional well. The Company expects to drill the well during 2000 at a cost of approximately $4 million. The Company is also committed to spend approximately $11 million in the Republic of Yemen over a two and one-half year period which began in July 1998. The expenditures will include the acquisition and interpretation of 150 square kilometers of seismic and the drilling of three exploration wells. At the end of the first two and one-half years, the Company has the option to extend the work program for a second two and one-half year period with similar work and capital commitments required. Through 1999, approximately $2 million of the $11 million commitment has been spent. To fulfill its commitment, the Company has budgeted to spend approximately $9 million in 2000 on the drilling of three wells. Except for the commitments discussed above, the timing of most of the Company's capital expenditures is discretionary with no material long-term capital expenditure commitments. Consequently, the Company has a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant. The Company uses internally generated cash flow to fund capital expenditures other than significant acquisitions. Of the Company's 1999 non- acquisition capital expenditures of $71.4 million, approximately 34 percent was spent on exploitation activities, including development and infill drilling, and approximately 65 percent was spent on exploration activities. The Company's preliminary capital expenditure budget for 2000 is currently set at $146 million, exclusive of acquisitions. The Company does not have a specific acquisition budget since the timing and size of acquisitions are difficult to forecast. The Company is actively pursuing additional acquisitions of oil and gas properties. In addition to internally generated cash flow and advances under its revolving credit facility, the Company may seek additional sources of capital to fund any future significant acquisitions (see "--Liquidity"), however, no assurance can be given that sufficient funds will be available to fund the Company's desired acquisitions. The Company's recent capital expenditure history is as follows:
Years Ended December 31, -------------------------------- (In thousands) 1999 1998 1997 -------- -------- -------- Acquisition of oil and gas reserves..................... $166,787 $105,023 $139,749 Drilling................................................ 46,280 114,773 71,069 Acquisition of undeveloped acreage and seismic.......... 12,742 35,024 10,349 Workovers and recompletions............................. 10,749 29,939 32,856 Acquisition and construction of gathering systems....... 680 1,831 1,209 Other................................................... 927 1,601 4,638 -------- -------- -------- Total................................................ $238,165 $288,191 $259,870 ======== ======== ========
32 Liquidity Internally generated cash flow and the borrowing capacity under its revolving credit facility are the Company's major sources of liquidity. In addition, the Company may use other sources of capital, including the issuance of additional debt securities or equity securities, to fund any major acquisitions it might secure in the future and to maintain its financial flexibility. In the past, the Company has accessed the public markets to finance significant acquisitions and provide liquidity for its future activities. Prior to 1999 in conjunction with the purchase of substantial oil and gas assets, the Company completed four public equity offerings as well as two public debt offerings, which provided the Company with aggregate net proceeds of $415 million. On January 26, 1999, the Company issued $150 million of its 9 3/4% Senior Subordinated Notes due 2009 (the "9 3/4% Notes"). The 9 3/4% Notes are redeemable at the option of the Company, in whole or in part, at any time on or after February 1, 2004. In addition, prior to February 1, 2002, the Company may redeem up to 33 1/3% of the 9 3/4% Notes with the proceeds of certain underwritten public offerings of the Company's common stock. The 9 3/4% Notes mature on June 30, 2009, with interest payable semiannually on June 30 and December 30 of each year. The net proceeds to the Company from the sale of the 9 3/4% Notes (approximately $146 million) were used to repay a portion of the existing indebtedness under the Company's revolving credit facility. On June 21, 1999, the Company completed a public offering of 9,000,000 shares of common stock, all of which were sold by the Company. Net proceeds of approximately $81.2 million were used to partially fund the purchase of the El Huemul concession from Total and Repsol in early July 1999. Also in July 1999, in connection with the exercise by the underwriters of a portion of the over- allotment option, the Company sold an additional 240,800 shares of common stock using the additional $2.1 million of net proceeds to reduce a portion of the Company's existing indebtedness under its revolving credit facility. Under the Amended and Restated Credit Agreement dated October 21, 1998, as amended (the "Bank Facility"), certain banks have provided to the Company an unsecured revolving credit facility. The Bank Facility establishes a borrowing base (currently $545 million) determined by the banks' evaluation of the Company's oil and gas reserves. The amount available to be borrowed under the Bank Facility is limited to the lesser of the borrowing base or the facility size, which is currently set at $535 million. The Company may increase the facility size up to $625 million without further approvals from the existing bank group if additional banks agree to join the group. Outstanding advances under the Bank Facility bear interest payable quarterly at a floating rate based on Bank of Montreal's alternate base rate (as defined) or, at the Company's option, at a fixed rate for up to six months based on the Eurodollar market rate ("LIBOR"). The Company's interest rate increments above the alternate base rate and LIBOR vary based on the level of outstanding senior debt to the borrowing base. As of February 29, 2000, the Company had elected a fixed rate based on LIBOR for a substantial portion of its outstanding advances, which resulted in an average interest rate of approximately seven percent per annum. In addition, the Company must pay a commitment fee ranging from 0.25 to 0.375 percent per annum on the unused portion of the banks' commitment. On a semiannual basis, the Company's borrowing base is redetermined by the banks based upon their review of the Company's oil and gas reserves. If the sum of outstanding senior debt exceeds the borrowing base, as redetermined, the Company must repay such excess. Any principal advances outstanding under the Bank Facility at September 11, 2001, will be payable in eight equal consecutive quarterly installments commencing December 1, 2001, with final maturity at September 11, 2003. At February 29, 2000, the unused portion of the Bank Facility was approximately $363 million. The unused portion of the Bank Facility and the Company's internally generated cash flow provide liquidity which may be used to finance future capital expenditures, including acquisitions. As additional acquisitions are made and such properties are added to the borrowing base, the banks' determination of the borrowing base and their commitments may be increased. 33 The Company's internally generated cash flow, results of operations and financing for its operations are dependent on oil and gas prices. For 1999, approximately 68 percent of the Company's production was oil. Realized oil prices for the year increased by 53 percent as compared to 1998 and total production on a BOE basis increased by three percent. As a result, the Company's earnings and cash flows have been materially increased compared to 1998. To the extent oil prices decline, the Company's earnings and cash flow from operations may be adversely impacted. However, the Company believes that its cash flows and unused availability under the Bank Facility are sufficient to fund its planned capital expenditures for the foreseeable future. Inflation In recent years inflation has not had a significant impact on the Company's operations or financial condition. Income Taxes The Company incurred a current provision for income taxes of approximately $6.0 million for 1999 and realized a current benefit of $4.1 million for 1998. The total provision for U.S. income taxes is based on the Federal corporate statutory income tax rate plus an estimated average rate for state income taxes. Earnings of the Company's foreign subsidiaries are subject to foreign income taxes. No U.S. deferred tax liability will be recognized related to the unremitted earnings of these foreign subsidiaries as it is the Company's intention, generally, to reinvest such earnings permanently. During 1999, as a result of significantly improved oil prices, the Company generated Argentina taxable income in excess of its $44.9 million of net operating loss ("NOL") carryforwards, thereby utilizing all of the carryforwards to offset 1999 taxable income. Included in the $44.9 million of carryforwards are $16.2 million which had a valuation allowance recorded against them in 1998 and $14.4 million of NOL's that were acquired, but not recorded due to provisions under SFAS No. 109. The utilization of these NOL's was benefitted in the Company's 1999 tax provision, thereby reducing the tax provision and increasing net income by approximately $10.7 million. The Company has a U.S. Federal alternative minimum tax ("AMT") credit carryforward of approximately $5.2 million which does not expire and is available to offset U.S. Federal regular income taxes in future years, but only to the extent that U.S. Federal regular income taxes exceed the AMT in such years. The Company also has an estimated U.S. Federal NOL carryforward for regular tax purposes at December 31, 1999, of approximately $49.4 million which will expire in 2018 if not previously utilized. Foreign Operations For information on the Company's foreign operations, see "Foreign Currency and Operations Risk" under Item 7A of this Form 10-K. Year 2000 Compliance Readers are cautioned that the forward-looking statements contained in the following Year 2000 discussion should be read in conjunction with the Company's disclosures under the heading "Forward-Looking Statements." The disclosures also constitute a "Year 2000 Readiness Disclosure" and "Year 2000 Statement" within the meaning of the Year 2000 Information and Readiness Disclosure Act of 1998. The Year 2000 Information and Readiness Disclosure Act of 1998 does not insulate the Company from liability under the federal securities laws with respect to disclosures relating to Year 2000 information. 34 Statement of Readiness. The Company completed various initiatives to ensure that its hardware, software and equipment would function properly with respect to dates before and after January 1, 2000. For this purpose, the phrase "hardware, software and equipment" includes systems that are commonly thought of as Information Technology systems ("IT"), as well as those Non-Information Technology systems ("Non-IT") and equipment which include embedded technology. IT systems include computer hardware and software and other related systems. Non-IT systems include certain oil and gas production and field equipment, gathering systems, office equipment, telephone systems, security systems and other miscellaneous systems. The Non-IT systems presented, and still presents, the greatest compliance challenge since identification of embedded technology is difficult and because the Company is, to a great extent, reliant on third parties for Non-IT compliance. The Company formed a Year 2000 ("Y2K") Project team, which was chaired by its Manager of Information Services. The team included corporate staff and representatives from the Company's business units. The phases of identification, assessment, remediation and testing made up the Y2K directive and were all completed by the fourth quarter of 1999. Included in the Company's Y2K Project were procedures to determine the readiness of its business partners, such as service companies, technology providers, transportation and communication providers, pipeline systems, materials suppliers and oil and gas product purchasers. By use of questionnaires, 14,000 notices were distributed which allowed the Company to determine the extent to which these business partners were addressing their Y2K issues. Each returned document was examined for a response that could be detrimental to the Company's operations. Those business partners who did not respond and who were considered key businesses in the support of the Company's operations were sent a second request, followed by direct correspondence, to determine their readiness. Any material adverse responses were reviewed to determine an alternate business partner selection or the need for alternative actions to mitigate the impact on the Company. The Cost to Address Y2K Issues. The cost of the Y2K Project was approximately $2.3 million, excluding costs of Company employees working on the Y2K Project. Costs incurred for the purchase of new software and hardware have been capitalized and all other costs were expensed as incurred. Approximately $1.0 million of third party consultant fees related to the Y2K Project were recorded as part of the Company's 1999 general and administrative expenses. Y2K Worst-Case Scenario. The Company's initial results from its assessment phase of the Y2K Project was that its internal systems had fewer Y2K compliance problems than initially anticipated. As the Company had all internal systems within its control compliant and tested before the year 2000, it believed its likely worst-case scenario was the possibility of operational interruptions due to non-compliance by third parties. This non-compliance could have caused operational problems such as temporary disruptions of certain production, delays in marketing and transportation of production and delays of payments for oil and gas sales. This risk was minimized by the Company's efforts to communicate and evaluate third party compliance. The Company has contingency plans in the event that problems arise due to third party non-compliance or any failures of the Company's systems. These plans were completed during the fourth quarter of 1999 and include, but are not limited to, backup and recovery procedures, installations of new systems, replacement of current services with temporary manual processes, finding non- technological alternatives or sources of information and finding alternative suppliers, service companies and purchasers. The Risks of Y2K Issues. As anticipated, the Company did not experience any material operational problems as a result of Y2K. Additionally, the Company did not experience any material problems due to the lack of compliance by other entities. While it is possible that the Company might still encounter problems that may relate to Y2K issues, it does not believe they will pose a significant operational problem or adversely impact the Company's results of operations, liquidity or financial condition. As of March 1, 2000, the Company had experienced no material adverse impact on the Company's operations or financial condition as a result of Y2K issues. 35 Item 7A. Quantitative and Qualitative Disclosures About Market Risk. The Company's operations are exposed to market risks primarily as a result of changes in commodity prices, interest rates and foreign currency exchange rates. The Company does not use derivative financial instruments for speculative or trading purposes. Commodity Price Risk The Company produces, purchases and sells crude oil, natural gas, condensate, natural gas liquids and sulfur. As a result, the Company's financial results can be significantly impacted as these commodity prices fluctuate widely in response to changing market forces. The Company has previously engaged in oil and gas hedging activities and intends to continue to consider various hedging arrangements to realize commodity prices which it considers favorable. During 1999, the Company entered into various oil hedges (swap agreements) for a total of 1.8 MMBbls of oil at a weighted average price of $22.43 per Bbl (NYMEX reference price) for 2000. The fair value of commodity swap agreements is the amount at which they could be settled, based on quoted market prices. At December 31, 1999, the Company would have received approximately $700,000 to terminate its oil swap agreements then in place. During the first quarter of 2000, the Company entered into additional oil hedging contracts through December 31, 2000, covering an additional 3.6 MMBbls of oil and a weighted average NYMEX reference price of $25.77 per Bbl. The Company continues to monitor oil and gas prices and may enter into additional oil and gas hedges or swaps in the future. Interest Rate Risk The Company's interest rate risk exposure results primarily from short-term rates, mainly LIBOR based borrowings from its commercial banks. To reduce the impact of fluctuations in interest rates the Company maintains a portion of its total debt portfolio in fixed rate debt. At December 31, 1999, the amount of the Company's fixed rate debt was approximately 64 percent of total debt. In the past, the Company has not entered into financial instruments such as interest rate swaps or interest rate lock agreements. However, it may consider these instruments to manage the impact of changes in interest rates based on management's assessment of future interest rates, volatility of the yield curve and the Company's ability to access the capital markets in a timely manner. The following table provides information about the Company's long-term debt principal payments and weighted average interest rates by expected maturity dates:
Fair Value There- at 2000 2001 2002 2003 2004 After Total 12/31/99 -------- -------- -------- -------- -------- -------- -------- -------- Long-Term Debt: Fixed rate (in thousands)....... - - - - - $399,118 $399,118 $395,400 Average interest rate........... - - - - - 9.2% 9.2% - Variable rate (in thousands).... - $ 28,275 $113,100 $ 84,825 - - $226,200 $226,200 Average interest rate........... - (a) (a) (a) - - (a) (a)
_____________________ (a) LIBOR plus an increment, based on the level of outstanding senior debt to the borrowing base, up to a maximum increment of 1.75 percent. Current increment above LIBOR is 0.875 percent. 36 Foreign Currency and Operations Risk International investments represent, and are expected to continue to represent, a significant portion of the Company's total assets. The Company has international operations in Argentina, Bolivia, Ecuador and Yemen. For 1999, the Company's operations in Argentina accounted for approximately 28 percent of the Company's revenues, 39 percent of the Company's operating income (before impairments of oil and gas properties) and 33 percent of its total assets. During such period, the Company's operations in Argentina represented its only foreign operations accounting for more than 10 percent of its revenues, operating income (before impairments of oil and gas properties) or total assets. The Company continues to identify and evaluate international opportunities but currently has no binding agreements or commitments to make any material international investment. As a result of such significant foreign operations, the Company's 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. The Company believes Argentina offers a relatively stable political environment and does not anticipate any significant change in the near future. The current democratic form of government has been in place since 1983 and, since 1989, has pursued a steady process of privatization, deregulation and economic stabilization and reforms involving the reduction of inflation and public spending. Argentina's 12-month trailing inflation rate measured by the Argentine Consumer Price Index declined from 200.7 percent as of June 1991 to 1.1 percent as of December 1999. All of the Company's Argentine revenues are U.S. dollar based, while a large portion of its costs are denominated in Argentine pesos. The Argentina Central Bank is obligated by law to sell dollars at a rate of one Argentine peso to one U.S. dollar and has sought to prevent appreciation of the peso by buying dollars at rates of not less than 0.998 peso to one U.S. dollar. As a result, the Company believes that should any devaluation of the Argentine peso occur, its revenues would be unaffected and its operating costs would not be significantly increased. At the present time, there are no foreign exchange controls preventing or restricting the conversion of Argentine pesos into dollars. Since the mid-1980's, Bolivia has been undergoing major economic reform, including the establishment of a free-market economy and the encouragement of foreign private investment. Economic activities that had been reserved for government corporations were opened to foreign and domestic private investments. Barriers to international trade have been reduced and tariffs lowered. A new investment law and revised codes for mining and the petroleum industry, intended to attract foreign investment, have been introduced. On February 1, 1987, a new currency, the Boliviano ("Bs"), replaced the peso at the rate of one million pesos to one Boliviano. The exchange rate is set daily by the Government's exchange house, the Bolsin, which is under the supervision of the Bolivian Central Bank. Foreign exchange transactions are not subject to any controls. The US$:Bs exchange rate at December 31, 1999, was US$1:Bs 6.00. The Company believes that any currency risk associated with its Bolivian operations would not have a material impact on the Company's financial position or results of operations. The economy of Ecuador has been uneven in recent years and has recently reached a crisis level due in large part to the "El Nino" weather phenomenon, the recent low oil price environment and political transition. Since 1992, the Ecuadorian government has generally sought to reduce its participation in the economy and has implemented certain macroeconomic reforms which were designed to reduce inflation. The Company believes the Ecuadorian government has a favorable attitude toward foreign investment and has strong international relationships with the U.S. 37 Due to the current economic crisis, the sucre (Ecuador's monetary unit) exchange rate against the US dollar increased from approximately 7,000:1 in January 1999 to almost 21,000:1 in December 1999. During the same period, inflation reached nearly 61 percent. The exchange rate has deteriorated further during 2000 reaching 25,000:1 during February and inflation for the year has reached 25 percent. The crisis has resulted in President Jamil Mahaud being replaced by Gustavo Naboa during a peaceful coup de etat carried out on January 21, 2000. The new government, following proposals made by President Mahaud, has adopted a plan to dollarize the sucre at 25,000:1 and the plan is currently in the congressional approval process. Dollarization is expected to be implemented and speculation against the sucre has been temporarily halted. Although the Company believes any currency risk associated with its operations in Ecuador would not have a material impact on its financial position or results of operations, it has policies in place that reduce its exposure to currency risk related to the sucre including maintaining essentially all of its cash in US dollar accounts primarily in U.S. bank accounts. At the present time, approximately 90 percent of the Company's revenues in Ecuador are US dollar based. Item 8. Financial Statements and Supplementary Data. The Consolidated Financial Statements and notes thereto, the report of independent public accountants and the supplementary financial and operating information are included elsewhere in this Form 10-K. