-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, JBdzSnBfE1NnN2zIgDvfNtRrqKddmcQpW5UHLJdN+uAIGJ2MMV9qqDImyKaNaY2K ikc8UHmPUahRmk/oQ3FUoQ== 0000950152-95-002253.txt : 19951004 0000950152-95-002253.hdr.sgml : 19951004 ACCESSION NUMBER: 0000950152-95-002253 CONFORMED SUBMISSION TYPE: S-4/A PUBLIC DOCUMENT COUNT: 8 FILED AS OF DATE: 19951003 SROS: NASD FILER: COMPANY DATA: COMPANY CONFORMED NAME: BENTON OIL & GAS CO CENTRAL INDEX KEY: 0000845289 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 770196707 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: S-4/A SEC ACT: 1933 Act SEC FILE NUMBER: 033-61299 FILM NUMBER: 95578441 BUSINESS ADDRESS: STREET 1: 1145 EUGENIA PL STREET 2: STE 200 CITY: CARPINTERIA STATE: CA ZIP: 93013 BUSINESS PHONE: 8055665600 MAIL ADDRESS: STREET 1: 300 ESPLANADE DRIVE SUITE 2000 CITY: OXNARD STATE: CA ZIP: 93030 S-4/A 1 BENTON OIL AND GAS COMPANY S-4/A 1 As filed with the Securities and Exchange Commission on October 3, 1995 Registration No. 33-61299 ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ----------------- AMENDMENT NO. 1 TO FORM S-4 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 BENTON OIL AND GAS COMPANY (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) DELAWARE 1311 77-0196707 (State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer of Incorporation or Classification Code) Identification Number) organization) --------------------------------------- 1145 EUGENIA PLACE SUITE 200 CARPINTERIA, CALIFORNIA 93013 (805) 566-5600 (ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER, INCLUDING AREA CODE OF REGISTRANT'S PRINCIPAL EXECUTIVE OFFICES) ----------------- WITH COPIES TO: Jack A. Bjerke Emens, Kegler, Brown, Hill & Ritter Co., L.P.A. 65 East State Street, Suite 1800 Columbus, Ohio 43215 (614) 462-5400 APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as practicable after the effective date of this Registration Statement. If the securities being registered on this Form are to be offered in connection with the formation of a holding company and there is compliance with General Information G, check the following box. / / CALCULATION OF REGISTRATION FEE
Proposed Maximum Proposed Maximum Title of Each Class of Amount to be Offering Price Per Aggregate Offering Amount of Securities to be Registered Registered Share Price Registration Fee - --------------------------------------------------------------------------------------------------------------------- Common Stock, par value $.01 per share 189,068(1) $10.806377 $9,084,683(2) $3,133(2) - --------------------------------------------------------------------------------------------------------------------- Warrants to purchase shares of Common Stock 651,610(1) (3) (3) (3) - --------------------------------------------------------------------------------------------------------------------- Common Stock Underlying Warrants 651,610 (4) (4) (4) - --------------------------------------------------------------------------------------------------------------------- (1) The Registrant has registered shares of Common Stock and Warrants in excess of the aggregate number of shares of Common Stock and Warrants offered in the Exchange. The Registration Statement includes additional shares of Common Stock and Warrants equal to 10% of the aggregate shares of Common Stock and Warrants offered in the Exchange to cover Common Stock and Warrants which could be issuable in connection with the exercise of dissenters' rights by California investors. (2) This Registration Statement relates to securities of the Registrant to be issued in exchange for partnership interests in the Benton Oil & Gas Combination Partnership 1989-1, L.P., a California limited partnership (the "1989-1 Partnership"), Benton Oil and Gas Combination Partnership 1990-1, L.P., a California limited partnership (the "1990-1 Partnership") and the Benton Oil & Gas Combination Partnership 1991-1, (the "1991-1 Partnership:) (collectively referred to as the "Partnerships"). Pursuant to Rule 457(f)(2), the offering price per share, aggregate offering price and registration fee is calculated based on the book value as of June 30, 1995 of a unit of partnership interest in the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership of approximately $1,170, $892 and $1,140, respectively. There were 281.8182, 1,419.192 and 281.8182 partnership units outstanding in the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership, respectively, with an aggregate book value of $1,916,973. Pursuant to Rule 457(i), the offering price per share, aggregate offering price and registration fee additionally includes the maximum amount of consideration which could be received by the Registrant upon exercise of the Warrants, which have an exercise price of $11.00, per share, with an aggregate maximum amount of consideration payable equal to $7,167,710. Of the Registration Fee, the Registrant paid $2,491 upon the initial filing of the Registration Statement on July 25, 1995. (3) The offering price per share, aggregate offering price and registration fee related to the Warrants are included in the calculations for Common Stock, above, as permitted by Rule 457(f)(2). (4) Pursuant to Rule 457(i), no additional fees are payable for registering the Common Stock underlying the Warrants.
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT THAT SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF THE SECURITIES ACT OF 1933 OR UNTIL THIS REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(A), MAY DETERMINE. ================================================================================ 2 CROSS REFERENCE SHEET Pursuant to Item 501(b) of Regulation S-K Showing Location in Prospectus of the Information Required by Part I of Form S-4.
Form S-4 Item Location in Prospectus ------------- ---------------------- A. Information About the Transaction 1. Forepart of Registration Statement and Outside Front Cover Page of Prospectus................................ Forepart of the Registration Statement; Outside Front Cover Page 2. Inside Front and Outside Back Cover Pages of Prospectus. Table of Contents; Available Information; Information Concerning Benton; Additional Information 3. Risk Factors, Ratio of Earnings to Fixed Charges and Other Information....................................... Summary; Risk Factors and Material Considerations 4. Terms of the Transaction................................ Summary; The Exchange Offer and Proposal; Method of Determining Exchange Values; Reasons for the Exchange Offer; Consent Procedures; Comparative Rights of Security Holders; Certain Federal Tax Consequences 5. Pro Forma Financial Information......................... Pro Forma Financial Information; Pro Forma Disclosure about Oil and Gas Activities; Pro Forma Combined Estimated Quantities of Oil and Gas Reserves; Pro Forma Oil and Gas Information 6. Material Contacts with the Company Being Acquired....... Summary; The Exchange Offer and Proposal; Method of Determining Exchange Values; Reasons for the Exchange Offer; Information Concerning 1989-1 Partnership; Information Concerning 1990-1 Partnership; Information Concerning 1991-1 Partnership 7. Additional Information Required for the offering by Persons and Parties Deemed to be Underwriters........... Not applicable 8. Interests of Named Experts and Counsel.................. Summary; The Exchange Offer and Proposal; Legal Matters; Experts
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Form S-4 Item Location in Prospectus ------------- ---------------------- 9. Disclosure of Commission Position on Indemnification for Securities Act Liabilities.......................... Not Applicable B. Information About the Registrant 10. Information with Respect to S-3 Registrants............. Available Information; Incorporation of Certain Documents by Reference; Summary; Risk Factors and Material Considerations; Price Range of Common Stock, Dividends and Distributions; Background of Exchange Offer; The Exchange Offer and Proposal; Reasons for the Exchange Offer; Failure to Approve the Proposals; Comparative Rights of Security Holders; Pro Forma Financial Information; Information Concerning Benton; Description of Securities 11. Incorporation of Certain Information by Reference....... Incorporation of Certain Documents by Reference 12. Information with Respect to S-2 or S-3 Registrants...... Not Applicable 13. Incorporation of Certain Information by Reference....... Not Applicable 14. Information with Respect to Registrant Other than S-3 of S-2 Registrants...................................... Not Applicable C. Information About the Company Being Acquired 15. Information with Respect to S-3 Companies............... Not Applicable 16. Information with Respect to S-2 or S-3 Companies........ Not Applicable 17. Information with Respect to Companies other than S-3 or S-2..................................................... Summary; Price Range of Common Stock, Dividends and Distributions; Background of Exchange offer; The Exchange Offer and Proposal; Method of Determining Exchange Values; Reasons for the Exchange Offer; Failure to Approve the Proposals; Comparative Rights of Security Holders; Information Concerning 1989-1 Partnership; Information Concerning 1990-1 Partnership; Information Concerning 1991-1 Partnership; Financial Statements of 1990-1 Partnership; Financial Statements of 1991-1 Partnership
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Form S-4 Item Location in Prospectus ------------- ---------------------- D. Voting and Management Information 18. Information if Proxies, Consents or Authorizations are to Be Solicited......................................... Not Applicable 19. Information if Proxies, Consents of Authorizations are not to be Solicited or in an Exchange Offer............. Summary; The Exchange Offer; Consent Procedures; Information Concerning Benton; Information Concerning 1989-1 Partnership; Information Concerning 1990-1 Partnership; Information Concerning 1991-1 Partnership
5 SUBJECT TO COMPLETION DATED OCTOBER 3, 1995 EXCHANGE OFFER AN AGGREGATE OF 171,880 SHARES OF COMMON STOCK AND WARRANTS TO PURCHASE AN AGGREGATE OF 592,373 SHARES OF COMMON STOCK FOR PARTNERSHIP UNITS IN BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P. (281.8182 PARTNERSHIP UNITS) BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P. (1,419.192 PARTNERSHIP UNITS) AND BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P. (281.8182 PARTNERSHIP UNITS) ------------- EXCHANGE RATIO: 107 SHARES OF COMMON STOCK AND 35 WARRANTS PER 1989-1 PARTNERSHIP UNIT 81 SHARES OF COMMON STOCK AND 334 WARRANTS PER 1990-1 PARTNERSHIP UNIT 95 SHARES OF COMMON STOCK AND 385 WARRANTS PER 1991-1 PARTNERSHIP UNIT This Prospectus (the "Prospectus") and accompanying Supplement is being furnished to the Investors ("Investors") in the Benton Oil & Gas Combination Partnership 1989-1, L.P., a California limited partnership (the "1989-1 Partnership"), the Benton Oil & Gas Combination Partnership 1990-1, L.P., a California limited partnership (the "1990-1 Partnership") and the Benton Oil & Gas Combination Partnership 1991-1, L.P., a California limited partnership (the "1991-1 Partnership") (collectively, the "Partnerships"), in connection with the offer by Benton Oil and Gas Company, a Delaware corporation and the managing general partner of each of the Partnerships ("Benton," or "Company," or "Managing General Partner") to exchange shares of Common Stock, $.01 par value of Benton ("Common Stock") and Warrants ("Warrants") to purchase shares of Common Stock of Benton (the "Exchange Offer") for all of the right, title and interest to units of Partnership interest in each of the Partnerships ("Partnership Units") held by Investors, at the exchange rate outlined below. Benton is offering to exchange shares of Common Stock and Warrants to owners of Partnership Units in the 1989-1 Partnership ("1989-1 Units"), the 1990-1 Partnership (the "1990-1 Units") and the 1991-1 Partnership (the "1991-1 Units") on the basis of $5,000.00 original investment on the terms and in the amounts set forth herein. See "Exchange Offer and Proposal" at page 51 and "Method of Determining Exchange Values" at page 58. The Warrants to be issued in connection with the Exchange Offer are execrable at a price of $11.00 per share and will expire three years form the date of issuance. For detailed information regarding the determination of the Total Exchange Values for each of the Partnerships, see "Method of Determining Exchange Values." On October 2, 1995, the last reported sales price of the Common Stock, as reported on NASDAQ National Market, was $ 11.13. In connection with the Exchange Offer, Benton is submitting Proposals to Investors in each of the Partnerships to amend the respective Partnership Agreements to provide for the transfer of all of the assets and liabilities of the Partnerships to Benton as of the December 31, 1994 Effective Date in exchange for Common Stock and Warrants in the amounts set forth herein and the pro rata distribution of such consideration in liquidation of the Partnerships. Each Investor who tenders his Partnership Units pursuant to the Exchange Offer will, by that tender, consent to the Proposal. 6 ADOPTION OF EACH OF THE PROPOSALS REQUIRES THE CONSENT OF INVESTORS OF SUCH PARTNERSHIP HOLDING 75% OR MORE OF THE PARTNERSHIP UNITS. IF INVESTORS IN A PARTNERSHIP HOLDING 75% OR MORE OF THE PARTNERSHIP UNITS ACCEPT THE EXCHANGE OFFER AND CONSENT TO THE PROPOSAL, ALL NON-DISSENTING HOLDERS OF UNITS IN THAT PARTNERSHIP WILL BE BOUND BY THE TERMS OF THE EXCHANGE AND PROPOSAL AND WILL RECEIVE THE NUMBER OF SHARES OF COMMON STOCK AND WARRANTS DESCRIBED HEREIN. DISSENTING HOLDERS WILL BE BOUND BY THE EXCHANGE OFFER AND WILL RECEIVE THE NUMBER OF SHARES OF COMMON STOCK AND WARRANTS COMPUTED IN ACCORDANCE WITH CALIFORNIA DISSENTERS' RIGHTS STATUTES. EACH OF THE EXCHANGE OFFERS TO THE PARTNERSHIPS IS INDEPENDENT OF THE EXCHANGE OFFER TO THE OTHER PARTNERSHIPS. THE EXCHANGE WILL ONLY BE CONSUMMATED FOR THOSE PARTNERSHIPS IN WHICH THE PROPOSAL HAS BEEN APPROVED BY THE INVESTORS. BENTON OIL AND GAS COMPANY, IN ADDITION TO BEING MANAGING GENERAL PARTNER OF THE THREE PARTNERSHIPS, OWNS 2.8182 1989-1 UNITS, 14.192 1990-1 UNITS AND 2.8182 1991-1 UNITS AND WILL VOTE SUCH UNITS THE SAME AS A MAJORITY OF INVESTORS VOTE THEIR UNITS. INVESTORS WILL RECEIVE THE CONSIDERATION SET FORTH HEREIN, AND THE RESPECTIVE PARTNERSHIP WILL BE DISSOLVED. ASSUMING CONSUMMATION OF THE EXCHANGE OFFER, ALL OF THE INVESTORS IN A PARTNERSHIP WHICH HAS APPROVED THE PROPOSAL PRESENTED TO SUCH PARTNERSHIP, WHETHER OR NOT THEY TENDER THEIR UNITS AND THUS VOTE IN FAVOR OF THE PROPOSAL, WILL RECEIVE THE SAME NUMBER OF SHARES OF COMMON STOCK AND WARRANTS AS THEY WOULD HAVE RECEIVED HAD THEY TENDERED THEIR PARTNERSHIP UNITS AND THE RESPECTIVE PARTNERSHIP WILL BE DISSOLVED. THE EXCHANGE OFFER INVOLVES VARIOUS RISKS THAT SHOULD BE CONSIDERED BY INVESTORS. SEE "RISK FACTORS AND MATERIAL CONSIDERATIONS," BEGINNING ON PAGE 34 OF THIS PROSPECTUS. IN PARTICULAR, INVESTORS SHOULD CONSIDER THE FOLLOWING FACTORS: - INVESTORS HAVE RECEIVED CASH DISTRIBUTIONS FROM THE PARTNERSHIPS, BUT WILL RECEIVE NO CASH DISTRIBUTIONS OR DIVIDENDS IN THE FORESEEABLE FUTURE FROM BENTON. - THE MARKET PRICE OF THE COMMON STOCK COULD DECLINE BELOW THE MARKET PRICE USED FOR CALCULATION OF THE RESPECTIVE EXCHANGE RATES, EXPOSING INVESTORS TO A REDUCED RETURN ON THEIR INVESTMENT. - THE EXCHANGE VALUE OF THE PARTNERSHIP UNITS WAS DETERMINED BY BENTON, WHICH HAS INHERENT CONFLICTS OF INTEREST, AND MAY NOT REFLECT THE VALUE OF THE NET ASSETS OF THE RESPECTIVE PARTNERSHIP IF SOLD TO AN UNAFFILIATED THIRD PARTY IN AN ARM'S LENGTH TRANSACTION. - BENTON HAS ATTRIBUTED A PRESENT VALUE TO THE WARRANTS, USING THE BLACK-SCHOLES OPTION PRICING MODEL. HOWEVER, THE ACTUAL VALUE, IF ANY, A HOLDER MAY REALIZE FROM THE WARRANTS WILL DEPEND ON THE EXCESS OF THE MARKET PRICE OF THE COMMON STOCK OVER THE EXERCISE PRICE OF THE WARRANT ON THE DATE THE WARRANT IS EXERCISED. - BENTON'S DETERMINATIONS OF THE RESPECTIVE EXCHANGE VALUES WERE BASED PRIMARILY ON THE ESTIMATED PRESENT VALUE OF EACH PARTNERSHIP'S PROVED OIL AND GAS RESERVES, WHICH INVOLVES MANY UNCERTAINTIES AND COULD RESULT IN AN UNDERVALUATION OF PARTNERSHIP UNITS. ALTHOUGH SUPPORTED BY AN INDEPENDENT OFFER FOR THE PURCHASE OF SUBSTANTIALLY ALL OF THE ASSETS OF EACH OF THE PARTNERSHIPS, THERE CAN BE NO ASSURANCE THAT THE RESPECTIVE EXCHANGE VALUES REPRESENT THE VALUE THE PARTNERSHIPS COULD RECEIVE IN THE SALE OF THE ASSETS OF THE PARTNERSHIP. 7 - THE ALTERNATIVES OF CONTINUING THE PARTNERSHIPS OR LIQUIDATING THEIR ASSETS COULD POTENTIALLY BE MORE BENEFICIAL TO INVESTORS THAN THE EXCHANGE OFFER. - NO INDEPENDENT REPRESENTATIVE WAS ENGAGED TO REPRESENT THE UNAFFILIATED INVESTORS IN NEGOTIATING THE TERMS OF THE EXCHANGE OFFER, WHICH MAY BE INFERIOR TO THOSE THAT COULD HAVE BEEN NEGOTIATED BY AN INDEPENDENT REPRESENTATIVE. - INVESTORS HAVE NO DISSENTER'S RIGHTS IN THE EXCHANGE OFFER, OTHER THAN LIMITED DISSENTERS' RIGHTS FOR CALIFORNIA RESIDENTS, AND THEREFORE CANNOT ELECT TO RECEIVE CASH FOR THEIR PARTNERSHIP UNITS. - OWNERSHIP OF COMMON STOCK MAY INVOLVE GREATER RISK THAN AN INVESTMENT IN THE PARTNERSHIP UNITS BECAUSE OF BENTON'S BROADER OPERATIONS, INCLUDING FOREIGN OPERATIONS, AND ITS USE OF DEBT TO FINANCE ONGOING OPERATIONS. - FUTURE EQUITY OFFERINGS BY BENTON COULD POTENTIALLY BE DILUTIVE TO INVESTORS HOLDING COMMON STOCK OR WARRANTS. The Exchange may be withdrawn at any time prior to its scheduled expiration date if Benton reasonably determines that a material change affecting the Partnerships or the Company has occurred. THE EXCHANGE WILL ONLY BE CONSUMMATED FOR THOSE PARTNERSHIPS IN WHICH THE PROPOSAL HAS BEEN APPROVED BY THE INVESTORS. The assets and liabilities of any Partnership which approves the respective Proposal and adopts the Exchange Offer will be transferred to Benton effective as of December 31, 1994 (the "Effective Date"). THE EXCHANGE OFFER EXPIRES AT 5:00 P.M. PACIFIC TIME ON ____________, 1995 UNLESS EXTENDED. -------------------------------- This Prospectus also constitutes the prospectus of Benton with respect to the shares of Common Stock and Warrants to be issued as consideration in the Exchange Offer. Benton has filed a Registration Statement on Form S-4 (together with any amendments thereto, the "Registration Statement") with the Securities and Exchange Commission (the "SEC"), of which this Prospectus and Supplement are a part. THE SHARES OF COMMON STOCK AND WARRANTS TO BE ISSUED IN CONNECTION WITH THE EXCHANGE HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. The approximate date on which this Prospectus and the accompanying Supplement will first be mailed to the Investors of the Partnerships is __________, 1995. THE DATE OF THIS PROSPECTUS IS ____________, 1995. 8 AVAILABLE INFORMATION Benton is subject to the informational requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and in accordance therewith files reports, proxy statements and other information with the SEC. The reports, proxy statements and other information filed by Benton with the SEC can be inspected and copied at the public reference facilities maintained by the SEC at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549, and should be available at the SEC's regional offices at 7 World Trade Center, New York, New York 10048, and 500 West Madison Street, 14th Floor, Chicago, Illinois 60661. Copies of such material may be obtained at prescribed rates from the Public Reference Section of the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549. The Common Stock is quoted on the National Association of Securities Dealers, Inc. Automated Quotation System/National Market System ("NASDAQ-NMS"), and certain of Benton's reports, proxy materials and other information may be available for inspection at the offices of the National Association of Securities Dealers, Inc., 1735 K Street, N.W., Washington, D.C. 20006. Benton has filed the Registration Statement with the SEC under the Securities Act of 1933, as amended (the "Securities Act"), with respect to the Common Stock and Warrants to be issued in connection with the Exchange. This Prospectus does not contain all of the information set forth in the Registration Statement and the exhibits thereto, certain parts of which are omitted in accordance with the rules and regulations of the SEC. Such additional information may be obtained from the SEC's principal office in Washington, D.C. INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE The following documents, heretofore filed by Benton with the SEC pursuant to the Exchange Act, are hereby incorporated by reference, except as superseded or modified herein (i) Benton's Annual Report on Form 10-K for the fiscal year ended December 31, 1994, as amended on Forms 10-K/A on May 2, 1995 and July 11, 1995; (ii) Benton's quarterly report on Form 10-Q for the quarter ended March 31, 1995; (iii) Benton's quarterly report on Form 10-Q for the quarter ended June 30, 1995; (vi) Benton's Current Report on Form 8-K filed on April 17, 1995; (v) Benton's Current Report on Form 8-K filed May 31, 1995; (vi) Benton's Registration Statement on Form 8-A filed on May 4, 1995, effective May 19, 1995; and (vii) the description of Common Stock set forth in Benton's Registration Statements and amendments filed pursuant to the Exchange Act on March 17, 1989, May 14, 1991 and May 15, 1992. All documents and reports filed by Benton with the SEC pursuant to Section 13(a), 13(c), 14 or 15(d) of the Exchange Act after the date of this Prospectus and prior to the date of consummation of the transaction and expiration of the Exchange Offer shall be deemed to be incorporated by reference in this Prospectus and to be a part hereof from the dates of filing of such documents or reports. Any statement contained in a document incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded for purposes of this Prospectus to the extent that a statement contained herein or in any other subsequently filed document which also is or is deemed to be incorporated by reference herein modifies or supersedes such statement. Any such statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this Prospectus. i 9 THIS PROSPECTUS INCORPORATES DOCUMENTS BY REFERENCE WHICH ARE NOT PRESENTED HEREIN OR DELIVERED HEREWITH. SUCH DOCUMENTS (OTHER THAN EXHIBITS TO SUCH DOCUMENTS, UNLESS SUCH EXHIBITS ARE SPECIFICALLY INCORPORATED BY REFERENCE TO SUCH DOCUMENTS) ARE AVAILABLE, WITHOUT CHARGE, TO ANY PERSON, INCLUDING ANY BENEFICIAL OWNER, TO WHOM THIS PROSPECTUS IS DELIVERED, ON WRITTEN OR ORAL REQUEST TO: BENTON OIL AND GAS COMPANY, 1145 EUGENIA PLACE, SUITE 200, CARPINTERIA, CALIFORNIA 93013, ATTENTION: CORPORATE SECRETARY, TELEPHONE (805) 566-5600. IN ORDER TO ENSURE DELIVERY OF THE DOCUMENTS PRIOR TO THE EXPIRATION OF THE EXCHANGE OFFER, REQUESTS MUST BE RECEIVED BY ________, 1995. No person is authorized to give any information or to make any representation not contained in this Prospectus or in the documents incorporated herein by reference in connection with the solicitation and the offering made hereby and, if given or made, such information or representation should not be relied upon as having been authorized by Benton. This Prospectus does not constitute an offer to sell, or a solicitation of an offer to purchase, the securities offered by this Prospectus, or the solicitation of a tender from any person, in any jurisdiction in which it is unlawful to make such offer, solicitation of an offer or tender solicitation. Neither the delivery of this Prospectus nor any distribution of the securities made under this Prospectus shall, under any circumstances, create an implication that there has been no change in the affairs of Benton and the Partnerships since the date of this Prospectus other than as set forth in the documents incorporated herein by reference. ii 10 TABLE OF CONTENTS SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Risk Factors and Material Considerations . . . . . . . . . . . . . . . . . . . . 1 The Parties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 The Exchange Offer and Proposals . . . . . . . . . . . . . . . . . . . . . . . . 5 Background and Alternatives to the Exchange . . . . . . . . . . . . . . . . . . . 7 Reasons for the Exchange Offer; Recommendation of the Managing General Partner . . 11 Managing General Partners Determination that Offer is Fair . . . . . . . . . . . 13 Summary of Tax Consequences . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Accounting Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Request For Investor Listing . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Business of Benton and the Partnerships After the Consummation of the Exchange . . 16 Comparative Rights of Security Holders . . . . . . . . . . . . . . . . . . . . . 16 Dissenters' Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Resales of Benton Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . 17 Description of the Warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Method of Determining Exchange Value for 1989-1 Partnership. . . . . . . . . . . . 18 Method of Determining Exchange Value for 1990-1 Partnership. . . . . . . . . . . . 20 Method of Determining Exchange Value for 1991-1 Partnership. . . . . . . . . . . . 24 Consent Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Conditions to Exchange . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Regulatory Approvals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Certain Historical and Pro Forma Financial Data . . . . . . . . . . . . . . . . . 27 Certain Comparative Information . . . . . . . . . . . . . . . . . . . . . . . . . 33 RISK FACTORS AND MATERIAL CONSIDERATIONS . . . . . . . . . . . . . . . . . . . . . . . 34 Risks Related to the Exchange Offer . . . . . . . . . . . . . . . . . . . . . . . 34 Risks Related to Benton . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 Risks Related to the Oil and Gas Industry . . . . . . . . . . . . . . . . . . . . 41 PRICE RANGE OF COMMON STOCK, DIVIDENDS AND DISTRIBUTIONS . . . . . . . . . . . . . . . 43 BACKGROUND OF EXCHANGE OFFER . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 1989-1 Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 1990-1 Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 1991-1 Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 Goldking Offer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 THE EXCHANGE OFFER AND PROPOSAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 Description of the Exchange Offer . . . . . . . . . . . . . . . . . . . . . . . . 51 The Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 Dissenters' Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 Distribution of Common Stock and Warrants . . . . . . . . . . . . . . . . . . . . 53 Election to Receive Cash In Lieu of Common Stock . . . . . . . . . . . . . . . . 53 Interests of Certain Persons in the Exchange and Proposals . . . . . . . . . . . 54 Resale of Benton Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . 54
iii 11 Fractional Shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 Stock Exchange Listing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 Accounting Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 Closing Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 Operations After the Exchange . . . . . . . . . . . . . . . . . . . . . . . . . . 55 Expenses; Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 Benton's Dividend Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 Litigation and Related Matters . . . . . . . . . . . . . . . . . . . . . . . . . 56 METHOD OF DETERMINING EXCHANGE VALUES . . . . . . . . . . . . . . . . . . . . . . . . . 58 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 1989-1 Partnership Exchange Value Components . . . . . . . . . . . . . . . . . . . 59 1990-1 Partnership Exchange Value Components . . . . . . . . . . . . . . . . . . . 60 1991-1 Partnership Exchange Value Components . . . . . . . . . . . . . . . . . . . 63 RECOMMENDATION OF THE MANAGING GENERAL PARTNER . . . . . . . . . . . . . . . . . . . . 65 Managing General Partner's Reasons for Proposing the Exchange Offer . . . . . . . 65 Managing General Partner's Determination that Exchange Offer is Fair . . . . . . 68 Benefits of Continued Operations . . . . . . . . . . . . . . . . . . . . . . . . 72 Benefits of Liquidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 Lack of Independent Representative . . . . . . . . . . . . . . . . . . . . . . . 82 Board of Directors of Benton; Benton's Reasons for the Exchange . . . . . . . . . 83 Fiduciary Duties of Benton . . . . . . . . . . . . . . . . . . . . . . . . . . . 83 Access to Investor List and Program Records. . . . . . . . . . . . . . . . . . . 84 FAILURE TO APPROVE THE PROPOSALS . . . . . . . . . . . . . . . . . . . . . . . . . . . 84 CONSENT PROCEDURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85 Written Consent and Vote Required . . . . . . . . . . . . . . . . . . . . . . . . 85 Consent Tabulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85 Expiration of Exchange Offer . . . . . . . . . . . . . . . . . . . . . . . . . . 85 Amount Tendered . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85 Revocability of Tenders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85 Solicitation of Letters of Transmittal . . . . . . . . . . . . . . . . . . . . . 86 Acceptance of Tenders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86 Special Requirements for Certain Investors . . . . . . . . . . . . . . . . . . . 86 Representations and Covenants . . . . . . . . . . . . . . . . . . . . . . . . . . 87 Validity of Tenders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87 Payments of Fees and Expenses . . . . . . . . . . . . . . . . . . . . . . . . . . 87 Compliance with Tender Offer Practices . . . . . . . . . . . . . . . . . . . . . 88 CERTAIN FEDERAL TAX CONSEQUENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . 89 Tax Consequences of the Exchange . . . . . . . . . . . . . . . . . . . . . . . . 89 Realization of Suspended Passive Losses . . . . . . . . . . . . . . . . . . . . . 90 Basis in Stock and Warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . 90 COMPARATIVE RIGHTS OF SECURITY HOLDERS . . . . . . . . . . . . . . . . . . . . . . . . 91 UNAUDITED PRO FORMA FINANCIAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . 99 INFORMATION CONCERNING BENTON . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106
iv 12 Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106 Recent Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112
v 13 INFORMATION CONCERNING 1989 - 1 PARTNERSHIP . . . . . . . . . . . . . . . . . . . . . . 113 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113 Description of Oil and Gas Properties . . . . . . . . . . . . . . . . . . . . . . 113 Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . 116 INFORMATION CONCERNING 1990 - 1 PARTNERSHIP . . . . . . . . . . . . . . . . . . . . . . 118 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118 Description of Oil and Gas Properties . . . . . . . . . . . . . . . . . . . . . . 119 Selected Historical Financial Data . . . . . . . . . . . . . . . . . . . . . . . 120 Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . 123 INFORMATION CONCERNING 1991 - 1 PARTNERSHIP . . . . . . . . . . . . . . . . . . . . . . 126 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126 Description of Oil and Gas Properties . . . . . . . . . . . . . . . . . . . . . . 126 Selected Historical Financial Data . . . . . . . . . . . . . . . . . . . . . . . 127 Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . 129 DESCRIPTION OF SECURITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132 LEGAL MATTERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133 EXPERTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133 GLOSSARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 134 INDEX TO FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-1
EXHIBITS - -------- EXHIBIT A Form of Warrant Agreement EXHIBIT B Reports of Huddleston & Co., Inc. Related to Estimated Reserves and Revenues of the Partnerships EXHIBIT C Description of the Proposals EXHIBIT D Letters of Transmittal EXHIBIT E California Dissenters' Rights Statute vi 14 SUMMARY The following is a summary of certain information contained elsewhere in this Prospectus. This summary is not intended to be a complete description of the matters covered in this Prospectus and is subject to and qualified in its entirety by reference to the more detailed information and financial statements contained elsewhere in this Prospectus, including the Supplement and Exhibits hereto and the documents incorporated herein by reference. Investors are urged to read carefully the entire Prospectus, including the Supplement and Exhibits. See Glossary included elsewhere in this Prospectus for definitions of certain oil and gas terms. RISK FACTORS AND MATERIAL CONSIDERATIONS The Exchange Offer. In addition to the information included in this Prospectus, the Investors should carefully consider the following factors in determining whether to accept the Exchange Offer and consent to the Proposal. The risks and effects of the Exchange will not be different for Investors based solely upon the Partnership in which he has invested. The risk factors summarized below are described in further detail elsewhere in this Prospectus at "Risk Factors and Material Considerations," beginning at page 34. Lack of Arm's Length Negotiations and Uncertainties in the Method of Determining Exchange Values. The Exchange Values were determined by Benton, based in part on an offer for the purchase of substantially all of the assets of the Partnerships from an unaffiliated third party, but may not reflect the actual value of the net assets of the respective Partnerships. The primary assets of each of the Partnerships considered by Benton when determining the Exchange Value were the proved oil and gas reserves of that Partnership (the "Proved Reserves") and the present value of associated future net cash flow as of December 31, 1994, as well as the offer to purchase the Umbrella Point Field, described herein. There are many uncertainties inherent in estimating quantities of Proved Reserves, and the present value attributed to each Partnership's Proved Reserves may be less than the future net cash flows actually received from that Partnership's interest in its wells. In that event, the use of this valuation methodology will have resulted in an undervaluation of the Partnership Units. See "Method of Determining Exchange Values." Potential Decline in Market Price of Common Stock. Access to an active trading market by exchanging Investors may result in a relatively large number of shares of Common Stock offered for sale immediately after the Closing Date. This may tend to lower the market price for the Common Stock. Future market conditions in the oil and gas industry in general or the effect of the conditions on Benton in particular could also adversely affect the market price of the Common Stock and thus the value of the Warrants. There can be no assurance regarding the potential appreciation in the market price of the Common Stock. Any decline in the market price of the Common Stock could reduce the Investor's return on investment or increase the loss on the Investor's original investment. Potential Benefits of Alternatives to the Exchange. The alternatives to the Exchange Offer are the continuation of the Partnerships or the liquidation of the Partnerships' assets and distribution of the liquidation proceeds to Investors, either of which could potentially be more beneficial to Investors than the Exchange by avoiding the risks associated with ownership of Benton Common Stock and, in the case of a liquidation of the Partnerships, by providing an immediate cash return 1 15 to Investors. See "Recommendation of the Managing General Partner--Managing General Partner's Reasons for Proposing the Exchange Offer," "--Managing General Partner's Determination that the Exchange Offer is Fair," and "--Alternatives to the Exchange." Lack of Independent Representatives for Investors; No Fairness Opinion. No independent representative was selected or hired to represent the interests of the Investors in negotiating the terms of the Exchange Offer. The Exchange Values and other terms of the Exchange Offer may therefore be inferior to those that could have been negotiated by an independent representative. Benton did not retain an independent third party to render an opinion regarding the fairness of the terms of the Exchange Offer to the Investors. Limited Dissenters' Rights. Investors who are California residents and who oppose the Proposal will have limited dissenters' rights. Other Investors who oppose the Proposal will have no dissenters' rights or appraisal rights, and therefore, no option to receive cash based on a separate appraisal of the Partnership assets in lieu of the Common Stock and Warrants based on the Exchange Values determined by Benton. The Managing General Partner could have provided all Investors with appraisal rights in structuring the Exchange Offer but elected not to do so, primarily because such rights are not provided for in the Partnership Agreements. The absence of these rights limit the options that would otherwise be available to Investors opposing the Exchange Offer. Effect on Dissenters' Rights on California Investors. Investors residing in California will be afforded limited dissenters' rights in accordance with the requirements for roll-up transactions under the California Code. By voting against the Proposal, Investors in the State of California will be deemed to exercise their dissenters' rights and will receive the number of shares of Common Stock and Warrants equal to the Exchange Value of their interests divided by the closing price of the Common Stock on the NASDAQ-NMS during the twenty days immediately after the Closing Date. If that average price is lower than the Exchange Price, dissenting California Investors will receive more shares of Common Stock and Warrants than they would otherwise receive in the Exchange Offer. If, however, the average price is higher than the Exchange Price, a dissenting Investor would receive fewer shares of Common Stock and Warrants. California Investors hold a substantial portion of the interests in the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership, and the impact of the exercise of dissenters' rights could materially increase or decrease the number of shares of Common Stock issued by Benton in connection with the Exchange Offer. Conflicts of Interest of Benton. Benton is the Managing General Partner of each of the Partnerships and its determination of the Exchange Values involves an inherent conflict of interest. As Managing General Partner, Benton owes fiduciary duties to the Investors in the Partnerships. In addition, it owes a duty to its stockholders. While Benton believes that it has fulfilled these obligations in its determination of the Exchange Values, which is supported, in part, by a reserve report audited by an independent petroleum engineer, no degree of objectivity or professional competence can eliminate the inherent conflict of interest. See "Recommendation of the Managing General Partner--Fiduciary Duties of Benton." Benton Dividend Policy. Benton's policy is to retain its earnings to support the growth of Benton's business. Accordingly, the Board of Directors of Benton has never declared cash dividends on its Common Stock and does not plan to do so in the foreseeable future. 2 16 Furthermore, the terms of Benton's debt agreements prohibit Benton from paying cash dividends on its Common Stock. Thus, upon consummation of the Exchange, Investors will no longer receive cash distributions and it is unlikely that cash dividends will be paid on the Benton Common Stock at any time in the foreseeable future. No Fractional Shares. No fractional shares will be issued in connection with the Exchange Offer. An Investor who would otherwise be entitled to a fractional share of Common Stock will be paid cash in lieu of such fractional shares. Warrants issued in connection with the Exchange Offer will be rounded to the nearest whole number of Warrants and no fractional interest will be issued. Risks Associated with Ownership of Common Stock of Benton. In addition to the information included in this Prospectus, the Investors should carefully consider the following factors related to Benton in determining whether to accept the Exchange Offer. The risk factors summarized below are described in further detail elsewhere in this Prospectus at "Risk Factors and Material Considerations." Losses From Benton's Operations. The historical financial data for Benton reflects net losses and decreased revenues for the years ended December 31, 1992 and 1993. Benton's ability to maintain its financing arrangements, produce its oil and gas reserves and service its debt obligations would be adversely affected by a lack of profitability. Foreign Operations. Almost all of Benton's oil and gas revenues and Proved Reserves are attributable to its operations in Venezuela and Russia. Benton's Venezuelan and Russian operations are subject to political, economic and other uncertainties inherent in the development of foreign properties. Properties Under Development. A substantial amount of Benton's Proved Reserves are undeveloped and require development activities and/or are proved developed behind-pipe or shut-in and require additional development activities. As a result, Benton will require substantial capital expenditures to develop all of its Proved Reserves. Engineers' Estimates of Reserves and Future Net Revenue. This Prospectus contains, and incorporates by reference, estimates of Benton's and the Partnerships' oil and gas reserves and future net revenues therefrom. Estimates of commercially recoverable oil and gas and the future net cash flows derived therefrom are based upon a number of variable factors and assumptions. Estimates to some degree are speculative and estimates of the commercially recoverable reserves of oil and natural gas, and the future net cash flows therefrom, prepared by different engineers or by the same engineer at different times, may vary substantially. The difficulty of making precise estimates is accentuated because most of Benton's Proved Reserves were non-producing at December 31, 1994. Development of Additional Reserves. Benton's future success may also depend upon its ability to find or acquire additional oil and gas reserves that are economically recoverable. There can be no assurance that Benton will be able to discover additional commercial quantities of oil and gas, or that Benton will be able to continue to acquire interests in underdeveloped oil and gas fields and enhance production and reserves therefrom. Partnership Litigation. Certain limited partners in Benton's oil and gas limited partnerships, including the Partnerships that are the subject of this Exchange Offer, filed suit against Benton 3 17 and others alleging breaches of contract, fiduciary duty and fraud. This suit has been voluntarily dismissed, subject to an agreement among the parties to arbitrate the issues and claims which were the subject of the claim. See "The Exchange Offer and Proposal--Litigation and Related Matters." In addition, Investors in partnerships which were sponsored by a third party have sued Benton on the theory that since it provided oil and gas drilling prospects to those partnerships and operated substantially all of their properties, it was responsible for alleged violations of securities laws in connection with the offer and sale of interests, contractual breach of fiduciary duty and fraud. See "The Exchange Offer and Proposal--Litigation and Related Matters." Retention and Attraction of Key Personnel. Benton depends to a large extent on the abilities and continued participation of certain key employees, the loss of whose services could have a material adverse effect on Benton's business. Regulation. The oil and gas industry is subject to broad and frequently changing regulations that could adversely affect the operations of Benton. In spite of the foregoing risks, Benton initiated and proposed the Exchange Offer and recommends adoption of the Proposals by each of the Partnerships to enable Benton to acquire the assets and liabilities of each of the Partnerships and to provide Investors with the potential benefits summarized below under the caption "Reasons for the Exchange Offer; Recommendation of the Managing General Partner." THE PARTIES BENTON OIL AND GAS COMPANY Benton Oil and Gas Company is primarily engaged in the development and production of oil and gas properties. The Company's operations are focused on the eastern region of Venezuela, the Gulf Coast region of Louisiana and the West Siberia region of Russia. Benton's business strategy is to seek new reserves in areas of low geologic risk and to exploit underdeveloped existing oil and gas fields. The Company implements the exploitation strategy through the in-house design and interpretation of 3-D seismic surveys and through workovers, recompletions, redrilling and exploration and development drilling. Internationally, the Company seeks projects with significant reserve potential in areas with low geologic risk and known proved reserves where, in certain situations, the Company can add value by employing modern exploration, drilling, completion and production techniques. To reduce risk, control costs, and facilitate local transactions, the Company has formed ventures with local foreign partners. Domestically, the Company integrates 3-D seismic technology with subsurface geologic data from previously drilled wells. This geophysical evaluation enables the Company to discover previously undetected reserves in existing fields. The Company believes that it enjoys a competitive advantage in finding and developing reserves on an economic basis because of its concentration on 3-D seismic technology, the training and qualifications of its in-house technical team and the practical experience and knowledge which this team has acquired over past years. The Company's recognized technical expertise has afforded it access to projects it otherwise would not have enjoyed. 4 18 In the ordinary course of its business, the Company continues to evaluate acquisition, joint venture and other opportunities that would enable it to further its business strategy. Benton was incorporated in Delaware in September 1988. Its principal executive offices are located at 1145 Eugenia Place, Suite 200, Carpinteria, California 93013 and its telephone number is (805) 566-5600. See "Summary -- Certain Historical and Pro Forma Financial Data" and "Information Concerning Benton" for a more detailed discussion of Benton. 1989-1 PARTNERSHIP Benton Oil & Gas Combination Partnership 1989-1, L.P., a California limited partnership, was formed September 1, 1989 to explore for oil and gas, acquire undeveloped leases and Proven Producing Properties and other interests, drill wells, recomplete existing wells and conduct all other operations relating to the exploration, production and sale of oil and gas. Benton Oil and Gas Company is the Managing General Partner of the 1989-1 Partnership. The principal executive offices of the Managing General Partner and the 1989-1 Partnership are located at 1145 Eugenia Place, Suite 200, Carpinteria, California 93013; telephone number: (805) 566-5600. 1990-1 PARTNERSHIP Benton Oil & Gas Combination Partnership 1990-1, L.P., a California limited partnership, was formed November 29, 1990 to explore for oil and gas, acquire undeveloped leases and Proven Producing Properties and other interests, drill wells, recomplete existing wells and conduct all other operations relating to the exploration, production and sale of oil and gas. Benton Oil and Gas Company is the Managing General Partner of the 1990-1 Partnership The principal executive offices of the Managing General Partner and the 1990-1 Partnership are located at 1145 Eugenia Place, Suite 200, Carpinteria, California 93013; telephone number: (805) 566-5600. 1991-1 PARTNERSHIP Benton Oil & Gas Combination Partnership 1991-1, L.P., a California limited partnership, was formed July 30, 1991 to explore for oil and gas, acquire undeveloped leases and Proven Producing Properties and other interests, drill wells, recomplete existing wells and conduct all other operations relating to the exploration, production and sale of oil and gas. Benton Oil and Gas Company is the Managing General Partner of the 1991-1 Partnership The principal executive offices of the Managing General Partner and the 1991-1 Partnership are located at 1145 Eugenia Place, Suite 200, Carpinteria, California 93013; telephone number: (805) 566-5600. 5 19 THE EXCHANGE OFFER AND PROPOSALS Benton is offering to exchange Common Stock and Warrants for Partnership Units in the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership (the "Exchange"). Investors who tender their Partnership Units will receive the number of shares of Common Stock and Warrants set forth herein in exchange for the Partnership Units. See "The Exchange Offer and Proposal" and "Method of Determining Exchange Values." In connection with the Exchange Offer, Benton is submitting Proposals to Investors in each of the Partnerships (the 1989-1 Proposal, the 1990-1 Proposal and the 1991-1 Proposal referred to collectively herein as the "Proposals") to amend the respective Partnership Agreements to provide for the transfer of all of the assets and liabilities of the Partnerships to Benton as of the December 31, 1994 Effective Date in exchange for Common Stock and Warrants in the amounts set forth below and the pro rata distribution of such consideration in liquidation of the Partnership. Each Investor who tenders his Partnership Units pursuant to the Exchange Offer will, by that tender, consent to the Proposal. If a Partnership adopts the Proposal by the consent of 75% of the Partnership Units, all Investors in that Partnership, whether or not they tendered their Units in the Exchange Offer, will receive the same amount of Common Stock and Warrants they would have received had they tendered their Partnership Units. CONSUMMATION OF THE EXCHANGE OFFER FOR A PARTNERSHIP IS CONDITIONED UPON APPROVAL BY THAT PARTNERSHIP OF THE PROPOSAL. APPROVAL OF THE PROPOSAL AND ADOPTION OF THE EXCHANGE OFFER IS NOT CONDITIONED UPON APPROVAL AND ACCEPTANCE BY ANY OTHER PARTNERSHIP. See "The Exchange Offer and Proposal." Holders of Units in the Partnerships who elect to accept the Exchange Offer may choose to accept cash in lieu of the Common Stock to be issued, BUT CASH WILL BE DISTRIBUTED TO THE HOLDER ONLY IF THE SALE OF THE UMBRELLA POINT FIELD TO GOLDKING TRINITY BAY CORP. ("GOLDKING"), AS DESCRIBED HEREIN, IS ACTUALLY CONSUMMATED. A holder should make a decision to accept the Exchange Offer based solely upon an investment decision in the Common Stock, because there can be no assurance from Benton that the Goldking sale will be consummated. See "The Exchange Offer and Proposal--Election to Receive Cash in Lieu of Common Stock" and "Consent Procedures--Solicitation of Letters of Transmittal." Common Stock issued in the Exchange will be freely transferable immediately following issuance. There will be no market for the Warrants. The Exchange Offer may be withdrawn if Benton determines, in the exercise of reasonable judgment, that a material change affecting the Partnerships or the Company has occurred. See "The Exchange Offer and Proposal." For a detailed description of Benton's determination of the Total Exchange Values for each of the Partnerships, see "Method of Determining Exchange Values." DISSENTERS' RIGHTS Investors residing in states other than California will not be afforded any dissenters' or appraisal rights. Under the rules adopted by the National Association of Securities Dealers, Inc. ("NASD"), Investors in roll-up transactions such as the Exchange Offer are entitled to certain dissenters' rights unless the sponsor adopts a 75% approval requirement for the transaction or other procedures designed to protect the rights of Investors. Although adoption of the Proposals by each of the Partnerships would require the consent under the Partnership Agreements of the holders of only a majority of the Partnership Units, the Managing General Partner has adopted a 75% approval procedure instead of providing dissenters' rights. 6 20 Investors residing in California will be afforded limited dissenters' rights in accordance with the requirements for roll-up transactions under the California Code. By voting against the Proposal, Investors in the State of California will be deemed to exercise their dissenters' rights and will receive the number of shares of Common Stock and Warrants equal to the Exchange Value of their interests divided by the closing price of the Common Stock on the NASDAQ-NMS during the twenty days immediately after the Closing Date. If that average price is lower than the Exchange Price, dissenting California Investors will receive more shares of Common Stock and Warrants than they would otherwise receive in the Exchange Offer. If, however, the average price is higher than the Exchange Price, a dissenting Investor would receive fewer shares of Common Stock and Warrants. California Investors hold a substantial portion of the interests in the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership and the impact of the exercise of dissenters' rights could materially increase or decrease the number of shares of Common Stock issued by Benton in connection with the Exchange Offer. See Exhibit E for a copy of the California Statute. BACKGROUND AND ALTERNATIVES TO THE EXCHANGE Background. Each of the Partnerships has completed its respective drilling operations and acquisitions. Benton has received inquiries and concerns from Investors and determined that the Partnerships had each reached the stage in its production history where consideration of the Exchange Offer became appropriate. That determination was based on the following factors: - Production Declines. Since 1993, the Partnerships' oil production volumes have declined from peak levels reached in 1992. Gas production began to decline in 1993 and 1994. These reductions are due to the natural decline occurring in the Umbrella Point Field, the Partnerships' most significant asset. Production volumes are expected to decline further in subsequent periods due to ongoing depletion of the Partnerships' wells. The decline in production rates due to depletion of reserves is neither unusual nor unexpected in the oil and gas industry. - Declining Distribution Rates. The Partnerships' production declines commencing in 1993 and 1994 contributed to the Partnerships' declining distribution rates in 1993 and 1994. - Partnership Litigation. Litigation, in the form of arbitration, has been instituted against Benton by certain Investors in the Partnerships which are the subject of this Exchange Offer. The claims made by the Investors have not been clearly defined. However, in general terms, the Investors allege that the Company failed to comply with the requirements of the Partnership Agreements with respect to the reports to be sent to individual partners, including audited financial statements and reserve reports, commingling of funds, breach of its fiduciary duties, fraudulent inducement to invest, conversion and negligent representation. The Company intends to vigorously defend its actions related to these Partnerships. However, the Company does believe that it is in its best interest and the best interests of the partners to resolve these issues, as it relates to the Partnerships, and to terminate the Partnerships on the terms set forth herein. The Company anticipates that if the Exchange Offer is approved, this will lessen the chance of additional litigation with respect to the Partnerships and may limit the potential damages with respect to the existing arbitration. 7 21 - Benton's Acquisition of the Partnership Properties. Although Benton has executed agreements for the sale of each of the Partnership's respective interests in the Umbrella Point Field, which constitutes substantially all of the assets of the Partnerships, there can be no assurance that the contemplated sale will be consummated. Benton has made the Exchange Offer to acquire the assets of these Partnerships approving the Proposals, and then intends to sell the Umbrella Point Field to Goldking on the terms described herein. Benton is a logical purchaser for various reasons, including Benton's (i) interest in reducing the overhead involved in administration of the Partnerships as Managing General Partner, (ii) greater diversification and capital resources enabling Benton to fund liabilities and expenses necessary for the full development of the Partnerships' properties (iii) interest in responding to the Investor's concerns about the future prospects of the Partnerships, since many of the Investors are also stockholders of Benton, and (iv) ability to assume the risk that the sale to Goldking will not be consummated. Although the acquisition of the Partnership's assets pursuant to the Exchange Offer will result in a charge against Benton's income, Benton does not expect that this one time charge will have a significant adverse affect on the market value of the Benton Common Stock. Alternatives to the Exchange. Although Benton has considered the continuation of the Partnerships or liquidation of the Partnerships as potential alternatives to the Exchange Offer, these alternatives were rejected for various reasons, including the following: - Solicitation of Offers to Purchase Partnership Properties; Goldking Purchase Offer. Benton has solicited bidders for the purchase of assets of each of the Partnerships. See "Background of Exchange Offer - Goldking Offer." The interest in purchasing the assets of the Partnerships was limited. In June 1995, Benton received an offer from Goldking Trinity Bay Corp. ("Goldking") to purchase all of the right, title and interest owned by each of the Partnerships and Benton in the Umbrella Point Field. The financing of the Goldking acquisition was subject to the ability of Goldking to acquire at least 75% of the working interests in the Field, and therefore, to preserve the offer for the Partnerships, Benton sold its corporate interest in the Umbrella Point Field (11.77% working interest) to Goldking for $756,872. Benton entered into agreements, on behalf of each of the Partnerships, with Goldking for the sale of the Partnerships' interests in the Umbrella Point Field, subject to approval of the Partnerships. In consideration of the sale, the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership would receive anticipated net proceeds in the aggregate of $323,296, $930,865 and $185,282, respectively, in addition to the earnest money deposits which have been paid by Goldking to the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership in the amount of $4,929, $14,192 and $2,824, respectively (the "Deposit"), if the sale were consummated as of June 30, 1995. The agreements with Goldking are not contingent upon each of the Partnerships approving the transaction. Benton has not recommended to the Investors a direct sale by the Partnerships of their interests in the Umbrella Point Field to Goldking since the sale of these assets would result in dissolution of the Partnerships pursuant to the respective Partnership Agreements. As discussed herein, Benton has attributed value to certain General Intangibles (as defined herein) to induce Investors to accept the Exchange Offer, which increases the Total Exchange Value attributed to the Partnerships. Benton believes that it is in the best interest of the Investors of each of the Partnerships to accept the Exchange Offer, which pursuant to Benton's method of determining the Total Exchange Value, will provide consideration in excess of the cash distribution an Investor would have received from the sale of the Partnership assets to Goldking. If the Exchange Offer and Proposal for the Partnerships are approved, Benton intends to sell the working interest in the Umbrella Point Field for each approving Partnership to Goldking, on the terms and for the consideration offered by Goldking to the Partnerships. Thus, if 8 22 all three of the Partnerships accept the Exchange Offer and consent to the Proposal, Benton will receive an aggregate of approximately $1,439,443 in cash from Goldking for the sale of the Partnerships' assets, subject to adjustment, and the Investors in the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership would receive total consideration valued at $370,098, $2,990,728 and $692,349, respectively. In evaluating the terms of the Goldking Offer, Benton analyzed the estimated value of each of the Partnerships' proved reserves and other assets. The Goldking purchase offer represents 99.3%, 88.1% and 88.0% of the total discounted future net cash flows for the proved reserves of the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership, respectively. Benton entered into the purchase agreements with Goldking in order to preserve the Investors' ability to sell the Partnership assets to Goldking at a price Benton believes is favorable to the Partnerships. Benton has proposed the Exchange Offer, contemplating the sale of the Partnership assets to Goldking on the terms described above, allowing Investors to receive the favorable consideration offered by Goldking for the purchase of the primary asset of each of the Partnerships, and receive value for other assets and General Intangibles of the Partnerships which would not be valued or provide little if any consideration in liquidation. If the Goldking sale is consummated, an Investor who accepts the Exchange Offer may elect to receive cash in lieu of Benton Common Stock in the amount set forth herein, providing an Investor with cash he or she would have received for the sale of the Partnership assets, with additional consideration in the form of Warrants to induce Investors to accept the Exchange Offer. See "The Exchange Offer and Proposal - Election to Receive Cash in Lieu of Common Stock." In addition to the Goldking offer, Benton received an offer to purchase the working interests owned by each of the Partnerships and Benton in the Umbrella Point Field from Hunter Resources, Inc. ("Hunter") in October 1994. Pursuant to the terms of that offer, Hunter would have paid a total of $8,000,000 in cash and $1,000,000 in the form of a promissory note, compared to Goldking's offer of $7,650,000 in cash. Both offers were for the working interests in the Umbrella Point Field owned by each of the Partnerships and the 11.77% working interest owned by Benton. Benton compared the Hunter offer, the Goldking offer and the estimated value of the Umbrella Point Field proved reserves at December 31, 1994 (see table below). In the case of all three Partnerships, the Hunter offer and the Goldking offer were in excess of the value of the proved reserves of the Umbrella Point Field. Hunter was unable to secure financing for the transaction and subsequently withdrew its offer. Due to Hunter's inability to secure financing for the purchase and the extent to which such offer exceeded the value of the Partnerships' proved reserves, Benton concluded that Hunter's offer was in excess of the market value of the Umbrella Point Field. When analyzing and considering the Goldking offer, Benton concluded that the purchase price offered by Goldking was in excess of the value of the Partnerships' proved reserves and, although less than the Hunter offer, represented a favorable market value for the property. 9 23
UMBRELLA POINT FIELD HUNTER OFFER(1) GOLDKING PROVED PARTNERSHIP (CASH & NOTES) OFFER(1) RESERVES(2) - ----------- -------------- -------- ----------- 1989-1 $ 443,602 $ 377,062 $325,540 1990-1 1,277,264 1,085,674 937,429 1991-1 254,228 216,093 186,589
