SEC Info  
    Home      Search      My Interests      Help      Sign In      Please Sign In

Vintage Petroleum Inc – ‘10-K405’ for 12/31/96

As of:  Thursday, 3/27/97   ·   For:  12/31/96   ·   Accession #:  930661-97-709   ·   File #:  1-10578

Previous ‘10-K405’:  None   ·   Next & Latest:  ‘10-K405’ on 3/13/00 for 12/31/99

  in   Show  &   Hints

  As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

 3/27/97  Vintage Petroleum Inc             10-K405    12/31/96    9:559K                                   Donnelley RR & So..Co/FA

Annual Report — [x] Reg. S-K Item 405   —   Form 10-K
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K405     Annual Report -- [x] Reg. S-K Item 405                42    244K 
 2: EX-4.3      Indenture Between Chase Manhattan and the Company    116    486K 
 3: EX-13       Portions of the Annual Report to Stockholders         26    188K 
 4: EX-21       Subsidiaries of the Company                            1      6K 
 5: EX-23.1     Consent of Arthur Andersen LLP                         1      6K 
 6: EX-23.2     Consent of Netherland, Sewell & Associates, Inc.       1      7K 
 7: EX-27       Financial Data Schedule                                2      9K 
 8: EX-99.1     Letter Regarding U.S. Oil and Gas Reserve              4     19K 
 9: EX-99.2     Letter Regarding South America Oil and Gas Reserve     3     15K 


10-K405   —   Annual Report — [x] Reg. S-K Item 405
Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
3Forward-Looking Statements
4Items 1 and 2. Business and Properties
5Recent Developments
10Exploitation and Development Activities
11West Coast Area
"Mid-Continent Area
12East Texas Area
"Argentina Concessions
22Proved reserves
30Item 3. Legal Proceedings
31Item 4. Submission of Matters to a Vote of Security-Holders
"Item 4A. Executive Officers of the Registrant
34Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
"Item 6. Selected Financial Data
"Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
"Item 8. Financial Statements and Supplementary Data
"Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
"Item 10. Directors and Executive Officers of the Registrant
"Item 11. Executive Compensation
"Item 12. Security Ownership of Certain Beneficial Owners and Management
"Item 13. Certain Relationships and Related Transactions
35Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
39Signatures
10-K4051st Page of 42TOCTopPreviousNextBottomJust 1st
 

================================================================================ 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, 1996 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.) 4200 ONE WILLIAMS CENTER TULSA, OKLAHOMA 74172 (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 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 March 17, 1997, 25,714,443 shares of the Registrant's Common Stock were outstanding, and the aggregate market value of the Common Stock held by non-affiliates was approximately $471,734,000. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Registrant's Annual Report to Stockholders for the fiscal year ended December 31, 1996, are incorporated by reference into Parts I and II of this Form 10-K. Portions of the Registrant's Proxy Statement for the Annual Meeting of Stockholders to be held May 13, 1997, are incorporated by reference into Part III of this Form 10-K. ================================================================================
10-K4052nd Page of 42TOC1stPreviousNextBottomJust 2nd
VINTAGE PETROLEUM, INC. FORM 10-K YEAR ENDED DECEMBER 31, 1996 TABLE OF CONTENTS Page ---- PART I Items 1 and 2. Business and Properties....................................... 1 Item 3. Legal Proceedings............................................. 27 Item 4. Submission of Matters to a Vote of Security-Holders.............................................. 28 Item 4A. Executive Officers of the Registrant.......................... 28 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters........................................... 31 Item 6. Selected Financial Data....................................... 31 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................. 31 Item 8. Financial Statements and Supplementary Data................... 31 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........................ 31 PART III Item 10. Directors and Executive Officers of the Registrant............ 31 Item 11. Executive Compensation........................................ 31 Item 12. Security Ownership of Certain Beneficial Owners and Management......................................... 31 Item 13. Certain Relationships and Related Transactions................ 31 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K................................................... 32 Signatures .............................................................. 36 -i-
10-K4053rd Page of 42TOC1stPreviousNextBottomJust 3rd
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 limited partnerships and joint ventures. "Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf" means billion cubic feet, "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 degrees 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 reserves" are estimated quantities of oil and gas 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 reserves" are those reserves which are expected to be recovered through existing wells with existing equipment and operating methods. "Proved undeveloped reserves" are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required. FORWARD-LOOKING STATEMENTS THIS FORM 10-K INCLUDES CERTAIN STATEMENTS THAT MAY BE DEEMED TO BE "FORWARD-LOOKING STATEMENTS" WITHIN THE MEANING OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995. ALL STATEMENTS IN THIS FORM 10-K, OTHER THAN STATEMENTS OF HISTORICAL FACTS, THAT ADDRESS ACTIVITIES, EVENTS OR DEVELOPMENTS THAT THE COMPANY EXPECTS, BELIEVES OR ANTICIPATES WILL OR MAY OCCUR IN THE FUTURE, INCLUDING THE DRILLING OF WELLS, RESERVE ESTIMATES, FUTURE PRODUCTION OF OIL AND GAS, FUTURE CASH FLOWS, FUTURE RESERVE ACTIVITY AND OTHER SUCH MATTERS ARE FORWARD-LOOKING STATEMENTS. ALTHOUGH THE COMPANY BELIEVES THE EXPECTATIONS EXPRESSED IN SUCH FORWARD-LOOKING STATEMENTS ARE BASED ON REASONABLE ASSUMPTIONS WITHIN THE BOUNDS OF ITS KNOWLEDGE OF ITS BUSINESS, SUCH STATEMENTS ARE NOT GUARANTEES OF FUTURE PERFORMANCE AND ACTUAL RESULTS OR DEVELOPMENTS MAY DIFFER MATERIALLY FROM THOSE IN THE FORWARD-LOOKING STATEMENTS. FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE IN FORWARD-LOOKING STATEMENTS INCLUDE: OIL AND GAS PRICES; EXPLOITATION AND EXPLORATION SUCCESSES; CONTINUED AVAILABILITY OF CAPITAL AND FINANCING; GENERAL ECONOMIC, MARKET OR BUSINESS CONDITIONS; ACQUISITION OPPORTUNITIES (OR LACK THEREOF); CHANGES IN LAWS OR REGULATIONS; RISK FACTORS LISTED FROM TIME TO TIME IN THE COMPANY'S REPORTS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION; AND OTHER FACTORS. THE COMPANY ASSUMES NO OBLIGATION TO UPDATE PUBLICLY ANY FORWARD-LOOKING STATEMENTS, WHETHER AS A RESULT OF NEW INFORMATION, FUTURE EVENTS OR OTHERWISE. -ii-
10-K4054th Page of 42TOC1stPreviousNextBottomJust 4th
PART I ITEMS 1 AND 2. BUSINESS AND PROPERTIES. GENERAL Vintage Petroleum, Inc. (the "Company") is an independent oil and gas company focused on the acquisition of producing oil and gas properties which contain the potential for increased value through exploitation and development. The Company, through its experienced management and engineering 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 infill wells. The Company believes that its primary strengths are its ability to add reserves at attractive prices through property acquisitions and subsequent exploitation, and its low cost operating structure. These strengths have allowed the Company to substantially increase reserves, production and cash flow during the last five years. As the Company has grown its cash flow and added to its technical staff, exploration has become a larger focus for its future growth. Planned exploration expenditures for 1997 of approximately $43 million represent 37 percent of the Company's capital budget, excluding acquisitions. At December 31, 1996, the Company owned and operated producing properties in 11 states, with its domestic proved reserves located primarily in four core areas: the West Coast, Gulf Coast, East Texas and Mid-Continent areas of the United States. During 1996, the Company expanded its Gulf Coast area through the acquisitions of certain oil and gas properties from Exxon Company, U.S.A. and Conoco Inc. In addition, the Company established a new core area in 1995 by acquiring 12 oil concessions, 11 of which are producing and operated by the Company, in the south flank of the San Jorge Basin in southern Argentina. The Company recently expanded its South American operations into Bolivia through the acquisition of Shamrock Ventures (Boliviana) Ltd. which owns and operates three blocks covering approximately 570,000 gross acres in the Chaco Plains area of southern Bolivia. The Company owned interests in 3,032 gross (2,004 net) producing wells in the United States as of December 31, 1996, of which approximately 81 percent are operated by the Company. The Company owned interests in 642 gross (629 net) producing wells in Argentina as of December 31, 1996, of which approximately 97 percent are operated by the Company. As of December 31, 1996, the Company's properties had proved reserves of 242.1 MMBOE, comprised of 178.3 MMBbls of oil and 382.8 Bcf of gas, with a present value of estimated future net revenues before income taxes (utilizing a 10 percent discount rate) of $1.8 billion and a standardized measure of discounted future net cash flows of $1.4 billion. The Company has consistently achieved growth in proved reserves, production and revenues and has been profitable every full year since its founding in 1983. From the first quarter of 1994 through the fourth quarter of 1996, the Company increased its average net daily production from 18,000 Bbls of oil to 35,800 Bbls of oil and from 78,500 Mcf of gas to 85,100 Mcf of gas. For the year ended December 31, 1996, the Company generated revenues of $311.7 million and net income of $41.2 million. Financial information relating to the Company's industry segments is set forth in "Note 8 to Consolidated Financial Statements - Segment Information" which is incorporated by reference from pages 42 and 43 of the Company's 1996 Annual Report to Stockholders. The Company was incorporated in Delaware on May 31, 1983. The Company's principal office is located at 4200 One Williams Center, Tulsa, Oklahoma 74172, and its telephone number is (918) 592-0101. -1-
10-K4055th Page of 42TOC1stPreviousNextBottomJust 5th
RECENT DEVELOPMENTS On February 5, 1997, the Company completed a public offering of 1,500,000 shares of its Common Stock, all of which were sold by the Company. The net proceeds to the Company of approximately $47.1 million were used to repay a portion of the existing indebtedness under the Company's revolving credit facility. Also 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. Upon a change in control (as defined) of the Company, holders of the 8 5/8% Notes may require the Company to repurchase all or a portion of the 8 5/8% Notes at a purchase price equal to 101 percent of the principal amount thereof; plus accrued and unpaid interest. The 8 5/8% Notes mature on February 1, 2009, with interest payable semiannually on February 1 and August 1 of each year. The 8 5/8% 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 the Company's 9% Senior Subordinated Notes Due 2005 (the "9% Notes"). The indenture for the 8 5/8% Notes contains limitations similar to those contained in the indenture for the 9% Notes. The net proceeds to the Company of approximately $96.4 million from the sale of the 8 5/8% Notes were used to repay a portion of the existing indebtedness under the Company's revolving credit facility. In February 1997, the Company reached an agreement with subsidiaries of Burlington Resources Inc. to purchase certain producing oil and gas properties and facilities located in the Gulf Coast of Texas and Louisiana for $114.1 million in cash, subject to closing adjustments. The effective date of the transaction is January 1, 1997, with closing scheduled for April 1, 1997, subject to board approvals by the Company and Burlington Resources Inc. and satisfaction of other normal conditions to closing. The properties to be acquired consist of several onshore fields, 5 offshore fields and a number of smaller fields covering over 74,000 net acres, about 46 percent of which are associated with offshore fields. The Company will operate the properties which have current net daily production averaging approximately 5,200 Bbls of oil and 17,000 Mcf of gas. Key producing areas are the West Ranch, Luling/Darst Creek and Terryville fields. West Ranch, located along the Texas Gulf Coast, produces primarily oil from the Greta sandstone formation at depths of 5,000 feet to 6,000 feet. Oil is also produced in the Luling/Darst Creek fields in south central Texas from the Edwards limestone formation at depths of less than 3,000 feet. Terryville, in north Louisiana, produces principally gas from the Cotton Valley and Gray formations between 9,000 feet and 13,000 feet. 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 exploitation potential, (b) focusing on low risk exploitation and development 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 engineering 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 low risk exploitation and development, (b) attractive purchase price, -2-
10-K4056th Page of 42TOC1stPreviousNextBottomJust 6th