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None. PART III Item 10. Directors and Executive Officers of the Registrant. The information required by this Item with respect to the Company's directors is incorporated by reference from the sections of the Company's definitive Proxy Statement for its 2000 Annual Meeting of Stockholders (the "Proxy Statement") entitled "Election of Directors" and "Section 16(a) Beneficial Ownership Reporting Compliance." The information required by this Item with respect to the Company's executive officers appears at Item 4A of Part I of this Form 10-K. Item 11. Executive Compensation. The information required by this Item is incorporated by reference from the section of the Proxy Statement entitled "Executive Compensation." Item 12. Security Ownership of Certain Beneficial Owners and Management. The information required by this Item is incorporated by reference from the section of the Proxy Statement entitled "Principal Stockholders and Security Ownership of Management." Item 13. Certain Relationships and Related Transactions. The information required by this Item is incorporated by reference from the section of the Proxy Statement entitled "Certain Transactions." 38 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K. (a) (1) Financial Statements: The financial statements of the Company and its subsidiaries and report of independent public accountants listed in the accompanying Index to Financial Statements are filed as a part of this Form 10-K. (2) Financial Statements Schedules: All schedules are omitted as inapplicable or because the required information is contained in the financial statements or included in the notes thereto. (3) Exhibits: The following documents are included as exhibits to this Form 10-K. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, such exhibit is filed herewith. 3.1 Restated Certificate of Incorporation, as amended, of the Company (Filed as Exhibit 3.2 to the Company's report on Form 10-Q for the quarter ended June 30, 1997, filed August 13, 1997). 3.2 Restated By-laws of the Company (Filed as Exhibit 3.2 to the Company's Registration Statement on Form S-1, Registration No. 33-35289 (the "S-1 Registration Statement")). 4.1 Form of stock certificate for Common Stock, par value $.005 per share (Filed as Exhibit 4.1 to the S-1 Registration Statement). 4.2 Indenture dated as of December 20, 1995, between The Chase Manhattan Bank (formerly Chemical Bank), as Trustee, and the Company (Filed as Exhibit 99.1 to the Company's report on Form 8-K filed January 16, 1996). 4.3 Indenture dated as of February 5, 1997, between The Chase Manhattan Bank, as Trustee, and the Company (Filed as Exhibit 4.3 to the Company's report on Form 10-K for the year ended December 31, 1996, filed March 27, 1997). 4.4 Indenture dated as of January 26, 1999, between The Chase Manhattan Bank, as Trustee, and the Company (Filed as Exhibit 4.4 to the Company's report on Form 10-K for the year ended December 31, 1998, filed March 12, 1999 (the "1998 Form 10- K")). 4.5 Rights Agreement, dated March 16, 1999, between the Company and ChaseMellon Shareholder Services, L.L.C., as Rights Agent (Filed as Exhibit 4.1 to the Company's Registration Statement on Form 8-A, filed March 22, 1999). 4.6 Certificate of Designation of Series A Junior Participating Preferred Stock of the Company (Filed as Exhibit 3.3 to the Company's Registration Statement on Form S-3, Registration No. 333-77619). 10.1* Employment and Noncompetition Agreement dated January 7, 1987, between the Company and Charles C. Stephenson, Jr. (Filed as Exhibit 10.19 to the S-1 Registration Statement). 39 10.2* Form of Indemnification Agreement between the Company and certain of its officers and directors (Filed as Exhibit 10.23 to the S-1 Registration Statement). 10.3* Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 4(d) to the Company's Registration Statement on Form S-8, Registration No. 33-37505). 10.4* Amendment No. 1 to Vintage Petroleum, Inc. 1990 Stock Plan, effective January 1, 1991 (Filed as Exhibit 10.15 to the Company's report on Form 10-K for the year ended December 31, 1991, filed March 30, 1992). 10.5* Amendment No. 2 to Vintage Petroleum, Inc. 1990 Stock Plan dated February 24, 1994 (Filed as Exhibit 10.15 to the Company's report on Form 10-K for the year ended December 31, 1993, filed March 29, 1994). 10.6* Amendment No. 3 to Vintage Petroleum, Inc. 1990 Stock Plan dated March 15, 1996 (Filed as Exhibit A to the Company's Proxy Statement for Annual Meeting of Stockholders dated April 1, 1996). 10.7* Amendment No. 4 to Vintage Petroleum, Inc. 1990 Stock Plan dated March 11, 1998 (Filed as Exhibit A to the Company's Proxy Statement for Annual Meeting of Stockholders dated March 31, 1998). 10.8* Amendment No. 5 to Vintage Petroleum, Inc. 1990 Stock Plan dated March 16, 1999 (Filed as Exhibit A to the Company's Proxy Statement for Annual Meeting of Stockholders dated March 31, 1999). 10.9* Vintage Petroleum, Inc. 401(k) Plan (Filed as Exhibit 4(c) to the Company's Registration Statement on Form S-8, Registration No. 33- 55706). 10.10* Vintage Petroleum, Inc. Non-Management Director Stock Option Plan (Filed as Exhibit 10.18 to the Company's report on Form 10-K for the year ended December 31, 1992, filed March 31, 1993 (the "1992 Form 10-K")). 10.11* Form of Incentive Stock Option Agreement under the Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.20 to the Company's report on Form 10-K for the year ended December 31, 1990, filed April 1, 1991). 10.12* Form of Non-Qualified Stock Option Agreement under the Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.20 to the 1992 Form 10-K). 10.13* Form of Non-Qualified Stock Option Agreement for non-employee directors under the Vintage Petroleum, Inc. 1990 Stock Plan. 10.14 Amended and Restated Credit Agreement dated as of October 21, 1998, among the Company, as borrower, and certain commercial lending institutions, as lenders, Bank of Montreal, as administrative agent, NationsBank, N.A., as syndication agent, and Societe Generale Southwest Agency, as documentation agent (Filed as Exhibit 10 to the Company's report on Form 10-Q for the quarter ended September 30, 1998, filed November 13, 1998). 10.15 First Amendment to the Amended and Restated Credit Agreement dated as of December 10, 1998, among the Company, as borrower, and certain commercial lending institutions, as lenders, Bank of Montreal, as administrative agent, Nations Bank, N.A., as syndication agent, and Societe Generale Southwest Agency, as documentation agent (Filed as Exhibit 10.14 to the 1998 Form 10-K). 40 10.16 Second Amendment to the Amended and Restated Credit Agreement dated as of May 19, 1999, among the Company, as borrower, and certain commercial lending institutions, as lenders, Bank of Montreal, as administrative agent, NationsBank, N.A., as syndication agent, and Societe Generale Southwest Agency, as documentation agent (Filed as Exhibit 10.1 to the Company's report on Form 10-Q for the quarter ended June 30, 1999, filed August 12, 1999). 10.17 Third Amendment to the Amended and Restated Credit Agreement dated as of November 18, 1999, among the Company, as borrower, and certain commercial lending institutions, as lenders, Bank of Montreal, as administrative agent, Bank of America, N.A., successor-in-interest by merger to NationsBank, N.A., as syndication agent, and Societe Generale Southwest Agency, as documentation agent. 21. Subsidiaries of the Company. 23.1 Consent of Arthur Andersen LLP. 23.2 Consent of Netherland, Sewell & Associates, Inc. 23.3 Consent of DeGolyer and MacNaughton. 27. Financial Data Schedule. ____________________ * Management contract or compensatory plan or arrangement. (b) Reports on Form 8-K. Form 8-K dated November 16, 1999, was filed November 16, 1999, to report under Item 5 the Company's press release dated November 16, 1999, announcing an increase in its borrowing base related to its unsecured revolving credit facility. No other reports on Form 8-K were filed during the fourth quarter of the fiscal year ended December 31, 1999. 41 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. VINTAGE PETROLEUM, INC. Date: March 13, 2000 By: /s/ C. C. Stephenson, Jr. --------------------------------- C. C. Stephenson, Jr. Chairman of the Board Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:
Signature Title Date --------- ----- ---- /s/ C. C. Stephenson, Jr. Director and Chairman of the Board March 13, 2000 - ---------------------------- C. C. Stephenson, Jr. /s/ S. Craig George Director, President and March 13, 2000 - ---------------------------- S. Craig George Chief Executive Officer (Principal Executive Officer) /s/ William L. Abernathy Director, Executive Vice President, March 13, 2000 - ---------------------------- William L. Abernathy Chief Operating Officer /s/ William C. Barnes Director, Executive Vice President, March 13, 2000 - ---------------------------- William C. Barnes Chief Financial Officer and Treasurer (Principal Financial Officer) /s/ Bryan H. Lawrence Director March 13, 2000 - ---------------------------- Bryan H. Lawrence /s/ John T. McNabb, II Director March 13, 2000 - ---------------------------- John T. McNabb, II /s/ Michael F. Meimerstorf Vice President and Controller March 13, 2000 - ---------------------------- Michael F. Meimerstorf (Principal Accounting Officer)
42 INDEX TO FINANCIAL STATEMENTS VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
Page ---- AUDITED FINANCIAL STATEMENTS OF VINTAGE PETROLEUM, INC. AND SUBSIDIARIES: Report of Independent Public Accountants......................................................... 44 Consolidated Balance Sheets as of December 31, 1999 and 1998..................................... 45 Consolidated Statements of Income (Loss) for the years ended December 31, 1999, 1998 and 1997.... 46 Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 1999, 1998 and 1997............................................................. 47 Consolidated Statements of Cash Flows for the years ended December 31, 1999, 1998 and 1997....... 48 Notes to Consolidated Financial Statements for the years ended December 31, 1999, 1998 and 1997.. 49
43 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of Vintage Petroleum, Inc.: We have audited the accompanying consolidated balance sheets of Vintage Petroleum, Inc. (a Delaware corporation) and subsidiaries as of December 31, 1999 and 1998, and the related consolidated statements of income (loss), changes in stockholders' equity and cash flows for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Vintage Petroleum, Inc. and subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Tulsa, Oklahoma February 21, 2000 44 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands, except shares and per share amounts)
ASSETS December 31, ---------------------- 1999 1998 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents......................................... $ 42,687 $ 5,245 Accounts receivable - Oil and gas sales............................................... 87,484 54,680 Joint operations................................................ 5,211 5,905 Prepaids and other current assets................................. 19,109 18,312 ---------- ---------- Total current assets............................................ 154,491 84,142 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT, at cost: Oil and gas properties, successful efforts method................. 1,521,672 1,368,914 Oil and gas gathering systems..................................... 15,453 14,774 Other............................................................. 17,287 16,276 ---------- ---------- 1,554,412 1,399,964 Less accumulated depreciation, depletion and amortization......... 583,060 501,722 ---------- ---------- 971,352 898,242 ---------- ---------- OTHER ASSETS, net.................................................... 42,291 31,791 ---------- ---------- $1,168,134 $1,014,175 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Revenue payable................................................... $ 25,899 $ 17,382 Accounts payable - trade.......................................... 26,118 24,812 Other payables and accrued liabilities............................ 41,885 24,731 ---------- ---------- Total current liabilities.................................... 93,902 66,925 ---------- ---------- LONG-TERM DEBT....................................................... 625,318 672,507 ---------- ---------- DEFERRED INCOME TAXES................................................ 15,780 - ---------- ---------- OTHER LONG-TERM LIABILITIES.......................................... 2,005 785 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Note 4) STOCKHOLDERS' EQUITY, per accompanying statements: Preferred stock, $.01 par, 5,000,000 shares authorized, zero shares issued and outstanding............................ - - Common stock, $.005 par, 80,000,000 shares authorized, 62,407,866 and 53,107,066 shares issued and outstanding....... 312 266 Capital in excess of par value.................................... 314,490 230,736 Retained earnings................................................. 116,327 42,956 ---------- ---------- 431,129 273,958 ---------- ---------- $1,168,134 $1,014,175 ========== ==========
The accompanying notes are an integral part of these statements. 45 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In thousands, except per share amounts)
For the Years Ended December 31, ---------------------------------- 1999 1998 1997 -------- --------- -------- REVENUES: Oil and gas sales.................................................. $370,731 $ 265,863 $354,490 Gas marketing...................................................... 60,275 54,108 45,981 Oil and gas gathering.............................................. 6,955 7,741 18,063 Gain on disposition of assets...................................... 54,991 - - Other income (expense)............................................. 3,783 1,223 (1,944) -------- --------- -------- 496,735 328,935 416,590 -------- --------- -------- COSTS AND EXPENSES: Lease operating, including production taxes........................ 115,471 122,726 114,346 Exploration costs.................................................. 14,674 24,056 12,667 Impairment of oil and gas properties............................... 3,306 70,913 8,785 Gas marketing...................................................... 57,550 51,560 43,398 Oil and gas gathering.............................................. 5,153 6,258 14,932 General and administrative......................................... 36,409 31,996 27,361 Depreciation, depletion and amortization........................... 107,807 108,975 96,307 Interest........................................................... 58,665 43,680 36,762 -------- --------- -------- 399,035 460,164 354,558 -------- --------- -------- Income (loss) before income taxes and minority interest......... 97,700 (131,229) 62,032 -------- --------- -------- PROVISION (BENEFIT) FOR INCOME TAXES: Current............................................................ 5,954 (4,068) 5,235 Deferred........................................................... 18,375 (39,496) 1,640 -------- --------- -------- 24,329 (43,564) 6,875 -------- --------- -------- MINORITY INTEREST IN INCOME OF SUBSIDIARY............................ - - (203) -------- --------- -------- NET INCOME (LOSS).................................................... $ 73,371 $ (87,665) $ 54,954 ======== ========= ======== EARNINGS (LOSS) PER SHARE: Basic.............................................................. $ 1.27 $ (1.69) $ 1.07 ======== ========= ======== Diluted............................................................ $ 1.24 $ (1.69) $ 1.05 ======== ========= ======== Weighted Average Common Shares Outstanding: Basic.............................................................. 57,989 51,900 51,178 ======== ========= ======== Diluted............................................................ 59,315 51,900 52,026 ======== ========= ========
The accompanying notes are an integral part of these statements. 46 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (In thousands, except per share amounts)
Capital In Excess Common Stock of Par Retained -------------- Shares Amount Value Earnings Total ------ ------ -------- -------- -------- BALANCE AT DECEMBER 31, 1996.................................. 48,138 $ 241 $152,200 $ 83,965 $236,406 Net income............................................... - - - 54,954 54,954 Issuance of common stock................................. 3,000 15 46,978 - 46,993 Exercise of stock options and resulting tax effects................................ 421 2 2,830 - 2,832 Cash dividends declared ($.07 per share)................. - - - (3,607) (3,607) ------ ------ -------- -------- -------- BALANCE AT DECEMBER 31, 1997.................................. 51,559 258 202,008 135,312 337,578 Net loss................................................. - - - (87,665) (87,665) Issuance of common stock................................. 1,325 7 26,493 - 26,500 Exercise of stock options and resulting tax effects................................ 223 1 2,235 - 2,236 Cash dividends declared ($.09 per share)................. - - - (4,691) (4,691) ------ ------ -------- -------- -------- BALANCE AT DECEMBER 31, 1998.................................. 53,107 266 230,736 42,956 273,958 Net income............................................... - - - 73,371 73,371 Issuance of common stock................................. 9,241 46 83,284 - 83,330 Exercise of stock options and resulting tax effects................................ 60 - 470 - 470 ------ ------ -------- -------- -------- BALANCE AT DECEMBER 31, 1999.................................. 62,408 $ 312 $314,490 $116,327 $431,129 ====== ====== ======== ======== ========
The accompanying notes are an integral part of these statements. 47 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
For the Years Ended December 31, --------------------------------- 1999 1998 1997 --------- --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)................................................ $ 73,371 $ (87,665) $ 54,954 Adjustments to reconcile net income (loss) to cash provided by operating activities - Depreciation, depletion and amortization...................... 107,807 108,975 96,307 Impairment of oil and gas properties.......................... 3,306 70,913 8,785 Exploration costs............................................. 14,674 24,056 12,667 Provision (benefit) for deferred income taxes................. 18,375 (39,496) 1,640 Gain on disposition of assets................................. (54,991) - - Minority interest in income of subsidiary..................... - - 203 --------- --------- --------- 162,542 76,783 174,556 Decrease (increase) in receivables............................... (32,110) 9,353 5,428 U.S. income tax refund receivable................................ 5,323 (5,323) - Increase (decrease) in payables and accrued liabilities.......... 29,500 (10,570) 7,187 Other............................................................ 3,603 (3,993) (569) --------- --------- --------- Cash provided by operating activities......................... 168,858 66,250 186,602 --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures - Oil and gas properties........................................ (237,484) (252,254) (257,275) Gathering systems and other................................... (2,669) (9,960) (2,275) Proceeds from sales of oil and gas properties.................... 78,241 588 360 Purchase of companies, net of cash acquired...................... - (10,651) (38,788) Other............................................................ 634 (3,042) (2,670) --------- --------- --------- Cash used by investing activities............................. (161,278) (275,319) (300,648) --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Sale of common stock............................................. 83,685 884 47,910 Sale of 9 3/4% Senior Subordinated Notes Due 2009................ 146,000 - - Sale of 8 5/8% Senior Subordinated Notes Due 2009................ - - 96,270 Advances on revolving credit facility and other borrowings....... 50,213 232,736 192,521 Payments on revolving credit facility and other borrowings....... (248,708) (20,711) (216,335) Dividends paid................................................... (1,328) (4,392) (3,297) --------- --------- --------- Cash provided by financing activities......................... 29,862 208,517 117,069 --------- --------- --------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............... 37,442 (552) 3,023 CASH AND CASH EQUIVALENTS, beginning of year....................... 5,245 5,797 2,774 --------- --------- --------- CASH AND CASH EQUIVALENTS, end of year............................. $ 42,687 $ 5,245 $ 5,797 ========= ========= =========