- ------------------ (1) Prior to any adjustments for revenues and expenses subsequent to the effective date of sale, which in the case of Goldking is January 1, 1995. These adjustments, through June 30, 1995, are the reason for the differences in Goldking proceeds listed in this table as compared to other places in the document. The adjustments were omitted from this table for comparative purposes. (2) Value of estimated future net cash flows from Proved Reserves of the Umbrella Point Field, as of December 31, 1994, as reflected in the reserve report for the Partnership as of that date. Although several other companies reviewed reserve information, production records and well data, no other serious inquiries were received by Benton for the purchase of the Partnerships' assets and Benton believes that no offer to purchase the assets of the Partnerships will be in excess of the Total Exchange Values. - Continuation of the Partnerships. Continuation of the Partnerships, while avoiding the risks associated with the Exchange Offer and the discontinuance of cash distributions, would result in declining operating results and distribution rates for each of the Partnerships because: (i) reserves will be depleted in the ordinary course from ongoing production, (ii) general and administrative expenses will remain the same regardless of the operating results of the Partnership assets, and (iii) the Partnership would have to incur the cost of plugging and abandoning Partnership wells when they become uneconomic or any future sale of the Partnership's wells would be at a price which would reflect the anticipated costs of such plugging and abandonment expenses. - Liquidation of the Partnerships. Benton has undertaken an analysis of the current liquidation value of each of the Partnerships. Results of that liquidation analysis reflect liquidation values per Unit for the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership estimated at $1,045, $742 and $855, respectively, or approximately 20%, 65% and 65%, respectively, less than the Total Exchange Values. Benton's liquidation analysis for each of the Partnerships is based upon Benton's estimate of cash proceeds that would be received by the Partnership on liquidating the assets of such Partnership. The liquidation values are supported by the offers to purchase the assets of the Partnerships, discussed above. Since Benton has solicited bidders for purchase of the assets of the Partnerships, it believes that liquidation of the Partnership assets would result in limited interest for those assets, and would likely result in valuations below the Total Exchange Values of the Partnership 10 24 Units. In view of the results of the liquidation analysis, Benton rejected the alternative of liquidation and has made the Exchange Offer to holders of Units in the Partnerships. REASONS FOR THE EXCHANGE OFFER; RECOMMENDATION OF THE MANAGING GENERAL PARTNER The Managing General Partner recommends that the Investors in each of the Partnerships consent to the Proposal and accept the Exchange Offer. See "Background of Exchange Offer". This recommendation is based on a number of factors summarized below. See "Recommendation of the Managing General Partner" for additional information. In considering the Exchange, the Managing General Partner took into account various advantages and disadvantages of the Exchange to each of the Partnerships and its respective Investors. The advantages the Managing General Partner considered included: (a) The Managing General Partner has reviewed the financial condition, results of operations and cash flows of Benton and each of the Partnerships, on a historical and a prospective basis. The Managing General Partners' analysis of the future prospects for each of the Partnerships indicates declining distributions to the investors. See "Recommendation of Managing General Partner Managing General Partner's Determination that Exchange Offer is Fair". For the years ended December 31, 1992, 1993 and 1994 and the six months ended June 30, 1994 and 1995, Benton had total revenues of $8,622,000, $7,504,000, $34,705,000, $12,160,000 and $25,870,000, respectively. For the years ended December 31, 1992 and 1993, Benton had a net loss of $2,909,000 and $4,829,000, respectively, compared to net income of $2,954,000 for the year ended December 31, 1994 and net income of $2,000 and $3,152,000 for the six months ended June 30, 1994 and 1995, respectively. The Managing General Partner has concluded that Benton's ability to access additional capital and its more diverse operations and oil and gas prospects in Venezuela, the Gulf Coast and Russia could continue to contribute to significant increases in Benton's results of operations and cash flow, while the Partnerships each have a short remaining economic life. (b) The Managing General Partner considered the potential growth rate and market price to earnings potential of Benton. The Managing General Partner's analysis of continuation of the Partnerships indicate that distributions are likely to decrease rapidly over the short economic life of the Partnerships. The Managing General Partner determined that the Investors will receive the benefit of any future growth in the value of their equity interest in Benton which will be more beneficial to the Investors than receiving cash distributions from the Partnerships through continuation for the Partnerships' economic lives. In addition, distributions to the Investors in connection with the Exchange Offer allow for distributions undiminished by ongoing Partnership plugging costs, which the Managing General Partner estimates through the life of the Partnerships to be $247, $160 and $56 per unit for the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership, respectively. (c) The Common Stock of Benton has an active trading market on NASDAQ National Market. This active trading market provides some liquidity to the Investors. The Partnership Units have no liquidity, and the Partnership Agreement restricts transfer of the Partnership Units. The Warrants that will be received in the Exchange Offer do not currently have a public trading market. (d) If the sale of the Umbrella Point Field to Goldking is consummated, Investors who accept the Exchange Offer may choose to receive cash in lieu of Common Stock of Benton, and will receive Warrants in the amounts set forth herein. This option allows an Investor to receive cash in an amount equal to that which would be received if the Investors sold the assets of the Partnership to 11 25 Goldking, and would allow the Investor to also receive additional consideration in the form of Warrants with a value equal to the General Intangibles of the Partnership, as described in further detail herein. CASH WILL BE DISTRIBUTED ONLY TO THOSE INVESTORS WHO CHOOSE TO RECEIVE CASH IN LIEU OF COMMON STOCK BY MAKING THE APPROPRIATE ELECTION IN THE LETTER OF TRANSMITTAL, ATTACHED HERETO AS EXHIBIT D, AND ONLY IF THE SALE OF THE UMBRELLA POINT FIELD TO GOLDKING IS CONSUMMATED FOR SUCH PARTNERSHIP. See "The Exchange Offer and Proposal - Election to Receive Cash In Lieu of Common Stock" and "Consent Procedures Solicitation of Letters of Transmittal." The Managing General Partner also considered certain disadvantages that included: (a) There are many uncertainties and risks inherent in the oil and gas industry. The Managing General Partner considered the possibilities that changes in the industry and continued volatility of oil and gas prices could have a significantly greater effect on the Partnership due to the Partnership's size compared to Benton and the greater diversification of oil and gas properties and prospects of Benton. However, the Managing General Partner also considered that increases in the price of oil and gas could have a more direct effect to the Investors if the Partnership assets were owned by the Partnership rather than Benton due to the size of the Partnership, the cash distributions to the Investors from the Partnerships and the percentage ownership in the Partnership of each of the Investors. However, Benton believes that an increase in oil and gas prices could generally increase revenues of Benton and could result in a corresponding increase in the market price of Benton Common Stock. (b) Benton is restricted under certain credit agreements from paying cash dividends to its stockholders and the Investors could continue to receive cash distributions from the Partnership. However, the Managing General Partner believes that the cash distributions to the Investors from each of the Partnerships will likely decrease rapidly as the remaining oil and natural gas reserves are depleted. (c) Upon the Exchange of the Partnership Units for Common Stock and Warrants, Investors will recognize gain equal to the amount by which the fair market value of the Common Stock and Warrants received by them exceeds their respective bases in the Partnership Units exchanged therefore. Thus, an Investor will have immediate tax consequences in connection with the Exchange Offer and liquidation of the Partnerships, and could be required to pay cash for such tax liabilities, even though the Investor receives only Common Stock and Warrants in connection with the Exchange. However, the Managing General Partner believes that the total consideration to be received by an Investor in the Partnerships, net of the tax consequences to such Investor, is more beneficial to the Investors than continuation of the Partnerships. (d) The Total Exchange Value for the Partnerships is calculated, in part, based upon the present value of the proved reserves for each of the Partnerships. There are numerous uncertainties inherent in estimating quantities of proved reserves. Although the Managing General Partner retained an independent petroleum engineer to audit the data and computations of the proved reserve estimates, the reserve estimates for the Partnerships could be undervalued and would therefore effect Benton's continuation analysis for each Partnership. However, Benton believes that a material undervaluation of the reserve estimates is unlikely and therefore the Exchange Offer will be more beneficial to the Investors than any alternative to the Exchange Offer. (e) The Managing General Partner considered the volatility of the market value of the Benton Common Stock and daily trading volume of the Common Stock on NASDAQ National Market. Although the market value for the Common Stock has fluctuated from a low of $4.25 in the first quarter of 1994 to a high of $15.13 in the second quarter of 1995, the market value has been less volatile in 12 26 1995, with the low of $8.63. The average daily trading volume for Benton Common Stock during the last 30 days has been 259,000 shares. Therefore, the Managing General Partner believes that the market value of the Benton Common Stock will not be significantly effected by the issuance of the Common Stock in connection with the Exchange Offer. See "Recommendation of the Managing General Partner." For other relevant factors, see also "Risk Factors and Material Considerations." MANAGING GENERAL PARTNER'S DETERMINATION THAT OFFER IS FAIR THE MANAGING GENERAL PARTNER OF THE PARTNERSHIPS HAS DETERMINED THAT THE EXCHANGE IS FAIR AND IS IN THE BEST INTERESTS OF THE PARTNERSHIPS AND THEIR PARTNERS AND HAS RECOMMENDED THAT THE PARTNERS OF THE PARTNERSHIPS TENDER THEIR PARTNERSHIP UNITS AND CONSENT TO THE PARTNERSHIP PROPOSAL. THE EXCHANGE OFFER IS NOT CONDITIONED UPON ACCEPTANCE AND APPROVAL BY ALL OF THE PARTNERSHIPS AND THE MANAGING GENERAL PARTNER BELIEVES THAT THE OFFER IS FAIR TO ALL INVESTORS, REGARDLESS OF WHICH OR THE NUMBER OF PARTNERSHIPS WHICH ACCEPT THE EXCHANGE OFFER FOR THE REASONS SET FORTH BELOW. General. The Managing General Partner has analyzed the terms of the Exchange Offer, the consideration and value offered to the Investors in exchange for their Partnership Units and the value of the consideration an Investor could expect to receive under various alternatives to the Exchange. In determining that the Exchange Offer is fair to the Investors, the Managing General Partner considered that the Investors who do not accept the Exchange Offer or who do not elect to receive cash in lieu of Benton Common Stock will receive Common Stock and Warrants of Benton, and could receive cash if the Partnerships were continued or liquidated. However, the Managing General Partner believes that because an Investor may elect to receive cash in lieu of Common Stock if the sale to Goldking is consummated, the Investors will receive consideration in excess of the alternatives to the Exchange if the Exchange Offer is accepted. The Managing General Partner's analysis of the consideration an Investor could receive under the alternatives to the Exchange are discussed below. The Managing General Partner believes that those Investors who receive Benton Common Stock will have access to a public trading market if such Investor elects to liquidate his investment for cash. The average daily trading volume for the Benton Common Stock on the NASDAQ National Market for the 30 trading days ended September 27, 1995 was 259,000 shares. The Managing General Partner believes that since the maximum aggregate number of shares of Benton Common Stock that will be issued in the Exchange Offer for all three Partnerships is 171,880, the issuance will have no material effect on the market value of the Benton Common Stock, and may allow all Investors receiving shares of Benton Common Stock in connection with the Exchange Offer and liquidation of the Partnerships to liquidate their investment in the market. Alternatives to the Exchange. The following tables summarize the results of Benton's liquidation analysis in comparison to the Exchange Values for the Partnership Units determined by Benton. The table also includes valuation data derived from Benton's analysis of continuing the Partnerships. Benton did not undertake its continuation analysis for the purpose of valuing the Partnerships, but solely to illustrate the likelihood of decreasing distributions based on oil and gas prices at December 31, 1994. However, because SEC disclosure standards for roll up transactions require a comparison of the value of the consideration offered in the transaction with the value of the consideration estimated for each alternative to the transaction, the tables also reflect the results of extending Benton's 13 27 continuation analysis for the balance of the estimated life of each of the Partnership's Proved Reserves, and discounting the projected stream of distributions to present value at the same 10% discount rate used in Benton's liquidation analysis to account for the timing of cash flows as well as production and concentration risks. For information concerning the assumptions used in determining the value attributable to each alternative, see "Recommendation of the Managing General Partner - Managing General Partner's Determination that Exchange Offer Is Fair." 1989-1 PARTNERSHIP
TOTAL VALUE PER VALUATION METHOD INVESTOR VALUE(1) 1989-1 UNIT - ---------------- ----------------- ----------- Exchange Value................................................... $ 370,098 $ 1,312 Liquidation value estimated by Benton............................ 294,634 1,045 Continuation analysis by Benton assuming natural gas prices of $1.63 per Mcf and oil prices of 90,661 322 $15.94 per Bbl(2)............................................ Value of Proved Reserves at December 31, 1994(3)................. 325,540 1,155
(1) The Exchange Value and liquidation value attribute no value to Managing General Partners' interests. The continuation analysis assumes continued distributions to the Managing General Partner pursuant to the terms of the Partnership Agreement. (2) The assumed natural gas and oil prices are the prices used for preparation of the Partnership's reserve report at December 31, 1994. The continuation analysis was calculated based upon Benton's estimate of the remaining economic life of the Partnership, estimated to be 3.5 years. (3) Based on the Partnership's December 31, 1994 reserve report prepared by Benton and audited by Huddleston. The reserves are valued as of December 31 of each year, based on oil and natural gas prices as of that date. Market prices for both oil and natural gas are subject to a significant degree of variation, and this variation will affect the calculation of future net cash flows reported by the Partnership at any specific date. 1990-1 PARTNERSHIP
TOTAL VALUE PER VALUATION METHOD INVESTOR VALUE(1) 1990-1 UNIT - ---------------- ----------------- ----------- Exchange Value................................................... $ 2,990,728 $ 2,107 Liquidation value estimated by Benton............................ 1,052,601 742 Continuation analysis by Benton assuming natural gas prices of $1.63 per Mcf and oil prices of 415,355 293 $15.94 per Bbl(2)............................................ Value of Proved Reserves at December 31, 1994(3)................. 1,057,123 745
(1) The Exchange Value and liquidation value attribute no value to Managing General Partners' interests. The continuation analysis assumes continued distributions to the Managing General Partner pursuant to the terms of the Partnership Agreement. (2) The assumed natural gas and oil prices are the prices used for preparation of the Partnership's reserve report at December 31, 1994. The continuation analysis was calculated based upon Benton's estimate of the remaining economic life of the Partnership, estimated to be 5.5 years. 14 28 (3) Based on the Partnership's December 31, 1994 reserve report prepared by Benton and audited by Huddleston. The reserves are valued as of December 31 of each year, based on oil and natural gas prices as of that date. Market prices for both oil and natural gas are subject to a significant degree of variation, and this variation will affect the calculation of future net cash flows reported by the Partnership at any specific date. 1991-1 PARTNERSHIP
TOTAL VALUE PER VALUATION METHOD INVESTOR VALUE(1) 1991-1 UNIT - ---------------- ----------------- ----------- Exchange Value................................................... $ 692,349 $ 2,456 Liquidation value estimated by Benton............................ 240,998 855 Continuation analysis by Benton assuming natural gas prices of $1.63 per Mcf and oil prices of 47,072 167 $15.94 per Bbl(2)............................................ Value of Proved Reserves at December 31, 1994(3) 210,445 747
(1) The Exchange Value and liquidation value attribute no value to Managing General Partners' interests. The continuation analysis assumes continued distributions to the Managing General Partner pursuant to the terms of the Partnership Agreement. (2) The assumed natural gas and oil prices are the prices used for preparation of the Partnership's reserve report at December 31, 1994. The continuation analysis was calculated based upon Benton's estimate of the remaining economic life of the Partnership, estimated to be 2.5 years. (3) Based on the Partnership's December 31, 1994 reserve report prepared by Benton and audited by Huddleston. The reserves are valued as of December 31 of each year, based on oil and natural gas prices as of that date. Market prices for both oil and natural gas are subject to a significant degree of variation, and this variation will affect the calculation of future net cash flows reported by the Partnership at any specific date. The actual amount that Investors would receive if the Partnerships continued their operations would depend on production levels, which cannot be predicted with certainty. In addition, the actual amount that Investors would receive under either of the alternatives to the Exchange would depend on future oil and gas prices. To the extent that future prices for those commodities are materially higher or lower than the pricing assumptions made by the Managing General Partner, those fluctuations would likely have a similar effect on the operating results, distribution rates and market value of the Partnership Units, largely negating the effect of price changes on a comparison between the Exchange and either alternative of continuing the Partnerships or liquidating its assets. In addition, Benton believes that liquidating the Partnerships would deprive Investors of the opportunity to benefit from any future upturn in oil and gas prices. For a more detailed discussion of the bases for the Managing General Partner's determination that the Exchange Offer is fair to Investors, see "Recommendation of the Managing General Partner--Managing General Partner's Determination that Exchange Offer is Fair." SUMMARY OF TAX CONSEQUENCES Upon consummation of the Exchange, Investors will realize gain in an amount equal to the excess of the fair market value of the Common Stock and Warrants received by them over their respective bases in the Partnership Units they hold. 15 29 Assuming the Investor has held his Interest for more than one year and assuming his Units have not been held for sale in the ordinary course of the Investor's trade or business, any gain or loss realized upon the transfer of the Partnership Units will be taxed as long term capital gain or loss, except to the extent that the consideration received is attributable to his allocable share of substantially appreciated inventory items and unrealized receivables (including depreciation recapture and excess intangible drilling and development costs) of the Partnerships. The portion of any gain attributable to these items will be taxed to the Investor as ordinary income. Investors should read the more detailed discussion of the federal income tax consequences contained in "Certain Federal Tax Consequences" and are also urged to consult with their own tax advisors with respect to the tax consequences to them of the transaction, including the application of state, local and foreign tax laws. ACCOUNTING TREATMENT The Exchange will be accounted for as a purchase by Benton. Accordingly, the purchase price will be allocated to assets and liabilities based on their estimated values as of the date of acquisition. REQUEST FOR INVESTOR LISTING Benton will furnish to any Investor, upon oral or written request, a current alphabetized listing of the names and addresses of all Investors of the Partnership in which the requesting Investor owns an interest. Requests should be addressed to Benton Oil and Gas Company, Investor Relations, 1145 Eugenia Place, Suite 200, Carpinteria, California 93013, telephone number 805-566-5600. Investors also have the right under the Partnership Agreements to inspect the books and records of the Partnership. BUSINESS OF BENTON AND THE PARTNERSHIPS AFTER THE CONSUMMATION OF THE EXCHANGE Benton is an independent oil and gas company engaged in the acquisition of producing properties and the exploration, development and production of oil and gas, primarily in the eastern region of Venezuela, the Gulf Coast of Louisiana and the West Siberia region of Russia. Benton has executed agreements on behalf of each of the Partnerships, pursuant to which Benton will sell the working interests in the Umbrella Point Field to Goldking on the terms described herein, subject to consummation of the Exchange. If, however, such sale is not consummated, Benton will operate the acquired Partnership assets as it operates its oil and gas properties, or may sell those assets to another third party. See "Background of Exchange Offer--Goldking Offer." 16 30 COMPARATIVE RIGHTS OF SECURITY HOLDERS For a comparison of the rights of Benton stockholders under Delaware law and Benton's Certificate of Incorporation and Bylaws with the rights of the Partners of each of the Partnerships under California law and the respective Partnership Agreements, see "Comparative Rights of Security Holders." RESALES OF BENTON COMMON STOCK The shares of Common Stock that will be issued to Investors in connection with the Exchange and upon liquidation of the Partnerships have been registered under the Securities Act. All shares of Common Stock received by Investors will be freely tradable by those Investors. DESCRIPTION OF THE WARRANTS To Investors who accept the Exchange Offer, Benton will issue Warrants to purchase shares of Common Stock. Each Warrant issued pursuant to the Exchange Offer will entitle the holder to purchase one share of Common Stock for each Warrant held, at an exercise price of $11.00 per share, subject to adjustment in certain circumstances. The Warrants will be issued pursuant to a Warrant Agreement, the form of which is attached hereto as Exhibit A. Pursuant to the terms of the Warrant Agreement, the Warrants will expire three years from the date issuance. The number of shares of Common Stock and the exercise price of the Warrants is subject to adjustment under certain circumstances, as described therein, including issuance of Common Stock or securities convertible into Common Stock to all holders of Benton Common Stock, exchange of Common Stock of Benton for other securities, issuance of Common Stock or other securities to all holders upon merger, reorganization, or sale of assets. The Warrants are not subject to redemption or call by Benton. If the Exchange Offer is accepted by more than 75% of the holders of the 1989-1 Units, 1990-1 Units and the 1991-1 Units, Benton will issue to all holders of such Units, Warrants to purchase an aggregate of 592,373 shares of Common Stock. On October 2, 1995, there were Warrants to purchase an aggregate of 1,919,752 shares of Common Stock issued and outstanding. See "Description of Securities." The number of Warrants to be issued in exchange for 1989-1 Units, 1990-1 Units and 1991-1 Units has been determined by dividing the estimated value of the General Intangibles of the Partnership by the estimated present value of $3.64 per Warrant. Benton has used the Black-Scholes option pricing model to calculate the present value of the Warrants. THE ACTUAL VALUE, IF ANY, A HOLDER MAY REALIZE FROM THE WARRANTS WILL DEPEND ON THE EXCESS OF THE MARKET PRICE OF THE COMMON STOCK OVER THE EXERCISE PRICE OF THE WARRANT ON THE DATE THE WARRANT IS EXERCISED, SO THAT THERE IS NO ASSURANCE THE VALUE REALIZED BY A HOLDER WILL BE AT OR NEAR THE VALUE ESTIMATED BY THE BLACK-SCHOLES OPTION PRICING MODEL. The estimated values under the model for the Warrants are based on assumptions that include (i) a stock price volatility of 33%, (ii) a risk-free rate of return based on a three year swap curve rate of 6.03%, and (iii) a Warrant exercise term of three years. The Securities and Exchange Commission requires disclosure of the value of consideration offered in connection with the Exchange Offer. BENTON'S USE OF THE BLACK-SCHOLES MODEL TO INDICATE THE PRESENT VALUE OF THE WARRANTS TO BE ISSUED IS NOT AN ENDORSEMENT OF THIS VALUATION, WHICH IS BASED UPON CERTAIN ASSUMPTIONS, INCLUDING THE ASSUMPTION THAT THE WARRANT WILL BE HELD FOR THE FULL THREE-YEAR TERM PRIOR TO EXERCISE. 17 31 METHOD OF DETERMINING EXCHANGE VALUE FOR 1989-1 PARTNERSHIP Components of the Exchange Value. The most significant assets considered by Benton in determining the Exchange Value of the 1989-1 Units were the anticipated net proceeds from the sale of the Umbrella Point Field. The purchase offer from Goldking was analyzed by Benton, based in part on the Proved Reserves of the 1989-1 Partnership and the estimated net cash flows attributable thereto, derived from a reserve report for the 1989-1 Partnership prepared by Benton and audited by Huddleston. The Exchange Values represent the sum of (i) the estimated cash proceeds from the anticipated sale to Goldking of the Umbrella Point Field, and (ii) the tax-basis balances of equipment as of December 31, 1994 and the net book value of current assets and liabilities (reflected on the unaudited balance sheet) of the 1989-1 Partnership as of June 30, 1995. These components represent all of the assets and liabilities of the 1989-1 Partnership and were determined as of June 30, 1995 to conform with the SEC reporting requirements for unaudited financial information. In determining the Exchange Value, Benton also considered the total consideration paid to date to participants in the 1989-1 Partnership. For the 1989-1 Partnership, and each of the other Partnerships, Benton assigned a Total Exchange Value to the Partnership which, based upon certain assumptions described herein, and in addition to the distributions paid to date, would provide Investors with consideration valued at 100% of their initial contribution to the Partnership. See "-- General Intangibles." The estimated cash proceeds from the sale to Goldking and the value of other tangible assets of the Partnership are attributable to shares of Benton Common Stock, or cash if the Investor makes the cash election described herein. The remaining dollar value, if any, is referred to herein as General Intangibles. Pursuant to the Exchange Offer, value attributed to General Intangibles will be distributed to Investors in the form of Warrants. The following unaudited table sets forth (i) the components of the Exchange Values of the 1989-1 Units and (ii) the Exchange Value per 1989-1 Unit held by an Investor. This information was compiled by Benton from the 1989-1 Partnership's tax records for the year ended December 31, 1994 and financial statements for the six months ended June 30, 1995. 18 32 1989-1 PARTNERSHIP EXCHANGE VALUE TABLE
Participants Total Exchange Value Per Exchange Value(1) Partnership Unit(2) ----------------- ------------------- COMPONENTS OF EXCHANGE VALUES: Estimated Cash Proceeds-Umbrella Point Field Sale................ $323,296 $1,147 Estimated Value of Proved Reserves of Other Properties at 12/31/94(3)................................................... 0 0 Current assets less current liabilities at 6/30/95(4)............ 6,338 22 Value Of Equipment At 12/31/94(5)................................ 4,563 16 -------- ------ Subtotal-Exchange Value attributable to stock............... 334,197 1,185 -------- ------ GENERAL INTANGIBLES.............................................. 35,901 127 -------- ------ Subtotal-Exchange Value attributable to Warrants............ 35,901 127 -------- ------ TOTAL EXCHANGE VALUE............................................. $370,098 $1,312 ======== ====== NUMBER OF SHARES OF COMMON STOCK TO BE ISSUED PER PARTNERSHIP UNIT(6) .................................... 107 NUMBER OF WARRANTS TO BE ISSUED PER PARTNERSHIP UNIT(7)... 35
- ---------------------------------- (1) No exchange value is attributable to Managing General Partner's interest. (2) Obtained by dividing the Total Exchange Value by 281.8182 partnership units. (3) Value of estimated future net cash flows from Proved Reserves of the Partnership excluding the Umbrella Point Field, as of December 31, 1994, as reflected in the reserve report for the Partnership as of that date. (4) Net book value of current assets and liabilities at June 30, 1995. (5) Tax-basis balances of equipment, excluding Umbrella Point Field equipment, at December 31, 1994. (6) Obtained by dividing the Total Exchange Value attributable to stock by the Common Stock price of $11.00, subject to rounding adjustments. (7) Obtained by dividing the estimated value of General Intangibles by the estimated present value of the Warrants ($3.64 per Warrant). Benton has determined the value attributed to General Intangibles based solely upon its evaluation of the success to date of the Partnership, total consideration paid to date to the participants and the value to Benton in dissolving and liquidating the Partnership. 19 33 Anticipated Sales Proceeds. In July 1995, Benton, on behalf of the 1989-1 Partnership, and Goldking executed an agreement whereby Goldking will purchase a 4.93% working interest in the Umbrella Point Field from the 1989-1 Partnership, subject to approval of the participants of the Partnership. Upon execution of the agreement, Goldking made an earnest money deposit in favor of the Partnership of $4,929, included as current assets of the Partnership (the "Deposit"). Subject to closing adjustments and excluding the Deposit, as of June 30, 1995 the Partnership's estimated cash proceeds from the sale would be $323,296, or $1,147 per 1989-1 Unit. Benton has made this Exchange Offer in contemplation of such sale, but the Exchange Offer is not conditioned upon consummation of such sale. General Intangibles. In determining the value attributed to General Intangibles, Benton evaluated the success to date of the 1989-1 Partnership, total consideration paid to date to the participants and the value to Benton of dissolving and liquidating the 1989-1 Partnership so that Benton can focus on its current operations and reduce the administrative burdens associated with operating the Partnership. Based upon Benton's evaluation of historical administrative costs for the 1989-1 Partnership, Benton estimates that the administrative costs for operating the Partnership will be approximately $35,000 per year. From inception through September 1995, the 1989-1 Partnership had made cash distributions to participants aggregating $848,836, or $3,012 per 1989-1 Unit. Benton acknowledges the concerns raised by the Investors in the 1989-1 Partnership with regard to operations of the Partnership, the lack of success and thus the disappointing returns on investment by the Investors. Because many of the Investors are or were stockholders of Benton, Benton desires to maintain a good relationship with these stockholders, many of whom have been strong supporters of Benton from inception, and Benton desires to avoid future claims against it by participants relating to the management of the Partnership. See "The Exchange Offer and Proposal -- Litigation and Related Matters." Assuming that the Investor in the 1989-1 Partnership elects to hold his or her shares of Common Stock and exercises his or her Warrants at the end of the three-year term, and the market price of the Common Stock is at or above approximately $16.75 per share, Benton believes that the Investors in the 1989-1 Partnership will have received consideration in the form of cash distributions, Common Stock and Warrants in excess of the initial investment in the 1989-1 Partnership, without regard to any tax benefits received by the participants. On October 2, 1995, the last sales price of the Benton Common Stock on NASDAQ National Market was $11.13 per share. The assumed market price of the Common Stock of $16.75 per share discussed above represents a 34% increase in the market value of the Benton Common Stock during the three year term of the Warrants. There can be no assurance that the market price of the Benton Common Stock will increase or that such price will be achieved. The value of the General Intangibles of the Partnership is not subject to valuation by third parties since the General Intangibles do not represent actual assets of the Partnership. Benton believes that the participants in the Partnership will not receive any value for the General Intangibles in any alternative to the Exchange. METHOD OF DETERMINING EXCHANGE VALUE FOR 1990-1 PARTNERSHIP Components of the Exchange Value. The most significant assets considered by Benton in determining the Exchange Value of the 1990-1 Units were the anticipated net proceeds from the sale of the Umbrella Point Field and Proved Reserves of the 1990-1 Partnership. The Exchange Values represent the sum of (i) the estimated cash proceeds from the anticipated sale of Umbrella Point Field to Goldking, (ii) the estimated present value of future net cash flows from the Proved Reserves of the 1990-1 Partnership as of December 31, 1994, discounted at 10% per year and calculated without escalation of prices and costs, as reflected in the reserve report for the 1990-1 Partnership as of that date prepared by Benton and audited by Huddleston, (iii) the tax-basis balances of equipment as of December 31, 1994 and the net book value of current assets and liabilities (reflected on the unaudited balance sheet) of the 20 34 1990-1 Partnership as of June 30, 1995, and (iv) the value of General Intangibles. These components represent all of the assets and liabilities of the 1990-1 Partnership and were determined as of the year end and June 30, 1995 to conform with the SEC reporting requirements for reserve information and unaudited financial information, respectively. Since the year-end reserve information is audited, the Exchange Values were derived from that information. In determining the Exchange Value, Benton also considered the total consideration paid to date to participants in the 1990-1 Partnership. For the 1990-1 Partnership, and each of the other Partnerships, Benton assigned a Total Exchange Value to the Partnership which, based upon certain assumptions described herein, and in addition to the distributions paid to date, would provide Investors with consideration valued at 100% of their initial contribution to the Partnership. See "- General Intangibles" for a discussion of the assumptions used by Benton. The estimated cash proceeds from the sale to Goldking and the value of other tangible assets of the Partnership are attributable to shares of Benton Common Stock, or cash if the investor makes the cash election described herein. The remaining dollar value is referred to herein as General Intangibles. Pursuant to the Exchange Offer, value attributed to General Intangibles will be distributed to Investors in the form of Warrants. The following unaudited table sets forth (i) the components of the Exchange Values of the 1990-1 Units and (ii) the Exchange Value per 1990-1 Unit held by an Investor. This information was compiled by Benton from the 1990-1 Partnership's reserve report as of December 31, 1994 (a summary of which is included in Exhibit B to this Prospectus) and the 1990-1 Partnership's tax records for the year ended December 31, 1994 and financial statements for the six months ended June 30, 1995. 21 35 1990-1 PARTNERSHIP EXCHANGE VALUE TABLE
COMPONENTS OF EXCHANGE VALUES: Estimated Cash Proceeds-Umbrella Point Field Sale................ $ 930,865 $ 656 Estimated Value Of Proved Reserves of Other Properties at 12/31/94(3)................................................... 119,694 84 Current assets less current liabilities at 6/30/95(4)............ 201,736 142 Value of equipment at 12/31/94(5)................................ 13,037 9 ---------- ------ Subtotal--Exchange Value attributable to stock.............. 1,265,332 891 ---------- ------ General Intangibles.............................................. 1,725,396 1,216 ---------- ------ Subtotal--Exchange Value attributable to warrants........... 1,725,396 1,216 ---------- ------ TOTAL EXCHANGE VALUE............................................. $2,990,728 $2,107 ========== ====== NUMBER OF SHARES OF COMMON STOCK TO BE ISSUED PER PARTNERSHIP UNIT(6)....................................... 81 NUMBER OF WARRANTS TO BE ISSUED PER PARTNERSHIP UNIT(7)..... 334
- --------------------------------- (1) No exchange value is attributable to Managing General Partner's interest. (2) Obtained by dividing the Total Exchange Value by 1,419.192 partnership units. (3) Value of estimated future net cash flows from Proved Reserves of the Partnership excluding the Umbrella Point Field, as of December 31, 1994, as reflected in the reserve report for the Partnership as of that date. (4) Net book value of current assets and liabilities at June 30, 1995. (5) Tax-basis balances of equipment, excluding Umbrella Point Field equipment, at December 31, 1994. (6) Obtained by dividing the Exchange Value attributable to stock by the Common Stock price of $11.00, subject to rounding adjustments. (7) Obtained by dividing the estimated value of General Intangibles by the estimated present value of the Warrants ($3.64 per Warrant). Benton has determined the value attributed to General Intangibles based solely upon its evaluation of the success to date of the Partnership, total consideration paid to date to the participants and the value to Benton in dissolving and liquidating the Partnership. Anticipated Sales Proceeds. In July 1995, Benton, on behalf of the 1990-1 Partnership, and Goldking executed an agreement whereby Goldking will purchase a 14.19% working interest in the Umbrella Point Field from the 1990-1 Partnership, subject to approval of the participants of the Partnership. Upon execution of the agreement, Goldking made an earnest money deposit in favor of the Partnership of $14,192, included as current assets of the Partnership (the "Deposit"). Subject to closing adjustments and excluding the Deposit, as of June 30, 1995 the Partnership's estimated cash proceeds from the sale would be $930,865, or $656 per 1990-1 Unit. Benton has made this Exchange Offer in contemplation of such sale, but the Exchange Offer is not conditioned upon consummation of such sale. 22 36 Proved Reserves. Proved Reserves of the 1990-1 Partnership and the estimated net cash flows attributable thereto were derived from a reserve report for the 1990-1 Partnership prepared by Benton and audited by Huddleston. The reserve estimates were prepared in accordance with SEC regulations, with estimated future net cash flows from Proved Reserves based on prices as of the date of the report held constant over the estimated life of the reserves and discounted at the prescribed rate of 10% per annum ("SEC PV 10"). No risk adjustment factor was applied to the estimated future net cash flows from the Proved Reserves of the 1990-1 Partnership to account for uncertainties inherent in projecting future production rates, and no adjustment was made to take into account fluctuations in oil and gas prices after December 31, 1994. General Intangibles. In determining the value attributed to General Intangibles, Benton evaluated the success to date of the 1990-1 Partnership, total consideration paid to date to the participants and the value to Benton of dissolving and liquidating the 1990-1 Partnership so that Benton can focus on its current operations and reduce the administrative burdens associated with operating the Partnership. Based upon Benton's evaluation of historical administrative costs for the 1990-1 Partnership, Benton estimates that the administrative costs for operating the Partnership will be approximately $80,000 per year. From inception through September 1995, the 1990-1 Partnership has made cash distributions to participants aggregating $2,452,364, or $1,728 per 1990-1 Unit. Benton acknowledges the concerns raised by the Investors in the 1990-1 Partnership with regard to operations of the Partnership, the lack of success and thus the disappointing returns on investment by the Investors. Because many of the Investors are or were stockholders of Benton, Benton desires to maintain a good relationship with these stockholders, many of whom have been strong supporters of Benton from inception, and Benton desires to avoid future claims against it by participants relating to the management of the Partnership. See "The Exchange Offer and Proposal -- Litigation and Related Matters." Assuming that the Investor in the 1990-1 Partnership elects to hold his or her shares of Common Stock and exercises his or her Warrants at the end of the three-year term, and the market price of the Common Stock is at or above approximately $16.75 per share, Benton believes that the Investors in the 1990-1 Partnership will have received consideration in the form of cash distributions, Common Stock and Warrants in excess of the initial investment in the 1990-1 Partnership, without regard to any tax benefits received by the participants. On October 2, 1995, the last sales price of the Benton Common Stock on NASDAQ National Market was $11.13 per share. The assumed market price of the Common Stock of $16.75 per share discussed above represents a 34% increase in the market value of the Benton Common Stock during the three year term of the Warrants. There can be no assurance that the market price of the Benton Common Stock will increase or that such price will be achieved. The value of the General Intangibles of the Partnership is not subject to valuation by third parties since the General Intangibles do not represent actual assets of the Partnership. Benton believes that the participants in the Partnership will not receive any value for the General Intangibles in any alternative to the Exchange. Uncertainties Inherent in Valuation Methodology. There are numerous uncertainties inherent in estimating quantities and production rates of hydrocarbons. Estimates of the 1990-1 Partnership's Proved Reserves by independent petroleum engineers other than Huddleston could result in higher or lower valuations than those determined by Benton and audited by Huddleston. The Exchange Values may not reflect the value of the 1990-1 Units or the value of the properties attributable to the 1990-1 Units if sold to an unaffiliated third party in an arm's length transaction. 23 37 METHOD OF DETERMINING EXCHANGE VALUE FOR 1991-1 PARTNERSHIP Components of the Exchange Value. The most significant assets considered by Benton in determining the Exchange Value of the 1991-1 Units were the anticipated net proceeds from the sale of the Umbrella Point Field and Proved Reserves of the 1991-1 Partnership. The Exchange Values represent the sum of (i) the estimated cash proceeds from the anticipated sale of Umbrella Point Field to Goldking, (ii) the estimated present value of future net cash flows from the Proved Reserves of the 1991-1 Partnership as of December 31, 1994, discounted at 10% per year and calculated without escalation of prices and costs, as reflected in the reserve report for the 1991-1 Partnership as of that date prepared by Benton and audited by Huddleston, (iii) the tax-basis balances of equipment as of December 31, 1994 and the net book value of current assets and liabilities (reflected on the unaudited balance sheet) of the 1991-1 Partnership as of June 30, 1995, and (iv) the value of General Intangibles. These components represent all of the assets and liabilities of the 1991-1 Partnership and were determined as of year end and June 30, 1995 to conform with the SEC reporting requirements for reserve information and unaudited financial information, respectively. Since the year-end reserve information is audited, the Exchange Values were derived from that information. In determining the Exchange Value, Benton also considered the total consideration paid to date to participants in the 1991-1 Partnership. For the 1991-1 Partnership, and each of the other Partnerships, Benton assigned a Total Exchange Value to the Partnership which, based upon certain assumptions described herein, and in addition to the distributions paid to date, would provide Investors with consideration valued at 100% of their initial contribution to the Partnership. See "- General Intangibles" for a discussion of the assumptions used by Benton. The estimated cash proceeds from the sale to Goldking and the value of other tangible assets of the Partnership are attributable to shares of Benton Common Stock, or cash if the Investor makes the cash election described herein. The remaining dollar value is referred to herein as General Intangibles. Pursuant to the Exchange Offer, value attributed to General Intangibles will be distributed to Investors in the form of Warrants. The following unaudited table sets forth (i) the components of the Exchange Values of the 1991-1 Units and (ii) the Exchange Value per 1991-1 Unit held by an Investor. This information was compiled by Benton from the 1991-1 Partnership's reserve report as of December 31, 1994 (a summary of which is included in Exhibit B to this Prospectus) and the 1991-1 Partnership's tax records for the year ended December 31, 1994 and financial statements for the six months ended June 30, 1995. 24 38 1991-1 PARTNERSHIP EXCHANGE VALUE TABLE
Participants Total Exchange Value Per Exchange Value(1) Partnership Unit(2) ----------------- ------------------- COMPONENTS OF EXCHANGE VALUES: Estimated Cash Proceeds--Umbrella Point Field Sale............ $185,282 $ 657 Estimated Value of Proved Reserves of Other Properties at 12/31/94(3)............................................... 23,856 85 Current Assets Less Current Liabilities At 6/30/95(4)........ 85,716 304 Value Of Equipment At 12/31/94(5)............................ 2,555 9 -------- ------ Subtotal-Exchange Value attributable to stock........... 297,409 1,055 -------- ------ General Intangibles.......................................... 394,940 1,401 -------- ------ Subtotal-Exchange Value attributable to warrants........ 394,940 1,401 -------- ------ TOTAL EXCHANGE VALUE......................................... $692,349 $2,456 ======== ====== NUMBER OF SHARES OF COMMON STOCK TO BE ISSUED PER PARTNERSHIP UNIT(6)............................... 95 NUMBER OF WARRANTS TO BE ISSUED PER PARTNERSHIP Unit(7)........................................... 385
- -------------------------------- (1) No exchange value is attributable to Managing General Partner's interest. (2) Obtained by dividing the Total Exchange Value by 281.8182 partnership units. (3) Value of estimated future net cash flows from Proved Reserves of the Partnership excluding the Umbrella Point Field, as of December 31, 1994, as reflected in the reserve report for the Partnership as of that date. (4) Net book value of current assets and liabilities at June 30, 1995. (5) Tax-basis balances of equipment, excluding Umbrella Point Field equipment, at December 31, 1994. (6) Obtained by dividing the Exchange Value attributable to stock by the Common Stock price of $11.00, subject to rounding adjustments. (7) Obtained by dividing the estimated value of General Intangibles by the estimated present value of the Warrants ($3.64 per Warrant). Benton has determined the value attributed to General Intangibles based solely upon its evaluation of the success to date of the Partnership, total consideration paid to date to the participants and the value to Benton in dissolving and liquidating the Partnership. Anticipated Sales Proceeds. In July 1995, Benton, on behalf of the 1991-1 Partnership, and Goldking executed an agreement whereby Goldking will purchase a 2.83% working interest in the Umbrella Point Field from the 1991-1 Partnership, subject to approval of the participants of the Partnership. Upon execution of the agreement, Goldking made an earnest money deposit in favor of the Partnership of $2,824, included as current assets of the Partnership (the "Deposit"). Subject to closing adjustments and excluding the Deposit, as of June 30, 1995 the Partnership's estimated cash proceeds from the sale would be $185,282, or $657 per 1991-1 Unit. Benton has made this Exchange Offer in contemplation of such sale, but the Exchange Offer is not conditioned upon consummation of such sale. 25 39 Proved Reserves. Proved Reserves of the 1991-1 Partnership and the estimated net cash flows attributable thereto were derived from a reserve report for the 1991-1 Partnership prepared by Benton and audited by Huddleston. The reserve estimates were prepared in accordance with SEC regulations, with estimated future net cash flows from Proved Reserves based on prices as of the date of the report held constant over the estimated life of the reserves and discounted at the prescribed rate of 10% per annum ("SEC PV 10"). No risk adjustment factor was applied to the estimated future net cash flows from the Proved Reserves of the 1991-1 Partnership to account for uncertainties inherent in projecting future production rates, and no adjustment was made to take into account fluctuations in oil and gas prices after December 31, 1994. General Intangibles. In determining the value attributed to General Intangibles, Benton evaluated the success to date of the 1991-1 Partnership, total consideration paid to date to the participants and the value to Benton of dissolving and liquidating the 1991-1 Partnership so that Benton can focus on its current operations and reduce the administrative burdens associated with operating the Partnership. Based upon Benton's evaluation of historical administrative costs for the 1991-1 Partnership, Benton estimates that the administrative costs for operating the Partnership will be approximately $31,000 per year. From inception through July 1995, the 1991-1 Partnership has made cash distributions to participants aggregating $338,182, or $1,200 per 1991-1 Unit. Benton acknowledges the concerns raised by the Investors in the 1991-1 Partnership with regard to operations of the Partnership, the lack of success and thus the disappointing returns on investment by the Investors. Because many of the Investors are or were stockholders of Benton, Benton desires to maintain a good relationship with these stockholders, many of whom have been strong supporters of Benton from inception, and Benton desires to avoid future claims against it by participants relating to the management of the Partnership. See "The Exchange Offer and Proposal--Litigation and Related Matters." Assuming that the Investor in the 1991-1 Partnership elects to hold his or her shares of Common Stock and exercises his or her Warrants at the end of the three-year term, and the market price of the Common Stock is at or above approximately $16.75 per share, Benton believes that the Investors in the 1991-1 Partnership will have received consideration in the form of cash distributions, Common Stock and Warrants in excess of the initial investment in the 1991-1 Partnership, without regard to any tax benefits received by the participants. On October 2, 1995, the last sales price of the Benton Common Stock on NASDAQ National Market was $11.13 per share. The assumed market price of the Common Stock of $16.75 per share discussed above represents a 34% increase in the market value of the Benton Common Stock during the three year term of the Warrants. There can be no assurance that the market price of the Benton Common Stock will increase or that such price will be achieved. The value of the General Intangibles of the Partnership is not subject to valuation by third parties since the General Intangibles do not represent actual assets of the Partnership. Benton believes that the participants in the Partnership will not receive any value for the General Intangibles in any alternative to the Exchange. Uncertainties Inherent in Valuation Methodology. There are numerous uncertainties inherent in estimating quantities and production rates of hydrocarbons. Estimates of the 1991-1 Partnership's Proved Reserves by independent petroleum engineers other than Huddleston could result in higher or lower valuations than those determined by Benton and audited by Huddleston. The Exchange Values may not reflect the value of the 1991-1 Units or the value of the properties attributable to the 1991-1 Units if sold to an unaffiliated third party in an arm's length transaction. 26 40 CONSENT PROCEDURES To tender Partnership Units in exchange for Common Stock and Warrants at the Exchange Rate applicable to the Partnership Unit and thereby consent to the Proposal, an Investor should complete and sign the Letter of Transmittal accompanying this Prospectus (a form of which is included as Exhibit D, and return it to Benton during the 60-day period ending at 5:00 p.m. Pacific Time on _________, 1995 (the "Expiration Date"). The Expiration Date may be extended for up to an additional 10-day period, although no extension is presently contemplated. Benton will not accept tenders of less than all of the Partnership Units held by an Investor. Tenders of Units and consents to the Proposals may be withdrawn upon written notice to Benton at any time prior to the Expiration Date. See "Consent Procedures." CONDITIONS TO EXCHANGE Closing Date. The Exchange Offer is expected to be consummated on the Closing Date, which will be no more than five days following the Expiration Date, as extended. 1989-1 Partnership. The Exchange Offer to the 1989-1 Partnership is conditioned upon consent of 75% of the 1989-1 Units to the 1989-1 Proposal and the absence of any material adverse development affecting the 1989-1 Partnership, as determined by Benton in the exercise of reasonable judgment. On the Closing Date, subject to satisfaction of these conditions, Benton intends to accept all 1989-1 Units validly tendered and not withdrawn pursuant to the Exchange Offer. 1990-1 Partnership. The Exchange Offer to the 1990-1 Partnership is conditioned upon consent of 75% of the 1990-1 Units to the 1990-1 Proposal and the absence of any material adverse development affecting the 1990-1 Partnership, as determined by Benton in the exercise of reasonable judgment. On the Closing Date, subject to satisfaction of these conditions, Benton intends to accept all 1990-1 Units validly tendered and not withdrawn pursuant to the Exchange Offer. 1991-1 Partnership. The Exchange Offer to the 1991-1 Partnership is conditioned upon consent of 75% of the 1991-1 Units to the 1991-1 Proposal and the absence of any material adverse development affecting the 1991-1 Partnership, as determined by Benton in the exercise of reasonable judgment. On the Closing Date, subject to satisfaction of these conditions, Benton intends to accept all 1991-1 Units validly tendered and not withdrawn pursuant to the Exchange Offer. REGULATORY APPROVALS No federal or state regulatory approval is required in connection with the Exchange Offer or the adoption of the Proposals by the Partnerships. CERTAIN HISTORICAL AND PRO FORMA FINANCIAL DATA Benton Selected Historical and Unaudited Pro Forma Consolidated Financial Data. The following selected consolidated financial data for Benton Oil and Gas Company as of and for each of the years in the five year period ended December 31, 1994 are derived from Benton's audited consolidated financial statements. The selected consolidated financial data for the six months ended June 30, 1994 and 1995 are derived from Benton's unaudited financial statements. In the opinion of management, such unaudited financial statements contain all adjustments (consisting of only normal recurring accruals) necessary for a fair presentation of the financial condition and results of operations as of and for the 27 41 periods presented. Operating results for the six months ended June 30, 1995 are not necessarily indicative of the results that may be expected for the entire fiscal year ending December 31, 1995. The pro forma operating data and pro forma balance sheet data below give effect to the Exchange Offer as if it had been completed on January 1, 1994 and June 30, 1995, respectively. The selected consolidated financial data below should be read in conjunction with Benton's consolidated financial statements and related notes thereto, Management's Discussion and Analysis of Financial Condition and Results of Operations, and Pro Forma Financial Information included elsewhere herein or incorporated by reference herein.
IN THOUSANDS, EXCEPT Six Months Ended PER SHARE AMOUNTS Years Ended December 31 June 30 ------------------------------------------------ ------------------ 1990(3) 1991(3) 1992 1993 1994 1994 1995 ------- ------- ---- ---- ---- ---- ---- OPERATING DATA Total revenues......... $ 4,677 $11,513 $ 8,622 $ 7,503 $ 34,705 $ 12,160 $25,870 Lease operating costs and production taxes..... 1,609 4,209 4,414 5,110 9,531 3,948 5,287 Depletion, depreciation and amortization......... 882 3,058 3,041 2,633 10,298 3,421 6,473 General and administrative expense.............. 1,709 1,998 2,245 2,631 5,242 2,445 3,884 Interest expense....... 318 1,736 1,831 1,958 3,888 1,597 3,361 ------- ------- ------- ------- -------- -------- ------- Income (loss) before income taxes and minority interest.... 159 512 (2,909) (4,829) 5,746 749 6,865 Income tax expense..... --- --- --- --- 698 --- 1,971 ------- ------- ------- ------- -------- -------- ------- Income (loss) before minority interest.... 159 512 (2,909) (4,829) 5,048 749 4,894 Minority interest...... --- --- --- --- 2,094 747 1,742 ------- ------- ------- ------- -------- --- ------- Net income (loss)...... $ 159 $ 512 $(2,909) $(4,829) $ 2,954 $ 2 $ 3,152 ======= ======= ======= ======= ======== ======== ======= Net income (loss) per common share(1).. $ 0.02 $ 0.04 $ (0.22) $ (0.26) $ 0.12 $ 0.00 $ 0.12 ======= ======= ======= ======= ======== ======== ======= Weighted average common shares outstanding(1)(2).... 10,357 11,838 12,981 18,609 24,851 25,153 26,459 Ratio of earnings to fixed charges(5)..... 1.47x 1.29x --- --- 1.92x 1.00x 2.51x Net increase (decrease) in cash and cash equivalents.......... $ 3,621 $(1,401) $ 9,996 $22,635 $(22,116) $(34,022) $11,224 Net cash provided by (used in) operating activities........... $ 4,797 $ 4,027 $ (648) $(1,790) $ 13,463 $ 3,299 $ 8,187
28 42
Year Ended Six Months Ended December 31, June 30, 1994 1995 ---- ---- PRO FORMA Before roll-up expenses and payments: Net income............................... $2,790 $3,035 Income per common share.................. $ 0.11 $ 0.11 Ratio of earnings to fixed charges(5).... 1.88x 2.47x After roll-up expenses and payments: Net income............................... $ 89 $3,035 Income per common share.................. $ 0.00 $ 0.11 Ratio of earnings to fixed charges(5).... 1.20x 2.47x
At December 31 At June 30, 1995 IN THOUSANDS, EXCEPT PER ------------------------------------------------ --------------------- SHARE AMOUNTS 1990 1991 1992 1993 1994 HISTORICAL PRO FORMA ---- ---- ---- ---- ---- ---------- --------- BALANCE SHEET DATA Cash and cash equivalents $ 5,078 $ 3,677 $13,673 $ 36,308 $ 14,193 $ 25,416 $ 25,105 Working capital (deficit) (1,861) (14,777) 10,486 26,635 21,785 22,139 23,327 Total assets 27,253 49,386 68,217 108,635 162,561 190,209 191,495 Long-term obligations, net of current portion 7,251 7,422 11,288 11,788 31,911 53,268 53,268 Total liabilities 17,190 29,177 15,574 24,614 74,302 97,400 97,340 Stockholders' equity(4) 10,064 20,209 50,468 84,021 88,259 92,809 94,155 Book Value Per Share $ 1.17 $ 1.96 $ 2.89 $ 3.40 $ 3.54 $ 3.70 $ 3.72
- ----------------- (1) The share information for the Company has been adjusted to reflect two-for-one stock splits in the form of 100% stock dividends effective July 9, 1990 and February 26, 1991. (2) The weighted average common shares outstanding for the Company have been adjusted for the effect of common stock equivalents for the years ended December 31, 1990, 1991 and 1994 and for the six months ended June 30, 1994 and 1995. (3) For the years ended December 31, 1991 and 1990 the Company recorded income tax expense of $174,000 and $41,000 respectively, and an extraordinary item for the utilization of loss carry forward for the same amounts. (4) No cash dividends were paid during any period presented. (5) For purposes of computing the ratio, "earnings" represents income (loss) from operations before income taxes and extraordinary items plus fixed charges exclusive of capitalized interest, and "fixed charges" consists of interest whether expensed or capitalized, amortization of debt expense and an estimated portion of rent expense representing interest costs. As a result of losses incurred by the Company for the years ended December 31, 1993 and 1992, earnings did not cover fixed charges by $4,829,000 and $2,909,000, respectively. 29 43 1989-1 Partnership Selected Historical Financial Data. The following selected financial data for the 1989-1 Partnership as of and for each of the years in the five year period ended December 31, 1994 are derived from the 1989-1 Partnership's audited financial statements. The selected consolidated financial data for the six months ended June 30, 1994 and 1995 are derived from the 1989-1 Partnership's unaudited financial statements. In the opinion of management, such unaudited financial statements contain all adjustments (consisting of only normal recurring accruals) necessary for a fair presentation of the financial condition and results of operations as of and for the periods presented. Operating results for the six months ended June 30, 1995 are not necessarily indicative of the results that may be expected for the entire fiscal year ending December 31, 1995. The selected financial data below should be read in conjunction with the 1989-1 Partnership's financial statements and related notes thereto and Management's Discussion and Analysis of Financial Condition and Results of Operations included elsewhere in this proxy Statement/Prospectus.
Six Months Ended Years Ended December 31, June 30, ----------------------------------------------------------------- ----------------------- 1990 1991 1992 1993 1994 1994 1995 ---- ---- ---- ---- ---- ---- ---- Operating Data Total revenue $ 212,781 $ 217,023 $ 225,460 $ 203,380 $ 160,413 $ 87,880 $ 77,765 Lease operating costs and production taxes 60,471 85,894 73,309 76,855 79,479 33,929 31,001 Exploration costs 1,627 1,891 789 789 Depletion, impairment and amortization 46,224 74,122 111,050 72,453 77,895 42,831 90,155 General and administrative 31,086 17,428 32,110 38,432 33,654 27,032 31,746 --------- --------- --------- --------- --------- --------- --------- Net income (loss) $ 75,000 $ 39,579 $ 7,364 $ 13,749 ($ 31,404) ($ 16,701) ($ 75,137) ========= ========= ========= ========= ========= ========= ========= Net decrease in cash and cash equivalents ($100,529) ($ 82,547) ($241,781) ($127,320) ($106,355) ($ 10,024) ($ 684) Net cash provided by operating activities 187,669 111,201 117,414 86,202 46,491 26,130 15,018 Distributions 140,064 211,364 281,818 169,936 135,615 30,436 -- Per Unit Operating Data (1) Net income (loss) 192 61 (70) (16) (149) (86) (300) Distributions of earnings 192 61 -- -- -- -- -- Distributions representing a return of capital 308 686 1,003 600 162 108 --
December 31, June 30, ------------------------------------------------------------ -------------------- 1990 1991 1992 1993 1994 1994 1995 ---- ---- ---- ---- ---- ---- ---- Balance Sheet Data Cash and cash equivalents $ 564,404 $ 481,857 $240,076 $112,756 $ 6,401 $102,732 $ 5,717 Total assets at book value 1,177,716 1,016,060 727,977 571,790 407,052 524,653 329,634 Total assets at the value assigned for purposes of roll-up transaction 370,098 Total liabilities 3,500 13,629 -- -- 2,281 -- -- General and limited partners' equity: Managing General Partner 34,706 54,437 79,213 94,780 14,658 101,700 23,147 Participants 1,139,510 947,994 648,764 477,010 390,113 422,953 306,487 ---------- ---------- -------- -------- -------- -------- -------- $1,174,216 $1,002,431 $727,977 $571,790 $404,771 $524,653 $329,634 ========== ========== ======== ======== ======== ======== ======== Per Unit Balance Sheet Data(1) Book value $ 4,084 $ 3,398 $ 2,325 $ 1,710 $ 1,398 $ 1,516 $ 1,099 Value assigned for purpose of the roll-up transaction 1,312 (1) Per unit data is based on indicated amounts allocable to limited partners other than Benton divided by 279 limited partner units outstanding.
30 44 1990-1 Partnership Selected Historical Financial Data. The following selected financial data for the 1990-1 Partnership as of and for each of the years in the five year period ended December 31, 1994 are derived from the 1990-1 Partnership's audited financial statements. The selected consolidated financial data for the six months ended June 30, 1994 and 1995 are derived from the 1990-1 Partnership's unaudited financial statements. In the opinion of management, such unaudited financial statements contain all adjustments (consisting of only normal recurring accruals) necessary for a fair presentation of the financial condition and results of operations as of and for the periods presented. Operating results for the six months ended June 30, 1995 are not necessarily indicative of the results that may be expected for the entire fiscal year ending December 31, 1995. The selected financial data below should be read in conjunction with the 1990-1 Partnership's financial statements and related notes thereto and Management's Discussion and Analysis of Financial Condition and Results of Operations included elsewhere in this Proxy Statement/Prospectus.
Six Months Ended Inception to Years Ended December 31 June 30, December 31 --------------------------------------------------- -------------------------- 1990 1991 1992 1993 1994 1994 1995 ----------- ---- ---- ---- ---- ---- ---- Operating Data Total revenue $ 477,806 $ 1,104,681 $ 770,517 $ 645,459 $ 524,786 $ 280,792 $ 235,273 Lease operating costs and production taxes 155,247 440,434 285,840 254,903 263,957 112,323 100,135 Exploration costs 29,089 887,842 8,952 9,570 6,607 5,331 1,812 Loss on sale of oil and gas properties 57,586 1,328 Depletion, impairment and amortization 142,600 425,583 1,560,665 189,309 224,635 113,834 153,641 General and administrative 36,753 176,317 69,510 99,967 78,547 58,782 67,323 ----------- ----------- ----------- --------- ----------- ----------- ----------- Net income (loss) $ 114,117 ($ 825,495) ($1,212,036) $ 91,710 ($ 48,960) ($ 9,478) ($ 88,966) =========== =========== =========== ========= =========== =========== =========== Net increase (decrease) in cash and cash equivalents $ 3,057,412 ($1,780,352) ($ 399,559) ($457,675) ($ 401,967) $ 9,583 $ 127,596 Net cash provided by operating activities 124,336 356,853 407,453 290,032 173,410 104,807 66,003 Distributions --- 706,351 1,071,312 604,582 463,345 64,633 -- Per Unit Operating Data (1) Net income (loss) 24 (703) (935) 9 (68) (27) (76) Distributions of earnings -- -- -- -- -- -- -- Distributions representing a return of capital -- 500 762 400 66 44 --
December 31, June 30, ---------------------------------------------------------- ---------------------- 1990 1991 1992 1993 1994 1994 1995 ---- ---- ---- ---- ---- ---- ---- Balance Sheet Data Cash and cash equivalents $3,057,412 $1,277,060 $ 877,501 $ 419,826 $ 17,859 $ 429,409 $ 145,455 Total assets at book value 6,719,035 4,713,665 2,380,317 1,867,445 1,355,140 1,793,334 1,266,174 Total assets at the value assigned for purposes of roll-up transaction 2,990,728 Total liabilities 523,524 50,000 -- -- -- -- -- General and Limited Partners' Equity: Managing General Partner 137,695 291,366 386,815 436,921 111,441 462,867 126,832 Participants 6,053,875 4,363,866 1,978,692 1,429,384 1,240,417 1,329,209 1,134,106 Special Limited Partners 3,941 8,433 14,810 1,140 3,282 1,258 5,236 ---------- ---------- ---------- ---------- ---------- ---------- ---------- $6,195,511 $4,663,665 $2,380,317 $1,867,445 $1,355,140 $1,793,334 $1,266,174 ========== ========== ========== ========== ========== ========== ========== Per Unit Balance Sheet Data(1) Book value $ 4,309 $ 3,106 $ 1,408 $ 1,017 $ 883 $ 946 $ 807 Value assigned for purpose of the roll-up transaction 2,107
(1) Per unit data is based on indicated amounts allocable to limited partners other than Benton divided by 1,405 limited partner units outstanding. 31 45 1991-1 Partnership Selected Historical Financial Data. The following selected financial data for the 1991-1 Partnership as of and for each of the years in the four year period ended December 31, 1994 are derived from the 1991-1 Partnership's audited financial statements. The selected consolidated financial data for the six months ended June 30, 1994 and 1995 are derived from the 1991-1 Partnership's unaudited financial statements. In the opinion of management, such unaudited financial statements contain all adjustments (consisting of only normal recurring accruals) necessary for a fair presentation of the financial condition and results of operations as of and for the periods presented. Operating results for the six months ended June 30, 1995 are not necessarily indicative of the results that may be expected for the entire fiscal year ending December 31, 1995. The selected financial data below should be read in conjunction with the 1991-1 Partnership's financial statements and related notes thereto and Management's Discussion and Analysis of Financial Condition and Results of Operations included elsewhere in this Proxy Statement/Prospectus.
Six Months Ended Inception to Years Ended December 31 June 30 December 31 ------------------------------------- ---------------------- 1991 1992 1993 1994 1994 1995 ---- ---- ---- ---- ---- ---- Operating Data Total revenue $ 108,288 $ 160,321 $ 112,524 $ 98,644 $ 52,188 $ 44,852 Lease operating costs and production taxes 54,069 40,093 36,276 38,002 14,599 12,553 Exploration costs 158,016 7,245 1,284 769 515 361 Loss on sale of oil and gas properties 61,225 225 Depletion, impairment and amortization 125,742 65,241 60,503 95,497 32,435 119,437 General and administrative 20,925 28,876 45,195 28,823 25,981 30,500 ----------- --------- --------- --------- -------- --------- Net loss ($ 250,464) ($ 42,359) ($ 30,734) ($ 64,447) ($21,342) ($118,224) =========== ========= ========= ========= ======== ========= Net increase (decrease) in cash and cash equivalents $ 1,233,019 ($955,826) ($100,013) ($117,010) ($54,775) $ 22,377 Net cash provided by (used in) operating activities (7,849) 85,839 38,782 28,758 11,544 1,438 Distributions 27,900 111,600 115,292 127,205 56,546 -- Per Unit Operating Data (1) Net income (loss) (914) (243) (146) (256) (87) (422) Distributions of earnings -- -- -- -- -- -- Distributions representing a return of capital 100 400 400 300 200 --
December 31, June 30, ---------------------------------------------- -------------------- 1991 1992 1993 1994 1994 1995 ---- ---- ---- ---- ---- ---- Balance Sheet Data Cash and cash equivalents $1,233,019 $277,193 $177,180 $ 60,170 $122,405 $ 82,547 Total assets at book value 1,815,157 777,067 631,041 439,389 553,153 321,165 Total assets at the value assigned for purposes of roll-up transaction 692,349 Total liabilities 884,131 -- -- -- -- -- General and Limited Partner's Equity: Managing General Partner 18,413 43,394 50,358 13,601 52,514 12,820 Participants 912,292 732,846 580,591 425,503 500,531 307,888 Special Limited Partners 321 827 92 285 108 457 ---------- -------- -------- -------- -------- -------- $ 931,026 $777,067 $631,041 $439,389 $553,153 $321,165 ========== ======== ======== ======== ======== ======== Per Unit Balance Sheet Data(1) Book value $ 3,270 $ 2,627 $ 2,081 $ 1,525 $ 1,794 $ 1,104 Value assigned for purpose of the roll-up transaction 2,456
(1) Per unit data is based on indicated amounts allocable to limited partners other than Benton divided by 279 limited partner units outstanding. 32 46 CERTAIN COMPARATIVE INFORMATION The following table sets forth certain unaudited comparative per Unit and per share data based on (i) the Financial Statements of the 1989-1 Partnership, the 1990-1 Partnership, the 1991-1 Partnership and Benton at and for the six months ended June 30, 1995 and the year ended December 31, 1994, and (ii) the unaudited pro forma financial information for Benton presented elsewhere in this Prospectus. The equivalent pro forma information for the Partnerships and Benton is based on a primary share computation and assumes that each of the Partnerships will approve the Proposals pursuant to the terms contained herein. The equivalent pro forma information for the 1989-1 Partnership reflects the pro forma per share values of 107 shares of Common Stock issuable per 1989-1 Unit; the equivalent pro forma information for the 1990-1 Partnership reflects the pro forma per share values of 81 shares of Common Stock issuable per 1990-1 Unit; and the equivalent pro forma information for the 1991-1 Partnership reflects the pro forma per share values of 95 shares of Common Stock issuable per 1991-1 Unit.