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 producing properties. This acquisition strategy has allowed the Company to rapidly grow its reserves at favorable acquisition prices. From January 1, 1994, through December 31, 1996, the Company acquired 120.7 MMBOE of proved oil and gas reserves at an average acquisition cost of $2.78 per BOE, which is significantly below the industry average. The Company replaced through acquisitions approximately 2.9 times its production of 41.5 MMBOE during the same period. . 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, 1994, through December 31, 1996, the Company spent approximately $154.8 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 77 percent of these operations, and the result of all of its exploitation activities, including development and infill drilling, succeeded in replacing more than 125 percent of production during this period. The Company has an extensive inventory of exploitation and development opportunities including identified projects which represent approximately a ten year inventory at current activity levels. The Company anticipates spending approximately $33 million in the United States and approximately $40 million in Argentina during 1997 on exploitation and development projects. . 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 reduce the cost and increase the success of its exploration program. From January 1, 1994, through December 31, 1996, the Company spent approximately $38.6 million on exploration activities including the drilling of 52 gross (29.51 net) exploration wells, of which approximately 63 percent gross (60 percent net) were productive. The Company has increased its 1997 exploration budget by 79 percent over 1996 to approximately $43 million with spending planned in its core areas in the United States and Argentina as well as in Block 19 of Ecuador and the Chaco Block in Bolivia. . 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 substantial 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 and 1995, the Company completed three public equity offerings, as well as a public debt offering in 1995, which provided the Company with aggregate net proceeds of approximately $272 million. Additionally, the -3-
10-K4057th Page of 42TOC1stPreviousNextBottomJust 7th
Company closed February 5, 1997, on its fourth public equity offering and its second public debt offering. Net proceeds from these offerings totaled approximately $143.5 million and were used to repay a portion of existing indebtedness under the Company's revolving credit facility thereby providing increased financial flexibility for future acquisitions. 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 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 in recent years and should in the future afford attractive opportunities to purchase domestic and international producing properties. The Company's ability to quickly evaluate and complete acquisitions as well as its financial flexibility allow it to take advantage of these opportunities as they materialize. 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. From January 1, 1994, through December 31, 1996, the Company made oil and gas property acquisitions involving total costs of approximately $335.5 million. As a result of these acquisitions, the Company acquired approximately 120.7 MMBOE of proved oil and gas reserves. The following table summarizes the Company's acquisition experience during the periods indicated: [Enlarge/Download Table] PROVED RESERVES WHEN ACQUIRED ACQUISITION ----------------------------- COST PER ACQUISITION OIL GAS BOE WHEN COSTS (MBbls) (MMcf) MBOE ACQUIRED ----------- ------- ------- ------ ---------- (In thousands) U.S. Acquisitions 1994............................................. $ 36,544 5,645 29,655 10,588 $3.45 1995............................................. 38,896 8,840 39,486 15,421 2.52 1996............................................. 50,480 8,095 20,787 11,560 4.37 -------- ------ ------- ------- ----- Total U.S. Acquisitions....... 125,920 22,580 89,928 37,569 3.35 -------- ------ ------- ------- ----- Argentina Acquisitions 1995............................................. 168,762 65,653 - 65,653 2.57 1996............................................. 3,754 2,849 - 2,849 1.32 -------- ------ ------- ------- ----- Total Argentina Acquisitions.. 172,516 68,502 - 68,502 2.52 -------- ------ ------- ------- ----- Bolivia Acquisition 1996............................................. 37,048 4,953 57,758 14,579 2.54 -------- ------ ------- ------- ----- Total U.S. and International Acquisitions..... $335,484 96,035 147,686 120,650 $2.78 ======== ====== ======= ======= ===== The following is a brief discussion of significant acquisitions in recent years: 1994 Acquisitions. The Company acquired approximately 5.6 MMBbls of oil and 29.7 Bcf of gas through a series of small transactions in 1994 for a total of approximately $36.5 million. The oil reserves are located primarily in the Colgrade field in Louisiana and the Rincon field in Southern -4-
10-K4058th Page of 42TOC1stPreviousNextBottomJust 8th
California. The gas reserves are located primarily in California's Sacramento Basin, Louisiana's Gulf Coast area and the Mid-Continent area in Oklahoma. The Company has identified numerous exploitation opportunities in these properties, including infill development drilling, adding productive intervals in existing producing wells and recompleting inactive wells. 1995 Acquisitions. In May 1995, the Company purchased all of Texaco Exploration and Production, Inc.'s interests in nine oil fields and seven gas fields in California located primarily in Kern, Ventura, Los Angeles, Orange and Santa Barbara Counties and the Sacramento Basin area for $26.7 million in cash (the "Texaco Properties"). Netherland, Sewell & Associates, Inc. ("Netherland, Sewell") estimated that proved reserves attributable to these properties at the date of acquisition were approximately 7.5 MMBbls of oil and 16.4 Bcf of gas. The Company has identified numerous exploitation opportunities in these properties including development drilling, recompletions, steam flood expansions as well as lease operating expense efficiencies. In the third quarter of 1995, the Company closed two acquisitions of related properties located in the south flank of the San Jorge Basin in southern Argentina, establishing a new core area for the Company. On July 5, 1995, the Company purchased approximately 51.8 percent of the outstanding common stock of Cadipsa S.A. ("Cadipsa") for 302,808 shares of the Company's Common Stock (then valued at $5.7 million) and $7.4 million in cash. Cadipsa's major assets include a 100 percent working interest in two concessions and a 50 percent working interest in three additional concessions, all five of which are mature, producing and operated by Cadipsa, covering approximately 322,000 gross acres. Cadipsa's net daily production at the date of acquisition was approximately 3,700 Bbls of mid-gravity oil from multiple zones at depths between 2,500 feet and 5,500 feet. The Company has subsequently purchased an additional 45.0 percent of Cadipsa which increases its total ownership to approximately 96.8 percent. On September 29, 1995, the Company purchased 100 percent of the outstanding common stock of Vintage Oil Argentina, Inc., formerly BG Argentina, S.A. ("Vintage Argentina") from British Gas plc, for $37.0 million in cash. Vintage Argentina's major assets consist of a 50 percent working interest in three of the producing concessions operated by Cadipsa. In November 1995, the Company entered into separate agreements with Astra Compania Argentina de Petroleo S.A. ("Astra") and Shell Compania Argentina de Petroleo S.A. ("Shell") to acquire certain producing oil and gas properties in Argentina (the "Astra/Shell Properties"). On November 30, 1995, the Company completed the purchase of the Astra portion of the Astra/Shell Properties by paying $17.9 million in cash for Astra's 35 percent working interest in the Astra/Shell Properties. On December 27, 1995, the Company completed the purchase of the remaining 65 percent working interest from Shell for $32.8 million cash and deferred payments valued at $5.1 million. The acquisition of the Astra/Shell Properties resulted in the Company acquiring 100 percent working interests in seven concessions, six of which are currently producing and all of which are located on the south flank of the San Jorge Basin in southern Argentina. The concessions cover approximately 450,000 acres and are located in close proximity to the Company's other Argentina properties. 1996 Acquisitions. On January 31, 1996, the Company purchased interests in two fields located in south-central Louisiana from Conoco Inc. for $13.9 million (the "Conoco Properties"). Funds were provided by advances under the Company's revolving credit facility. The Conoco Properties included 26 gross (21 net) productive wells with net daily production of approximately 1,000 Bbls of oil and 550 Mcf of gas. All of the wells are now operated by the Company. The primary producing sands include the Ortego A, Haas, Tate, Wilcox 1 through 6 and the Middle and Basal Cockfield at depths ranging from 7,500 feet to 12,000 feet. Planned exploitation activities include workovers, recompletions and developmental drilling. -5-
10-K4059th Page of 42TOC1stPreviousNextBottomJust 9th
On November 20, 1996, the Company purchased certain producing oil and gas properties and facilities from Exxon Company, U.S.A. located in south Alabama for approximately $28.5 million in cash, subject to post-closing adjustments (the "Exxon Properties"). Funds were provided by advances under the Company's revolving credit facility. The Exxon Properties include an interest in two fields totaling approximately 5,000 net acres with a total of 17 gross (9.9 net) productive wells with current net daily production of approximately 1,450 Bbls of oil and liquids and 2,800 Mcf of gas. All of the wells are now operated by the Company. The primary producing sands are the Smackover and Norphlet at depths of approximately 15,000 feet. Future exploitation activities will include operating cost reductions, treating plant efficiencies, workovers and infill drilling. In November 1996, the Company agreed to purchase 100 percent of the outstanding common stock of Shamrock Ventures (Boliviana) Ltd. ("Shamrock") from affiliates of Ultramar Diamond Shamrock Corporation for approximately $29.0 million in cash. In addition, at closing on January 7, 1997, the Company repaid all of Shamrock's existing bank debt (approximately $9.2 million). Funds for the purchase of the stock and the repayment of debt were provided by advances under the Company's revolving credit facility. Shamrock's assets include (a) oil and gas properties valued at $37.0 million (including the effect of approximately $7.0 million of deferred income taxes recorded under the purchase method of accounting), and (b) inventory, receivables, cash and other assets net of liabilities (other than bank debt repaid at closing) of approximately $8.2 million. This transaction is subject to government approvals. The acquisition of Shamrock represents an extension of the Company's South American operating area that was initially established through a series of acquisitions in Argentina during 1995. The oil and gas properties of Shamrock consist of three blocks, totaling approximately 570,000 gross acres, in the Chaco Plains area of southern Bolivia. This region has experienced the greatest amount of exploration and currently accounts for the majority of the country's production. The properties consist of a 100 percent interest in the Chaco and Porvenir blocks, and a 50 percent interest in the Nupuco block. Proved reserves at the time of acquisition, as estimated by Netherland, Sewell, were 57.8 Bcf of gas and 5.0 MMBbls of oil. Current net daily production is approximately 14,500 Mcf of gas and 230 Bbls of condensate. The recent realized price on the properties for natural gas was approximately $1.39 per Mcf. The purchase also included a 29 mile gas pipeline and an interest in a gas processing plant with a capacity of 110 MMcf per day. Liquids are transferred through the pipeline to the processing plant. The current market for the gas is Argentina. The Company believes that the Shamrock properties contain substantial upside potential which may be realized through exploitation and future exploration. There can be no assurance, however, that such potential will be realized. Bolivia occupies the strategic pivotal position in the area known as the "Southern Cone" of South America. The Company expects that gas will be the key energy source for the developing regional economies. The development of the sizable gas reserves in southern Bolivia will play an important role as a source of energy for the net importing countries of this region, the most significant of which is Brazil. Third party plans call for construction of a gas pipeline from Santa Cruz, Bolivia to Sao Paulo, Brazil which is anticipated to be completed by 1999. The Company plans to begin work during 1997 to evaluate the exploration prospects on the Bolivian properties in order to be ready to take advantage of the increased market for Bolivian gas that should occur if the pipeline to Brazil is completed. There can be no assurance, however, that this Brazilian market will be developed. The Company intends to continue its growth strategy emphasizing reserve additions through its acquisition efforts. The Company may utilize any one or a combination of its line of credit with banks, institutional financing, issuance of debt securities or additional equity securities and internally generated cash flow to finance its acquisition efforts. No assurance can be given that sufficient external funds -6-