The accompanying notes are an integral part of these statements. 48 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the Years Ended December 31, 1999, 1998 and 1997 1. Business and Significant Accounting Policies Consolidation Vintage Petroleum, Inc. is an independent energy company with operations primarily in the exploration and production, gas marketing and gathering segments of the oil and gas industry. Approximately 99 percent of the Company's operations are within the exploration and production segment based on 1999 operating income before impairments of oil and gas properties and gains on asset sales. Its core areas of exploration and production operations include the West Coast, Gulf Coast, East Texas and Mid-Continent areas of the United States, the San Jorge Basin of Argentina, the Chaco Basin in Bolivia and Ecuador. The consolidated financial statements include the accounts of Vintage Petroleum, Inc. and its wholly- and majority-owned subsidiaries and its proportionately consolidated general partner interests in various joint ventures (collectively, the "Company"). All significant intercompany accounts and transactions have been eliminated in consolidation. The preparation of financial statements in conformity with accounting principles generally accepted in the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain 1998 and 1997 amounts have been reclassified to conform with the 1999 presentation. These reclassifications have no impact on net income (loss). Oil and Gas Properties Under the successful efforts method of accounting, the Company capitalizes all costs related to property acquisitions and successful exploratory wells, all development costs and the costs of support equipment and facilities. All costs related to unsuccessful exploratory wells are expensed when such wells are determined to be non-productive; other exploration costs, including geological and geophysical costs, are expensed as incurred. The Company recognizes gain or loss on the sale of properties on a field basis. Unproved leasehold costs are capitalized and are reviewed periodically for impairment. Costs related to impaired prospects are charged to expense. If oil and gas prices decline in the future, some of these unproved prospects may not be economic to develop which could lead to increased impairment expense. Costs of development dry holes and proved leaseholds are amortized on the unit-of-production method based on proved reserves on a field basis. The depreciation of capitalized production equipment and drilling costs is based on the unit-of-production method using proved developed reserves on a field basis. Estimated abandonment costs, net of salvage value, are included in the depreciation and depletion calculation. 49 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) The Company reviews its proved oil and gas properties for impairment on a field basis. For each field, an impairment provision is recorded whenever events or circumstances indicate that the carrying value of those properties may not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future net revenues from production of total proved oil and gas reserves over the economic life of the reserves, based on the Company's expectations of future oil and gas prices and costs. In estimating the future net revenues at December 31, 1999, the Company assumed that the current oil price environment would return to more historical levels over a short period of time and thereafter, escalate annually. The Company assumed gas prices and operating costs would escalate annually beginning at current levels. Due to the volatility of oil and gas prices, it is possible that the Company's assumptions regarding oil and gas prices may change in the future and may result in future impairment provisions. The Company recorded impairment provisions related to its proved oil and gas properties of $3.3 million, $70.9 million and $8.8 million in 1999, 1998 and 1997, respectively. Revenue Recognition Natural gas revenues are recorded using the sales method. Under this method, the Company recognizes revenues based on actual volumes of gas sold to purchasers. The Company and other joint interest owners may sell more or less than their entitlement share of the natural gas volumes produced. A liability is recorded and revenue is deferred if the Company's excess sales of natural gas volumes exceed its estimated remaining recoverable reserves. Hedging The Company periodically uses hedges (swap agreements) to reduce the impact of oil and natural gas price fluctuations. Gains or losses on swap agreements are recognized as an adjustment to sales revenue when the related transactions being hedged are finalized. Gains or losses from swap agreements that do not qualify for accounting treatment as hedges are recognized currently as other income or expense. The cash flows from such agreements are included in operating activities in the consolidated statements of cash flows. The Company participated in oil hedges covering 1.84 MMBbls during 1999. The impact of these hedges reduced the Company's U.S. average oil price by 11 cents to $15.92 per Bbl and its overall average oil price by six cents to $16.62 per Bbl. The Company was not a party to any oil hedges in 1998. During 1997, the impact of Argentina oil hedges reduced the Company's overall average oil price 24 cents to $17.02 per Bbl and its average Argentina oil price was reduced 66 cents to $16.67 per Bbl. Approximately 49 percent of the 1997 Argentina oil production was covered by hedges. In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS No. 133"). In June 1999, the FASB issued Statement No. 137, Accounting for Derivative Instruments and Hedging Activities- Deferral of the Effective Date of FASB Statement No. 133. SFAS No. 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. 50 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) SFAS No. 133, as amended, is effective for fiscal years beginning after June 15, 2000; however, beginning June 16, 1998, companies may implement the statement as of the beginning of any fiscal quarter. SFAS No. 133 cannot be applied retroactively and must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts. The Company has not yet quantified the impact of adopting SFAS No. 133 on its financial statements and has not determined the timing of or method of the adoption of SFAS No. 133. However, it should be noted that the impact of SFAS No. 133 could increase volatility in future reported earnings and other comprehensive income. Depreciation Depreciation of property, plant and equipment (other than oil and gas properties) is provided using both straight-line and accelerated methods based on estimated useful lives ranging from three to seven years. Income Taxes Deferred income taxes are provided on transactions which are recognized in different periods for financial and tax reporting purposes. Such temporary differences arise primarily from the deduction of certain oil and gas exploration and development costs which are capitalized for financial reporting purposes and differences in the methods of depreciation. Statements of Cash Flows Cash equivalents consist of highly liquid money-market mutual funds and bank deposits with initial maturities of three months or less. At December 31, 1999, the Company had approximately $40 million in escrow accounts primarily related to potential like-kind exchange transactions. These funds were invested in highly liquid investment funds at year end. During the years ended December 31, 1999, 1998 and 1997, the Company made cash payments for interest totaling $56.8 million, $42.4 million and $33.2 million, respectively. Cash payments for U.S. income taxes of $1.5 million and $5.3 million were made for 1998 and 1997, respectively. No cash payments for U.S. income taxes were made during 1999. Cash payments of $1.3 million were made during 1998 for foreign tax withholdings. No cash payments were made during 1999 or 1997 for foreign income taxes. In November 1998, the Company purchased 100 percent of the outstanding common stock of Elf Hydrocarbures Equateur, S.A., a French subsidiary of Elf Aquitaine. Total consideration included cash and common stock of the Company. The value of the non-cash consideration was $26.5 million and is not reflected in the Company's 1998 Statement of Cash Flows. 51 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Earnings Per Share Basic earnings (loss) per common share were computed by dividing net income (loss) by the weighted average number of shares outstanding during the period. Diluted earnings per common share for 1999 and 1997 were computed assuming the exercise of all dilutive options, as determined by applying the treasury stock method. For 1998, the computation of diluted loss per share was antidilutive; therefore, the amounts reported for basic and diluted loss per share were the same. Had the Company been in a net income position for 1998, the Company's diluted weighted average outstanding common shares as calculated under SFAS No. 128 would have been 54,604,530 with an additional 1,629,000 shares at an average exercise price of $17.83 that would have been antidilutive. In addition, for the year ended December 31, 1999, the Company had outstanding stock options for 1,635,000 additional shares of the Company's common stock, with an average exercise price of $17.70, which were antidilutive. The Company had no antidilutive shares for the year ended December 31, 1997. General and Administrative Expense The Company receives fees for operation of jointly-owned oil and gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $2.9 million, $2.7 million and $2.6 million in 1999, 1998 and 1997, respectively. Lease Operating Expense For the years ended December 31, 1999, 1998 and 1997, the Company recorded gross production taxes of $7.5 million, $7.4 million and $8.9 million, respectively, in lease operating expenses. Revenue Payable Amounts payable to royalty and working interest owners resulting from sales of oil and gas from jointly-owned properties and from purchases of oil and gas by the Company's marketing and gathering segments are classified as revenue payable in the accompanying financial statements. Accounts Receivable The Company's oil and gas, gas marketing and gathering sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates, independent marketing companies and major oil companies. The Company's joint operations accounts receivable are from a large number of major and independent oil companies, partnerships, individuals and others who own interests in the properties operated by the Company. 52 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Comprehensive Income In June 1997, the Financial Accounting Standards Board issued Statement No. 130, Reporting Comprehensive Income ("SFAS No. 130"), establishing standards for reporting and display of comprehensive income and its components in financial statements. SFAS No. 130 defines comprehensive income as the total of net income and all other non-owner changes in equity. SFAS No. 130 is effective for fiscal years beginning after December 15, 1997. The Company had no non-owner changes in equity other than net income and losses during the years ended December 31, 1999, 1998 and 1997. 2. Long-Term Debt Long-term debt at December 31, 1999 and 1998, consisted of the following:
(In thousands) 1999 1998 -------- -------- Revolving credit facility............................................. $226,200 $423,500 Senior subordinated notes: 9% Notes due 2005, less unamortized discount........................ 149,755 149,714 8 5/8% Notes due 2009, less unamortized discount.................... 99,363 99,293 9 3/4% Notes due 2009............................................... 150,000 - -------- -------- $625,318 $672,507 ======== ========
The Company has no long-term debt maturities prior to December 1, 2001. Aggregate maturities of long-term debt for each of the years ending December 31, 2001, through December 31, 2003, are $28.3 million, $113.1 million and $84.8 million, with $399.1 million thereafter. The Company had $5.9 million and $5.3 million of accrued interest payable related to its long-term debt at December 31, 1999 and 1998, respectively, included in other payables and accrued liabilities. Revolving Credit Facility The Company has available an unsecured revolving credit facility under the Amended and Restated Credit Agreement dated October 21, 1998, as amended (the "Bank Facility"), between the Company and certain banks. The Bank Facility establishes a borrowing base (currently $545 million) based on the banks' evaluation of the Company's oil and gas reserves. The amount available to be borrowed under the Bank Facility is limited to the lesser of the borrowing base or the facility size, which is currently set at $535 million. The Company may increase the facility size up to $625 million without further approvals from the existing bank group if additional banks agree to join the group. Outstanding advances under the Bank Facility bear interest payable quarterly at a floating rate based on Bank of Montreal's alternate base rate (as defined) or, at the Company's option, at a fixed rate for up to six months based on the Eurodollar market rate ("LIBOR"). The Company's interest rate increments above the alternate base rate and LIBOR vary based on the level of outstanding senior debt to the borrowing base. In addition, the Company must pay a commitment fee ranging from 0.25 to 0.375 percent per annum on the unused portion of the banks' commitment. Total outstanding advances at December 31, 1999, were $226.2 million at an average interest rate of approximately 7.5 percent. 53 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) On a semiannual basis, the Company's borrowing base is redetermined by the banks based upon their review of the Company's oil and gas reserves. The Company's borrowing base was last redetermined in December 1999. If the sum of outstanding senior debt exceeds the borrowing base, as redetermined, the Company must repay such excess. Any principal advances outstanding at September 11, 2001, will be payable in eight equal consecutive quarterly installments commencing December 1, 2001, with maturity at September 11, 2003. The terms of the Bank Facility impose certain restrictions on the Company regarding the pledging of assets and limitations on additional indebtedness. In addition, the Bank Facility requires the maintenance of a minimum current ratio (as defined) and tangible net worth (as defined) of not less than $238.6 million plus 75 percent of the net proceeds of any future equity offerings less any impairment writedowns required by GAAP or by the Securities and Exchange Commission. Senior Subordinated Notes On December 20, 1995, the Company issued $150 million of its 9% Senior Subordinated Notes due 2005 (the "9% Notes"). The 9% Notes are redeemable at the option of the Company, in whole or in part, at any time on or after December 15, 2000. The 9% Notes mature on December 15, 2005, with interest payable semiannually on June 15 and December 15 of each year. On February 5, 1997, the Company issued $100 million of its 8 5/8% Senior Subordinated Notes due 2009 (the "8 5/8% Notes"). The 8 5/8% Notes are redeemable at the option of the Company, in whole or in part, at any time on or after February 1, 2002. The 8 5/8% Notes mature on February 1, 2009, with interest payable semiannually on February 1 and August 1 of each year. On January 26, 1999, the Company issued $150 million of its 9 3/4% Senior Subordinated Notes due 2009 (the "9 3/4% Notes"). The 9 3/4% Notes are redeemable at the option of the Company, in whole or in part, at any time on or after February 1, 2004. In addition, prior to February 1, 2002, the Company may redeem up to 33 1/3% of the 9 3/4% Notes with the proceeds of certain underwritten public offerings of the Company's common stock. The 9 3/4% Notes mature on June 30, 2009, with interest payable semiannually on June 30 and December 30 of each year. The net proceeds to the Company from the sale of the 9 3/4% Notes (approximately $146 million) were used to repay a portion of the existing indebtedness under the Company's Bank Facility. The 9% Notes, 8 5/8% Notes and 9 3/4% Notes (collectively, the "Notes") are unsecured senior subordinated obligations of the Company, rank subordinate in right of payment to all senior indebtedness (as defined) and rank pari passu with each other. Upon a change in control (as defined) of the Company, holders of the Notes may require the Company to repurchase all or a portion of the Notes at a purchase price equal to 101 percent of the principal amount thereof, plus accrued and unpaid interest. The indentures for the Notes contain limitations on, among other things, additional indebtedness and liens, the payment of dividends and other distributions, certain investments and transfers or sales of assets. 3. Capital Stock Public Offerings and Other Issuances On February 5, 1997, the Company completed a public offering of 3,000,000 shares of common stock, all of which were sold by the Company. Net proceeds to the Company of approximately $47 million were used to repay a portion of existing indebtedness under the Company's revolving credit facility. 54 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) On November 4, 1998, the Company issued 1,325,000 shares of common stock to Elf Aquitaine as partial consideration for the acquisition of its French subsidiary, Elf Hydrocarbures Equateur, S.A., which owns producing oil properties and undeveloped acreage in Ecuador. The 1,325,000 shares of common stock of the Company is valued at a guaranteed amount of $20 per share, or $26.5 million. If the Company's prevailing share price is not equal to at least $20 per share after two years from the date of closing, then the Company will be required to deliver additional consideration under the price guarantee provision of the agreement. Such additional consideration, if any, is payable, at the Company's option, in cash or additional shares of the Company's common stock. On March 16, 1999, the Company's Board of Directors adopted a stockholder rights plan and declared a dividend distribution of one Preferred Share Purchase Right on each outstanding share of the Company's common stock which was made on April 5, 1999, to stockholders of record on that date. The Rights will expire on April 5, 2009. The Rights will be exercisable only if a person or group acquires 15 percent or more of the Company's common stock or announces a tender offer the consummation of which would result in ownership by a person or group of 15 percent or more of the common stock. Each Right will entitle stockholders to buy one-one-thousandth of a share of a new series of junior participating preferred stock at an exercise price of $60. If the Company is acquired in a merger or other business combination transaction after a person has acquired 15 percent or more of the Company's outstanding common stock, each Right will entitle its holder to purchase, at the Right's then-current exercise price, a number of the acquiring company's common shares having a market value of twice such price. In addition, if a person or group acquires 15 percent or more of the Company's outstanding common stock, each Right will entitle its holder (other than such person or members of such group) to purchase, at the Right's then-current exercise price, a number of the Company's common shares having a market value of twice such price. Prior to the acquisition by a person or group of beneficial ownership of 15 percent or more of the Company's common stock, the Rights are redeemable for one cent per Right at the option of the Company's Board of Directors. On June 21, 1999, the Company completed a public offering of 9,000,000 shares of common stock, all of which were sold by the Company. Net proceeds of approximately $81.2 million were used to partially fund the purchase of certain oil and gas properties from a subsidiary of Total Fina S.A. and a subsidiary of Repsol S.A. in early July 1999. On July 15, 1999, in connection with the exercise by the underwriters of a portion of the over-allotment option, the Company sold an additional 240,800 shares of common stock using the additional $2.1 million of net proceeds to reduce a portion of the Company's existing indebtedness under its revolving credit facility. 55 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Stock Plans The Company has three fixed plans which reserve shares of common stock for issuance to key employees and non-management directors. The Company accounts for these plans under Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("APB No. 25") and has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation ("SFAS No. 123"). Accordingly, no compensation cost has been recognized. Had compensation cost for these plans been determined consistent with the provisions of SFAS No. 123, the Company's net income (loss) and earnings (loss) per share would have been reduced (increased) to the following pro forma amounts:
(In thousands, except per share amounts) 1999 1998 1997 -------- -------- -------- Net income (loss) - as reported..................... $73,371 $(87,665) $ 54,954 Net income (loss) - pro forma....................... 71,130 (89,759) 53,501 Earnings (loss) per share - as reported: Basic........................................ 1.27 (1.69) 1.07 Diluted...................................... 1.24 (1.69) 1.05 Earnings (loss) per share - pro forma: Basic........................................ 1.23 (1.73) 1.05 Diluted...................................... 1.20 (1.73) 1.03
The pro forma effect on net income (loss) for 1999, 1998 and 1997 may not be representative of the pro forma effect on net income in future years because SFAS No. 123 has not been applied to options granted prior to January 1, 1995. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. The weighted average assumptions used for options granted in 1999 include a dividend yield of 0.6 percent, expected volatility of approximately 38.6 percent, a risk-free interest rate of approximately 5.1 percent and expected lives of 4.2 years. The weighted average assumptions used for options granted in 1998 include a dividend yield of 0.6 percent, expected volatility of approximately 27.1 percent, a risk-free interest rate of approximately 5.7 percent and expected lives of 4.2 years. The weighted average assumptions used for options granted in 1997 include a dividend yield of 0.4 percent, expected volatility of approximately 28.9 percent, a risk-free interest rate of approximately 6.3 percent and expected lives of 4.2 years. Under the 1983 Stock Option Plan, as amended (the "1983 Plan"), incentive stock options were granted to key employees of the Company. Generally, options granted under the 1983 Plan were exercisable for a two to seven year period beginning three years from the date granted. As of December 31, 1997, all available options had been granted and exercised under the 1983 Plan. 56 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Under the 1990 Stock Plan, as amended (the "1990 Plan"), a total of up to 6,000,000 shares of common stock are available for issuance to key employees and directors of the Company. The 1990 Plan permits the granting of any or all of the following types of awards: (a) stock options, (b) stock appreciation rights and (c) restricted stock. As of December 31, 1999, awards for a total of 415,000 shares of common stock remain available for grant under the 1990 Plan. The 1990 Plan is administered by the Board of Directors of the Company (the "Board"). Subject to the terms of the 1990 Plan, the Board has the authority to determine plan participants, the types and amounts of awards to be granted and the terms, conditions and provisions of awards. Options granted pursuant to the 1990 Plan may, at the discretion of the Board, be either incentive stock options or non-qualified stock options. The exercise price of incentive stock options may not be less than the fair market value of the common stock on the date of grant and the term of the option may not exceed 10 years. In the case of non- qualified stock options, the exercise price may not be less than 85 percent of the fair market value of the common stock on the date of grant. Any stock appreciation rights granted under the 1990 Plan will give the holder the right to receive cash in an amount equal to the difference between the fair market value of the share of common stock on the date of exercise and the exercise price. Restricted stock under the 1990 Plan will generally consist of shares which may not be disposed of by participants until certain restrictions established by the Board lapse. Under the Non-Management Director Stock Option Plan (the "Director Plan"), 60,000 shares of common stock are available for issuance to the outside directors of the Company. Each outside director receives an initial option to purchase 5,000 shares of common stock during the director's first year of service to the Company. Annually thereafter, options to purchase 1,000 shares of common stock are to be granted to each outside director. Options granted pursuant to the Director Plan are non-qualified stock options with terms not to exceed 10 years and the option exercise price must equal the fair market value of the common stock on the date of grant. As of December 31, 1999, options for a total of 20,000 shares of common stock remain available for grant under the Director Plan. The following is an analysis of all option activity under the 1983 Plan, the 1990 Plan and the Director Plan for 1999, 1998 and 1997:
1999 1998 1997 ----------------------------- -------------------------- -------------------------- Wtd. Avg. Wtd. Avg. Wtd. Avg. Exercise Exercise Exercise Shares Price Shares Price Shares Price ------------ ------------- ----------- ------------ ----------- ----------- Beginning stock options outstanding................ 3,606,142 $ 12.79 3,060,322 $ 10.53 2,688,904 $ 8.13 Stock options granted....... 1,070,000 7.30 819,000 20.11 810,000 15.53 Stock options canceled...... - - (50,000) 14.08 - - Stock options exercised..... (60,000) 5.94 (223,180) 8.44 (438,582) 4.99 ------------ ----------- ----------- Ending stock options outstanding................ 4,616,142 $ 11.61 3,606,142 $ 12.79 3,060,322 $ 10.53 ============ ========== =========== ======== =========== ======== Ending stock options exercisable................ 1,967,256 $ 8.94 1,490,788 $ 8.47 1,406,757 $ 8.15 ============ ========== =========== ======== =========== ======== Weighted average fair value of options........... $ 2.24 $ 4.14 $ 4.92 ============ =========== ===========