At or for the Six Months Ended At and for the Year Ended June 30, 1995 December 31, 1994 ------------------------------ ---------------------------- Equivalent Equivalent Historical Pro Forma(1) Historical Pro Forma(1) ---------- ------------ ---------- ------------ 1989-1 PARTNERSHIP: Book value per 1989-1 Unit ....... $ 1,099 $ 398 $ 1,398 N/A Cash distributions per 1989-1 Unit -- -- 162 -- Net income (loss) per 1989-1 Unit (300) 12 (149) $ 12(2) 1990-1 PARTNERSHIP: Book value per 1990-1 Unit ....... $ 807 $ 301 $ 883 N/A Cash distributions per 1990-1 Unit -- -- 66 -- Net income (loss) per 1990-1 Unit (76) 9 (68) $ 9(2) 1991-1 PARTNERSHIP: Book value per 1991-1 Unit ....... $ 1,104 $ 353 $ 1,525 N/A Cash distributions per 1991-1 Unit -- -- 300 -- Net income (loss) per 1991-1 Unit (422) 10 (256) $ 10(2) BENTON OIL AND GAS: Book value per common share ...... $ 3.70 $ 3.72 $ 3.54 N/A Net income per share ............. 0.12 0.11 0.12 $ 0.11(2) Dividends per common share ....... -- -- -- --
- ------------------------- (1) Equivalent pro forma data assumes that each of the Partnerships accepts the Exchange Offer and each of the participants elects to receive Benton Common Stock in exchange for their Units. (2) Equivalent pro forma net income per share and per Unit for the year ended December 31, 1994 is based on pro forma income before roll-up expenses and payments. The equivalent pro forma amounts based on net income after roll-up expenses and payments is $0 per 1989-1 Unit, $0 per 1990-1 Unit, $0 per 1991-1 Unit and $0 per Benton common share. 33 47 RISK FACTORS AND MATERIAL CONSIDERATIONS In addition to the material contained elsewhere herein, the following factors should be carefully considered. RISKS RELATED TO THE EXCHANGE OFFER Elimination of Cash Distributions. The Exchange will result in the Investors holding shares of Common Stock of Benton. Benton has paid no cash dividends on its Common Stock and does not anticipate paying cash dividends on its Common Stock in the foreseeable future. The cash distributions paid by the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership were $54, $22 and $100 per $5,000 Unit, respectively, for each of the first three quarters of 1994 and none of the Partnerships made cash distributions in the fourth quarter of 1994 or in 1995. Despite the elimination of cash distributions to the Partners in connection with the Exchange, Benton believes that if the Partnerships were to continue operations, the cash distributions that Investors would receive from the Partnerships would rapidly decline as the reserves of the Partnerships are depleted. Potential Decline in Market Price of the Common Stock. The Exchange Values, together with the cumulative distributions paid by the Partnerships, reflect a loss on an Investor's initial investment of $676, $1,165 and $1,344 per 1989-1 Unit, 1990-1 Unit and 1991-1 Unit, respectively. Investors will be exposed to a greater loss on their investment if the market price for the Common Stock declines below the Unit Exchange Price. The market price for the Common Stock fluctuated during 1994 from a high of $9.125 per share to a low of $4.25 per share, with an average daily trading volume of 163,855 shares, and has fluctuated from a high of $15.13 per share to a low of $8.63 per share during 1995. See "Price Range of Common Stock, Dividends and Distributions." There may be a large number of shares of Common Stock offered for sale immediately after the Closing Date for various reasons, including the liquidity that the Exchange will afford to Investors, who have not had access to a trading market for the Partnership Units and may wish to liquidate their investment at the first opportunity. This may tend to lower the market price for the Common Stock. Any return to depressed conditions in the oil and gas industry in general and the effect of those conditions on Benton in particular could also adversely affect the market price of the Common Stock. A downturn in the general economic and stock market conditions or in the drilling record and production performance of Benton or results of operations for Benton that are lower than expected by the marketplace could be expected to have a similar impact on the Common Stock. The number of shares of Common Stock offered in exchange for Partnership Units has been determined by dividing the Exchange Value of the tangible assets of the Partnerships by the Common Stock Exchange Price of $11.00, subject to rounding adjustments. The Common Stock Exchange Price is based upon the average closing price of the Company's Common Stock, as reported by NASDAQ National Market, for the 20 trading days from August 14, 1995 through September 11, 1995, and will not be adjusted to reflect any subsequent increase or decrease in the market price of the Common Stock after that date, except to the extent required by dissenters' rights for California residents. See "The Exchange Offer and Proposal--Dissenters' Rights." Lack of Arm's Length Negotiations to Determine Value of Partnership Units. The Exchange Values of the Partnership Units ($1,312 for 1989-1 Units, $2,107 for 1990-1 Units and $2,456 for 1991-1 Units) were determined by Benton based, in part, on the estimated present value of each of the Partnerships' Proved Reserves and Benton's valuation of the General Intangibles of each Partnership (as described herein) and, as a result of Benton's inherent conflict of interests and uncertainties involved in estimating reserve quantities and values, may not reflect the value of the oil and gas properties and other 34 48 assets of each of the Partnerships if all such assets were sold to an unaffiliated third party in an arm's length transaction. See "Uncertainties in the Method of Determining Exchange Values" and "Valuation Conflict of Interest" below. While Benton believes that the methodology employed in determining the Exchange Values is fair to Investors, resulting in valuations that exceed the estimated liquidation values of each of the Partnerships ($294,634 for the 1989-1 Partnership, $1,052,601 for the 1990-1 Partnership and $240,998 for the 1991-1 Partnership), these liquidation values were determined by Benton, without an independent appraisal of such liquidation values. Uncertainties in the Method of Determining Exchange Values. While Benton believes that the method of determining the Exchange Values represents a fair, reasonable and proper method of valuing the Partnership Units, the method of determining the Exchange Values is subject to various uncertainties and may have resulted in a valuation that would differ from offers made by independent bidders. The components of the Exchange Value and the factors underlying these uncertainties are described below. Other Assets and Liabilities. The method of determining the Exchange Values takes into account the estimated value of other assets and liabilities of each of the Partnerships as of June 30, 1995. In calculating the Exchange Values, the net book value of current assets and liabilities of the respective Partnerships was derived from that Partnership's unaudited balance sheet as of June 30, 1995, prepared on the accrual basis. The value of the Partnerships' wells and other equipment was derived from the respective Partnership's tax-basis balances at year end. These balances reflect the cost of the equipment less accumulated depreciation for tax accounting purposes. The tax-basis value of the equipment and the balance sheet book value of current assets and liabilities used by Benton in the calculation of Exchange Values may be higher or lower than the fair market value of those assets and liabilities. Subsequent Events. Exchange Values will not be adjusted to reflect changes in the present value of the estimated future net cash flows attributable to the Proved Reserves of the Partnerships after December 31, 1994, although oil and gas prices in subsequent periods may differ from the prices used on the date of the reserve reports. No Fractional Shares. No fractional shares will be issued in connection with the Exchange Offer. An Investor who would otherwise be entitled to a fractional share of Common Stock will be paid cash in lieu of such fractional shares. Warrants issued in connection with the Exchange Offer will be rounded to the nearest whole number of Warrants and no fractional interest will be issued. Potential Benefits of Alternatives to the Exchange. Instead of proposing the Exchange, Benton could instead continue to operate the Partnerships, or with the approval of the Investors of each of the Partnerships, seek to liquidate the Partnerships' assets and distribute the liquidation proceeds in accordance with the provisions of the Partnership Agreements, enabling Investors to reinvest proceeds from the asset sales in the case of a liquidation and avoid the market risks associated with the ownership of Benton Common Stock to be received in the Exchange. Both alternatives were rejected by Benton based on its analysis of their comparative results and values. Benton believes that continuation of the Partnerships would result in substantial additional reductions in the cash distribution rates for each of the Partnerships due primarily to expected production declines from depletion of reserves. Benton's analysis of continuing the Partnerships in light of these factors, based on average oil and gas prices received in 1994 and reserve data as of December 31, 1994, reflects declines in annual distribution rates (i) per 1989-1 Unit from $600 in 1993 to $162 in 1994, to $114 in 1995, to $146 in 1996, to $91 in 1997 and $7 in 1998, (ii) per 1990-1 Unit from $400 in 1993 to $66 in 1994, to $97 in 1995, to $119 in 1996, to $76 in 1997 and $30 in 1998, and (iii) per 1991-1 Unit from $400 in 1993 to $300 in 1994, to $61 in 1995, to 35 49 $83 in 1996, to $40 in 1997 and to $0 in 1998. However, each Partnership's future performance will depend on actual oil and gas prices and production levels, which could materially affect Benton's continuation analysis in either direction. In addition, the liquidation values estimated by Benton were based on an actual third party offer received by Benton for the purchase and sale of the Umbrella Point Field. These liquidation valuations estimated by Benton could, however, prove to be incorrect since the estimates are based on various pricing and other market related assumptions. Necessity for Effective Registration Statement for Exercise of Warrants. An Investor in the Partnerships who receives Warrants in connection with the Exchange Offer must exercise those Warrants pursuant to an effective Registration Statement filed by Benton with the Securities and Exchange Commission. In addition, Benton will be required to comply with the state securities laws of each state in which a Warrant holder is a resident prior to permitting the exercise of the Warrants by such Investor. If Benton is unable to register or comply with an exemption from registration requirements under state or federal securities laws, Benton will not be permitted to issue shares of Benton Common Stock upon exercise of the Warrants. Benton intends to immediately file with the Securities and Exchange Commission a Registration Statement covering the exercise of Warrants by the Investors and will take all reasonable steps to insure that such Registration Statement remains effective throughout the term of the Warrants, pursuant to provisions of the Warrant Agreement. However, there can no assurance that such a Registration Statement will be effective at a time when a holder seeks to exercise his Warrant. The absence of an effective Registration Statement will not extend the term of the Warrants. Thus, an Investor who receives Warrants in connection with the Exchange Offer may not be able to exercise such Warrants when he or she so desires, if there is no effective Registration Statement with the Securities and Exchange Commission or if Benton has failed to register or perfect an exemption under state securities laws. Because Benton is required under the Warrant Agreement to maintain an effective Registration Statement and comply with the state securities laws, an Investor could seek appropriate legal remedies for Benton's failure to fulfill this contractual obligation. Inherent Uncertainties in Estimating Reserves and Future Net Cash Flows. The present value of estimated future net cash flows from the Proved Reserves of the Partnerships, a significant factor considered in determining the Exchange Values, cannot be determined with a high degree of certainty. There are numerous uncertainties inherent in estimating quantities of Proved Reserves and on projecting future rates of production, future development, recompletion and workover expenditures, prices to be received upon the sale and costs to be incurred in production. The data set forth in the audit letter which summarizes the reserve report for each of the Partnerships included in Exhibit B to this Prospectus represent estimates only and may vary materially from the quantities of oil and gas actually recovered and the future net cash flows received upon the sale thereof. Benton's use of these estimates in determining the Exchange Values for the Partnerships could therefore result in an undervaluation of the Partnership Units. Valuation Conflict of Interest. The determination of the Exchange Values by Benton involves a conflict of interest because of Benton's duties as Managing General Partner of the Partnerships and its purchase of the assets. Accordingly, Benton's determination may not reflect the value of the Partnership's net assets if all such assets were sold to an unaffiliated third party in an arm's length transaction. As Managing General Partner of the Partnerships, Benton owes fiduciary duties to the Investors, and also owes a duty to the stockholders of Benton. While Benton believes that it has fulfilled these obligations in its determination of the Exchange Values, no degree of objectivity or professional competence can eliminate the inherent conflict of interest. 36 50 Lack of Independent Representative; No Fairness Opinion. Benton did not engage an independent representative to negotiate the terms of the Exchange Offer on behalf of the Investors. As a result, the Exchange Values and other terms of the Exchange Offer may not be as favorable as the terms that an independent representative might have obtained. In addition, Benton did not retain an independent third party to render an opinion with regard to the fairness of the Exchange Offer to the Investors and the Partnerships. Limited Dissenters' Rights. Investors residing in states other than California will not be afforded any dissenters' or appraisal rights. Under the rules adopted by the NASD, Investors in roll-up transactions such as the Exchange Offer are entitled to certain dissenters' rights unless the sponsor adopts a 75% approval requirement for the transaction or other procedures designed to protect the rights of Investors. Although adoption of the Proposals by each of the Partnerships would require the consent under the Partnership Agreements of the holders of only a majority of the Partnership Units, the Managing General Partner has adopted a 75% approval procedure instead of providing dissenters' rights. Effects of Dissenters' Rights on California Investors. Investors residing in California will be afforded limited dissenters' rights in accordance with the requirements for roll-up transactions under Section 25014.7 of the California Code. By voting against the Proposal, Investors in the State of California will be deemed to exercise their dissenters' rights and will receive the number of shares of Common Stock and Warrants equal to the Exchange Value of their interests divided by the closing price of the Common Stock on the NASDAQ-NMS during the twenty days immediately after the Closing Date. If that average price is lower than the Exchange Price, dissenting California Investors will receive more shares of Common Stock and Warrants than they would otherwise receive in the Exchange Offer. IF, HOWEVER, THE AVERAGE PRICE IS HIGHER THAN THE EXCHANGE PRICE A DISSENTING INVESTOR WOULD RECEIVE FEWER SHARES OF COMMON STOCK AND WARRANTS. See Exhibit E to this Prospectus. California Investors hold a substantial portion of the interests in the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership and the impact of the exercise of dissenters' rights could materially increase or decrease the number of shares of Common Stock issued by Benton in connection with the Exchange Offer. Risks Relating to Certain Federal Income Tax Considerations. Upon consummation of the Exchange, Investors will recognize gain in the amount equal to the excess of the fair market value of the Common Stock and Warrants received by them over their respective bases in the Partnership Units they hold. Further, the Internal Revenue Service may seek to recharacterize the transaction as a transfer of assets by the Partnerships in exchange for Common Stock and Warrants and subsequent liquidation of the Partnerships and distribution of their remaining assets. Such a recharacterization of the transaction may adversely affect the characterization of income recognized by Investors upon consummation of the Exchange. In addition, under such circumstances, the tax consequences realized by an Investor consenting to the Exchange may differ from that realized by Investors who do not participate in the Exchange but rather receive Common Stock and Warrants upon liquidation of the Partnerships. RISKS RELATED TO BENTON Losses From Operations. The historical financial data for Benton reflect net losses of $2,909,335 and $4,828,590 for the years ended December 31, 1992 and 1993, respectively and net income of $2,954,161 for the year ended December 31, 1994, and $3,151,601 for the six months ended June 30, 1995. Benton had total revenues of $8,622,109, $7,503,796 and $34,704,806 for the years ended December 31, 1992, 1993 and 1994, respectively, and $12,160,025 and $25,870,396 for the six months ended June 30, 1994 and 1995, respectively. The decreased revenues for the year ended December 31, 1993 compared to the year ended December 31, 1992 was due in part to the sale by Benton of certain 37 51 non-strategic oil and gas properties. During 1992 and 1993, Benton made a significant amount of capital expenditures for infra-structure, production facilities, pipelines and 3-D seismic surveys. Such expenditures did not immediately increase production from Benton's oil and gas properties. However, Benton believes that with this infra-structure complete, Benton will focus its capital expenditures on development of its oil and gas properties, which Benton expects will continue the trend of increased revenues from the year ended December 31, 1994 to December 31, 1995. As Benton's revenues increase, and the capital expenditures related to infra-structure decrease, Benton expects to improve its profitability. Benton's ability to maintain its financing arrangements, produce its oil and gas reserves and service its debt obligations would be adversely affected by a lack of profitability. Any improvement in profitability of Benton will be dependent upon improvement in the development of reserves, revenues from the sale of oil and gas reserves and oil and gas pricing, and there can be no assurance that such improvement will occur. Consummation of the Exchange Offer with all of the Partnerships will result in significant expenses recorded by Benton. See "Unaudited Pro Forma Financial Information." Foreign Operations. During 1994, Benton derived approximately 78% of its consolidated oil and gas revenues and approximately 97% of its Proved Reserves from its foreign operations in Venezuela and Russia. Benton's Venezuelan and Russian operations are subject to political, economic and other uncertainties inherent in the development of foreign properties including, without limitation, risks of war, revolution, expropriation, cancellation, renegotiation or modification of existing contracts, export and transportation regulations and tariffs, taxation and royalty policies, foreign exchange restrictions, adverse changes in currency value, international monetary fluctuations, environmental controls and other hazards arising out of foreign governmental sovereignty over certain areas in which Benton plans to conduct operations. Benton's operations have not been materially affected to date by political instability or the recent banking crisis in Venezuela. Similarly, to date, Benton's operations have not been materially adversely affected by the recent political or economic instability in Russia. However, there can be no assurance that Benton's operations will not be materially adversely affected by political or economic instability or burdensome taxation in the future. Benton currently carries no insurance against political instability. However, Benton has applied for insurance to cover the risk of currency inconvertibility for its Venezuelan operations with the Overseas Private Investment Corporation ("OPIC"), an agency of the United States government. There can be no assurance that Benton will be able to obtain this insurance. Benton has limited experience in conducting oil and gas operations in Venezuela and Russia. Benton formed ventures with local partners in Venezuela and Russia in an attempt to reduce some of the risks associated with conducting operations in such countries and to facilitate local transactions. Benton may encounter unforeseen difficulties in Venezuela and Russia, including problems related to production and deliverability of oil and gas, and any such difficulties could have a material adverse effect on Benton. Furthermore, the timing and extent of Benton's development activities in Venezuela are subject to the approval of Lagoven and the Ministry of Energy and Mines. There can be no assurance that the development activities proposed by Benton-Vinccler will receive the necessary approval. In addition, pursuant to the Articles of Incorporation/By-Laws of Benton-Vinccler, the consent of both Benton and Vinccler is a prerequisite to certain corporation transactions and other matters relating to Benton-Vinccler, including, without limitation, any sale of corporate assets, any assignment or sub-contracting of the operating service agreement with Lagoven, any change in Benton-Vinccler's corporate capital, duration or corporate purpose, any merger between Benton-Vinccler and another company as well as 38 52 certain amendments to Benton-Vinccler's Articles of Incorporation/By-Laws. There can be no assurance that Benton and Vinccler will agree upon any such proposed transactions or matters. In addition to the factors discussed above, Russia has established an export tariff on all oil exported from Russia, which, as imposed, has the effect of reducing the cash flows and potential profits to Benton. However, Russia has issued or drafted various decrees and legislation under which certain oil and gas ventures, including GEOILBENT, are eligible for relief from such oil export tariff until such time as they have recovered their capital investment. GEOILBENT has received a waiver from the export tariff for 1995, and expects to apply for renewal of such waiver for 1996 and 1997. However, there can be no assurance that any such renewals can be obtained. Furthermore, after the waiver for 1995 was issued to GEOILBENT, a new Russian law came into force which repeals all tax and custom benefits previously granted to participants in foreign economic activities, except for those granted pursuant to certain federal laws, including the law "On Customs Tariff." While it is not clear whether the repeal applies to GEOILBENT's waiver for 1995, GEOILBENT believes that its waiver should be regarded as granted pursuant to the law "On Customs Tariff." The legislative and regulatory environment in Russia continues to be subject to frequent change and uncertainty. In addition, the license which grants GEOILBENT the right to develop the North Gubkinskoye Field sets forth required levels of oil and gas production through the year 2000 and requires GEOILBENT to make additional royalty payments in the event that such production levels are not achieved during any three year period. As a result of the recent volatility in net wellhead oil prices and the export tariff, GEOILBENT's production for 1994 was significantly lower than that required for 1994, and, if such adverse conditions were to continue, GEOILBENT might produce significantly less oil and gas than required under the license during the next few years, which could result in GEOILBENT paying significantly higher royalties under the license. Benton will not receive distributions from GEOILBENT until it has expended its capital requirements under the terms of the joint venture agreement. As of September 15, 1995, Benton has spent approximately $24.4 million of the $25.8 million it has committed to spend by the end of 1995. However, oil and gas production in Russia has been adversely affected by recent volatility of net wellhead oil prices and the oil export tariff. If these conditions continue, Benton believes that the joint venture agreement may be modified to reduce that amount or to extend the due date of its obligation and modify other terms. Benton believes that after it has satisfied such capital commitments, it will not receive any significant distributions from GEOILBENT for several years because substantially all of the money received by GEOILBENT from the North Gubkinskoye Field will be reinvested to fund future development activities. Properties Under Development. As of December 31, 1994, approximately 79% of Benton's Proved Reserves were undeveloped and required development activities consisting primarily of recompletions, drilling of replacement wells and other development drilling. In addition, approximately 3% of Benton's Proved Reserves were proved developed behind-pipe or shut-in, requiring additional development work. As a result, Benton will require substantial capital expenditures to develop all of its proved reserves. At December 31, 1994, the anticipated future development costs for Proved Reserves in Venezuela, Russia and the United States were $79.5 million, $25.4 million and $2.0 million, respectively. Benton does not have the capital to develop all of these reserves. Benton expects to finance these future development costs through cash flow from operations, sales of property interests, non-recourse project financing and the offering of debt or equity securities. If such capital is not available, Benton will either enter into joint ventures to develop the projects, which will result in Benton retaining a smaller interest, or not develop the reserves. There can be no certainty regarding the commercial 39 53 feasibility of developing these reserves, the availability of financing, or the timing or costs associated therewith. If such capital is available, there can be no assurance that the Company will be able to develop and produce sufficient reserves to recover the costs expended and operate the wells profitability. In addition, Benton may not be able to control the development activities in fields either operated by industry partners or in which development activities are subject to approval by its partners. If Benton and its industry partners are not able to meet the financial and development obligations in these fields, the interests in the affected properties may be sold, farmed out or forfeited. Engineers' Estimates of Reserves and Future Net Revenue. This Prospectuses contains or incorporates by reference estimates of Benton's oil and gas reserves and the future net revenues therefrom which have been prepared by Benton and audited by Huddleston & Co., Inc., independent petroleum engineers. Estimates of commercially recoverable oil and gas reserves and of the future net cash flows derived therefrom are based upon a number of variable factors and assumptions, such as historical production from the subject properties, comparison with other producing properties, the assumed effects of regulation by government agencies and assumptions concerning future operating costs, severance and excise taxes, export tariffs, abandonment costs, development costs and workover and remedial costs, all of which may vary considerably from actual results. All such estimates are to some degree speculative, and various classifications of reserves are only attempts to define the degree of speculation involved. For these reasons, estimates of the commercially recoverable reserves of oil and natural gas attributable to any particular property or group of properties, the classification, cost and risk of recovering such reserves and estimates of the future net cash flows expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. The difficulty of making precise estimates is accentuated by the fact that 82% of Benton's total Proved Reserves were non-producing as of December 31, 1994. Therefore, Benton's actual production, revenues, severance and excise taxes, export tariffs, development expenditures, workover and remedial expenditures, abandonment expenditures and operating expenditures with respect to its reserves will likely vary from such estimates, and such variances may be material. In addition, actual future net cash flows will be affected by factors such as actual production, supply and demand for oil and natural gas, availability and capacity of gas gathering systems and pipelines, curtailments in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. The timing of actual future net revenues from proved reserves, and thus their actual present value, can be affected by the timing of the incurrence of expenditures in connection with development of oil and gas properties. The 10% discount factor, which is required by the SEC to be used to calculate present value for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the oil and gas industry. Discounted present value, no matter what discount rate is used, is materially affected by assumptions as to the amount and timing of future production, which may and often do prove to be inaccurate. Development of Additional Reserves. Benton's future success may also depend upon its ability to find or acquire additional oil and gas reserves that are economically recoverable. Except to the extent that Benton conducts successful exploration or development activities or acquires properties containing proved reserves, the proved reserves of Benton will generally decline as reserves are produced. There can be no assurance that Benton will be able to discover additional commercial quantities of oil and gas, or that Benton will be able to continue to acquire interests in underdeveloped oil and gas fields and enhance production and reserves by conducting workovers and recompletions, drilling replacements wells and drilling development wells, or that Benton will have continuing success drilling productive wells and acquiring underdeveloped properties at low finding costs. 40 54 Litigation. On June 13, 1994, certain partners in the Partnerships and certain other Investors in oil and gas limited partnerships sponsored by Benton filed suit against Benton in the Ventura Superior Court. The allegations in the complaint related to Benton's operation of the Partnerships and original sale of the Partnership Units. In an effort to resolve the concerns raised by these partners, Benton agreed to submit the matter to arbitration, conditioned upon the execution of a mutually satisfactory arbitration agreement. After discussions between Benton and the agent for the partners failed to produce a satisfactory arbitration agreement, Benton filed an answer to the complaint. The parties have now voluntarily dismissed the action and submitted the issues and claims to arbitration. Benton believes that the allegations made by the partners in the arbitration are without merit and intends to vigorously defend this action. In addition, Investors in partnerships which were sponsored by a third party have sued Benton on the theory that since it provided oil and gas drilling prospects to those partnerships and operated substantially all of their properties, it was responsible for alleged violations of securities laws in connection with the offer and sale of interests, contractual breach of fiduciary duty and fraud. See "The Exchange Offer and Proposal--Litigation and Related Matters." Retention and Attraction of Key Personnel. Benton depends to a large extent on the abilities and continued participation of certain key employees, the loss of whose services could have a material adverse effect on Benton's business. In an effort to minimize the risk, Benton has entered into employment agreements with certain key employees, and has purchased a $5.0 million key-man life insurance policy on the life of A.E. Benton. Furthermore, as a result of Benton's recent growth, Benton currently is seeking additional accounting and operating personnel. There can be no assurance that Benton will be able to attract and retain such personnel on acceptable terms and the failure to do so could have a material adverse effect on Benton. RISKS RELATED TO THE OIL AND GAS INDUSTRY Risk of Oil and Gas Operations. Benton's operations are subject to all of the risks normally incident to the operation and development of oil and gas properties and the drilling of oil and gas wells, including encountering unexpected formations or pressures, blowouts, cratering and fires, and, in horizontal wellbores, the increased risk of mechanical failure and collapsed holes, the occurrence of any of which could result in personal injuries, loss of life, environmental damages and other damage to the properties of Benton or others. In addition, because Benton acquires interests in underdeveloped oil and gas fields that have been operated by others for many years, Benton may be liable for any damage or pollution caused by any prior operations of such oil and gas fields. Moreover, offshore operations are subject to a variety of operating risks peculiar to the marine environment--such as hurricanes or other adverse weather conditions--to more extensive governmental regulation, including certain regulations that may, in certain circumstances, impose absolute liability for environmental damage, and to interruption or termination of business activities by government authorities based upon environmental or other considerations. In accordance with customary industry practice, Benton is not fully insured against these risks, nor are all such risks insurable. Accordingly, there can be no assurance that such insurance as Benton does maintain will be adequate to cover any losses or exposure for liability. Current Oil and Gas Industry Conditions. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the control of Benton. These factors include political conditions in the Middle East, the foreign supply of oil and natural gas, 41 55 the price of foreign imports, the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels and overall economic conditions. Lower oil and natural gas prices also may reduce the amount of Benton's oil and natural gas that is economic to produce. In addition, the marketability of Benton's production depends upon the availability and capacity of gas gathering systems and pipelines. Government Regulation; Environmental Risks. Benton's business is regulated by certain federal, state, local and foreign laws and regulations relating to the development, production, marketing and transmission of oil and gas, as well as environmental and safety matters. There can be no assurance that laws and regulations enacted in the future will not adversely affect Benton's exploration for, or the production and marketing of, oil and gas. Oil and gas operations are subject to extensive foreign, federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws which are often difficult and costly to comply with and which carry substantial penalties for failure to comply. The regulatory burden on the oil and gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect the operations of Benton. Compliance with environmental requirements generally could have a material adverse effect upon the capital expenditures, earnings or competitive position of Benton. Competition. The oil and gas exploration and production business is highly competitive. A large number of companies and individuals engage in the drilling for oil and gas, and there is a high degree of competition for desirable oil and gas properties suitable for drilling and for materials and third-party services essential for their exploration and development. Many of Benton's competitors have greater financial and other resources than does Benton. 42 56 PRICE RANGE OF COMMON STOCK, DIVIDENDS AND DISTRIBUTIONS Benton's Common Stock is traded on the National Association of Securities Dealers, Inc.--Automated Quotation System ("NASDAQ-NMS") under the symbol "BNTN." There is no public market for the Partnership Units. The following table sets forth, for the calendar years indicated, the high and low sales prices for the Common Stock reported on the American Stock Exchange through September 8, 1993 and thereafter on the NASDAQ-NMS.
YEAR HIGH LOW - ---- ---- --- 1992 First Quarter $ 11.13 $ 7.63 Second Quarter 9.00 6.88 Third Quarter 8.50 5.00 Fourth Quarter 6.63 5.00 1993 First Quarter 8.25 5.50 Second Quarter 10.25 7.63 Third Quarter 9.38 6.50 Fourth Quarter 7.63 3.88 1994 First Quarter 7.00 4.25 Second Quarter 7.63 5.38 Third Quarter 7.75 6.50 Fourth Quarter 9.13 7.00 1995 First Quarter 11.13 8.63 Second Quarter 15.13 10.25 Third Quarter (through September 30) 13.88 9.50
- ----------------------------- Benton's policy is to retain its earnings to support the growth of Benton's business. Accordingly, the Board of Directors of Benton has never declared cash dividends on its Common Stock and does not plan to do so in the foreseeable future. Furthermore, the terms of Benton's debt agreements prohibit the payment of cash dividends on Benton's Common Stock. The Partnerships do make cash distributions to the Investors from Partnership cash flow. The following table sets forth the amount of cash distributions paid per Unit by each Partnership to its Investors during the periods indicated. 43 57
PARTNERSHIP 1989 1990 1991 1992 1993 1994 1995 - ----------- ---- ---- ---- ---- ---- ---- ---- 1989-1 $0 $500 $747 $1,003 $600 $162 $0 1990-1 N/A $ 0 $500 $ 762 $400 $ 66 $0 1991-1 N/A N/A $100 $ 400 $400 $300 $0
- ------------------ The last cash distribution made by any of the Partnerships was in August 1994. The reasons for the lack of distributions include (i) declining oil and gas production combined with higher lease operating expenses and production taxes for 1994, compared to 1993; (ii) continued capital expenditures at the Umbrella Point Field; and (iii) lower natural gas prices. As an example, the Umbrella Point Field's natural gas price ranged from $1.84 to $2.77 per Mcf for 1993, compared to $1.47 to $2.42 per Mcf for 1994. During the first seven months of 1995, natural gas prices at Umbrella Point Field have continued to decline to a range of $1.40 to $1.75 per Mcf. On July 24, 1995, the last full trading day preceding the filing of the Exchange Offer, the closing price of Benton's Common Stock on the NASDAQ-NMS was $12.375 per share. Because the market price for Benton's Common Stock is subject to fluctuation, the total Exchange Value that an Investor will receive in connection with the Exchange Offer may increase or decrease prior to the Exchange. Holders of Partnership Units are urged to obtain current market quotations for the Benton Common Stock. 44 58 BACKGROUND OF EXCHANGE OFFER 1989-1 PARTNERSHIP The 1989-1 Partnership commenced business on September 1, 1989. Benton, as managing general partner and sponsor of the 1989-1 Partnership, sold an aggregate of $1,409,091 in 1989-1 Units. At June 30, 1995, total cash distributions to holders of 1989-1 Units was $848,836. The 1989-1 Partnership owns a 4.93% working interest in the Umbrella Point Field located in the northern end of Upper Galveston Bay, in Texas state waters. The 1989-1 Partnership also owns a 6.57% working interest in East Cameron Block 229, located off the coast of Grand Chenier, Louisiana in the Gulf of Mexico. As of September 1995, the Umbrella Point Field had ten wells producing at combined average daily rates of 312 Bbl of oil and 3.1 MMcf of natural gas. At January 1, 1995, the 1989-1 Partnership's interest in East Cameron Block 229 was determined to be uneconomic. See "Information Concerning 1989-1 Partnership - Description of Oil and Gas Properties." The 1989-1 Partnership has paid cumulatively $3,012 in cash distributions per 1989-1 Unit to date. Since inception through June 30, 1995, the 1989-1 Partnership has produced and sold approximately 238,748 Mcf of natural gas and 31,347 Bbl of oil. Since 1993, the Partnership's oil production volumes have declined from peak levels reached in 1992. Gas production began to decline in 1994. These reductions are due to the natural decline occurring in the Umbrella Point Field, the Partnership's most significant asset. Production volumes are expected to decline further in subsequent periods due to ongoing depletion of the Partnership's wells. The total amount of reserves encountered by and economically produced from the wells acquired or drilled was substantially less than anticipated. In addition, recent fluctuations in gas prices has impacted the 1989-1 Partnership. Prices received for the sale of natural gas from the Umbrella Point Field, the most significant Partnership property, ranged from $1.84 to $2.77 per Mcf during 1993, compared to $1.47 to $2.42 per Mcf during 1994. During the first seven months of 1995, prices received for the sale of natural gas from the Umbrella Point Field has continued to decline to a range of $1.40 to $1.75 per Mcf. During these periods of declining natural gas prices, the 1989-1 Partnership's cash flow was reduced while operating costs and third party costs did not decline. Also as a result of lower natural gas prices, the amount of the 1989-1 Partnership's reserves that can be produced economically is reduced substantially. In addition, many of the Investors in the 1989-1 Partnership have expressed concern regarding the historical performance and continued operation of the 1989-1 Partnership and its properties. See "The Exchange Offer and Proposal--Litigation and Related Matters." In response to these concerns, the Managing General Partner analyzed and evaluated the 1989-1 Partnership's original objectives, current status and future prospects. The Managing General Partner retained an independent petroleum engineer to prepare an updated estimate of the remaining reserves of the 1989-1 Partnership properties and the value of such reserves. In addition, the Managing General Partner made available to third parties the 1989-1 Partnership well, production, reserve and property information for the purpose of soliciting third party bids for the purchase of the 1989-1 Partnership's assets. See "Recommendation of the Managing General Partner--Managing General Partner's Determination that Exchange Offer is Fair" for a discussion of the third party bids received by the Managing General Partner. 45 59 As the Private Placement Memorandum used to sell the 1989-1 Units explained, oil and gas exploration and production have many risks, including the risk that exploring for and producing natural gas and oil is highly speculative. The search for oil and gas can result in unprofitable efforts not only from the drilling of dry holes but from wells which, although initially productive, do not produce oil and gas in sufficient amounts to return a profit on the costs expended. In addition, there is a risk that oil and gas prices could decline and the quantities of oil and gas discovered might not be sufficient to return the initial investment. Based on the geological and geophysical information available prior to the drilling and acquisition of the 1989-1 Partnership's properties, the Managing General Partner believed that the 1989-1 Partnership's wells would be able to provide economic benefit. However, based on the current evaluation of the 1989-1 Partnership reserves and future prospects, the Managing General Partner believes the most logical economic course for the limited partners is to exchange the remaining assets as soon as possible pursuant to the terms of the Exchange Offer. 1990-1 PARTNERSHIP The Partnership commenced business on November 29, 1990. Benton, as managing general partner and sponsor of the 1990-1 Partnership, sold an aggregate of $7,095,960 of 1990-1 Units. Through June 30, 1995, the Partnership has made cash distributions in the aggregate of $2,452,364. The 1990-1 Partnership purchased an 8.4% working interest in 32 producing wells in the Round Mountain Field, located in the San Joaquin Basin of California. The 1990-1 Partnership sold its interest in Round Mountain in September 1992. The 1990-1 Partnership owned a 38% working interest in the Hopper Canyon 12-1 well, located in Ventura County, California. In April 1992, the 1990-1 Partnership sold its interest in the well to Fortune Petroleum for cash and shares of common stock, which were subsequently sold. The 1990-1 Partnership also owned a 44.67% working interest in the North Fisher Reef No. 13-16A well. Although this prospect had multiple objectives, all objectives were determined to be non-commercial and the well was plugged and abandoned. The 1990-1 Partnership had a 12.5% working interest in the Prather 43-1 well. Once the well was drilled to total depth, it was determined to be uneconomic and was plugged and abandoned. The 1990-1 Partnership currently owns a 14.19% working interest in the Umbrella Point Field located in the Upper Galveston Bay, in Texas state waters. The Partnership also owns a 22.85% working interest in the East Cameron Block 229, located off the coast of Grand Chenier, Louisiana in the Gulf of Mexico. As of September 1995, the Umbrella Point Field had ten wells producing at combined average daily rates of 312 Bbl of oil and 3.1 MMcf of natural gas. At January 1, 1995, the 1990-1 Partnership's interest in East Cameron Block 229 was determined to be uneconomic. See "Information Concerning 1990-1 Partnership-Description of Oil and Gas Properties." The 1990-1 Partnership originally purchased a 0.38% working interest in the West Cote Blanche Bay Field, located in a shallow bay in St. Mary Parish, Louisiana. In 1991, the Partnership sold a 0.06% working interest in the West Cote Blanche Bay Field to the 1991-1 Partnership. In March 1995, the Partnership sold its 0.32% working interest in wells above the depth of approximately 10,575 feet. As of September 1995, the 1990-1 Partnership currently owns a 0.32% working interest in 3 wells in the West Cote Blanche Bay Field which are currently producing at a combined rate of approximately 21 MMcf of natural gas per day. See "Information Concerning 1990-1 Partnership - Description of Oil and Gas Properties." Beginning in 1993, the Partnership's oil production volumes have declined from peak levels reached in 1991 and 1992. Gas production began to decline in 1994. These reductions are due to the natural decline occurring in the Umbrella Point Field, the Partnership's most significant asset. 46 60 Production volumes are expected to decline further in subsequent periods due to ongoing depletion of the Partnership's wells. The 1990-1 Partnership has paid cumulatively $1,728 in cash distributions per 1990-1 Unit to date. Since inception through June 30, 1995, the 1990-1 Partnership has produced and sold approximately 686,501 Mcf of natural gas and 109,044 Bbl of oil. The total amount of reserves encountered by and economically produced from the wells acquired or drilled was substantially less than anticipated. In addition, recent fluctuations in gas prices has impacted the 1990-1 Partnership. Prices received for the sale of natural gas from the Umbrella Point Field, the most significant Partnership property, ranged from $1.84 to $2.77 per Mcf during 1993, compared to $1.47 to $2.42 per Mcf during 1994. During the first seven months of 1995, prices received for the sale of natural gas from the Umbrella Point Field has continued to decline to a range of $1.40 to $1.75 per Mcf. During these periods of declining natural gas prices, the 1990-1 Partnership's cash flow was reduced while operating costs and third party costs did not decline. Also as a result of lower natural gas prices, the amount of the 1990-1 Partnership's reserves that can be produced economically is reduced substantially. In addition, many of the Investors in the 1990-1 Partnership have expressed concern regarding the historical performance and continued operation of the 1990-1 Partnership and its properties. See "The Exchange Offer and Proposal--Litigation and Related Matters." In response to these concerns, the Managing General Partner analyzed and evaluated the 1990-1 Partnership's original objectives, current status and future prospects. The Managing General Partner retained an independent petroleum engineer to prepare an updated estimate of the remaining reserves of the 1990-1 Partnership properties and the value of such reserves. In addition, the Managing General Partner made available to third parties the 1990-1 Partnership well, production, reserve and property information for the purpose of soliciting third party bids for the purchase of the 1990-1 Partnership's assets. See "Recommendation of the Managing General Partner--Managing General Partner's Determination that Exchange Offer is Fair" for a discussion of the third party bids received by the Managing General Partner. As the Private Placement Memorandum used to sell the 1990-1 Units explained, oil and gas exploration and production have many risks, including the risk that exploring for and producing natural gas and oil is highly speculative. The search for oil and gas can result in unprofitable efforts not only from the drilling of dry holes but from wells which, although initially productive, do not produce oil and gas in sufficient amounts to return a profit on the costs expended. In addition, there is a risk that oil and gas prices could decline and the quantities of oil and gas discovered might not be sufficient to return the initial investment. Based on the geological and geophysical information available prior to the drilling and acquisition of the 1990-1 Partnership's properties, the Managing General Partner believed that the 1990-1 Partnership's wells would be able to provide economic benefit. However, based on the current evaluation of the 1990-1 Partnership reserves and future prospects, the Managing General Partner believes the most logical economic course is to exchange the remaining assets as soon as possible pursuant to the terms of the Exchange Offer. 1991-1 PARTNERSHIP The Partnership commenced business on July 30, 1991. Benton, as managing general partner and sponsor of the 1991-1 Partnership, sold an aggregate of $1,409,091 of 1991-1 Units. At June 30, 1995, the 1991-1 Partnership had distributed an aggregate of $338,182 to participants. The 1991-1 Partnership owned a 38.0% working interest in the Hopper Canyon 12-1 well, located in Ventura County, California. The 47 61 1991-1 Partnership subsequently sold its interest in this well to Fortune Petroleum, for cash proceeds and shares of common stock, which were subsequently sold. The 1991-1 Partnership also owned a 17.5% working interest in the Prather 43-1 well, located in Acadia Parish, Louisiana. This well was drilled to total depth and it was determined to be uneconomical, and was therefore plugged and abandoned. The 1991-1 Partnership owns a 2.83% working interest in the Umbrella Point Field, located in the Upper Galveston Bay, in Texas state waters. As of September 1995, the Umbrella Point Field had ten wells producing at combined average daily rates of 312 Bbl of oil and 3.1 MMcf of natural gas. The 1991-1 Partnership purchased a 0.06% working interest in the West Cote Blanche Bay Field, located in a shallow bay in St. Mary Parish, Louisiana, from the 1990-1 Partnership. In March 1995, the Partnership sold its 0.06% working interest in certain depths (above approximately 10,575 feet) in the West Cote Blanche Bay Field. The 1991-1 Partnership has a 0.06% working interest in 3 wells below the depth of approximately 10,575 feet. These wells are currently producing at a combined rate of approximately 21 MMcf of natural gas per day. See "Information Concerning 1991-1 Partnership - Description of Oil and Gas Properties." Beginning in 1993, the Partnership's oil production volumes have declined from peak levels reached in 1992. Gas production declined in 1993. These reductions are due to the natural decline occurring in the Umbrella Point Field, the Partnership's most significant asset. Production volumes are expected to decline further in subsequent periods due to ongoing depletion of the Partnership's wells. The 1991-1 Partnership has paid cumulatively $1,200 in cash distributions per 1991-1 Unit to date. Since inception through June 30, 1995, the 1991-1 Partnership has produced and sold approximately 81,261 Mcf of natural gas and 16,477 Bbl of oil. The total amount of reserves encountered by and economically produced from the wells acquired or drilled was substantially less than anticipated. In addition, recent fluctuations in gas prices has impacted the 1991-1 Partnership. Prices received for the sale of natural gas from the Umbrella Point Field, the most significant Partnership property, ranged from $1.84 to $2.77 per Mcf during 1993, compared to $1.47 to $2.42 per Mcf during 1994. During the first seven months of 1995, prices received for the sale of natural gas from the Umbrella Point Field has continued to decline to a range of $1.40 to $1.75 per Mcf. During these periods of declining natural gas prices, the 1991-1 Partnership's cash flow was reduced while operating costs and third party costs did not decline. Also as a result of lower natural gas prices, the amount of the 1991-1 Partnership's reserves that can be produced economically is reduced substantially. In addition, many of the Investors in the 1991-1 Partnership have expressed concern regarding the historical performance and continued operation of the 1991-1 Partnership and its properties. See "The Exchange Offer and Proposal--Litigation and Related Matters." In response to these concerns, the Managing General Partner analyzed and evaluated the 1991-1 Partnership's original objectives, current status and future prospects. The Managing General Partner retained an independent petroleum engineer to prepare an updated estimate of the remaining reserves of the 1991-1 Partnership properties and the value of such reserves. In addition, the Managing General Partner made available to third parties the 1991-1 Partnership well, production, reserve and property information for the purpose of soliciting third party bids for the purchase of the 1991-1 Partnership's assets. See "Recommendation of the Managing General Partner--Managing General Partner's Determination that Exchange Offer is Fair" for a discussion of the third party bids received by the Managing General Partner. 48 62 As the Private Placement Memorandum used to sell the 1991-1 Units explained, oil and gas exploration and production have many risks, including the risk that exploring for and producing natural gas and oil is highly speculative. The search for oil and gas can result in unprofitable efforts not only from the drilling of dry holes but from wells which, although initially productive, do not produce oil and gas in sufficient amounts to return a profit on the costs expended. In addition, there is a risk that oil and gas prices could decline and the quantities of oil and gas discovered might not be sufficient to return the initial investment. Based on the geological and geophysical information available prior to the drilling and acquisition of the 1991-1 Partnership's properties, the Managing General Partner believed that the 1991-1 Partnership's wells would be able to provide economic benefit. However, based on the current evaluation of the 1991-1 Partnership reserves and future prospects, the Managing General Partner believes the most logical economic course is to exchange the remaining assets as soon as possible, pursuant to the terms of the Exchange Offer. GOLDKING OFFER In 1994, the Managing General Partner of each of the Partnerships determined that, with other working interest owners in the Umbrella Point Field, a purchaser for the property should be solicited. In May 1994, a regional investment bank which specializes in the energy industry was retained by the working interest owners on an exclusive basis to solicit purchasers of the Umbrella Point Field. A data package related to the property was assembled and delivered to approximately 100 potential purchasers. Interested parties then scheduled meetings to review detailed information regarding the Umbrella Point Field in an established data room. Goldking was among the potential purchasers who received such a data package. In June 1995, Benton received an offer from Goldking to purchase all of the right, title and interest owned by each of the Partnerships and Benton in the Umbrella Point Field. Goldking made a similar offer to all other working interest owners in the Umbrella Point Field. Goldking's intent is to own 100% of the working interests in the Field. To obtain financing for the purchase of the working interests, Goldking was required to acquire not less than a 75% working interest in the Field. In order to preserve the offer for the Partnerships, Benton sold its corporate interest in the Umbrella Point Field (11.77% working interest) for $756,872. Benton entered into agreements, on behalf of each of the Partnerships, with Goldking for the sale of the Partnerships' interests in the Umbrella Point Field, subject to approval of the Partnerships. In consideration of this sale, the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership would receive anticipated net proceeds determined as of June 30, 1995 in the aggregate of $323,296, $930,296 and $185,282, respectively, if the sale were consummated, subject to adjustments for revenues, expenses and capital expenditures after that date. The agreements with Goldking are not contingent upon each of the Partnerships approving the transaction. In addition to the Goldking offer, Benton received an offer to purchase the working interests owned by each of the Partnerships and Benton in the Umbrella Point Field from Hunter Resources, Inc. ("Hunter") in October 1994. Pursuant to the terms of that offer, Hunter would have paid a total of $8,000,000 in cash and $1,000,000 in the form of a promissory note, compared to Goldking's offer of $7,650,000 in cash. Both offers were for the working interests in the Umbrella Point Field owned by each of the Partnerships and the 11.77% working interest owned by Benton. Benton compared the Hunter offer, the Goldking offer and the estimated value of the Umbrella Point Field proved reserves at December 31, 1994 (see table below). In the case of all three Partnerships, the Hunter offer and the Goldking offer were in excess of the value of the proved reserves of the Umbrella Point Field. Hunter was unable to secure financing for the transaction and subsequently withdrew its offer. Due to Hunter's inability to secure financing for the purchase and the extent to which 49 63 such offer exceeded the value of the Partnerships' proved reserves, Benton concluded that Hunter's offer was in excess of the market value of the Umbrella Point Field. When analyzing and considering the Goldking offer, Benton concluded that the purchase price offered by Goldking was in excess of the value of the Partnerships' proved reserves and, although less than the Hunter offer, represented a favorable market value for the property.