10-K40510th Page of 42TOC1stPreviousNextBottomJust 10th
will be available to fund the Company's desired acquisitions. For additional discussion of the Company's liquidity, see pages 29 and 30 of the Company's 1996 Annual Report to Stockholders. The Company does not have a specific acquisition budget since the timing and size of acquisitions are difficult to forecast. The Company is constantly reviewing acquisition possibilities. The Company may expand into new domestic core areas. The Company is also evaluating additional acquisition opportunities in other countries which the Company believes are politically stable. At the present time the Company has no binding agreements with respect to any significant acquisitions other than the agreement with Burlington Resources Inc. (see "--Recent Developments"). EXPLOITATION AND DEVELOPMENT ACTIVITIES The Company concentrates its acquisition efforts on proved producing properties which demonstrate a potential for significant additional development through workovers, behind-pipe recompletions, secondary recovery operations, the drilling of development or infill wells, and other exploitation techniques. The Company has pursued an active workover and recompletion program on the properties it has acquired and intends to continue its workover and recompletion program in the future. The Company's exploitation staff focuses on maximizing the value of the properties within its reserve base. The Company's exploitation engineers, who strive to offset normal production declines and replace the Company's annual production, have replaced more than 125 percent of its production during the last three years. The results of their efforts are reflected in revisions to reserves. Net revisions to reserves for 1996 totaled 29.5 MMBOE, or 171 percent of the Company's production of 17.3 MMBOE. From January 1, 1994, through December 31, 1996, the Company spent approximately $65.8 million on recompletion and workover operations. A measure of the overall success of the Company's recompletion and workover operations during this period (excluding minor equipment repair and replacement) has been that improved production or operating efficiencies have been achieved from approximately 77 percent of such operations. However, there can be no assurance that such results will continue. The Company anticipates spending in excess of $29 million on workover and recompletion operations during 1997. The expenditures required for this program have historically been, and are expected to continue to be, financed by internally generated funds. Development drilling activity is generated both through the Company's exploration efforts and as a result of the Company's 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. From January 1, 1994, through December 31, 1996, the Company participated in the drilling of 142 gross (99.15 net) development wells, of which approximately 90 percent gross (90 percent net) were productive. However, there can be no assurance that this past rate of drilling success will continue in the future. The Company is pursuing development drilling in the West Coast, Gulf Coast, Mid- Continent and East Texas areas as well as its Argentina concessions and anticipates continued growth in its drilling activities. Additionally, the Company has numerous infill drilling locations in several East Texas area fields, specifically South Gilmer (Cotton Valley formation), Southern Pine (Travis Peak formation), Bethany Longstreet (Hosston formation) and Rosewood (Cotton Valley formation) fields. During 1996, the Company participated in the drilling of 68 gross (56.61 net) development wells. At December 31, 1996, the Company's proved reserves included approximately 88 development or infill drilling locations on its U.S. acreage and 160 locations on its Argentine acreage. In addition, the -7-
10-K40511th Page of 42TOC1stPreviousNextBottomJust 11th
Company has an extensive inventory of development and infill drilling locations on its existing properties which are not included in proved reserves. The Company spent approximately $43.3 million on development/infill drilling during 1996 and expects to spend approximately $45 million on its development/infill drilling activities during 1997. 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: West Coast Area. The San Miguelito/Rincon field area, acquired from Conoco, Santa Fe Energy and Mobil, continues to be the primary focus of the Company's West Coast exploitation efforts. Consolidation of the three acquisition areas into a single operating unit has significantly reduced operating costs. At the time of the initial acquisition in July 1993, the Company identified 18 exploitation projects; however, since that time, the Company has completed 90 projects. Exploitation efforts including artificial lift enhancements, waterflood optimization, recompletions and sidetracking junked producers have resulted in sustaining the average field production at levels comparable to that of three years prior. As a result, the Company has been able to increase proved reserves each year since the properties were acquired. Also during 1996, the Company initiated pilot waterflooding operations on the Fourth Grubb producing interval. Based on this successful pilot injection test, full scale waterflooding operations will be initiated during 1997. Ongoing reservoir studies continue to identify significant upside to the Company's existing inventory of exploitation projects. Gulf Coast Area. In the Galveston Bay area of Texas, the Company performed 12 workovers in the Red Fish Reef, Trinity Bay and Fishers Reef fields which are 100 percent owned by the Company and which historically have had good exploitation potential. This work consisted of recompletions and repair jobs in the multi-pay Frio zones productive in the area which resulted in a total gross production increase of 250 Bbls of oil per day and 4,200 Mcf of gas per day. During 1996, the Company also performed recompletions and workovers on seven wells in the Tepetate field, a 100 percent owned field acquired from Conoco in January 1996, which resulted in gross production increases of 850 Bbls of oil per day and 400 Mcf of gas per day. The Company also experienced a successful 1996 exploitation program in the South Pass 24 field where three recompletions and one development well resulted in increased gross daily production from the field of 140 Bbls of oil and 4,370 Mcf of gas. Mid-Continent Area. Water injection began in October 1993 in the Shawnee Townsite Unit waterflood project and oil response began in November 1994. Gross unit production has increased from a low of 250 Bbls of oil per day to a current rate of approximately 2,750 Bbls of oil per day. Oil rates are forecasted to peak at approximately 3,500 Bbls of oil per day in 1997. An engineering and geological study performed in 1996 has refined the reservoir characterization and established the viability of drilling several infill development wells within the unit boundary to recover oil that would otherwise be undrained. In addition to the Shawnee waterflood, the Company is actively pursuing four other secondary recovery projects located in the Texas Panhandle. Each of these waterflood projects is targeting the Upper Morrow sand at depths of approximately 8,000 feet. Three of these units have been approved and water injection has been initiated. Installation of the final unit is expected to commence in the first quarter of 1997. Two analogous Upper Morrow fields producing in the immediate area have already responded favorably to waterflood operations. The Company owns working interests ranging from 82 percent to 100 percent in each of the four projects. The Company anticipates additional proved reserves will be added based on the level of success of these secondary recovery projects. -8-
10-K40512th Page of 42TOC1stPreviousNextBottomJust 12th
East Texas Area. Gas development projects remain the focus of the Company's exploitation efforts in East Texas. In the South Gilmer field, Upshur County, Texas, a Company engineering study performed in 1993 established the potential viability of 10 infill drilling locations along with workover opportunities in eight existing wells. This exploitation work was initiated in 1994 and successful workovers were conducted on five wells. Seven of the infill locations have now been drilled and completed. As a result of this work, gross field production has increased to over 9,000 Mcf per day. The Company's working interests in these wells range from 73 percent to 99 percent. Argentina Concessions. Development and extensional drilling along with development of secondary recovery projects have been the focus of the Company's exploitation efforts in its Argentina properties. During 1996, the Company continued the expansion of the Canadon Minerales Block 123A waterflood by adding additional sands to the flood and completing additional patterns. Water injection began in February 1992 and first oil response was seen approximately 12 months later. Since the initiation of this project, gross production has increased from 150 Bbls of oil per day to 1,300 Bbls of oil per day. During 1996, the Company installed two new waterflood projects in areas immediately adjacent to the Block 123A waterflood. There are two additional areas in Canadon Minerales for which new waterflood projects are planned for 1997. Numerous other areas within the other concessions are being evaluated as future waterflood candidates. Drilling activity commenced during February 1996 and reached its peak with three rigs running during the fourth quarter of 1996. Forty-one wells were drilled in 1996 and an additional 10 were in process at year end 1996. The two main areas where this activity was concentrated were Canadon Minerales with 25 wells drilled and Canadon Seco with 12 wells drilled. Largely due to the results of this drilling activity, gross production during 1996 increased from 3,500 Bbls of oil per day to 6,900 Bbls of oil per day in Canadon Minerales and from 1,300 Bbls of oil per day to 3,200 Bbls of oil per day in Canadon Seco. During 1996, the Company acquired 124 square kilometers (48 square miles) of 3-D seismic to aid in the optimum placement of future drilling locations. This data was acquired in an attempt to aid in the evaluation of the extremely complex stratigraphy that has historically caused problems in geologic interpretation in this basin. The first three wells that were drilled from the evaluation of the 3-D seismic data have proven successful. If future wells verify these initial results, the Company believes that substantial upside potential that has historically been overlooked can be economically exploited. EXPLORATION 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 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 Ecuador and Bolivia are characterized by higher potential and higher risk. From January 1, 1994, through December 31, 1996, the Company spent $38.6 million on exploration activities. The Company plans to spend approximately $43 million on exploration activities during 1997, approximately $31 million in the U.S. and Argentina and approximately $12 million in other international areas. The following is a brief discussion of the primary areas of exploration activity for the Company: -9-
10-K40513th Page of 42TOC1stPreviousNextBottomJust 13th
United States. Gulf Coast Area. In the Galveston Bay area of Texas, the Company --------------- has acquired over 180 square miles of new 3-D seismic data and controls over 30,000 net acres in shallow state waters. The Company uses 3-D seismic data to identify new exploration and extensional opportunities in new reservoirs as well as in existing fields. The Company has identified several new prospects in Galveston Bay. The Texas State Tract-75, an exploratory well which utilized 3-D seismic data, was drilled in the Umbrella Point area and was successfully completed as a producer. One or more offset wells are planned to be drilled at Umbrella Point in 1997. The Texas State Tract No. 2-3A well in the area of Fishers Reef West is scheduled to spud during the second quarter of 1997. A third exploratory prospect, White Heron, is also scheduled to spud during the second quarter of 1997. The Galveston Bay prospects, if successful, may require multiple development wells to drain target reservoirs. Working interests net to the Company range between 33 percent and 100 percent in Galveston Bay. At the Company's Deweyville prospect, a new 10 square mile 3-D seismic survey is being used to aid in the identification of an expanded Yegua Trend on the Texas and Louisiana border. The Company has a 90 percent working interest in this prospect and is in the process of acquiring additional acreage. Mid-Continent Area. The focus of the Company's Mid-Continent ------------------ drilling program continues to be the Anadarko and Ardmore Basins. In the Fort-X prospect, four exploratory wells were drilled in 1996 utilizing 3-D seismic. All four wells found sands targeted to be developed. Two were completed as producers and are producing at 1,250 to 2,500 Mcf of gas per day. A fifth well is currently drilling. With the information obtained from these four wells, the Company has entered into two large 3-D seismic joint ventures in the Anadarko Basin aimed at increasing its inventory of exploratory prospects, drilling activity and reserves in selected multi-pay areas over the next several years. The Wheeler project, in which the Company has a 25 percent working interest, is a 150 square mile 3-D seismic survey in the Texas Panhandle targeting the productive Granite Wash, Morrow, Hunton and Arbuckle formations which are known to exist regionally. An exploratory well is planned for the first half of 1997. The