57 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Of the 4,616,142 options outstanding at December 31, 1999: (a) 1,705,000 options have exercise prices between $3.50 and $8.38, with a weighted average exercise price of $7.28 and a weighted average contractual life of 7.3 years (647,000 of these options are exercisable currently at a weighted average price of $7.34); (b) 2,088,142 options have exercise prices between $8.78 and $15.50, with a weighted average exercise price of $11.80 and a weighted average contractual life of 6.0 years (1,310,032 of these options are exercisable currently at a weighted average price of $9.66); and (c) 823,000 options have exercise prices between $16.06 and $20.19, with a weighted average exercise price of $20.06 and a weighted average contractual life of 8.2 years (10,224 of these options are exercisable currently at a weighted average price of $17.21). All of the outstanding options are exercisable at various times in years 2000 through 2009. All incentive stock options and non-qualified options were granted at fair market value on the date of grant. As of December 31, 1999, no awards other than incentive and non-qualified stock options have been granted under the 1990 Plan. Generally, options granted under the 1990 Plan have a 10- year term and provide for vesting after three years. At December 31, 1999, a total of 5,051,142 shares of the Company's common stock are reserved for issuance pursuant to the 1990 Plan and the Director Plan. Preferred Stock Preferred stock at December 31, 1999, consists of 5,000,000 authorized but unissued shares. Preferred stock may be issued from time to time in one or more series, and the Board of Directors, without further approval of the stockholders, is authorized to fix the dividend rates and terms, conversion rights, voting rights, redemption rights and terms, liquidation preferences, sinking fund and any other rights, preferences, privileges and restrictions applicable to each series of preferred stock. 4. Commitments and Contingencies The Company committed to perform 17,728 work units related to its concession rights in the Naranjillos field in Santa Cruz Province, Bolivia awarded in late 1997. Through December 31, 1999, the Company has completed a total of 8,977 work units through capital expenditures in 1998 and 1999 of $7.6 million and $24.1 million, respectively. The total remaining work unit commitment is guaranteed by the Company through a $56.4 million letter of credit; however, the Company anticipates that it will fulfill the remaining work unit commitment through approximately $35 to $40 million of various drilling capital expenditures. The Company has budgeted to spend $37 million in 2000 to complete 8,751 work units, fulfilling its Naranjillos field commitment. During July 1999, the Company also committed to perform an additional 1,068 work units in its Chaco field location in Bolivia over the next two years. This work commitment is secured by a $5.3 million letter of credit. Under the Company's exploration contract on Block 19 in Ecuador, the Company is required to drill one additional well. The Company expects to drill this well during the third quarter of 2000 at a cost of approximately $4 million. 58 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) The Company is also committed to spend approximately $11 million in the Republic of Yemen over a two and one-half year period which began July 28, 1998. This work commitment is guaranteed by an $11 million letter of credit. The expenditures include the acquisition and interpretation of over 150 square kilometers of seismic and the drilling of three exploration wells. At the end of the first two and one-half years, the Company has the option to extend the work program for a second two and one-half year period with similar work and capital commitments required. Through 1999, approximately $2 million of the $11 million commitment has been spent. To fulfill its commitment, the Company has budgeted to spend approximately $9 million in 2000 on drilling the three exploration wells. The Company had $93.7 million in letters of credit (including the $72.7 million in letters of credit discussed above) outstanding at December 31, 1999. These letters of credit relate primarily to various obligations for acquisition and exploration activities in South America and bonding requirements of various state regulatory agencies for oil and gas operations. The Company's availability under its revolving credit facility is reduced by the outstanding balance of letters of credit (excluding the $56.4 million Bolivia letter of credit discussed above). On November 4, 1998, the Company issued 1,325,000 shares of common stock to Elf Aquitaine as partial consideration for the acquisition of its French subsidiary, Elf Hydrocarbures Equateur, S.A., which owns producing oil properties and undeveloped acreage in Ecuador. The 1,325,000 shares of common stock of the Company is valued at a guaranteed amount of $20 per share, or $26.5 million. If the Company's prevailing share price is not equal to at least $20 per share after two years from the date of closing, the Company will be required to deliver additional consideration under the price guarantee provision of the agreement. Such additional consideration, if any, is payable, at the Company's option, in cash or additional shares of the Company's common stock. Had the Company been required to fulfill its commitment under the price guarantee at December 31, 1999 (based on the average price for the preceding 60 trading days of $11.28), it would have had to pay an additional $11.5 million in cash or issue an additional 1.0 million shares of its common stock. Rent expense was $1.8 million, $1.2 million and $1.2 million for 1999, 1998 and 1997, respectively. The future minimum commitments under long-term, non- cancellable leases for office space are $1.2 million, $1.1 million, $1.3 million, $1.4 million and $1.5 million for the calendar years 2000 through 2004, respectively with $3.6 million remaining in years thereafter. On November 5, 1996, the Province of Santa Cruz, Argentina brought suit against the Company's subsidiary Cadipsa S.A. in the Corte Suprema de Justicia de la Nacion (the Supreme Court of Justice of the Argentine Republic, Buenos Aires, Argentina), Dossier No. s-1451, seeking to recover approximately $10.6 million (which sum includes interest) allegedly due as additional royalties on four concessions granted in 1990 in which the Company currently owns a 100 percent working interest. The Company and its predecessors in title have been paying royalties at an eight percent rate; the Province of Santa Cruz claims the rate should be 12 percent. The amount of such claim will increase at the differential of these royalty rates until this claim is resolved. With respect to the 50 percent interest in the two concessions that the Company acquired from British Gas, plc, the Company believes that it is entitled to indemnification by British Gas, plc for any loss sustained by the Company as a result of this claim. Such indemnification equals approximately $5.2 million of the current $21.4 million claim as of December 31, 1999. The Company has no indemnification from its predecessors in title with respect to the payment of royalties on the other two concessions. The Company expects the outcome of this litigation to be decided during 2000 and although the Company cannot predict the outcome, based upon the advice of counsel, the Company does not expect this claim to have a material adverse impact on the Company's financial position, results of operations, or total proved reserves. 59 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) The Company is a defendant in various other lawsuits and is a party in governmental proceedings from time to time arising in the ordinary course of business. In the opinion of management, none of the various other pending lawsuits and proceedings should have a material adverse impact on the Company's financial position or results of operations. 5. Financial Instruments Price Risk Management The Company periodically uses hedges (swap agreements) to reduce the impact of oil and natural gas price fluctuations on its operating results and cash flows. These swap agreements typically entitle the Company to receive payments from (or require it to make payments to) the counter parties based upon the differential between a fixed price and a floating price based on a published index. The Company's hedging activities are conducted with major corporations and investment and commercial banks which the Company believes are minimal credit risks. At December 31, 1999, the Company was a party to oil price swap agreements for 2000 covering 1.8 MMBbls at a weighted average NYMEX reference price of $22.43 per Bbl. During the first quarter of 2000, the Company entered into additional oil hedging contracts through December 31, 2000, covering an additional 3.6 MMBbls of oil and a weighted average NYMEX reference price of $25.77 per Bbl. The Company continues to monitor oil and gas prices and may enter into additional oil and gas hedges or swaps in the future. At December 31, 1998, the Company was a party to natural gas basis swaps for the calender year 1999 covering a total of 30.8 million MMBtu of gas. These natural gas basis swaps were used to hedge the basis differential between the NYMEX reference price and industry delivery point indexes under which the gas is sold. Fair Value of Financial Instruments The Company values financial instruments as required by Statement of Financial Accounting Standards No. 107, Disclosures About Fair Value of Financial Instruments. The Company estimates the value of the Notes based on quoted market prices. The Company estimates the value of its other long-term debt based on the estimated borrowing rates currently available to the Company for long-term loans with similar terms and remaining maturities. The estimated fair value of the Company's long-term debt at December 31, 1999 and 1998, was $621.6 million and $663.0 million, respectively, compared with a carrying value of $625.3 million and $672.5 million, respectively. The fair value of commodity swap agreements is the amount at which they could be settled, based on quoted market prices. The Company was unable to estimate the fair value of the natural gas basis swaps in place at December 31, 1998, as there was no quoted market price available. At December 31, 1999, the Company would have received approximately $700,000 to terminate its oil swap agreements then in place. The carrying value of other financial instruments approximates fair value because of the short maturity of those instruments. 60 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) 6. Income Taxes Income (loss) before income taxes and minority interest is composed of the following:
(In thousands) 1999 1998 1997 ----------- ----------- ----------- Domestic....................... $ 33,097 $ (122,331) $ 31,919 Foreign........................ 64,603 (8,898) 30,113 ----------- ----------- ----------- $ 97,700 $ (131,229) $ 62,032 =========== =========== ===========
The total provision (benefit) for income taxes consists of the following:
(In thousands) 1999 1998 1997 ----------- ----------- ----------- Current: Domestic................ $ 1,036 $ (5,324) $ 4,277 Foreign................. 4,918 1,256 958 Deferred: Domestic................ 11,730 (43,722) 6,003 Foreign................. 6,645 4,226 (4,363) ---------- ----------- ----------- $ 24,329 $ (43,564) $ 6,875 ========== =========== ===========
A reconciliation of the Federal statutory income tax rate to the effective rate is as follows:
1999 1998 1997 ----------- ----------- ----------- Statutory U.S. income tax rate..................... 35.0% (35.0)% 35.0% State income tax................................... 3.9 (3.9) 3.9 Federal income tax credits......................... (0.1) 1.8 (3.0) Foreign withholding tax............................ - 1.3 - Foreign operations................................. (2.9) (3.4) 0.6 Argentina NOL valuation allowance.................. - 4.3 - Argentina NOL valuation allowance reversal......... (5.8) - (5.0) Argentina NOL carryforward utilization............. (5.2) - (18.4) Other.............................................. - 1.7 (2.0) ----------- ----------- ----------- 24.9% (33.2)% 11.1% ----------- ----------- -----------
61 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) The components of the Company's net deferred tax asset (liability) as of December 31, 1999 and 1998, are as follows:
(In thousands) 1999 1998 ----------- ---------- Deferred Tax Assets: U.S. Federal and State net operating loss carryforwards............... $ 20,426 $ 31,396 Argentina net operating loss carryforwards............................ - 10,682 U.S. Federal alternative minimum tax credit carryforward.............. 5,242 4,815 Argentina asset tax credit carryforward............................... - 1,739 Other temporary book/tax differences.................................. 4,101 5,433 ----------- ---------- 29,769 54,065 Valuation allowance................................................... - (5,677) ----------- ---------- 29,769 48,388 ----------- ---------- Deferred Tax Liabilities: Book/tax differences in property basis................................ 45,183 45,436 Other temporary book/tax differences.................................. 366 447 ----------- ---------- 45,549 45,883 ----------- ---------- Net deferred tax asset (liability)................................ $ (15,780) $ 2,505 =========== ==========
Earnings of the Company's foreign subsidiaries are subject to foreign income taxes. No U.S. deferred tax liability will be recognized related to the unremitted earnings of these foreign subsidiaries, as it is the Company's intention, generally, to reinvest such earnings permanently. As of December 31, 1999, the Company had an estimated U.S. Federal alternative minimum tax ("AMT") credit carryforward of approximately $5.2 million. The AMT credit carryforward does not expire and is available to offset U.S. Federal regular income taxes in future years, but only to the extent that U.S. Federal regular income taxes exceed the AMT in such years. As of December 31, 1999, the Company had an estimated net operating loss ("NOL") carryforward for U.S. Federal income tax purposes of $49.4 million. The U.S. Federal carryforward can be carried forward up to the year 2018 and can be used to offset future taxable income of the Company. The Company also has various state NOL carryforwards which have varying lengths of allowable carryforward periods ranging from 5 to 20 years and can be used to offset future state taxable income. As of December 31, 1999, the Company has fully utilized all NOL and asset tax credit carryforwards for Argentina income tax reporting purposes and thus reversed in 1999 the valuation allowance previously placed against its Argentina NOL carryforwards. 7. Significant Acquisitions On April 1, 1997, the Company acquired certain producing oil and gas properties and facilities located in the Gulf Coast area of Texas and Louisiana from subsidiaries of Burlington Resources Inc. for approximately $102.7 million in cash (the "Burlington Acquisition"). Funds for this acquisition were provided by advances under the Company's revolving credit facility. 62 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) If the Burlington Acquisition had been consummated as of January 1, 1997, the Company's unaudited pro forma revenues, net income and earnings per share for the year ended December 31, 1997, would have been as shown below; however, such pro forma information is not necessarily indicative of what actually would have occurred had the transaction occurred on such date. 1997 ----------- Revenues (in thousands)........... $431,306 Net income (in thousands)......... 57,565 Earnings per share: Basic.......................... 1.12 Diluted........................ 1.11 8. Segment Information The Company adopted Statement of Financial Accounting Standards No. 131, Disclosures About Segments of an Enterprise and Related Information, in 1998 which changes the way the Company reports information about its operating segments. The Company's reportable business segments have been identified based on the differences in products or services provided. Revenues for the exploration and production segment are derived from the production and sale of natural gas and crude oil. Revenues for the gathering segment arise from the transportation and sale of natural gas and crude oil. The gas marketing segment generates revenue by earning fees through the marketing of Company produced gas volumes and the purchase and resale of third party produced gas volumes. The Company evaluates the performance of its operating segments based on operating income. Operations in the gathering and gas marketing industries are in the United States. The Company operates in the oil and gas exploration and production industry in the United States, South America and in Yemen beginning in 1998. Summarized financial information for the Company's reportable segments is shown on the following page. 63 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Exploration and Production ------------------------------- Other Gas U.S. Argentina Foreign Gathering Marketing Corporate Total ---------- ----------- -------- --------- --------- --------- ---------- 1999 (in thousands) - -------------------------------------- Revenues from external customers................ $275,486 $138,411 $ 13,873 $ 6,955 $60,275 $ 1,735 $ 496,735 Intersegment revenues........................... - - - 1,350 1,285 - 2,635 Depreciation, depletion and amortization expense...................... 70,520 29,496 3,703 1,400 - 2,688 107,807 Impairment of oil and gas properties............ 3,306 - - - - - 3,306 Operating income (loss)......................... 112,902 77,033 665 402 2,725 (953) 192,774 Total assets.................................... 520,443 379,099 174,009 6,372 6,601 81,610 1,168,134 Capital investments............................. 51,571 131,551 54,362 680 - 1,989 240,153 Long-lived assets............................... 476,153 342,179 144,673 3,629 - 4,718 971,352 1998 (in thousands) - -------------------------------------- Revenues from external customers................ $195,060 $ 65,819 $ 5,782 $ 7,741 $54,108 $ 425 $ 328,935 Intersegment revenues........................... - - - 884 1,466 - 2,350 Depreciation, depletion and amortization expense...................... 75,479 26,610 2,968 1,693 - 2,225 108,975 Impairment of oil and gas properties............ 70,913 - - - - - 70,913 Operating income (loss)......................... (66,275) 12,282 (2,098) (210) 2,548 (1,800) (55,553) Total assets.................................... 569,560 256,525 113,956 7,500 8,735 57,899 1,014,175 Capital investments............................. 177,970 44,592 63,798 1,831 - 3,156 291,347 Long-lived assets............................... 536,885 245,831 100,441 4,350 - 10,735 898,242 1997 (in thousands) - -------------------------------------- Revenues from external customers................ $252,353 $ 93,864 $ 8,896 $18,063 $45,981 $(2,567) $ 416,590 Intersegment revenues........................... - - - 1,750 1,671 - 3,421 Depreciation, depletion and amortization expense...................... 66,798 23,333 3,419 1,360 - 1,397 96,307 Impairment of oil and gas properties............ 8,785 - - - - - 8,785 Operating income (loss)......................... 78,927 45,707 1,131 3,388 2,584 (5,582) 126,155 Total assets.................................... 567,279 237,544 50,887 8,564 12,427 38,693 915,394 Capital investments............................. 193,816 52,819 12,026 1,209 - 1,799 261,669 Long-lived assets............................... 527,321 227,774 42,933 4,190 - 4,669 806,887
Intersegment sales are priced in accordance with terms of existing contracts and current market conditions. Capital investments include expensed exploratory costs. Corporate general and administrative costs and interest costs are not allocated to segments. During 1997, sales to one crude oil purchaser of the exploration and production segment represented approximately 10 percent of the Company's total revenues (exclusive of eliminations of intersegment sales and the impact of hedges). The Company had no single purchaser to which sales of any segment in 1998 exceeded 10 percent of the Company's total revenues. During 1999, sales to two crude oil purchasers of the exploration and production segment represented approximately 14 percent and 11 percent, respectively, of the Company's normal operating revenues (exclusive of eliminations of intersegment sales and the impact of hedges). U.S. exploration and production revenues from external customers for 1999 include $55.0 million of net proceeds from sales of oil and gas properties. 64 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) 9. Detail of Prepaids and Other Current Assets
(In thousands) 1999 1998 --------- ---------- Property divestiture proceeds receivable................ $ 9,704 $ - Value added tax receivable.............................. - 2,750 U.S. Income tax refund receivable....................... - 5,323 Other prepaids and current assets....................... 9,405 10,239 --------- ---------- $ 19,109 $ 18,312 ========= ==========
10. Quarterly Results (Unaudited) The following is a summary of the quarterly results of operations for the years ended December 31, 1999 and 1998:
(In thousands, except per share amounts) Quarter Ended -------------------------------------------- Mar. 31 Jun. 30 Sept. 30 Dec. 31 ---------- --------- ---------- --------- 1999 ---- Revenues.................................. $ 66,004 $ 92,561 $ 136,429 $201,741 Operating income (loss)................... (6,372) 27,724 60,916 113,196 Net income (loss)......................... (18,121) 5,183 27,278 59,031 Earnings (loss) per share: Basic.................................. (.34) .10 .44 .95 Diluted................................ (.34) .09 .43 .92 1998 ---- Revenues.................................. $ 89,994 $ 84,932 $ 79,285 $ 74,724 Operating income (loss)................... 13,497 4,137 3,781 (74,744) Net income (loss)......................... (1,582) (9,508) (9,925) (66,650) Earnings (loss) per share: Basic.................................. (.03) (.18) (.19) (1.27) Diluted................................ (.03) (.18) (.19) (1.27)
Revenues and operating income for the quarter ended December 31, 1999, were increased by $47.3 million related to gains recognized on the sale of certain oil and gas properties. The impact of this item increased net income for the quarter ended December 31, 1999, by $28.9 million or 46 cents per basic share and 45 cents per diluted share. Operating income for the quarter ended December 31, 1998, was decreased by $70.9 million due to impairments of oil and gas properties resulting from declines in oil and gas prices during the fourth quarter. The impact of this item reduced net income for the quarter ended December 31, 1998, by $43.3 million or 83 cents per basic and diluted share. 65 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) 11. Supplementary Financial Information for Oil and Gas Producing Activities Results of Operations from Oil and Gas Producing Activities The following sets forth certain information with respect to the Company's results of operations from oil and gas producing activities for the years ended December 31, 1999, 1998 and 1997. The Company began operations in Ecuador in November 1998.