UMBRELLA POINT FIELD HUNTER OFFER(1) GOLDKING PROVED PARTNERSHIP (CASH & NOTES) OFFER(1) RESERVES(2) - ----------- --------------- ---------- ----------- 1989-1 $ 443,602 $ 377,062 $ 325,540 1990-1 1,277,264 1,085,674 937,429 1991-1 254,228 216,093 186,589
- ---------- (1) Prior to any adjustments for revenues and expenses subsequent to the effective date of sale, which in the case of Goldking is January 1, 1995. These adjustments, through June 30, 1995, are the reason for the differences in Goldking proceeds listed in this table as compared to other places in the document. The adjustments were omitted from this table for comparative purposes. (2) Value of estimated future net cash flows from Proved Reserves of the Umbrella Point Field, as of December 31, 1994, as reflected in the reserve report for the Partnership as of that date. 50 64 THE EXCHANGE OFFER AND PROPOSAL DESCRIPTION OF THE EXCHANGE OFFER General. Benton is offering to exchange Common Stock and Warrants for Partnership Units in the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership (the "Exchange"). Investors who tender their Partnership Units will receive the number of shares of Common Stock and Warrants set forth below for the respective Partnership Units. In connection with the Exchange Offer, Benton is submitting Proposals to Investors in each of the Partnerships to amend the respective Partnership Agreements to provide for the transfer of all of the assets and liabilities of the Partnerships to Benton as of the December 31, 1994 Effective Date in exchange for Common Stock and Warrants in the amounts set forth below and the pro rata distribution of such consideration in liquidation of the Partnership. 1989-1 Partnership. If the Exchange Offer is consummated, each holder of a 1989-1 Unit who tenders his Units in connection with the Exchange Offer will receive (i) 107 shares of Common Stock, and (ii) Warrants to purchase 35 shares of Common Stock with an exercise price of $11.00 per share. Fractional shares of Common Stock will not be issued in connection with the Exchange Offer or liquidation of the 1989-1 Partnership. A Partner in the 1989-1 Partnership otherwise entitled to a fractional share of Common Stock will be paid in cash in lieu of such fractional shares. Warrants to be issued will be rounded to the nearest whole number of Warrants and no fractional interests will be issued. 1990-1 Partnership. If the Exchange Offer is consummated, each holder of a 1990-1 Unit who tenders his Units in connection with the Exchange Offer will receive (i) 81 shares of Common Stock and (ii) Warrants to purchase 334 shares of Common Stock with an exercise price of $11.00 per share. Fractional shares of Common Stock will not be issued in connection with the Exchange Offer or liquidation of the 1990-1 Partnership. A Partner in the 1990-1 Partnership otherwise entitled to a fractional share of Common Stock will be paid in cash in lieu of such fractional shares. Warrants to be issued will be rounded to the nearest whole number of Warrants and no fractional interests will be issued. 1991-1 Partnership. If the Exchange Offer is consummated, each holder of a 1991-1 Unit who tenders his Units in connection with the Exchange Offer will receive (i) 95 shares of Common Stock and (ii) Warrants to purchase 385 shares of Common Stock with an exercise price of $11.00 per share. Fractional shares of Common Stock will not be issued in connection with the Exchange Offer or liquidation of the 1991-1 Partnership. A Partner in the 1991-1 Partnership otherwise entitled to a fractional share of Common Stock will be paid in cash in lieu of such fractional shares. Warrants to be issued will be rounded to the nearest whole number of Warrants and no fractional interests will be issued. THE PROPOSAL Description of Proposal. Benton is submitting to the Investors in each of the Partnerships the proposal to adopt an amendment to each of the Partnerships' Partnership Agreements annexed as Exhibit C to this Prospectus. The respective amendments, if adopted by each of the Partnerships in accordance with the amendment procedures in the Partnership Agreement will provide for the following steps: - The transfer to Benton in exchange for the Common Stock and Warrants set forth below, of all of the assets of the Partnership and the assumption by Benton of all liabilities of the Partnership effective as of the Effective Date. 51 65 - The dissolution of each of the Partnerships and the distribution to the Investors of the Common Stock and Warrants allocable to their interests in liquidation promptly following the Closing Date. Each Investor who tenders his Partnership Units pursuant to the Exchange Offer will by that tender, consent to the proposal for that Partnership. If a Partnership adopts the proposal by the consent of 75% of the Partnership Units for the respective Partnership, all Investors in that Partnership, whether or not they tendered their Units in the Exchange Offer, will receive the same amount of Common Stock and Warrants as they would have received had they tendered their Partnership Units. Consummation of the Exchange Offer for a partnership is conditioned upon approval by that partnership of the proposal. Approval of the proposal and adoption of the Exchange Offer is not conditioned upon approval or acceptance by any other partnership. Investors who do not return a completed Letter of Transmittal will not receive Benton Common Stock or Warrants until Benton has distributed immediately after the closing date and Investors have return an executed Transfer Application issuable to them in the exchange, which may result in a delay in receiving the Common Stock and Warrants if the transfer application is not properly returned. Timing of Common Stock Issuance. Assuming that the proposal is adopted and the Exchange Offer is consummated, Benton will have the benefit of each of the Partnership's assets and associated cash flows commencing on the effective date of December 31, 1994. The Common Stock and Warrants issued in the exchange will be freely transferable immediately following issuance. On the Closing Date, Benton will cause certificates representing the Common Stock and the Warrants issuable in the Exchange to be registered in the name of the holders who have accepted the Exchange Offer. Benton will also cause a certificate representing the shares of Common Stock and Warrants that will be issued to participants upon liquidation of each of the Partnerships to be issued in the name of the Partnership, pending dissolution, liquidation and winding-up of the Partnerships. Immediately thereafter, Benton will cause the shares of Common Stock and Warrants issued in the name of the Partnership to be transferred into certificates representing Common Stock and Warrants, registered in the names of the individual participants remaining in the Partnerships following liquidation. Conditions. Benton may, in it sole discretion, at any time on or prior to the closing date, refuse to consummate, abandon or terminate the exchange offer and withdraw the proposal if after the date of this prospectus, in the sole judgment of Benton, a material change shall have occurred or been threatened (or any development shall have occurred or been threatened involving a prospective material change) affecting (or likely to affect) the business or properties of Benton or the partnerships or if Benton shall have become aware of any facts or circumstances that have or may have material significance with respect to Benton's operations. If any event shall occur or any matter shall have been brought to the attention of Benton, that, in the sole judgment of Benton materially affects the partnerships, whether adversely or otherwise, or the exchange offer for interest in the partnerships, Benton may refuse to accept tenders of interest in the partnerships, or may modify or amend the Exchange Offer to take the event or matter into account. The absence of the material change affecting Benton or the Partnerships is the only material condition to the exchange offer. If that condition has not been fulfilled or the exchange offer is withdrawn by Benton, each letter of transmittal tendering an interest or consenting to the proposal will be void and no Common Stock or Warrants will be issued in exchange for the interests in the respective partnership. 52 66 DISSENTERS' RIGHTS Investors residing in states other than California will not be afforded any dissenters' or appraisal rights. Under the rules adopted by the National Association of Securities Dealers, Inc., ("NASD"), Investors in roll-up transactions such as the Exchange Offer are entitled to certain dissenters' rights unless the sponsor adopts a 75% approval requirement for the transaction or other procedures designed to protect the rights of Investors. Although adoption of the Proposals by each of the Partnerships would require the consent under the Partnership Agreements of the holders of only a majority of the Partnership Units, the Managing General Partner has adopted a 75% approval procedure instead of providing dissenters' rights. Investors residing in California will be afforded limited dissenters' rights in accordance with the requirements for roll-up transactions under Section 25014.7 of the California Code. See Exhibit E to this Prospectus. By voting against the Proposal, Investors in the State of California will be deemed to exercise their dissenters' rights and will receive the number of shares of Common Stock and Warrants equal to the Exchange Value of their interests divided by the closing price of the Common Stock on the NASDAQ-NMS during the twenty days immediately after the Closing Date. If that average price is lower than the Exchange Price, dissenting California Investors will receive more shares of Common Stock and Warrants than they would otherwise receive in the Exchange Offer. IF, HOWEVER, THE AVERAGE PRICE IS HIGHER THAN THE EXCHANGE PRICE, A DISSENTING INVESTOR WOULD RECEIVE FEWER SHARES OF COMMON STOCK AND WARRANTS. California Investors hold a substantial portion of the interests in the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership and the impact of the exercise of dissenters' rights could materially increase or decrease the number of shares of Common Stock issued by Benton in connection with the Exchange Offer. DISTRIBUTION OF COMMON STOCK AND WARRANTS Each Investor who returns a completed Letter of Transmittal, even if he withholds consent to the Proposal, will thereby have provided to Benton the necessary information to issue the Common Stock and Warrants provided the Exchange Offer is consummated. Assuming that the Proposals are adopted by the Partnerships and the Exchange Offer is consummated, Investors who have returned a completed Letter of Transmittal will receive the Common Stock and Warrants issuable to them in the Exchange promptly after the Closing Date. An Investor who does not return a completed Letter of Transmittal will not be eligible to receive the Common Stock and Warrants after the Closing Date. Instead, the Common Stock and Warrants, attributable to that Investor's Partnership Units will be held of record by the respective Partnerships. Immediately after the Closing Date, Benton will deliver a Transfer Notice to each Investor who has not returned a Letter of Transmittal. The Transfer Notice should be completed and returned to Benton promptly. Upon return of the executed Transfer Notice, Benton will have the Common Stock and Warrants transferred and delivered to the Investor. ELECTION TO RECEIVE CASH IN LIEU OF COMMON STOCK Holders of Units in the Partnerships who elect to accept the Exchange Offer may elect to receive cash in lieu of shares of Common Stock to be issued, BUT CASH WILL BE DISTRIBUTED TO HOLDERS MAKING SUCH ELECTION ONLY IF THE SALE OF THE UMBRELLA POINT FIELD TO GOLDKING, AS DESCRIBED HEREIN, IS ACTUALLY CONSUMMATED. If the sale of the Umbrella Point Field working interests to Goldking is consummated, a holder who elects to receive cash in lieu of Common Stock will receive $1,185 for each 53 67 1989-1 Unit, $891 for each 1990-1 Unit and $1,055 for each 1991-1 Unit, with Warrants in the amounts described herein. The amount of cash to be paid per Partnership Unit was computed based upon the estimated cash proceeds per Unit to be received pursuant to the Goldking purchase offer, plus pro rata distribution of working capital of the Partnership. A holder of Units in the Partnerships who accepts the Exchange Offer and elects to receive cash in lieu of shares of Common Stock, assuming that the Goldking transaction is consummated, will receive cash and Warrants with a total value of $1,312, $2,107 and $2,456 for each 1989-1 Unit, 1990-1 Unit and 1991-1 Unit, respectively. There can be no assurance from Benton that the sale of the Umbrella Point Field to Goldking will be consummated, and therefore, an Investor should make a decision to accept the Exchange Offer based solely upon a decision to receive Common Stock and Warrants in the amounts set forth herein. INTERESTS OF CERTAIN PERSONS IN THE EXCHANGE AND PROPOSALS In considering the recommendation of the Managing General Partner, the Investors should be aware that the Managing General Partner has interests in the Exchange that are in addition to the interests of the Partnerships and the Investors generally. Benton is the Managing General Partner of each of the Partnerships and its determination of the Exchange Values involves an inherent conflict of interest. As Managing General Partner, Benton owes fiduciary duties to the Investors in the Partnerships. In addition, it owes a duty to its stockholders. While Benton believes that it has fulfilled these obligations in its determination of the Exchange Values, which is supported, in part, by a reserve report audited by an independent petroleum engineer, no degree of objectivity or professional competence can eliminate the inherent conflict of interest. RESALE OF BENTON COMMON STOCK The issuance of the Benton Common Stock to be received by the Investors who tender their Partnership Units and the shares to be received by Investors in liquidation of the Partnerships, as well as the issuance of the Common Stock upon exercise of the Warrants, has been registered under the Securities Act. Such shares may be traded freely and without restriction by those Investors of the Partnerships not deemed to be "affiliates" of the Partnerships, as that term is defined in the rules under the Securities Act. "Affiliates" are generally defined as persons who control, are controlled by or are under common control with the Partnership at the time of the Exchange. Accordingly, "affiliates" generally will include the Managing General Partner and any Investor who owns in excess of 10% of the Partnership interests. Benton Common Stock received by those Investors who are deemed to be "affiliates" of a Partnership may be resold without registration as provided by Rules 144 and 145, or as otherwise permitted, under the Securities Act. This Prospectus does not cover any resales of Benton Common Stock received by affiliates of the Partnerships or by certain family members or related interests. Any Investor who becomes an affiliate of Benton will be subject to similar restrictions under Rule 144. FRACTIONAL SHARES No fractional shares of Benton Common Stock will be issued. Fractional share interests which would otherwise be issuable shall entitle the holder thereof to receive, in lieu of such fractional interest, an amount of cash equal to the product of such fraction multiplied by the closing price of the Benton Common Stock on the NASDAQ-NMS on the Closing Date. Warrants to be issued will be rounded to the nearest whole number of Warrants and no fractional interests will be issued. 54 68 STOCK EXCHANGE LISTING All of the currently issued and outstanding shares of Common Stock of Benton are admitted for trading and quoted on the NASDAQ-NMS, and application has been made to the NASDAQ-NMS for admission for trading of the shares of Common Stock to be issued in connection with the Exchange Offer and the shares of Common Stock issuable upon exercise of the Warrants. There is currently no trading market for the Warrants, and Benton does not expect a trading market to develop. ACCOUNTING TREATMENT The Exchange will be accounted for as a purchase by Benton. Accordingly, the purchase price will be allocated to assets and liabilities based on their estimated fair values as of the date of acquisition. CLOSING DATE The Exchange Offer is expected to be consummated on the Closing Date, which will be no more than five days following the Expiration Date. Benton may withdraw the Exchange Offer at any time prior to the Expiration Date under certain circumstances, including the existence of any state or federal statute, rule, regulation or order, or entry of any judicial or administrative order that would prohibit the transactions contemplated by the Exchange Offer and the Proposals. 1989-1 Partnership. The Exchange Offer to the 1989-1 Partnership is conditioned upon consent of 75% of the 1989-1 Units to the 1989-1 Proposal and the absence of any material adverse development affecting the 1989-1 Partnership, as determined by Benton in its sole discretion. On the Closing Date, subject to satisfaction of these conditions, Benton intends to accept all 1989-1 Units validly tendered and not withdrawn pursuant to the Exchange Offer. 1990-1 Partnership. The Exchange Offer to the 1990-1 Partnership is conditioned upon consent of 75% of the 1990-1 Units to the 1990-1 Proposal and the absence of any material adverse development affecting the 1990-1 Partnership, as determined by Benton in its sole discretion. On the Closing Date, subject to satisfaction of these conditions, Benton intends to accept all 1990-1 Units validly tendered and not withdrawn pursuant to the Exchange Offer. 1991-1 Partnership. The Exchange Offer to the 1991-1 Partnership is conditioned upon consent of 75% of the 1991-1 Units to the 1991-1 Proposal and the absence of any material adverse development affecting the 1991-1 Partnership, as determined by Benton in its sole discretion. On the Closing Date, subject to satisfaction of these conditions, Benton intends to accept all 1991-1 Units validly tendered and not withdrawn pursuant to the Exchange Offer. OPERATIONS AFTER THE EXCHANGE Benton is an independent oil and gas company engaged in the acquisition of producing properties and exploration, development and production of oil and gas, primarily in the eastern region of Venezuela, the Gulf Coast of Louisiana and the West Siberia region of Russia. Upon consummation of the Exchange, Benton intends to sell the working interests in the Umbrella Point Field to Goldking on the terms described herein. If, however, such sale is not consummated, Benton will operate the acquired Partnership assets as it operates its oil and gas properties, or may sell those assets to another third party. 55 69 EXPENSES; FEES All expenses incurred in connection with the Exchange Offer and the Proposals and the transactions contemplated thereby will be paid by Benton. Benton will pay the expenses incurred in connection with tender offer to the Investors of the Partnerships and will pay all fees and expenses in connection with this Prospectus, including fees and expenses payable in connection with the Registration Statement of which this Prospectus is a part. BENTON'S DIVIDEND POLICY Benton's policy is to retain its earnings to support the growth of Benton's business. Accordingly, the Board of Directors of Benton has never declared cash dividends on its Common Stock and does not plan to do so in the foreseeable future. Furthermore, the terms of its credit agreements prohibit the payment of cash dividends on Benton's Common Stock. LITIGATION AND RELATED MATTERS On June 13, 1994, certain partners in the Partnerships and certain other Investors in oil and gas limited partnerships sponsored by Benton, including the Partnerships that are the subject of this Exchange Offer, filed suit against Benton in the Ventura Superior Court. The allegations in the complaint related to Benton's operation of the Partnerships and original sale of the Partnership Units. In an effort to resolve the concerns raised by these partners, Benton agreed to submit the matter to arbitration, conditioned upon the execution of a mutually satisfactory arbitration agreement. After discussions between Benton and the agent for the partners failed to produce a satisfactory arbitration agreement, Benton filed an answer to the complaint. The parties have now voluntarily dismissed the action and submitted the issues and claims to arbitration. Specifically, the allegations in the complaint which are subject to the arbitration relate to Benton's operation of the partnerships and in the sale of the partnership units, including allegations against Benton for breach of contract, fraudulent inducement to invest in the partnerships, negligent misrepresentation in the sale of the partnership units, breach of fiduciary duties, and conversion of partnership funds to Benton's own benefit. The plaintiffs seek actual and punitive damages in an unspecified amount, and rescission of the sale of the partnership units. Benton filed an answer to the complaint which denied the allegations and believes that the allegations made by the partners in the arbitration are without merit and intends to vigorously defend this action. Acceptance of the Exchange Offer and approval of the Proposals by the Investors of the Partnerships will result in the dissolution of any Partnership obtaining such approval and the Common Stock and Warrants received in the Exchange will be distributed, in liquidation, to the Investors of such Partnership who did not tender their Partnership Units. YOUR CONSENT TO THE PROPOSAL MAY AFFECT THE AMOUNT OF DAMAGES, IF ANY, YOU COULD RECEIVE IN THE ARBITRATION DISCUSSED ABOVE AND EACH INVESTOR IS ENCOURAGED TO CONSULT HIS OR HER LEGAL ADVISOR TO DETERMINE THE EFFECT OF ANY CONSENT ON THE PROPOSAL. In the arbitration proceeding, the arbitrator will determine the extent of liability against Benton, if any, related to the allegations submitted. If any liability is found to exist, the arbitrator will determine the amount of any damages, actual and/or punitive. The arbitrator may consider all distributions made to the partners from the partnerships in determining the extent of damages, if any. In such analysis, the arbitrator may consider the consideration received by Investors in connection with the Exchange Offer, which could significantly reduce any damage award against Benton. However, there can be no assurance that an arbitrator will consider such factors in his or her determination of damages if the allegations are found to be true and damages are to 56 70 be awarded. Benton expects to present this Exchange Offer to the arbitrator to be considered in determining the extent of damages, if any. 57 71 METHOD OF DETERMINING EXCHANGE VALUES GENERAL The Exchange Values have been assigned to the Partnership Units to determine the number of shares of Common Stock and Warrants to be offered for each Partnership Unit. The Exchange Values were determined by Benton and are not the result of negotiations with independent representatives of the Partnerships. Accordingly, the Exchange Values may not reflect the value of the Partnership Units or the value of the Partnership properties if all the assets were to be sold to an unaffiliated third party in an arm's length transaction. Benton did seek third party bids for the sale of the Partnerships' assets and received an offer to purchase the Partnerships' working interests in the Umbrella Point Field from Goldking. The Exchange Values are based in part on this third party offer from Goldking. Management of Benton has substantial experience in evaluating and operating oil and gas properties in the Partnerships' production areas and believes on the basis of that experience that the methodology employed in determining the Exchange Values is fair to Investors and considered in the oil and gas industry as being favorable to sellers of producing properties. In determining the Exchange Value, Benton considered the total distributions paid to date to participants in the respective Partnerships. For each of the Partnerships, Benton assigned a Total Exchange Value to the Partnership which, based upon certain assumptions described below, and in addition to the distributions paid to date, would provide Investors with consideration valued at 100% of their initial contribution to the Partnership. The estimated cash proceeds from the sale of the working interests in the Umbrella Point Field to Goldking and the value of other tangible assets of the Partnership are attributable to shares of Benton Common Stock, or cash if the Investor makes the cash election described herein. The remaining dollar value, if any, is referred to herein as General Intangibles. Pursuant to the Exchange Offer, value attributed to General Intangibles will be distributed to Investors in the form of Warrants. The number of shares of Common Stock and Warrants to be issued pursuant to the Exchange Offer has been determined relative to a Total Exchange Value assigned to the 1989-1 Partnership Units, the 1990-1 Partnership Units and the 1991-1 Partnership Units aggregating $370,098, $2,990,728, and $692,349, respectively. The number of shares of Common Stock offered in exchange for Partnership Units has been determined by dividing the Exchange Value of the tangible assets of the Partnership by a Common Stock price of $11.00, subject to rounding adjustments. The Common Stock price is based upon the average closing price of the Common Stock on NASDAQ-National Market for the 20 trading days immediately preceding September 12, 1995 and will not reflect any subsequent increase or decrease in the market price for the Common Stock after that date, except to the extent required by dissenters' rights for California residents. The number of Warrants to be assigned to each Partnership Unit was determined by dividing the estimated value of the General Intangibles of the Partnership by the estimated present value per Warrant. Benton has used the Black-Scholes option pricing model to calculate the present value of the Warrants, which yielded a value of $3.64 per Warrant. The Warrants are exercisable at a price of $11.00 per share and will expire three years from the date of issuance. The most significant assets considered in determining the Exchange Values were the anticipated cash proceeds from the sale of Umbrella Point Field and the Proved Reserves of the Partnerships. The Exchange Values reflect these oil and gas assets and all other assets and liabilities of the Partnerships. These components reflect (i) the estimated cash proceeds from the sale of Umbrella Point Field to Goldking, (ii) the estimated present value of future net cash flows from Proved Reserves of the Partnership as of December 31, 1994, discounted 10% per year and calculated without escalation of 58 72 prices and costs prepared by Benton and audited by Huddleston, (iii) the net book value of current assets and liabilities of the Partnership as of June 30, 1995, (iv) the tax-basis balances of equipment as of December 31, 1994, and (v) the General Intangibles of the Partnership. Based on management's experience in evaluating reserve acquisition opportunities and transactions in the Partnerships' production areas, Benton believes that the components of the Exchange Values reflect all appropriate valuation criteria for the Partnerships in accordance with industry practice. Each component of the Exchange Value, estimated on the basis of interim data, is presented for each of the Partnerships in the tables and discussions below. Huddleston is a firm of petroleum and geological engineers, in the business of preparing and auditing oil and gas reserve information. Huddleston has been engaged in this business since 1965, and the personnel performing the audits of the Partnerships' reserves are certified Petroleum Engineers. Huddleston has performed the annual audit of the oil and gas reserve information of Benton since 1992, and is compensated by Benton for such audit in the amount of approximately $7,100 per year. In addition, Huddleston has provided an annual audit of the reserve information for each of the Partnerships for 1994 for approximately $3,145, $10,759 and $2,648 for the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership, respectively. Additionally, Huddleston has assisted the Company in the preparation of reports which estimate the future recoverable reserves for Benton's Russian project. These reports were part of a study to obtain long-term financing for the Russian project. For these services, the Company paid Huddleston an aggregate of $58,770. In connection with the annual audit by Huddleston of the Benton reserve information, Huddleston audited the reserve information related to Benton's interest in the Umbrella Point Field. Because of Huddleston's qualifications and familiarity with the fields in which the Partnerships own a working interest, the Managing General Partner retained Huddleston to audit the annual reserve information for each of the Partnerships. The compensation paid to Huddleston to audit the annual reserve information for each of the Partnerships, used by Benton in preparation of the Exchange Offer, is not contingent upon approval of the Exchange Offer and Proposals. 1989-1 PARTNERSHIP EXCHANGE VALUE COMPONENTS General. The following table sets forth each of the Exchange Value components, estimated on an interim basis. EXCHANGE VALUE COMPONENTS Estimated Cash Proceeds--Umbrella Point Field..................................... $323,296 Present Value of Proved Reserves of other properties (SEC PV 10).................. 0 Cash.............................................................................. 5,717 Intercompany receivable--Benton Oil and Gas Company............................... 621 Value of equipment................................................................ 4,563 General Intangibles............................................................... 35,901 -------- Exchange Value.................................................................... $370,098 ========
Other Assets and Liabilities. The tax-basis balances of the 1989-1 Partnership's equipment, excluding Umbrella Point field equipment, aggregated $4,563 at December 31, 1994, and the net book value of its current assets and liabilities as of June 30, 1995 reflect a balance of $6,338, excluding property held for sale. The equipment value and net current assets are based upon the 1989-1 Partnership's 1994 year-end tax accounting records and June 30, 1995 unaudited financial statements, 59 73 respectively, maintained in accordance with the applicable provisions of the 1989-1 Partnership Agreement. Benton believes that valuing the 1989-1 Partnership's equipment (comprised of oil and gas production and transportation facilities) at tax-basis balances is favorable to the sellers of the producing properties since many purchasers in transactions evaluated by Benton, as part of its Benton's involvement in the production area, allocate nominal value to well equipment on the theory that its salvage value at the end of the commercial lives of acquired wells will approximate the cost of plugging and abandoning the wells. Benton believes that the original cost of the equipment less the deductions computed through 1994 year end for tax purposes represents a reasonable approximation of the fair market value of the equipment to Benton. Benton also believes that valuing the current assets and liabilities of the 1989-1 Partnership (comprised of cash and intercompany receivable) at their book value as of June 30, 1995 is appropriate to reflect the fair market value of these items, which are expected to be collected and paid to Benton, to the extent outstanding, in the stated amounts reflected in the 1989-1 Partnership's unaudited balance sheet as of that date. General Intangibles. In determining the value attributed to General Intangibles, Benton evaluated the success to date of the 1989-1 Partnership, total consideration paid to date to the participants and the value to Benton of dissolving and liquidating the 1989-1 Partnership so that Benton can focus on its current operations and reduce the administrative burdens associated with operating the Partnership. Based upon Benton's evaluation of historical administrative costs for the 1989-1 Partnership, Benton estimates that the administrative costs for operating the Partnership will be approximately $35,000 per year. From inception through September 1995, the 1989-1 Partnership has made cash distributions to participants aggregating $848,836, or $3,012 per 1989-1 Unit. In forming the 1989-1 Partnership, Benton sold an aggregate of $1,409,091 in 1989-1 Units. Benton acknowledges the concerns raised by the Investors in the 1989-1 Partnership with regard to operations of the Partnership, and the disappointing returns on investment by the Investors. Because many of the Investors are or were stockholders of Benton, Benton desires to maintain a good relationship with these stockholders, many of whom have been strong supporters of Benton from inception, and Benton desires to avoid future claims against it by participants relating to the management of the Partnership. "See The Exchange Offer and Proposal-Litigation and Related Matters." Assuming that the Investor in the 1989-1 Partnership elects to hold his or her shares of Common Stock, and the market price of Common Stock is at or above approximately $16.75 per share, Benton believes that the Investors in the 1989-1 Partnership will have received consideration in the form of cash distributions and Common Stock in excess of the initial investment in the 1989-1 Partnership, without regard to any tax benefits received by the participants. On October 2, 1995, the last sales price of the Benton Common Stock on NASDAQ National Market was $11.13 per share. The assumed market price of the Common Stock of $16.75 per share discussed above represents a 34% increase in the market value of the Benton Common Stock. There can be no assurance that the market price of the Benton Common Stock will increase or that such price will be achieved. 1990-1 PARTNERSHIP EXCHANGE VALUE COMPONENTS General. The following table sets forth each of the Exchange Value components, estimated on an interim basis. 60 74 EXCHANGE VALUE COMPONENTS Estimated Cash Proceeds-Umbrella Point Field......................................... $930,865 Present value of Proved Reserves of other properties (SEC PV 10)..................... 119,694 Cash................................................................................. 145,455 Intercompany receivable--Benton Oil and Gas Company.................................. 56,281 Value of equipment................................................................... 13,037 General Intangibles.................................................................. 1,725,396 ---------- Exchange Value....................................................................... $2,990,728 ==========
Proved Reserves. The calculation of the present value of the 1990-1 Partnership's Proved Reserves for the purpose of determining the Exchange Value complies with the rules and regulations of the SEC relating to the calculation of the present value of future net cash flows determined as of December 31, 1994 attributable to proved oil and gas reserves for disclosure and financial reporting purposes. The regulations governing these reserves do not permit the use of escalated prices and costs except in accordance with existing contractual arrangements, and the resulting SEC PV 10 calculations may overestimate or underestimate the actual future cash flows from the production and sale of oil and gas and, consequently, the present value thereof. The gross quantities of Proved Reserves attributable to the 1990-1 Partnership's interest in its wells, together with the estimated present value of those reserves, were estimated on an SEC PV 10 basis as of December 31, 1994 in a reserve report prepared by Benton and audited by Huddleston. A summary of the report and a copy of the audit letter, setting forth the criteria and assumptions used in evaluating the 1990-1 Partnership's Proved Reserves, are included in Exhibit B. There are numerous uncertainties inherent in estimating quantities of Proved Reserves. Huddleston audited the data and computations used by Benton's petroleum engineer in their evaluation of the total Proved Reserves attributable to all of the wells in which the 1990-1 Partnership had an interest as of December 31, 1994. Estimates by other independent petroleum engineers could vary from Benton's estimates and could result in higher or lower valuations. The estimates of the 1990-1 Partnership's future gross revenues attributable to its estimated Proved Reserves as of December 31, 1994 were calculated based on natural gas and crude oil prices in effect on that date. Those prices had a weighted average of $1.63 per Mcf for natural gas and $15.94 per Bbl for oil. Future operating and development costs were based on the 1990-1 Partnership's operating and development costs as of December 31, 1994 and were used without escalation. Future severance (production) and ad valorem (property) taxes were calculated using rates prevailing at December 31, 1994. The estimated future gross revenues, future operating and development costs and production taxes were allocated to the 1990-1 Partnership in accordance with its interest in oil and gas properties, taking into account applicable reversionary and overriding royalty interests. The present values of the estimated net cash flows attributable to the 1990-1 Partnership's Proved Reserves of other properties were calculated by discounting the future net cash flows to present value at the rate of 10% per year, as prescribed by SEC regulations covering reserve reporting for financial disclosure purposes. The discount factor is intended to reflect the timing of future net cash flows. No further discount or risk adjustment was applied. Present value, regardless of the discount rate 61 75 used, is materially affected by assumptions as to timing of future production, which may prove to have been inaccurate. Other Assets and Liabilities. The tax-basis balances of the 1990-1 Partnership's equipment, excluding Umbrella Point Field equipment, aggregated $13,037 at December 31, 1994, and the net book value of its current assets and liabilities as of June 30, 1995 reflect a balance of $201,736, excluding property held for sale. The equipment value and net current assets are based upon the 1990-1 Partnership's 1994 year-end tax accounting records and June 30, 1995 unaudited financial statements, respectively, maintained in accordance with the applicable provisions of the 1990-1 Partnership Agreement. Benton believes that valuing the 1990-1 Partnership's equipment (comprised of oil and gas production and transportation facilities) at tax-basis balances is favorable to the sellers of the producing properties since many purchasers in transactions evaluated by Benton, as part of Benton's involvement in the production area, allocate nominal value to well equipment on the theory that its salvage value at the end of the commercial lives of acquired wells will approximate the cost of plugging and abandoning the wells. Benton believes that the original cost of the equipment less the deductions computed through 1994 year end for tax purposes represents a reasonable approximation of the fair market value of the equipment to Benton. Benton also believes that valuing the current assets and liabilities of the 1990-1 Partnership (comprised of cash and intercompany receivable) at their book value as of June 30, 1995 is appropriate to reflect the fair market value of these items, which are expected to be collected and paid to Benton, to the extent outstanding, in the stated amounts reflected in the 1990-1 Partnership's unaudited balance sheet as of that date. General Intangibles. In determining the value attributed to General Intangibles, Benton evaluated the success to date of the 1990-1 Partnership, total consideration paid to date to the participants and the value to Benton of dissolving and liquidating the 1990-1 Partnership so that Benton can focus on its current operations and reduce the administrative burdens associated with operating the Partnership. Based upon Benton's evaluation of historical administrative costs for the 1990-1 Partnership, Benton estimates that the administrative costs for operating the Partnership will be approximately $80,000 per year. From inception through September 1995, the 1990-1 Partnership has made cash distributions to participants aggregating $2,452,364, or $1,728 per 1990-1 Unit. In forming the 1990-1 Partnership, Benton sold an aggregate of $7,095,960 of 1990-1 Units. Benton acknowledges the concerns raised by the Investors in the 1990-1 Partnership with regard to operations of the Partnership, the lack of success and thus the disappointing returns on investment by the Investors. Because many of the Investors are or were stockholders of Benton, Benton desires to maintain a good relationship with these stockholders, many of whom have been strong supporters of Benton from inception, and Benton desires to avoid future claims against it by participants relating to the management of the Partnership. See "The Exchange Offer and Proposal--Litigation and Related Matters." Assuming that the Investor in the 1990-1 Partnership elects to hold his or her shares of Common Stock and exercises his or her Warrants at the end of the three-year term, and the market price of the Common Stock is at or above approximately $16.75 per share, Benton believes that the Investors in the 1990-1 Partnership, will have received consideration in the form of cash distributions, Common Stock and Warrants in excess of the initial investment in the 1990-1 Partnership, without regard to any tax benefits received by the participants. On October 2, 1995, the last sales price of the Benton Common Stock on NASDAQ National Market was $11.13 per share. The assumed market price of the Common Stock of $16.75 per share discussed above represents a 34% increase in the market value of the Benton Common Stock during the three year term of the Warrants. There can be no assurance that the market price of the Benton Common Stock will increase or that such price will be achieved. The value of the General Intangibles of the Partnership is not subject to valuation by third parties since the General Intangibles do not 62 76 represent actual assets of the Partnership. Benton believes that the participants in the Partnership will not receive any value for the General Intangibles in any alternative to the Exchange. Subsequent Adjustments. The Exchange Values will not be adjusted to reflect changes after December 31, 1994 in the present value of the estimated future net cash flows attributable to the 1990-1 Partnership's Proved Reserves. No adjustments will be made to the Exchange Values on account of changes in demand for or costs or prices of oil and gas that differ from the assumptions employed or other market related events after December 31, 1994, although those could affect the value of the 1990-1 Units. 1991-1 PARTNERSHIP EXCHANGE VALUE COMPONENTS General. The following table sets forth each of the Exchange Value components, estimated on an interim basis. EXCHANGE VALUE COMPONENTS Estimated cash proceeds--Umbrella Point Field.......................................... $185,282 Present Value of Proved Reserves of other properties (SEC PV 10)....................... 23,856 Cash................................................................................... 82,547 Intercompany Receivable--Benton Oil and Gas Company.................................... 3,169 Value of Equipment..................................................................... 2,555 General Intangibles.................................................................... 394,940 -------- Exchange Value......................................................................... $692,349 ========
Proved Reserves. The calculation of the present value of the 1991-1 Partnership's Proved Reserves of other properties for the purpose of determining the Exchange Value complies with the rules and regulations of the SEC relating to the calculation of the present value of future net cash flows determined as of December 31, 1994 attributable to proved oil and gas reserves for disclosure and financial reporting purposes. The regulations governing these reserves do not permit the use of escalated prices and costs except in accordance with existing contractual arrangements, and the resulting SEC PV 10 calculations may overestimate or underestimate the actual future cash flows from the production and sale of oil and gas and, consequently, the present value thereof. The gross quantities of Proved Reserves attributable to the 1991-1 Partnership's interest in its wells, together with the estimated present value of those reserves, were estimated on an SEC PV 10 basis as of December 31, 1994 in a reserve report prepared by Benton and audited by Huddleston. A summary of the report and a copy of the audit letter, setting forth the criteria and assumptions used in evaluating the 1991-1 Partnership's Proved Reserves, are included in Exhibit B. There are numerous uncertainties inherent in estimating quantities of Proved Reserves. Huddleston audited the data and computations used by Benton's petroleum engineer in their evaluation of the total Proved Reserves attributable to all of the wells in which the 1991-1 Partnership had an interest as of December 31, 1994. Estimates by other independent petroleum engineers could vary from Benton's estimates and could result in higher or lower valuations. The estimates of the 1991-1 Partnership's future gross revenues attributable to its estimated Proved Reserves as of December 31, 1994 were calculated based on natural gas and crude oil prices in 63 77 effect on that date. Those prices had a weighted average of $1.63 per Mcf for natural gas and $15.94 per Bbl for oil. Future operating and development costs were based on the 1991-1 Partnership's operating and development costs as of December 31, 1994 and were used without escalation. Future severance (production) and ad valorem (property) taxes were calculated using rates prevailing at December 31, 1994. The estimated future gross revenues, future operating and development costs and production taxes were allocated to the 1991 - 1 Partnership in accordance with its interest in oil and gas properties, taking into account applicable reversionary and overriding royalty interests. The present values of the estimated net cash flows attributable to the 1991-1 Partnership's Proved Reserves were calculated by discounting the future net cash flows to present value at the rate of 10% per year, as prescribed by SEC regulations covering reserve reporting for financial disclosure purposes. The discount factor is intended to reflect the timing of future net cash flows. No further discount or risk adjustment was applied. Present value, regardless of the discount rate used, is materially affected by assumptions as to timing of future production, which may prove to have been inaccurate. Other Assets and Liabilities. The tax-basis balances of the 1991-1 Partnership's equipment, excluding the Umbrella Point field equipment, aggregated $2,555 at December 31, 1994, and the net book value of its current assets and liabilities as of June 30, 1995 reflect a balance of $85,716, excluding property held for sale. The equipment value and net current assets are based upon the 1991-1 Partnership's 1994 year-end tax accounting records and June 30, 1995 unaudited financial statements, respectively, maintained in accordance with the applicable provisions of the 1991-1 Partnership Agreement. Benton believes that valuing the 1991-1 Partnership's equipment (comprised of oil and gas production and transportation facilities) at its tax-basis balances is favorable to the sellers of the producing properties since many purchasers in transactions evaluated by Benton, as part of its on-going involvement in the production area, allocate nominal value to well equipment on the theory that its salvage value at the end of the commercial lives of acquired wells will approximate the cost of plugging and abandoning the wells. Benton believes that the original cost of the equipment less the deductions computed through 1994 year end for tax purposes represents a reasonable approximation of the fair market value of the equipment to Benton. Benton also believes that valuing the current assets and liabilities of the 1991-1 Partnership (comprised of cash and intercompany receivable) at their book value as of June 30, 1995 is appropriate to reflect the fair market value of these items, which are expected to be collected and paid to Benton, to the extent outstanding, in the stated amounts reflected in the 1991-1 Partnership's unaudited balance sheet as of that date. General Intangibles. In determining the value attributed to General Intangibles, Benton evaluated the success to date of the 1991-1 Partnership, total consideration paid to date to the participants and the value to Benton of dissolving and liquidating the 1991-1 Partnership so that Benton can focus on its current operations and reduce the administrative burdens associated with operating the Partnership. Based upon Benton's evaluation of historical administrative costs for the 1991-1 Partnership, Benton estimates that the administrative costs for operating the Partnership will be approximately $30,000 per year. From inception through September 1995, the 1991-1 Partnership has made cash distributions to participants aggregating $338,182, or $1,200 per 1991-1 Unit. In forming the 1991-1 Partnership, Benton sold an aggregate of $1,409,091 in 1991-1 Units. Benton acknowledges the concerns raised by the Investors in the 1991-1 Partnership with regard to operations of the Partnership, the lack of success and thus the disappointing returns on investment by the Investors. Because many of the Investors are or were stockholders of Benton, 64 78 Benton desires to maintain a good relationship with these stockholders, many of whom have been strong supporters of Benton from inception, and Benton desires to avoid future claims against it by participants relating to the management of the Partnership. See "The Exchange Offer and Proposal -- Litigation and Related Matters." Assuming that the Investor in the 1991-1 Partnership elects to hold his or her shares of Common Stock and exercises his or her Warrants at the end of the three-year term, and the market price of the Common Stock is at or above approximately $16.75 per share, Benton believes that the Investors in the 1991-1 Partnership, will have received consideration in the form of cash distributions, Common Stock and Warrants in excess of the initial investment in the 1991-1 Partnership, without regard to any tax benefits received by the participants. On October 2, 1995, the last sales price of the Benton Common Stock on NASDAQ National Market was $11.13 per share. The assumed market price of the Common Stock of $16.75 per share discussed above represents a 34% increase in the market value of the Benton Common Stock during the three year term of the Warrants. There can be no assurance that the market price of the Benton Common Stock will increase or that such price will be achieved. The value of the General Intangibles of the Partnership is not subject to valuation by third parties since the General Intangibles do not represent actual assets of the Partnership. Benton believes that the participants in the Partnership will not receive any value for the General Intangibles in any alternative to the Exchange. Subsequent Adjustments. The Exchange Values will not be adjusted to reflect changes after December 31, 1994 in the present value of the estimated future net cash flows attributable to the 1991 - 1 Partnership's Proved Reserves. No adjustments will be made to the Exchange Values on account of changes in demand for or costs or prices of oil and gas that differ from the assumptions employed or other market related events after December 31, 1994, although those could affect the value of the 1991 - 1 Units. RECOMMENDATION OF THE MANAGING GENERAL PARTNER MANAGING GENERAL PARTNER'S REASONS FOR PROPOSING THE EXCHANGE OFFER As Managing General Partner, Benton initiated and has proposed the Exchange Offer and has recommended the approval of the Proposals. Benton's decision is based on its conclusion that the Exchange will be more beneficial to Investors than the alternatives of continuing the Partnerships or liquidating all of the assets of the Partnerships and that the terms of the Exchange Offer and related Proposals, including the method used to determine the Exchange Values and the procedures involved in the Proposals, are both fair and appropriate. The Managing General Partner, in reaching its conclusion to recommend that each of the Investors accept the Exchange Offer and approve the Proposals, considered a number of factors, including, without limitation, the following: (a) The financial condition, results of operations and cash flows of Benton and each of the Partnerships, both on a historical and a prospective basis. The Managing General Partner has reviewed the financial condition, results of operations and cash flows of Benton and each of the Partnerships, on a historical and a prospective basis. The Managing General Partners' analysis of the future prospects for each of the Partnerships indicates declining distributions to the investors. See "--Benefits of Continued Operations". For the years ended December 31, 1992, 1993 and 1994 and the six months ended June 30, 1994 and 1995, Benton had total revenues of $8,622,000, $7,503,000, $34,705,000, $12,160,000 and $25,870,000, respectively. For the years ended December 31, 1992 and 1993, Benton had a net loss of $2,909,000 and $4,829,000, respectively, compared to net income of $2,954,000 for the year ended December 31, 1994 and net income of $2,000 and $3,152,000 for the six months ended June 30, 1994 65 79 and 1995. Benton's ability to access additional capital and its more diverse operations and oil and gas prospects in Venezuela, the Gulf Coast and Russia could continue to contribute to significant increases in Benton's results of operations and cash flow. (b) Current market conditions and historical market prices, volatility and trading information with respect to the Common Stock of Benton, compared to the lack of a trading market for the Partnership Units. In this regard, the Managing General Partner considered the potential growth rate and market price to earnings potential of Benton. The Managing General Partner believes that the Investors will receive the benefit of any future growth in the value of their equity interest in Benton rather than receiving cash distributions from the Partnerships, which are likely to decrease rapidly as the remaining oil and natural gas reserves of the Partnerships are depleted. Concerns raised by several Investors in the Partnerships are indicative to the Managing General Partner of the desire of many Investors to liquidate their investment in the Partnership. The Managing General Partner's analysis of continuation of the Partnerships indicate that distributions are likely to decrease rapidly over the short economic life of the Partnerships. Although Benton is restricted from paying cash dividends to its stockholders, the Managing General Partner concluded that the Exchange Offer will allow for liquidation of their investment for those Investors who so desire, while allowing other Investors to retain an equity interest in the oil and gas industry through ownership of Benton Common Stock, with access to a public trading market if and when he or she desires to liquidate the investment. (c) Plugging Costs to be Incurred if Partnerships Continue. Distributions to the Investors in connection with the Exchange Offer allow for distributions undiminished by ongoing Partnership plugging costs, which the Managing General Partner estimates through the life of the Partnership to be $247, $160 and $56 per Unit for the 1989 - 1 Partnership, the 1990 - 1 Partnership and the 1991 - 1 Partnership, respectively. The Managing General Partner's analysis of the continuation of the Partnerships indicates that the economic life of each of the Partnerships is short. "See -- Managing General Partner's Determination that Exchange Offer is Fair -- Alternatives to the Exchange." Based upon this analysis, the Managing General Partner concluded that the Exchange Offer allows the Investors to receive distributions from the Partnerships without reduction for plugging costs, which Benton estimates will represent 76.7%, 54.6%, and 33.5% of total distributions to Investors in the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership if each such Partnership continues to operate through its respective economic life. (d) Liquidity of the Common Stock of Benton compared to the lack of liquidity of the Partnership Units. The Common Stock of Benton has an active trading market on NASDAQ - NMS. However, the Warrants that will be received in the Exchange Offer do not currently have a public trading market. The Partnership Units have no liquidity, and the Partnership Agreement restricts transfer of the Partnership Units. (e) Favorable terms of Exchange Offer. The terms and conditions of the Exchange Offer, including the amount of consideration to be paid the Investors and the form of the consideration, the parties' representations, warranties, covenants and agreements, and the conditions to their respective obligations set forth in the Exchange Offer. The Managing General Partner deemed that the Exchange Offer is favorable to each of the Partnerships' Investors. In reaching this conclusion, the Managing General Partner noted the nature of the representations and warranties and the limited number of conditions in the Exchange Offer. The Managing General Partner believes that in the absence of extraordinary or unforeseen circumstances, there is a high likelihood that the transaction will be completed, subject to the requisite approval of the Partnerships' Investors. Accordingly, the Managing 66 80 General Partner believes that the Exchange Offer is more favorable to each of the Investors than purchase and sale agreements that are customarily entered into. (f) The review of other alternatives for the Partnerships, including possible sales of Partnership assets to third parties, continued operation of the Partnerships and liquidation of the Partnerships. The Managing General Partner did not believe that the sale of all of the assets of any of the Partnerships were as attractive to the Partnerships as the Exchange Offer because of the premium over the value of the reserves being offered by Benton in the Exchange Offer, the uncertainty that a third party purchaser could be found for all of the assets, and if found, whether a purchase and sale agreement could be negotiated on terms favorable to the Partnerships. The only third party offer received by the Managing General Partner which resulted in an agreement for purchase of a substantial portion of the Partnerships' properties was the cash offer from Goldking, described herein. For a discussion of the Managing General Partner's efforts to solicit purchasers of the Partnerships' assets, see "Background of Exchange Offer." If the Goldking sale is consummated, an Investor may elect to receive cash in lieu of the Common Stock he would receive in the Exchange Offer, if such election is made on the Letter of Transmittal to be used in accepting the Exchange Offer. The Managing General Partner did not believe that the continued operation of the Partnerships was as attractive to the Partnerships as the Exchange Offer because the Managing General Partner believes that the continued cash distributions made by the Partnerships are likely to decrease rapidly as the remaining oil and natural gas reserves are depleted. The Managing General Partner did not believe that liquidation of the Partnership was as attractive to the Partnerships as the Exchange Offer because the estimated liquidation values of the Partnerships are substantially less than the consideration to be received by each of the Investors under the Exchange Offer. See " -- Managing General Partner's Determination that Exchange Offer is Fair -- Alternatives to the Exchange." (g) Risks inherent in the oil and gas industry. Inherent in the oil and gas industry are many uncertainties and risks. The Managing General Partner considered the possibilities that changes in the industry and continued volatility of oil and gas prices could have a significantly greater effect on the Partnership due to the Partnership's size compared to Benton and the greater diversification of oil and gas properties and prospects of Benton. However, the Managing General Partner also considered that increases in the price of oil and gas could have a more direct effect to the investors if the Partnership assets were owned by the Partnership rather than Benton due to the size of the Partnership, the cash distributions to the investors from the Partnerships and the percentage ownership in the Partnership of each of the investors. However, Benton believes that an increase in oil and gas prices could generally increase revenues of Benton and could corresponding increase the market price of the Benton Common Stock. (h) Restrictions on cash dividends. Benton is restricted under certain credit agreements from paying cash dividends to its stockholders and the Investors could continue to receive cash distributions from the Partnership. However, the Managing General Partner believes that the cash distributions to the Investors from each of the Partnerships will likely decrease rapidly as the remaining oil and natural gas reserves are depleted. See " -- Managing General Partner's Determination that Exchange Offer is Fair -- Alternatives to the Exchange." Although Benton is restricted from paying cash dividends to its stockholders, the Managing General Partner concluded that Investors who desire cash distributions can liquidate their Benton Common Stock and make alternate investment decisions, but those Investors will not similarly be able to liquidate their investment in the Partnership Units as cash distributions from the Partnerships decrease. (i) Tax consequences. Upon the Exchange of the Partnership Units for Common Stock and Warrants, investors will recognize gain equal to the amount by which the fair market value of the 67 81 Common Stock and Warrants received by them exceeds their respective bases in the Partnership Units exchanged therefore. Thus, an investor will have immediate tax consequences in connection with the Exchange Offer and liquidation of the Partnerships, and could be required to pay cash for such tax liabilities, even though the investor receives only Common Stock and Warrants in connection with the Exchange. However, the Managing General Partner believes that the total consideration to be received by an investor in the Partnerships, net of the tax consequences to such investor, is more beneficial to the investors than continuation of the Partnerships. (j) Concerns of Investors. The Managing General Partner also considered the concerns expressed by the many Investors in the Partnerships regarding the historical performance and continued operation of each of the Partnerships and their respective properties, including the litigation instituted by certain of the Investors. The Managing General Partner recognizes these concerns and concluded that it must recommend to the Investors a favorable alternative to continuation of the Partnerships. Based upon the analysis of alternatives to the Exchange Offer, the Managing General Partner must determine to recommend the Exchange Offer as the most favorable alternative to the Investors. See " -- Managing General Partner's Determination that Exchange Offer is Fair -- Alternatives to the Exchange." In view of the wide variety of factors considered in connection with its evaluation of the terms of the Exchange, the Managing General Partner did not find it practicable to, and did not, quantify or otherwise attempt to assign relative weights to the specific factors considered in reaching its determination. MANAGING GENERAL PARTNER'S DETERMINATION THAT EXCHANGE OFFER IS FAIR THE MANAGING GENERAL PARTNER OF EACH OF THE PARTNERSHIPS HAS DETERMINED THAT THE EXCHANGE IS FAIR AND IS IN THE BEST INTERESTS OF THE PARTNERSHIPS AND THEIR RESPECTIVE PARTNERS AND HAS RECOMMENDED THAT THE PARTNERS OF EACH OF THE PARTNERSHIPS TENDER THEIR PARTNERSHIP UNITS AND CONSENT TO THE PARTNERSHIP PROPOSALS. THE EXCHANGE OFFER IS NOT CONDITIONED UPON ACCEPTANCE AND APPROVAL BY ALL OF THE PARTNERSHIPS AND THE MANAGING GENERAL PARTNER BELIEVES THAT THE OFFER IS FAIR TO ALL INVESTORS, REGARDLESS OF WHICH OR THE NUMBER OF PARTNERSHIPS WHICH ACCEPT THE EXCHANGE OFFER FOR THE REASONS SET FORTH BELOW. General. The Managing General Partner has analyzed the terms of the Exchange Offer, the consideration and value offered to the Investors in exchange for their Partnership Units and the value of consideration an Investor could expect to receive under various alternatives to the Exchange. In determining that the Exchange Offer is fair to the Investors, the Managing General Partner considered that the Investors who do not accept the Exchange Offer or who do not elect to receive cash in lieu of Benton Common Stock will receive Common Stock and Warrants of Benton, and could receive cash if the Partnerships were continued or liquidated. However, the Managing General Partner believes that because an Investor may elect to receive cash in lieu of Common Stock if the sale to Goldking is consummated, the Investors will receive consideration in excess of the alternatives to the Exchange if the Exchange Offer is accepted. The Managing General Partner's analysis of the consideration an Investor could receive under the alternatives to the Exchange are discussed below. The Managing General Partner believes that those Investors who receive Benton Common Stock will have access to a public trading market if such Investor elects to liquidate his investment for cash. The average daily trading volume for the Benton Common Stock on the NASDAQ National Market for the 30 trading days ended September 27, 1995 was 259,000 shares. The Managing General Partner believes that since the maximum aggregate number of shares of Benton Common Stock that will be issued in the Exchange 68 82 Offer for all three Partnerships is 171,880, the issuance will have no material effect on the market value of the Benton Common Stock, and may allow all Investors receiving shares of Benton Common Stock in connection with the Exchange Offer and liquidation of the Partnerships to liquidate their investment in the market. The Managing General Partner believes that the Exchange Offer is fair to all Investors, regardless of which or the number of Partnerships which accept the Exchange Offer. The assets of the Partnerships which Benton will acquire if the Exchange Offer is accepted and approved by each of the Partnerships are immaterial to the total asset value of Benton. See "Unaudited Pro Forma Financial Information." Alternatives to the Exchange. The Managing General Partner's analysis of the most probable results of continuing the Partnerships indicate that, while continuing the Partnerships would avoid the risks associated with the ownership of Common Stock in Benton, Investors will receive potentially greater values by participating in the Exchange than they would derive from this alternative. Benton estimates that continuing the 1989-1 Partnership under market and operating conditions prevailing in 1994 would likely generate decreasing annual distributions of $114 per 1989-1 Unit in 1995, $146 in 1996, $91 in 1997 and $7 in 1998. Benton estimates that the remaining economic life of the 1989-1 Partnership is 3.5 years. Benton estimates that continuing the 1990-1 Partnership under market and operating conditions prevailing in 1994 would likely generate decreasing annual distributions of $97 per 1990-1 Unit in 1995, $119 in 1996, $76 in 1997, $30 in 1998, $10 in 1999 and $1 in 2,000. Benton estimates that the remaining economic life of the 1990-1 Partnership is 5.5 years. Benton estimates that continuing the 1991-1 Partnership under market and operating conditions prevailing in 1994 would likely generate decreasing annual distributions of $61 per 1991-1 Unit in 1995, $83 in 1996, $40 in 1997 and $0 in 1998. Benton estimates that the remaining economic life of the 1991-1 Partnership is 2.5 years. Benton believes that the Partnerships will have no residual value in their assets at the end of the economic life of the respective Partnerships. The Managing General Partner also believes that, while liquidating the Partnerships through the sale of assets for cash would provide an immediate cash return and avoid the risks associated with owning Benton Common Stock, the Exchange will provide Investors with greater values than they would likely receive in liquidation of the Partnerships. Benton's liquidation analysis reflects an estimated liquidation value of approximately $294,634, $1,052,601 and $240,998 of the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership, respectively, or $1,045, $742 and $855 per 1989-1 Unit, 1990-1 Unit and 1991-1 Unit, respectively. Benton received an independent offer from Goldking to purchase each of the Partnership's interest in the Umbrella Point Field (which price represents 99.3%, 88.1% and 88.0% of the total Proved Reserve estimates of the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership, respectively) for an estimated total purchase price in cash of $1,439,443 as of June 30, 1995, subject to adjustments. This estimated purchase price would represent potential cash distributions to the Investors equal to $1,147, $656 and $657 per 1989-1 Unit, 1990-1 Unit and 1991-1 Unit, respectively. Benton's liquidation analysis is based on the anticipated proceeds from the sale of the Umbrella Point Field to Goldking, plus working capital for the Partnership at June 30, 1995, less estimated general and administrative costs involved in liquidation of the Partnership. For purposes of determining the general and administrative costs to the Partnership, Benton estimated that general and administrative expenses would approximate the general and administrative expenses incurred by the Partnership during the year ended December 31, 1994. The following tables summarize the results of Benton's liquidation analysis in comparison to the Exchange Values for the Partnership Units determined by Benton. The table also includes valuation data 69 83 derived from Benton's analysis of continuing the Partnerships. Benton did not undertake its continuation analysis for the purpose of valuing the Partnerships, but solely to illustrate the likelihood of decreasing distributions based on oil and gas prices at December 31, 1994. However, because SEC disclosure standards for roll up transactions require a comparison of the value of the consideration offered in the transaction with the value of the consideration estimated for each alternative to the transaction, the tables also reflect the results of extending Benton's continuation analysis for the balance of the estimated life of the Partnerships' Proved Reserves, and discounting the projected stream of distributions to present value at the same 10% discount rate used in Benton's liquidation analysis to account for the timing of cash flows as well as production and concentration risks. 70 84 1989 - 1 PARTNERSHIP
TOTAL VALUE PER VALUATION METHOD INVESTOR VALUE(1) 1989 - 1 UNIT - ---------------- ----------------- ------------- Exchange Value......................................... $370,098 $1,312 Liquidation value estimated by Benton.................. 294,634 1,045 Continuation analysis by Benton assuming natural gas prices of $1.63 per Mcf and oil prices of $15.94 per Bbl(2)......................................... 90,661 322 Value of Proved Reserves at December 31, 1994(3)....... 325,540 1,155
(1) The Exchange Value and liquidation value attribute no value to Managing General Partners' interests. The continuation analysis assumes continued distributions to the Managing General Partner pursuant to the terms of the Partnership Agreement. (2) The assumed natural gas and oil prices are the prices used for preparation of the Partnership's reserve report at December 31, 1994. The continuation analysis was calculated based upon Benton's estimate of the remaining economic life of the Partnership, estimated to be 3.5 years. (3) Based on the Partnership's December 31, 1994 reserve report prepared by Benton and audited by Huddleston. The reserves are valued as of December 31 of each year, based on oil and natural gas prices as of that date. Market prices for both oil and natural gas are subject to a significant degree of variation, and this variation will affect the calculation of future net cash flows reported by the Partnership at any specific date. 1990 - 1 PARTNERSHIP
TOTAL VALUE PER VALUATION METHOD INVESTOR VALUE(1) 1990 - 1 UNIT - ---------------- ----------------- ------------- Exchange Value......................................... $2,990,728 $2,107 Liquidation value estimated by Benton.................. 1,052,601 742 Continuation analysis by Benton assuming natural gas prices of $1.63 per Mcf and oil prices of $15.94 per Bbl(2)......................................... 415,355 293 Value of Proved Reserves at December 31, 1994(3)....... 1,057,123 745
(1) The Exchange Value and liquidation value attribute no value to Managing General Partners' interests. The continuation analysis assumes continued distributions to the Managing General Partner pursuant to the terms of the Partnership Agreement. (2) The assumed natural gas and oil prices are the prices used for preparation of the Partnership's reserve report at December 31, 1994. The continuation analysis was calculated based upon Benton's estimate of the remaining economic life of the Partnership, estimated to be 5.5 years. (3) Based on the Partnership's December 31, 1994 reserve report prepared by Benton and audited by Huddleston. The reserves are valued as of December 31 of each year, based on oil and natural gas prices as of that date. Market prices for both oil and natural gas are subject to a significant degree of variation, and this variation will affect the calculation of future net cash flows reported by the Partnership at any specific date. 71 85 1991 - 1 PARTNERSHIP
TOTAL VALUE PER VALUATION METHOD INVESTOR VALUE(1) 1991 - 1 UNIT - ---------------- ----------------- ------------- Exchange Value........................................... $692,349 $2,456 Liquidation value estimated by Benton.................... 240,998 855 Continuation analysis by Benton assuming natural gas prices of $1.63 per Mcf and oil prices of $15.94 per Bbl(2)........................................... 47,072 167 Value of Proved Reserves at December 31, 1994(3)......... 210,445 747