second project is a 500 square mile 3-D seismic joint venture in which the Company has a 31.25 percent working interest. Eight areas of interest have been selected for geologic imaging, targeting the Granite Wash, Red Fork, Morrow, Springer, Hunton and Arbuckle formations. In the Stagecoach evaluation area of southern Oklahoma, the Company has initiated an extensional drilling program utilizing a new frac technology aimed at developing a large 6,000 net acre lease block. Drilling of the first well has begun with evaluation expected in early 1997. If successful, the play could open up additional extensional projects in this gas rich sub-basin. The Company's working interests in these prospects range between 70 percent and 100 percent. West Coast Area. Based on a discovery made by the Company in 1995, --------------- 3-D seismic data is being used to generate additional prospects in the Buttes Slough area of Northern California. Three to five wells are planned in the Grimes area during 1997. In the Zaca field located in Santa Barbara County, an exploratory horizontal well is targeted to be drilled in 1997 to access potential reserves in new fault blocks. The Company owns a 100 percent working interest in this field and has eight additional exploratory prospects. International. South America. The Company is currently pursuing several ------------- international exploratory projects which, if successful, have the potential to increase the growth of the Company. The Company believes that its existing projects in Ecuador and Bolivia have the potential to significantly increase reserves. The exploration play with the largest potential for reserve additions, as estimated by the Company, is Block 19 in the Oriente Basin in Ecuador. The Company has a 30 percent working interest in a project to explore Block 19. Numerous commercially productive fields have been discovered in this basin. Primary targets are the Hollin, Napo "U" and "T" sands which are productive in other significant fields in this basin. Two wells are planned for 1997. In Bolivia, geological studies are underway to -10-
10-K40514th Page of 42TOC1stPreviousNextBottomJust 14th
confirm a prospect which has been identified on the Company's recently acquired acreage. Pending the results of these studies, the Company plans to drill a well during 1997 that would test independent oil and gas concepts in this area. Additionally, the Company has identified several exploratory leads on the 570,000 acres it controls which, if successfully developed into prospects, could require several years to test. The Company's working interest in the area is 100 percent. In Argentina, in the Cerro Wenceslao concession in the western portion of the San Jorge Basin, an exploratory project is currently underway to test an area structurally high on an anticline feature to a prior well with oil shows. A similar structural feature located in the northeast portion of the same concession produces from numerous sands in the Bajo Barreal formation. This field is currently producing at a rate of 1,520 Bbls of oil per day with a cumulative recovery to date of 17 MMBbls of oil. The Company has a 100 percent working interest in the Cerro Wenceslao concession. OIL AND GAS PROPERTIES At December 31, 1996, the Company owned and operated producing properties in 11 states, with its U.S. proved reserves located primarily in four core areas: the West Coast, Gulf Coast, East Texas and Mid-Continent areas. In addition, during 1995 the Company established a new core area in the San Jorge Basin of Argentina. As of December 31, 1996, the Company operated approximately 3,101 productive wells and also owned non-operating interests in 579 productive wells. Oil and gas sales from the Company's producing properties accounted for approximately 83 percent, 82 percent and 76 percent of the Company's revenues for the years ended December 31, 1996, 1995 and 1994, respectively. 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. The following table summarizes the Company's proved reserves in its 30 largest fields in the U.S., its five largest concessions in Argentina and its largest concession in Bolivia at December 31, 1996, as estimated by Netherland, Sewell. These fields and concessions represent approximately 76 percent of the Company's proved reserves on such date. -11-
10-K40515th Page of 42TOC1stPreviousNextBottomJust 15th
[Enlarge/Download Table] LOCATION NET OIL NET GAS AREA FIELD/CONCESSION NAME (COUNTY, STATE OR PROVINCE) (MBBLS) (MMCF) MBOE -------------------------- ----------------------------- --------------------------- ------- ------- ------ West Coast San Miguelito Ventura, CA 17,753 4,580 18,516 South Mountain Ventura, CA 6,130 6,308 7,182 Rincon Ventura, CA 4,734 3,823 5,372 Ojai-Silverthread Ventura, CA 2,915 13,567 5,176 Santa Maria Valley/Cat Canyon Santa Barbara, CA 4,089 - 4,089 Buena Vista Hills Kern, CA 2,522 5,264 3,399 Pleito Ranch Kern, CA 2,993 1,212 3,195 North Tejon Kern, CA 1,701 8,440 3,108 Sespe Ventura, CA 2,690 2,433 3,096 Canfield Ranch Kern, CA 2,552 443 2,626 Zaca Santa Barbara, CA 2,101 - 2,101 Lathrop San Joaquin, CA - 11,475 1,913 Wheeler Ridge Kern, CA 1,352 2,029 1,690 North Antelope Hills Kern, CA 1,661 - 1,661 Tejon Kern, CA 1,532 143 1,556 Gulf Coast South Pass 24 Plaquemines, LA 2,500 10,009 4,168 Flomaton Escambia, AL 2,002 7,574 3,264 Tepetate Acadia, LA 2,305 1,017 2,475 Waveland Hancock, MS 249 10,827 2,053 Ville Platte Evangeline, LA 1,147 4,043 1,821 Pachuta Creek Clarke, MS 1,607 317 1,660 Fanny Church Escambia, AL 1,126 2,185 1,490 Trinity Bay Chambers, TX 1,310 1,022 1,481 East Texas South Gilmer Upshur, TX 762 26,147 5,120 Colgrade Winn, LA 3,960 - 3,960 Southern Pine Cherokee, TX - 22,132 3,689 Fruitvale Van Zandt, TX 21 20,308 3,405 Mid-Continent Shawnee Pottawatomie, OK 2,209 61 2,220 Booker Ochiltree, TX 1,775 92 1,791 Strong City Roger Mills, OK 53 10,149 1,745 San Jorge Basin, Argentina Canadon Minerales Santa Cruz Province 25,816 - 25,816 Las Heras/Piedra Clavada Santa Cruz Province 15,489 - 15,489 Canadon Seco Santa Cruz Province 11,547 - 11,547 Cerro Wenceslao Santa Cruz Province 9,205 - 9,205 Meseta Espinosa Santa Cruz Province 8,043 - 8,043 Chaco Plains, Bolivia Nupuco Tarija Department 860 45,236 8,399 West Coast Area. The Company expanded its operations to the West Coast in 1992 through two separate acquisitions of properties located in Kern, Ventura, and Santa Barbara Counties in California. Since 1992, the Company has continued to expand its operations in the West Coast area through additional property acquisitions. As of December 31, 1996, the area comprised 32 percent of the Company's total proved reserves and 53 percent of the Company's U.S. proved reserves. The Company currently operates 1,171 productive wells with current daily gross production of approximately 12,300 Bbls of mid-gravity oil, 2,050 Bbls of heavy oil and 27,100 Mcf of gas. In addition, the Company owns an interest in 71 productive wells operated by others. San Miguelito. The San Miguelito field is located in the west ------------- central portion of the greater Ventura Avenue field just north of the City of Ventura, California. Production is from multiple pay intervals in Pliocene-age sands which span 7,000 vertical feet. Well depths generally range from 7,000 feet to just over 16,000 feet in the deepest wells. Currently, active waterflood operations are -12-
10-K40516th Page of 42TOC1stPreviousNextBottomJust 16th
underway in three of the producing zones. With the field still producing in excess of 3,300 gross Bbls of oil per day, the Company believes additional waterflood potential exists in lower sands currently producing on primary depletion. The Company operates this single lease property with a 100 percent working and 87.5 percent net revenue interest. For additional information regarding this field, see "--Exploitation and Development Activities--West Coast Area." South Mountain. The South Mountain field, located just south of -------------- Santa Paula, California, has become one of the Company's major producing areas. As a result of the acquisition of the Texaco Properties, which included certain properties in this field, the Company now operates 226 active wells in the South Mountain field. Current gross daily production of 1,100 Bbls of oil and 2,175 Mcf of gas comes from Eocene and Pliocene sand intervals at depths of 3,000 feet to 10,000 feet. The solution gas and gravity drainage producing mechanisms are responsible for low decline rates which result in long-life reserves. In addition to the producing wells, the Company also operates the South Mountain Gas Gathering System which transports approximately 3,500 Mcf per day of Company and third party gas. The Company's working interests in the South Mountain field range from 50 percent to 100 percent with net revenue interests from 42 percent to 100 percent; however, the properties are predominantly owned 100 percent. Rincon. The Rincon field is located on the western updip end of ------ the greater Ventura Avenue field just north of the City of Ventura, California, and adjacent to the Company's San Miguelito field properties. Like the San Miguelito field, production is from multiple pay intervals of Pliocene-age sands. These intervals span several thousand feet with three waterfloods currently in operation. Producing intervals range in depth from approximately 3,500 feet to 14,000 feet. The Company operates this field with a 100 percent working and 80 percent net revenue interest. Current daily gross production from this field is approximately 1,000 Bbls of oil and 900 Mcf of gas. During 1996, the Company was able to increase total field production through development of uphole producing intervals and re-vitalization of existing waterfloods. The Company believes that significant upside reserve potential remains in the development of these shallow producing horizons as well as workover and stimulation activity in the presently producing intervals. For additional information regarding this field, see "--Exploitation and Development Activities--West Coast Area." Ojai-Silverthread and Timber Canyon. The Ojai field, which extends ----------------------------------- to the Silverthread and Timber Canyon areas, is located in the western central portion of Ventura County, California. All production in this area is from the fractured Monterey Shale formation which is encountered at depths ranging from 2,000 feet to 6,000 feet. The Company operates 118 productive wells in this field with a 100 percent working interest and net revenue interests ranging from 83 percent to 100 percent. The properties are mature, characterized by pressure depletion and gravity drainage, with highly predictable production decline rates. Combined current daily gross production exceeds 750 Bbls of oil and 3,200 Mcf of gas. Santa Maria Valley/Cat Canyon. The Company operates these two ----------------------------- heavy (low gravity) oil fields near Santa Maria, California. At the end of 1992, the Company built and commenced operation of two non-conventional fuel facilities. Those facilities are located in the Santa Maria Valley and Cat Canyon fields and now produce oil from tar sands. Since December 1992, the Company has produced over 800 MBbls of tar sand oil through these facilities. In addition, the Company operates one waterflood. Total produced volume from the fields currently is in excess of 1,500 gross Bbls of oil per day. The Company's working interests in the fields are 100 percent with net revenue interests ranging from 74.5 percent to 100 percent. Buena Vista Hills. The Buena Vista Hills field is located ----------------- approximately 25 miles east of Bakersfield, California. Production is from the Upper Channel, Main Massive and Interbed zones at a depth of 5,000 feet to 5,500 feet. The Company operates 24 productive wells in the field with a 100 percent working interest. Daily gross production is 650 Bbls of oil and 400 Mcf of gas. The Company -13-
10-K40517th Page of 42TOC1stPreviousNextBottomJust 17th