1999 ---------------------------------------------------- (In thousands) U.S. Argentina Bolivia Other Total -------- --------- ------- ------- -------- Revenues......................................... $220,495 $ 138,411 $ 4,519 $ 9,353 $372,778 Production (lifting) costs....................... 80,516 31,882 1,757 1,316 115,471 Exploration costs................................ 8,242 - 1,671 4,761 14,674 Impairment of proved properties.................. 3,306 - - - 3,306 Depreciation, depletion and amortization......... 70,520 29,496 2,380 1,323 103,719 -------- --------- ------- ------- -------- Results of operations before income taxes........ 57,911 77,033 (1,289) 1,953 135,608 Income tax expense (benefit)..................... 22,527 16,695 (438) (1,670) 37,114 -------- --------- ------- ------- -------- Results of operations (excluding corporate overhead and interest costs)................. $ 35,384 $ 60,338 $ (851) $ 3,623 $ 98,494 ======== ========= ======= ======= ========
1998 ---------------------------------------------------- (In thousands) U.S. Argentina Bolivia Other Total -------- --------- ------- ------- -------- Revenues......................................... $195,060 $ 65,819 $ 5,334 $ 448 $266,661 Production (lifting) costs....................... 94,332 26,737 1,424 233 122,726 Exploration costs................................ 20,610 191 2,255 1,000 24,056 Impairment of proved properties.................. 70,913 - - - 70,913 Depreciation, depletion and amortization......... 75,479 26,610 2,858 110 105,057 -------- --------- ------- ------- -------- Results of operations before income taxes........ (66,274) 12,281 (1,203) (895) (56,091) Income tax expense (benefit)..................... (25,781) 4,299 (423) (356) (22,261) -------- --------- ------- ------- -------- Results of operations (excluding corporate overhead and interest costs)................. $(40,493) $ 7,982 $ (780) $ (539) $(33,830) ======== ========= ======= ======= ========
66 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
1997 ----------------------------------------------------- (In thousands) U.S. Argentina Bolivia Other Total -------- --------- ------- ------- ---------- Revenues.......................................... $252,353 $ 93,864 $ 8,896 $ - $ 355,113 Production (lifting) costs........................ 89,069 24,129 1,148 - 114,346 Exploration costs................................. 8,774 695 130 3,068 12,667 Impairment of proved properties................... 8,785 - - - 8,785 Depreciation, depletion and amortization.......... 66,798 23,333 3,401 18 93,550 -------- --------- ------- ------- ---------- Results of operations before income taxes......... 78,927 45,707 4,217 (3,086) 125,765 Income tax expense (benefit)...................... 30,703 - 1,433 (1,193) 30,943 -------- --------- ------- ------- ---------- Results of operations (excluding corporate overhead and interest costs)............... $ 48,224 $ 45,707 $ 2,784 $(1,893) $ 94,822 ======== ========= ======= ======= ==========
Capitalized Costs and Costs Incurred Relating to Oil and Gas Producing Activities The Company's net investment in oil and gas properties at December 31, 1999 and 1998, was as follows:
1999 ----------------------------------------------------- (In thousands) U.S. Argentina Bolivia Other Total -------- --------- ------- ------- ---------- Unproved properties not being amortized........... $ 15,867 $ - $ - $ 7,504 $ 23,371 Proved properties being amortized................. 910,357 440,842 96,793 50,309 1,498,301 -------- --------- ------- ------- ---------- Total capitalized costs.................... 926,224 440,842 96,793 57,813 1,521,672 Less accumulated depreciation, depletion and amortization................. 455,158 98,663 8,501 1,433 563,755 -------- --------- ------- ------- ---------- Net capitalized costs...................... $471,066 $ 342,179 $88,292 $56,380 $ 957,917 ======== ========= ======= ======= ==========
1998 ----------------------------------------------------- (In thousands) U.S. Argentina Bolivia Other Total -------- --------- ------- ------- ---------- Unproved properties not being amortized........... $ 14,906 $ - $ - $ 4,784 $ 19,690 Proved properties being amortized................. 932,334 314,997 67,675 34,218 1,349,224 -------- --------- ------- ------- ---------- Total capitalized costs.................... 947,240 314,997 67,675 39,002 1,368,914 Less accumulated depreciation, depletion and amortization................. 410,355 69,166 6,126 110 485,757 -------- --------- ------- ------- ---------- Net capitalized costs...................... $536,885 $ 245,831 $61,549 $38,892 $ 883,157 ======== ========= ======= ======= ==========
67 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) The following sets forth certain information with respect to costs incurred (exclusive of general support facilities) in the Company's oil and gas activities during 1999, 1998 and 1997:
1999 ----------------------------------------------------- (In thousands) U.S. Argentina Bolivia Other Total -------- --------- ------- -------- --------- Acquisitions: Undeveloped properties........... $ 510 $ - $ - $ 600 $ 1,110 Producing properties............. 31,662 121,015 - 14,110 166,787 Exploratory........................... 10,316 - 27,834 6,882 45,032 Development........................... 9,083 10,536 2,955 1,981 24,555 -------- --------- ------- -------- --------- Total costs incurred............. $ 51,571 $131,551 $30,789 $ 23,573 $ 237,484 ======== ========= ======= ======== =========
1998 ----------------------------------------------------- (In thousands) U.S. Argentina Bolivia Other Total -------- --------- ------- -------- --------- Acquisitions: Undeveloped properties........... $ 6,460 $ - $ - $ 4,301 $ 10,761 Producing properties............. 70,805 - - 34,218 105,023 Exploratory........................... 49,952 1,416 10,324 1,000 62,692 Development........................... 50,753 43,176 13,949 6 107,884 -------- --------- ------- -------- --------- Total costs incurred............. $177,970 $ 44,592 $24,273 $ 39,525 $ 286,360 ======== ========= ======= ======== =========
1997 ----------------------------------------------------- (In thousands) U.S. Argentina Bolivia Other Total -------- --------- ------- -------- --------- Acquisitions: Undeveloped properties........... $ 7,138 $ - $ 560 $ 75 $ 7,773 Producing properties............. 133,548 - 6,201 - 139,749 Exploratory........................... 16,463 3,971 - 2,983 23,417 Development........................... 36,667 48,848 2,148 59 87,722 -------- --------- ------- -------- --------- Total costs incurred............. $193,816 $ 52,819 $8,909 $ 3,117 $ 258,661 ======== ========= ======= ======== =========
68 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Estimated Quantities of Proved Oil and Gas Reserves (Unaudited) 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. The following is an analysis of the Company's proved oil and gas reserves located in the United States, Argentina and Ecuador as estimated by the independent petroleum consultants of Netherland, Sewell & Associates, Inc. and in Bolivia as estimated by the independent petroleum consultants of DeGolyer and MacNaughton.
U.S. Argentina Bolivia Ecuador Total ------------------ ------------------- ------------------ -------------------- -------- Oil Gas Oil Gas Oil Gas Oil Oil Gas (MBbls) (MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) ------- -------- ------- -------- -------- -------- --------- --------- -------- Proved reserves at December 31, 1996............. 94,338 325,088 79,005 - 4,953 57,758 - 178,296 382,846 Revisions of previous estimates..................... (9,693) (18,045) 7,065 - 607 28,414 - (2,021) 10,369 Extensions, discoveries and other additions........... 345 29,451 1,211 - - - - 1,556 29,451 Production..................... (9,692) (36,623) (5,630) - (135) (6,068) - (15,457) (42,691) Purchase of reserves-in-place............. 24,653 62,253 - - 758 111,212 - 25,411 173,465 Sales of reserves-in-place..... (17) (1,277) - - - - - (17) (1,277) ------- -------- ------- -------- -------- -------- --------- --------- -------- Proved reserves at December 31, 1997............. 99,934 360,847 81,651 - 6,183 191,316 - 187,768 552,163 Revisions of previous estimates..................... (38,473) (11,252) (4,579) 12,024 (665) 101,624 2,546 (41,171) 102,396 Extensions, discoveries and other additions........... 306 28,345 4,091 - 2,968 121,419 - 7,365 149,764 Production..................... (9,912) (42,176) (6,322) - (122) (5,062) (78) (16,434) (47,238) Purchase of reserves-in-place............. 5,452 53,027 - - - - 21,577 27,029 53,027 Sales of reserves-in-place..... (100) (3,279) - - - - - (100) (3,279) ------- -------- ------- -------- -------- -------- --------- --------- -------- Proved reserves at December 31, 1998............. 57,207 385,512 74,841 12,024 8,364 409,297 24,045 164,457 806,833 Revisions of previous estimates..................... 52,684 32,505 24,496 25,222 (1,952) 21,129 1,709 76,937 78,856 Extensions, discoveries and other additions........... 110 1,844 - - 1,746 88,424 - 1,856 90,268 Production..................... (8,643) (39,150) (7,560) (4,682) (77) (4,522) (597) (16,877) (48,354) Purchase of reserves-in-place............. 10,343 14,947 44,694 81,072 - - 23,039 78,076 96,019 Sales of reserves-in-place..... (1,259) (34,633) - - - - - (1,259) (34,633) ------- -------- ------- -------- -------- -------- --------- --------- -------- Proved reserves at December 31, 1999............. 110,442 361,025 136,471 113,636 8,081 514,328 48,196 303,190 988,989 ======= ======== ======= ======== ======== ======== ========= ========= ======== Proved developed reserves at: December 31, 1997........... 79,494 316,306 47,806 - 1,502 140,124 - 128,802 456,430 ======= ======== ======= ======== ======== ======== ========= ========= ======== December 31, 1998........... 51,481 330,371 47,167 12,024 4,390 278,317 1,255 104,293 620,712 ======= ======== ======= ======== ======== ======== ========= ========= ======== December 31, 1999........... 94,722 302,444 90,125 92,696 6,414 415,743 5,524 196,785 810,883 ======= ======== ======= ======== ======== ======== ========= ========= ========
69 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) The Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves ("Standardized Measure") is a disclosure requirement under SFAS No. 69. The Standardized Measure does not purport to present the fair market value of proved oil and gas reserves. This would require consideration of expected future economic and operating conditions which are not taken into account in calculating the Standardized Measure. Under the Standardized Measure, future cash inflows were estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production, development and abandonment costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the Company's tax basis in the associated proved oil and gas properties. Tax credits and permanent differences were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10 percent annual discount rate to arrive at the Standardized Measure. Set forth below is the Standardized Measure relating to proved oil and gas reserves at December 31, 1999 and 1998:
1999 ---------------------------------------------------------------- (In thousands) U.S. Argentina Bolivia Ecuador Total ---------- ----------- --------- ----------- ----------- Future cash inflows...................... $3,287,165 $ 3,326,461 $ 713,314 $ 1,012,113 $ 8,339,053 Future production costs.................. 1,265,432 947,564 51,564 235,312 2,499,872 Future development and abandonment costs..................... 188,019 195,729 47,050 140,423 571,221 ---------- ----------- --------- ----------- ----------- Future net cash inflows before income tax expense.................... 1,833,714 2,183,168 614,700 636,378 5,267,960 Future income tax expense................ 538,602 654,633 189,054 204,990 1,587,279 ---------- ----------- --------- ----------- ----------- Future net cash flows.................... 1,295,112 1,528,535 425,646 431,388 3,680,681 10 percent annual discount for estimated timing of cash flows........ 475,281 583,187 222,991 151,985 1,433,444 ---------- ----------- --------- ----------- ----------- Standardized Measure of discounted future net cash flows................. $ 819,831 $ 945,348 $ 202,655 $ 279,403 $ 2,247,237 ========== =========== ========= =========== ===========
70 VINTAGE PETROLEUM, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
1998 ----------------------------------------------------- (In thousands) U.S. Argentina Bolivia Ecuador Total ---------- --------- -------- -------- ---------- Future cash inflows.......................................... $1,314,729 $ 638,317 $439,241 $145,230 $2,537,517 Future production costs...................................... 570,034 311,989 41,582 44,758 968,363 Future development and abandonment costs..................... 129,903 125,204 48,613 49,087 352,807 ---------- --------- -------- -------- ---------- Future net cash inflows before income tax expense........................................ 614,792 201,124 349,046 51,385 1,216,347 Future income tax expense.................................... 42,539 - 107,025 6,008 155,572 ---------- --------- -------- -------- ---------- Future net cash flows........................................ 572,253 201,124 242,021 45,377 1,060,775 10 percent annual discount for estimated timing of cash flows............................ 188,044 74,049 130,825 19,635 412,553 ---------- --------- -------- -------- ---------- Standardized Measure of discounted future net cash flows..................................... $ 384,209 $ 127,075 $111,196 $ 25,742 $ 648,222 ========== ========= ======== ======== ==========
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) The following is an analysis of the changes in the Standardized Measure during 1999, 1998 and 1997:
(In thousands) 1999 1998 1997 ---------- ---------- ---------- Standardized Measure - beginning of year.............................. $ 648,222 $1,016,645 $1,392,841 Increases (decreases) - Sales, net of production costs..................................... (255,260) (145,709) (240,767) Net change in sales prices, net of production costs................ 1,218,764 (505,314) (824,264) Discoveries and extensions, net of related future development and production costs............................ 62,427 98,521 56,334 Changes in estimated future development costs...................... (52,195) (17,025) (89,637) Development costs incurred......................................... 21,472 98,434 77,127 Revisions of previous quantity estimates........................... 732,703 (124,097) 3,508 Accretion of discount.............................................. 70,357 122,256 180,714 Net change in income taxes......................................... (687,057) 150,582 215,131 Purchase of reserves-in-place...................................... 496,237 110,389 240,658 Sales of reserves-in-place......................................... (54,135) (1,493) (2,518) Timing of production of reserves and other......................... 45,702 (154,967) 7,518 ---------- ---------- ---------- Standardized Measure - end of year.................................... $2,247,237 $ 648,222 $1,016,645 ========== ========== ==========