(1) The Exchange Value and liquidation value attribute no value to Managing General Partners' interests. The continuation analysis assumes continued distributions to the Managing General Partner pursuant to the terms of the Partnership Agreement. (2) The assumed natural gas and oil prices are the prices used for preparation of the Partnership's reserve report at December 31, 1994. The continuation analysis was calculated based upon Benton's estimate of the remaining economic life of the Partnership, estimated to be 2.5 years. (3) Based on the Partnership's December 31, 1994 reserve report prepared by Benton and audited by Huddleston. The reserves are valued as of December 31 of each year, based on oil and natural gas prices as of that date. Market prices for both oil and natural gas are subject to a significant degree of variation, and this variation will affect the calculation of future net cash flows reported by the Partnership at any specific date. The actual amount that Investors would receive if the Partnerships continued their respective operations would depend on production levels, which cannot be predicted with certainty. In addition, the actual amount that Investors would receive under either of the alternatives to the Exchange would depend on future oil and gas prices. To the extent that future prices for those commodities are materially higher or lower than the pricing assumptions made by the Managing General Partner, those fluctuations would likely have a similar effect on the operating results, distribution rates and market value of the Partnership Units, largely negating the effect of price changes on a comparison between the Exchange and either alternative of continuing the Partnerships or liquidating their assets. In addition, Benton believes that liquidating the Partnerships would deprive Investors of the opportunity to benefit from any future upturn in oil and gas prices. BENEFITS OF CONTINUED OPERATIONS The 1989-1 Partnership. Continuing to operate the 1989-1 Partnership could benefit the Investors by avoiding many of the risks associated with owning Benton Common Stock. In addition, Benton does not pay cash dividends on its shares of Common Stock and does not anticipate paying dividends in the foreseeable future. However, Benton's continuation analysis reflects a present value that is $322 per 1989-1 Unit, or $990 per 1989-1 Unit below the Exchange Value. Accordingly, Benton believes that Investors are likely to receive less value if the 1989-1 Partnership continues in its present form than they would receive by participating in the Exchange. While this conclusion is supported by Benton's analysis of continuing the 1989-1 Partnership, there can be no assurance that the Exchange will be more beneficial to Investors than continuing the 1989-1 Partnership. In determining that the 1989-1 Partnership had reached the stage in its production history when consideration of the Exchange Offer became appropriate, the Managing General Partner evaluated the anticipated results of continuing the 1989-1 Partnership. 72 86 The Managing General Partner's continuation analysis for the 1989-1 Partnership is based upon the Partnership's reserve report at December 31, 1994, prepared by the Managing General Partner and audited by Huddleston. The continuation analysis assumes revenues, taxes and expenses will be allocated to participants and the Managing General Partner in the percentages set forth in the 1989-1 Partnership Agreement. Based upon these assumptions, and further discounted at 10%, the cash flow to the participants for the years indicated are as follows: 1989-1 PARTNERSHIP CONTINUATION ANALYSIS
YEAR TOTAL CASH FLOW(1) CASH FLOW PER UNIT (2) ---- ------------------ ---------------------- 1995 $30,640 $109 1996 37,445 133 1997 21,150 75 1998 1,426 5 ------- ---- TOTAL(3) $90,661 $322 ======= ====
- ------------------------- (1) Reflects total cash flow allocated to participants of the 1989-1 Partnership, after allocation of cash flow to Managing General Partner's interest pursuant to the terms of the 1989-1 Partnership Agreement. (2) Obtained by dividing the total cash flow by 281.8182 Partnership Units. (3) Benton's continuation analysis estimates that the remaining economic life of the 1989-1 Partnership is 3.5 years. This analysis assumes that total revenues, production taxes and lease operating expenses will be consistent with those assumptions set forth in the 1989-1 Partnership reserve report dated December 31, 1994, and that annual general and administrative expenses will be consistent with actual general and administrative expenses incurred by the 1989-1 Partnership for the year ended December 31, 1994. The continuation analysis assumes capital expenditures during 1995 based upon actual capital expenditures through June 30, 1995 and assumes capital expenditures thereafter consistent with those set forth in the Partnership's reserve report. The 1990-1 Partnership. Continuing to operate the 1990-1 Partnership could benefit the Investors by avoiding many of the risks associated with owning Benton Common Stock. In addition, Benton does not pay cash dividends on its shares of Common Stock and does not anticipate paying dividends in the foreseeable future. However, Benton's continuation analysis reflects a present value that is $293 per 1990-1 Unit, or $1,813 per 1990-1 Unit below the Exchange Value. Accordingly, Benton believes that Investors are likely to receive less value if the 1990-1 Partnership continues in its present form than they would receive by participating in the Exchange. While this conclusion is supported by Benton's analysis of continuing the 1990-1 Partnership, there can be no assurance that the Exchange will be more beneficial to Investors than continuing the 1990-1 Partnership. 73 87 In determining that the 1990-1 Partnership had reached the stage in its production history when consideration of the Exchange Offer became appropriate, the Managing General Partner evaluated the anticipated results of continuing the 1990-1 Partnership. 74 88 The Managing General Partner's continuation analysis for the 1990-1 Partnership is based upon the Partnership's reserve report at December 31, 1994, prepared by the Managing General Partner and audited by Huddleston. The continuation analysis assumes revenues, taxes and expenses will be allocated to participants and the Managing General Partner in the percentages set forth in the 1990-1 Partnership Agreement. Based upon these assumptions, and further discounted at 10%, the cash flow to the participants for the years indicated are as follows: 1990-1 PARTNERSHIP CONTINUATION ANALYSIS
YEAR TOTAL CASH FLOW(1) CASH FLOW PER UNIT(2) ---- ------------------ ---------------------- 1995 $131,114 $92 1996 153,178 108 1997 89,495 63 1998 31,851 22 1999 9,253 7 2000 464 1 -------- ---- TOTAL (3) $415,355 $293 ======== ====
- ------------------------- (1) Reflects total cash flow allocated to participants of the 1990-1 Partnership, after allocation of cash flow to Managing General Partner's interest pursuant to the terms of the 1990-1 Partnership Agreement. (2) Obtained by dividing the total cash flow by 1,419.192 Partnership Units. (3) Benton's continuation analysis estimates that the remaining economic life of the 1990-1 Partnership is 5.5 years. This analysis assumes that total revenues, production taxes and lease operating expenses will be consistent with those assumptions set forth in the 1990-1 Partnership reserve report dated December 31, 1994, and that annual general and administrative expenses will be consistent with actual general and administrative expenses incurred by the 1990-1 Partnership for the year ended December 31, 1994. The continuation analysis assumes capital expenditures during 1995 based upon actual capital expenditures through June 30, 1995 and assumes capital expenditures thereafter consistent with those set forth in the Partnership's reserve report. The 1991-1 Partnership. Continuing to operate the 1991-1 Partnership could benefit the Investors by avoiding many of the risks associated with owning Benton Common Stock. In addition, Benton does not pay cash dividends on its shares of Common Stock and does not anticipate paying dividends in the foreseeable future. However, Benton's continuation analysis reflects a present value that is $167 or $2,290 per 1991-1 Unit below the Exchange Value. Accordingly, Benton believes that Investors are likely to receive less value if the 1991-1 Partnership continues in its present form than they would receive by participating in the Exchange. While this conclusion is supported by Benton's analysis of continuing the 1991-1 Partnership, there can be no assurance that the Exchange will be more beneficial to Investors than continuing the 1991-1 Partnership. 75 89 In determining that the 1991-1 Partnership had reached the stage in its production history when consideration of the Exchange Offer became appropriate, the Managing General Partner evaluated the anticipated results of continuing the 1991-1 Partnership. The Managing General Partner's continuation analysis for the 1991-1 Partnership is based upon the Partnership's reserve report at December 31, 1994, prepared by the Managing General Partner and audited by Huddleston. The continuation analysis assumes revenues, taxes and expenses will be allocated to participants and the Managing General Partner in the percentages set forth in the 1991-1 Partnership Agreement. Based upon these assumptions, and further discounted at 10%, the cash flow to the participants for the years indicated are as follows: 1991-1 PARTNERSHIP CONTINUATION ANALYSIS
YEAR TOTAL CASH FLOW(1) CASH FLOW PER UNIT(2) ---- ------------------ --------------------- 1995 $16,472 $58 1996 21,258 75 1997 9,342 34 ------- ---- TOTAL(3) $47,072 $167 ======= ====
- ------------------------- (1) Reflects total cash flow allocated to participants of the 1991-1 Partnership, after allocation of cash flow to Managing General Partner's interest pursuant to the terms of the 1991-1 Partnership Agreement. (2) Obtained by dividing the total cash flow by 281.8182 Partnership Units. (3) Benton's continuation analysis estimates that the remaining economic life of the 1991-1 Partnership is 2.5 years. This analysis assumes that total revenues, production taxes and lease operating expenses will be consistent with those assumptions set forth in the 1991-1 Partnership reserve report dated December 31, 1994, and that annual general and administrative expenses will be consistent with actual general and administrative expenses incurred by the 1991-1 Partnership for the year ended December 31, 1994. The continuation analysis assumes capital expenditures during 1995 based upon actual capital expenditures through June 30, 1995 and assumes capital expenditures thereafter consistent with those set forth in the Partnership's reserve report. BENEFITS OF LIQUIDATION The 1989-1 Partnership. If the 1989-1 Partnership liquidated its assets and completed a dissolution upon the sale of its assets for cash, the Investors would benefit by receiving an immediate cash return without continuing to be subject to the risks of owning Benton Common Stock and Warrants and risks of participation in oil and gas operations. In addition, if the 1989-1 Partnership were liquidated in a cash transaction, the Investors could reinvest the proceeds in similar or different investments. For the reasons described below, however, Benton believes that liquidating the 1989-1 Partnership would not provide Investors with greater values than those they would receive in the Exchange. Although Benton 76 90 made various assumptions that it believes to be reasonable in conducting the liquidation analysis supporting this conclusion, there can be no assurance that those assumptions would ultimately prove to be correct and that proceeds of a cash sale would not exceed the value of the Common Stock and Warrants issuable in the Exchange. Benton's decision to recommend the approval of the Proposal is supported by its internal liquidation analysis, reflecting a liquidation value of $294,634 or $1,045 per 1989-1 Unit. It is further supported by an independent offer to purchase the 1989-1 Partnership's interest in the Umbrella Point Field by Goldking (which price represents 99.3% of the total Proved Reserve estimates of the 1989-1 Partnership) for a total purchase price in cash of $323,296. This purchase price would represent cash distributions to the Investors, following satisfaction of current liabilities, equal to $1,147 per 1989-1 Unit. Based on these factors, Benton has concluded that, while an asset sale in liquidation of the 1989-1 Partnership might result in limited third-party interest in the 1989-1 Partnership's most significant asset, and a sale of the Partnership's properties as a whole would provide an immediate cash return to Investors, it would likely result in valuations by an unaffiliated bidder below the Total Exchange Value, and further, any cash received would likely be equal to or less than the liquidation value after payment of transaction costs and costs associated with liquidation and dissolution, if another third party was willing to purchase only the assets of the 1989-1 Partnership. Benton has not conditioned this Exchange Offer on approval by the other Partnerships described herein, but believes that a third party would significantly discount the value of the Partnership's properties if it could not purchase the working interests owned by all three Partnerships. Additionally, Benton has assumed sole responsibility for payment of all transaction costs associated with the Exchange Offer, allowing distribution of consideration without deduction for such costs. Benton believes it unlikely that a third party would offer to purchase the Partnership's assets, and also assume responsibility for payment of transaction costs. 77 91 1989-1 PARTNERSHIP LIQUIDATION ANALYSIS Estimated Cash Proceeds from Sale of Umbrella Point Field........... $323,296 Working Capital (1)................................................. 6,338 General and Administrative Expense(2)............................... (35,000) -------- Net Aggregate Liquidation Value............................ $294,634 ======== Liquidation Value Per Unit(3).............................. $ 1,045 ========
- ------------------------- (1) At June 30, 1995, the 1989-1 Partnership had current assets, less property held for sale, of $6,338, and liabilities of $0, resulting in a working capital balance of $6,338, excluding the property held for sale. (2) Estimated expenses to the Partnership in preparing the Partnership financial statements, tax returns, Investor tax statements and similar administrative matters. This estimate was determined based upon the actual expenses incurred by the 1989-1 Partnership for general and administrative expense for the year ended December 31, 1994. (3) Obtained by dividing the net aggregate liquidation value by 281.8182 Partnership Units. No liquidation value has been attributed to the Managing General Partners' interest. Benton's liquidation analysis assumed that a Majority in Interest of the Investors would approve the sale of all or substantially all of the 1989-1 Partnership's assets, as required under the 1989-1 Partnership Agreement. Based on this analysis, the Managing General Partner concluded that Investors would benefit more from the Exchange than a potential liquidation of the 1989-1 Partnership. The 1990-1 Partnership. If the 1990-1 Partnership liquidated its assets and completed a dissolution upon the sale of its assets for cash, the Investors would benefit by receiving an immediate cash return without continuing to be subject to the risks of owning Benton Common Stock and Warrants and risks of participation in oil and gas operations. In addition, if the 1990-1 Partnership were liquidated in a cash transaction, the Investors could reinvest the proceeds in similar or different investments. For the reasons described below, however, Benton believes that liquidating the 1990-1 Partnership would not provide Investors with greater values than those they would receive in the Exchange. Although Benton made various assumptions that it believes to be reasonable in conducting the liquidation analysis supporting this conclusion, there can be no assurance that those assumptions would ultimately prove to be correct and that proceeds of a cash sale would not exceed the value of the Common Stock and Warrants issuable in the Exchange. Benton's decision to recommend the approval of the Proposal is supported by its internal liquidation analysis, reflecting a liquidation value of $1,052,601 or $742 per 1990-1 Unit. It is further 78 92 supported by an independent offer to purchase the 1990-1 Partnership's interest in the Umbrella Point Field by Goldking (which price represents 88.1% of the total Proved Reserve estimates of the 1990-1 Partnership) for an estimated total purchase price in cash of $930,865. This purchase price would represent cash distributions to the Investors equal to $656 per 1990-1 Unit. Based on these factors, Benton has concluded that, while an asset sale in liquidation of the 1990-1 Partnership might result in limited third-party interest in the 1990-1 Partnership's most significant asset, a sale of the Partnership's properties as a whole would provide an immediate cash return to Investors but would likely result in valuations by an unaffiliated bidder below the total Exchange Value, and further, any cash received would likely be equal to or less than the liquidation value after payment of transaction costs and costs associated with liquidation and dissolution. Benton has not conditioned this Exchange Offer on approval by the other Partnerships described herein, but believes that a third party would significantly discount the value of the Partnership's properties if it could not purchase the working interests owned by all three Partnerships. Additionally, Benton has assumed sole responsibility for payment of all transaction costs associated with the Exchange Offer, allowing distribution of consideration without deduction for such costs. Benton believes it unlikely that a third party would offer to purchase the Partnership's assets, and also assume responsibility for payment of transaction costs. 79 93 1990-1 PARTNERSHIP LIQUIDATION ANALYSIS Estimated Cash Proceeds from Sale of Umbrella Point Field.......... $930,865 Working Capital(1)................................................. 201,736 General and Administrative Expense(2).............................. (80,000) ---------- Net Aggregate Liquidation Value........................... $1,052,601 ========== Liquidation Value Per Unit(3)............................. $ 742 ==========
- ------------------------- (1) At June 30, 1995, the 1990-1 Partnership had current assets, less property held for sale, of $201,736 and liabilities of $0, resulting in a working capital balance of $201,736, excluding the property held for sale. (2) Estimated expenses to the Partnership in preparing the Partnership financial statements, tax returns, Investor tax statements and similar administrative matters. This estimate was determined based upon the actual expenses incurred by the 1990-1 Partnership for general and administrative expense for the year ended December 31, 1994. (3) Obtained by dividing the net aggregate liquidation value by 1,419.192 Partnership Units. No liquidation value has been attributed to the Managing General Partners' interests. Benton's liquidation analysis did not take into account additional discount factors that an unaffiliated buyer might apply to reflect the 1990-1 Partnership's concentration of production and value in one major property or its lack of a majority working interest in its wells. In addition, Benton did not attempt to quantify the potential impact of being able to secure a single buyer for all of the 1990-1 Partnership's properties under the circumstances where the only available purchaser limited its bid to the 1990-1 Partnership's most significant property interest and excluded less desirable properties. Benton's liquidation analysis assumed that a Majority in Interest of the Investors would approve the sale of all or substantially all of the 1990-1 Partnership's assets, as required under the 1990-1 Partnership Agreement. Based on this analysis, the Managing General Partner concluded that Investors would benefit more from the Exchange than a potential liquidation of the 1990-1 Partnership. The 1991-1 Partnership. If the 1991-1 Partnership liquidated its assets and completed a dissolution upon the sale of its assets for cash, the Investors would benefit by receiving an immediate cash return without continuing to be subject to the risks of owning Benton Common Stock and Warrants and risks of participation in oil and gas operations. In addition, if the 1991-1 Partnership were liquidated in a cash transaction, the Investors could reinvest the proceeds in similar or different investments. For the reasons described below, however, Benton believes that liquidating the 1991-1 Partnership would not provide Investors with greater values than those they would receive in the Exchange. Although Benton 80 94 made various assumptions that it believes to be reasonable in conducting the liquidation analysis supporting this conclusion, there can be no assurance that those assumptions would ultimately prove to be correct and that proceeds of a cash sale would not exceed the value of the Common Stock and Warrants issuable in the Exchange. Benton's decision to recommend the approval of the Proposal is supported by its internal liquidation analysis, reflecting a liquidation value of $240,998 or $855 per 1991-1 Unit. It is further supported by an independent offer to purchase the 1991-1 Partnership's interest in the Umbrella Point Field by Goldking (which price represents 88.0% of the total Proved Reserve estimates of the 1991-1 Partnership) for a total purchase price in cash of $185,282. This purchase price would represent cash distributions to the Investors equal to $657 per 1991-1 Unit. Based on these factors, Benton has concluded that, while an assets sale in liquidation of the 1991-1 Partnership might result in limited third-party interest in the 1991-1 Partnership's most significant asset, a sale of the Partnership's properties as a whole would provide an immediate cash return to Investors but would likely result in valuations by an unaffiliated bidder below the total Exchange Value, and further, any cash received would likely be equal to or less than the liquidation value after payment of transaction costs and costs associated with liquidation and dissolution. Benton has not conditioned this Exchange Offer on approval by the other Partnerships described herein, but believes that a third party would significantly discount the value of the Partnership's properties if it could not purchase the working interests owned by all three Partnerships. Additionally, Benton has assumed sole responsibility for payment of all transaction costs associated with the Exchange Offer, allowing distribution of consideration without deduction for such costs. Benton believes it unlikely that a third party would offer to purchase the Partnership's assets, and also assume responsibility for payment of transaction costs. 81 95 1991-1 PARTNERSHIP LIQUIDATION ANALYSIS Estimated Cash Proceeds from Sale of Umbrella Point Field........... $185,282 Working Capital(1).................................................. 85,716 General and Administrative Expense(2)............................... (30,000) -------- Net Aggregate Liquidation Value............................ $240,998 ======== Liquidation Value Per Unit(3).............................. $ 855 ========
- ------------------------- (1) At June 30, 1995, the 1991-1 Partnership had current assets, less property held for sale, of $85,716 and liabilities of $0 resulting in a working capital balance of $85,716, excluding the property held for sale. (2) Estimated expenses to the Partnership in preparing the Partnership financial statements, tax returns, Investor tax statements and similar administrative matters. This estimate was determined based upon the actual expenses incurred by the 1991-1 Partnership for general and administrative expense for the year ended December 31, 1994. (3) Obtained by dividing the net aggregate liquidation value by 281.8182 Partnership Units. No liquidation value has been attributed to the Managing General Partners' interests. Material changes in Benton's liquidation analysis did not take into account additional discount factors that an unaffiliated buyer might apply to reflect the 1991-1 Partnership's concentration of production and value in one major property or its lack of a majority working interest in its wells. In addition, Benton did not attempt to quantify the potential impact of being able to secure a single buyer for all of the 1991-1 Partnership's properties under the circumstances where the only available purchaser limited its bid to the 1991-1 Partnership's most significant property interest and excluded less desirable properties. Benton's liquidation analysis assumed that a Majority in Interest of the Investors would approve the sale of all or substantially all of the 1991-1 Partnership's assets, as required under the 1991-1 Partnership Agreement. Based on this analysis, the Managing General Partner concluded that Investors would benefit more from the Exchange than a potential liquidation of the 1991-1 Partnership. LACK OF INDEPENDENT REPRESENTATIVE Benton did not engage an independent representative to negotiate the terms of the Exchange Offer on behalf of the Investors, since Benton believed that the Exchange Values for each of the Partnerships is in excess of the fair value of the assets of the Partnerships. In addition, Benton did not want to pay fees to a third party to negotiate the terms of the Exchange. As a result, the Exchange 82 96 Values and other term of the Exchange Offer may not be as favorable as the terms that an independent representative might have obtained. BOARD OF DIRECTORS OF BENTON; BENTON'S REASONS FOR THE EXCHANGE At a meeting held on April 26, 1995, the Board of Directors of Benton unanimously approved the Exchange Offer and the issuance of Benton Common Stock and Warrants in connection with the Exchange. The Delaware Corporation Law does not require that the Benton stockholders approve the Exchange Offer or the issuance of Benton Common Stock or Warrants, and no such approval is being sought. In reaching its conclusion to approve the Exchange Offer, the Board of Directors of Benton determined that the purchase of the Partnership assets by Benton is consistent with and in furtherance of the long - term business strategy of Benton. In addition, the Board believes that the Exchange Offer provides the Investors in the Partnerships, many of whom are Benton stockholders, the opportunity to benefit from the continued growth of Benton and consideration in excess of the liquidation value of each of the Partnerships. The Board understands the significant risks associated with the oil and gas industry and drilling for oil and natural gas, but acknowledges the concerns raised by the Investors in the Partnerships with regard to the disappointing returns on investment by the Investors. Because many of the Investors are also stockholders of Benton, the Board believes it prudent to maintain a good relationship with these stockholders, who have been strong supporters of Benton from inception, and the consideration to be given under the Exchange Offer is indicative of Benton's desire to address the concerns of its Investors and stockholders. The Board of Directors believes that the Exchange Offer may serve to resolve the issues and claims made by certain Investors in the Litigation and may forestall any further litigation surrounding or arising from the Partnerships. In addition, the Board believes that dissolution of the Partnerships upon consummation of the Exchange and adoption of the Proposals by each of the Partnerships will allow Benton to focus its resources on the core assets and projects of Benton. FIDUCIARY DUTIES OF BENTON General. Benton's fiduciary duties to the Investors include legal responsibilities of loyalty, care and good faith. As Managing General Partner of the Partnerships, Benton may not profit by any conduct or transaction in contravention of its fiduciary obligations to the Investors. Rights of action by or on behalf of the Investors for any breach of these duties are provided under most state limited partnership or other laws. Under California law, which is the choice of law provided in the Partnership Agreements, a limited partner may bring action against a general partner, upon a showing of the breach of its fiduciary duty, to recover his capital contribution or to seek an accounting and dissolution of the partnership. While a general partner would have the burden of dispelling all doubts concerning its conduct, simple negligence or an error in judgment not amounting to a breach of fiduciary duty would constitute a defense to the limited partner's actions under California law. Benton believes that it has complied with its fiduciary duties in the management of each of the Partnerships and in connection with the Exchange Offer. Remedies for Breach of Fiduciary Duties. Under California law, except as described below, if a non-consenting Investor believes that adoption of the Proposal or consummation of the Exchange would constitute a breach of the General Partner's fiduciary duties, the Investor could institute legal action against the General Partner to enjoin the Exchange or implementation of the Amendments contemplated by the Proposal or to recover damages resulting from the consummation of the Exchange. In appropriate 83 97 circumstances, a limited partner may institute a class action against its general partner on behalf of himself and the other similarly situated limited partners or a derivative action against a general partner on behalf of the partnership to recover damages for a breach of a general partner's fiduciary duties. This is a developing area of the law, and Investors who have questions concerning the General Partner's duties should consult with their own legal counsel. Limitations on Investors' Remedies. The Partnership Agreements provide that the General Partner and its affiliates will not be liable to the Partnership or the Investors for errors of judgment or any acts or omissions that do not constitute negligence or misconduct. In addition, the Partnership Agreements provide generally that, to the extent permitted by law, the Partnership will indemnify the General Partner and its affiliates providing services on behalf of the Partnerships against judgments and amounts paid in settlement, plus costs and expenses (including reasonable attorneys' fees and expenses) actually and reasonably incurred, if the indemnitee acted in good faith and in a manner reasonably believed to be in, or not opposed to, the best interests of the Partnership. In the opinion of the SEC, indemnification for liabilities arising under the Securities Act is against public policy and therefore unenforceable. ACCESS TO INVESTOR LIST AND PROGRAM RECORDS. Benton will provide free of charge to any Investor, upon written request, a current alphabetized listing of all Investors' names and addresses of the Investors in a Partnership in which the requesting Investor owns a Partnership Unit. Investors are afforded this right under the Partnership Agreement and federal and state law. Investors also have the right under the Partnership Agreement to inspect the books and records of his Partnership at all reasonable times. FAILURE TO APPROVE THE PROPOSALS In the event that the Investors of any of the Partnerships fail to approve the Proposal, as set forth in this Prospectus, the Exchange of Partnership Units tendered pursuant to the Exchange offer will not be consummated and the assets of that Partnership will not be transferred to Benton. However, the assets of any Partnership whose Investors do approve the Proposal and accept the Exchange will be transferred to Benton. In the event the Investors of a Partnership fail to approve the Proposal, that Partnership would continue in its business as heretofore operated. However, it is possible that a new offer might be negotiated between such Partnership and Benton. No such other terms have been discussed or agreed upon. In addition, the Managing General Partner may also explore other alternatives, such as the sale of that Partnership's assets to a third party. However, there is no assurance that the Managing General Partner could find a third party interested in purchasing such assets or that the terms and conditions of such a purchase and sale agreement would be as favorable as the terms offered pursuant to the Exchange Offer. Pursuant to the terms of the purchase agreements with Goldking, the seller or purchaser may terminate the agreement if the closing has not occurred on or before December 31, 1995. If the Partnerships do not approve the Proposals, there can be no assurance that a sale of the Partnerships' assets for cash pursuant to the Goldking Agreement can be accomplished prior to such termination date. The terms of each of the Partnership Agreements require that such a sale be approved by the participants prior to consummation of such a sale. 84 98 CONSENT PROCEDURES WRITTEN CONSENT AND VOTE REQUIRED Investors may tender their Partnership Units or vote against the Proposal by properly completing and executing the Letter(s) of Transmittal accompanying this Prospectus and attached as Exhibit D in accordance with the instructions contained therein, and delivering it, together with any requisite supporting documents indicated in the Letter of Transmittal, prior to the Expiration Date, to Benton at the following address: Benton Oil and Gas Company 1145 Eugenia Place, Suite 200 Carpinteria, California 93013 Telephone: (805) 566-5600 PARTNERSHIP UNITS WILL NOT BE VALIDLY TENDERED UNLESS THE LETTER OF TRANSMITTAL HAS BEEN COMPLETELY AND FULLY EXECUTED IN ACCORDANCE WITH THE INSTRUCTIONS THERETO AND ACCOMPANIED BY ALL OTHER REQUIRED DOCUMENTS IN FORM AND SUBSTANCE SATISFACTORY TO BENTON. All questions concerning the validity, form and eligibility (including time of receipt) of tenders will be determined by Benton, whose determination will be final and binding. CONSENT TABULATION All votes consenting to the Proposal and withholding consent, as directed in the Letter of Transmittal submitted by Investors, will be tabulated by First Interstate Bank. First Interstate Bank has agreed to make the tabulation available to Investors upon request to Benton. EXPIRATION OF EXCHANGE OFFER The Exchange Offer will be held open for 60 days from the date of this Prospectus and will expire at 5:00 p.m. Pacific Time on the Expiration Date. The Expiration Date will be ________, 1995, unless extended by Benton for a period of up to 60 days. Notice of extension of the Exchange Offer, if made, will be given by mail to each Investor. An extension will be effective upon mailing of notice. AMOUNT TENDERED Benton will not accept tenders of less than all of an Investor's Partnership Units. REVOCABILITY OF TENDERS Tenders of Partnership Units and consents to the Proposal may be revoked at any time prior to the Expiration Date by sending notice of revocation to Benton at 1145 Eugenia Place, Suite 200, Carpinteria, California 93013, Attention: Toni L. Jackson. The notice should identify the Investor, indicate the Partnership Units for which he is revoking his tender and indicate an intention to revoke a prior tender and withhold consent to the Proposal. If this Prospectus is amended to reflect a material adverse development, the Expiration Date will be extended, if required, to afford at least 20 days for Investors to revoke their prior tender of Partnership Units. 85 99 SOLICITATION OF LETTERS OF TRANSMITTAL Benton intends to enter into an agreement with participating NASD broker/dealers ("Solicitating Dealer") to assist in the solicitation of Letters of Transmittal for the Exchange Offer. Each Solicitating Dealer who executes an agreement with Benton will be entitled to receive a fee and expense reimbursement from Benton equal to 2% of the aggregate Exchange Value of Units held by Investors who return a completed Letter of Transmittal (whether they vote for or against the Proposal) as a result of its solicitation effort (or an aggregate for all Solicitating Dealers of up to $81,064), as evidenced by the appearance of its name on the Letter of Transmittal in the space provided for that purpose. Total fee and expense reimbursements to the Solicitating Dealers will not exceed 2% of the Total Exchange Value. Benton has agreed to indemnity Solicitating Dealers against certain civil liabilities, including liabilities under the Securities Act. The Solicitating Dealers may be deemed to be underwriters within the meaning of the Securities Act. Holders of Units in the Partnerships who elect to accept the Exchange Offer may elect to receive cash in lieu of shares of Common Stock to be issued, BUT CASH WILL BE DISTRIBUTED TO HOLDERS MAKING SUCH ELECTION ONLY IF THE SALE OF THE UMBRELLA POINT FIELD TO GOLDKING, AS DESCRIBED HEREIN, IS ACTUALLY CONSUMMATED. A holder who wishes to accept the Exchange Offer and make an election to receive cash in lieu of shares of Common Stock should properly indicate such election on the Letter of Transmittal. If the sale of the Umbrella Point Field working interests to Goldking in consummated, a holder who elects to receive cash in lieu of Common Stock will receive $1,185 for each 1989-1 Unit, $891 for each 1990-1 Unit and $1,055 for each 1991-1 Unit, with Warrants in the amounts described herein. There can be no assurance from Benton that the sale of the Umbrella Point Field to Goldking will be consummated, and therefore, an Investor should make a decision to accept the Exchange Offer based solely upon a decision to receive Common Stock and Warrants in the amounts set forth herein. ACCEPTANCE OF TENDERS On the Closing Date, subject to the satisfaction or waiver of the conditions to the Exchange Offer, Benton will accept all Partnership Units properly tendered pursuant to the Exchange Offer. If the Partnerships accept the Proposals, Benton will, on behalf of the approving Partnerships, cause the assets of such Partnerships, subject to associated liabilities, to be withdrawn from the Partnership and contributed to Benton, effective as of the Effective Date, in exchange for the Common Stock and Warrants which will be issued and delivered promptly after the Closing Date. On the Closing Date, Benton will cause certificates representing the Common Stock and the Warrants issuable in the Exchange to be registered in the name of the holders who have accepted the Exchange Offer. Benton will also cause a certificate representing the shares of Common Stock and Warrants that will be issued to participants upon liquidation of each of the Partnerships to be issued in the name of the Partnership, pending dissolution, liquidation and winding-up of the Partnerships. Immediately thereafter, Benton will cause the shares of Common Stock and Warrants issued in the name of the Partnership to be transferred into certificates representing Common Stock and Warrants, registered in the names of the individual participants remaining in the Partnerships following liquidation. SPECIAL REQUIREMENTS FOR CERTAIN INVESTORS Some of the Investors are entities such as estates, trusts, corporations, limited partnerships or general partnerships. With respect to a Partnership Unit tendered by an Investor other than an individual, 86 100 Benton may elect, at its option, to require that each Letter of Transmittal be accompanied by evidence that the Investor has met all requirements of its governing instruments, such as applicable partnership or joint venture agreements, and is authorized to tender its Partnership Units under the laws of the jurisdiction in which the entity was organized. With respect to most trusts, including individual retirement accounts, Benton expects to require only that the named trustee (or authorized representative thereof) execute the Letter of Transmittal. REPRESENTATIONS AND COVENANTS Each Investor represents in the Letter of Transmittal that he has, and will have as of the Closing Date, the right and authority to transfer his Partnership Unit, and that his Partnership Unit is free and clear of all liens, encumbrances and adverse claims. The Letter of Transmittal also contains a covenant by the Investor to execute any additional documents and instruments that may be reasonably required to more effectively transfer to and to vest in Benton the assets underlying the tendered Partnership Units and a power of attorney to Benton to permit Benton, as Managing General Partner, to execute on his behalf any additional documents necessary to consummate the Exchange, including any documents on behalf of the Investors that may be necessary to withdraw the assets of the Partnership and contribute those assets to Benton. VALIDITY OF TENDERS All questions concerning the validity, form, eligibility (including time of receipt) and acceptance of the Partnership Units tendered will be determined by Benton, whose determination will be final and binding. The interpretation by Benton of the terms and conditions of the Exchange Offer (including the instructions to the Letter of Transmittal) will also be final and binding. Benton reserves the right to waive any irregularities or conditions regarding the manner of tender. Any irregularities in connection with such tenders must be cured within such time as Benton determines unless waived by Benton. Tenders will be deemed not to have been made until irregularities have been cured or waived. Any Letter of Transmittal not properly completed and executed will be returned by Benton to the tendering Investor as soon as practicable unless the irregularities are cured or waived. Benton is under no duty to give notification of defects in tenders, and will not incur liability for failure to give such notification. Delivery of the Transmittal Letter is at the risk of the Investor. A tender will be effective only when the Letter of Transmittal is actually received by Benton. To ensure receipt of the Letter of Transmittal and all other required documents, if any, when sent by the U.S. Mail, Investors should use certified or registered mail, return receipt requested. PAYMENTS OF FEES AND EXPENSES Fees and expenses incurred in connection with the Exchange Offer will be paid by Benton, whether or not the Proposals are accepted. Fees and expenses incident to the Exchange Offer are estimated to be approximately $545,000, all of which will be funded from Benton's working capital. The estimated fees and expenses for the Exchange Offer are itemized below. 87 101 SEC registration fee ...................... $ 3,133 NASD filing fee ........................... 1,223 NASDAQ-NMS listing fees ................... 5,000 Soliciting Agent fees ..................... 70,000 Legal fees and expenses ................... 200,000 Blue sky expenses ......................... 5,000 Printing costs ............................ 175,000 Engineering fees .......................... 10,000 Accounting fees ........................... 50,000 Miscellaneous ............................. 25,644 -------- Total ................... $545,000 ========
COMPLIANCE WITH TENDER OFFER PRACTICES In conducting the Exchange Offer, Benton will comply with the provisions of Rule 14e - 1 under the Exchange Act relating to the Solicitation of tenders and the payment of consideration in a tender offer. 88 102 CERTAIN FEDERAL TAX CONSEQUENCES The following tax discussion summarizes certain federal income tax consequences of the Exchange. This summary is based upon an opinion rendered to Benton by Emens, Kegler, Brown, Hill & Ritter Co., L.P.A., counsel to Benton in connection with the Exchange. A copy of such opinion has been filed as an exhibit to the Registration Statement, and is available to an Investor upon written request to Benton. It is intended to provide only a general summary and does not include a complete analysis of the consequences that may vary with or are contingent upon individual circumstances, such as a taxpayer who is subject to special provisions of the Internal Revenue Code. This discussion does not address the federal income tax treatment of other transactions related to the Exchange, any aspect of state, local or foreign tax laws, or any federal laws other than those pertaining to income tax. None of the parties have requested a ruling from the Internal Revenue Service with respect to the federal income tax consequences of the Exchange. No assurance can be given that future legislation, regulations, administrative pronouncements or court decisions will not significantly change the law and materially affect the conclusions expressed herein. Any such change, even though made after the consummation of the Exchange, could be applied retroactively. MATERIAL TAX CONSEQUENCES OF THE EXCHANGE Upon the exchange of the Partnership Units for Common Stock and Warrants, Investors shall recognize gain equal to the amount by which the fair market value of the Common Stock and Warrants received by them exceeds their respective bases in the Partnership Units exchanged therefor. Similarly, those Investors who do not participate in the Exchange, but rather receive Common Stock and Warrants upon liquidation of the Partnerships, should be deemed to have transferred their Partnership Units for Common Stock and Warrants. Therefore, an Investor will recognize gain and be liable for taxes although the Investor will not receive cash (except for Investors who may elect the cash option) and will thus be required to sell the Common Stock or otherwise secure cash to pay the taxes. It is possible that the Internal Revenue Service may argue that the transaction constitutes a transfer of assets of the Partnership to Benton for Common Stock and Warrants with the Common Stock and Warrants then distributed to the Investors in liquidation of their interests in the Partnerships. Under such a characterization of the transactions, the Partnerships would recognize gain on the disposition of the assets which would be allocated to the Investors. Such a characterization could affect the amount of gain recognized by the Investor. However, courts evaluating the transfer of all of the assets of a partnership followed by a termination of the business of the partnership have generally held that such transactions will be characterized as a transfer of partnership interests in exchange for the assets received rather than a transfer by the partnership of assets and subsequent liquidation. Therefore, the treatment afforded Investors not consenting to the Exchange should not differ from the tax treatment realized by Investors who agree to exchange their Partnership Units for Common Stock and Warrants. Assuming the Investor has held his Interest for more than one year and assuming his Interest has not been held for sale in the ordinary course of the Investor's trade or business, any gain or loss realized upon the transfer of the Partnership Units will be taxed as long term capital gain or loss, except to the extent that the consideration received is attributable to his allocable share of substantially appreciated inventory items and unrealized receivables (including depreciation recapture and excess intangible drilling and development costs) of the Partnerships. The portion of any gain attributable to these items will be taxed to the Investor as ordinary income. In addition, in the event of a recharacterization of the transaction as a transfer of assets, additional ordinary income could be recognized by the Partnerships which would be allocable to Investors. 89 103 REALIZATION OF SUSPENDED PASSIVE LOSSES Upon disposition of the Partnership Units, the Investors will have completely disposed of their Interest in the Partnerships. Any Investor who has any suspended passive losses resulting from the ownership of Partnership Units will realize those suspended passive losses upon consummation of the Exchange. BASIS IN STOCK AND WARRANTS Upon consummation of the Exchange, the basis of the Investors in the Common Stock and Warrants received by them shall be equal to the fair market value of such securities as of the date of consummation of the Exchange. THE PRECEDING DISCUSSION IS INTENDED ONLY AS A SUMMARY OF CERTAIN FEDERAL INCOME TAX CONSEQUENCES OF THE EXCHANGE AND DOES NOT PURPORT TO BE A COMPLETE ANALYSIS OR DISCUSSION OF ALL POTENTIAL TAX EFFECTS RELEVANT THERETO. THUS, INVESTORS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS AS TO THE SPECIFIC TAX CONSEQUENCES TO THEM OF THE EXCHANGE, INCLUDING TAX RETURN REPORTING REQUIREMENTS, THE APPLICABILITY AND EFFECT OF FEDERAL, STATE, LOCAL AND OTHER APPLICABLE TAX LAWS AND THE EFFECT OF ANY PROPOSED CHANGES IN THE TAX LAWS. 90 104 COMPARATIVE RIGHTS OF SECURITY HOLDERS The following comparative information is an accurate summary of the material differences associated with rights of a holder of Units in the Partnerships versus stockholders in Benton. The rights and duties of Unitholders summarized below are the same for each of the Partnerships, except as otherwise noted.
PARTNERSHIPS BENTON OIL AND GAS COMPANY Distributions and Dividends Each of the Partnership Agreements provides Although holders of Common Stock are entitled for cash distributions in the discretion of to receive any dividends declared thereon by the Managing General Partner in an amount Benton's Board of Directors out of legally equal to approximately the difference between available funds, no dividends are expected to revenues allocated to the respective partners be paid on the Common Stock for the and costs charged to the partners. The foreseeable future. Under Delaware law, Partnership Agreement states that the dividends may be paid out of the Company's provisions do not serve as a limitation on surplus or out of its net profits for the the right of the Managing General Partner to fiscal year in which the dividend is declared retain, pledge or use so much of the revenues and/or the preceding fiscal year. In or other assets of the Partnerships to addition, the Company's credit agreements conduct additional operations, establish restrict the Company's ability to pay cash reserves for anticipated expenditures or dividends. repay any amounts borrowed by the Partnerships to finance the conduct of such operations. Tax Matters None of the Partnerships are subject to The Company is subject to federal income tax federal or state income taxes. Each partner on its consolidated income after allowable is allocated his pro rata share of the deductions and credits. Stockholders will not Partnership's taxable income. be taxed on the Company's income but will generally be subject to federal and state income taxes on dividends received from the Company, if any.
91 105
Voting Rights Holders of Units in the Partnerships are Stockholders of Benton are entitled to one entitled to one vote per Unit on matters vote per share on all matters submitted to submitted to them for a vote, on any sale of them for a vote, including the election and all or substantially all of the assets, removal of directors, amendments to the dissolution of the Partnership and removal of Certificate of Incorporation, certain mergers the Managing General Partner. Each of these and share exchanges, dissolution and the sale matters requires the consent of a majority of of all or substantially all of the assets of the outstanding Units. the Company. These matters require the approval of a majority of the outstanding Common Stock. Accordingly, the holders of Units will not receive a security with significantly different voting rights, other than eliminating the right to compel dissolution and adding the right to participate in annual elections of directors. However, former holders of Units will own a smaller percentage interest in the Company than they currently own in the respective Partnerships, resulting in a corresponding decrease in their voting power. Right to Call Meetings Meetings of the participants of the Special meetings of the Company's Partnerships may be called by the Managing stockholders may be called by the President, General Partner or by holders of at least 10% Board of Directors or by holders of not less of the outstanding Units. Actions requiring a than 10% of the Common Stock. Actions vote of the holders of Units may be taken requiring a vote may be taken without a without a meeting upon written consent by the meeting upon written consent by the same same percentage of Unitholders required to percentage of stockholders required to approve the action at a meeting. approve the action at a meeting. Right to Investor List Under California law, a holder of Units has The Company is required to maintain a list of the right to examine or copy a listing of the the names and addresses of all stockholders names and addresses and record ownership at its principal office during normal business positions of the holders of Units. hours for any proper purpose and, in certain circumstances, to provide a copy of the list to any stockholder upon request.
92 106
Assessments and Limited Liability Under the terms of the Partnership Agreements, The Company's stockholders will not be Unitholders are not subject to additional subject to assessments or to personal assessments. The liability of the Unitholders liability for obligations of the Company. is generally limited to their capital contributions and, in certain circumstances, the amount of any capital distributed or returned to them. Allocations and Dilution Under the terms of the Partnership Agreements, The Company's Certificate of Incorporation the participants pay 99% of the lease authorizes the issuance of up to 40,000,000 acquisition, geophysical and seismic costs, shares of Common Stock and 5,000,000 shares well costs, general and administrative of Preferred Stock, including shares that may expenses and organization and offering be divided into one or more additional series expenses, including commissions, while the with rights and preferences to be determined co-managing general partners pay 1% of such by the Company's Board of Directors without costs. any stockholder action. An Investor's percentage interest in the Company is subject to dilution upon issuance of additional securities by the Company. Under the terms of the 1989-1 Partnership Agreement, Revenues, production taxes and lease operating expenses on proven producing wells are allocated 99% to the participants and 1% to the co-managing general partners. Revenues, production taxes and lease operating expenses on recompleted wells are allocated 74.25% to the participants and 25.75% to the co-managing general partners. On new wells drilled, revenues, production taxes and lease operating expenses are allocated 64.35% to the participants and 35.65% to the co-managing general partners. Under the terms of the 1990-1 Partnership Agreement, general and administrative expenses and lease operating expenses are shared 74.25% by the participants and 25.75% by the co-managing general partners. Revenues and production taxes are allocated
93 107
73.5974% to the participants, 25.5236% to the co-managing general partners, and .879% to broker/dealers (special limited partners) who met certain minimum sales requirements in the initial offering in the 1990-1 Units. Under the terms of the 1991-1 Partnership Agreement, for the first 12 months of the Partnership, general and administrative expenses were covered by a fee, equal to 3% of the initial capital raised, paid by the 1991-1 Partnership to Benton. The fee was payable 99% by the participants and 1% by the co-managing general partners. General and administrative expenses after the first 12 months and lease operating expenses are shared 74.25% by the participants and 25.75% by the co-managing general partners. Revenues and production taxes are allocated 73.944% to the participants, 25.6438% to the co-managing general partners and .4122% to broker/dealers (special limited partners) who met certain minimum sales requirements in the initial offering of the 1991-1 Units. Allocations outlined above are made to Unitholders in proportion to the number of Units owned. Liquidity There is no trading market for the Units. The Company's Common Stock is traded on the NASDAQ-NMS and the shares issued pursuant to this Exchange Offer will be freely tradable by non-affiliates of the Company. There is no trading market for the Warrants. Redemption and Conversion The Units are not redeemable or convertible The Common Stock is not redeemable or into other securities. convertible. The Warrants can be exercised for Common Stock upon payment of the exercise price ($11.00
94 108 per share) prior to expiration of the Warrant. Financial Reporting The Unitholders are entitled to receive The Company is subject to the reporting audited annual financial statements and requirements of the Exchange Act and files reserve reports for the Partnerships. periodic reports as well as proxy statements with the SEC, copies of which are provided or are available to its stockholders. Operating Strategy The Partnerships were formed to invest in oil Benton is primarily engaged in the and natural gas activities by acquiring proven development and production of oil and gas producing properties that have additional properties. Benton's operations are focused development potential, recompleting previously on the Eastern Region of Venezuela, the Gulf drilled wells and drilling new wells. The Coast Region of Louisiana and the West Partnerships' properties are all located in a Siberia Region of Russia. Benton's business small number of fields within the United strategy is to seek new reserves in areas of States. Although each of the Partnership low geologic risk and to exploit Agreements permits the Managing General underdeveloped existing oil and gas fields. Partners to borrow money on behalf of such Benton implements the exploitation strategy Partnership, Benton's policy as Managing through the in-house design and General Partner has been to refrain from interpretation of 3-D seismic surveys and financing oil and gas activities through through workovers, recompletions, redrilling credit. and exploration and development drilling. Benton has, and will continue to, finance a portion of its oil and gas activities through issuance of debt instruments or under credit arrangements. Management and Compensation Benton and a wholly owned subsidiary, Benton The stockholders of Benton Oil and Gas Oil and Gas Company of Louisiana, are the Company elect directors annually and the Co-Managing General Partners of each of the directors elect officers of the Company to Partnerships. Benton makes all decisions serve at the discretion of the Board. regarding the business and operations of the Officer salaries and incentive compensation Partnerships, including production, are determined annually by the Board of development and other activities, and any sale Directors and/or the President of Benton. of properties and the acquisition of additional properties. The Co-Managing General Partners do not receive any management fees or other
95 109 fees from any of the Partnerships. The Partnerships pay the Co-Managing General Partners for lease operating expenses, well costs and general and administrative expenses incurred by them on behalf of the Partnerships. Benton receives allocations of profits and losses. See "--Allocation and Dilution," above. Fiduciary Duties The Co-Managing General Partners fiduciary The fiduciary duties owed by the directors of duties to the Unitholders include legal Benton to its stockholders under the Delaware responsibilities of loyalty, care and good General Corporation law and remedies available faith. Benton may not profit from drilling in for a breach of those responsibilities are contravention of its fiduciary obligation to similar to those applicable to the Partnerships the Partners. and the Unitholders. Therefore, the Exchange generally will not involve any reduction in the standard of care owed to Investors or in the remedies available for any breach of those duties. Moreover, the elimination of the dual rule of the Board of Directors as the governing body of Benton with its obligations to stockholders of Benton as well as obligations and duties owed to Unitholders by Benton, as Managing General Partner, should remove most of the conflicts of interest inherent in the current structure. Limits on Management's Liability The Partnership Agreements provide that in any Benton's Certificate of Incorporation and threatened, pending or completed action, suit Bylaws provide for the elimination of or proceeding to which the Co-Managing General directors' liability for monetary damages Partners were or are a party or are threatened arising from a breach of certain fiduciary to be made a party by reason of the fact that obligations and for the indemnification of they were or are a Co-Managing General Partner directors, officers and agents to the full of the Partnership involving any alleged cause extent permitted by the Delaware General of action for damages arising from the Corporation Law. These provisions generally performance of oil and gas activities, provide for indemnification in the absence of including exploration, development, gross negligence or willful misconduct and completion, operation, or other activities cannot be amended without the affirmative relative to management and disposition of oil vote of a majority of the outstanding shares and gas properties or production of Common Stock.
96 110 from such properties, the Partnership will indemnify the Co-Managing General Partners against expenses actually and reasonably incurred by them in connection with such action, suit or proceeding if they acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the Partnership, and provided that their conduct does not constitute negligence, misconduct, or a breach of their fiduciary obligations to the Unitholders. The Unitholders under the Agreement are each solely and individually responsible only for their pro rata share of the liabilities and obligations of the Partnership, and any Unitholder who incurs liability in excess of his pro rata share shall be entitled to contribution from the other Unitholders. Each Co-Managing General Partner agrees to indemnify each Unitholder from paying any liabilities or obligations of the Partnership in excess of such Unitholders capital contribution. Continuation of Existence The Partnership Agreement for the 1989-1 The Company has a perpetual term, subject to Partnership, the 1990-1 Partnership and the dissolution upon the occurrence of specified 1991-1 Partnership provides for a term ending events. on December 31, 2039, December 31, 2039 and December 31, 2040, respectively, or until an earlier dissolution upon specified events, but contemplates continuing operations in accordance with its objectives. Anti-Takeover Provisions There are no anti - takeover provisions in the Benton is subject to the anti-takeover Partnership Agreements or under California protections of the Delaware General Partnership law. Corporation Law, which prohibit business combinations with interested stockholders under certain circumstances. In addition, Benton has adopted a shareholder rights plan, or
97 111 poison pill, which could have the effect if delaying or impeding an unfriendly takeover of the Company. Liquidation Rights In the event of liquidation, the partners are In the event of liquidation, holders of entitled to a distribution in proportion to Common Stock would be entitled to share their positive capital account balances after ratably in any assets of the Company the creditors, including Partners, who are remaining after satisfaction of obligations creditors (to the extent permitted by law), to its creditors and liquidation preferences have been paid. If the liabilities of the on any series of Preferred Stock of the partnership exceed the assets upon Company then outstanding. The Company liquidation, or otherwise if any General currently has no shares of Preferred Stock Partner then has a negative balance in its outstanding and has no plans to issue any capital account, the General Partners must shares of Preferred Stock in the foreseeable contribute funds to the Partnership in the future. ratio of their negative capital accounts until the negative capital accounts are eliminated. Right to Compel Dissolution The Partnership may be dissolved by the Under Delaware law, stockholders of the written vote or consent by Participants Company may not vote to compel dissolution of representing a majority of the outstanding the Company without prior action by its Board units. of Directors.
98 112 UNAUDITED PRO FORMA FINANCIAL INFORMATION The following unaudited pro forma combined information reflects the combination of Benton and the Partnerships, including pro forma adjustments to account for the Exchange Offer. The minimum pro forma amounts reflect the acquisition of the 1991-1 Partnership and the maximum pro forma amounts reflect the acquisition of all the Partnerships. The pro forma balance sheet at June 30, 1995 is prepared assuming the acquisition of the Partnerships occurred on June 30, 1995. The pro forma statements of operations and cash flows for the year ended December 31, 1994 and the six months ended June 30, 1995 are prepared assuming the acquisition of the Partnerships occurred on January 1, 1994. The pro forma statements assume the Limited Partners accept common stock, rather than cash, in exchange for their partnership units. The unaudited pro forma combined financial information below should be read in conjunction with the financial statements of Benton and the Partnerships and the related notes thereto included elsewhere in the Prospectus. 99 113 PRO FORMA CONSOLIDATED BALANCE SHEET JUNE 30, 1995
Consolidated Minimum Pro Remaining Benton Oil and Forma Minimum Pro Forma Maximum Gas Company Adjustments Notes Pro Forma Adjustments Notes Pro Forma -------------------------------------------------------------------------------------------- ASSETS: Current Assets: Cash and cash equivalents $ 25,416,122 $ 82,547 (a) $ 24,953,669 $ 151,172 (d) $ 25,104,841 (545,000) (g) Restricted cash 19,550,000 19,550,000 19,550,000 Accounts receivable: Accrued oil and gas revenue 11,412,303 11,412,303 11,412,303 Joint interest and other 3,745,439 3,745,439 3,745,439 Property held for sale 756,872 185,282 (a) 942,154 1,254,161 (d) 2,196,315 Prepaid expense & other 1,903,825 1,903,825 1,903,825 ------------ --------- ------------ ----------- ------------ Total Current Assets 62,784,561 (277,171) 62,507,390 1,405,333 63,912,723 Other Assets 1,438,315 1,438,315 1,438,315 Property and Equipment, net 125,986,352 49,243 (a) 126,009,846 133,573 (d) 126,143,798 (25,749) (b) 379 (e) ------------ --------- ------------ ----------- ------------ Total Assets $190,209,228 ($253,677) $189,955,551 $ 1,539,285 $191,494,836 ============ ========= ============ =========== ============ LIABILITIES: Current Liabilities: Accounts payable: Revenue distribution $ 866,461 $866,461 $ 866,461 Trade and other 9,591,452 (3,169) (a) 9,588,283 (56,902) (d) 9,531,381 Accrued interest payable, payroll and related taxes 1,173,599 1,173,599 1,173,599 Income taxes payable 1,586,616 1,586,616 1,586,616 Short term borrowings 21,534,318 21,534,318 21,534,318 Current portion of long term debt 5,893,160 5,893,160 5,893,160 ------------ --------- ------------ ----------- ------------ Total Current Liabilities 40,645,606 (3,169) 40,642,437 (56,902) 40,585,535 Long Term Debt 53,268,253 53,268,253 53,268,253 Minority Interest 3,486,233 3,486,233 3,486,233 STOCKHOLDERS' EQUITY: Common stock 251,054 268 (c) 251,322 1,451 (f) 252,773 Additional paid-in-capital 94,317,797 689,164 (c) 94,461,961 3,356,033 (f) 97,817,994 (545,000) (g) Accumulated Deficit (1,759,715) (394,940) (h) (2,154,655) (1,761,297) (h) (3,915,952) ----------- --------- ------------ ----------- ------------ Total Stockholders' Equity 92,809,136 (250,508) 92,558,628 1,596,187 94,154,815 ------------ --------- ------------ ----------- ------------ Total Liabilities and Stockholders' Equity $190,209,228 ($253,677) $189,955,551 $ 1,539,285 $191,494,836 ============ ========= ============ =========== ============ Book value per share $3.70 $3.68 $3.72 ===== ===== ===== Common shares outstanding 25,105,493 25,132,265 25,277,373 ========== ========== ==========
Notes: (a) Combine assets of the 1991-1 Partnership, net of intercompany receivables and payables. (b) Record purchase of 1991-1 Partnership properties. (c) Record issuance of 26,772 shares and 108,500 warrants to the participants in the acquisition of the 1991-1 Partnership at the average market value of the 20 days ended September 11, 1995 of $11.00 per share and $3.64 per warrant. (d) Combine assets of the 1989-1 Partnership and 1990-1 Partnership, net of intercompany receivables and payables. (e) Record purchase of 1989-1 Partnership and 1990-1 Partnership properties. 100 114 (f) Record issuance of 145,108 shares and 483,873 warrants to the participants in the acquisition of the 1989-1 Partnership and the 1990-1 Partnership at the average market value for the 20 days ended September 11, 1995 of $11.00 per share and $3.64 per warrant. (g) Record payment of stock issuance fees and distribution expenses. (h) Record roll-up expenses associated with acquiring the Partnership units. The participants are given the option of accepting cash or shares of the Company's common stock in exchange for their partnership units. The pro forma balance sheet above assumes that the participants accept stock in exchange for their partnership units. If all the participants accept cash rather than shares, cash would be reduced to $24,656,259 and $23,207,902 for the minimum and maximum pro forma balance sheets, respectively. Common shares outstanding would be reduced to 25,105,493, common stock would be reduced to $251,054 and additional paid in capital would be reduced to $94,167,737 and $95,929,033 in the minimum and maximum pro forma balance sheets, respectively. 101 115 PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 1995
Consolidated Minimum Pro Remaining Benton Oil and Forma Minimum Pro Forma Maximum Gas Company Adjustments Notes Pro Forma Adjustments Notes Pro Forma -------------------------------------------------------------------------------------- REVENUES: Oil and gas sales $24,829,260 $ 33,219 (a) $24,862,479 $ 242,212 (b) $25,104,691 Gain on exchange rates 118,786 118,786 118,786 Investment earnings 873,521 577 (a) 874,098 633 (b) 874,731 Partnership fees, reimbursements and other 48,829 (5,412) (c) 43,417 (28,414) (c) 15,003 ----------- -------- ----------- --------- ----------- 25,870,396 28,384 25,898,780 214,431 26,113,211 ----------- -------- ----------- --------- ----------- EXPENSES: Lease operating costs and production taxes 5,287,071 9,684 (a) 5,296,755 102,700 (b) 5,399,455 Depletion, depreciation, and amortization 6,473,402 20,849 (d) 6,494,251 157,869 (d) 6,652,120 General and administrative 3,883,606 22,404 (a) 3,900,598 79,574 (b) 3,951,758 (5,412) (c) (28,414) (c) Interest 3,361,041 3,361,041 3,361,041 Minority Interest in net income 1,742,573 1,742,573 1,742,573 20,747,693 47,525 20,795,218 311,729 21,106,947 Income before income taxes and roll-up expenses and payments 5,122,703 (19,141) 5,103,562 (97,298) 5,006,264 Income taxes 1,971,102 1,971,102 1,971,102 ----------- -------- ----------- --------- ----------- Income before roll-up expenses and payments 3,151,601 (19,141) 3,132,460 (97,298) 3,035,162 Roll-up expenses and payments ----------- -------- ----------- --------- ----------- Income (loss) after roll-up expenses $ 3,151,601 ($19,141) $ 3,132,460 ($97,298) $ 3,035,162 =========== ======== =========== ========= =========== Income per common share: Before roll-up expenses and payments $0.12 $0.12 $0.11 ----- ----- ----- After roll-up expenses and payments $0.12 $0.12 $0.11 ----- ----- ----- Weighted average common shares outstanding 26,459,123 26,485,895 26,631,003 ========== ========== ========== Ratio of earnings to fixed charges: Before roll-up expenses and payments 2.51x 2.50x 2.47x ----- ----- ----- After roll-up expenses and payments 2.51x 2.50x 2.47x ----- ----- -----
Notes: (a) Record the participants' share of the 1991-1 Partnership. (b) Record the participants' share of the 1989-1 Partnership and 1990-1 Partnership. (c) Eliminate allocated overhead costs from partnerships. (d) Record depletion on oil and gas properties acquired from partnerships. The participants are given the option of accepting either cash or shares of the Company's common stock in exchange for their partnership units. The pro-forma statements of operations above assume that the participants accept stock in exchange for their partnership units. If all the participants accept cash rather than shares, the weighted average number of shares would be 26,459,123 for both the minimum and maximum pro-forma statements of operations. 102 116 PRO FORMA CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 1995
Consolidated Minimum Benton Oil and Pro Forma Minimum Gas Company Adjustments Notes Pro Forma ---------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net Income (loss) $ 3,151,601 $ (19,141) (a) $ 3,132,460 Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depletion, depreciation and amortization: 6,473,402 20,849 (a) 6,494,251 Net earnings from limited partnerships (20,435) (270) (c) (20,705) Amortization of financing costs 90,640 90,640 Loss on disposal of assets 10,632 10,632 Minority interest in undistributed earnings of subsidiary 1,742,573 1,742,573 (Increase) decrease in accounts receivable (1,919,152) (1,919,152) (Increase) decrease in prepaid expenses and other (1,339,986) (1,339,986) Increase in accounts payable (1,562,974) 4,728 (a) (1,558,246) Increase (decrease) in accrued Interest payable, payroll and related taxes (25,497) (25,497) Increase in income taxes payable 1,586,616 1,586,616 ------------ --------- ------------ TOTAL ADJUSTMENTS 5,035,819 25,307 5,061,126 ------------ --------- ------------ NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 8,187,420 6,166 8,193,586 ------------ --------- ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Proceeds from sale of property and equipment 14,708,863 29,200 (a) 14,738,063 Additions of property and equipment (27,130,397) (12,989) (a) (27,143,386) ------------ --------- ------------ NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (12,421,534) 16,211 (12,405,323) ------------- --------- ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from exercise of stock options and warrants 611,738 611,738 Proceeds from issuance of notes payable 22,040,000 22,040,000 Payments on commercial paper, other short term borrowings and notes payable (6,980,406) (6,980,406) Increase in other assets (213,664) (213,664) ------------ --------- ------------ NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 15,457,668 15,457,668 ------------ --------- ------------ NET DECREASE IN CASH 11,223,554 22,377 11,245,931 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 14,192,568 (484,830) 13,707,738 ------------ --------- ------------ CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 25,416,122 ($462,453) $24,953,669
Remaining Pro Forma Maximum Adjustments Notes Pro Forma -------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net Income (loss) ($97,298) (b) $ 3,035,162 Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depletion, depreciation and amortization: 157,869 (b) 6,652,120 Net earnings from limited partnerships 20,705 (c) Amortization of financing costs 90,640 Loss on disposal of assets 10,632 Minority interest in undistributed earnings of subsidiary 1,742,573 (Increase) decrease in accounts receivable (1,919,152) (Increase) decrease in prepaid expenses and other (1,339,986) Increase in accounts payable (22,301) (b) (1,580,547) Increase (decrease) in accrued Interest payable, payroll and related taxes (25,497) Increase in income taxes payable 1,586,616 --------- ------------ TOTAL ADJUSTMENTS 156,273 5,217,399 --------- ------------ NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 58,975 8,252,561 --------- ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Proceeds from sale of property and equipment 146,900 (b) 14,884,963 Additions of property and equipment (78,963) (b) (27,222,349) --------- ------------ NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES 67,937 (12,337,386) --------- ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from exercise of stock options and warrants 611,738 Proceeds from issuance of notes payable 22,040,000 Payments on commercial paper, other short term borrowings and notes payable (6,980,406) Increase in other assets (213,664) --------- ------------ NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 15,457,668 --------- ------------ NET DECREASE IN CASH 126,912 11,372,843 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 24,260 13,731,998 --------- ------------ CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 151,172 $ 25,104,841
Notes: (a) Combine cash flow of the 1991-1 Partnership. (b) Combine cash flows of the 1989-1 Partnership and 1990-1 Partnership. (c) Eliminate intercompany items. 103 117 PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 1994