has an ongoing annual workover program in the field. Future projects include continued recompletions, infill drilling and potential waterflooding. Pleito Ranch. The Pleito Ranch field is located on the southern ------------ end of the San Joaquin Basin. Production is from Miocene-age Chanac and Santa Margarita sands below the Wheeler Ridge thrust fault. Well depths range from 11,000 feet to 14,000 feet. All productive wells are operated by the Company with a 100 percent working and net revenue interest. The recovery mechanism is predominantly gravity drainage and is characterized by low decline, long-life reserves with current gross production of approximately 600 Bbls of oil per day. North Tejon. The North Tejon field is located near the southern ----------- end of the San Joaquin Basin. This field is divided into a series of fault blocks with productive reservoirs in the lower Miocene, Oligocene, Zemorrian and Eocene sands. These producing zones range in depth from 5,400 feet to 11,300 feet. All productive wells are operated by the Company with a 100 percent working and net revenue interest. Current gross production rates average in excess of 200 Bbls of oil per day and 2,200 Mcf of gas per day. The Company believes that future projects in this field may increase production and reserves. Gulf Coast Area. The Gulf Coast Area comprised approximately 14 percent of the Company's December 31, 1996, total proved reserves. Production in this area is predominantly from structural accumulations in reservoirs of Miocene Age. The depths of the producing reservoirs in this area range from 1,200 feet to 14,500 feet. The Company currently operates 288 productive wells and owns interests in an additional 166 productive wells in this area. Daily gross production from the operated wells currently averages 7,000 Bbls of oil and 49,800 Mcf of gas. Additional development potential exists in this area from recompletions in existing wellbores particularly in the South Pass 24 (70 percent working interest), Red Fish Reef (100 percent working interest), and Panther Reef (96 percent average working interest) fields. South Pass 24. The South Pass 24 field is located in state waters ------------- of Plaquemines Parish, Louisiana, at shallow water depths averaging 10 feet to 20 feet. The 33 productive oil wells and seven productive gas wells in this field are operated by the Company and one other operator. The South Pass 24 field produces hydrocarbons from various members of the Miocene sand series at an average depth of approximately 7,000 feet. Future value enhancements in this field are expected to come from exploitation opportunities. Flomaton. This field, purchased from Exxon in 1996, is located in -------- Escambia County, Alabama, and produces from the Norphlet sand at 15,000 feet. Company operated gross daily production is 600 Bbls of oil and 10,000 Mcf of gas from nine wells. The Company anticipates significant reduction in operating costs due to planned treating plant efficiency improvements. The Company is also examining the feasibility of accelerating recovery through infill drilling. Tepetate. The Tepetate field is located in Acadia Parish, Louisiana. -------- The major producing sand is the Ortega A. The Company is the operator and owns a 100 percent working interest in the field. Over 20 productive sands are found in the field, primarily in the Frio and Anahuac formations. The depths of the producing sands range from 7,500 feet to 10,000 feet. The field currently produces 1,000 Bbls of oil per day and 12,500 Bbls of water per day from 11 producing wells. The water is reinjected through four injection wells and one disposal well. Several workovers and equipment changes have increased the production from 500 Bbls of oil per day to the current level since acquisition in February 1996. Waveland. The Waveland field is located in Hancock County, -------- Mississippi, and produces from the Washita-Fredricksburg, Paluxy and Mooringsport formations at depths ranging from 11,800 feet to 13,340 feet. The Company currently operates gross daily production of 3,500 Mcf of gas. This -14-
10-K40518th Page of 42TOC1stPreviousNextBottomJust 18th
field contains a significant amount of reserves that are behind-pipe in existing well bores. The Company intends to further develop this field through a series of workovers and recompletions with two to four such projects scheduled for 1997. Ville Platte. The Ville Platte field is located in east-central ------------ Evangeline Parish, Louisiana. The field has 26 productive sands with six sands currently producing. The Company acquired operating interest in the field in February 1996. The Haas, Tate, and Wilcox 1 through 6 were unitized in 1951 into the Ville Platte Unit. The Company operates the Ville Platte Unit with a 77.8 percent working interest. Other current producing sands are the Middle and Basal Cockfield reservoirs. The Company owns a 100 percent working interest in most of the wells completed in the non-unitized sands. The depths of the producing sands range from 8,000 feet to 12,000 feet. The field currently produces 225 Bbls of oil per day from 15 wells. East Texas Area. The East Texas Area comprised approximately eight percent of the Company's December 31, 1996, total proved reserves. The Cotton Valley, Smackover and Travis Peak formations are the dominant producing reservoirs on the Company's acreage in this area. The Company currently operates daily gross production of 1,250 Bbls of oil and 27,600 Mcf of gas from 673 operated productive wells in this area. The Company owns an interest in an additional 71 productive wells in this area. Significant infill drilling potential exists on the Company's acreage in the South Gilmer, Colgrade, Southern Pine, Rosewood, Bethany Longstreet and Bear Grass fields. The Company plans to continue infill drilling programs in Southern Pine, Colgrade and South Gilmer fields. During 1996, these infill drilling programs have resulted in the addition of five wells, all of which were successful. For additional information regarding these producing operations, see "--Exploitation and Development Activities--East Texas Area." South Gilmer. The South Gilmer field, the Company's largest field ------------ in the East Texas area, is located in Upshur County and produces from the Cotton Valley Lime formation at average depths of 11,300 feet to 11,800 feet. The Company currently operates 18 productive wells and owns interests in three additional productive wells in this field. A workover program implemented in 1994 increased production substantially in five wells. The Company began the drilling of an infill well in December 1994, with two additional wells drilled in 1995 and four wells in 1996. All seven wells resulted in successful completions. Significant behind-pipe reserves are booked for the Company's 6,727 gross acres in the Cotton Valley sand formation. Colgrade. The Colgrade field is located in Winn Parish, Louisiana -------- and currently produces 750 Bbls of oil per day from the Wilcox formation at a depth of 1,400 feet. The Company operates 437 active wells in this field. During 1996, a pilot project was initiated to increase fluid withdrawal rates from these wells using submersible pumps. To date, 38 wells tested using such pumps have indicated increased cumulative oil production of 144 Bbls per day. Projecting this success to an additional 257 candidate wells should result in a peak field rate in 1998 of 1,650 Bbls of oil per day, or an increase in excess of 100 percent over the current rate. These submersible pumps are low cost and replace conventional rod pump installations. Surface facilities are being modified to handle the increased rates. The Company generally has a 100 percent working interest and an 88 percent net revenue interest in this field. Southern Pine. The Southern Pine field is located in Cherokee ------------- County, Texas, and produces from the Travis Peak formation. The Company currently operates 26 productive wells in this field. The Company completed the drilling of eight development wells in 1995. These wells, combined with the ten wells acquired from Herd Producing Company in March 1995, increased gross daily production from 1,200 Mcf of gas to a peak rate of 10,000 Mcf of gas. The installations of plunger lift and central compression during 1996 have helped maintain the current gross daily production of 6,700 Mcf of gas. -15-
10-K40519th Page of 42TOC1stPreviousNextBottomJust 19th
Mid-Continent Area. The Mid-Continent Area extends from the Arkoma Basin of Eastern Oklahoma to the Texas Panhandle and north to include Kansas. This area comprises six percent of the Company's total proved reserves as of December 31, 1996. The Company currently operates daily gross production of 4,200 Bbls of oil and 28,400 Mcf of gas from 328 operated productive wells in this area. The Company owns an interest in an additional 249 productive wells in this area. The Company's largest field in the Mid-Continent Area is the Shawnee Townsite field, which the Company operates. On March 1, 1993, a unit was formed for secondary recovery operations with water injection initiated in October 1993. For additional information regarding this field, see "--Exploitation and Development Activities--Mid-Continent Area." Argentina Concessions. The Argentina properties consist primarily of 12 mature producing concessions located on the south flank of the San Jorge Basin. These concessions comprised approximately 33 percent of the Company's December 31, 1996, total proved reserves. The Company currently operates 625 productive wells (100 percent working interest) with daily gross production of 16,450 Bbls of oil. In addition, the Company owns an interest in 17 productive wells operated by others. At December 31, 1996, the Company's proved reserves included approximately 160 development or infill drilling locations and 281 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. Canadon Minerales. The primary oil producing reservoirs of the ----------------- Canadon Minerales oil concession are the Mina del Carmen and Canadon Seco formations which are both fluvial channel sand bodies at depths ranging from 3,000 feet to 6,000 feet. This concession currently has 184 producing wells and 32 water injection wells with daily gross production of approximately 7,050 Bbls of oil. Approximately 20 percent of the concession's daily production is produced from the Block 123A waterflood, which contains 22 producing wells and 17 water injection wells. The Block 123A waterflood was expanded during 1996 to include additional sands. Also during 1996, two additional waterflood projects were initiated in areas adjacent to Block 123A. At this time there are two additional waterflood projects scheduled for development. Future evelopment plans at Canadon Minerales include numerous workovers and development drilling locations. Many of the workovers are expected to return idle wells back to production by perforating zones not produced by the former owner. Log cross sections reveal many zones which do not appear to have been previously tested. The proved undeveloped locations are generally infill development locations in areas offsetting existing production. Well depths vary from 3,000 feet to 6,000 feet. The first well was drilled in the first quarter of 1996 and 25 wells were drilled on this concession during 1996. See "--Exploitation and Development Activities--Argentina Concessions." Las Heras/Piedra Clavada. The primary oil producing reservoirs of ------------------------ the Las Heras/Piedra Clavada oil concession are the Castillo and Bajo Barreal formations which are both fluvial channel sand bodies with good to moderate sand quality at depths ranging from 3,500 feet to 7,000 feet. Currently, there are 88 producing wells and five water injection wells with daily gross production of approximately 1,200 Bbls of oil. There is one active waterflood in Block 24, which contains 13 producing wells and five water injection wells. In addition to the activities in Block 24, there are three other waterflood projects scheduled for development at Las Heras/Piedra Clavada. Future development plans at Las Heras/Piedra Clavada include numerous workovers and development drilling locations. Many of these workovers are expected to return idle wells back to production by perforating additional zones. Cross sections reveal many zones which do not appear to -16-
10-K40520th Page of 42TOC1stPreviousNextBottomJust 20th
have been tested. The proved undeveloped locations are generally infill development locations in areas offsetting existing production. Canadon Seco. The primary oil producing reservoirs of the Canadon ------------ Seco oil concession are the Canadon Seco and Mina del Carmen which are fluvial channel sand bodies at depths ranging from 4,000 feet to 7,000 feet. This field currently has 79 producing wells and eight water injection wells with a daily gross production of approximately 3,300 Bbls of oil. There are three active waterfloods at Canadon Seco which contain a total of 10 producing wells and eight water injection wells. The Block VIIIAo waterflood has additional drilling and water injection conversions scheduled for additional development of the concession. Additional development plans at Canadon Seco include numerous workovers and development drilling locations. Many of the workovers are expected to return idle wells back to production by perforating additional zones. See "-- Exploitation and Development Activities--Argentina Concessions." Cerro Wenceslao. The primary oil producing reservoir of the Cerro --------------- Wenceslao oil concession is the Bajo Barreal which contains sands at depths ranging from 1,000 feet to 3,000 feet. Currently, there are 122 producing oil wells and 9 water injection wells with daily gross production of approximately 1,550 Bbls of oil. Future development plans at Cerro Wenceslao include workovers, fracture stimulations, and development drilling on several drilling locations. In addition, the Company plans to further develop the significant waterflood potential in Block 2, Block 5 and the East Flank Block. Meseta Espinosa. The primary oil producing reservoirs of the --------------- Meseta Espinosa oil concession are the Canadon Seco and Mina del Carmen which are fluvial channel sand bodies with good to moderate sand quality at depths ranging from 4,000 feet to 7,000 feet. This concession currently has 103 producing wells and 10 water injection wells with a daily gross production of approximately 2,550 Bbls of oil. There are seven active waterfloods at Meseta Espinosa which contain a total of 17 producing wells and 10 water injection wells. One new proven waterflood project was installed during 1996. It will be followed by the implementation of a second new proven waterflood project. Additional development plans at Meseta Espinosa include several workovers and the drilling of development wells. Bolivia Concessions. The Bolivia properties consist of two producing concessions and one exploration concession located in the Chaco Plains area of southern Bolivia. The Company has a 100 percent working interest in the Chaco exploration concession and the Porvenir producing concession. In the other concession, Nupuco, the Company has a 50 percent working interest. The Company operates all three concessions. These concessions comprise approximately six percent of the Company's total proved reserves and include 6 gross (5.00 net) active producing wells, all of which are operated by the Company. The current daily gross production is approximately 35,000 Mcf of gas and 685 Bbls of condensate. Nupuco. The Nupuco field is located in the southern part of Bolivia ------ approximately 230 miles south of the city of Santa Cruz and approximately 60 miles north of the border with Argentina. The primary gas producing reservoirs are the Triassic age Cangapi and the Carboniferious age San Telmo and Escarpment. This field currently has 2 gross (1.00 net) active producing wells with daily gross production of approximately 30 MMcf of gas and 600 Bbls of condensate. -17-