71 INDEX TO EXHIBITS The following documents are included as exhibits to this Form 10-K. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, such exhibit is filed herewith. Exhibit Number Description ------ ----------- 3.1 Restated Certificate of Incorporation, as amended, of the Company (Filed as Exhibit 3.2 to the Company's report on Form 10-Q for the quarter ended June 30, 1997, filed August 13, 1997). 3.2 Restated By-laws of the Company (Filed as Exhibit 3.2 to the Company's Registration Statement on Form S-1, Registration No. 33-35289 (the "S- 1 Registration Statement")). 4.1 Form of stock certificate for Common Stock, par value $.005 per share (Filed as Exhibit 4.1 to the S-1 Registration Statement). 4.2 Indenture dated as of December 20, 1995, between The Chase Manhattan Bank (formerly Chemical Bank), as Trustee, and the Company (Filed as Exhibit 99.1 to the Company's report on Form 8-K filed January 16, 1996). 4.3 Indenture dated as of February 5, 1997, between The Chase Manhattan Bank, as Trustee, and the Company (Filed as Exhibit 4.3 to the Company's report on Form 10-K for the year ended December 31, 1996, filed March 27, 1997). 4.4 Indenture dated as of January 26, 1999, between The Chase Manhattan Bank, as Trustee, and the Company (Filed as Exhibit 4.4 to the Company's report on Form 10-K for the year ended December 31, 1998, filed March 12, 1999 (the "1998 Form 10-K")). 4.5 Rights Agreement, dated March 16, 1999, between the Company and ChaseMellon Shareholder Services, L.L.C., as Rights Agent (Filed as Exhibit 4.1 to the Company's Registration Statement on Form 8-A, filed March 22, 1999). 4.6 Certificate of Designation of Series A Junior Participating Preferred Stock of the Company (Filed as Exhibit 3.3 to the Company's Registration Statement on Form S-3, Registration No. 333-77619). 10.1* Employment and Noncompetition Agreement dated January 7, 1987, between the Company and Charles C. Stephenson, Jr. (Filed as Exhibit 10.19 to the S-1 Registration Statement). 10.2* Form of Indemnification Agreement between the Company and certain of its officers and directors (Filed as Exhibit 10.23 to the S-1 Registration Statement). 10.3* Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 4(d) to the Company's Registration Statement on Form S-8, Registration No. 33- 37505). 10.4* Amendment No. 1 to Vintage Petroleum, Inc. 1990 Stock Plan, effective January 1, 1991 (Filed as Exhibit 10.15 to the Company's report on Form 10-K for the year ended December 31, 1991, filed March 30, 1992). 10.5* Amendment No. 2 to Vintage Petroleum, Inc. 1990 Stock Plan dated February 24, 1994 (Filed as Exhibit 10.15 to the Company's report on Form 10-K for the year ended December 31, 1993, filed March 29, 1994). 10.6* Amendment No. 3 to Vintage Petroleum, Inc. 1990 Stock Plan dated March 15, 1996 (Filed as Exhibit A to the Company's Proxy Statement for Annual Meeting of Stockholders dated April 1, 1996). 10.7* Amendment No. 4 to Vintage Petroleum, Inc. 1990 Stock Plan dated March 11, 1998 (Filed as Exhibit A to the Company's Proxy Statement for Annual Meeting of Stockholders dated March 31, 1998). 10.8* Amendment No. 5 to Vintage Petroleum, Inc. 1990 Stock Plan dated March 16, 1999 (Filed as Exhibit A to the Company's Proxy Statement for Annual Meeting of Stockholders dated March 31, 1999). 10.9* Vintage Petroleum, Inc. 401(k) Plan (Filed as Exhibit 4(c) to the Company's Registration Statement on Form S-8, Registration No. 33- 55706). 10.10* Vintage Petroleum, Inc. Non-Management Director Stock Option Plan (Filed as Exhibit 10.18 to the Company's report on Form 10-K for the year ended December 31, 1992, filed March 31, 1993 (the "1992 Form 10- K")). 10.11* Form of Incentive Stock Option Agreement under the Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.20 to the Company's report on Form 10-K for the year ended December 31, 1990, filed April 1, 1991). 10.12* Form of Non-Qualified Stock Option Agreement under the Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.20 to the 1992 Form 10-K). 10.13* Form of Non-Qualified Stock Option Agreement for non-employee directors under the Vintage Petroleum, Inc. 1990 Stock Plan. 10.14 Amended and Restated Credit Agreement dated as of October 21, 1998, among the Company, as borrower, and certain commercial lending institutions, as lenders, Bank of Montreal, as administrative agent, NationsBank, N.A., as syndication agent, and Societe Generale Southwest Agency, as documentation agent (Filed as Exhibit 10 to the Company's report on Form 10-Q for the quarter ended September 30, 1998, filed November 13, 1998). 10.15 First Amendment to the Amended and Restated Credit Agreement dated as of December 10, 1998, among the Company, as borrower, and certain commercial lending institutions, as lenders, Bank of Montreal, as administrative agent, Nations Bank, N.A., as syndication agent, and Societe Generale Southwest Agency, as documentation agent (Filed as Exhibit 10.14 to the 1998 Form 10-K). 10.16 Second Amendment to the Amended and Restated Credit Agreement dated as of May 19, 1999, among the Company, as borrower, and certain commercial lending institutions, as lenders, Bank of Montreal, as administrative agent, NationsBank, N.A., as syndication agent, and Societe Generale Southwest Agency, as documentation agent (Filed as Exhibit 10.1 to the Company's report on Form 10-Q for the quarter ended June 30, 1999, filed August 12, 1999). 10.17 Third Amendment to the Amended and Restated Credit Agreement dated as of November 18, 1999, among the Company, as borrower, and certain commercial lending institutions, as lenders, Bank of Montreal, as administrative agent, Bank of America, N.A., successor-in-interest by merger to NationsBank, N.A., as syndication agent, and Societe Generale Southwest Agency, as documentation agent. 21. Subsidiaries of the Company. 23.1 Consent of Arthur Andersen LLP. 23.2 Consent of Netherland, Sewell & Associates, Inc. 23.3 Consent of DeGolyer and MacNaughton. 27. Financial Data Schedule. ____________________ * Management contract or compensatory plan or arrangement. EX-10.13 2 NON-QUALIFIED STOCK OPTION AGREEMENT Exhibit 10.13 NON-QUALIFIED STOCK OPTION AGREEMENT ------------------------------------ THIS NON-QUALIFIED STOCK OPTION AGREEMENT (this "Agreement") is made and entered into effective as of the ____ day of _________, _____ ("Effective Date") by and between VINTAGE PETROLEUM, INC. (the "Company"), a Delaware corporation, and __________________ ("Participant"). W I T N E S S E T H: -------------------- WHEREAS, the Board of Directors of the Company (the "Board") has adopted the Vintage Petroleum, Inc. 1990 Stock Plan (as amended, the "Plan"); and WHEREAS, effective May 11, 1999, the Plan allows non-employee directors of the Company to be eligible to receive awards under the Plan; and WHEREAS, Participant is a non-employee director of the Company and the Board desires to grant to Participant a non-qualified stock option under the Plan; NOW THEREFORE, in consideration of the premises and the covenants and agreements herein contained, the parties hereto agree: 1. GRANT OF OPTION. The Company hereby grants to Participant the right --------------- and option to purchase from the Company, during the periods and on the terms and conditions hereinafter set forth, an aggregate of ______ shares of its common stock, par value $.005 per share ("Share" or "Shares"), at a price of $_______ per share, being the Fair Market Value (as defined in the Plan) of a Share on the Effective Date (hereinafter, the "Option"). 2. EXERCISE PERIOD. Subject to the terms of this Agreement, the Option --------------- may be exercised, in whole or in part, from time to time after the date hereof, subject to the following limitations: (a) The Option may not be exercised during the first year following the date hereof. On or after the first anniversary of the date hereof (i.e., _____________), the Option may be exercised for all of the total Shares covered by the Option. (b) Notwithstanding the limitations of Section 2(a) above, the Option shall become fully exercisable for the total number of Shares covered by the Option upon the Retirement (as hereinafter defined) from the Board of the Participant if such retirement occurs after the six-month anniversary of the date hereof. For these purposes, "Retirement" means the Participant's retirement from the Board at the end of any full term to which such Participant was elected, retirement from the Board at any time at or after age 70, or retirement at any time with the consent of the Board. Notwithstanding the above exercise period, the Option may become fully exercisable immediately under certain other circumstances set forth in the Plan. (c) Subject to the limitations of Section 2(a) above, the Option (or any unexercised portion thereof) may not be exercised: (i) more than six months after termination of the Participant's service as a member of the Board for any reason other than death or Retirement (and then only to the extent that the Participant could have exercised such option on the date service terminated in accordance with Section 2(a) above); (ii) more than twelve months after the Participant's Retirement from the Board; or (iii) more than twelve months after death of the Participant, if death occurs while serving as a member of the Board or during the six- month period referred to in subparagraph (i) hereof or the twelve- month period referred to in subparagraph (ii) hereof (and then only to the extent that the Participant could have exercised such option on the date of death in accordance with Section 2(a) or Section 2(b) above, as the case may be); provided, however, that the Option may not be exercised after ________, _____. The Option, to the extent not exercised during such period, as the case may be, shall terminate upon the expiration of such period. 3. EXERCISE OF OPTION. At the time of exercise, Participant shall ------------------ deliver to the Company a written notice duly signed by Participant stating the number of Shares as to which the Option is being exercised at that time, together with payment (a) in cash (or certified or bank cashier's check payable to the order of the Company), (b) by delivery of shares of common stock of the Company then owned by Participant (such shares being valued at their fair market value at the time of such exercise), or (c) by a combination of such methods, for the full exercise price of said Shares, plus any applicable withholding tax thereon, whereupon certificates therefor will be issued to Participant. The minimum number of Shares which may be purchased at any time by exercise of the Option is 1,000 Shares unless the number purchased is the total number purchasable under the Option at that time. 4. THE PLAN AND AMENDMENTS. This Agreement shall be subject to the terms ----------------------- and conditions of the Plan as presently constituted and as may be amended hereafter from time to time, including the discretion therein provided to the committee of the Board which administers the Plan. Except as may be otherwise provided by the Plan, amendments to the Plan shall constitute amendments to this Agreement and shall be incorporated herein without the execution of any amendment or supplement hereto by the parties. The parties further agree to any amendment of this Agreement, without the execution of any amendment or supplement, upon notice from the Company to Participant that the terms and conditions of this Agreement shall be amended to conform to any formal guidelines published by the Secretary of the Treasury or his delegate prescribing the requirements for non-qualified stock options. -2- 5. STOCKHOLDER RIGHTS PRIOR TO EXERCISE OF OPTIONS. Neither Participant ----------------------------------------------- nor any of Participant's beneficiaries shall be deemed to have any rights as a stockholder of the Company with respect to any Shares covered by the Option until the date of the issuance by the Company of a certificate to Participant for such Shares. 6. TRANSFER TAXES. The Company shall at all times during the term of the -------------- Option reserve and keep available such number of Shares as will be sufficient to satisfy the requirements of this Agreement, and shall pay all original issue and transfer taxes with respect to the issue and transfer of such Shares pursuant hereto and all other fees and expenses necessarily incurred by the Company in connection therewith. 7. INVESTMENT REPRESENTATION. Participant (or Participant's guardian or ------------------------- legal representative or Participant's successor in the event of death) represents and agrees that if Participant exercises the Option, in whole or in part, at a time when there is not in effect under the Securities Act of 1933, as amended, a registration statement relating to the Shares issuable upon exercise hereof and available for delivery a prospectus meeting the requirements of Section 10 of said Act, Participant will acquire such Shares upon such exercise for the purpose of investment and not with a view to their resale or distribution and that upon each such exercise of the Option Participant will furnish to the Company a written statement to such effect, satisfactory to the Company in form and substance. Such written agreement shall also state that such Shares shall not be transferred except pursuant to an effective registration statement under said Act or in accordance with an exemption from registration thereunder. The certificates issued for all Shares issued hereunder shall contain the following legend if a registration statement relating to the Shares issuable upon exercise hereof is not in effect at the time of exercise of the Option: The securities evidenced by this certificate have not been registered under the Securities Act of 1933 or any applicable state securities laws. The securities have been acquired for investment and may not be sold or transferred for value in the absence of an effective registration of them under the Securities Act of 1933 and any applicable state securities laws, or receipt by the Company of an opinion of counsel or other evidence acceptable to the Company that such registration is not required under such acts. 8. PAYMENT OF WITHHOLDING TAX. Upon exercise by Participant of the --------------------------- Option, the Company shall have the right to deduct from any cash amounts otherwise payable to Participant any amounts required to satisfy all tax withholding requirements imposed upon such exercise under applicable federal, state, local or other laws. Alternatively, to satisfy any such withholding requirements, the Company may, at the request of Participant, but shall not be required to, withhold from the number of Shares to be issued that number of Shares (based on the fair market value of the Shares at the time of such exercise) necessary to satisfy such tax withholding requirements. -3- 9. NOTICES. All notices to the Company pursuant to this Agreement must ------- be in writing and delivered by hand or by mail, addressed to Vintage Petroleum, Inc., 4200 One Williams Center, Tulsa, Oklahoma 74172, Attention: Charles C. Stephenson, Jr. Notices shall become effective upon their receipt by the Company delivered as aforesaid. 10. GOVERNING LAW. This Agreement shall be governed by and construed in ------------- accordance with the laws of the State of Delaware (without regard to the conflicts of rules thereof). IN WITNESS WHEREOF, the parties have executed this Agreement effective as of the day and year first above written. VINTAGE PETROLEUM, INC. By:_______________________________ Name:__________________________ Title:_________________________ PARTICIPANT: __________________________________ -4- EX-10.17 3 AMENDED AND RESTATED CREDIT AGREEMENT Exhibit 10.17 THIRD AMENDMENT TO THE AMENDED AND RESTATED CREDIT AGREEMENT dated as of November 18, 1999 among Vintage Petroleum, Inc., as the Borrower, and CERTAIN COMMERCIAL LENDING INSTITUTIONS, as the Lenders, BANK OF MONTREAL, acting through certain U.S. branches or agencies, as administrative agent, BANK OF AMERICA, N.A., successor-in-interest by merger to Nationsbank, N.A. as syndication agent, and SOCIETE GENERALE, SOUTHWEST AGENCY, as documentation agent. Bank of Montreal as Arranger THIRD AMENDMENT TO THE AMENDED AND RESTATED CREDIT AGREEMENT ------------------------------------------------------------ THIS THIRD AMENDMENT TO THE AMENDED AND RESTATED CREDIT AGREEMENT, dated as of November 18, 1999 (the "Third Amendment"), among VINTAGE PETROLEUM, INC., a --------------- Delaware corporation (the "Borrower"), the various financial institutions as are -------- or may become parties hereto (collectively, the "Lenders"), BANK OF AMERICA, ------- N.A., successor-in-interest by merger to Nationsbank, N.A., as syndication agent, SOCIETE GENERALE, SOUTHWEST AGENCY, as documentation agent, and BANK OF MONTREAL, acting through certain of its U.S. branches or agencies ("Bank of ------- Montreal"), as administrative agent (the "Agent") for the Lenders. - -------- ----- W I T N E S S E T H: - - - - - - - - - - WHEREAS, the Borrower, the Agent and each of the Lenders have heretofore entered into that certain Amended and Restated Credit Agreement, dated as of October 21, 1998 which has been amended by that certain First Amendment to the Amended and Restated Credit Agreement, dated as of December 10, 1998, and by that certain Second Amendment to the Amended and Restated Credit Agreement, dated as of May 19, 1999 (as so amended the "Credit Agreement"); and WHEREAS, the Borrower, the Agent and the Lenders now intend to amend the Credit Agreement in certain respects. NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein contained, each of the Borrower, the Agent and the Lenders agree as follows: SECTION 1. Defined Terms. Terms defined in the Credit Agreement are used -------------- in this Third Amendment with the same meaning, unless otherwise indicated. SECTION 2. Amendments to Credit Agreement. ------------------------------ A. The Credit Agreement is amended by replacing Exhibit F and Exhibit I to the Credit Agreement with the Exhibit F and Exhibit I, respectively, attached to this Third Amendment. B. Each reference in the Credit Agreement to the Notes shall be deemed to include a reference to the Replacement Notes (as defined in Section 5(ii) hereof). C. The following definition of "Bolivian Letter of Credit Percentage"shall be inserted in its alphabetically appropriate place in Section 1.1 of the Credit Agreement: "Bolivian Letter of Credit Percentage" means, relative to any Lender, ------------------------------------ the percentage set forth opposite the name of such Lender in Column 3 of Exhibit F to this Agreement as such percentage may be adjusted from time to --------- time pursuant to Lender -1- Assignment Agreements executed by a Lender and its Assignee Lenders and delivered pursuant to Section 10.11 or as a result of an increase of the ------------- Maximum Commitment Amount as provided in Section 2.1.6." ------------- D. The definition of "Maximum Commitment Amount" and "Percentage" appearing in ---------- Section 1.1 of the Credit Agreement shall each be amended and restated in their entirety to read as follows: ""Maximum Commitment Amount" means an amount equal to $535,000,000 as ------------------------- such amount may be increased pursuant to Section 2.1.6." ------------- ""Percentage" means, relative to any Lender, the percentage set forth ---------- opposite the name of such Lender in Column 1 of Exhibit F to this Agreement --------- as such percentage may be adjusted from time to time pursuant to Lender Assignment Agreements executed by a Lender and its Assignee Lenders and delivered pursuant to Section 10.11 or as a result of an increase of the ------------- Maximum Commitment Amount as provided in Section 2.1.6." ------------- E. Section 2.1.4 of the Credit Agreement is hereby amended and restated in its ------------- entirety to read as follows: "SECTION 2.1.4 Bolivian Letter of Credit. Issuer has issued and each ------------------------- Lender possesses a participation in, to the extent of each Lender's Bolivian Letter of Credit Percentage, the Bolivian Letter of Credit, in accordance