Consolidated Minimum Remaining Benton Oil and Pro Forma Minimum Pro Forma Maximum Gas Company Adjustments Notes Pro Forma Adjustments Notes Pro Forma --------------------------------------------------------------------------------- REVENUES: Oil and gas sales $31,942,810 $ 71,407 (a) $32,014,217 $ 519,381 (b) $32,533,598 Gain on exchange rates 1,445,307 1,445,307 1,445,307 Investment earnings 1,180,824 1,938 (a) 1,182,762 5,640 (b) 1,188,402 Partnership fees, reimbursement and other 135,865 (6,792) (c) 129,073 (35,657) (c) 93,416 ----------- --------- ----------- ----------- ----------- 34,704,806 66,553 34,771,359 489,364 35,260,723 ----------- --------- ----------- ----------- ----------- EXPENSES Lease operating costs and production taxes 9,531,264 28,991 (a) 9,560,255 268,121 (b) 9,828,376 Depletion, depreciation and amortization 10,298,112 38,867 (d) 10,336,979 314,945 (d) 10,651,924 General and administrative 5,241,295 20,824 (a) 5,255,327 91,038 (b) 5,310,708 (6,792) (c) (35,657) (c) Interest 3,887,961 3,887,961 3,887,961 Minority interest in net income 2,094,211 2,094,211 2,094,211 ----------- --------- ----------- ----------- ----------- 31,052,843 81,890 31,134,733 638,447 31,773,180 ----------- --------- ----------- ----------- ----------- Income before income taxes and roll-up expenses and payments 3,651,963 (15,337) 3,636,626 (149,083) 3,487,543 Income taxes (697,802) (697,802) (697,802) ----------- --------- ----------- ----------- Income before roll-up expenses and payments 2,954,161 (15,337) 2,938,824 (149,083) 2,789,741 Roll-up expenses and payments 939,940 (e) 939,940 1,761,298 (e) 2,701,238 ----------- --------- ----------- ----------- Income after roll-up expenses and payments $ 2,954,161 $(955,277) $ 1,998,884 $(1,910,381) $ 88,503 =========== ========= =========== =========== =========== Income per common share: Before roll-up expenses and payments $0.12 $0.12 $0.11 After roll-up expenses and payments $0.12 $0.08 $0.00 Weighted average common shares outstanding 24,850,922 24,877,694 25,022,802 =========== =========== =========== Ratio of earnings to fixed charges: Before roll-up expenses and payments 1.92x 1.92x 1.88x After roll-up expenses and payments 1.92x 1.68x 1.20x
Notes: (a) Record the participants' shares of the 1991-1 Partnership. (b) Record the participants' share of the 1989-1 Partnership and 1990-1 Partnership. (c) Eliminate allocated overhead costs from partnerships. (d) Record depletion on oil and gas properties acquired from partnerships. (e) Record roll-up expenses and payments associated with the acquisition of partnership units. Included as roll-up expenses and payments are the value of the warrants issued to the participants (which are being issued as an inducement to the participants to accept the Exchange Offer) and issuance and distribution expenses which will be charged to paid in capital in connection with the issuance of the securities. The participants are given the option of accepting either cash or shares of the Company's common stock in exchange for their partnership units. The pro-forma statements of operations above assume that the participants accept stock in exchange for their partnership units. If all the participants accept cash rather than shares the weighted average number of shares would be 24,850,922 for both the minimum and maximum pro forma statements of operations. 104 118 PRO FORMA CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 1994
Consolidated Minimum Remaining Benton Oil Pro Forma Minimum Pro Forma Maximum and Gas Adjustments Notes Pro Forma Adjustments Notes Pro Forma Company ---------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net Income (loss) $ 2,954,161 ($15,337) (a) $ 2,938,824 $(149,083) (b) $ 2,789,741 Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depletion, depreciation and amortization 10,298,112 38,867 (a) 10,336,979 314,945 (b) 10,651,924 Net earnings from limited partnerships (63,486) 7,520 (c) (55,966) 55,966 (c) Amortization of financing costs 114,311 114,311 114,311 Minority interest in undistributed earnings of subsidiary 2,094,211 2,094,211 2,094,211 (Increase) decrease in accounts receivable (10,384,670) (10,384,670) (10,384,670) (Increase) decrease in prepaid expenses and other (84,905) (2,292) (a) (87,197) (2,265) (b) (89,462) Increase in accounts payable 7,974,335 7,974,335 7,974,335 Increase (decrease) in accrued interest payable, payroll and related taxes 560,720 560,720 560,720 ----------- ---------- ------------ --------- ------------ TOTAL ADJUSTMENTS 10,508,628 44,095 10,552,723 368,646 10,921,369 ----------- ---------- ------------ --------- ------------ NET CASH PROVIDED BY OPERATING ACTIVITIES 13,462,789 28,758 13,491,547 219,563 13,711,110 ----------- ---------- ------------ --------- ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Proceeds from sale of property and equipment 5,803,215 7,699 (a) 5,810,914 7,672 (b) 5,818,586 Additions of property and equipment (38,403,322) (23,323) (a) (38,426,645) (155,822) (b) (38,582,467) Increase in restricted cash (19,250,000) (19,250,000) (19,250,000) Distributions from limited partnerships 502,167 (127,205) (c) 374,962 (598,960) (c) (223,998) Payment for purchase of Benton-Vinccler, net of cash acquired (2,501,973) (2,501,973) (2,501,973) ----------- ---------- ------------ --------- ------------ NET CASH PROVIDED BY USED IN INVESTING ACTIVITIES (53,849,913) (142,829) (53,992,742) (747,110) (54,739,852) ----------- ---------- ------------ --------- ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from exercise of stock options and 83,740 83,740 83,740 warrants Proceeds from issuance of notes payable 21,360,000 21,360,000 21,360,000 Proceeds from commercial paper and other short term borrowings 23,217,775 23,217,775 23,217,775 Increase in other assets (1,683,583) (2,939) (a) (1,686,522) 19,225 (b) (1,667,297) Payments on commercial paper, other short term borrowings and notes payable (24,706,358) (24,706,358) (24,706,358) Payment of stock issuance costs (545,000) (d) (545,000) (545,000) ----------- ---------- ------------ --------- ------------ NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 18,271,574 (547,939) 17,723,635 19,225 17,742,860 ----------- ---------- ------------ --------- ------------ NET DECREASE IN CASH (22,115,550) (662,010) (22,777,560) (508,322) (23,285,882) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 36,308,118 177,180 36,485,298 532,582 37,017,880 ----------- ---------- ------------ --------- ------------ CASH AND CASH EQUIVALENTS AT END OF PERIOD $14,192,568 ($484,830) $ 13,707,738 $ 24,260 $ 13,731,998 =========== ========== ============ ========= ============
Notes: (a) Combine cash flow of the 1991-1 Partnership. (b) Combine cash flows of the 1989-1 Partnership and 1990-1 Partnership. (c) Eliminate intercompany items. (d) Record issuance costs associated with the acquisition of partnership units. 105 119 INFORMATION CONCERNING BENTON BUSINESS Benton Oil and Gas Company is primarily engaged in the development and production of oil and gas properties. The Company's operations are focused on the eastern region of Venezuela, the Gulf Coast region of Louisiana and the West Siberia region of Russia. Benton's business strategy is to seek new reserves in areas of low geologic risk and to exploit underdeveloped existing oil and gas fields. The Company implements the exploitation strategy through the in-house design and interpretation of 3-D seismic surveys and through workovers, recompletions, redrilling and exploration and development drilling. Internationally, the Company seeks projects with significant reserve potential in areas with low geologic risk and known proved reserves where, in certain situations, the Company can add value by employing modern exploration, drilling, completion and production techniques. To reduce risk, control costs, and facilitate local transactions, the Company has formed ventures with local foreign partners. Domestically, the Company integrates 3-D seismic technology with subsurface geologic data from previously drilled wells. This geophysical evaluation enables the Company to discover previously undetected reserves in existing fields. The Company believes that it enjoys a competitive advantage in finding and developing reserves on an economic basis because of its concentration on 3-D seismic technology, the training and qualifications of its in-house technical team and the practical experience and knowledge which this team has acquired over past years. The Company's recognized technical expertise has afforded it access to projects it otherwise would not have enjoyed. In the ordinary course of its business, the Company continues to evaluate acquisition, joint venture and other opportunities that would enable it to further its business strategy. Principal Areas of Activity The following table summarizes the Company's proved reserves at December 31, 1994 by principal geographic area:
PROVED RESERVES ------------------------------------------------------------- CRUDE OIL AND CONDENSATE (MBBL) NATURAL GAS (MMCF) OIL EQUIVALENT (MBOE) Venezuela(1) 60,707 0 60,707 United States 233 16,077 2,913 Russia(2) 17,540 0 17,540 ------ ------ ------ Total 78,480 16,077 81,160 ====== ====== ======
- -------------- (1) All Venezuelan reserves are attributable to an operating service agreement between Benton-Vinccler and Lagoven, S.A. under which all mineral rights are owned by the Government of Venezuela. 106 120 (2) The Company's engineering estimates, which have been prepared by the Company and audited by Huddleston & Co., Inc., independent petroleum engineers, indicate that approximately 18 Bcf of natural gas reserves (net to the Company's interest) will be developed and produced in association with the development and production of the Company's proved undeveloped oil reserves in Russia. The Company expects that, due to current market conditions, it will initially reinject or flare such associated natural gas production and, accordingly, no future net reserves have been assigned to these reserves. Under the joint venture agreement, such reserves are owned by the Company in the same proportion as all other hydrocarbons in the North Gubkinskoye Field, and subsequent changes in conditions could result in the assignment of value to these reserves. VENEZUELA In July 1992, the Company and Vinccler, a Venezuelan construction and engineering company, signed an operating service agreement with Lagoven, S.A. ("Lagoven"), an affiliate of the national oil company, Petroleos de Venezuela S.A. ("PDVSA"), to reactivate and further develop the Uracoa, Bombal and Tucupita Fields (the "Fields"), which are a part of the South Monagas Unit (the "Unit"). Of the 230 foreign companies responding to Venezuela's initial call for indications of interest, the Company was one of three foreign companies ultimately awarded an operating service agreement to reactivate existing fields by PDVSA. The Company was the first U.S. company since 1976 to be granted such an oil field development contract in Venezuela. Under the terms of the operating service agreement, Benton-Vinccler, the Company's 80% owned Venezuelan subsidiary, is a contractor for Lagoven and is responsible for overall operations of the South Monagas Unit, including all necessary investments to reactivate and develop the Fields comprising the Unit. The Venezuelan government maintains full ownership of all hydrocarbons in the Fields. Benton-Vinccler invoices Lagoven each quarter based on Bbls of oil accepted by Lagoven during the quarter, using quarterly adjusted contract service fees per Bbl, and receives its payments from Lagoven in U.S. dollars deposited directly into a U.S. bank account. The operating service agreement provides for Benton-Vinccler to receive an operating fee for each Bbl of crude oil delivered and a capital recovery fee for certain of its capital expenditures, provided that such operating fee and capital recovery fee cannot exceed the maximum total fee per Bbl set forth in the agreement. The operating fee is subject to periodic adjustments to reflect changes in the special energy index of the U.S. Consumer Price Index, and the maximum total fee is subject to periodic adjustments to reflect changes in the average of certain world crude oil prices. During each quarter of 1994, the adjusted maximum total fee was less than the adjusted operating fee, resulting in no capital recovery fee. The Company cannot predict the extent to which future maximum total fee adjustments will provide for a capital recovery fee. The Unit is in the southeastern part of the state of Monagas in eastern Venezuela. The Unit is approximately 51 miles long, eight miles wide and consists of 157,843 acres, of which the Fields comprise approximately one-half. Benton-Vinccler intends to explore the remaining portions of the Unit for possible development activities. At December 31, 1994, Proved Reserves attributable to the Company's Venezuelan operations were 60.7 MMBOE, which represented 75% of the Company's Proved Reserves, all of which were located in the Uracoa and Bombal Fields. Benton-Vinccler has reactivated fifteen previously drilled wells and completed 21 new wells using modern drilling and completion techniques that have not previously been utilized on the Fields. Benton-Vinccler also has installed specialized production facilities commonly used in heavy oil production in the United States but not previously utilized extensively in Venezuela to process crude oil of similar gravity or quality. Benton-Vinccler commenced production during the second quarter of 1993. During 1994, average daily production steadily increased from 3,400 Bbl of oil during the first quarter to 6,700 Bbl in the second quarter, 7,200 Bbl in the third quarter and 10,200 Bbl in the fourth quarter. Currently, 36 wells are producing approximately 14,000 Bbl of oil per day. 107 121 Benton-Vinccler intends to completely develop the Uracoa Field by drilling approximately 90 to 100 wells. It also plans to reactivate and completely develop the Bombal Field by drilling approximately 25-30 wells and to evaluate the potential of the Tucupita Field in 1996 by testing 3 wells. During the first quarter of 1995, Benton-Vinccler shot 150 kilometers of seismic and is currently interpreting the data. Following the initial interpretations of such seismic, Benton-Vinccler may also drill one or more wells to extend the boundaries of the three known fields or to confirm the existence of additional fields previously undetected in the area. Budget and development plans submitted by Benton-Vinccler have been approved by Lagoven in the past and the Company believes that such approvals will be granted in the future. In June 1994, the Venezuelan government, amid economic uncertainties and bank crises, suspended certain constitutional rights and implemented certain exchange and price controls. Currently, exchange and price controls remain in place, with no indication of when such controls will be lifted. To date, neither the current economic uncertainties nor the exchange and price controls have had an adverse effect on the Company's operations in Venezuela. The Company has applied for insurance to cover the risk of currency repatriation and inconvertibility, expropriation and interference with operations for its Venezuelan operations with OPIC, an agency of the United States government. While OPIC has indicated that such insurance is available, there can be no assurance that the Company will be able to obtain this insurance. UNITED STATES Louisiana. The Company has successfully pursued acquisition and joint venture opportunities in the United States which have become more readily available as major oil and gas companies continue to consolidate operations and focus exploration and development activities outside the United States. At December 31, 1994, Proved Reserves of the Company attributable to the United States were 2.9 MMBOE, which represented 4% of the Company's Proved Reserves. Substantially all of the Company's domestic activities are located in the Louisiana Gulf Coast at the West Cote Blanche Bay, Rabbit Island and Belle Isle Fields. The Company, Texaco, Inc. ("Texaco") and Oryx Energy Company ("Oryx") are currently producing from and further developing the fields by using 3-D seismic technology integrated with subsurface geologic data from previously drilled wells. In addition, the Company entered into certain agreements with Tenneco Ventures Corporation ("Tenneco") whereby Tenneco has purchased certain interests in the Company's operations in the three fields and was given the right to participate as a 50% partner in certain of the Company's future activities in the Gulf Coast for the next five years. Several key elements common to the three fields include their discovery and initial development prior to World War II, peak production periods occurring prior to 1960, extremely complex geology, relatively little modern exploration technology being applied, and long-term natural gas sales contracts at prices below $0.30 per Mcf which discouraged any significant drilling and development until the contracts expired in the last few years. The state leases relating to these fields were subject to litigation between Texaco and the State of Louisiana. Although the Company was not a party to this litigation, its interests in the three fields were subject to the litigation. In February 1994, Texaco and the State entered into a Global Settlement Agreement. As a result of this agreement, Texaco committed to certain acreage development and drilling obligations which may affect the Company and certain of its Louisiana properties. The Company believes that the settlement should have no effect on its proved reserves and will have no material adverse effect on the Company. 108 122 West Cote Blanche Bay Field. The West Cote Blanche Bay Field is located on 5,892 acres in a shallow bay in St. Mary Parish, approximately 125 miles southwest of New Orleans with water depths averaging seven to eight feet. The field was discovered in 1938 by Texaco, which continues to operate the field. The Company believes that, at approximately 3.5 miles long and two miles wide, the West Cote Blanche Bay Field contains one of the largest salt domes in the Gulf Coast. More than 300 separate oil and gas reservoirs have been identified by Texaco and the Company from a total of approximately 680 wellbores in 180 different sandstone formations, at depths from 1,700 to 13,000 feet. At December 31, 1994, the field had cumulatively produced over 181 MMBbl of oil and 225 Bcf of natural gas. Since the Company's first acquisition of an interest in the West Cote Blanche Bay Field, it has worked with Texaco in the technical evaluation of the field. Until late 1994, the prospect evaluations covered all depths and included the drilling wells and a substantial number of recompletions and replacement wells in oil reservoirs at depths of 2,000 to 10,500 feet. As a result of ongoing evaluation, in late 1994 the Company decided to focus almost exclusively on exploitation of gas and oil reservoirs at depths below 10,000 feet, utilizing the results of the 3-D seismic interpretations. To mitigate the risk of concentrating on deeper, more expensive wells, the Company sold approximately 25% of its working interest to Tenneco. Also, in March 1995, the Company and its affiliates and Tenneco sold their interests in the shallower oil depths (above approximately 10,575 feet) to WRT Energy Corporation, another working interest owner in the field. Rabbit Island Field. Rabbit Island is located in state waters in Iberia and St. Mary Parishes, approximately 95 miles southwest of New Orleans. The dome was discovered in 1939 by Texaco which continues to operate the field. Compared to West Cote Blanche Bay, on whose 5,892 acres more than 800 wells have been drilled, just over 200 wells have been drilled on the 27,909 acres of the Rabbit Island Field. Cumulative production through December 31, 1994 was 48 MMBbl of oil and 1.2 Tcf of gas from 51 productive zones. In 1992, the Company signed an agreement with Texaco to fund and conduct a 3-D seismic program covering approximately 105 square miles over the Rabbit Island project area. The estimated cost to the Company of this program is approximately $6.0 million, substantially all of which has been expended. The seismic survey has been shot, processed and is currently being interpreted. Pursuant to the agreement, the Company may drill five wells over a period of up to five years. As identified below, the first well has been drilled. Assuming the remaining four wells are drilled in accordance with the terms set forth in the agreement, the Company will earn a 50% working interest in the entire field (other than among other things, wells previously drilled by Texaco). The first well in the drilling program was successfully completed in January 1995 and is currently producing approximately 9.5 MMcf of natural gas per day. The Company expects to drill up to four additional wells during 1995 at Rabbit Island at a cost of up to $4 million. Certain of the Company's rights and 50% of its interest in the Field were sold to Tenneco in July 1993. In May 1995, the Company and Tenneco signed an agreement in principle with Texaco to expand the acreage under the Rabbit Island Field agreement by 10,452 acres in exchange for an increase in the number of earning wells to be drilled by the Company from 5 to 8 wells. Belle Isle Field. The Belle Isle Field is located on the shore of the Atchafalaya Bay, approximately 75 miles southwest of New Orleans, in St. Mary Parish. The field was discovered in 1941 and developed by Sun Oil Company. Currently, 12,000 acres on the north portion of the field are operated by Oryx, and 6,400 acres on the south portion of the field are operated by Apache Corporation 109 123 (previously operated by Texaco). As of December 31, 1994, the Belle Isle Field had cumulatively produced over 50 MMBbl of oil and 1 Tcf of natural gas. In 1990, the Company reached an agreement with Oryx to shoot a 3-D seismic survey over its portion of the field. Pursuant to the agreement, upon completing the survey and processing the seismic data, Oryx granted the Company the right to participate in the drilling of wells on Oryx's portion of the field and the Company will have a 33% working interest in any well so drilled from the top of the deep sands known as the "Rob L Sands" (at a depth of 12,500 feet) and below. Under the agreement, up to two exploratory wells and two development wells may be drilled in any calendar year. In the event that Oryx decides to solicit the participation of a third party in certain drilling operations above the Rob L Sands, Oryx has granted the Company a right of first refusal to participate in such drilling and receive a 33% working interest in the resulting wells. In 1991, the Company reached an agreement with Texaco to evaluate 5,500 acres on the southern portion of the field by extending the 3-D seismic survey. Pursuant to this agreement, upon the Company's completion of the seismic survey and its drilling of an initial test well in accordance with the terms set forth in the agreement, Texaco assigned to the Company a 50% working interest in its entire 6,400 acre portion of the Belle Isle Field (other than, among other things, existing wells previously drilled by Texaco). In 1992, the Company completed a 55.75 square mile 3-D seismic survey over the Belle Isle Field, thereby satisfying the survey obligations that are prerequisites for earning working interests in the Texaco portion of the Field and the Oryx wells. The survey was reprocessed in 1993 and is being evaluated on an ongoing basis. In 1993, the Company satisfied the drilling requirements under the agreement with Texaco, thereby earning its 50% working interest on the Texaco portion of the field. In October 1994, the Company completed the Belle Isle State Lease 340 No. 1 well. This well is currently producing at rates of approximately 6 MMcf of natural gas per day. The Company has until September 1, 1997 to exercise its right to participate in any future Oryx wells. If the Company has participated in the drilling of a producing well by that time, the Company's right to participate in future wells will continue. Certain of the Company's rights and 50% of its interest in the Field were sold to Tenneco in July 1993. In January 1995 Texaco sold its interest in Belle Isle to Apache Corporation. The Company is unable at this time to assess the impact on the development of the field as a result of this sale. Tenneco Agreements. In June 1993, the Company entered into an agreement with Tenneco which provided for payments to the Company of approximately $6.7 million in exchange for a 50% interest in the Company's operations at the Rabbit Island and Belle Isle Fields. The agreement also provided Tenneco with a five year option to participate on a promoted basis as a 50% partner in any future ventures that the Company acquired in the Gulf Coast area, except for the West Cote Blanche Bay Field. The Company also has granted an option in favor of Tenneco to purchase, at a market price, all of the Company's gas produced from the Gulf Coast. Tenneco has exercised its option to purchase the Company's share of natural gas production from all three fields. In November 1994, the Company sold to Tenneco a 10.8% working interest (24.9% of the Company's 43.3% working interest) in the West Cote Blanche Bay Field for approximately $5.8 million and future consideration of up to $3.7 million. 110 124 WRT Agreement. In March 1995, the Company and its affiliates and Tenneco sold to WRT Energy Corporation a 43.75% working interest in the shallower depths (above approximately 10,575 feet) in the West Cote Blanche Bay Field for an aggregate purchase price of $20 million. Of this aggregate purchase price, the Company received $14.9 million. OTHER PROPERTIES At December 31, 1994, the Company had proved reserves of 180 MBOE and 6 MBOE in the Umbrella Point Field in Texas and certain fields in Louisiana and Mississippi, respectively. In July 1995, the Company sold its interest in the Umbrella Point Field. Actual exploration and development activities in the United States could ultimately vary from those currently projected by the Company, depending, among other factors, on the availability of drilling rigs, the availability of financing, the success of the activities and the continued concurrence of working interest partners as to the timing and extent of such activities. RUSSIA In December 1991, the joint venture agreement forming GEOILBENT among the Company (34% interest) and two Russian partners, Purneftegasgeologia and Purneftegas (each having a 33% interest), was registered with the Ministry of Finance of the USSR. The Company's partners are the official exploration and production bodies which have been discovering and operating fields in the region covered by the joint venture for many years, and which have access to pipelines, railroads and other vital infrastructure. GEOILBENT develops, produces and markets oil and condensate from the North Gubkinskoye Field in the West Siberia region of Russia, approximately 2,000 miles northeast of Moscow. The field, which covers an area approximately 15 miles long and 4 miles wide, has been delineated with over 60 exploratory wells (which tested 26 zones) and is surrounded by large proven fields. Before commencement of GEOILBENT's operations, North Gubkinskoye was one of the largest non-producing fields in the region. At December 31, 1994, the Proved Reserves attributable to the North Gubkinskoye Field were 17.5 MMBOE, which represented 22% of the Company's Proved Reserves. During the third quarter of 1992, GEOILBENT commenced initial operations which included the construction of a 37 mile oil pipeline and installation of temporary production facilities. Completed in April 1993, with a design capacity of 75,000 Bbl of oil per day, the pipeline transports oil from the North Gubkinskoye Field south to the main Russian oil pipeline network. The venture has been exporting oil since the fourth quarter of 1993. GEOILBENT identified nine previously existing delineation wells that were capable of being reentered and placed these on production. These delineation wells were not originally intended by Purneftegasgeologia to be commercial producers. Therefore, completion procedures for optimum production were not employed. The Company believes that production rates from future wells using western completion technologies will be significantly greater. GEOILBENT has commenced drilling a series of development wells in the North Gubkinskoye Field. Three Russian drilling rigs are drilling development wells offsetting previously drilled exploration wells. GEOILBENT is utilizing Russian equipment and personnel whenever feasible. Supervision is provided jointly by an American and Russian management team. Russian equipment, including Russian rigs, are being upgraded by certain western technology and materials including shaker screens, monitoring equipment and drilling and completion fluids. Such measures, along with paying for Russian 111 125 equipment and personnel in rubles, allows GEOILBENT to minimize its investment and operating expenses. Russia has established an export tariff on all oil exported from Russia which, as imposed, has the effect of significantly reducing the cash flows and potential profits to the Company. However, Russia has issued or drafted various decrees and legislation under which certain oil and gas joint ventures, including GEOILBENT, are eligible for relief from such oil export tariff until such time as they have recovered their capital investment. GEOILBENT has received a waiver from the export tariff for 1995, and expects to apply for renewal of such waiver for 1996 and 1997. However, there can be no assurance that any such renewals can be obtained. Furthermore, after the waiver for 1995 was issued to GEOILBENT, a new Russian law came into force which repeals all tax and customs benefits previously granted to participants in foreign economic activities, except for those granted pursuant to certain federal laws, including the law "On Customs Tariff". While it is not clear whether the repeal applies to GEOILBENT's waiver for 1995, GEOILBENT believes that its waiver should be regarded as granted pursuant to the law "On Customs Tariff". The legislative and regulatory environment in Russia continues to be subject to frequent change and uncertainty. The Company believes that the joint venture partners will continually assess regulatory and economic conditions affecting the Russian operations, make investment decisions accordingly and make adjustments to the amount and/or timing of contribution requirements as appropriate and permitted under the law. In addition, the license which grants GEOILBENT the right to develop the North Gubkinskoye Field sets forth required levels of oil and gas production through the year 2000 and requires GEOILBENT to make additional royalty payments in the event that such production levels are not achieved during any three year period. As part of its plan to fund the development of the North Gubkinskoye Field, the Company has retained Morgan Guaranty to act as financial advisor to the Company and GEOILBENT in obtaining project debt financing. Morgan Guaranty has assisted the Company in approaching multilateral financial institutions and export finance agencies. Any retainer and percentage success fees paid to Morgan Guaranty will be credited as the Company's capital contribution. There can be no assurance that such financing will become available on terms acceptable to the Company or GEOILBENT. GEOILBENT has been successful, on a limited basis, in obtaining working capital funding from certain institutions in Moscow. NAFTA Moscow, the exporter which handles GEOILBENT's oil sales, made a short-term production payment advance during the quarter ended March 331, 1995 of $3.0 million. International Moscow Bank, which is majority owned by non-Russian European banks, has made two short-term loans to GEOILBENT totaling $6 million. The bank loans were guaranteed by the Company, which is providing certain portions of the cash for such debt service during 1995 to complete its charter fund obligation. RECENT EVENTS On June 30, 1995, Benton issued $20 million in 13% senior unsecured notes due June 30, 2007. Interest is payable semi-annually on June 30 and December 30, beginning December 30, 1995. Annual principal payments of $4 million are due on June 30 of each year, beginning June 30, 2003. The proceeds from the note offering will be used primarily for the continued development of Benton's Venezuelan project and for working capital purposes. 112 126 INFORMATION CONCERNING 1989-1 PARTNERSHIP GENERAL Objectives. The 1989-1 Partnership is a limited partnership which was formed to invest in oil and natural gas activities by acquiring proven producing properties that have additional development potential, recompleting previously drilled wells and drilling new wells. The primary financial objective of the 1989-1 Partnership is to make quarterly distributions to its Investors from available cash flow while replacing and expanding its reserves on a cost-effective basis. The Partnership made regular distributions to partners through August 1994, but has not made subsequent cash distributions due to declining oil and gas production combined with higher lease operating expenses and production taxes, continued capital expenditures and lower natural gas prices. Management. Benton Oil and Gas Company and a wholly-owned subsidiary, Benton Oil and Gas Company of Louisiana, are the Co-Managing General Partners. Benton makes all decisions regarding the business and operations of the 1989-1 Partnership, including production, development and other activities, and any sale of properties and the acquisition of additional properties. The Managing General Partners receive 1.0% of the oil and gas revenues on proven producing wells, 25.75% of the oil and gas revenues on recompleted wells and 35.65% of the oil and gas revenues on new wells. In addition, Benton and its subsidiary own 2.8182 Units in the 1989-1 Partnership. The Co-Managing General Partners do not receive any management fees or other fees from the 1989-1 Partnership. The 1989-1 Partnership pays the Co-Managing General Partners for lease operating expenses, well costs and general and administrative expenses incurred on behalf of the Partnership. Organization. Benton, as managing general partner and sponsor of the 1989-1 Partnership, sold an aggregate of $1,409,091 in 1989-1 Units. Of the net proceeds raised of $1,260,214 which were available for partnership activities, $815,526 was used in oil and gas activities of the Partnerships, as contemplated in the private placement memorandum for the offering, and the remaining proceeds were distributed to the participants. DESCRIPTION OF OIL AND GAS PROPERTIES The following table sets forth certain information as of January 1, 1995 related to the 1989-1 Partnership's interest in its oil and gas properties. 113 127
Proved Reserves at January 1, 1995 1994 Production ---------------------------------- --------------- Present Value of Estimated Future Net Cash Flows Discounted Property Oil (Bbls) Gas (Mcf) at 10% (Bbls) (Mcf) - -------- ---------- --------- --------------------- ------ ------ Umbrella Point Field 24,130 183,181 $325,540 5,475 29,871 East Cameron Block 229 0 0 0 0 8,173 -------- -------- -------- ------ ------ TOTAL 24,130 183,181 $325,540 5,475 38,044 ======== ======== ======== ====== ======
Additional information regarding these fields is set forth below. Umbrella Point Field. The Umbrella Point Field is located in State Tracts 74 and 87, which consist of 1,280 acres in the northern end of Upper Galveston Bay, in Texas state waters. Sun Oil Co. discovered the field in May 1957. Oil and gas production is from fifteen stacked Frio sands ranging in depth from the F-1 sand at 7,612 feet to the F-15 sand at 8,994 feet. The 1989-1 Partnership has a 4.93% working interest in the Umbrella Point Field with 10 wells producing, as of September 1995, at combined average daily rates of 312 Bbl of oil and 3.1 MMcf of natural gas. East Cameron Block 229. East Cameron Block 229 is located on 5,000 acres in federal waters eighty miles off the coast of Grand Chenier, Louisiana in the Gulf of Mexico. The 1989-1 Partnership has a 6.57% working interest in East Cameron Block 229. Cumulative expenditures by the 1989-1 Partnership on East Cameron Block 229 are $144,893. As of January 1, 1995, the 1989-1 Partnership's interest in East Cameron Block 229 was determined to be uneconomic to produce. 114 128 SELECTED HISTORICAL FINANCIAL DATA The following selected financial data for the 1989-1 Partnership as of and for each of the years in the five year period ended December 31, 1994 are derived from the 1989-1 Partnership's audited financial statements. The selected consolidated financial data for the six months ended June 30, 1994 and 1995 are derived from the 1989-1 Partnership's unaudited financial statements. In the opinion of management, such unaudited financial statements contain all adjustments (consisting of only normal recurring accruals) necessary for a fair presentation of the financial condition and results of operations as of and for the periods presented. Operating results for the six months ended June 30, 1995 are not necessarily indicative of the results that may be expected for the entire fiscal year ending December 31, 1995. The selected financial data below should be read in conjunction with the 1989-1 Partnership's financial statements and related notes thereto and Management's Discussion and Analysis of Financial Condition and Results of Operations included elsewhere in this Prospectus.
Six Months Ended Years Ended December 31, June 30, ----------------------------------------------------------------- ----------------------- 1990 1991 1992 1993 1994 1994 1995 ---- ---- ---- ---- ---- ---- ---- Operating Data Total revenue $ 212,781 $ 217,023 $ 225,460 $ 203,380 $ 160,413 $ 87,880 $ 77,765 Lease operating costs and production taxes 60,471 85,894 73,309 76,855 79,479 33,929 31,001 Exploration costs 1,627 1,891 789 789 Depletion, impairment and amortization 46,224 74,122 111,050 72,453 77,895 42,831 90,155 General and administrative 31,086 17,428 32,110 38,432 33,654 27,032 31,746 --------- --------- --------- --------- --------- --------- --------- Net income (loss) $ 75,000 $ 39,579 $ 7,364 $ 13,749 ($ 31,404) ($ 16,701) ($ 75,137) ========= ========= ========= ========= ========= ========= ========= Net decrease in cash and cash equivalents ($100,529) ($ 82,547) ($241,781) ($127,320) ($106,355) ($ 10,024) ($ 684) Net cash provided by operating activities 187,669 111,201 117,414 86,202 46,491 26,130 15,018 Distributions 140,064 211,364 281,818 169,936 135,615 30,436 -- Per Unit Operating Data(1) Net income (loss) 192 61 (70) (16) (149) (86) (300) Distributions of earnings 192 61 -- -- -- -- -- Distributions representing a return of capital 308 686 1,003 600 162 108 --
December 31, June 30, ------------------------------------------------------------------ ------------------------ 1990 1991 1992 1993 1994 1994 1995 ---- ---- ---- ---- ---- ---- ---- Balance Sheet Data Cash and cash equivalents $ 564,404 $ 481,857 $ 240,076 $ 112,756 $ 6,401 $ 102,732 $ 5,717 Total assets at book value 1,177,716 1,016,060 727,977 571,790 407,052 524,653 329,634 Total assets at the value assigned for purposes of 370,098 roll-up transaction Total liabilities 3,500 13,629 -- -- 2,281 -- -- General and limited partners' equity: Managing General Partner 34,706 54,437 79,213 94,780 14,658 101,700 23,147 Participants 1,139,510 947,994 648,764 477,010 390,113 422,953 306,487 ---------- ---------- ---------- ---------- ---------- ---------- ---------- $1,174,216 $1,002,431 $ 727,977 $ 571,790 $ 404,771 $ 524,653 $ 329,634 ========== ========== ========== ========== ========== ========== ========== Per Unit Balance Sheet Data(1) Book value $ 4,084 $ 3,398 $ 2,325 $ 1,710 $ 1,398 $ 1,516 $ 1,099 Value assigned for purpose of the roll-up transaction 1,312
115 129 (1) Per unit data is based on indicated amounts allocable to limited partners divided by 279 limited partner units outstanding. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS General Benton Oil & Gas Combination Partnership 1989-1, L.P. was formed July 31, 1989 for the purpose of investing in oil and natural gas activities by acquiring proven producing properties, recompleting previously drilled wells and developing and drilling oil and gas wells in the state waters of Texas and off-shore Louisiana. Benton Oil and Gas Company and a wholly owned subsidiary are the Co-Managing General Partners, and as such, conduct, direct and exercise full control over all activities of the Partnership. Oil and gas properties are accounted for using the successful efforts methods. Under this method, costs of drilling exploratory wells are initially capitalized pending determination of whether the well can produce proved reserves. All costs relating to the non-productive exploratory wells are expensed. Costs relating to productive exploratory wells and all development wells are capitalized and depleted on a unit-of-production basis over the life of the remaining proved developed reserves. Delay rentals and geological and geophysical costs are expensed as incurred. Under the terms of the 1989-1 Partnership Agreement, the participants pay 99% of the lease acquisition, geophysical and seismic costs, well costs, general and administrative expenses, and organization and offering expenses, including commissions, while the Co-Managing General Partners pay 1% of such costs. Revenues, production taxes and lease operating expenses on proven producing wells are allocated 99% to the participants and 1% to the Co-Managing General Partners. Revenues, production taxes and lease operating expenses on recompleted wells are allocated 74.25% to the participants and 25.75% to the Co-Managing General Partners. On new wells drilled, revenues, production taxes and lease operating expenses are allocated 64.35% to the participants and 35.65% to the Co-Managing General Partners. Results of Operations Six months Ended June 30, 1995 and 1994. For the six months ended June 30, 1995, the 1989-1 Partnership had revenues of $77,765 compared to $87,880 for the same period in 1994, representing a decrease of 12%. This decrease was primarily due to reduced oil sales quantities and lower gas prices related to the Umbrella Point Field which were partially offset by increased gas sales quantities in the field. The production for the six months ended June 30, 1995 was 2,303 Bbl of crude oil and condensate and 23,552 Mcf of natural gas compared to production of 3,038 Bbl of crude oil and condensate and 18,636 Mcf of natural gas for the comparable period in 1994. For the six months ended June 30, 1995, crude oil and natural gas prices averaged $17.34 per Bbl and $1.60 per Mcf, respectively, compared to $14.69 per Bbl and $2.26 per Mcf, respectively, during the comparable period. Lease operating costs and production taxes for the period ended June 30, 1995 were $31,001, a decrease of 9% from $33,929 in the comparable period. The decrease was primarily due to legal fees incurred in 1994 related to damage to production facilities. Depletion, impairment and amortization expenses were $90,155 for the period ended June 30, 1995, an increase of 110% from $42,831 for the comparable period primarily due to the impairment of the Umbrella Point Field as a result of the proposed sale of the property. General and administrative expenses were $31,746 for the period ended 116 130 June 30, 1995, an increase of 17% from $27,032 for the comparable period primarily due to increased audit and tax preparation fees and costs related to the review of the Partnership's reserves by an independent petroleum engineering firm. For the reasons discussed above, the net loss for the six months ended June 30, 1995 was $75,137, compared to a loss of $16,701 for the period ended June 30, 1994. Years Ended December 31, 1994 and 1993. For the year ended December 31, 1994, the 1989-1 Partnership had total revenues of $160,413 compared to $203,380 for the same period in 1993, representing a decrease of 21%, primarily due to reduced gas sales quantities and lower oil and gas prices. The production for the year ended December 31, 1994 was 5,475 Bbl of crude oil and condensate and 38,044 Mcf of natural gas compared to production of 5,773 Bbl of crude oil and condensate and 47,433 Mcf of natural gas for the comparable period in 1993. For the year ended December 31, 1994, crude oil and natural gas prices averaged $15.47 per Bbl and $1.95 per Mcf, respectively, compared to $17.09 per Bbl and $2.12 per Mcf, respectively, during the comparable period. Lease operating costs and production taxes for the year ended December 31, 1994 were $79,479, an increase of 3% from $76,855 in the comparable period. A significant portion of the Partnership's lease operating expenses are associated with fixed rather than variable costs such as contract pumping services and equipment rentals. While certain variable costs decreased as oil and gas sales quantities decreased during the period, other non-variable costs increased resulting in an aggregate increase of $2,624 or 3% during 1994 compared to 1993. Depletion, impairment and amortization expenses were $77,895 for the year ended December 31, 1994, an increase of 8% from $72,453 for the comparable period primarily due to downward revisions to oil and gas reserves in the Umbrella Point field during 1994. General and administrative expenses were $33,654 for the year ended December 31, 1994, a decrease of 12% from $38,432 for the comparable period primarily due to reduced third party administrative support costs. For the reasons discussed above, the net loss for the year ended December 31, 1994 was $31,404, compared to net income of $13,749 for the year ended December 31, 1993. Years Ended December 31, 1993 and 1992. For the year ended December 31, 1993, the 1989-1 Partnership had total revenues of $203,380 compared to $225,460 for the same period in 1992, representing a decrease of 10%. The production for the year ended December 31, 1993 was 5,773 Bbl of crude oil and condensate and 47,433 Mcf of natural gas compared to production of 6,947 Bbl of crude oil and condensate and 47,323 Mcf of natural gas for the comparable period in 1992. For the year ended December 31, 1993, crude oil and natural gas prices averaged $17.09 per Bbl and $2.12 per Mcf, respectively, compared to $18.72 per Bbl and $1.79 per Mcf, respectively, during the comparable period. Depletion, impairment and amortization expenses were $72,453 for the year ended December 31, 1993, compared to $111,050 for the same period in 1992, representing a decrease of 35%. This decrease was primarily due to the complete depletion of the East Cameron Field in 1992 and was partially offset by increased depletion of the Umbrella Point Field. General and administrative expenses for the year ended December 31, 1993 were $38,432 an increase of 20% from $32,110 in the comparable period primarily due to increased professional fees. For the reasons discussed above, the net income for the year ended December 31, 1993 was $13,749, compared to net income of $7,364 for the year ended December 31, 1992. 117 131 Capital Resources and Liquidity The oil and gas industry is a highly capital intensive business. The Partnership requires capital principally to fund the following costs: (i) drilling and completion costs of wells and the cost of production and transportation facilities; (ii) purchase of leases and other interests in oil and gas producing properties; and (iii) general and administrative expenses. The amount of available capital significantly affects the scope of the Partnership's operations. In June 1995, the Partnership entered into an agreement to sell its principal remaining oil and gas properties (see Note 4 to the 1989-1 Partnership Financial Statements). Assuming the sale is completed, the Partnership will have no further oil and gas activities. If the sale is not completed, the properties have a remaining economic life of approximately 3.5 years. Effects of Inflation and Changing Prices The 1989-1 Partnership's results of operations and cash flow are affected by changing oil and gas prices. If the price of oil and gas increases, there could be a corresponding increase in the cost to the Partnership for drilling and related services as well as an increase in revenues. To date, inflation has had a minimal effect on the Partnership. INFORMATION CONCERNING 1990-1 PARTNERSHIP GENERAL Objectives. The 1990-1 Partnership is a limited partnership which was formed to invest in oil and natural gas activities by primarily acquiring proven producing properties that have additional development potential, recompleting previously drilled wells and drilling new wells. The primary financial objective of the 1990-1 Partnership is to make quarterly distributions to its Investors from available cash flow while replacing and expanding its reserves on a cost-effective basis. The Partnership made regular cash distributions to partners through August 1994, but has not made subsequent cash distributions due to declining oil and gas production combined with higher lease operating costs and production taxes, continued capital expenditures and lower natural gas prices. Management. Benton Oil and Gas Company and a wholly-owned subsidiary, Benton Oil and Gas Company of Louisiana, are the Co-Managing General Partners. Benton makes all decisions regarding the business and operations of the 1990-1 Partnership, including production, development and other activities, and any sale of properties and the acquisition of additional properties. The Managing General Partners receive 25.5236% of the oil and gas revenues from the 1990-1 Partnership. In addition, Benton and its subsidiary own 14.192 Units in the 1990-1 Partnership. The Co-Managing General Partners do not receive any management fees or other fees from the 1990-1 Partnership. The 1990-1 Partnership pays the Co-Managing General Partners for lease operating expenses, well costs and general and administrative expenses incurred on behalf of the Partnership. Organization. Benton, as managing general partner and sponsor of the 1990-1 Partnership, sold an aggregate of $7,088,000 of 1990-1 Units. Of the net proceeds raised of $6,070,551 which were available for partnership activities, $5,007,909 was used in oil and gas activities of the Partnership, as 118 132 contemplated in the private placement memorandum for the offering, and the remaining proceeds were distributed to the participants. DESCRIPTION OF OIL AND GAS PROPERTIES The following table sets forth certain information as of January 1, 1995 related to the 1990-1 Partnership's interest in its oil and gas properties.
Proved Reserves at January 1, 1995 1994 Production ---------------------------------- --------------- Present Value of Estimated Future Net Cash Flows Discounted Property Oil (Bbls) Gas (Mcf) at 10% (Bbls) (Mcf) - -------- ---------- --------- --------------------- ------ ------- Umbrella Point Field 69,488 527,433 $ 937,429 15,709 85,974 West Cote Blanche Bay Field 1,322 132,467 119,694 1,470 13,391 East Cameron Block 229 0 0 0 0 28,414 ------ ------- ---------- ------ ------- TOTAL 70,810 659,900 $1,057,123 17,179 127,779 ====== ======= ========== ====== =======
Additional information regarding these fields is set forth below. Umbrella Point Field. The Umbrella Point Field is located in State Tracts 74 and 87, which consist of 1,280 acres in the northern end of Upper Galveston Bay, in Texas state waters. Sun Oil Co. discovered the field in May, 1957. Oil and gas production is from fifteen stacked Frio sands ranging in depth from the F-1 sand at 7,612 feet to the F-15 sand at 8,994 feet. The 1990-1 Partnership originally acquired a 17.02% working interest in the Umbrella Point Field in 1990 for $1,204,222. However, in 1991, it sold a 2.83% working interest to the 1991-1 Partnership for $373,205 prior to closing adjustments. The 1990-1 Partnership has a 14.19% working interest in the Umbrella Point Field with 10 wells producing, as of September 1995, at combined average daily rates of 312 Bbl of oil and 3.1 MMcf of natural gas. West Cote Blanche Bay Field. The West Cote Blanche Bay Field is located on 5,892 acres in a shallow bay in St. Mary Parish, Louisiana, approximately 125 miles southwest of New Orleans with water depths averaging seven to eight feet. The field was discovered in 1938 by Texaco, which continues to operate the field. More than 300 separate oil and gas reservoirs have been identified by Texaco and the Company from a total of approximately 680 wellbores in 180 different sandstone formations, at depths from 1,700 to 13,000 feet. The 1990-1 Partnership originally purchased a 0.38% working interest in the West Cote Blanche Bay Field in 1990. However, in 1991, it sold a 0.06% working interest to the 1991-1 Partnership for $94,352 prior to closing adjustments. In March 1995, the Partnership sold a 0.32% working interest in certain depths (above approximately 10,575 feet), in the West Cote Blanche Bay Field for a purchase price of $146,900. The 1990-1 Partnership has a 0.32% working interest in three wells below the depth of approximately 10,575 feet. These wells are currently producing at a combined rate of approximately 21 MMcf of natural gas per day. East Cameron Block 229. East Cameron Block 229 is located on 5,000 acres in federal waters eighty miles off the coast of Grand Chenier, Louisiana in the Gulf of Mexico. The 1990-1 Partnership has a 22.85% working interest in East Cameron Block 229. Cumulative expenditures by the 1990-1 Partnership 119 133 on East Cameron Block 229 are $943,012. As of January 1, 1995, the 1990-1 Partnership's interest in East Cameron Block 229 was determined to be uneconomic. The following is a description of properties in which the 1990-1 Partnership owned an interest, but subsequently sold or abandoned. Round Mountain Field. The Round Mountain Field is located on the southeast flank of the San Joaquin Basin of Kern County, California, approximately 10 miles northeast of Bakersfield. The field was discovered in 1927 and average drilling depths range from 1,400 feet to 2,100 feet. The 1990-1 Partnership purchased an 8.40% working interest in 32 producing wells in the Round Mountain Field. However, due to the inability to significantly increase production and after $787,595 in cumulative expenditures, Benton determined it was in the best interest of the Partnership to sell its working interest in Round Mountain Field. In September 1992, the 1990-1 Partnership sold its interest in Round Mountain to Nahama & Weagant Energy Company for $19,386. Hopper Canyon 12-1 Well. The Hopper Canyon 12-1 well is located in Ventura County, California. This well was successfully drilled and completed in the fourth quarter of 1991. The well produced at rates of approximately 24 Bbl of oil and 45 MMcf of gas per day. However, Benton determined it was in the best interest of the Partnership to sell its 38.0% working interest in the well. In April 1992, the 1990-1 Partnership sold its interest in the 12-1 well to Fortune Petroleum. Proceeds from the sale were $17,881, consisting of $3,461 in cash and stock of Fortune Petroleum with a fair market value of $14,420 (the stock was subsequently sold in November 1994 with the 1990-1 Partnership receiving $7,672). In addition, the 1990-1 Partnership retained a production payment of $8,845 which was paid from monthly net income from the 12-1 well. The 1990-1 Partnership's cumulative expenditures on the Hopper Canyon 12-1 well were $211,134. Prather 43-1 Well. This prospect was located in Acadia Parish, Louisiana. This well was drilled to a total depth of approximately 11,000 feet. It was determined to be uneconomical and was plugged and abandoned. The 1990-1 Partnership had a 12.5% working interest in this well with total expenditures of $96,225. North Fisher Reef #13-16A Well. This prospect was located in Trinity Bay, Chambers County, Texas. This offshore oil and gas prospect was drilled to a total depth of 11,000 feet in February 1991. This prospect had multiple objectives, however, all objectives were determined to be non-commercial and the well was plugged and abandoned. The 1990-1 Partnership had a 44.67% working interest in this well with cumulative expenditures of $134,715. SELECTED HISTORICAL FINANCIAL DATA The following selected financial data for the 1990-1 Partnership, as of and for each of the years in the five year period ended December 31, 1994 are derived from the 1990-1 Partnership's audited financial statements. The selected consolidated financial data for the six months ended June 30, 1994 and 1995 are derived from the 1990-1 Partnership's unaudited financial statements. In the opinion of management, such unaudited financial statements contain all adjustments (consisting of only normal recurring accruals) necessary for a fair presentation of the financial condition and results of operations as of and for the periods presented. Operating results for the six months ended June 30, 1995 are not necessarily indicative of the results that may be expected for the entire fiscal year ending December 31, 1995. The selected financial data below should be read in conjunction with the 1990-1 Partnership's 120 134 financial statements and related notes thereto and Management's Discussion and Analysis of Financial Condition and Results of Operations included elsewhere in this Prospectus. 121 135
Six Months Ended Inception to Years Ended December 31, June 30, December 31 ---------------------------------------------------- ---------------------- 1990 1991 1992 1993 1994 1994 1995 ---- ---- ---- ---- ---- ---- ---- Operating Data Total revenue $ 477,806 $ 1,104,681 $ 770,517 $ 645,459 $ 524,786 $ 280,792 $ 235,273 Lease operating costs and production taxes 155,247 440,434 285,840 254,903 263,957 112,323 100,135 Exploration costs 29,089 887,842 8,952 9,570 6,607 5,331 1,812 Loss on sale of oil and gas properties 57,586 1,328 Depletion, impairment and amortization 142,600 425,583 1,560,665 189,309 224,635 113,834 153,641 General and administrative 36,753 176,317 69,510 99,967 78,547 58,782 67,323 ---------- ----------- ----------- --------- --------- --------- --------- Net income (loss) $ 114,117 ($ 825,495) ($1,212,036) $ 91,710 ($ 48,960) ($ 9,478) ($ 88,966) ========== =========== =========== ========= ========= ========= ========= Net increase (decrease) in cash and cash equivalents $3,057,412 ($1,780,352) ($ 399,559) ($457,675) ($401,967) $ 9,583 $ 127,596 Net cash provided by operating activities 124,336 356,853 407,453 290,032 173,410 104,807 66,003 Distributions 706,351 1,071,312 604,582 463,345 64,633 -- Per Unit Operating Data (1) Net income (loss) 24 (703) (935) 9 (68) (27) (76) Distributions of earnings -- -- -- -- -- -- -- Distributions representing a return of capital -- 500 762 400 66 44 --
December 31, March 31, -------------------------------------------------------------- ----------------------- 1990 1991 1992 1993 1994 1994 1995 ---- ---- ---- ---- ---- ---- ---- Balance Sheet Data Cash and cash equivalents $3,057,412 $1,277,060 $ 877,501 $ 419,826 $ 17,859 $ 429,409 $ 145,455 Total assets at book value 6,719,035 4,713,665 2,380,317 1,867,445 1,355,140 1,793,334 1,266,174 Total assets at the value assigned for purposes of 2,990,728 roll-up transaction Total liabilities 523,524 50,000 -- -- -- -- -- General and limited partners' equity: Managing General Partner 137,695 291,366 386,815 436,921 111,441 462,867 126,832 Participants 6,053,875 4,363,866 1,978,692 1,429,384 1,240,417 1,329,209 1,134,106 Special Limited Partners 3,941 8,433 14,810 1,140 3,282 1,258 5,236 ---------- ---------- ---------- ---------- ---------- ---------- ---------- $6,195,511 $4,663,665 $2,380,317 $1,867,445 $1,355,140 $1,793,334 $1,266,174 ========== ========== ========== ========== ========== ========== ========== Per Unit Balance Sheet Data(1) Book value $ 4,309 $ 3,106 $ 1,408 $ 1,017 $ 883 $ 946 $ 807 Value assigned for purpose of the roll-up transaction 2,107
(1) Per unit data is based on indicated amounts allocable to limited partners divided by 1,405 limited partner units outstanding. 122 136 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS General The 1990-1 Partnership was formed November 29, 1990 for the purpose of investing in oil and natural gas activities by acquiring proven producing properties, recompleting previously drilled wells and developing and drilling new oil and gas wells. Benton Oil and Gas Company and a wholly owned subsidiary are the Co-Managing General Partners, and as such, conduct, direct and exercise full control over all activities of the Partnership. Oil and gas properties are accounted for using the successful efforts methods. Under this method, costs of drilling exploratory wells are initially capitalized pending determination of whether the well can produce proved reserves. All costs relating to non-productive exploratory wells are expensed. Costs relating to productive exploratory wells and all development wells are capitalized and depleted on a unit-of-production basis over the life of the remaining proved developed reserves. Delay rentals and geological and geophysical costs are expensed as incurred. Under the terms of the 1990-1 Partnership Agreement, the participants pay 99% of the lease acquisition, geophysical and seismic costs, well costs, and organization and offering expenses, including commissions, while the Co-Managing General Partners pay 1% of such costs. General and administrative expenses and lease operating expenses are shared 74.25% by the participants and 25.75% by the Co-Managing General Partners. Revenues and production taxes are allocated 73.5974% to the participants and 25.5236% to the Co-Managing General Partners and 0.879% to broker/dealers who met certain minimum sales requirements in the initial offering of the 1990-1 Units. Results of Operations Six Months Ended June 30, 1995 and 1994. For the six months ended June 30, 1995, the 1990-1 Partnership had revenues of $235,273 compared to $280,792 for the same period in 1994, representing a decrease of 16%. This decrease was primarily due to reduced oil sales quantities and lower gas prices related to the Umbrella Point Field which were partially offset by increased gas sales quantities in the field. The production for the six months ended June 30, 1995 was 6,879 Bbl of crude oil and condensate and 71,474 Mcf of natural gas compared to production of 9,507 Bbl of crude oil and condensate and 59,966 Mcf of natural gas for the comparable period in 1994. For the six months ended June 30, 1995, crude oil and natural gas prices averaged $17.46 per Bbl and $1.60 per Mcf, respectively, compared to $15.00 per Bbl and $2.22 per Mcf, respectively, during the comparable period. Lease operating costs and production taxes for the period ended June 30, 1995 were $100,135, a decrease of 11% from $112,322 in the comparable period. The decrease was primarily due to legal fees incurred in 1994 related to damage to production facilities. Depletion, impairment and amortization expenses were $153,641 for the period ended June 30, 1995, an increase of 35% from $113,834 for the comparable period primarily due to the impairment of the Umbrella Point Field as a result of the proposed sale of the property. General and administrative expenses were $67,323 for the period ended June 30, 1995, an increase of 15% from $58,782 for the comparable period primarily due to increased audit and tax preparation fees and costs related to the review of the Partnership's reserves by an independent petroleum engineering firm. 123 137 For the reasons discussed above, the net loss for the six months ended June 30, 1995 was $88,966, compared to a loss of $9,478 for the period ended June 30, 1994. Years Ended December 31, 1994 and 1993. For the year ended December 31, 1994, the 1990-1 Partnership had total revenues of $524,786 compared to $645,459 for the same period in 1993, representing a decrease of 19%, primarily due to reduced oil and gas sales quantities combined with reduced oil and gas prices. The production for the year ended December 31, 1994 was 17,179 Bbl of crude oil and condensate and 127,779 Mcf of natural gas compared to production of 18,518 Bbl of crude oil and condensate and 146,746 Mcf of natural gas for the comparable period in 1993. For the year ended December 31, 1994, crude oil and natural gas prices averaged $15.83 per Bbl and $1.93 per Mcf, respectively, compared to $17.31 per Bbl and $2.11 per Mcf, respectively, during the comparable period. Lease operating costs and production taxes for the year ended December 31, 1994 were $263,957, an increase of 4% from $254,903 in the comparable period. A significant portion of the Partnership's lease operating expenses are associated with fixed rather than variable costs such as contract pumping services and equipment rentals. While certain variable costs decreased as oil and gas sales quantities decreased during the period, other non-variable costs increased resulting in an aggregate increase of $9,054 or 4% during 1994 compared to 1993. Depletion, impairment and amortization expenses were $224,635 for the year ended December 31, 1994, an increase of 19% from $189,309 for the comparable period primarily due to impairment of the West Cote Blanche Bay Field. General and administrative expenses were $78,547 for the year ended December 31, 1994, a decrease of 21% from $99,967 for the comparable period primarily due to the sale at a gain of marketable equity securities in 1994 which had been written down to approximate market value in 1993 and reduced third party administrative support costs. For the reasons discussed above, the net loss for the year ended December 31, 1994 was $48,960, compared to net income of $91,710 for the year ended December 31, 1993. Years Ended December 31, 1993 and 1992. For the year ended December 31, 1993, the 1990-1 Partnership had total revenues of $645,459 compared to $770,517 for the same period in 1992, representing a decrease of 16%. This decrease was primarily due to reduced oil and gas sales from the Umbrella Point and East Cameron Fields due to the fields' natural production decline and sales of the Round Mountain and Hopper Canyon properties. The production for the years ended December 31, 1993 was 18,518 Bbl of crude oil and condensate and 146,746 Mcf of natural gas compared to production of 26,184 Bbl of crude oil and condensate and 145,477 Mcf of natural gas for the comparable period in 1992. For the year ended December 31, 1993, crude oil and natural gas prices averaged $17.31 per Bbl and $2.11 per Mcf, respectively, compared to $18.20 per Bbl and $1.78 per Mcf, respectively, during the comparable period. Lease operating costs and production taxes for the year ended December 31, 1993 were $254,903, a decrease of 11% from $285,840 in the comparable period. Depletion, impairment and amortization expenses were $189,309 for the year ended December 31, 1993, compared to $1,560,665 for the same period in 1992, representing a decrease of 88%. This decrease was primarily due to the impairment of the Round Mountain Field in 1992 as a result of its sale and the complete depletion of the East Cameron Field in 1992. These decreases were partially offset by increased depletion of the Umbrella Point Field in 1993 due to downward revisions to oil and gas reserves during the year. General and administrative expenses for the year ended December 31, 1993 were $99,967, an increase of 44% from $69,510 in the comparable period, primarily related to increased professional fees. 124 138 For the reasons discussed above, the net income for the year ended December 31, 1993 was $91,710, compared to net loss of $1,212,036 for the year ended December 31, 1992. Capital Resources and Liquidity The oil and gas industry is a highly capital intensive business. The Partnership requires capital principally to fund the following costs: (i) drilling and completion costs of wells and the cost of production and transportation facilities; (ii) purchase of leases and other interests in oil and gas producing properties; and (iii) general and administrative expenses. The amount of available capital significantly effects the scope of the Partnership's operations. In June 1995, the Partnership entered into an agreement to sell its principal remaining oil and gas properties (see Note 4 to the 1990-1 Partnership Financial Statements). Assuming the sale is completed, the Partnership will have very limited remaining oil and gas activities. If the sale is not completed, the properties have a remaining economic life of approximately 5.5 years. Effects of Inflation and Changing Prices The 1990-1 Partnership's results of operations and cash flow are affected by changing oil and gas prices. If the price of oil and gas increases, there could be a corresponding increase in the cost to the Partnership for drilling and related services as well as an increase in revenues. To date, inflation has had a minimal effect on the Partnership. 125 139 INFORMATION CONCERNING 1991-1 PARTNERSHIP GENERAL Objectives. The 1991-1 Partnership is a limited partnership which was formed to invest in oil and natural gas activities by primarily acquiring proven producing properties that have additional development potential, recompleting previously drilled wells and drilling new wells. The primary financial objective of the 1991-1 Partnership is to make quarterly distributions to its Investors from available cash flow while replacing and expanding its reserves on a cost-effective basis. The Partnership made regular cash distributions to partners through August 1994, but has not made subsequent cash distributions due to declining oil and gas production combined with higher lease operating costs and production taxes, continued capital expenditures and lower natural gas prices. Management. Benton Oil and Gas Company and a wholly-owned subsidiary, Benton Oil and Gas Company of Louisiana, are the Co-Managing General Partners. Benton makes all decisions regarding the business and operations of the 1991-1 Partnership, including development and other activities, and any sale of properties and the acquisition of additional properties. The Managing General Partners receive 25.6438% of the oil and gas revenues from the 1991-1 Partnership. In addition, Benton and its subsidiary own 2.8182 Units in the 1991-1 Partnership. The Co-Managing General Partners do not receive any management fees or other fees from the 1991-1 Partnership. The 1991-1 Partnership pays the Co-Managing General Partners for lease operating expenses, well costs and general and administrative expenses incurred on behalf of the Partnership. Organization. Benton, as managing general partner and sponsor of the 1991-1 Partnership, sold an aggregate of $1,409,091 of 1991-1 Units. Of the net proceeds raised of $1,055,886 which were available for partnership activities, $927,510 was used in oil and gas activities of the Partnership, as contemplated in the private placement memorandum for the offering, and the remaining proceeds were distributed to the participants. DESCRIPTION OF OIL AND GAS PROPERTIES The following table sets forth certain information as of January 1, 1995 related to the 1991-1 Partnership's interest in its oil and gas properties.
Proved Reserves at January 1, 1995 1994 Production ---------------------------------- --------------- Present Value of Estimated Future Net Cash Flows Discounted Property Oil (Bbls) Gas (Mcf) at 10% (Bbls) (Mcf) - -------- ---------- --------- --------------------- ------ ------ Umbrella Point Field 13,832 104,982 $186,589 3,127 17,148 West Cote Blanche Bay Field 264 26,356 23,856 293 2,667 ------ ------- -------- ----- ------ TOTAL 14,096 131,338 $210,445 3,420 19,815 ====== ======= ======== ===== ======
Additional information regarding these fields is set forth below. 126 140 Umbrella Point Field. The Umbrella Point Field is located in State Tracts 74 and 87, which consist of 1,280 acres in the northern end of Upper Galveston Bay, in Texas state waters. Sun Oil Co. discovered the field in May, 1957. Oil and gas production is from fifteen stacked Frio sands ranging in depth from the F-1 sand at 7,612 feet to the F-15 sand at 8,994 feet. The 1991-1 Partnership acquired a 2.83% working interest in the Umbrella Point Field from the 1990-1 Partnership for $373,205 prior to closing adjustments. As of September 1995, the Umbrella Point Field had 10 wells producing at combined average daily rates of 312 Bbl of oil and 3.1 MMcf of natural gas. West Cote Blanche Bay Field. The West Cote Blanche Bay Field is located on 5,892 acres in a shallow bay in St. Mary Parish, Louisiana, approximately 125 miles southwest of New Orleans with water depths averaging seven to eight feet. The field was discovered in 1938 by Texaco, which continues to operate the field. More than 300 separate oil and gas reservoirs have been identified by Texaco and the Company from a total of approximately 680 wellbores in 180 different sandstone formations, at depths from 1,700 to 13,000 feet. The 1991-1 Partnership purchased a 0.06% working interest in the West Cote Blanche Bay Field from the 1990-1 Partnership for $94,352 prior to closing adjustments. In March 1995, the Partnership sold its 0.06% working interest in certain depths (above approximately 10,575 feet) in the West Cote Blanche Bay Field for a purchase price of $29,200. The 1991-1 Partnership has a 0.06% working interest in three wells below the depth of approximately 10,575 feet. These wells are currently producing at a combined rate of approximately 21 MMcf of natural gas per day. The following is a description of properties the 1991-1 Partnership at one time had an interest in but subsequently sold or abandoned. Hopper Canyon 12-1 Well. The Hopper Canyon 12-1 well is located in Ventura County, California. This well was successfully drilled and completed in the fourth quarter of 1991. The well produced at rates of approximately 24 Bbl of oil and 45 MMcf of gas per day. However, Benton determined it was in the best interest of the Partnership to sell its 38.0% working interest in the well. In April 1992, the 1991-1 Partnership sold its interest in the 12-1 well to Fortune Petroleum. Proceeds from the sale were $17,881, consisting of $3,461 in cash and stock of Fortune Petroleum with a fair market value of $14,420 (the stock was subsequently sold in November 1994 with the 1991-1 Partnership receiving $7,699). In addition, the 1991-1 Partnership retained a production payment of $8,845 which was paid from monthly net income from the 12-1 well. The 1991-1 Partnership's cumulative expenditures on the Hopper Canyon 12-1 well were $211,132. Prather 43-1 Well. This prospect was located in Acadia Parish, Louisiana. This well was drilled to a total depth of approximately 11,000 feet. It was determined to be uneconomical and was plugged and abandoned. The 1991-1 Partnership had a 17.5% working interest in this well with total cumulative expenditures of $134,715. SELECTED HISTORICAL FINANCIAL DATA The following selected financial data for the 1991-1 Partnership as of and for each of the years in the four year period ended December 31, 1994 are derived from the 1991-1 Partnership's audited financial statements. The selected consolidated financial data for the six months ended June 30, 1994 and 1995 are derived from the 1991-1 Partnership's unaudited financial statements. In the opinion of management, such unaudited financial statements contain all adjustments (consisting of only normal recurring accruals) necessary for a fair presentation of the financial condition and results of operations as of and for the periods presented. Operating results for the six months ended June 30, 1995 are not necessarily indicative of the results that may be expected for the entire fiscal year ending December 31, 127 141 1995. The selected financial data below should be read in conjunction with the 1991-1 Partnership's financial statements and related notes thereto and Management's Discussion and Analysis of Financial Condition and Results of Operations included elsewhere in this Prospectus.