10-K40521st Page of 42TOC1stPreviousNextBottomJust 21st
MARKETING The Company's gas production and gathered gas are sold primarily 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 an insignificant amount of the Company's gas 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. In order to more efficiently handle spot market transactions, the Company's gas marketing activities are handled by Vintage Gas, Inc., its wholly-owned gas marketing affiliate, which commenced operation on May 1, 1991. This marketing affiliate purchases gas on the spot market from the Company and third parties. Generally, the marketing affiliate purchases this gas on a month-to-month basis at a percentage of resale prices. Gas marketing accounted for approximately 10 percent, 11 percent and 15 percent of the Company's revenues for the years ended December 31, 1996, 1995 and 1994, respectively. 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 SAPA and Petrobras at West Texas Intermediate spot prices less a specified differential. The most significant purchaser of the Company's oil during 1996 was Texaco Trading and Transportation, Inc. Such oil purchases amounted to approximately 15 percent of the Company's total revenues for 1996. No other purchaser of the Company's oil or gas during 1996 exceeded 10 percent of the Company's total revenues. 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. Three hedges (swap agreements) are currently in place for a total of 7,500 Bbls of oil per day at a weighted average price of $19.26 per Bbl (NYMEX reference price) for the period January 1997 through December 1997. GATHERING SYSTEMS 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 22 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 300 miles of varying diameter pipe with a combined capacity in excess of 175 MMcf of gas per day. At December 31, 1996, there were 432 wells (most of 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. Oil and gas gathering accounted for approximately 7 percent, 6 percent and 8 percent of the Company's revenues for the years ended December 31, 1996, 1995 and 1994, respectively. -18-
10-K40522nd Page of 42TOC1stPreviousNextBottomJust 22nd
RESERVES At December 31, 1996, the Company had proved reserves, as estimated by Netherland, Sewell, of 242.1 MMBOE, comprised of 178.3 MMBbls of oil and 382.8 Bcf of gas. The following table sets forth, at December 31, 1996, 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): [Download Table] Proved Reserves: Future net revenues........................................ $3,140,212 Present value of future net revenues before income taxes, discounted at 10 percent.................................. 1,807,137 Standardized measure of discounted future net cash flows... 1,392,841 Proved Developed Reserves: Future net revenues........................................ 2,309,759 Present value of future net revenues before income taxes, discounted at 10 percent.................................. 1,386,361 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, 1996, economic conditions. The estimated future production is priced at prices prevailing at December 31, 1996, except where fixed and determinable price escalations are provided by contract. The resulting estimated future gross revenues are reduced by estimated future costs to develop and produce the proved reserves, based on December 31, 1996, 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 10 to Consolidated Financial Statements -Supplementary Financial Information for Oil and Gas Producing Activities" which is incorporated by reference from pages 44 through 48 of the Company's 1996 Annual Report to Stockholders. The following table sets forth estimates of the proved oil and gas reserves of the Company at December 31, 1996, as evaluated by Netherland, Sewell: [Enlarge/Download Table] OIL (MBbls) GAS(MMcf) ------------------------------- --------------------------------- MBOE DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL TOTAL --------- ----------- ------- --------- ----------- -------- ------- West Coast (a).... 51,240 11,081 62,321 87,952 6,149 94,101 78,005 Gulf Coast........ 16,434 2,022 18,456 86,074 12,833 98,907 34,941 East Texas........ 5,382 424 5,806 72,438 15,743 88,181 20,502 Mid-Continent..... 5,880 1,281 7,161 42,974 899 43,873 14,473 Other U.S......... 314 280 594 26 - 26 598 --------- ---------- ------- -------- --------- -------- ------- Total U.S...... 79,250 15,088 94,338 289,464 35,624 325,088 148,519 Argentina......... 46,582 32,423 79,005 - - - 79,005 Bolivia........... 1,007 3,946 4,953 51,276 6,482 57,758 14,580 --------- ---------- ------- -------- --------- -------- ------- Total Company.. 126,839 51,457 178,296 340,740 42,106 382,846 242,104 ========= ========== ======= ======== ========= ======== ======= -------------- (a) Total proved oil reserves include 6.8 MMBbls of heavy oil located in the Company's Santa Maria Valley/Cat Canyon, North Antelope Hills and Zaca fields in California. -19-
10-K40523rd Page of 42TOC1stPreviousNextBottomJust 23rd
Estimates of the Company's 1996 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. Approximately 74 percent of the U.S. proved reserves associated with infill drilling locations are located in the Company's 30 largest U.S. fields. 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 10 to Consolidated Financial Statements -Supplementary Financial Information for Oil and Gas Producing Activities" which is incorporated by reference from pages 44 through 48 of the Company's 1996 Annual Report to Stockholders. PRODUCTIVE WELLS; DEVELOPED ACREAGE The following table sets forth the Company's domestic and international productive wells and developed acreage assignable to such wells at December 31, 1996: [Download Table] PRODUCTIVE WELLS -------------------------------------- DEVELOPED ACREAGE OIL GAS TOTAL -------------------- ------------ ---------- ------------ GROSS NET GROSS NET GROSS NET GROSS NET --------- --------- ----- ----- ----- ---- ----- ----- U.S........ 574,163 317,674 2,107 1,631 925 373 3,032 2,004 Argentina.. 1,008,339 844,372 642 629 - - 642 629 Bolivia.... 84,014 72,895 - - 6 5 6 5 --------- --------- ----- ----- ----- ---- ----- ----- Total..... 1,666,516 1,234,941 2,749 2,260 931 378 3,680 2,638 ========= ========= ===== ===== ===== ==== ===== ===== 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. Of the gross wells reported above, five had multiple completions. PRODUCTION; UNIT PRICES; COSTS The following table sets forth information with respect to production and average unit prices and costs for the periods indicated: -20-
10-K40524th Page of 42TOC1stPreviousNextBottomJust 24th
[Download Table] YEARS ENDED DECEMBER 31, ------------------------------ 1996 1995 1994 --------- -------- ------ Production: Oil (MBbls) - U.S....................... 7,694 6,647 6,657 Argentina................. 4,245 961 - Total..................... 11,939 7,608 6,657 Gas, all U.S. (MMcf)....... 32,366 30,610 28,884 Average sales prices: Oil (per Bbl) - U.S....................... $ 17.19 (a) $ 15.44 $ 13.53 Argentina................. 15.91 (a) 13.98 - Total..................... 16.73 (a) 15.26 13.53 Gas, all U.S. (per Mcf).... 1.81 1.46 1.78 Production costs (per BOE): U.S........................ 5.42 5.24 5.17 Argentina.................. 4.93 5.42 - Total...................... 5.30 5.25 5.17 ----------- (a) The impact of oil hedges reduced the Company's 1996 U.S., Argentina and total average oil prices per Bbl by $1.47, $2.96 and $2.00, 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. UNDEVELOPED ACREAGE At December 31, 1996, the Company held the following undeveloped acres located in the United States, Ecuador and Bolivia. With respect to such United States acreage held under leases, 96,950 gross (34,535 net) acres are held under leases with primary terms that expire at varying dates through December 31, 2000, unless commercial production is commenced. The Ecuador and Bolivia acreage are held under concessions with primary terms that expire at varying dates in 1999. The following table sets forth the location of the Company's undeveloped acreage and the number of gross and net acres in each. Although substantial undeveloped acreage exists in the Company's concessions in Argentina, the concessions in their entirety are held by production. -21-
10-K40525th Page of 42TOC1stPreviousNextBottomJust 25th
[Download Table] GROSS NET STATE/COUNTRY ACRES ACRES ----------------------------------- --------- ------- California.......................... 6,698 6,090 Colorado............................ 2,720 972 Kansas.............................. 1,420 1,420 Louisiana........................... 1,182 430 Mississippi......................... 204 65 Montana............................. 12,382 6,250 New Mexico.......................... 11,469 1,656 Oklahoma............................ 13,978 8,510 Texas............................... 52,506 13,985 --------- ------- Total U.S.......................... 102,559 39,378 Ecuador............................. 494,226 148,268 Bolivia............................. 485,552 485,552 --------- ------- Total Company...................... 1,082,337 673,198 ========= ======= DRILLING ACTIVITY During the periods indicated, the Company drilled or participated in the drilling of the following exploratory and development wells: [Download Table] YEARS ENDED DECEMBER 31, ---------------------------------------- 1996 1995 1994 ------------ ------------ ------------ GROSS NET GROSS NET GROSS NET ----- ----- ----- ----- ----- ----- Development: United States - Productive............ 22 12.67 36 19.26 31 18.75 Non-Productive........ 5 2.94 5 3.49 2 1.04 Argentina - Productive............ 39 39.00 - - - - Non-Productive........ 2 2.00 - - - - ----- ----- ----- ----- ----- ----- Total................ 68 56.61 41 22.75 33 19.79 ===== ===== ===== ===== ===== ===== Exploratory: United States - Productive............ 6 3.00 13 9.84 12 2.82 Non-Productive........ 7 3.12 5 2.69 5 4.04 Argentina - Productive............ 2 2.00 - - - - Non-Productive........ 1 1.00 - - - - Other International - Productive............ - - - - - - Non-Productive........ 1 1.00 - - - - ----- ----- ----- ----- ----- ----- Total................ 17 10.12 18 12.53 17 6.86 ===== ===== ===== ===== ===== ===== Total: Productive............. 69 56.67 49 29.10 43 21.58 Non-Productive......... 16 10.06 10 6.18 7 5.07 ----- ----- ----- ----- ----- ----- Total................. 85 66.73 59 35.28 50 26.65 ===== ===== ===== ===== ===== ===== The above well information excludes wells in which the Company has only a royalty interest. -22-
10-K40526th Page of 42TOC1stPreviousNextBottomJust 26th
At December 31, 1996, the Company was a participant in the drilling or completion of 23 gross (19.63 net) wells. All of the Company's drilling activities are conducted with independent contractors. The Company owns no drilling equipment. 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 obtain and 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. Increases in worldwide energy production capability have brought about substantial surpluses in energy supplies in recent years. This, in turn, has resulted in substantial competition for markets historically served by domestic gas resources from alternative sources of energy, such as residual fuel oil, and among domestic gas suppliers. Changes in government regulations relating to the production, transportation and marketing of gas have also resulted in significant changes in the historical marketing patterns of the industry. Generally, these changes have resulted in the abandonment by many pipelines of long-term contracts for the purchase of gas, the development by gas producers of their own marketing programs to take advantage of new regulations requiring pipelines to transport gas for regulated fees, and the emergence of various types of marketing companies and other aggregators of gas supplies. As a consequence, gas prices, which were once effectively determined by government regulations, are now largely established by competition. Competitors of the Company in this market include other producers, gas pipelines and their affiliated marketing companies, independent marketers, and providers of alternate energy supplies, such as residual fuel oil. 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. RISKS OF INTERNATIONAL OPERATIONS International investments represent approximately 39 percent of the Company's total proved reserves at December 31, 1996, and are expected to represent a significant portion of the Company's total assets in the future. The Company continues to evaluate international investment opportunities but currently has no binding agreements or commitments to make any material international acquisitions. The Company's foreign properties, operations or investments may be adversely affected by local political and economic developments, exchange controls, currency fluctuations, royalty and tax increases, retroactive tax claims, expropriation, import and export regulations and other foreign laws or policies as well as by laws and policies of the United States affecting foreign trade, taxation and investment. In addition, in the event of a dispute arising from foreign operations, the Company may -23-