with the terms of Section 2.8." ----------- F. Clause (iii) of Section 2.1.6 of the Credit Agreement is hereby amended and restated in its entirety to read as follows: " (iii) the identity of the then Lenders, if any, which have agreed with the Borrower to increase their respective Commitments in an amount such that their respective Percentages and Bolivian Letter of Credit Percentages, after giving effect to such requested increase, will be the same or greater than their respective Percentages and Bolivian Letter of Credit Percentages, respectively, prior to giving effect to such requested increase (each such then Lender being a then "Increasing Lender"), each other Lender which has agreed to increase its Commitment in an amount such that its respective Percentage and Bolivian Letter of Credit Percentage after giving effect to such a requested increase will be less than its respective Percentage or Bolivian Letter of Credit Percentage, respectively, prior to giving effect to such requested increase (each such Lender being a "Partially Increasing Lender") and the identity of each financial institution not already a Lender, if any, which has agreed with the Borrower to become a Lender to effect such requested increase in the Maximum Commitment Amount (each such assignee shall be reasonably acceptable to the Agent and the Issuer and each such assignee being a then "New Lender" and each Lender which has not agreed to increase its Commitment being a "Reducing Lender"), provided that in no case shall the -------- ---- dollar amount or the Percentage of a Lender's share of the -2- Maximum Commitment Amount or Bolivian Letter of Credit Percentage of the Bolivian Letter of Credit be increased without the express written consent of such Lender; and" G. Section 2.1.6 of the Credit Agreement is hereby further amended by inserting in the final paragraph of such Section the phrase "or Bolivian Letter of Credit Percentage, as appropriate," after the words "respective Lender's Percentages" in the penultimate line of such paragraph. H. Section 2.2.4 of the Credit Agreement is hereby amended and restated in its entirety to read as follows: "SECTION 2.2.4 Mandatory as to Bolivian Letter of Credit. ----------------------------------------- (a) Each Lender's participation in, and its rights and obligations with respect to, the Bolivian Letter of Credit shall be automatically terminated on January 15, 2001. (b) Each reduction in the Stated Amount of the Bolivian Letter of Credit shall be made ratably among the Lenders in accordance with their respective Bolivian Letter of Credit Percentages." I. Section 2.8.4 of the Credit Agreement is hereby amended and restated in its entirety to read as follows: "SECTION 2.8.4 Other Lender's Participations. ----------------------------- SECTION 2.8.4 Other Lenders' Participation. Each Revolving Loan ---------------------------- Letter of Credit issued pursuant to Section 2.8.2 shall, effective upon its ------------- issuance and without further action, be issued on behalf of all Lenders (including the Issuer thereof) pro rata according to their respective Percentages. Each Lender shall, to the extent of its Percentage, be deemed irrevocably to have participated in the issuance of any such Revolving Loan Letter of Credit and is hereby deemed to have participated to the extent of its Bolivian Letter of Credit Percentage (effective the date hereof) in the issuance of the Bolivian Letter of Credit and shall be responsible to reimburse promptly the Issuer thereof for Reimbursement Obligations which have not been reimbursed by the Borrower in accordance with Section 2.8.5, ------------- or which have been reimbursed by the Borrower but must be returned, restored or disgorged by such Issuer for any reason, and each Lender shall, to the extent of its Percentage or Bolivian Letter of Credit Percentage, as applicable, be entitled to receive from the Agent a ratable portion of the letter of credit fees received by the Agent pursuant to Section 3.3.3, with ------------- respect to each Letter of Credit. In the event that the Borrower shall fail to reimburse any Issuer, or if for any reason Revolving Loans shall not be made to fund any Reimbursement Obligation, all as provided in Section 2.8.5 ------------- and in an amount equal to the amount of any drawing honored by such Issuer under a Letter of Credit issued by it (including without limitation, the Bolivian Letter of Credit), or in the event such Issuer must for any reason return or disgorge such reimbursement, -3- such Issuer shall promptly notify each Lender of the unreimbursed amount of such drawing and of such Lender's respective participation therein calculated on the basis of its Percentage or its Bolivian Letter of Credit Percentage, as applicable. Each Lender shall make available to such Issuer, whether or not any Default shall have occurred and be continuing, an amount equal to its respective participation, calculated on the basis of its Percentage or its Bolivian Letter of Credit Percentage, as applicable, in same day or immediately available funds at the office of such Issuer specified in such notice if the Issuer shall notify the Agent on or before 11:30 a.m. (U.S. Central time) of any Business Day by the close of business on such Business Day or if the Issuer shall notify the Agent after 11:30 a.m. (U.S. Central time) of any Business Day not later than 11:30 a.m. (U.S. Central time) on the Business Day (under the laws of the jurisdiction of such Issuer) after the date notified by such Issuer. In the event that any Lender fails to make available to such Issuer the amount of such Lender's participation in such Letter of Credit as provided herein, such Issuer shall be entitled to recover such amount on demand from such Lender together with interest at the daily average Federal Funds Rate for three Business Days (together with such other compensatory amounts as may be required to be paid by such Lender to the Agent pursuant to the Rules for Interbank Compensation of the council on International Banking or the Clearinghouse Compensation Committee, as the case may be, as in effect from time to time) and thereafter at the LIBO Rate plus the Applicable Margin. Nothing in this Section 2.8.4 shall be deemed to prejudice the right of any ------------- Lender to recover from any Issuer any amounts made available by such Lender to such Issuer pursuant to this Section 2.8.4 in the event that it is ------------- determined by a court of competent jurisdiction that the payment with respect to a Letter of Credit by such Issuer in respect of which payment was made by such Lender constituted gross negligence or wilful misconduct on the part of such Issuer. Each Issuer shall distribute to each other Lender which has paid all amounts payable by it under this Section 2.8.4 ------------- with respect to any Letter of Credit issued by such Issuer such other Lender's Percentage or Bolivian Letter of Credit Percentage, as applicable, of all payments received by such Issuer from the Borrower in reimbursement of drawings honored by such Issuer under such Letter of Credit when such payments are received." J. Section 2.8.5 of the Credit Agreement is hereby amended by inserting the word "(in accordance with each Lender's Percentage without regard to whether the underlying Disbursement arises with respect to a Revolving Loan Letter of Credit or the Bolivian Letter of Credit)" after the "Revolving Loans" in the fourth sentence thereof. K. Section 4.8 of the Credit Agreement is hereby amended and restated in its entirety to read as follows: "SECTION 4.8 Sharing of Payments. If any Lender shall obtain any payment ------------------- or other recovery (whether voluntary, involuntary, by application of setoff or otherwise) on account of any Loan or participation in a Letter of Credit (other than pursuant to the terms of Sections 4.3, 4.4 and 4.5) in excess ------------ --- --- of its pro rata share (calculated by reference to such --- ---- -4- Lender's Percentage or Bolivian Letter of Credit Percentage, as applicable) of payments then or therewith obtained by all Lenders, such Lender shall purchase from the other Lenders such participations in Loans made by them and participations in Letters of Credit held by them as shall be necessary to cause such purchasing Lender to share the excess payment or other recovery ratably (calculated by reference to such Lender's Percentage or Bolivian Letter of Credit Percentage, as applicable) with each of them; provided, however, that if all or any portion of the excess payment or -------- ------- other recovery is thereafter recovered from such purchasing Lender, the purchase shall be rescinded and each Lender which has sold a participation to the purchasing Lender shall repay to the purchasing Lender the purchase price to the ratable extent of such recovery (calculated by reference to such Lender's Percentage or Bolivian Letter of Credit Percentage, as applicable) together with an amount equal to such selling Lender's ratable share (according to the proportion of (1) the amount of such selling Lender's required repayment to the purchasing Lender to (2) the total -- amount so recovered from the purchasing Lender) of any interest or other amount paid or payable by the purchasing Lender in respect of the total amount so recovered. The Borrower agrees that any Lender so purchasing a participation from another Lender pursuant to this Section 4.8 may, to the ----------- fullest extent permitted by law, exercise all its rights of payment (including pursuant to Section 4.9) with respect to such participation as ----------- fully as if such Lender were the direct creditor of the Borrower in the amount of such participation. If under any applicable bankruptcy, insolvency or other similar law, any Lender receives a secured claim in lieu of a setoff to which this Section 4.8 applies, such Lender shall, to ----------- the extent practicable, exercise its rights in respect of such secured claim in a manner consistent with the rights of the Lenders entitled under this Section 4.8 to share in the benefits of any recovery on such secured ----------- claim." L. Section 9.2 of the Credit Agreement is hereby amended by replacing the word "Percentage" therein with the words and punctuation "Percentage or Bolivian Letter of Credit Percentage, as applicable,". M. Section 10.11.1 of the Credit Agreement is hereby amended by inserting the words and punctuation ", except with the prior written consent of the Agent," after the words "(which assignment and delegation shall be" in the full paragraph appearing between clauses (b) and (c) of such Section. N. Section 10.13 of the Credit Agreement is hereby amended by inserting the words "and Bolivian Letter of Credit Percentages, as applicable" after the word "Percentages" but before the period in the last sentence of such Section. SECTION 3. Borrowing Base. The Borrower, the Agent and the Lenders -------------- hereby agree that the amount of the Borrowing Base shall be as set forth in a letter agreement between the Borrower and the Agent dated November 8, 1999. -5- SECTION 4. Reaffirmation of Credit Agreement. This Third Amendment shall --------------------------------- be deemed to be an amendment to the Credit Agreement, and the Credit Agreement, as amended hereby, is hereby ratified, approved and confirmed in each and every respect. All references to the Credit Agreement in any other document, instrument, agreement or writing shall hereafter be deemed to refer to the Credit Agreement as amended hereby. SECTION 5. Effectiveness. This Third Amendment shall become effective as ------------- of November 18, 1999, upon satisfaction of the following conditions: (i) the Agent shall have received counterparts hereof duly executed by Borrower, each Lender, each holder of a Note and the Agent (or, in the case of any party as to which an executed counterpart shall not have been received, facsimile, telegraphic, telex or other written confirmation from such party of execution of a counterpart hereof by such party); and, (ii) the Borrower shall have delivered to each Lender a promissory note in the form of Exhibit A to the Credit Agreement payable to the order of such Lender in a maximum principal amount equal to such Lender's Percentage, as amended hereby, of the Maximum Commitment Amount, as amended hereby, which promissory note shall be in exchange for, but not in payment of, those Notes held by each such Lender prior to the effectiveness of this Third Amendment (each promissory note delivered pursuant to this Section 5(ii) a "Replacement Note"). SECTION 6. Severability. Any provision of this Third Amendment, the Credit ------------ Agreement as amended by this Third Amendment or any other Loan Document which is prohibited or unenforceable in any jurisdiction shall, as to such provision and such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions of this Third Amendment, the Credit Agreement as amended by this Third Amendment or such Loan Document or affecting the validity or enforceability of such provision in any other jurisdiction. SECTION 7. Headings. The various headings of this Third Amendment are -------- inserted for convenience only and shall not affect the meaning or interpretation of this Third Amendment or any provisions hereof. SECTION 8. Execution in Counterparts, Effectiveness, etc. This Third --------------------------------------------- Amendment may be executed by the parties hereto in several counterparts, each of which shall be executed by the different parties on different counterparts and be deemed to be an original and all of which shall constitute together but one and the same Third Amendment. SECTION 9. Governing Law; Entire Agreement. THIS THIRD AMENDMENT SHALL ------------------------------- BE DEEMED TO BE A CONTRACT MADE UNDER AND GOVERNED BY THE INTERNAL LAWS OF THE STATE OF ILLINOIS. This Third Amendment constitutes the -6- entire understanding among the parties hereto with respect to the subject matter hereof and supersedes any prior agreements, written or oral, with respect thereto. THIS WRITTEN THIRD AMENDMENT REPRESENTS THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES. SECTION 10. Successors and Assigns. This Third Amendment shall be binding ---------------------- upon and shall inure to the benefit of the parties hereto and their respective successors and assigns; provided, however, that (i) the Borrower may not assign -------- ------- or transfer its rights or obligations hereunder without the prior written consent of the Agent and all Lenders; and (ii) the rights of sale, assignment and transfer of the Lenders are subject to Section 10.11 of the Credit ------------- Agreement. SECTION 11. Forum Selection and Consent to Jurisdiction. ANY LITIGATION ------------------------------------------- BASED HEREON, OR ARISING OUT OF, UNDER, OR IN CONNECTION WITH, THIS THIRD AMENDMENT, THE CREDIT AGREEMENT AS AMENDED BY THIS THIRD AMENDMENT OR ANY OTHER LOAN DOCUMENT, OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN) OR ACTIONS OF THE AGENT, THE LENDERS OR THE BORROWER MAY BE BROUGHT AND MAINTAINED IN THE COURTS OF THE STATE OF ILLINOIS OR IN THE UNITED STATES DISTRICT COURT FOR THE NORTHERN DISTRICT OF ILLINOIS. THE BORROWER HEREBY EXPRESSLY AND IRREVOCABLY SUBMITS TO THE JURISDICTION OF THE COURTS OF THE STATE OF ILLINOIS AND OF THE UNITED STATES DISTRICT COURT FOR THE NORTHERN DISTRICT OF ILLINOIS FOR THE PURPOSE OF ANY SUCH LITIGATION AS SET FORTH ABOVE AND IRREVOCABLY AGREES TO BE BOUND BY ANY JUDGMENT RENDERED THEREBY IN CONNECTION WITH SUCH LITIGATION. THE BORROWER FURTHER IRREVOCABLY CONSENTS TO THE SERVICE OF PROCESS BY REGISTERED MAIL, POSTAGE PREPAID, OR BY PERSONAL SERVICE WITHIN OR WITHOUT THE STATE OF ILLINOIS. THE BORROWER HEREBY EXPRESSLY AND IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION WHICH IT MAY HAVE OR HEREAFTER MAY HAVE TO THE LAYING OF VENUE OF ANY SUCH LITIGATION BROUGHT IN ANY SUCH COURT REFERRED TO ABOVE AND ANY CLAIM THAT ANY SUCH LITIGATION HAS BEEN BROUGHT IN AN INCONVENIENT FORUM. TO THE EXTENT THAT THE BORROWER HAS OR HEREAFTER MAY ACQUIRE ANY IMMUNITY FROM JURISDICTION OF ANY COURT OR FROM ANY LEGAL PROCESS (WHETHER THROUGH SERVICE OR NOTICE, ATTACHMENT PRIOR TO JUDGMENT, ATTACHMENT IN AID OF EXECUTION OR OTHERWISE) WITH -7- RESPECT TO ITSELF OR ITS PROPERTY, THE BORROWER HEREBY IRREVOCABLY WAIVES SUCH IMMUNITY IN RESPECT OF ITS OBLIGATIONS UNDER THIS THIRD AMENDMENT, THE CREDIT AGREEMENT AS AMENDED BY THIS THIRD AMENDMENT AND THE OTHER LOAN DOCUMENTS. SECTION 12. Waiver of Jury Trial. THE AGENT, THE LENDERS AND THE BORROWER -------------------- HEREBY KNOWINGLY, VOLUNTARILY AND INTENTIONALLY WAIVE ANY RIGHTS THEY MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION BASED HEREON, OR ARISING OUT OF, UNDER, OR IN CONNECTION WITH, THIS THIRD AMENDMENT, THE CREDIT AGREEMENT AS AMENDED BY THIS THIRD AMENDMENT OR ANY OTHER LOAN DOCUMENT, OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN) OR ACTIONS OF THE AGENT, THE LENDERS OR THE BORROWER. THE BORROWER ACKNOWLEDGES AND AGREES THAT IT HAS RECEIVED FULL AND SUFFICIENT CONSIDERATION FOR THIS PROVISION (AND EACH OTHER PROVISION OF EACH OTHER LOAN DOCUMENT TO WHICH IT IS A PARTY) AND THAT THIS PROVISION IS A MATERIAL INDUCEMENT FOR THE AGENT AND THE LENDERS ENTERING INTO THIS THIRD AMENDMENT, THE CREDIT AGREEMENT AS AMENDED BY THIS THIRD AMENDMENT AND EACH SUCH OTHER LOAN DOCUMENT. -8- IN WITNESS WHEREOF, the requisite parties hereto have caused this Third Amendment to be executed by their respective officers thereunto duly authorized as of the day and year first above written and shall be effective as of such date. VINTAGE PETROLEUM, INC. By: /s/ William C. Barnes ----------------------------- William C. Barnes, Executive Vice President and Chief