Six Months Ended Inception to Years Ended December 31 June 30 December 31 ------------------------------------- ---------------------- 1991 1992 1993 1994 1994 1995 ---- ---- ---- ---- ---- ---- Operating Data Total revenue $ 108,288 $ 160,321 $ 112,524 $ 98,644 $ 52,188 $ 44,852 Lease operating costs and production taxes 54,069 40,093 36,276 38,002 14,599 12,553 Exploration costs 158,016 7,245 1,284 769 515 361 Loss on sale of oil and gas properties 61,225 225 Depletion, impairment and amortization 125,742 65,241 60,503 95,497 32,435 119,437 General and administrative 20,925 28,876 45,195 28,823 25,981 30,500 ----------- --------- --------- --------- -------- --------- Net loss ($ 250,464) ($ 42,359) ($ 30,734) ($ 64,447) ($21,342) ($118,224) =========== ========= ========= ========= ======== ========= Net increase (decrease) in cash and cash equivalents $ 1,233,019 ($955,826) ($100,013) ($117,010) ($54,775) $ 22,377 Net cash provided by (used in) operating activities (7,849) 85,839 38,782 28,758 11,544 1,438 Distributions 27,900 111,600 115,292 127,205 56,546 -- Per Unit Operating Data(1) Net income (loss) (914) (243) (146) (256) (87) (422) Distributions of earnings -- -- -- -- -- -- Distributions representing a return of capital 100 400 400 300 200 --
December 31 June 30 ---------------------------------------------- -------------------- 1991 1992 1993 1994 1994 1995 ---- ---- ---- ---- ---- ---- Balance Sheet Data Cash and cash equivalents $1,233,019 $277,193 $177,180 $ 60,170 $122,405 $ 82,547 Total assets at book value 1,815,157 777,067 631,041 439,389 553,153 321,165 Total assets at the value assigned for purposes of roll-up transaction 692,349 Total liabilities 884,131 -- -- -- -- -- General and limited partners' equity: Managing General Partner 18,413 43,394 50,358 13,601 52,514 12,820 Participants 912,292 732,846 580,591 425,503 500,531 307,888 Special Limited Partners 321 827 92 285 108 457 ---------- -------- -------- -------- -------- -------- $ 931,026 $777,067 $631,041 $439,389 $553,153 $321,165 ========== ======== ======== ======== ======== ======== Per Unit Balance Sheet Data(1) Book value $ 3,270 $ 2,627 $ 2,081 $ 1,525 $ 1,794 $ 1,104 Value assigned for purpose of the roll-up transaction 2,456
(1) Per unit data is based on indicated amounts allocable to limited partners divided by 279 limited partner units outstanding. 128 142 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS General The 1991-1 Partnership was formed for the purpose of investing in oil and natural gas activities by acquiring proven producing properties, recompleting previously drilled wells and developing and drilling new oil and gas wells. Benton Oil and Gas Company and a wholly owned subsidiary are the Co-Managing General Partners, and as such, conduct, direct and exercise full control over all activities of the Partnership. Oil and gas properties are accounted for using the successful efforts methods. Under this method, costs of drilling exploratory wells are initially capitalized pending determination of whether the well can produce proved reserves. All costs relating to non-productive exploratory wells are expensed. Costs relating to productive exploratory wells and all development wells are capitalized and depleted on a unit-of-production basis over the life of the remaining proved developed reserves. Delay rentals and geological and geophysical costs are expensed as incurred. Under the terms of the 1991-1 Partnership Agreement, the participants pay 99% of the lease acquisition, geophysical and seismic costs, well costs, and organization and offering expenses, including commissions, while the Co-Managing General Partners pay 1% of such costs. For the first twelve months of the Partnership, general and administrative expenses are covered by a fee, equal to 3% of the initial capital raised, paid by the Partnership to Benton. The fee is paid 99% by the participants and 1% by the Co-Managing General Partners. General and administrative expenses after the first twelve months and lease operating expenses are shared 74.25% by the participants and 25.75% by the Co-Managing General Partners. Revenues and production taxes are allocated 73.944% to the participants and 25.6438% to the Co-Managing General Partners, and 0.4122% to broker/dealers who met certain minimum sales requirements in the initial offering of 1991-1 Units. Results of Operations Six Months Ended June 30, 1995 and 1994. For the six months ended June 30, 1995, the 1991-1 Partnership had revenues of $44,852 compared to $52,188 for the same period in 1994, representing a decrease of 14%. This decrease was primarily due to reduced oil sales quantities and lower gas prices related to the Umbrella Point Field which were partially offset by increased gas sales quantities in the field. The production for the six months ended June 30, 1995 was 1,368 Bbl of crude oil and condensate and 12,039 Mcf of natural gas compared to production of 1,893 Bbl of crude oil and condensate and 8,813 Mcf of natural gas for the comparable period in 1994. For the six months ended June 30, 1995, crude oil and natural gas prices averaged $17.79 per Bbl and $1.64 per Mcf, respectively, compared to $16.01 per Bbl and $2.28 per Mcf, respectively, during the comparable period. Lease operating costs and production taxes for the period ended June 30, 1995 were $12,553, a decrease of 14% from $14,599 in the comparable period. The decrease was primarily due to legal fees incurred in 1994 related to damage to production facilities. Depletion, impairment and amortization expenses were $119,437 for the period ended June 30, 1995, an increase of 268% from $32,435 for the comparable period primarily due to the impairment of the Umbrella Point Field as a result of the proposed sale of the property. General and administrative expenses were $30,500 for the period ended June 30, 1995, an increase of 17% from $25,981 for the comparable period primarily due to increased 129 143 audit and tax preparation fees and costs related to the review of the Partnership's reserves by an independent petroleum engineering firm. For the reasons discussed above, the net loss for the six months ended June 30, 1995 was $118,224, compared to a loss of $21,342 for the period ended June 30, 1994. Years Ended December 31, 1994 and 1993. For the year ended December 31, 1994, the 1991-1 Partnership had total revenues of $98,644 compared to $112,524 for the same period in 1993, representing a decrease of 12%, primarily due to price decreases. The production for the year ended December 31, 1994 was 3,420 Bbl of crude oil and condensate and 19,815 Mcf of natural gas compared to production of 3,686 Bbl of crude oil and condensate and 18,256 Mcf of natural gas for the comparable period in 1993. For the year ended December 31, 1994, crude oil and natural gas prices averaged $16.83 per Bbl and $1.94 per Mcf, respectively, compared to $18.14 per Bbl and $2.21 per Mcf, respectively, during the comparable period. Lease operating costs and production taxes for the year ended December 31, 1994 were $38,002, an increase of 5% from $36,276 in the comparable period. A significant portion of the Partnership's lease operating expenses are associated with fixed rather than variable costs such as contract pumping services and equipment rentals. Costs increased by $1,726 or 5% during 1994 compared to 1993. Depletion, impairment and amortization expenses were $95,497 for the year ended December 31, 1994, an increase of 58% from $60,503 for the comparable period primarily due to impairment of the West Cote Blanche Bay Field. General and administrative expenses were $28,823 for the year ended December 31, 1994, a decrease of 36% from $45,195 for the comparable period primarily due to the sale at a gain of marketable equity securities in 1994 which had been written down to approximate market value in 1993 and reduced third party administrative support costs. For the reasons discussed above, the net loss for the year ended December 31, 1994 was $64,447, compared to net loss of $30,734 for the period ended December 31, 1993. Years Ended December 31, 1993 and 1992. For the year ended December 31, 1993, the 1991-1 Partnership had total revenues of $112,524 compared to $160,321 for the same period in 1992, representing a decrease of 30%. This decrease was primarily due to reduced oil and gas sales from the Umbrella Point and West Cote Blanche Bay Fields due to the fields' natural production decline and sale of the Hopper Canyon property. The production for the year ended December 31, 1993 was 3,686 Bbl of crude oil and condensate and 18,256 Mcf of natural gas compared to production of 4,727 Bbl of crude oil and condensate and 19,222 Mcf of natural gas for the comparable period in 1992. For the year ended December 31, 1993, crude oil and natural gas prices averaged $18.14 per Bbl and $2.21 per Mcf, respectively, compared to $20.02 per Bbl and $1.84 per Mcf, respectively, during the comparable period. Lease operating costs and production taxes for the year ended December 31, 1993 were $36,276, a decrease of 10% from $40,093 in the comparable period. Depletion, impairment and amortization expenses were $60,503 for the year ended December 31, 1993, compared to $65,241 for the same period in 1992, representing a decrease of 7% primarily due to the increased depletion of the Umbrella Point Field in 1993 as a result of downward revisions to oil and gas reserves during the year. The increase was partially offset, however, by the sale of the Hopper Canyon property in 1992. General and administrative expenses for the year ended December 31, 1993 were $45,195, an increase of 57% from $28,876 in the comparable period, primarily related to increased professional fees. 130 144 For the reasons discussed above, the net loss for the year ended December 31, 1993 was $30,734, compared to net loss of $42,359 for the year ended December 31, 1992. Capital Resources and Liquidity The oil and gas industry is a highly capital intensive business. The Partnership requires capital principally to fund the following costs: (i) drilling and completion costs of wells and the cost of production and transportation facilities; (ii) purchase of leases and other interests in oil and gas producing properties; and (iii) general and administrative expenses. The amount of available capital significantly effects the scope of the Partnership's operations. In June 1995, the Partnership entered into an agreement to sell its principal remaining oil and gas properties (see Note 4 to the 1991-1 Partnership Financial Statements). Assuming the sale is completed, the Partnership will have very limited remaining oil and gas activities. If the sale is not completed, the properties have a remaining economic life of approximately 2.5 years. Effects of Inflation and Changing Prices The 1991-1 Partnership's results of operations and cash flow are affected by changing oil and gas prices. If the price of oil and gas increases, there could be a corresponding increase in the cost to the Partnership for drilling and related services as well as an increase in revenues. To date, inflation has had a minimal effect on the Partnership. 131 145 DESCRIPTION OF SECURITIES Benton is authorized to issue 40,000,000 shares of Common Stock and 5,000,000 shares of Preferred Stock. Common Stock. The holders of Common Stock are entitled to one vote per share for each share held of record on all matters submitted to a vote of the stockholders and are entitled to receive ratably such dividends as are declared by the Board of Directors out of funds legally available therefor. In the event of liquidation, dissolution or winding up of Benton, holders of the Common Stock have the right to a ratable portion of the assets remaining after payment of liabilities and liquidation preferences of any outstanding shares of Preferred Stock. The holders of Common Stock have no preemptive rights or rights to convert their Common Stock into other securities and are not subject to future calls or assessments by Benton. All outstanding shares of Common Stock are fully paid and nonassessable. All shares of Common Stock to be issued in connection with the Sale will be fully paid and nonassessable. Preferred Stock. The Board of Directors may, without further action of the stockholders, issue Preferred Stock in one or more series and fix rights and preferences thereof, including dividend rights, dividend rates, conversion rights, voting rights, terms of redemption, redemption price or prices, liquidation preferences and the number of shares constituting any series or the designation of such series (provided that the Board of Directors has no authority to issue more than 5,000,000 shares of Preferred Stock). No shares of Preferred Stock are currently outstanding. The rights of the holders of Common Stock will be subject to, and may be adversely affected by, the rights of the Preferred Stock, which while providing desirable flexibility in achieving corporate objectives, could have the effect of making it more difficult for a person to acquire, or of discouraging a person from acquiring, a majority of the voting stock of Benton. Warrants. The Warrants entitle the holder to purchase one share of Benton Common Stock for each Warrant at an exercise price, payable in cash, of $11.00 per share, subject to adjustment in certain circumstances. The holders of Warrants have no rights as stockholders of Benton. The Warrants will be issued pursuant to the terms of the Warrant Agreement, the form of which is attached hereto as Exhibit A, and will expire three years from the date of issuance. The number of shares of Common Stock and the exercise price of the Warrants is subject to adjustment under certain circumstances described in the Warrant Agreement, including issuance of Common Stock or securities convertible into Common Stock to all holders of Benton Common Stock, exchange of Common Stock of Benton for other securities, issuance of Common Stock or other securities to all holders upon merger, reorganization or sale of assets. The Warrants are not subject to redemption or call by Benton. If the Exchange Offer is accepted by more than 75% of the holders of the 1989-1 Units, the 1990-1 Units and the 1991-1 Units, Benton will issue to all holders of such Units, Warrants to purchase an aggregate of 592,373 shares of Common Stock. Pursuant to the terms of other common stock purchase warrants and warrant agreements, Benton has issued common stock purchase warrants, on various terms and for exercise prices ranging from $7.30 per share to $17.09 per share. As of September 22, 1995, there were common stock purchase warrants to purchase an aggregate of 1,919,752 shares of Common Stock issued and outstanding. 132 146 LEGAL MATTERS The validity of the Securities to be issued pursuant to the Exchange Offer will be passed upon for Benton, and certain federal income tax matters related to the Exchange Offer will be passed upon for Benton, by Emens, Kegler, Brown, Hill & Ritter, Co., L.P.A., Columbus, Ohio. EXPERTS The consolidated financial statements of Benton and the financial statements of the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership as of December 31, 1994 and 1993 and for each of the three years in the period ended December 31, 1994 included in this Prospectus have been audited by Deloitte & Touche LLP, independent auditors, as stated in their reports appearing herein and have been so included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing. The information appearing herein, and incorporated herein by reference, with respect to proved oil and gas reserves of Benton at December 31, 1992, 1993 and 1994, to the extent stated herein, was estimated by Benton and audited by Huddleston & Co., Inc., independent petroleum engineers, and is included herein on the authority of such firm as experts in petroleum engineering. The information appearing herein with respect to proved oil and gas reserves of the 1989-1 Partnership at December 31, 1992, 1993 and 1994, to the extent stated herein, was estimated by Benton and audited by Huddleston & Co., Inc., independent petroleum engineers, and is included herein on the authority of such firm as experts in petroleum engineering. The information appearing herein with respect to proved oil and gas reserves of the 1990-1 Partnership at December 31, 1992, 1993 and 1994, to the extent stated herein, was estimated by Benton and audited by Huddleston & Co., Inc., independent petroleum engineers, and is included herein on the authority of such firm as experts in petroleum engineering. The information appearing herein with respect to proved oil and gas reserves of the 1991-1 Partnership at December 31, 1992, 1993 and 1994, to the extent stated herein, was estimated by Benton and audited by Huddleston & Co., Inc., independent petroleum engineers, and is included herein on the authority of such firm as experts in petroleum engineering. 133 147 GLOSSARY When the following terms are used in the text they have the meanings indicated. MCF. "Mcf" means thousand cubic feet. "MMcf" means million cubic feet. "Bcf" means billion cubic feet. "Tcf" means trillion cubic feet. BBL. "Bbl" means barrel. "MBbl" means thousand barrels. "MMBbl" means million barrels. "BBbl" means billion barrels. BOE. "BOE" means barrels of oil equivalent, which are determined using the ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf of natural gas so that six Mcf of natural gas is referred to as one barrel of oil equivalent or "BOE." "MBOE" means thousands of barrels of oil equivalent. "MMBOE" means millions of barrels of oil equivalent. CAPITAL EXPENDITURES. "Capital Expenditures" means costs associated with exploratory and development drilling (including exploratory dry holes); leasehold acquisitions; seismic data acquisitions; geological, geophysical and land-related overhead expenditures; delay rentals; producing property acquisitions; and other miscellaneous capital expenditures. COMPLETION COSTS. "Completion Costs" means, as to any well, all those costs incurred after the decision to complete the well as a producing well. Generally, these costs include all costs, liabilities and expenses, whether tangible or intangible, necessary to complete a well and bring it into production, including installation of service equipment, tanks and other materials necessary to enable the well to deliver production. DEVELOPMENT WELL. A "Development Well" is a well drilled as an additional well to the same reservoir as other producing wells on a lease, or drilled on an offset lease not more than one location away from a well producing from the same reservoir. EXPLORATORY WELL. "An "Exploratory Well" is a well drilled in search of a new and as yet undiscovered pool of oil or gas, or to extend the known limits of a field under development. FINDING COSTS. "Finding Cost," expressed in dollars per BOE, is calculated by dividing the amount of total capital expenditures incurred related to acquisitions, exploration and development costs (reduced by proceeds from any sale of oil and gas properties) by the amount of total net reserves added or reduced as a result of property acquisitions and sales, drilling activities and reserve revisions during the same period. FUTURE DEVELOPMENT COST. "Future Development Cost" of proved non-producing reserves, expressed in dollars per BOE, is calculated by dividing the amount of future capital expenditures related to development properties by the amount of total proved non-producing reserves associated with such activities. GROSS ACRES OR WELLS. "Gross Acres or Wells" are the total acres or wells, as the case may be, in which an entity has an interest, either directly or through an affiliate. 134 148 LIFTING COSTS. "Lifting Costs" are the expenses of lifting oil from a producing formation to the surface, consisting of the costs incurred to operate and maintain wells and related equipment and facilities, including labor costs, repair and maintenance, supplies, insurance, production, severance and windfall profit taxes. MMBTU. "MMBtu" means one million British thermal units. A British thermal unit is the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit. NET ACRES OR WELLS. A party's "Net Acre" or "Net Wells" are calculated by multiplying the number of gross acres or gross wells in which that party has an interest by the fractional interest of the party in each such acre or well. OIL AND GAS LEASE. An "Oil and Gas Lease" is an agreement whereby the grantee receives for a period of time the full or partial interest in oil and gas properties, oil and gas mineral rights, fee rights or other rights of the grantor granting the grantee the right to drill for, produce and sell oil and gas upon payment of rentals, bonuses and/or royalties. Oil and Gas Leases are generally acquired from private landowners and federal and state governments. PRODUCING PROPERTIES OR RESERVES. "Producing Reserves" are Proved Developed Behind-Pipe Reserves expected to be produced from existing completion intervals now open for production in existing wells. "Producing Properties" are properties to which Producing Reserves have been assigned by an independent petroleum engineer. PROVED DEVELOPED BEHIND-PIPE RESERVES. "Proved Developed Reserves" are Proved Reserves which can be expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. RESERVES. "Reserves" means crude oil and natural gas, condensate and natural gas liquids, which are net of leasehold burdens, are stated on a net revenue interest basis, and are found to be commercially recoverable. ROYALTY INTEREST. "A Royalty Interest" is an interest in an oil and gas property entitling the owner to a share of oil and gas production (or the proceeds of the sale thereof) free of the costs of production. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS, BEFORE PROVISION FOR INCOME TAXES. The "Standardized measure of discounted future net cash flows, before provision for income taxes" is a method of determining the present value of Proved Reserves. Future net revenues from Proved Reserves are estimated assuming that oil and gas prices and production and development costs remain constant. The resulting stream of revenues, before provision for income taxes, is then discounted at the rate of 10% per year to obtain a present value. Sometimes referred to herein as "PV10". 3-D SEISMIC. "3-D Seismic" is the method by which a three dimensional image of the earth's subsurface is created through the interpretation of aerially collected seismic data. 3-D surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contributed significantly to field appraisal, development and production. UNDEVELOPED ACREAGE. "Undeveloped Acreage" is oil and gas acreage (including, in applicable instances, rights in one or more horizons which may be penetrated by existing wellbores, but which have not been tested) to which Proved Reserves have not been assigned by independent petroleum engineers. 135 149 WORKING INTEREST. A "Working Interest" is the operating interest under an Oil and Gas Lease which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith. In this Prospectus, natural gas volumes are stated at the legal pressure base of the state or area in which the reserves are located at 60 degrees Fahrenheit. 136 150 INDEX TO FINANCIAL STATEMENTS
PAGE ---- Index to Benton Oil and Gas Company and Subsidiaries Consolidated Financial Statements........................................................................ F-2 Index to Benton Oil & Gas Combination Partnership 1989-1, L.P. Financial Statements........................................................................ F-28 Index to Benton Oil & Gas Combination Partnership 1990-1, L.P. Financial Statements........................................................................ F-38 Index to Benton Oil & Gas Combination Partnership 1991-1, L.P. Financial Statements........................................................................ F-49
F-1 151 INDEX TO BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED FINANCIAL STATEMENTS
PAGE ---- Independent Auditors' Report........................................................ F-3 Consolidated Balance Sheets at December 31, 1993 and 1994 and June 30, 1995......... F-4 Consolidated Statements of Operations for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months Ended June 30, 1994 and 1995.......................... F-5 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months Ended June 30, 1995........................ F-6 Consolidated Statements of Cash Flows for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months Ended June 30, 1994 and 1995.......................... F-7 Notes to Consolidated Financial Statements for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months Ended June 30, 1994 and 1995..................... F-9
F-2 152 INDEPENDENT AUDITORS' REPORT Benton Oil and Gas Company Carpinteria, California We have audited the accompanying consolidated balance sheets of Benton Oil and Gas Company and subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Benton Oil and Gas Company and subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. Deloitte & Touche LLP Los Angeles, California March 31, 1995 F-3 153 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
DECEMBER 31, ----------------------------- JUNE 30, 1993 1994 1995 ------------ ------------ ------------ (UNAUDITED) ASSETS CURRENT ASSETS: Cash and cash equivalents...................... $ 36,308,118 $ 14,192,568 $ 25,416,122 Restricted cash (Note 4)....................... 300,000 19,550,000 19,550,000 Accounts receivable: Accrued oil and gas revenue................. 940,618 9,357,782 11,412,303 Joint interest and other (Note 12).......... 1,578,679 3,880,808 3,745,439 Property held for sale (Note 2)................ 14,887,700 756,872 Prepaid expenses and other..................... 333,263 563,839 1,903,825 ------------ ------------ ------------ TOTAL CURRENT ASSETS................... 39,460,678 62,432,697 62,784,561 OTHER ASSETS..................................... 1,008,452 2,550,607 1,438,315 PROPERTY AND EQUIPMENT (Notes 1,2,3,5,10,11 and 15): Oil and gas properties (full cost method -- costs of $11,975,615, $16,695,284 and $13,383,439 excluded from amortization at December 31, 1993 and 1994 and June 30, 1995, respectively)......................... 77,079,977 116,209,554 150,552,235 Furniture and fixtures......................... 673,848 1,439,484 1,948,965 ------------ ------------ ------------ 77,753,825 117,649,038 152,501,200 Accumulated depletion and depreciation......... (9,587,983) (20,071,223) (26,514,848) ------------ ------------ ------------ 68,165,842 97,577,815 125,986,352 ------------ ------------ ------------ $108,634,972 $162,561,119 $190,209,228 =========== =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable: Revenue distribution........................ $ 10,289 $ 594,782 $ 866,461 Trade and other............................. 3,542,355 11,426,105 9,591,452 Accrued interest payable, payroll and related taxes....................................... 399,362 1,199,096 1,173,599 Income taxes payable........................... 1,586,616 Commercial paper and other short term borrowings (Note 4)......................... 7,668,588 21,035,401 21,534,318 Current portion of long term debt (Note 3)..... 1,205,107 6,392,114 5,893,160 ------------ ------------ ------------ TOTAL CURRENT LIABILITIES.............. 12,825,701 40,647,498 40,645,606 LONG TERM DEBT (Note 3).......................... 11,788,374 31,911,164 53,268,253 MINORITY INTEREST (Note 11)...................... 1,743,660 3,486,233 COMMITMENTS AND CONTINGENCIES (Notes 3,5,10 and 15) STOCKHOLDERS' EQUITY (Notes 2,3,7,8,9 and 11): Preferred stock, par value $0.01 a share; authorized 5,000,000 shares; outstanding, none Common stock, par value $0.01 a share; authorized 40,000,000 shares; issued and outstanding 24,676,848, 24,899,848 and 25,105,493 at December 31, 1993 and 1994 and June 30, 1995 respectively.................. 246,768 248,998 251,054 Additional paid-in capital..................... 91,639,606 92,921,115 94,317,797 Accumulated deficit............................ (7,865,477) (4,911,316) (1,759,715) ------------ ------------ ------------ TOTAL STOCKHOLDERS' EQUITY............. 84,020,897 88,258,797 92,809,136 ------------ ------------ ------------ $108,634,972 $162,561,119 $190,209,228 =========== =========== ===========
See notes to consolidated financial statements. F-4 154 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
SIX MONTHS ENDED JUNE 30, YEARS ENDED DECEMBER 31, --------------------------------------- ------------------------- 1992 1993 1994 1994 1995 ----------- ----------- ----------- ----------- ----------- (UNAUDITED) REVENUES Oil and gas sales (Notes 14 and 15).................... $ 8,209,134 $ 7,222,310 $31,942,810 $11,168,872 $24,829,260 Net gain (loss) on exchange rates...................... (206,481) 1,445,307 449,487 118,786 Investment earnings........... 185,094 393,843 1,180,824 513,579 873,521 Partnership fees, reimbursements and other... 227,881 94,124 135,865 28,087 48,829 ----------- ----------- ----------- ----------- ----------- 8,622,109 7,503,796 34,704,806 12,160,025 25,870,396 ----------- ----------- ----------- ----------- ----------- EXPENSES Lease operating costs and production taxes........... 4,413,620 5,110,264 9,531,264 3,948,268 5,287,071 Depletion, depreciation and amortization............... 3,041,375 2,632,924 10,298,112 3,421,035 6,473,402 General and administrative.... 2,245,236 2,631,445 5,241,295 2,444,769 3,883,606 Interest...................... 1,831,213 1,957,753 3,887,961 1,596,693 3,361,041 ----------- ----------- ----------- ----------- ----------- 11,531,444 12,332,386 28,958,632 11,410,765 19,005,120 ----------- ----------- ----------- ----------- ----------- INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTEREST... (2,909,335) (4,828,590) 5,746,174 749,260 6,865,276 INCOME TAX EXPENSE (Note 6)..... 697,802 1,971,102 ----------- ----------- ----------- ----------- ----------- INCOME (LOSS) BEFORE MINORITY INTEREST...................... (2,909,335) (4,828,590) 5,048,372 749,260 4,894,174 MINORITY INTEREST (Note 11)..... 2,094,211 747,597 1,742,573 ----------- ----------- ----------- ----------- ----------- NET INCOME (LOSS)............... $(2,909,335) $(4,828,590) $ 2,954,161 $ 1,663 $ 3,151,601 ========== ========== ========== ========== ========== NET EARNINGS (LOSS) PER COMMON SHARE (Note 13)..................... $ (0.22) $ (0.26) $ 0.12 $ 0.00 $ 0.12 ========== ========== ========== ========== ==========
See notes to consolidated financial statements. F-5 155 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992 AND (UNAUDITED) SIX MONTHS ENDED JUNE 30, 1995
COMMON ADDITIONAL SHARES COMMON PAID-IN ACCUMULATED ISSUED STOCK CAPITAL DEFICIT TOTAL ---------- -------- ----------- ----------- ----------- Balance at January 1, 1992.............. 10,307,214 $103,072 $20,233,054 $ (127,552) $20,208,574 Issuance of common shares: Exercise of warrants.................. 10,000 100 17,900 18,000 Exercise of stock options............. 1,354,520 13,545 2,400,996 2,414,541 Acquisitions.......................... 221,790 2,218 2,243,920 2,246,138 Sale of common stock.................. 5,196,785 51,968 27,924,850 27,976,818 Redeemable common stock............... 351,088 3,511 180,919 184,430 Compensation expense attributed to stock options............................... 329,103 329,103 Net loss for the year................... (2,909,335) (2,909,335) ---------- -------- ----------- ----------- ----------- Balance at December 31, 1992............ 17,441,397 174,414 53,330,742 (3,036,887) 50,468,269 Issuance of common shares: Exercise of warrants.................. 2,500 25 18,225 18,250 Exercise of stock options............. 284,211 2,842 540,490 543,332 Sale of common stock.................. 7,000,000 70,000 35,585,406 35,655,406 Redeemable common stock............... 2,022,323 2,022,323 Retirement of stock..................... (51,260) (513) (513) Compensation expense attributed to stock options............................... 142,420 142,420 Net loss for the year................... (4,828,590) (4,828,590) ---------- -------- ----------- ----------- ----------- Balance at December 31, 1993............ 24,676,848 246,768 91,639,606 (7,865,477) 84,020,897 Issuance of common shares: Exercise of stock options............. 23,000 230 83,509 83,739 Acquisitions.......................... 200,000 2,000 1,198,000 1,200,000 Net income for the year................. 2,954,161 2,954,161 ---------- -------- ----------- ----------- ----------- Balance at December 31, 1994............ 24,899,848 248,998 92,921,115 (4,911,316) 88,258,797 Issuance of common shares: Exercise of stock options (unaudited)........................ 127,902 1,279 610,459 611,738 Conversion of notes and debentures (unaudited)........................ 77,743 777 786,223 787,000 Net income for the period (unaudited)... 3,151,601 3,151,601 ---------- -------- ----------- ----------- ----------- Balance at June 30, 1995 (unaudited).... 25,105,493 $251,054 $94,317,797 $(1,759,715) $92,809,136 ========= ======== ========== ========== ==========
See notes to consolidated financial statements. F-6 156 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
SIX MONTHS ENDED JUNE 30, YEARS ENDED DECEMBER 31, ------------------------------------------ ----------------------------- 1992 1993 1994 1994 1995 ------------ ------------ ------------ ------------ ------------ (UNAUDITED) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income (loss).............................. $ (2,909,335) $ (4,828,590) $ 2,954,161 $ 1,663 $ 3,151,601 Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depletion, depreciation and amortization..... 3,041,375 2,632,924 10,298,112 3,421,035 6,473,402 Compensation expense attributed to stock options.................................... 329,103 142,420 Net earnings from limited partnerships....... (183,858) (106,230) (63,486) (38,488) (20,435) Loss on disposition of assets................ 10,632 Interest paid in stock....................... 44,649 20,145 Minority interest in undistributed earnings of subsidiary.............................. 2,094,211 747,597 1,742,573 (Increase) decrease in accounts receivable... 1,628,823 (1,465,725) (10,384,670) (6,627,742) (1,919,152) (Increase) decrease in prepaid expenses and other...................................... 44,517 (288,217) (84,905) (4,937) (1,339,986) Increase (decrease) in accounts payable...... (2,905,840) 1,759,747 7,974,335 5,324,484 (1,562,974) Increase (decrease) in accrued interest payable, payroll and related taxes.................. (114,151) 204,117 560,720 153,032 (25,497) Increase in income taxes payable............. 1,586,616 ------------ ------------ ------------ ------------ ------------ TOTAL ADJUSTMENTS.......................... 2,261,227 3,038,625 10,508,628 3,032,137 5,035,819 ------------ ------------ ------------ ------------ ------------ NET CASH USED IN OPERATING ACTIVITIES...... (648,108) (1,789,965) 13,462,789 3,033,800 8,187,420 ------------ ------------ ------------ ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Proceeds from sale of property and equipment.................................. 2,965,820 7,822,120 5,803,215 128,113 14,708,863 Additions of property and equipment.......... (13,951,247) (26,169,581) (38,403,322) (17,896,570) (27,130,397) Increase in restricted cash.................. (300,000) (19,250,000) (22,000,000) Distributions from limited partnerships...... 391,540 28,667 502,167 1,492 Additions to investments in affiliates....... (350,282) Payment for purchase of Benton-Vinccler, net of cash acquired........................... (2,501,973) (2,501,973) ------------ ------------ ------------ ------------ ------------ NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES............................... (10,944,169) (18,618,794) (53,849,913) (42,268,938) (12,421,534) ------------ ------------ ------------ ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from sale of common stock........... 29,276,567 36,120,000 Direct offering costs........................ (982,114) (464,594) Proceeds from exercise of stock options and warrants................................... 2,432,541 561,582 83,740 22,727 611,738 Issuance of convertible subordinated debentures................................. 6,428,000 Proceeds from issuance of notes payable...... 404,776 21,360,000 22,040,000 Proceeds from commercial paper and other short term borrowings...................... 7,668,588 23,217,775 23,060,188 (Increase) decrease in other assets.......... (806,992) 3,460 (1,683,583) (19,623) (213,664) Payments on commercial paper, other short term borrowings and notes payable.......... (14,877,300) (672,230) (24,706,358) (17,849,721) (6,980,406) Deficiency payments on redeemable common stock...................................... (287,194) (172,917) ------------ ------------ ------------ ------------ ------------ NET CASH PROVIDED BY FINANCING ACTIVITIES............................... 21,588,284 43,043,889 18,271,574 5,213,571 15,457,668 ------------ ------------ ------------ ------------ ------------ NET INCREASE (DECREASE) IN CASH............ 9,996,007 22,635,130 (22,115,550) (34,021,567) 11,223,554 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD....................................... 3,676,981 13,672,988 36,308,118 36,308,118 14,192,568 ------------ ------------ ------------ ------------ ------------ CASH AND CASH EQUIVALENTS AT END OF PERIOD..... $ 13,672,988 $ 36,308,118 $ 14,192,568 $ 2,286,551 $ 25,416,122 =========== =========== =========== =========== =========== SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid during the period for interest expense.................................... $ 1,483,585 $ 1,838,848 $ 3,299,189 $ 1,136,493 $ 3,215,165 =========== =========== =========== =========== =========== Cash paid during the period for income taxes...................................... $ 715,507 $ 160,594 $ 368,427 =========== =========== =========== =========== ===========
F-7 157 SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES: Costs of $314,123, incurred during the year ended December 31, 1991, which were attributable to the public offering of the Company's common stock completed in January 1992, and previously included in other assets, were offset against gross proceeds received from the sale of stock during the year ended December 31, 1992. During the year ended December 31, 1992, the Company acquired interests in oil and gas properties in exchange for 221,790 shares of the Company, valued at $2,246,138 and a $529,197 reduction in the Company's joint interest account receivable balance due from the seller. On July 7, 1992, the Company issued 351,088 shares of Redeemable common stock in connection with refinancing of indebtedness in the amount of $2,582,050. During the year ended December 31, 1992, 27,000 of these shares were resold for net proceeds of $180,919, which were allocated $120,270 for redemption, $44,649 for interest and $16,000 for costs of refinancing, and the Company made cash payments of $319,081. During the year ended December 31, 1993, 272,828 shares of Redeemable common stock were resold for net proceeds to the selling stockholders of $2,022,323, and the Company made cash payments of $200,000, terminating the Company's guarantee obligation. The reduction was allocated $2,002,178 for redemption and $20,145 for interest. On May 19, 1993, the Company redeemed the remaining 51,260 shares at their par value of $.01 per share. During the year ended December 31, 1992, the Company acquired $43,790 of fixed assets through capital lease obligations and seller financing. During the year ended December 31, 1993, the Company converted $2,113,429 of accounts payable into a note payable and entered into capital lease agreements for the purchase of furniture and fixtures in the amount of $79,521. On March 4, 1994, the Company acquired capital stock from Vinccler representing an additional 30% ownership interest in Benton-Vinccler for $3 million in cash, $10 million in non-interest bearing notes payable (with a present value of $9.2 million assuming a 10% interest rate) and 200,000 shares of the Company's common stock. The excess of the purchase price over the net book value of assets acquired was $13,880,100, which was allocated to oil and gas properties. During the year ended December 31, 1994, the Company converted $143,658 of accounts payable into a note payable, financed the purchase of computer equipment in the amount of $105,000 and financed the purchase of oil and gas equipment in the amount of $1,733,675. During the six months ended June 30, 1995, the Company financed the purchase of oil and gas equipment in the amount of $7,029,985 and leased office equipment in the amount of $54,473. During the six months ended June 30, 1995, $117,000 of the Company's 8% convertible notes and $670,000 of the Company's 8% convertible debentures were retired in exchange for 9,975 and 67,768 shares of the Company's common stock, respectively. See notes to consolidated financial statements. F-8 158 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992 AND (UNAUDITED) SIX MONTHS ENDED JUNE 30, 1995 AND 1994 NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization Benton Oil and Gas Company (the "Company") engages in the exploration, development, production and management of oil and gas properties. The Company and its subsidiary Benton Oil and Gas Company of Louisiana, formerly Energy Partners, participate as the managing general partner of three oil and gas limited partnerships formed during 1989 through 1991. Under the provisions of the limited partnership agreements, the Company receives compensation as stipulated therein, and functions as an agent for the partnerships to arrange for the management, drilling, and operation of properties, and assumes customary contingent liabilities for partnership obligations. The consolidated financial statements include the accounts of the Company and its subsidiaries. The Company's investments in limited partnerships, the Russia joint venture ("GEOILBENT") and the Venezuela joint venture (through December 31, 1993) are proportionately consolidated based on the Company's ownership interest. Effective January 1, 1994, the Venezuela joint venture was incorporated and, as a result of the Company's acquisition of additional capital stock of such corporation (See Note 11), has been fully consolidated. All material intercompany profits, transactions and balances have been eliminated. Cash and Cash Equivalents Cash equivalents include money market funds and short term certificates of deposit with original maturity dates of less than three months. Accounts Receivable The Company's accounts receivable are considered fully collectible; therefore, no allowance is considered necessary. Other Assets Other assets consist principally of costs associated with the issuance of long term debt. Debt issue costs are amortized on a straight-line basis over the life of the debt. Property and Equipment The Company follows the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with the acquisition, exploration, and development of oil and gas reserves are capitalized as incurred, including exploration overhead of $1,412,170, $1,736,678 and $1,696,330 for the years ended December 31, 1992, 1993 and 1994, respectively and $784,268 and $1,090,375 for the six months ended June 30, 1994 and 1995, respectively. Only overhead which is directly identified with acquisition, exploration or development activities is capitalized. All costs related to production, general corporate overhead and similar activities are expensed as incurred. The costs of oil and gas properties are accumulated in cost centers on a country by country basis, subject to a cost center ceiling (as defined by the Securities and Exchange Commission). All capitalized costs of oil and gas properties (excluding unevaluated property acquisition and exploration costs) and the estimated future costs of developing proved reserves, are depleted over the estimated useful lives of the properties by application of the unit-of-production method using only proved oil and gas reserves. Depletion expense attributable to the United States cost center for the years ended December 31, 1992, 1993 and 1994 was $2,937,887, $2,142,133 and $4,247,304 ($5.71, $6.47 and $7.46 per equivalent barrel), respectively and for the six months ended June 30, 1994 and 1995 was $1,364,783 and $1,389,665 ($6.51 and F-9 159 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) $7.13 per equivalent barrel), respectively. Depletion expense attributable to the Venezuelan cost center for the years ended December 31, 1993 and 1994 was $229,080 and $4,998,213 ($1.43 and $1.98 per equivalent barrel), respectively and for the six months ended June 30, 1994 and 1995 was $1,627,301 and $4,147,913 ($1.77 and $1.99 per equivalent barrel), respectively. Depletion expense attributable to the Russian cost center for the years ended December 31, 1993 and 1994 was $99,207 and $837,818 ($3.51 and $2.85 per equivalent barrel), respectively and for the six months ended June 30, 1994 and 1995 was $322,175 and $785,008 ($3.42 and $2.87 per equivalent barrel), respectively. Depreciation of furniture and fixtures is computed using the straight-line method, with depreciation rates based upon the estimated useful life applied to the cost of each class of property. Depreciation expense was $65,213, $123,623 and $185,336 for the years ended December 31, 1992, 1993 and 1994, respectively and $72,904 and $143,724 for the six months ended June 30, 1994 and 1995, respectively. Taxes on Income Deferred income taxes reflect the net tax effects, calculated at currently effective rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements and (b) operating loss and tax credit carryforwards. A valuation allowance is recorded, if necessary, to reduce net deferred income tax assets to the amount expected to be recoverable. Foreign Currency Russia and Venezuela are considered highly inflationary economies. Therefore, all foreign operations are remeasured in United States dollars and any currency gains or losses are recorded in the statement of operations. Fair Value of Financial Instruments The Company's financial instruments consist primarily of cash, accounts receivable and payable, commercial paper and other short-term borrowings and debt instruments. In addition, in 1994 the Company entered into a commodity hedge agreement (See Note 15). The book values of all financial instruments, other than debt instruments, are representative of their fair values due to their short-term maturity. The book values of the Company's debt instruments, except the convertible subordinated debentures and notes, are considered to approximate their fair values because the interest rates of these instruments are based on current rates offered to the Company. Based on the last trading on December 31, 1994, the convertible subordinated debentures had a fair value of approximately $6,685,000. There is no active market for the convertible subordinated notes. Based on discounting the future cash flows related to the notes at interest rates currently offered to the Company, approximately 13%, the notes would have a fair value of approximately $3,600,000 at December 31, 1994. The fair value of the hedge agreement is the estimated amount the Company would have to pay to terminate the agreement, taking into account current oil prices and the current creditworthiness of the hedge counterparties. The estimated termination cost associated with the hedge agreement at December 31, 1994 is approximately $1,132,000. Interim Reporting In the opinion of the Company, the accompanying unaudited consolidated financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly the financial position as of June 30, 1995, and the results of operations for the six month periods ended June 30, 1994 and 1995. The results of operations for the six month period ended June 30, 1995 are not necessarily indicative of the results to be expected for the full year. F-10 160 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 2 -- ACQUISITIONS AND SALES In February 1992, the Company sold its interests in its Colorado properties for net proceeds of approximately $0.8 million. Proceeds of the sale were used primarily to repay portions of the Company's long term debt. In March 1992, the Company acquired additional working interests in several oil and gas properties in Louisiana, California and Texas in which the Company already had an interest. The purchase price was approximately $2.7 million. After giving effect to certain closing adjustments, including adjustment of joint interest receivables, the Company issued 213,957 shares of common stock to the seller as full consideration for the acquisition. In September 1992, the Company sold the majority of its interests in its California properties for net proceeds of $2.1 million, which were used to repay debt. In June 1993, the Company sold 50% of its interests in the Belle Isle and Rabbit Island Fields in exchange for reimbursement of certain expenditures incurred through the closing date plus the additional reimbursement of certain future costs as incurred. As of December 31, 1994, $6.5 million of the Company's costs have been reimbursed. Additionally, in May 1993, the Company sold its interest in the South Scott Prospect in Lafayette Parish, Louisiana for $1.5 million. The proceeds from these sales were used for working capital purposes. In March 1994, the Company acquired capital stock from Vinccler representing an additional 30% ownership interest in Benton-Vinccler for $3 million in cash, $10 million in non-interest bearing notes payable (with a present value of $9.2 million assuming a 10% interest rate) payable in various installments over 24 months and 200,000 shares of the Company's common stock. The excess of the purchase price over the book value of the 30% interest was allocated to oil and gas properties. In November 1994, the Company sold a 10.8% working interest (24.9% of the Company's 43.3% working interest) in the West Cote Blanche Bay Field for approximately $5.8 million and future consideration of up to $3.7 million. In March 1995, the Company sold its 32.5% working interest in certain depths (above approximately 10,575 feet) in the West Cote Blanche Bay Field for a purchase price of approximately $14.9 million. The sales price has been reflected as property held for sale at December 31, 1994. In July 1995, the Company sold its interest in the Umbrella Point Field for net proceeds of approximately $0.8 million. The proceeds from the sale will be used for working capital purposes and have been reflected as property held for sale at June 30, 1995. F-11 161 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 3 -- LONG TERM DEBT Long term debt consists of the following:
DECEMBER 31, --------------------------- 1993 1994 ----------- ----------- JUNE 30, 1995 ----------- (UNAUDITED) Senior unsecured notes with interest at 13%. See description below................................. $20,000,000 Senior unsecured notes with interest at 13%. See description below................................. $15,000,000 15,000,000 Revolving secured credit facility. Interest payments due quarterly beginning March 31, 1995. Principal payments due quarterly beginning March 31, 1997. See description below. ........................... 5,000,000 5,000,000 Convertible subordinated debentures with interest at 8%. See description below......................... $ 6,428,000 6,428,000 5,758,000 Convertible subordinated notes with interest at 8%. See description below............................. 4,662,000 4,662,000 4,545,000 Non-interest bearing promissory notes payable with a face value of $6 million at December 31, 1994 and $2 million at June 30, 1995, discounted using a 10% interest rate. The notes are due in various installments through January 1996. See Note 11.... 5,747,878 1,926,933 Vendor financing with interest at 13.5%. Principal and interest payments in monthly installments of $200,000. Unsecured............................... 1,703,082 Bank financing with interest at LIBOR plus 7.5%. Secured by certain GEOILBENT oil export proceeds. See description below............................. 1,292,000 1,564,000 Vendor financing with interest ranging from 10.5 to 13.5%. Principal and interest payments are due in varying installments through June 1997. Unsecured......................................... 5,200,106 Other -- various equipment purchases and leases with principal and interest payments due monthly from $180 to $3,916. Interest rates vary from 10.0% to 16.91%. Notes and leases mature from August 1995 to February 1998..................................... 200,399 173,400 167,374 ----------- ----------- ----------- 12,993,481 38,303,278 59,161,413 Less current portion................................ 1,205,107 6,392,114 5,893,160 ----------- ----------- ----------- $11,788,374 $31,911,164 $53,268,253 ========== ========== ==========
On June 30, 1995, the Company issued $20 million in senior unsecured notes due June 30, 2007, with interest at 13% per annum, payable semi-annually on June 30 and December 31. Annual principal payments of $4 million are due on June 30 of each year beginning on June 30, 2003. Early payment of the notes could result in a substantial prepayment penalty. The note agreement contains financial covenants including a minimum ratio of current assets to current liabilities and a maximum ratio of funded liabilities to net worth and to domestic and certain Venezuelan oil and gas reserves. The note agreement also provides for limitations on liens, additional indebtedness, certain capital expenditures, dividends, sales of assets and mergers. Additionally, in connection with the issuance of the notes, the Company issued warrants entitling the holder to purchase 125,000 shares of common stock at $17.09 per share, subject to adjustment in certain circumstances, that are exercisable on or before June 30, 2007. F-12 162 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) On September 30, 1994, the Company issued $15 million in senior unsecured notes due September 30, 2002, with interest at 13% per annum. Interest is payable semi-annually on March 30 and September 30 beginning March 30, 1995. Annual principal payments of $3 million are due on September 30 of each year beginning on September 30, 1998. Early payment of the notes could result in a substantial prepayment penalty. The note agreement contains financial covenants including a minimum ratio of current assets to current liabilities and a maximum ratio of liabilities to net worth or domestic oil and gas reserves. The note agreement also provides for limitations on liens, additional indebtedness, certain capital expenditures, dividends, sales of assets and mergers. Additionally, in connection with the issuance of the notes, the Company issued warrants entitling the holder to purchase 250,000 shares of common stock at $9.00 per share, subject to adjustment in certain circumstances, that are exercisable on or before September 30, 2002. On December 27, 1994, the Company entered into a revolving secured credit facility. Under the credit agreement, the Company may borrow up to $15 million, with the initial available principal limited to $10 million, on a revolving basis for two years, at which time the facility will become a term loan due December 31, 1999. Borrowings under the credit agreement are secured in part by mortgages on the Company's U.S. properties and in part by a guarantee provided by the financial institution which arranged the credit facility. Interest on borrowings under the credit agreement accrues, at the Company's option, at either a floating rate (higher of prime rate plus 3% or the Federal Funds Rate plus 5%) or a fixed rate (rate of interest at which deposits of dollars are available to lender in the interbank eurocurrency market plus 4.5%). The floating rate borrowings may be prepaid at any time without penalty and the fixed rate borrowings may be repaid on the last day of an interest period without penalty, or at the option of the Company during an interest period upon payment of a make-whole premium. The credit agreement contains financial covenants including a minimum ratio of current assets to current liabilities and maximum ratio of liabilities to net worth or domestic oil and gas reserves, and also provides for limitations on liens, dividends, sales of assets and mergers. Additionally, in exchange for the credit enhancement, the arranging financial institution and commercial bank received warrants entitling the holder to purchase 50,000 shares of common stock at $12.00 per share, subject to adjustment in certain circumstances, that are exercisable on or before December 2004, and the arranging institution receives a 5% net profits interest in the Company's properties whose development is financed by the facility. In May 1992, the Company issued $6,428,000 aggregate principal amount of publicly offered 8% Convertible Subordinated Debentures due May 1, 2002, convertible at the option of the holder at 101.157 shares per $1,000 principal amount with interest payments due May 1 and November 1. Net proceeds to the Company were approximately $5,711,000 and were used primarily to repay certain indebtedness. At the Company's option, it may redeem the debentures in whole or in part at any time on or after May 1, 1994, at 105% of par plus accrued interest, declining annually to par on May 1, 1999. The debentures also provide that the holders can redeem their debentures following a change in control (as defined) of the Company. The Company has the option to pay the repurchase price in cash or shares of its common stock. In October 1991, the Company issued $4,662,000 aggregate principal amount of privately placed 8% Convertible Subordinated Notes ("Notes") due October 1, 2001, convertible at the option of the note holder at 85.259 shares per $1,000 principal amount with interest payments due April 1 and October 1. Net proceeds to the Company were approximately $4,237,000. At the Company's option it may prepay the Notes in whole or in part at any time on or after October 1, 1993 at 105% of the principal amount plus accrued interest declining annually to the principal amount on October 1, 1998. The Notes also provide that the holders can redeem their Notes in cash following a change in control (as defined) of the Company. In August 1994, GEOILBENT entered into an agreement with International Moscow Bank for a $4 million loan with the following terms: 14 monthly payments, interest at LIBOR plus 7.5%, with interest only payments for the first four months and monthly principal and interest payments thereafter. In connection with this agreement, the Company provided to International Moscow Bank a guarantee of payment under F-13 163 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) which the Company has agreed to pay such loan in full if GEOILBENT fails to make the scheduled payments. At December 31, 1994, the Company's share of the outstanding balance was $1.3 million. In March 1995, GEOILBENT's credit facility with International Moscow Bank was expanded to $6 million, with interest only payments for 3 months and monthly principal and interest payments thereafter. The Company has similarly guaranteed this indebtedness, through which the Company intends to fulfill substantially all of its remaining charter fund contribution requirements. At June 30, 1995, the Company's share of the outstanding balance was $1.6 million. The principal requirements for the long term debt outstanding at December 31, 1994 are due as follows for the years ending December 31: 1995............................................................ $ 6,392,114 1996............................................................ 801,378 1997............................................................ 1,686,100 1998............................................................ 4,667,020 1999............................................................ 4,666,666 Subsequent Years................................................ 20,090,000 ----------- $38,303,278 ==========
NOTE 4 -- COMMERCIAL PAPER AND OTHER SHORT TERM BORROWINGS In February 1994, Benton-Vinccler borrowed $15 million from Morgan Guaranty Trust Company of New York ("Morgan Guaranty"). Benton-Vinccler subsequently borrowed from the same bank an additional $7 million for working capital requirements. Benton-Vinccler made a payment of $2.75 million in September 1994, leaving a balance of $19.25 million. The credit facility is collateralized in full by time deposits from the Company, bears interest at LIBOR plus 3/4%, and is renewed on a monthly basis. The loan arrangement contains no restrictive covenants and no financial ratio covenants. During the fourth quarter of 1994 and the first six months of 1995, Benton-Vinccler acquired approximately $3.4 million of drilling and production equipment from trading companies and suppliers under terms which include payment within a 12-month period in monthly and quarterly installments at interest rates from 6.7% to 10.75%. The outstanding balances related to these transactions at both December 31, 1994 and June 30, 1995 were approximately $1.5 million. In June 1994, GEOILBENT entered into a payment advance agreement with NAFTA Moscow, the export agency which markets GEOILBENT's oil production to purchasers in Europe. The payment advance of $2.5 million against future oil shipments, which bore an effective discount rate of 12%, was repaid through withholdings from oil sales on a monthly basis through December 1994. During the quarter ended March 31, 1995, GEOILBENT received $3.0 million in production payment advances pursuant to a similar agreement with NAFTA Moscow containing similar terms. At June 30, 1995, the Company's share of the outstanding liability was approximately $0.5 million. NOTE 5 -- COMMITMENTS AND CONTINGENCIES The state leases relating to the West Cote Blanche Bay Field, the portion of the Belle Isle Field owned by Texaco and the Rabbit Island Field, were the subject of litigation between Texaco and the State of Louisiana. The Company's interests in the Fields, which include substantially all of the Company's domestic reserves, were originally owned by Texaco under certain leases granted by the State. Although the Company was not a party to this litigation, its interests in the Fields were subject to the litigation. In February 1994, the State and Texaco entered into a Global Settlement Agreement to settle all disputes related to this litigation. As a result of this agreement, Texaco has committed to certain acreage development and drilling obligations which may F-14 164 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) affect the Company and certain of its Louisiana properties. The Company believes that the settlement should have no effect on its proved reserves and should have no material adverse effect on the Company. In the normal course of its business, the Company may periodically become subject to actions threatened or brought by its investors or partners in connection with the operation or development of its properties or the sale of securities. Prior to 1992, the Company was engaged in the formation and operation of oil and gas limited partnership interests. In 1992, the Company ceased raising funds through such sales. In connection with its role as managing general partner of certain limited partnerships, the Company may become subject to actions brought by limited partners of these partnerships. Certain of such limited partners have brought an action against the Company in connection with the Company's operations of several of the limited partnerships in which it acted as managing general partner. The plaintiffs seek actual and punitive damages for alleged actions and omissions by the Company in operating the partnerships and alleged misrepresentations made by the Company in selling the limited partnership interests. The plaintiff's representative and the Company have entered into an arbitration agreement to resolve these issues. The Company is also a defendant in an action brought by investors in a series of unaffiliated limited partnerships for whose general partner the Company provided all or a substantial portion of the drilling prospects and drilled and operated a number of wells. The plaintiffs allege that the Company aided the general partner in misrepresentations, fraud and breaches of fiduciary duties, and seek an unspecified amount of compensatory and punitive damages. The Company intends to vigorously defend these actions and does not believe the claims raised are meritorious. However, new developments could alter this conclusion at any time. The Company will be forced to expend time and financial resources to defend or resolve all such matters. The Company is also subject to ordinary litigation that is incidental to its business. None of the above matters are expected to have a material adverse effect on the Company. The Company's aggregate rental commitments and related sub-leases, for noncancellable agreements at December 31, 1994, are as follows:
RENTAL COMMITMENTS SUB-LEASES ----------- ---------- 1995.................................................... $ 449,618 $ (119,090) 1996.................................................... 427,751 (143,027) 1997.................................................... 307,764 1998.................................................... 303,640 1999.................................................... 302,504 Thereafter.............................................. 1,543,260 ----------- ---------- $3,334,537 $ (262,117) ========== =========
Rental expense was $222,279, $233,934 and $255,650 for the years ended December 31, 1992, 1993 and 1994, respectively. F-15 165 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 6 -- TAXES ON INCOME The tax effects of significant items comprising the Company's net deferred income taxes as of December 31, 1993 and 1994 are as follows:
1993 1994 ----------- ----------- Deferred tax assets: Operating loss carryforwards............................ $10,926,000 $12,950,000 Foreign tax credit carryforwards........................ 549,000 Valuation allowance....................................... (7,000,000) (5,324,000) ----------- ----------- Total..................................................... 3,926,000 8,175,000 ----------- ----------- Deferred tax liabilities: Difference in basis of property......................... 3,926,000 4,145,000 Undistributed earnings of foreign subsidiaries.......... 4,030,000 ----------- ----------- Total..................................................... 3,926,000 8,175,000 ----------- ----------- Net deferred tax liability................................ $ -- $ -- ========== ==========
A comparison of the income tax expense at the federal statutory rate to the Company's provision for income taxes is as follows:
1992 1993 1994 ----------- ----------- ----------- Income (loss) before income taxes: United States..................................... $(2,909,000) $(2,988,000) $(4,363,000) Foreign........................................... (1,841,000) 10,109,000 ----------- ----------- ----------- Total.......................................... $(2,909,000) $(4,829,000) $ 5,746,000 ========== ========== ========== Computed tax expense at the statutory rate........ $ (990,000) $(1,690,000) $ 2,011,000 State income taxes, net of federal effect......... 287,000 Other............................................. 76,000 Change in valuation allowance..................... 990,000 1,690,000 (1,676,000) ----------- ----------- ----------- Provision for income taxes........................ $ -- $ -- $ 698,000 ========== ========== ==========
The provision for income taxes for 1994 consists primarily of foreign income taxes currently payable. The Company is providing for deferred income taxes on undistributed earnings of foreign subsidiaries. The Company has provided a valuation allowance for the excess benefits of operating loss and tax credit carryforwards. As of December 31, 1994, the Company had, for federal income tax purposes, operating loss carryforwards of approximately $32.4 million, expiring in the years 2003 through 2009. If the carryforwards are ultimately realized, approximately $3.0 million will be credited to additional paid-in capital for tax benefits associated with deductions for income tax purposes related to stock options. The Company has available approximately $12.4 million and approximately $1.5 million of net operating loss carryforwards for state and foreign income tax purposes, respectively. NOTE 7 -- STOCK OPTIONS The Company adopted its 1988 Stock Option Plan in December 1988 authorizing options to acquire up to 418,824 shares of common stock. Under the plan, incentive stock options were granted to key employees and other options, stock or bonus rights were granted to key employees, directors, independent contractors and consultants at prices equal to or below market price, exercisable over various periods. F-16 166 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company adopted its 1989 Nonstatutory Stock Option Plan during 1989 covering 2,000,000 shares of common stock which were granted to key employees, directors, independent contractors and consultants at prices equal to or below market prices, exercisable over various periods. The plan was amended during 1990 to add 1,960,000 shares of common stock to the plan. As shares became exercisable under the 1988 and 1989 plans, the Company recorded compensation expense (a portion of which is associated with exploration overhead and is therefore capitalized) to the extent that the market price on the date of grant exceeded the option price. For years ended December 31, 1993 and 1992, compensation expense of $142,420 and $329,103, respectively, has been recorded. In September 1991, the Company adopted the 1991-1992 Stock Option Plan and the Directors' Stock Option Plan. The 1991-1992 Stock Option Plan permits the granting of stock options to purchase up to 2,500,000 shares of the Company's common stock in the form of incentive stock options ("ISOs") and nonqualified stock options ("NQSOs") to officers and employees of the Company. Options may be granted as ISOs, NQSOs or a combination of each, with exercise prices not less than the fair market value of the common stock on the date of the grant. The amount of ISOs that may be granted to any one participant is subject to the dollar limitations imposed by the Internal Revenue Code of 1986, as amended. In the event of a change in control of the Company, all outstanding options become immediately exercisable to the extent permitted by the 1991-1992 Stock Option Plan. All options granted to date under the 1991-1992 Stock Option Plan vest ratably over a three-year period from their dates of grant. The Directors' Stock Option Plan permits the granting of nonqualified stock options ("Director NQSOs") to purchase up to 200,000 shares of common stock to nonemployee directors of the Company. Upon election as a director and annually thereafter, each individual who serves as a nonemployee director automatically is granted an option to purchase 10,000 shares of common stock at a price not less than the fair market value of common stock on the date of grant. All Director NQSOs vest automatically on the date of the grant of the options.
1989 NONSTATUTORY 1988 STOCK OPTION PLAN STOCK OPTION PLAN ------------------------------------- ---------------------------------------- OPTION OPTION CURRENTLY OPTION OPTION CURRENTLY PRICES SHARES EXERCISABLE PRICES SHARES EXERCISABLE --------------- -------- ----------- ---------------- ---------- ----------- Balance at January 1, 1992......... $1.17 to $4.89 329,967 196,631 $1.39 to $11.75 2,390,332 1,206,999 ========== ========== Options exercised.................. $1.17 to $1.97 (216,334) $1.39 to $4.89 (1,138,186) -------- ---------- Balance at December 31, 1992....... 113,633 113,633 1,252,146 852,148 ========== ========== Options cancelled.................. $2.55 (40,000) Options exercised.................. $1.17 (33,633) $1.39 to $4.89 (250,579) -------- ---------- Balance at December 31, 1993....... 80,000 80,000 961,567 951,567 ========== ========== Options exercised.................. $2.81 to $4.89 (23,000) -------- ---------- Balance at December 31, 1994....... $4.89 80,000 80,000 $1.39 to $11.75 938,567 938,567 ========= ========== ========== ==========
F-17 167 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
1991-1992 STOCK OPTION PLAN DIRECTORS' STOCK OPTION PLAN ---------------------------------------- ------------------------------------- OPTION OPTION CURRENTLY OPTION OPTION CURRENTLY PRICES SHARES EXERCISABLE PRICES SHARES EXERCISABLE ----------------- --------- ----------- ---------------- ------- ----------- Balance at January 1, 1992.......... $10.125 328,000 $10.125 30,000 -- Options granted..................... $5.25 to $8.75 510,000 $6.25 to $10.25 50,000 --------- ------- Balance at December 31, 1992........ 838,000 109,334 80,000 9,999 ========== ========== Options granted..................... $8.13 to $8.75 345,000 $7.00 40,000 Options cancelled................... $7.75 to $10.125 (70,000) --------- ------- Balance at December 31, 1993........ 1,113,000 365,332 120,000 36,667 ========== ========== Options granted..................... $5.63 to $9.125 885,000 $6.813 40,000 Options cancelled................... $10.125 (3,000) --------- ------- Balance at December 31, 1994........ $5.50 to $10.125 1,995,000 733,334 $6.25 to $10.25 160,000 160,000 ========= ========== ======== ==========
In addition to options issued pursuant to the plans, options for 80,000, 135,000 and 19,000 shares of common stock were issued in 1994, 1993 and 1992, respectively, to individuals other than officers, directors or employees of the Company at prices ranging from $5.63 to $10.25. The options vest over three to four years and at December 31, 1994, 76,000 options were vested. NOTE 8 -- STOCK WARRANTS During the years ended December 31, 1991, 1992 and 1994, the Company issued a total of 690,793, 658,617 and 450,000 warrants, respectively. Each warrant entitles the holder to purchase one share of common stock at the exercise price of the warrant. Substantially all the warrants are immediately exercisable upon issuance. In April 1991, 655,813 warrants were issued in connection with the privately placed sale of the Company's common stock. In October 1991, the Company issued 34,980 warrants to a placement agent who marketed the Company's 8% convertible subordinated notes. In January 1992, 29,841 warrants were issued to a placement agent who sold shares in the public offering of the Company's stock. In February 1992, 37,118 warrants were issued in connection with the marketing of working interests in a well the Company drilled. Also in February 1992, 25,000 warrants were issued in connection with an acquisition of a working interest in a well. In April 1992, 31,400 warrants were issued to a placement agent who marketed the Company's 8% convertible subordinated debentures and in July 1992, 5,000 warrants were issued to a consultant to the Company of which 2,500 were exercised during the year ended December 31, 1993. The Company was the managing general partner of two limited partnerships that were liquidated in November 1992. In October 1992, 530,258 warrants were issued to the partners in these partnerships in connection with the liquidation. In September 1994, 250,000 warrants were issued in connection with the issuance of $15 million in senior unsecured notes and in December 1994, 50,000 warrants were issued in connection with a revolving secured credit facility. F-18 168 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In July 1994, the Company issued warrants entitling the holder to purchase a total of 150,000 shares of common stock at $7.50 per share, subject to adjustment in certain circumstances, that are exercisable on or before July 2004. 50,000 warrants were immediately exercisable, and 50,000 warrants become exercisable each July in 1995 and 1996. The dates the warrants were issued, the expiration dates, the exercise prices and the number of warrants issued and outstanding at December 31, 1994 were:
DATE ISSUED EXPIRATION DATE EXERCISE PRICE ISSUED OUTSTANDING - -------------- --------------- -------------- --------- ----------- April 1991 April 1996 $14.41* 592,786 592,786 April 1991 April 1996 11.56* 63,027 63,027 October 1991 October 1996 14.07 34,980 34,980 January 1992 January 1997 12.03 29,841 29,841 February 1992 February 1997 14.63* 37,118 37,118 February 1992 February 1997 9.00 25,000 25,000 April 1992 April 1997 10.30 31,400 31,400 July 1992 July 1997 7.30 5,000 2,500 October 1992 October 1997 10.00 530,258 530,258 July 1994 July 2004 7.50 150,000 150,000 September 1994 September 2002 9.00 250,000 250,000 December 1994 December 2004 12.00 50,000 50,000 --------- ----------- 1,799,410 1,796,910 ======== =========
- --------------- * Price represents weighted average price. NOTE 9 -- REDEEMABLE COMMON STOCK On July 7, 1992, the Company issued 351,088 shares of Redeemable common stock valued at $2,582,050. In connection with the stock issuance, the Company guaranteed that proceeds from the resale of the shares of common stock by the holders would be $2,582,050 plus accrued interest by July 1, 1993. During the period ended December 31, 1992, 27,000 shares were resold for net proceeds of $180,919, and the Company made cash payments of $319,081. During the six months ended June 30, 1993, 272,828 shares were resold for net proceeds to the selling stockholders of $2,022,323, and the Company made cash payments of $200,000, terminating the Company's guarantee obligation. The Company redeemed the remaining 51,260 shares on May 19, 1993 at their par value of $0.01 per share. NOTE 10 -- RUSSIA JOINT VENTURE In December 1991, a joint venture agreement forming GEOILBENT, Limited, between the Company and two Russian partners, Purneftegasgeologia and Purneftegas, was approved by the appropriate regulatory bodies in Russia. GEOILBENT's charter is to explore, develop, produce and market oil, condensate and natural gas from the North Gubkinskoye field in the West Siberia region of Russia, approximately two thousand miles northeast of Moscow. At the time of GEOILBENT's formation, the field, which covers an area approximately 15 miles long and 4 miles wide, had been delineated with over 60 wells, had been production tested and had logged numerous oil and gas sands, but had never been commercially produced. The joint venture agreement calls for the Company to have a 34% working interest and the two Russian partners each to have a 33% working interest in the joint venture. Production commenced during the third quarter of 1993. The Company is obligated under the terms of the GEOILBENT charter agreement with its partners to make contributions of approximately $25.8 million by December 31, 1995. At December 31, 1994, the Company's contributions totaled approximately $19.4 million. During the first part of 1994, a combination of volatile crude oil prices and a relatively high export tariff, among other factors, constrained the pace of F-19 169 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) development of the field by GEOILBENT. For the year ended December 31, 1994, the Company recorded an expense for the export tariff of $1,397,317 which is included in lease operating expenses and production taxes. In September 1994, GEOILBENT received a recommendation from the Interdepartmental Commission of the Ministry of Fuel and Energy for a waiver for one year from the export tariff. Such waiver was received in March 1995, effective retroactively to January 1, 1995. GEOILBENT expects to apply for renewal of the waiver for 1996 and 1997. The export tariff was reduced from 30 ECUs per ton to 20 ECUs per ton for 1995, and there have been certain discussions regarding further reductions in the future. However, the Russian regulatory environment continues to be volatile and the Company is unable to predict the availability of the waiver during the remainder of 1995 or for the future. The Company continues to evaluate the economic and political environment in Russia to assess the potential effect on the Company and its Russian operations. NOTE 11 -- VENEZUELA JOINT VENTURE On July 31, 1992, the Company and its partner, Venezolana de Inversiones y Construcciones Clerico, C.A. ("Vinccler"), signed an operating service agreement to reactivate and further develop three Venezuelan oil fields with Lagoven, S.A., an affiliate of the national oil company, Petroleos de Venezuela, S.A. The operating service agreement covers the Uracoa, Bombal and Tucupita fields that comprise the South Monagas unit. Under the terms of the operating service agreement, Benton-Vinccler, a corporation owned 80% by the Company and 20% by Vinccler, is a contractor for Lagoven and is responsible for overall operations of the South Monagas unit, including all necessary investments to reactivate and develop the fields comprising the unit. Benton-Vinccler receives an operating fee in U.S. dollars deposited into a U.S. commercial bank account for each barrel of crude oil produced (subject to periodic adjustments to reflect changes in a special energy index of the U.S. Consumer Price Index) and is reimbursed according to a prescribed formula in U.S. dollars for its capital costs, provided that such operating fee and cost recovery fee cannot exceed the maximum dollar amount per barrel set forth in the agreement (which amount is periodically adjusted to reflect changes in the average of certain world crude oil prices). The Venezuelan government maintains full ownership of all hydrocarbons in the fields. Pursuant to the original joint venture agreement, the Company and Vinccler each owned a 50% interest in a joint venture which operated the South Monagas unit. Effective January 1, 1994, the operating service agreement and the joint venture assets and liabilities were transferred to Benton-Vinccler, a corporation in which the Company and Vinccler each owned 50% of the capital stock. On March 4, 1994, the Company acquired capital stock from Vinccler representing an additional 30% ownership interest in Benton-Vinccler for $3 million in cash, $10 million in non-interest bearing notes payable (with a present value of $9.2 million assuming a 10% interest rate) payable in various installments over 24 months and 200,000 shares of the Company's common stock. The excess of the purchase price over the book value of the 30% interest was allocated to oil and gas properties. Prior to the acquisition of the additional 30% interest in Benton-Vinccler, the Company's interest in the Venezuelan joint venture was proportionately consolidated based on its ownership interest. Effective with the acquisition of the additional 30% interest in Benton-Vinccler, the Company has included Benton-Vinccler in its consolidated financial statements, with the 20% owned by Vinccler reflected as a minority interest. F-20 170 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following unaudited pro forma data represents the results of operations for the Company for the year ended December 31, 1993 and 1994 as though the acquisition of the 30% interest had been completed and Benton-Vinccler had been consolidated as of January 1, 1993 and 1994, respectively.