10-K40527th Page of 42TOC1stPreviousNextBottomJust 27th
be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts in the United States. The Company may also be hindered or prevented from enforcing its rights with respect to a governmental instrumentality because of the doctrine of sovereign immunity. REGULATION The 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 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. In March 1992, Oklahoma enacted legislation which further limits the daily allowable of gas production during periods of low demand for gas. The Oklahoma Corporation Commission sets production levels quarterly. The production of gas from a single well is limited to the greater of a specified Mcf per day or a percentage of the total daily production capacity of the well. Since March 1992, the daily Mcf has been between 750 and 1,000 Mcf and the total daily production has ranged from 25 percent to 50 percent. Effective July 1, 1992, the Texas Railroad Commission, which is the state agency that regulates oil and gas production in Texas (the "TRC"), enacted new regulations that may limit the rate at which oil and gas may be produced from the Company's Texas properties. Under the new Texas rules, the TRC relies upon certain information filed monthly by well operators, in addition to using historical production data for each well during comparable past periods, to arrive at a production allowable. These Texas and Oklahoma regulations and legislation have not had a significant impact on the Company's operations. The Company cannot predict whether other states will adopt similar regulations or legislation. The effect of such future legislation and regulations may be to decrease the allowable daily production and the revenues from gas properties, including properties that produce both oil and gas. It is also possible that such future legislation and regulations may result in a decrease in gas production in such states, which could exert upward pressure on the price of gas. -24-
10-K40528th Page of 42TOC1stPreviousNextBottomJust 28th
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 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 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"). Since 1978, maximum selling prices of certain categories of gas, whether sold in interstate or intrastate commerce, were regulated pursuant to the NGPA. The NGPA established various categories of gas and provided for graduated deregulation of price controls of several categories of gas and the deregulation of sales of certain categories of gas. All price deregulation contemplated under the NGPA has already taken place. On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 (the "Decontrol Act") was enacted. The Decontrol Act amended the NGPA to remove, as of July 27, 1989, both price and nonprice controls from gas not subject to a contract in effect on July 26, 1989. Gas under contract on July 26, 1989, was decontrolled on the earlier of the termination of the contract or January 1, 1993. Gas from wells spudded after July 26, 1989, was decontrolled on May 15, 1991, even if those wells were still covered by an existing contract. In December 1992, the FERC issued Order 547, which, effective January 7, 1993, constitutes a blanket certificate of public convenience and necessity pursuant to Section 7 of the NGA authorizing any company which is not an interstate natural gas pipeline or an affiliate thereof to make sales for resale at negotiated rates in interstate commerce of any category of gas that is subject to the FERC's NGA jurisdiction. As a result of such deregulation provisions, virtually all of the Company's gas production is no longer subject to price regulation. Gas which has been removed from price regulation is subject only -25-
10-K40529th Page of 42TOC1stPreviousNextBottomJust 29th
to that price contractually agreed upon between the producer and purchaser. Under current market conditions, deregulated gas prices under recently negotiated contracts tend to be substantially lower than most regulated price ceilings that were previously prescribed by the NGPA. In February 1988, the FERC issued Order No. 490, which promulgated new abandonment regulations for expired, canceled or modified contracts involving the sale of certain gas committed or dedicated to interstate commerce prior to the enactment of the NGPA. The new rules largely eliminate delays and regulatory burdens associated with securing approval to abandon gas service upon termination or expiration of a contract for the sale of such gas. The new rules also significantly facilitate certain pipelines' ability to discontinue purchasing such gas under terms unfavorable to the pipeline in situations in which the contract has expired or terminated, but abandonment authorization is required to terminate the service. The Company has gas purchase agreements with purchasers that have been abandoned pursuant to Order No. 490. Order No. 490 is currently being challenged in the courts. The Company is unable to predict the outcome of these proceedings, and is also unable to predict the consequences to it of any possible future vacation of Order No. 490. Commencing in 1985, the FERC promulgated a series of orders and regulations adopting 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 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. The FERC's actions in these areas have been subject to extensive judicial review and have generated significant industry comment and proposals for modifications to existing regulations. In April 1992 (and clarified in August 1992 and finalized in November 1992), the FERC issued Order 636, a complex regulation which changed gas pipeline operations, services and rates. 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. To the extent the pipeline company or its sales affiliate makes gas sales as a merchant in the future, it will do so in direct competition with all other sellers pursuant to private contracts; however, pipeline companies are not required to remain "merchants" of gas, and many of the interstate pipeline companies have or will become "transporters only." Each pipeline company had to develop the specific terms of service in individual proceedings. The new rules and various pipeline compliance filings are the subject of appeals and resulting remand proceedings concerning certain issues. The Company cannot predict whether and to what extent further FERC remand proceedings and judicial review will affect these matters. 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. 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 status as a gatherer. Further, while some states provide for the rate regulation -26-
10-K40530th Page of 42TOC1stPreviousNextBottomJust 30th
of pipelines engaged in the intrastate transportation of gas, such regulation has not generally been applied against gatherers of gas. The Company's gathering systems could be adversely affected should they be subjected in the future to the application of such state or federal regulation. As a result of Order 636 a number of interstate pipeline companies have (i) "spun down" their gathering systems from regulated pipeline transportation companies to unregulated affiliates, (ii) "spun-off" gathering systems to non- related entities, and/or (iii) "refunctionalized" portions of their pipeline facilities from transmission to gathering. In May 1994 (and clarified in December 1994) FERC ruled that it generally does not have jurisdiction over gathering facilities absent abuse involving the pipeline-affiliate relationship. However, FERC directed pipelines spinning down or off their gathering systems to include certain Order No. 497 standards of conduct in their tariffs and to enter into continuity of service agreements with existing users or to execute a "default contract" with users with whom they cannot reach agreement, with the default contract to contain a minimum two-year term, use the pipeline gatherer's then current rate (with an appropriate escalator clause) for existing customers for similar service, and contain terms and conditions consistent with those applicable to the pipeline's gathering service. In addition, the interstate pipeline must seek authority under Section 7(b) of the NGA to abandon certified gathering facilities and must file for authority under Section 4 of the NGA to terminate gathering service from both certified and uncertified facilities. On appeal, FERC's decisions were generally upheld, except the court held that FERC did not have the authority to require an unregulated entity to implement "default contracts" and therefore remanded this aspect back to FERC. A consequence of this divestiture of gathering facilities could be separate, and higher, gathering fees. 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. EMPLOYEES The Company employs approximately 193 people in its Tulsa office whose functions are associated with management, engineering, geology, land and legal, accounting, financial planning, and administration. In addition, approximately 171 full time employees are responsible for the supervision and operation of its U.S. field activities. The Company also has approximately 136 employees located in South America for the management and operation of its properties in Argentina and Bolivia. The Company believes its relations with its employees are excellent. ITEM 3. LEGAL PROCEEDINGS. On November 5, 1996, the Province of Santa Cruz, Argentina brought suit against Cadipsa 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 -27-
10-K40531st Page of 42TOC1stPreviousNextBottomJust 31st
British Gas, plc for any loss sustained by the Company as a result of this claim. Such indemnification equals approximately $4.0 million of the $10.6 million claim. The Company has no indemnification from its predecessors in title with respect to the payment of royalties on the other two concessions. Although the Company cannot predict the outcome of this litigation, 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 or results of operations. The Company is also a named defendant in various 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, 1996. ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT. The following table sets forth certain information regarding the executive officers of the Company. Officers are elected annually by the Board of Directors and serve at its discretion. [Enlarge/Download Table] NAME AGE POSITION --------------------------- --- ----------------------------------------------------- Charles C. Stephenson, Jr.. 60 Director and Chairman of the Board of Directors Jo Bob Hille............... 55 Director, Vice Chairman of the Board of Directors and Chief Executive Officer S. Craig George............ 44 Director, President and Chief Operating Officer William C. Barnes.......... 42 Director, Executive Vice President, Chief Financial Treasurer and Secretary William L. Abernathy....... 45 Senior Vice President--Acquisitions Robert W. Cox.............. 51 Vice President--General Counsel William E. Dozier.......... 44 Vice President--Operations Michael F. Meimerstorf..... 40 Vice President and Controller Robert E. Phaneuf.......... 50 Vice President--Corporate Development Barry D. Quackenbush....... 55 Vice President--Production Larry W. Sheppard.......... 42 Vice President--International 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 also serves as a Director of AAON, Inc. Mr. Stephenson has a B.S. Degree in Petroleum Engineering from the University of Oklahoma, and has approximately 37 years of oil and gas experience. Mr. Hille, the other co-founder of the Company, has been a Director of the Company since June 1983, Chief Executive Officer of the Company since March 1994 and Vice Chairman of the Company -28-
10-K40532nd Page of 42TOC1stPreviousNextBottomJust 32nd
since September 1995. He was also President of the Company from May 1990 to September 1995, Chief Operating Officer of the Company from April 1987 to March 1994, Executive Vice President of the Company from June 1983 to May 1990 and Treasurer and Secretary of the Company from June 1983 to April 1987. From August 1972 to March 1983, Mr. Hille was employed by Andover where he served at various times primarily as Executive Vice President and Vice President--Operations. Mr. Hille has a B.S. Degree in Petroleum Engineering from the University of Tulsa, and has approximately 31 years of oil and gas experience. Mr. George has been a Director since October 1991, President of the Company since September 1995 and Chief Operating Officer of the Company since March 1994. He was also 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. 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. Abernathy has been Senior Vice President--Acquisitions of the Company since March 1994. He was 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. 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. Dozier has been Vice President--Operations of the Company since May 1992. 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- -29-
10-K40533rd Page of 42TOC1stPreviousNextBottomJust 33rd
Continent and Gulf Coast areas. He has a B.S. Degree in Petroleum Engineering from the University of Texas. 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 joined the Company as Vice President--Corporate Development in 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. Mr. Quackenbush has been Vice President--Production of the Company since May 1990. He was Manager--Production of the Company from November 1989 to May 1990. From May 1970 to July 1989, Mr. Quackenbush was employed by Tenneco Oil Co., an oil and gas company, where he served as Acquisition Manager and in various engineering positions. He has a B.S. Degree in Petroleum Engineering from the Colorado School of Mines. 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. -30-