Financial Officer Address: 110 West Seventh Street Tulsa, Oklahoma 74119 Facsimile No.: (918) 878-5781 Attention: William C. Barnes, Executive Vice President and Chief Financial Officer S-1 BANK OF MONTREAL acting through its U.S. branches and agencies, including initially its Chicago, Illinois branch, as Agent By: /s/ Sara J. Teasdale ------------------------------------ Name: Sara J. Teasdale, Director Address: 115 South LaSalle Street, 11th Floor West Chicago, Illinois 60603 Facsimile No.: (312) 750-3456 Attention: Terri Perez-Ford, Specialist with copy to: Bank of Montreal Houston Agency 700 Louisiana Street 4400 Bank of America Center Houston, Texas 77002 Facsimile No.: (713) 223-4007 Attention: William Stumpf, Associate S-2 LENDERS: ------- BANK OF MONTREAL, as Lender By: /s/ Sara J. Teasdale ----------------------------------------- Name: Sara J. Teasdale Title: Director Domestic Office: 115 South LaSalle Street 11th Floor West Chicago, Illinois 60603 Facsimile No. (312) 750-3456 Attention: Terri Perez-Ford, Specialist LIBOR Office: 115 South LaSalle Street Chicago, Illinois 60603 Facsimile No.: (312) 750-3456 Attention: Terri Perez-Ford, Specialist with copy to: Bank of Montreal Houston Agency 700 Louisiana Street 4400 Bank of America Center Houston, Texas 77002 Facsimile No.: (713) 223-4007 Attention: William Stumpf, Associate S-3 ABN AMRO BANK N.V., as Lender and Co-Agent By: /s/ Robert J. Cunningham ------------------------------------------ Name: Robert J. Cunningham Title: Group Vice President By: /s/ Jamie A. Conn ------------------------------------------ Name: Jamie A. Conn Title: Vice President Domestic Office: 208 South LaSalle, Suite 1500 Chicago, IL 60604-1003 Facsimile No.: (312) 992-5157 Attention: Loan Administration LIBOR Office: 208 South LaSalle, Suite 1500 Chicago, IL 60604-1003 Facsimile No.: (312) 992-5111 Attention: Credit Administration with a copy to: ABN Amro Bank N.V. Three Riverway, Suite 1700 Houston, TX 77056 Facsimile: (713) 961-1699 Attention: Robert J. Cunningham S-4 BANKBOSTON, N.A., as Lender and Co-Agent By: /s/ Bryon E. Cail ---------------------------------------- Name: Bryon E. Cail Title: Loan Officer Domestic Office: 100 Federal Street MS 01-08-04 Boston, MA 02110 Facsimile No.: (617) 434-3652 Attention: Allison Rossi LIBOR Office: 100 Federal Street MS 01-08-04 Boston, MA 02110 Facsimile No.: (617) 434-3652 Attention: Allison Rossi S-5 THE BANK OF NEW YORK, as Lender By: /s/ Raymond J. Palmer ----------------------------------------- Name: Raymond J. Palmer Title: Vice President Domestic Office: One Wall Street New York, NY 10286 Facsimile No.: (212) 635-7923 Attention: Ray Palmer LIBOR Office: One Wall Street New York, NY 10286 Facsimile No.: (212) 635-7923 Attention: Ray Palmer S-6 THE BANK OF NOVA SCOTIA, as Lender and Lead Manager By: /s/ F. C. H. Ashby ------------------------------------- Name: F. C. H. Ashby Title: Senior Manager Loan Operations Domestic Office: The Bank of Nova Scotia, Atlanta Office 600 Peachtree Street, N.E. Suite 2700 Atlanta, GA 30308 Facsimile No. (404) 888-8998 Attention: Cleve Bushey LIBOR Office: The Bank of Nova Scotia, Atlanta Office 600 Peachtree Street, N.E. Suite 2700 Atlanta, GA 30308 Facsimile No.: (404) 888-8998 Attention: Cleve Bushey with a copy to: The Bank of Nova Scotia 1100 Louisiana Street, Suite 3000 Houston, TX 77002 Attention: Spencer Smith S-7 BANK OF OKLAHOMA, NATIONAL ASSOCIATION, as Lender By: /s/ Kevin A. Humphrey ---------------------------------- Name: Kevin A. Humphrey Title: Vice President Domestic Office: One Williams Center, 8th Floor Tulsa, OK 74172 Facsimile No.: (918) 588-6880 Attention: Michael Coats LIBOR Office: One Williams Center, 8th Floor Tulsa, OK 74172 Facsimile No.: (918) 588-6880 Attention: Michael Coats S-8 PARIBAS, as Lender and Co-Agent By: /s/ A. David Dodd ------------------------------------- Name: A. David Dodd Title: Vice President By: /s/ Barton D. Schouest ------------------------------------- Name: Barton D. Schouest Title: Managing Director Domestic Office: 1200 Smith Street, Suite 3100 Houston, TX 77002 Facsimile No. (713) 659-3832 Attention: Leah Evans-Hughes LIBOR Office: 1200 Smith Street, Suite 3100 Houston, TX 77002 Facsimile No. (713) 659-3832 Attention: Leah Evans-Hughes S-9 THE FUJI BANK LTD. as Lender By: /s/ Yoshiaki Inoue ------------------------------------ Name: Yoshiaki Inoue Title: Senior Vice President & Manager Domestic Office: 1 Houston Bank Center, Suite 4100 1221 McKinney Street Houston, Texas 77010 Facsimile No.: (713) 759-0717 Attention: Tommy Watts LIBOR Office: 1 Houston Bank Center, Suite 4100 1221 McKinney Street Houston, Texas 77010 Facsimile No.: (713) 759-0717 Attention: Tommy Watts S-10 CHRISTIANIA BANK OG KREDITKASSE ASA, as Lender By: /s/ William S. Phillips ---------------------------------------- Name: William S. Phillips Title: First Vice President By: /s/ Peter M. Dodge ---------------------------------------- Name: Peter M. Dodge Title: Senior Vice President Domestic Office: New York Branch 11 West 42nd Street New York, NY 10036 Facsimile No. (212) 827-4888 Attention: Peter Dodge LIBOR Office: New York Branch 11 West 42nd Street New York, NY 10036 Facsimile No.: (212) 827-4888 Attention: Peter Dodge S-11 CREDIT LYONNAIS, as Lender By: /s/ Philippe Soustra --------------------------------- Name: Philippe Soustra Title: Senior Vice President Domestic Office: Credit Lyonnais New York Branch 1301 Avenue of the Americas New York, NY 10019 Facsimile No. (713) 751-0307 Attention: Christine Smith-Byerly Credit Lyonnais Houston Representative Office LIBOR Office: Credit Lyonnais New York Branch 1301 Avenue of the Americas New York, NY 10019 Facsimile No.: (713) 751-0307 Attention: Christine Smith-Byerly Credit Lyonnais Houston Representative Office S-12 FIRST UNION NATIONAL BANK, as Lender and Lead Manager By: /s/ David E. Humphreys ----------------------------------- Name: David E. Humphreys Title: Vice President Domestic Office: 301 South College Street Charlotte, NC 28288 Facsimile No. (713) 650-6354 Attention: David E. Humphreys LIBOR Office: 301 South College Street Charlotte, NC 28288 Facsimile No.: (713) 650-6354 Attention: David E. Humphreys S-13 MEES PIERSON CAPITAL CORP., as Lender and Lead Manager By: /s/ Darrell W. Holley -------------------------------------- Name: Darrell W. Holley Title: Managing Director By: /s/ Kayel Lowthan -------------------------------------- Name: Kayel Low than Title: Managing Director Domestic Office: MeesPierson Capital Corp. 300 Crescent Court, Suite 1750 Dallas, Texas 75201 Facsimile No. (214) 754-5981 Attention: Yolanda Dittmar/Angela Pross LIBOR Office: MeesPierson Capital Corp. 300 Crescent Court, Suite 1750 Dallas, Texas 75201 Facsimile No. (214) 754-5981 Attention: Yolanda Dittmar/Angela Pross Wiring Instructions: Chase Manhattan Bank ABA #021000021 Credit to: MeesPierson New York Agency Acct.#001-1-624418 For further Credit: MeesPierson Capital Corp. Ref: Vintage Petroleum, Inc. Acct.#: 100980360 S-14 NATEXIS Banque BFCE, as Lender By: /s/ Timothy L. Polvado ------------------------------------------ Name: Timothy L. Polvado Title: Vice President and Group Manager By: /s/ N. Eric Ditges ------------------------------------------ Name: N. Eric Ditges Title: Vice President Domestic Office: NATEXIS Banque Southwest Representative Office 333 Clay Street, Suite 4340 Houston, TX 77002 Facsimile No. (713) 759-9908 Attention: Eric Ditges LIBOR Office: NATEXIS Banque Southwest Representative Office 333 Clay Street, Suite 4340 Houston, TX 77002 Facsimile No.: (713) 759-9908 Attention: Tanya McAllister with a copy to: NATEXIS Banque New York Branch 645 5th Avenue, 20th Floor New York, NY 10022 Facsimile No.: (212) 872-5045 Attention: Joan Rankine S-15 BANK OF AMERICA, N.A. as Lender and Syndication Agent By: /s/ Denise A. Smith -------------------------------------- Name: Denise A. Smith Title: Managing Director Domestic Office: 901 Main Street, 64th Floor Dallas, TX 75202 Facsimile No. (214) 508-1285 Attention: Denise Smith LIBOR Office: 901 Main Street, 64th Floor Dallas, TX 75202 Facsimile No.: (214) 508-1285 Attention: Denise Smith with copy to: 901 Main Street, 14th Floor Dallas, Texas 75202 Facsimile No.: (214) 508-1215 Attention: Betty Canales S-16 THE SANWA BANK LIMITED, as Lender and Lead Manager By: /s/ Clyde Redford ----------------------------------------- Name: Clyde Redford Title: Domestic Office: 55 East 52nd Street, 26th Floor New York, NY 10055 Facsimile No. (212) 754-2360 Attention: C. Lawrence Murphy LIBOR Office: 55 East 52nd Street, 26th Floor New York, NY 10055 Facsimile No.: (212) 754-2360 Attention: C. Lawrence Murphy S-17 SOCIETE GENERALE, SOUTHWEST AGENCY, as Lender and Documentation Agent By: /s/ Paul Cornell ------------------------------------ Name: Paul Cornell Title: Vice President Domestic Office: 4800 Trammell Crow Center 2001 Ross Avenue Dallas, Texas 75201 Facsimile No. (214) 754-0171 Attention: Loan Operations LIBOR Office: 4800 Trammell Crow Center 2001 Ross Avenue Dallas, Texas 75201 Facsimile No.: (214) 754-0171 Attention: Loan Operations with copy to: Societe Generale, Southwest Agency 1111 Bagby, Suite 2020 Houston, Texas 77002 Facsimile No. (713) 650-0824 Attention: Paul Cornell S-18 UNION BANK OF CALIFORNIA, N.A., as Lender and Lead Manager By: /s/ Gary Shekerjian --------------------------------------- Name: Gary Shekerjian Title: Assistant Vice President Domestic Office: 500 North Akard St. #4200 Dallas, Texas 75201 Facsimile No. (214) 922-4209 Attention: Gary Shekerjian LIBOR Office: Energy Capital Services 445 S. Figueroa Street, 15th Floor Los Angeles, CA 90071 Facsimile No.: (213) 236-4096 Attention: Patricia Gonzales S-19 EXHIBIT F COMMITMENTS Omitted. The Registrant agrees to furnish supplementally a copy of this omitted Exhibit to the Securities and Exchange Commission upon its request. F-1 EXHIBIT I Bank of Montreal Houston Agency 700 Louisiana Street 4400 Bank of America Center Houston, Texas 77002 Telecopier: (713) 223-4007 Date:______________ Notice of Commitment Increase Reference is made to the Amended and Restated Credit Agreement, dated as of October 21, 1998, among Vintage Petroleum, Inc., a Delaware corporation, (the "Borrower"), certain financial institutions and the Bank of Montreal (the -------- "Agent") (as amended, modified and supplemented to the date hereof, the "Credit ----- Agreement"). Capitalized terms used herein but not otherwise defined have the meanings assigned to them in the Credit Agreement. The undersigned hereby gives notice pursuant to Section 2.1.6 of the Agreement of its intent to increase the Maximum Commitment Amount by the amount of $__________, effective ___________ (the "Commitment Increase Effective Date"). The existing Lenders agreeing to increase their Commitments and the assignees agreeing to become New Lenders to effect such requested increase are identified below. From and after the Commitment Increase Effective Date, the respective Commitments of the existing Lenders agreeing to increase their Commitments and the New Lenders will be as set forth below: Existing Lenders: Share of Maximum Percentage Share of Bolivian Commitment Bolivian Letter of Amount Letter of Credit Credit Percentage _________________ $________________ ___________ $___________ ___________ _________________ $________________ ___________ $___________ ___________ _________________ $________________ ___________ $___________ ___________ _________________ $________________ ___________ $___________ ___________ _________________ $________________ ___________ $___________ ___________ _________________ $________________ ___________ $___________ ___________ I-1 New Lenders: Share of Maximum Percentage Share of Bolivian Commitment Bolivian Letter of Amount Letter of Credit Credit Percentage _________________ $________________ ___________ $___________ ___________ _________________ $________________ ___________ $___________ ___________ _________________ $________________ ___________ $___________ ___________ _________________ $________________ ___________ $___________ ___________ _________________ $________________ ___________ $___________ ___________ _________________ $________________ ___________ $___________ ___________ _________________ $________________ ___________ $___________ ___________ The undersigned Authorized Officer represents and warrants that (a) the increase requested hereby complies with the requirements of Section 2.1.6 of the Agreement and (b) except [as set forth on Annex A hereto, and]* to the extent the undersigned gives notice to the Agent to the contrary prior to 5:00 p.m., (U.S. central time) on the Business Day before the Commitment Increase Effective Date, no Default or Event of Default exists as of the date hereof and no Default will exist on the Commitment Increase Effective Date. _________________________________ By:______________________________ Name: Title: ________________ */ If the representation and warranty in clause (b) would be incorrect, include the material in the brackets and set forth the reasons such representation and warranty would be incorrect on an attachment labeled Annex A. I-2 EX-21 4 SUBSIDIARIES OF THE REGISTRANT Exhibit 21 SUBSIDIARIES OF THE REGISTRANT ------------------------------ State or Jurisdiction Ownership Name of Incorporation Percentage ---- --------------------- ---------- Vintage Gas, Inc. Oklahoma 100 Vintage Marketing, Inc. Oklahoma 100 Vintage Pipeline, Inc. Oklahoma 100 Vintage Petroleum International, Oklahoma 100 Inc. Vintage Oil Argentina, Inc. Cayman Islands 100 Cadipsa S.A. Republic of Argentina 97 Vintage Petroleum Argentina, Inc. Cayman Islands 100 Vintage Petroleum Ecuador, Inc. Cayman Islands 100 Vintage Petroleum Boliviana, Ltd. Bermuda 100 VP Argentina, Inc. Cayman Islands 100 Vintage Petroleum Yemen, Inc. Cayman Islands 100 Vintage Oil Ecuador, S.A. France 100 EX-23.1 5 CONSENT OF ARTHUR ANDERSEN L.L.P. EXHIBIT 23.1 Arthur Andersen LLP CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report dated February 21, 2000 included in this Form 10-K, into the Company's previously filed Registration Statements on Form S-8 (File Nos. 33-37505 and 333-88297) and Registration Statements on Form S-3 (File Nos. 333-68351 and 333-77619). /s/ Arthur Andersen LLP ARTHUR ANDERSEN LLP Tulsa, Oklahoma March 13, 2000 EX-23.2 6 CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC. EXHIBIT 23.2 [LOGO] [LETTERHEAD OF NETHERLAND, SEWELL & ASSOCIATES, INC. CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS --------------------------------------------------------- As Petroleum Engineers, we hereby consent to the inclusion of the information included in this Form 10-K with respect to (a) the oil and gas reserves of Vintage Petroleum, Inc., for the United States, Argentina and Ecuador, the future net revenues from such reserves, and the present value thereof, and (b) the oil and gas reserves of certain oil and gas properties in the El Huemul concession acquired by Vintage Petroleum, Inc. from Total Austral S.A. and Repsol S.A., as described in this Form 10-K, which information has been included in this Form 10-K in reliance upon the report of this firm and upon the authority of this firm as experts in petroleum engineering. We hereby further consent to all references to our firm included in this Form 10-K and to the incorporation by reference in the Registration Statements on Form S-8, Nos. 33- 37505 and 333-88297, and the Registration Statements on Form S-3, Nos. 333-68351 and 333-77619, of Vintage Petroleum, Inc. of such information. NETHERLAND, SEWELL & ASSOCIATES, INC. By: /s/ Frederic D. Sewell ----------------------------------------- Frederic D. Sewell President Dallas, Texas March 13, 2000 EX-23.3 7 CONSENT OF DEGOLYER AND MACNAUGHTON EXHIBIT 23.3 DeGolyer and MacNaughton One Energy Square Dallas, Texas 75206 March 10, 2000 Vintage Petroleum, Inc. 110 W. 7th Street Tulsa, Oklahoma 74119 Gentlemen: We hereby consent to the references to our firm and to our reserves estimates for the year ended December 31, 1999, as set forth in the Annual Report on Form 10-K (the Annual Report) of Vintage Petroleum, Inc. (the Company). Our estimates of the oil, condensate, and natural gas reserves of certain properties owned by the Company are contained in our report entitled "Appraisal Report, as of December 31, 1999, on Reserves of Certain Properties in Bolivia Operated by Vintage Petroleum, Inc." References to us and our estimates are included in the "Oil and Gas Properties" section on page 10, the "Reserves" section on page 14, and "Notes to Consolidated Financial Statements" on page 69. However, we are necessarily unable to verify (i) the accuracy of future net revenues and discounted present value of future net revenues contained in the Annual Report because our estimates of future net revenues and discounted present worth of future net revenues have been combined with estimates prepared by other petroleum consultants and (ii) the accuracy of reserves estimates and the basis for changes to reserves estimates prior to December 31, 1998. Additionally, we hereby consent to the incorporation by reference in the Company's Registration Statements Nos. 33-37505 and 333-88297 on Form S-8 and Nos. 333-68351 and 333-77619 on Form S-3 of such references made in the Annual Report. Very truly yours, /s/ DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON EX-27 8 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM DECEMBER 31, 1999 FORM 10-K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 12-MOS DEC-31-1999 JAN-01-1999 DEC-31-1999 42,687 0 92,695 0 0 154,491 1,554,412 583,060 1,168,134 93,902 625,318 0 0 312 430,817 1,168,134 437,961 496,735 192,848 192,848 147,522 0 58,665 97,700 24,329 73,371 0 0 0 73,371 1.27 1.24
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