10-K40534th Page of 42TOC1stPreviousNextBottomJust 34th
PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. The information required by this Item is incorporated by reference from the sections on page 51 of the Company's 1996 Annual Report to Stockholders entitled "Stock Price Information," "Dividend Policy" and "Number of Stockholders." ITEM 6. SELECTED FINANCIAL DATA. The information required by this Item is incorporated by reference from page 25 of the Company's 1996 Annual Report to Stockholders. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The information required by this Item is incorporated by reference from pages 26 through 30 of the Company's 1996 Annual Report to Stockholders. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. The information required by this Item is incorporated by reference from pages 31 through 49 of the Company's 1996 Annual Report to Stockholders. 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 1997 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." -31-
10-K40535th Page of 42TOC1stPreviousNextBottomJust 35th
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 below are incorporated by reference from the following pages of the Company's 1996 Annual Report to Stockholders: Annual Report Page ------------- Consolidated Balance Sheets as of December 31, 1996 and 1995..... 31 Consolidated Statements of Income for the years ended December 31, 1996, 1995 and 1994.............................. 32 Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 1996, 1995 and 1994.......... 33 Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994.............................. 34 Notes to Consolidated Financial Statements for the years ended December 31, 1996, 1995 and 1994.............................. 35 through 48 Report of Independent Public Accountants......................... 49 (2) Financial Statement Schedules: All schedules are omitted as inapplicable or because the required information is contained in the financial statements or included in the footnotes 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 of the Company (Filed as Exhibit 3.1 to the Company's Registration Statement on Form S-1, Registration No. 33-35289 (the "S-1 Registration Statement")). 3.2 Restated By-laws of the Company (Filed as Exhibit 3.2 to 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 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 February 5, 1997, between The Chase Manhattan Bank, as Trustee, and the Company. -32-
10-K40536th Page of 42TOC1stPreviousNextBottomJust 36th
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* Employment and Noncompetition Agreement dated January 7, 1987, between the Company and Jo Bob Hille (Filed as Exhibit 10.20 to the S-1 Registration Statement). 10.3* Employment Agreement dated September 19, 1995, between the Company and Robert E. Phaneuf (Filed as Exhibit 10.3 to the Company's report on Form 10-K for the year ended December 31, 1995, filed April 1, 1996). 10.4* 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). 10.5* 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). 10.6* 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). 10.7* 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). 10.8* 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). 10.9* 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 Credit Agreement dated August 29, 1996, among the Company, as borrower, certain commercial lending institutions, as lenders, and Bank of Montreal, as agent (Filed as Exhibit 10.1 to the Company's report on Form 10-Q for the quarter ended September 30, 1996, filed November 7, 1996). 10.14 First Amendment to Credit Agreement (Exhibit No. 10.13 above) dated October 21, 1996, among the Company, as borrower, certain commercial lending institutions, as lenders, and Bank of Montreal, as agent (Filed as Exhibit 10.2 to the Company's report on Form 10-Q for the quarter ended September 30, 1996, filed November 7, 1996). -33-
10-K40537th Page of 42TOC1stPreviousNextBottomJust 37th
10.15 Second Amendment to Credit Agreement (Exhibit No. 10.13 above) dated January 9, 1997, among the Company, as borrower, certain commercial lending institutions, as lenders, and Bank of Montreal, as agent (Filed as Exhibit 99 to the Company's Registration Statement on Form S-3, Registration No. 333-19569). 10.16 Assignment Agreement dated November 3, 1995, between Shell Compania Argentina de Petroleo S.A. and Vintage Petroleum Argentina, Inc. (Filed as Exhibit 2.1 to the Company's Registration Statement on Form S-3, Registration No. 33-97844 (the "S-3 Registration Statement")). 10.17 Assignment Agreement dated November 3, 1995, between Astra Compania Argentina de Petroleo S.A. and Vintage Petroleum Argentina, Inc. (Filed as Exhibit 2.2 to the S-3 Registration Statement). 10.18 Cadipsa Main Purchase Agreement dated June 2, 1995, between certain shareholders of Cadipsa S.A. listed in Annex 1 thereto and Vintage Petroleum Argentina, Inc. (Filed as Exhibit 2.1 to the Company's report on Form 8-K filed July 20, 1995). 10.19 Purchase Agreement dated June 2, 1995, between certain shareholders of Cadipsa S.A. listed in Annex 1 thereto and Vintage Petroleum, Argentina Inc. (Filed as Exhibit 2.2 to the Company's report on Form 8-K filed July 20, 1995). 10.20 Amended and Restated Investment Agreement dated April 28, 1994, between Cadipsa S.A. and International Finance Corporation ("IFC") (Filed as Exhibit 99.1 to the S-3 Registration Statement). 10.21 Rescheduling, Amendatory and Temporary Guarantee Agreement dated September 28, 1995, between Cadipsa S.A. and the Company and IFC (Filed as Exhibit 99.2 to the S-3 Registration Statement). 10.22 Purchase Agreement dated September 28, 1995, between IFC and Vintage Petroleum Argentina, Inc. (Filed as Exhibit 99.3 to the S-3 Registration Statement). 10.23 British Gas BGA Purchase Agreement dated September 28, 1995, between British Gas plc and Vintage Petroleum Argentina, Inc. (Filed as Exhibit 2.1 to the Company's report on Form 8-K filed October 4, 1995). 13. Portions of the Company's 1996 Annual Report to Stockholders. 21. Subsidiaries of the Company. 23.1 Consent of Arthur Andersen LLP. 23.2 Consent of Netherland, Sewell & Associates, Inc. 27. Financial Data Schedule. 99.1 Letter of Netherland, Sewell & Associates, Inc. dated March 17, 1997, regarding U.S. oil and gas reserve information. 99.2 Letter of Netherland, Sewell & Associates, Inc. dated March 24, 1997, regarding South American oil and gas reserve information. ----------------------- -34-
10-K40538th Page of 42TOC1stPreviousNextBottomJust 38th
* Management contract or compensatory plan or arrangement. (b) Reports on Form 8-K. No reports on Form 8-K were filed during the fourth quarter of the fiscal year ended December 31, 1996. -35-
10-K40539th Page of 42TOC1stPreviousNextBottomJust 39th
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 27, 1997 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: [Enlarge/Download Table] SIGNATURE TITLE DATE --------- ----- ---- /s/ C. C. Stephenson, Jr. Director and Chairman of the Board March 27, 1997 ---------------------------- C. C. Stephenson, Jr. /s/ Jo Bob Hille Director, Vice Chairman of the March 27, 1997 ---------------------------- Board and Chief Executive Officer Jo Bob Hille (Principal Executive Officer) /s/ S. Craig George Director, President and March 27, 1997 ---------------------------- Chief Operating Officer S. Craig George /s/ William C. Barnes Director, Executive Vice President, March 27, 1997 ---------------------------- Chief Financial Officer and William C. Barnes Treasurer (Principal Financial Officer) /s/ Bryan H. Lawrence Director March 27, 1997 ---------------------------- Bryan H. Lawrence /s/ John T. McNabb, II Director March 27, 1997 ---------------------------- John T. McNabb, II /s/ Michael F. Meimerstorf Vice President and Controller March 27, 1997 ---------------------------- (Principal Accounting Officer) Michael F. Meimerstorf -36-
10-K40540th Page of 42TOC1stPreviousNextBottomJust 40th
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 of the Company (Filed as Exhibit 3.1 to the Company's Registration Statement on Form S-1, Registration No. 33-35289 (the "S-1 Registration Statement")). 3.2 Restated By-laws of the Company (Filed as Exhibit 3.2 to 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 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 February 5, 1997, between The Chase Manhattan Bank, as Trustee, and the Company. 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* Employment and Noncompetition Agreement dated January 7, 1987, between the Company and Jo Bob Hille (Filed as Exhibit 10.20 to the S-1 Registration Statement). 10.3* Employment Agreement dated September 19, 1995, between the Company and Robert E. Phaneuf (Filed as Exhibit 10.3 to the Company's report on Form 10-K for the year ended December 31, 1995, filed April 1, 1996). 10.4* 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). 10.5* 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). 10.6* 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). 10.7* 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-K40541st Page of 42TOC1stPreviousNextBottomJust 41st
10.8* 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). 10.9* 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 Credit Agreement dated August 29, 1996, among the Company, as borrower, certain commercial lending institutions, as lenders, and Bank of Montreal, as agent (Filed as Exhibit 10.1 to the Company's report on Form 10-Q for the quarter ended September 30, 1996, filed November 7, 1996). 10.14 First Amendment to Credit Agreement (Exhibit No. 10.13 above) dated October 21, 1996, among the Company, as borrower, certain commercial lending institutions, as lenders, and Bank of Montreal, as agent (Filed as Exhibit 10.2 to the Company's report on Form 10-Q for the quarter ended September 30, 1996, filed November 7, 1996). 10.15 Second Amendment to Credit Agreement (Exhibit No. 10.13 above) dated January 9, 1997, among the Company, as borrower, certain commercial lending institutions, as lenders, and Bank of Montreal, as agent (Filed as Exhibit 99 to the Company's Registration Statement on Form S-3, Registration No. 333-19569). 10.16 Assignment Agreement dated November 3, 1995, between Shell Compania Argentina de Petroleo S.A. and Vintage Petroleum Argentina, Inc. (Filed as Exhibit 2.1 to the Company's Registration Statement on Form S-3, Registration No. 33-97844 (the "S-3 Registration Statement")). 10.17 Assignment Agreement dated November 3, 1995, between Astra Compania Argentina de Petroleo S.A. and Vintage Petroleum Argentina, Inc. (Filed as Exhibit 2.2 to the S-3 Registration Statement). 10.18 Cadipsa Main Purchase Agreement dated June 2, 1995, between certain shareholders of Cadipsa S.A. listed in Annex 1 thereto and Vintage Petroleum Argentina, Inc. (Filed as Exhibit 2.1 to the Company's report on Form 8-K filed July 20, 1995). 10.19 Purchase Agreement dated June 2, 1995, between certain shareholders of Cadipsa S.A. listed in Annex 1 thereto and Vintage Petroleum, Argentina Inc. (Filed as Exhibit 2.2 to the Company's report on Form 8-K filed July 20, 1995). 10.20 Amended and Restated Investment Agreement dated April 28, 1994, between Cadipsa S.A. and International Finance Corporation ("IFC") (Filed as Exhibit 99.1 to the S-3 Registration Statement).
10-K405Last Page of 42TOC1stPreviousNextBottomJust 42nd
10.21 Rescheduling, Amendatory and Temporary Guarantee Agreement dated September 28, 1995, between Cadipsa S.A. and the Company and IFC (Filed as Exhibit 99.2 to the S-3 Registration Statement). 10.22 Purchase Agreement dated September 28, 1995, between IFC and Vintage Petroleum Argentina, Inc. (Filed as Exhibit 99.3 to the S-3 Registration Statement). 10.23 British Gas BGA Purchase Agreement dated September 28, 1995, between British Gas plc and Vintage Petroleum Argentina, Inc. (Filed as Exhibit 2.1 to the Company's report on Form 8-K filed October 4, 1995). 13. Portions of the Company's 1996 Annual Report to Stockholders. 21. Subsidiaries of the Company. 23.1 Consent of Arthur Andersen LLP. 23.2 Consent of Netherland, Sewell & Associates, Inc. 27. Financial Data Schedule. 99.1 Letter of Netherland, Sewell & Associates, Inc. dated March 17, 1997, regarding U.S. oil and gas reserve information. 99.2 Letter of Netherland, Sewell & Associates, Inc. dated March 24, 1997, regarding South American oil and gas reserve information. --------------------------- * Management contract or compensatory plan or arrangement.

Dates Referenced Herein   and   Documents Incorporated by Reference

Referenced-On Page
This ‘10-K405’ Filing    Date First  Last      Other Filings
2/1/095
2/1/025
12/31/002410-K
5/13/971DEF 14A,  PRE 14A
4/1/9758-K
Filed on:3/27/9739DEF 14A
3/24/973742
3/17/97142
2/5/97540
1/9/973741
1/7/979
1/1/975
For Period End:12/31/96138
11/20/969
11/7/96364110-Q
11/5/9630
10/21/963641
9/30/96364110-Q
8/29/963641
4/1/963641
3/15/963641
1/31/968
1/16/963540
12/31/951440
12/27/958
12/20/953540
11/30/958
11/3/953741
10/4/953742
9/29/958
9/28/953742
9/19/953640
7/20/953741
7/5/958
6/2/953741
1/1/9530
12/31/941435
4/28/943741
3/29/943640
2/24/943640
1/1/94612
12/31/933640
3/31/933641
3/1/9319
1/7/9328
1/1/9328
12/31/923641
7/1/9227
3/30/923640
 List all Filings 
Top
Filing Submission 0000930661-97-000709   –   Alternative Formats (Word / Rich Text, HTML, Plain Text, et al.)

Copyright © 2018 Fran Finnegan & Company.  All Rights Reserved.
AboutPrivacyRedactionsHelp — Sat., Nov. 17, 2:04:40.1am ET