1993 1994 ----------- ----------- REVENUES........................................................... $ 8,881,674 $34,766,997 ----------- ----------- EXPENSES Lease operating costs and production taxes.............................................. 6,274,717 9,531,264 Depletion, depreciation and amortization......................... 2,967,221 10,298,112 General and administrative....................................... 3,092,499 5,241,295 Interest......................................................... 3,412,100 4,141,653 ----------- ----------- 15,746,537 29,212,324 ----------- ----------- Income (loss) before income taxes and minority interest............ (6,864,863) 5,554,673 Income taxes....................................................... 697,802 ----------- ----------- Income (loss) before minority interest............................. (6,864,863) 4,856,871 Minority interest.................................................. (411,551) 2,085,392 ----------- ----------- Net income (loss).................................................. $(6,453,312) $ 2,771,479 ========== ========== Net income (loss) per common share................................. $ (0.34) $ 0.11 ========== ==========
NOTE 12 -- RELATED PARTY TRANSACTIONS On December 31, 1993, the Company guaranteed a loan made to Mr. A.E. Benton, its President and Chief Executive Officer for $300,000. In January 1994, the Company loaned $800,000 to Mr. Benton with interest at prime plus 1% payable in November 1995, or on demand by the Company, whichever occurs first; in September 1994, Mr. Benton made a payment of $207,014 against this loan. NOTE 13 -- EARNINGS (LOSS) PER SHARE Primary earnings per common share are computed by dividing net income (loss) by the weighted average number of common and common equivalent shares outstanding. Common equivalent shares are shares which may be issuable upon exercise of outstanding stock options and warrants; however, they are not included in the computation for the years ended December 31, 1992 and 1993, since their effect would be to reduce the net loss per share and for the year ended December 31, 1994, because their effect would result in dilution of less than 3%. Total weighted average shares outstanding during the years ended December 31, 1992, 1993 and 1994 were 12,981,105, 18,608,770 and 24,850,922, respectively. Total weighted average common and common equivalent shares outstanding during the six months ended June 30, 1994 and 1995 were 25,153,248 and 26,459,123, respectively. Fully diluted earnings per common share are not presented since the conversion of the Company's 8% Convertible Subordinated Notes and 8% Convertible Subordinated Debentures would have an anti-dilutive effect. NOTE 14 -- MAJOR CUSTOMERS The Company is principally involved in the business of oil and gas exploration and production. Oil and gas purchasers that represent more than 10% of oil and gas revenues for the year ended December 31, 1994 were Lagoven, S.A. (67%) and Texon Corporation (10%); for the year ended December 31, 1993 were Texon Corporation (63%) and Lagoven, S.A. (18%); and for the year ended December 31, 1992 were Plains Marketing and Transportation, Inc. formerly Sunnybrook Transmission, Inc. (60%) and Texon Corporation (11%). F-21 171 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 15 -- OIL AND GAS ACTIVITIES Total costs incurred in oil and gas acquisition, exploration and development activities were:
VENEZUELA UNITED STATES RUSSIA TOTAL ----------- ------------- ----------- ------------ YEAR ENDED DECEMBER 31, 1992 Property acquisition costs........ $ 880,937 $ 3,182,151 $ 3,012,615 $ 7,075,703 Development costs................. 511,982 3,090,966 4,093,933 7,696,881 Exploration costs................. 1,980,546 1,980,546 ----------- ------------- ----------- ------------ $ 1,392,919 $ 8,253,663 $ 7,106,548 $ 16,753,130 ========== =========== ========== =========== YEAR ENDED DECEMBER 31, 1993 Property acquisition costs........ $ 380,178 $ 380,178 Development costs................. $ 6,307,756 2,149,632 $10,483,807 18,941,195 Exploration costs................. 373,348 6,258,127 6,631,475 ----------- ------------- ----------- ------------ $ 6,681,104 $ 8,787,937 $10,483,807 $ 25,952,848 ========== =========== ========== =========== YEAR ENDED DECEMBER 31, 1994 Property acquisition costs........ $13,446,757 $ 875,129 $ 14,321,886 Development costs................. 24,676,748 2,993,728 $ 8,654,730 36,325,206 Exploration costs................. 265,856 2,542,935 2,808,791 ----------- ------------- ----------- ------------ $38,389,361 $ 6,411,792 $ 8,654,730 $ 53,455,883 ========== =========== ========== ===========
The Company's aggregate amount of capitalized costs related to oil and gas producing activities consists of the following at December 31:
VENEZUELA UNITED STATES RUSSIA TOTAL ----------- ------------- ----------- ------------ DECEMBER 31, 1993 Proved property costs............. $ 8,074,023 $ 40,197,929 $16,832,410 $ 65,104,362 Costs excluded from amortization................... 9,551,744 2,423,871 11,975,615 Less accumulated depletion........ (229,080) (9,031,202) (99,207) (9,359,489) ----------- ------------ ----------- ------------ $ 7,844,943 $ 40,718,471 $19,157,074 $ 67,720,488 =========== ============ =========== ============ DECEMBER 31, 1994 Proved property costs............. $46,523,663 $ 27,508,414 $25,482,193 $ 99,514,270 Costs excluded from amortization................... 6,743,012 7,523,454 2,428,818 16,695,284 Less accumulated depletion........ (5,227,293) (13,278,505) (937,025) (19,442,823) ----------- ------------ ----------- ------------ $48,039,382 $ 21,753,363 $26,973,986 $ 96,766,731 =========== ============ =========== ============
The Company regularly evaluates its unproved properties to determine whether impairment has occurred. The Company has excluded from amortization its interest in unproved properties, the cost of uncompleted exploratory activities, and portions of major development costs. Costs excluded from amortization at December 31, 1994 totalled $16,695,284, including $6,743,012 related to Venezuela, $3,398,505 related to West Cote Blanche Bay, $1,569,255 related to Belle Isle, $2,113,609 related to Rabbit Island, $2,428,818 related to Russia, and $442,085 related to other prospects. The principal portion of such costs are expected to be included in amortizable costs during the next four years. Excluded costs at December 31, 1994 consisted of the following by year incurred:
PRIOR TO 1992 1992 1993 1994 TOTAL ------------- ---------- ---------- ---------- ----------- Property acquisition costs......... $ 3,091,936 $ 564,829 $ 7,164 $ 4,947 $ 3,668,876 Development costs.................. 1,802,000 6,743,012 8,545,012 Exploration costs.................. 1,161,964 623,725 1,943,823 751,884 4,481,396 ------------- ---------- ---------- ---------- ----------- $ 4,253,900 $1,188,554 $3,752,987 $7,499,843 $16,695,284 ========== ========= ========= ========= ==========
F-22 172 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Results of operations for oil and gas producing activities were:
VENEZUELA UNITED STATES RUSSIA TOTAL ----------- ------------- ---------- ----------- YEAR ENDED DECEMBER 31, 1992 Oil and gas revenues................... $ 8,209,134 Expenses: Lease operating costs and production taxes.................. 4,413,620 Depletion............................ 2,937,887 ------------- Total expenses.................... 7,351,507 ------------- Results of operations from oil and gas producing activities................. $ 857,627 ========== YEAR ENDED DECEMBER 31, 1993 Oil and gas revenues................... $ 1,332,927 $ 5,565,455 $ 323,928 $ 7,222,310 Expenses: Lease operating costs and production taxes.................. 1,164,453 3,487,510 458,301 5,110,264 Depletion............................ 229,080 2,142,133 99,207 2,470,420 ----------- ------------- ---------- ----------- Total expenses.................... 1,393,533 5,629,643 557,508 7,580,684 ----------- ------------- ---------- ----------- Results of operations from oil and gas producing activities................. $ (60,606) $ (64,188) $ (233,580) $ (358,374) ========== ========== ========= ========== YEAR ENDED DECEMBER 31, 1994 Oil and gas revenues................... $21,472,015 $ 6,957,855 $3,512,940 $31,942,810 Expenses: Lease operating costs and production taxes.................. 3,807,434 2,891,209 2,832,621 9,531,264 Depletion............................ 4,998,213 4,247,303 837,818 10,083,334 ----------- ------------- ---------- ----------- Total expenses.................... 8,805,647 7,138,512 3,670,439 19,614,598 ----------- ------------- ---------- ----------- Results of operations from oil and gas producing activities................. $12,666,368 $ (180,657) $ (157,499) $12,328,212 ========== ========== ========= ==========
In May 1994, the Company entered into a commodity hedge agreement designed to reduce a portion of the Company's risk from oil price movements. Pursuant to the hedge agreement, the Company will receive $16.82 per Bbl and will pay the average price per Bbl of West Texas Intermediate Light Sweet Crude Oil. Such payments will be made with respect to production of 1,000 Bbl of oil per day for 1994, 1,250 Bbl of oil per day in 1995 and 1,500 Bbl of oil per day for 1996. During the year ended December 31, 1994, the Company incurred losses of $328,868 under the hedge agreement. The Company is exposed to credit loss in the event of non-performance by the counterparty. The Company anticipates, however, that the counterparty will be able to fully satisfy its obligation under the contract. Quantities of Oil and Gas Reserves (unaudited) Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. All Venezuelan reserves are attributable to an operating service agreement between the Company and Lagoven, S.A., under which all mineral rights are owned by the government of Venezuela. Sales of reserves in place in 1994 include reserves related to the United States properties sold in March 1995 (See Note 2). The evaluations of the oil and gas reserves as of December 31, 1992, 1993 and 1994 were audited by Huddleston & Co., Inc., independent petroleum engineers. F-23 173 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
MINORITY UNITED INTEREST IN VENEZUELA STATES RUSSIA TOTAL VENEZUELA NET TOTAL --------- ------- ------ ------- ----------- --------- PROVED RESERVES -- CRUDE OIL, CONDENSATE, AND GAS LIQUIDS (MBBLS) YEAR ENDED DECEMBER 31, 1992 Proved reserves beginning of the year......... 13,007 8,137 21,144 21,144 Revisions of previous estimates............... 278 (4 ) 274 274 Purchases of reserves in place................ 8,966 579 9,545 9,545 Extensions, discoveries and improved recovery.................................... 42 42 42 Production.................................... (376) (376) (376) Sales of reserves in place.................... (336) (336) (336) --------- ------- ------ ------- ----------- --------- Proved reserves end of year................... 8,966 13,194 8,133 30,293 0 30,293 ========= ======= ====== ======= ========= ========= YEAR ENDED DECEMBER 31, 1993 Proved reserves beginning of the year......... 8,966 13,194 8,133 30,293 30,293 Revisions of previous estimates............... 32 (2,490) 259 (2,199) (2,199) Extensions, discoveries and improved recovery.................................... 10,551 132 1,757 12,440 12,440 Production.................................... (160) (292) (28 ) (480) (480) Sales of reserves in place.................... (286) (286) (286) --------- ------- ------ ------- ----------- --------- Proved reserves end of year................... 19,389 10,258 10,121 39,768 0 39,768 ========= ======= ====== ======= ========= ========= YEAR ENDED DECEMBER 31, 1994 Proved reserves beginning of the year......... 19,389 10,258 10,121 39,768 39,768 Revisions of previous estimates............... (2,583) 1,819 (201 ) (965) 517 (448) Purchases of reserves in place................ 19,389 19,389 (7,756) 11,633 Extensions, discoveries and improved recovery.................................... 27,032 152 7,914 35,098 (5,406) 29,692 Production.................................... (2,520) (226) (294 ) (3,040) 504 (2,536) Sales of reserves in place.................... (11,770) (11,770) (11,770) --------- ------- ------ ------- ----------- --------- Proved reserves end of year................... 60,707 233 17,540 78,480 (12,141) 66,339 ========= ======= ====== ======= ========= ========= PROVED DEVELOPED RESERVES AT: January 1, 1992............................... 8,233 8,233 8,233 December 31, 1992............................. 2,269 10,905 13,174 13,174 December 31, 1993............................. 3,999 8,153 400 12,552 12,552 December 31, 1994............................. 12,580 155 2,772 15,507 (2,516) 12,991 PROVED RESERVES -- NATURAL GAS (MMCF) YEAR ENDED DECEMBER 31, 1992 Proved reserves beginning of the year......... 25,343 25,343 25,343 Revisions of previous estimates............... 286 286 286 Purchases of reserves in place................ 797 797 797 Extensions, discoveries and improved recovery.................................... 648 648 648 Production.................................... (832) (832) (832) Sales of reserves in place.................... (6,787) (6,787) (6,787) --------- ------- ------ ------- ----------- --------- Proved reserves end of year................... 0 19,455 0 19,455 0 19,455 ========= ======= ====== ======= ========= ========= YEAR ENDED DECEMBER 31, 1993 Proved reserves beginning of the year......... 19,455 19,455 19,455 Revisions of previous estimates............... (3,400) (3,400) (3,400) Extensions, discoveries and improved recovery.................................... 2,820 2,820 2,820 Production.................................... (233) (233) (233) Sales of reserves in place.................... (543) (543) (543) --------- ------- ------ ------- ----------- --------- Proved reserves end of year................... 0 18,099 0 18,099 0 18,099 ========= ======= ====== ======= ========= ========= YEAR ENDED DECEMBER 31, 1994 Proved reserves beginning of the year......... 18,099 18,099 18,099 Revisions of previous estimates............... (1,120) (1,120) (1,120) Extensions, discoveries and improved recovery.................................... 9,153 9,153 9,153 Production.................................... (2,062) (2,062) (2,062) Sales of reserves in place.................... (7,993) (7,993) (7,993) --------- ------- ------ ------- ----------- --------- Proved reserves end of year................... 0 16,077 0 16,077 0 16,077 ========= ======= ====== ======= ========= ========= PROVED DEVELOPED RESERVES AT: January 1, 1992............................... 16,184 16,184 16,184 December 31, 1992............................. 9,930 9,930 9,930 December 31, 1993............................. 6,584 6,584 6,584 December 31, 1994............................. 8,385 8,385 8,385
F-24 174 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (1) The Securities and Exchange Commission requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The above estimates are based on current technology and economic conditions, and the Company considers such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be Proved Reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place. (2) Proved Developed Reserves are reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. This classification includes: (a) Proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and (b) Proved developed nonproducing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and gas available for production should be relatively small compared to the cost of a new well. Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as Proved Developed Reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. (3) Proved Undeveloped Reserves are Proved Reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Proved Reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for Proved Undeveloped Reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir. (4) The Company's engineering estimates indicate that approximately 18 Bcf of natural gas reserves (net to the Company's interest) will be developed and produced in association with the development and production of the Company's proved oil reserves in Russia. The Company expects that, due to current market conditions, it will initially reinject or flare such associated natural gas production, and accordingly, no future net revenue has been assigned to these reserves. Under the joint venture agreement, such reserves are owned by the Company in the same proportion as all other hydrocarbons in the field, and subsequent changes in conditions could result in the assignment of value to these reserves. (5) Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities (unaudited) The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS No. 69. In preparing this data, assumptions and estimates have been used, and the Company cautions against viewing this information as a forecast of future economic conditions. F-25 175 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. Future income taxes were estimated by applying the year-end statutory tax rates to the future pre-tax cash inflows, less the tax basis of the properties involved, and adjusted for permanent differences and tax credits and allowances. The resultant future net cash inflows are discounted using a ten percent discount rate. Russia has established an export tariff on all oil produced in and exported from Russia. GEOILBENT has received a waiver from the export tariff for 1995. For purposes of estimating future net cash flows, the export tariff has been applied to the Company's Russian production for the remainder of the life of the operations after 1995, although the Company believes that additional waivers may be obtained in the future. The discounted value of the waiver net to the Company's interest as of December 31, 1994 was approximately $3 million. STANDARDIZED MEASURE
MINORITY UNITED INTEREST IN VENEZUELA STATES RUSSIA TOTAL VENEZUELA NET TOTAL --------- -------- -------- --------- ----------- --------- (AMOUNTS IN THOUSANDS) DECEMBER 31, 1992 Future cash inflow................................. 88,255 275,734 148,842 512,831 Future production costs............................ (12,018 ) (94,685) (58,757) (165,460) Other related future costs......................... (11,338 ) (64,402) (12,644) (88,384) --------- -------- -------- --------- Future net revenue before income taxes............. 64,899 116,647 77,441 258,987 10% annual discount for estimated timing of cash flows............................................ (32,720 ) (57,679) (26,778) (117,177) --------- -------- -------- --------- Discounted future net cash flows before income taxes............................................ 32,179 58,968 50,663 141,810 Future income taxes, discounted at 10% per annum... (11,208 ) (10,296) (16,296) (37,800) --------- -------- -------- --------- Standardized measure of discounted future net cash flows....................................... $ 20,971 $ 48,672 $ 34,367 $ 104,010 ========= ======== ======== ========= DECEMBER 31, 1993 Future cash inflow................................. $148,130 $183,911 $111,333 $ 443,374 Future production costs............................ (16,952 ) (65,224) (55,461) (137,637) Other related future costs......................... (19,841 ) (54,733) (16,370) (90,944) --------- -------- -------- --------- Future net revenue before income taxes............. 111,337 63,954 39,502 214,793 10% annual discount for estimated timing of cash flows............................................ (39,131 ) (28,984) (15,265) (83,380) --------- -------- -------- --------- Discounted future net cash flows before income taxes............................................ 72,206 34,970 24,237 131,413 Future income taxes, discounted at 10% per annum... (21,248 ) (2,924) (4,725) (28,897) --------- -------- -------- --------- Standardized measure of discounted future net cash flows....................................... $ 50,958 $ 32,046 $ 19,512 $ 102,516 ========= ======== ======== ========= DECEMBER 31, 1994 Future cash inflow................................. $528,214 $ 32,091 $204,520 $ 764,825 $(105,643) $ 659,182 Future production costs............................ (64,950 ) (3,760) (98,767) (167,477) 12,990 (154,487) Other related future costs......................... (79,486 ) (2,002) (25,378) (106,866) 15,897 (90,969) --------- -------- -------- --------- ----------- --------- Future net revenue before income taxes............. 383,778 26,329 80,375 490,482 (76,756) 413,726 10% annual discount for estimated timing of cash flows............................................ (114,948 ) (7,672) (31,542) (154,162) 22,990 (131,172) --------- -------- -------- --------- ----------- --------- Discounted future net cash flows before income taxes............................................ 268,830 18,657 48,833 336,320 (53,766) 282,554 Future income taxes, discounted at 10% per annum... (96,127 ) (371) (16,435) (112,933) 19,225 (93,708) --------- -------- -------- --------- ----------- --------- Standardized measure of discounted future net cash flows....................................... $172,703 $ 18,286 $ 32,398 $ 223,387 $ (34,541) $ 188,846 ========= ======== ======== ========= ========= =========
F-26 176 BENTON OIL AND GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
YEARS ENDED DECEMBER 31, ---------------------------------- 1992 1993 1994 -------- -------- -------- (AMOUNTS IN THOUSANDS) CHANGES IN STANDARDIZED MEASURE Balance, January 1......................................... $ 78,464 $104,010 $102,516 Changes resulting from: Sales of oil and gas, net of related costs................. (3,796) (2,112) (22,412) Revisions to estimates of proved reserves: Pricing.................................................. 5,073 (52,239) (6,243) Quantities............................................... 1,163 (6,292) (4,150) Sales of reserves in place................................. (4,339) (1,735) (28,664) Extensions, discoveries and improved recovery, net of future costs............................................. 1,595 47,700 169,860 Purchases of reserves in place............................. 34,207 72,206 Accretion of discount...................................... 10,255 14,181 13,142 Change in income taxes..................................... (12,558) 8,903 (84,036) Development costs incurred................................. 3,091 10,480 13,365 Changes in timing and other................................ (9,145) (20,380) (2,197) -------- -------- -------- Balance, December 31....................................... $104,010 $102,516 $223,387 ======== ======== ========
NOTE 16 -- QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly financial data is as follows:
QUARTER ENDED --------------------------------------------------- MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, --------- -------- ------------- ------------ (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA) YEAR ENDED DECEMBER 31, 1993 Revenues............................................ $ 1,803 $1,930 $ 1,701 $ 2,069 Expenses............................................ 2,551 2,658 2,914 4,209 --------- -------- ------------- ------------ Net loss............................................ $ (748) $ (728) $(1,213) $ (2,140) ======= ====== ========== ========== Net loss per common share(1)........................ $ (0.04) $(0.04) $ (0.07) $ (0.10) ======= ====== ========== ========== YEAR ENDED DECEMBER 31, 1994 Revenues............................................ $ 3,755 $8,478 $ 9,573 $ 12,899 Expenses............................................ 4,834 6,649 6,726 10,750 --------- -------- ------------- ------------ Income (loss) before income taxes and minority interest.......................................... (1,079) 1,829 2,847 2,149 Income taxes........................................ -- -- 270 428 --------- -------- ------------- ------------ Income (loss) before minority interest.............. (1,079) 1,829 2,577 1,721 Minority interest................................... 63 685 751 595 --------- -------- ------------- ------------ Net income (loss)................................... $(1,142) $1,144 $ 1,826 $ 1,126 ======= ====== ========== ========== Net income (loss) per common share.................. $ (0.05) $ 0.05 $ 0.07 $ 0.05 ======= ====== ========== ==========
- --------------- (1) The sum of the quarters for 1993 does not equal the total year net income per share due to rounding. F-27 177 BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P. INDEX TO FINANCIAL STATEMENTS
PAGE ----- Independent Auditors' Report.......................................................... F-29 Balance Sheets at December 31, 1993 and 1994 and June 30, 1995........................ F-30 Statements of Operations for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months Ended June 30, 1994 and 1995............................................. F-31 Statements of Partners' Capital for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months Ended June 30, 1995.............................................. F-32 Statements of Cash Flows for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months Ended June 30, 1994 and 1995............................................. F-33 Notes to Financial Statements for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months ended June 30, 1994 and 1995......................................... F-34
F-28 178 INDEPENDENT AUDITORS' REPORT Benton Oil & Gas Combination Partnership 1989-1, L.P. Carpinteria, California We have audited the accompanying balance sheets of Benton Oil & Gas Combination Partnership 1989-1, L.P. as of December 31, 1994 and 1993, and the related statements of operations, partners' capital, and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of Benton Oil & Gas Combination Partnership 1989-1, L.P. at December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. Deloitte & Touche LLP Los Angeles, California March 31, 1995 F-29 179 BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P. BALANCE SHEETS
DECEMBER 31, --------------------- JUNE 30, 1993 1994 1995 -------- -------- --------- (UNAUDITED) ASSETS Current Assets: Cash..................................................... $112,756 $ 6,401 $ 5,717 Receivable from Co-Managing General Partners............. 13,535 621 Property held for sale (Note 4).......................... 323,296 -------- -------- --------- Total Current Assets............................. 126,291 6,401 329,634 Oil and Gas Properties (net of accumulated depletion of $338,673 and $414,876, respectively)..................... 443,807 400,651 Organization Costs (net of accumulated amortization of $10,994)................................................. 1,692 -------- -------- --------- Total Assets..................................... $571,790 $407,052 $ 329,634 ======== ======== ======== LIABILITIES AND PARTNERS' CAPITAL Current Liabilities: Payable to Co-Managing General Partners.................. $ 2,281 Commitments and Contingencies (Note 5) Partners' Capital: Co-Managing General Partners' capital.................... $ 94,780 $ 14,658 $ 23,147 Participants' capital.................................... 477,010 390,113 306,487 -------- -------- --------- Total Partners' Capital.......................... 571,790 404,771 329,634 -------- -------- --------- Total Liabilities and Partners' Capital.......... $571,790 $407,052 $ 329,634 ======== ======== ========
See accompanying notes to financial statements. F-30 180 BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P. STATEMENTS OF OPERATIONS
SIX MONTHS YEARS ENDED DECEMBER 31, ENDED JUNE 30, ------------------------------ ------------------- 1992 1993 1994 1994 1995 -------- -------- -------- -------- -------- (UNAUDITED) Revenues Oil and gas sales......................... $214,854 $199,399 $158,875 $ 86,664 $ 77,733 Other income.............................. 10,606 3,981 1,538 1,216 32 -------- -------- -------- -------- -------- 225,460 203,380 160,413 87,880 77,765 -------- -------- -------- -------- -------- Expenses Lease operating costs and production taxes.................................. 73,309 76,855 79,479 33,929 31,001 Exploration costs......................... 1,627 1,891 789 789 Depletion, impairment and amortization.... 111,050 72,453 77,895 42,831 90,155 General and administrative................ 32,110 38,432 33,654 27,032 31,746 -------- -------- -------- -------- -------- 218,096 189,631 191,817 104,581 152,902 -------- -------- -------- -------- -------- Net Income (Loss)...................... $ 7,364 $ 13,749 $(31,404) $(16,701) $(75,137) ======== ======== ======== ======== ========
See accompanying notes to financial statements. F-31 181 BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P. STATEMENTS OF PARTNERS' CAPITAL FOR THE YEARS ENDED DECEMBER 31, 1992, 1993 AND 1994 AND (UNAUDITED) SIX MONTHS ENDED JUNE 30, 1995
CO-MANAGING GENERAL PARTNERS PARTICIPANTS TOTAL ----------- ------------ ---------- Balance, January 1, 1992................................... $ 54,437 $ 947,994 $1,002,431 Net income (loss).......................................... 26,841 (19,477) 7,364 Distributions.............................................. (2,065) (279,753) (281,818) ----------- ------------ ---------- Balance, December 31, 1992................................. 79,213 648,764 727,977 Net income (loss).......................................... 18,103 (4,354) 13,749 Distributions.............................................. (2,536) (167,400) (169,936) ----------- ------------ ---------- Balance, December 31, 1993................................. 94,780 477,010 571,790 Net income (loss).......................................... 10,295 (41,699) (31,404) Distributions.............................................. (90,417) (45,198) (135,615) ----------- ------------ ---------- Balance, December 31, 1994................................. 14,658 390,113 404,771 Net income (loss) (unaudited).............................. 8,489 (83,626) (75,137) ----------- ------------ ---------- Balance, June 30, 1995 (unaudited)......................... $ 23,147 $ 306,487 $ 329,634 ========== ========= =========
See accompanying notes to financial statements. F-32 182 BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P. STATEMENTS OF CASH FLOWS
SIX MONTHS YEARS ENDED DECEMBER 31, ENDED JUNE 30, --------------------------------- --------------------- 1992 1993 1994 1994 1995 --------- --------- --------- -------- -------- (UNAUDITED) Cash flows from operating activities: Net Income (Loss).................... $ 7,364 $ 13,749 $ (31,404) $(16,701) $(75,137) Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depletion, impairment and amortization.................... 111,050 72,453 77,895 42,831 90,155 Decrease in accounts payable...... (1,000) --------- --------- --------- -------- -------- Net cash provided by operating activities....... 117,414 86,202 46,491 26,130 15,018 --------- --------- --------- -------- -------- Cash flows from investing activities: Expenditures on oil and gas properties........................ (38,469) (56,330) (33,047) (9,495) (12,800) --------- --------- --------- -------- -------- Net cash used in investing activities...................... (38,469) (56,330) (33,047) (9,495) (12,800) --------- --------- --------- -------- -------- Cash flows from financing activities: Net (increase) decrease in receivable from Co-Managing General Partners.......................... (38,908) 12,744 13,535 3,777 (621) Net increase (decrease) in payable to Co-Managing General Partners...... 2,281 (2,281) Partner distributions................ (281,818) (169,936) (135,615) (30,436) --------- --------- --------- -------- -------- Net cash used in financing activities...................... (320,726) (157,192) (119,799) (26,659) (2,902) --------- --------- --------- -------- -------- Net decrease in cash................... (241,781) (127,320) (106,355) (10,024) (684) Cash at beginning of period............ 481,857 240,076 112,756 112,756 6,401 --------- --------- --------- -------- -------- Cash at end of period.................. $ 240,076 $ 112,756 $ 6,401 $102,732 $ 5,717 ========= ========= ========= ======== ========
See accompanying notes to financial statements. F-33 183 BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P. NOTES TO FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1992, 1993 AND 1994 AND (UNAUDITED) SIX MONTHS ENDED JUNE 30, 1994 AND 1995 NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization Benton Oil & Gas Combination Partnership 1989-1, L.P. (Partnership) was formed for the purpose of investing in oil and natural gas by acquiring proven producing properties, recompleting previously drilled wells and developing and drilling oil and gas wells in the state waters of Texas and offshore Louisiana. Benton Oil and Gas Company (Benton) and a wholly owned subsidiary are the Co-Managing General Partners and as such conduct, direct and exercise full control over all activities of the Partnership. Oil and Gas Properties Oil and gas properties are accounted for using the successful efforts method. Under this method, costs of drilling exploratory wells are initially capitalized pending determination of whether the well can produce proved reserves. All costs relating to nonproductive exploratory wells are expensed. Costs relating to productive exploratory wells and all development wells are capitalized and depleted on a units-of-production basis over the life of the remaining proved developed reserves. Delay rentals and geological and geophysical costs are expensed as incurred. Proved properties are reviewed periodically on a property-by-property basis for impairment by comparing capitalized costs to undiscounted estimated future cash flows from the properties. Unproved oil and gas properties are periodically assessed for impairment of value and a loss is recognized as appropriate. Organization Costs Organization costs are amortized over a period of five years using the straight-line method. Income Taxes No provision has been made for income taxes as the liability for such taxes is that of the partners rather than of the Partnership. At December 31, 1993 and 1994, the financial statement bases of the Partnership's assets exceeded their tax bases by $179,502 and $179,796, respectively. Interim Reporting In the opinion of the Partnership, the accompanying unaudited consolidated financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly the financial position as of June 30, 1995, and the results of operations for the six month periods ended June 30, 1994 and 1995. The results of operations for the six month period ended June 30, 1995 are not necessarily indicative of the results to be expected for the full year. NOTE 2 -- PARTICIPATION IN COSTS AND REVENUES Under the terms of the Partnership agreement, the general and limited partners (Participants) pay 99% of the lease acquisition, geophysical and seismic costs, well costs, general and administrative expenses, and organization and offering expenses, including commissions, while the Co-Managing General Partners pay 1% of such costs. Revenues, production taxes and lease operating expenses on proven producing wells are allocated 99% to the Participants and 1% to the Co-Managing General Partners. Revenues, production taxes and lease operating expenses on recompleted wells are allocated 74.25% to the Participants and 25.75% to the Co-Managing General Partners. On new wells drilled, revenues, production taxes and lease operating expenses are allocated 64.35% to the Participants and 35.65% to the Co-Managing General Partners. F-34 184 BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) NOTE 3 -- RELATED PARTY TRANSACTIONS The Partnership pays the Co-Managing General Partners for general and administrative expenses, lease operating expenses and well costs incurred on behalf of the Partnership. Benton pays the Partnership for revenues collected on behalf of the Partnership. NOTE 4 -- OIL AND GAS PROPERTIES In June 1995, the Partnership entered into an agreement to sell its principal oil and gas properties. The sales price is subject to adjustments for revenues, expenses and capital expenditures related to the properties until the closing date. The agreement is subject to the approval of 75% of the partners. A provision for impairment was made during the six months ended June 30, 1995 to reflect the excess of book value over the adjusted sales price of $323,296. The adjusted sales price has been reflected as property held for sale at June 30, 1995. NOTE 5 -- COMMITMENTS AND CONTINGENCIES On June 13, 1994, certain limited partners of the Partnership, with limited partners of other Benton partnerships, brought an action against Benton in connection with its operation of the partnerships as managing general partner. The parties have agreed to submit the dispute to arbitration and the lawsuit has been dismissed. The plaintiffs seek actual and punitive damages for alleged actions and omissions of Benton in connection with operating the partnerships and alleged misrepresentations made by Benton in selling the limited partnership interests. At this time, the Partnership has not been named a defendant in this action. However, if the Partnership is added as a defendant, the Partnership would be forced to expend financial resources to defend or resolve any such matters. Benton does not believe that the Partnership will be adversely affected by this action. NOTE 6 -- OIL AND GAS ACTIVITIES Total costs incurred in oil and gas exploration and development were:
1992 1993 1994 --------- --------- --------- Development costs............................... $ 38,469 $ 56,330 $ 33,047 Exploration costs............................... 1,627 1,891 789 --------- --------- --------- $ 40,096 $ 58,221 $ 33,836 ========= ========= =========
The Partnership's aggregate amount of capitalized costs related to oil and gas producing activities consisted of the following at December 31:
1992 1993 1994 --------- --------- --------- Proved property costs........................... $ 726,150 $ 782,480 $ 815,527 Less accumulated depletion...................... (268,757) (338,673) (414,876) --------- --------- --------- $ 457,393 $ 443,807 $ 400,651 ========= ========= =========
QUANTITIES OF OIL AND GAS RESERVES (UNAUDITED) Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. F-35 185 BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) The evaluations of the oil and gas reserves were prepared by J.C. White, an independent petroleum engineer until January 1, 1993, when he became an employee of Benton.
1992 1993 1994 ------- -------- ------- PROVED RESERVES -- CRUDE OIL, CONDENSATE (BBLS) BALANCE, JANUARY 1............................................. 47,156 57,283 33,640 Revisions of previous estimates............................. 7,274 (17,870) (4,035) Extensions, discoveries and improved recovery............... 9,800 Production.................................................. (6,947) (5,773) (5,475) ------- -------- ------- BALANCE, DECEMBER 31........................................... 57,283 33,640 24,130 ======= ======== ======= PROVED DEVELOPED RESERVES AT DECEMBER 31:........................ 57,283 33,640 24,130 ======= ======== ======= PROVED RESERVES -- NATURAL GAS (MCF) BALANCE, JANUARY 1............................................. 280,941 502,817 273,851 Revisions of previous estimates............................. 211,038 (181,533) (52,626) Extensions, discoveries and improved recovery............... 58,161 Production.................................................. (47,323) (47,433) (38,044) ------- -------- ------- BALANCE, DECEMBER 31........................................... 502,817 273,851 183,181 ======= ======== ======= PROVED DEVELOPED RESERVES AT DECEMBER 31:........................ 502,817 273,851 183,181 ======= ======== =======
- --------------- (1) The Securities and Exchange Commission requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The above estimates are based on current technology and economic conditions, and Benton considers such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be Proved Reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place. (2) Proved Developed Reserves are reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. This classification includes: (a) Proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and (b) Proved developed nonproducing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the costs of making such oil and gas available for production should be relatively small compared to the cost of a new well. Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as Proved Developed Reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. (3) Proved Undeveloped Reserves are Proved Reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for F-36 186 BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Proved Reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for Proved Undeveloped Reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir. (4) Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVE QUANTITIES (UNAUDITED) The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS No. 69. In preparing this data, assumptions and estimates have been used, and Benton cautions against viewing this information as a forecast of future economic conditions. Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. The resultant future net cash inflows are discounted using a ten percent discount rate.
DECEMBER 31, ---------------------------------------- 1992 1993 1994 ---------- ----------- --------- STANDARDIZED MEASURE Future cash inflow............................... $1,935,000 $ 1,123,000 $ 678,000 Future production costs.......................... (718,000) (427,000) (262,000) Other related future costs....................... (13,000) (13,000) (5,000) ---------- ----------- --------- Future net revenue............................... 1,204,000 683,000 411,000 10% annual discount for estimated timing of cash flows..................................... (568,000) (135,000) (85,000) ---------- ----------- --------- Standardized measure of discounted future net cash flows..................................... $ 636,000 $ 548,000 $ 326,000 ========= ========== =========
YEARS ENDED DECEMBER 31, ------------------------------------ 1992 1993 1994 --------- --------- -------- CHANGES IN STANDARDIZED MEASURE Balance, January 1..................................... $ 638,000 $ 636,000 $548,000 Changes resulting from: Sales of oil and gas, net of related costs............. (142,000) (123,000) (79,000) Revisions to estimates of proved reserves: Pricing............................................. (58,000) 10,000 (80,000) Quantities.......................................... 37,000 (52,000) (76,000) Extensions, discoveries and improved recovery, net of future costs........................................ 79,000 Accretion of discount.................................. 64,000 64,000 55,000 Development costs incurred............................. 18,000 13,000 8,000 Changes in timing and other............................ (50,000) --------- --------- -------- Balance, December 31................................... $ 636,000 $ 548,000 $326,000 ========= ========= ========
F-37 187 BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P. INDEX TO FINANCIAL STATEMENTS
PAGE ---- Independent Auditors' Report.......................................................... F-39 Balance Sheets at December 31, 1993 and 1994 and June 30, 1995........................ F-40 Statements of Operations for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months Ended June 30, 1994 and 1995............................................. F-41 Statements of Partners' Capital for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months Ended June 30, 1995.............................................. F-42 Statements of Cash Flows for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months Ended June 30, 1994 and 1995............................................. F-43 Notes to Financial Statements for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months Ended June 30, 1994 and 1995......................................... F-44
F-38 188 INDEPENDENT AUDITORS' REPORT Benton Oil & Gas Combination Partnership 1990-1, L.P. Carpinteria, California We have audited the accompanying balance sheets of Benton Oil & Gas Combination Partnership 1990-1, L.P. as of December 31, 1994 and 1993, and the related statements of operations, partners' capital, and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of Benton Oil & Gas Combination Partnership 1990-1, L.P. at December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. Deloitte & Touche LLP Los Angeles, California March 31, 1995 F-39 189 BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P. BALANCE SHEETS
DECEMBER 31, ------------------------- JUNE 30, 1993 1994 1995 ---------- ---------- ----------- (UNAUDITED) ASSETS Current Assets: Cash................................................. $ 419,826 $ 17,859 $ 145,455 Receivable from Co-Managing General Partners......... 40,291 36,882 56,281 Marketable equity securities......................... 5,407 Property held for sale (Note 4)...................... 146,900 930,865 ---------- ---------- ----------- Total Current Assets.............................. 465,524 201,641 1,132,601 Oil and Gas Properties (net of accumulated depletion of $1,421,548, $1,614,158 and $974,988, respectively)... 1,398,850 1,152,597 133,573 Organization Costs (net of accumulated amortization of $7,772, $9,941 and $10,843, respectively)............ 3,071 902 ---------- ---------- ----------- Total Assets...................................... $1,867,445 $1,355,140 $ 1,266,174 ========= ========= ========= PARTNERS' CAPITAL Commitments and Contingencies (Note 5) Partners' Capital: Co-Managing General Partners' capital................ $ 436,921 $ 111,441 $ 126,832 Participants' capital................................ 1,429,384 1,240,417 1,134,106 Special Limited Partners' Capital.................... 1,140 3,282 5,236 ---------- ---------- ----------- Total Partners' Capital........................... $1,867,445 $1,355,140 $ 1,266,174 ========= ========= =========
See accompanying notes to financial statements. F-40 190 BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P. STATEMENTS OF OPERATIONS
SIX MONTHS YEARS ENDED DECEMBER 31, ENDED JUNE 30, ------------------------------------- --------------------- 1992 1993 1994 1994 1995 ----------- -------- -------- -------- -------- (UNAUDITED) Revenues Oil and gas sales............... $ 735,886 $630,682 $518,728 $275,947 $234,454 Other income.................... 34,631 14,777 6,058 4,845 819 ----------- -------- -------- -------- -------- 770,517 645,459 524,786 280,792 235,273 ----------- -------- -------- -------- -------- Expenses Lease operating costs and production taxes............. 285,840 254,903 263,957 112,323 100,135 Exploration costs............... 8,952 9,570 6,607 5,331 1,812 Loss on sale of oil and gas properties................... 57,586 1,328 Depletion, impairment and amortization................. 1,560,665 189,309 224,635 113,834 153,641 General and administrative...... 69,510 99,967 78,547 58,782 67,323 ----------- -------- -------- -------- -------- 1,982,553 553,749 573,746 290,270 324,239 ----------- -------- -------- -------- -------- Net Income (Loss)............ $(1,212,036) $ 91,710 $(48,960) $ (9,478) $(88,966) ========== ======== ======== ======== ========
See accompanying notes to financial statements. F-41 191 BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P. STATEMENTS OF PARTNERS' CAPITAL FOR THE YEARS ENDED DECEMBER 31, 1992, 1993 AND 1994 AND (UNAUDITED) SIX MONTHS ENDED JUNE 30, 1995
CO-MANAGING SPECIAL LIMITED GENERAL PARTNERS PARTICIPANTS PARTNERS TOTAL ---------------- ------------ ---------------- ---------- Balance, January 1, 1992............ $ 291,366 $ 4,363,866 $ 8,433 $4,663,665 Net income (loss)................... 95,449 (1,313,862) 6,377 (1,212,036) Distributions....................... (1,071,312) (1,071,312) ---------------- ------------ ---------------- ---------- Balance, December 31, 1992.......... 386,815 1,978,692 14,810 2,380,317 Net income.......................... 73,700 12,692 5,318 91,710 Distributions....................... (23,594) (562,000) (18,988) (604,582) ---------------- ------------ ---------------- ---------- Balance, December 31, 1993.......... 436,921 1,429,384 1,140 1,867,445 Net income (loss)................... 42,947 (96,237) 4,330 (48,960) Distributions....................... (368,427) (92,730) (2,188) (463,345) ---------------- ------------ ---------------- ---------- Balance, December 31, 1994.......... 111,441 1,240,417 3,282 1,355,140 Net income (loss) (unaudited)....... 15,391 (106,311) 1,954 (88,966) ---------------- ------------ ---------------- ---------- Balance, June 30, 1995 (unaudited)....................... $ 126,832 $ 1,134,106 $ 5,236 $1,266,174 ============ ========== ============ =========
See accompanying notes to financial statements. F-42 192 BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P. STATEMENTS OF CASH FLOWS
SIX MONTHS YEARS ENDED DECEMBER 31, ENDED JUNE 30, ----------------------------------- ------------------- 1992 1993 1994 1994 1995 ----------- --------- --------- -------- -------- (UNAUDITED) Cash flows from operating activities: Net Income (Loss)...................... $(1,212,036) $ 91,710 $ (48,960) $ (9,478) $(88,966) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depletion, impairment and amortization...................... 1,560,665 189,309 224,635 113,834 153,641 Dryhole costs....................... 1,238 Loss on sale of oil and gas properties........................ 57,586 1,328 Realized gain on sale of marketable equity securities................. (2,265) Unrealized loss on marketable equity securities........................ 9,013 451 ----------- --------- --------- -------- -------- Net cash provided by operating activities........................ 407,453 290,032 173,410 104,807 66,003 ----------- --------- --------- -------- -------- Cash flows from investing activities: Expenditures on oil and gas properties.......................... (151,217) (179,512) (123,113) (50,358) (65,908) Proceeds from sale of marketable equity securities.......................... 7,672 Proceeds from sale of oil and gas properties.......................... 26,485 146,900 ----------- --------- --------- -------- -------- Net cash provided by (used in) investing activities.............. (124,732) (179,512) (115,441) (50,358) 80,992 ----------- --------- --------- -------- -------- Cash flows from financing activities: Net (increase) decrease in receivable from Co-Managing General Partners... (12,415) 36,387 3,409 19,767 (19,399) Decrease in receivable from Affiliate........................... 451,447 Decrease in payable to Affiliate....... (50,000) Partner distributions.................. (1,071,312) (604,582) (463,345) (64,633) ----------- --------- --------- -------- -------- Net cash used in financing activities........................ (682,280) (568,195) (459,936) (44,866) (19,399) ----------- --------- --------- -------- -------- Net increase (decrease) in cash.......... (399,559) (457,675) (401,967) 9,583 127,596 Cash at beginning of period.............. 1,277,060 877,501 419,826 419,826 17,859 ----------- --------- --------- -------- -------- Cash at end of period.................... $ 877,501 $ 419,826 $ 17,859 $429,409 $145,455 ========== ========= ========= ======== ========
Supplemental information on non-cash investing activities During 1992, the Partnership sold an interest in oil and gas property in exchange for cash of $3,461 and stock with a fair market value of $14,420. See Note 4 for additional information on the transaction. See accompanying notes to financial statements. F-43 193 BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P. NOTES TO FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1992, 1993 AND 1994 AND (UNAUDITED) SIX MONTHS ENDED JUNE 30, 1994 AND 1995 NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization Benton Oil & Gas Combination Partnership 1990-1, L.P. (Partnership) was formed to invest in oil and natural gas by acquiring proven producing properties, recompleting previously drilled wells and developing and drilling new wells. Benton Oil and Gas Company (Benton) and a wholly owned subsidiary are the Co-Managing General Partners and as such conduct, direct and exercise full control over all activities of the Partnership. Marketable Equity Securities Marketable equity securities are stated at the lower of aggregate cost or market. At December 31, 1993, the cost of marketable equity securities was $14,420 with a valuation allowance of $9,013 for an approximate market value of $5,407. Marketable equity securities were sold in November 1994 for $7,672 for a realized gain of $2,265. Oil and Gas Properties Oil and gas properties are accounted for using the successful efforts method. Under this method, costs of drilling exploratory wells are initially capitalized pending determination of whether the well can produce proved reserves. All costs relating to nonproductive exploratory wells are expensed. Costs relating to productive exploratory wells and all development wells are capitalized and depleted on a units-of-production basis over the life of the remaining proved developed reserves. Delay rentals and geological and geophysical costs are expensed as incurred. Proved properties are reviewed periodically on a property-by-property basis for impairment by comparing capitalized costs to undiscounted estimated future cash flows from the properties. Unproved oil and gas properties are periodically assessed for impairment of value and a loss is recognized as appropriate. Organization Costs Organization costs are amortized over a period of five years using the straight-line method. Income Taxes No provision has been made for income taxes as the liability for such taxes is that of the partners rather than of the Partnership. At December 31, 1993 and 1994, the financial statement bases of the Partnership's assets exceeded their tax bases by $451,217 and $338,528, respectively. Interim Reporting In the opinion of the Partnership, the accompanying unaudited consolidated financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly the financial position as of June 30, 1995, and the results of operations for the six month periods ended June 30, 1994 and 1995. The results of operations for the six month period ended June 30, 1995 are not necessarily indicative of the results to be expected for the full year. F-44 194 BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) NOTE 2 -- PARTICIPATION IN COSTS AND REVENUES Under the terms of the Partnership agreement, the general and limited partners (Participants) pay 99% of the lease acquisition, geophysical and seismic costs, well costs, and organization and offering expenses, including commissions, while the Co-Managing General Partners pay 1% of such costs. General and administrative expenses and lease operating expenses are shared 74.25% by the Participants and 25.75% by the Co-Managing General Partners. Revenues and production taxes are allocated 73.5974% to the Participants, 25.5236% to the Co-Managing General Partners and 0.879% to broker/dealers (Special Limited Partners) who met certain minimum sales requirements in the initial offering of the Partnership units. NOTE 3 -- RELATED PARTY TRANSACTIONS The Partnership pays the Co-Managing General Partners for general and administrative expenses, lease operating expenses and well costs incurred on behalf of the Partnership. Benton pays the Partnership for revenues collected on behalf of the Partnership. NOTE 4 -- OIL AND GAS PROPERTIES During 1992, a provision for impairment of oil and gas properties was made to reflect reductions in the estimated value of reserves. In April 1992, a working interest in a California well was sold. Proceeds from the sale of the Partnership's interest were $17,881, consisting of cash and stock of the company purchasing the well. In addition, the Partnership retained a production payment of $8,845 to be paid from monthly net income from the well. In September 1992, the Partnership's interest in its remaining California oil and gas wells were sold for net proceeds of $19,386. In March 1995, the Partnership sold its 0.32% working interest in certain depths (above approximately 10,575 feet) in the West Cote Blanche Bay Field for a purchase price of $146,900. The sales price has been reflected as property held for sale at December 31, 1994. Impairment of $13,569 has been recorded to reflect the anticipated loss in connection with the sale of the property. In June 1995, the Partnership entered into an agreement to sell its principal oil and gas properties. The sales price is subject to adjustments for revenues, expenses and capital expenditures related to the properties until the closing date. The agreement is subject to the approval of 75% of the partners. A provision for impairment was made during the six months ended June 30, 1995 to reflect the excess of book value over the adjusted sales price of $930,865. The adjusted sales price has been reflected as property held for sale at June 30, 1995. NOTE 5 -- COMMITMENTS AND CONTINGENCIES On June 13, 1994, certain limited partners of the Partnership, with limited partners of other Benton partnerships, brought an action against Benton in connection with its operation of the partnerships as managing general partner. The parties have agreed to submit the dispute to arbitration and the lawsuit has been dismissed. The plaintiffs seek actual and punitive damages for alleged actions and omissions of Benton in connection with operating the partnerships and alleged misrepresentations made by Benton in selling the limited partnership interests. At this time, the Partnership has not been named a defendant in this action. However, if the Partnership is added as a defendant, the Partnership would be forced to expend financial resources to defend or resolve any such matters. Benton does not believe that the Partnership will be adversely affected by this action. F-45 195 BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) NOTE 6 -- OIL AND GAS ACTIVITIES Total costs incurred in oil and gas exploration and development were:
1992 1993 1994 ----------- ----------- ----------- Development costs........................... $ 151,217 $ 179,512 $ 123,113 Exploration costs........................... 7,714 9,570 6,607 ----------- ----------- ----------- $ 158,931 $ 189,082 $ 129,720 ========== ========== ==========
The Partnership's aggregate amount of capitalized costs related to oil and gas producing activities consists of the following at December 31:
1992 1993 1994 ----------- ----------- ----------- Proved property costs....................... $ 2,640,886 $ 2,820,398 $ 2,766,755 Less accumulated depletion.................. (1,234,408) (1,421,548) (1,614,158) ----------- ----------- ----------- $ 1,406,478 $ 1,398,850 $ 1,152,597 ========== ========== ==========
QUANTITIES OF OIL AND GAS RESERVES (UNAUDITED) Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. The evaluations of the oil and gas reserves were prepared by J.C. White, an independent petroleum engineer until January 1, 1993, when he became an employee of Benton.
1992 1993 1994 ----------- -------- -------- PROVED RESERVES -- CRUDE OIL, CONDENSATE (BBLS) BALANCE, JANUARY 1 ............................ 1,466,208 256,792 168,418 Revisions of previous estimates............. (853,994) (69,856) (311) Extensions, discoveries and improved recovery.................................. 16,809 917 Production.................................. (26,184) (18,518) (17,179) Sales of reserves in place.................. (346,047) (81,035) ----------- -------- -------- BALANCE, DECEMBER 31 .......................... 256,792 168,418 70,810 ========== ======== ======== PROVED DEVELOPED RESERVES AT DECEMBER 31......... 240,281 153,192 69,682 ========== ======== ======== PROVED RESERVES -- NATURAL GAS (MCF) BALANCE, JANUARY 1 ............................ 972,607 1,572,670 972,011 Revisions of previous estimates............. 672,297 (453,913) (218,429) Extensions, discoveries and improved recovery.................................. 73,243 34,097 Production.................................. (145,477) (146,746) (127,779) ----------- -------- -------- BALANCE, DECEMBER 31 .......................... 1,572,670 972,011 659,900 ========== ======== ======== PROVED DEVELOPED RESERVES AT DECEMBER 31......... 1,503,774 888,739 549,429 ========== ======== ========
- --------------- (1) The Securities and Exchange Commission requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve F-46 196 BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The above estimates are based on current technology and economic conditions, and Benton considers such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be Proved Reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place. (2) Proved Developed Reserves are reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. This classification includes: (a) Proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and (b) Proved developed nonproducing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and gas available for production should be relatively small compared to the cost of a new well. Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as Proved Developed Reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. (3) Proved Undeveloped Reserves are Proved Reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Proved Reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for Proved Undeveloped Reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir. (4) Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors. Also, additional production data at West Cote Blanche Bay enabled Benton to better conform estimates of future production to historical trends. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVE QUANTITIES (UNAUDITED) The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS No. 69. In preparing this data, assumptions and estimates have been used, and Benton cautions against viewing this information as a forecast of future economic conditions. Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. The resultant future net cash inflows are discounted using a ten percent discount rate. F-47 197 BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, ------------------------------------------ 1992 1993 1994 ----------- ----------- ---------- STANDARDIZED MEASURE Future cash inflow................................. $ 7,470,000 $ 4,637,000 $2,205,000 Future production costs............................ (2,714,000) (1,740,000) (775,000) Other related future costs......................... (514,000) (442,000) (55,000) ----------- ----------- ---------- Future net revenue................................. 4,242,000 2,455,000 1,375,000 10% annual discount for estimated timing of cash flows........................................... (2,020,000) (604,000) (318,000) ----------- ----------- ---------- Standardized measure of discounted future net cash flows........................................... $ 2,222,000 $ 1,851,000 $1,057,000 ========== ========== =========
YEARS ENDED DECEMBER 31, ------------------------------------------ 1992 1993 1994 ----------- ----------- ---------- CHANGES IN STANDARDIZED MEASURE Balance, January 1................................. $ 3,907,000 $ 2,222,000 $1,851,000 Changes resulting from: Sales of oil and gas, net of related costs......... (450,000) (376,000) (255,000) Revisions to estimates of proved reserves: Pricing......................................... 34,000 (163,000) (295,000) Quantities...................................... (1,101,000) (108,000) (202,000) Sales of reserves in place......................... (824,000) (114,000) Extensions, discoveries and improved recovery, net of future costs................................. 124,000 35,000 Accretion of discount.............................. 391,000 222,000 185,000 Development costs incurred......................... 141,000 54,000 57,000 Changes in timing and other........................ (205,000) ----------- ----------- ---------- Balance, December 31............................... $ 2,222,000 $ 1,851,000 $1,057,000 ========== ========== =========
F-48 198 BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P. INDEX TO FINANCIAL STATEMENTS
PAGE ---- Independent Auditors' Report........................................................ F-50 Balance Sheets at December 31, 1993 and 1994 and June 30, 1995...................... F-51 Statements of Operations for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months Ended June 30, 1994 and 1995....................................... F-52 Statements of Partners' Capital for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months Ended June 30, 1995............................................ F-53 Statements of Cash Flows for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months Ended June 30, 1994 and 1995....................................... F-54 Notes to Financial Statements for the Years Ended December 31, 1992, 1993 and 1994 and the Six Months Ended June 30, 1994 and 1995................................... F-55
F-49 199 INDEPENDENT AUDITORS' REPORT Benton Oil & Gas Combination Partnership 1991-1, L.P. Carpinteria, California We have audited the accompanying balance sheets of Benton Oil & Gas Combination Partnership 1991-1, L.P. as of December 31, 1994 and 1993, and the related statements of operations, partners' capital, and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of Benton Oil & Gas Combination Partnership 1991-1, L.P., at December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. Deloitte & Touche LLP Los Angeles, California March 31, 1995 F-50 200 BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P. BALANCE SHEETS
DECEMBER 31, --------------------- JUNE 30, 1993 1994 1995 -------- -------- --------- (UNAUDITED) ASSETS Current Assets: Cash..................................................... $177,180 $ 60,170 $ 82,547 Receivable from Co-Managing General Partners............. 4,958 7,897 3,169 Marketable equity securities............................. 5,407 Property held for sale (Note 4).......................... 29,200 185,282 -------- -------- --------- Total Current Assets.................................. 187,545 97,267 270,998 Oil and Gas Properties (net of accumulated depletion of $138,392, $192,942 and $23,188, respectively)............ 441,188 340,737 49,243 Organization Costs (net of accumulated amortization of $2,308, $3,231 and $3,692, respectively)................. 2,308 1,385 924 -------- -------- --------- Total Assets.......................................... $631,041 $439,389 $ 321,165 ======== ======== ======== PARTNERS' CAPITAL Commitments and Contingencies (Note 5) Partners' Capital: Co-Managing General Partners' capital.................... $ 50,358 $ 13,601 $ 12,820 Participants' capital.................................... 580,591 425,503 307,888 Special Limited Partners' Capital........................ 92 285 457 -------- -------- --------- Total Partners' Capital............................... $631,041 $439,389 $ 321,165 ======== ======== ========
See accompanying notes to financial statements. F-51 201 BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P. STATEMENTS OF OPERATIONS
SIX MONTHS YEARS ENDED DECEMBER 31, ENDED JUNE 30, ---------------------------------- ---------------------- 1992 1993 1994 1994 1995 -------- -------- -------- -------- --------- (UNAUDITED) Revenues Oil and gas sales................ $129,990 $107,181 $ 96,034 $ 50,419 $ 44,075 Other income..................... 30,331 5,343 2,610 1,769 777 -------- -------- -------- -------- --------- 160,321 112,524 98,644 52,188 44,852 -------- -------- -------- -------- --------- Expenses Lease operating costs and production taxes.............. 40,093 36,276 38,002 14,599 12,553 Exploration costs................ 7,245 1,284 769 515 361 Loss on sale of oil and gas property...................... 61,225 225 Depletion, impairment and amortization.................. 65,241 60,503 95,497 32,435 119,437 General and administrative....... 28,876 45,195 28,823 25,981 30,500 -------- -------- -------- -------- --------- 202,680 143,258 163,091 73,530 163,076 -------- -------- -------- -------- --------- Net Loss...................... $(42,359) $(30,734) $(64,447) $(21,342) $(118,224) ======== ======== ======== ======== =========
See accompanying notes to financial statements. F-52 202 BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P. STATEMENTS OF PARTNERS' CAPITAL FOR THE YEARS ENDED DECEMBER 31, 1992, 1993 AND 1994 AND (UNAUDITED) SIX MONTHS ENDED JUNE 30, 1995
CO-MANAGING SPECIAL GENERAL LIMITED PARTNERS PARTICIPANTS PARTNERS TOTAL ----------- ------------ -------- --------- Balance, January 1, 1992..................... $ 18,413 $ 912,292 $ 321 $ 931,026 Net income (loss)............................ 24,981 (67,846) 506 (42,359) Distributions................................ (111,600) (111,600) ----------- ------------ -------- --------- Balance, December 31, 1992................... 43,394 732,846 827 777,067 Net income (loss)............................ 9,500 (40,655) 421 (30,734) Distributions................................ (2,536) (111,600) (1,156) (115,292) ----------- ------------ -------- --------- Balance, December 31, 1993................... 50,358 580,591 92 631,041 Net income (loss)............................ 6,566 (71,387) 374 (64,447) Distributions................................ (43,323) (83,701) (181) (127,205) ----------- ------------ -------- --------- Balance, December 31, 1994................... 13,601 425,503 285 439,389 Net income (loss) (unaudited)................ (781) (117,615) 172 (118,224) ----------- ------------ -------- --------- Balance, June 30, 1995 (unaudited)........... $ 12,820 $ 307,888 $ 457 $ 321,165 ========== ========= ======= =========
See accompanying notes to financial statements. F-53 203 BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P. STATEMENTS OF CASH FLOWS
SIX MONTHS YEARS ENDED DECEMBER 31, ENDED JUNE 30, --------------------------------------- ---------------------- 1992 1993 1994 1994 1995 ----------- --------- --------- -------- --------- (UNAUDITED) Cash flows from operating activities: Net Loss..................... $ (42,359) $ (30,734) $ (64,447) $(21,342) $(118,224) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depletion, impairment and amortization............ 65,241 60,503 95,497 32,435 119,437 Dryhole costs............. 1,732 Loss on sale of oil and gas property............ 61,225 225 Realized gain on sale of marketable equity securities.............. (2,292) Unrealized loss on marketable equity securities.............. 9,013 451 ----------- --------- --------- -------- --------- Net cash provided by operating activities.... 85,839 38,782 28,758 11,544 1,438 ----------- --------- --------- -------- --------- Cash flows from investing activities: Expenditures on oil and gas properties................ (32,154) (35,786) (23,323) (8,686) (12,989) Proceeds from sale of marketable equity securities................ 7,699 Proceeds from sale of oil and gas properties............ 3,461 29,200 ----------- --------- --------- -------- --------- Net cash provided by (used in) investing activities................ (28,693) (35,786) (15,624) (8,686) 16,211 ----------- --------- --------- -------- --------- Cash flows from financing activities: Net (increase) decrease in receivable from Co-Managing General Partners.................. (449,926) 12,283 (2,939) (1,087) 4,728 Decrease in payable to Affiliate................. (451,446) Partner distributions........ (111,600) (115,292) (127,205) (56,546) ----------- --------- --------- -------- --------- Net cash provided by (used in) financing activities.............. (1,012,972) (103,009) (130,144) (57,633) 4,728 ----------- --------- --------- -------- --------- Net increase (decrease) in cash......................... (955,826) (100,013) (117,010) (54,775) 22,377 Cash at beginning of period.... 1,233,019 277,193 177,180 177,180 60,170 ----------- --------- --------- -------- --------- Cash at end of period.......... $ 277,193 $ 177,180 $ 60,170 $122,405 $ 82,547 ========== ========= ========= ======== =========
Supplemental information on non-cash investing activities During 1992, the Partnership sold an interest in oil and gas property in exchange for cash of $3,461 and stock with a fair market value of $14,420. See Note 4 for additional information on the transaction. See accompanying notes on financial statements. F-54 204 BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P. NOTES TO FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1992, 1993 AND 1994 AND (UNAUDITED) SIX MONTHS ENDED JUNE 30, 1994 AND 1995 NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization Benton Oil & Gas Combination Partnership 1991-1, L.P. (Partnership) was formed to invest in oil and natural gas by acquiring proven producing properties, enhancing production of previously drilled wells and drilling new wells. Benton Oil and Gas Company (Benton) and a wholly owned subsidiary are the Co-Managing General Partners and as such conduct, direct and exercise full control over all activities of the Partnership. Marketable Equity Securities Marketable equity securities are stated at the lower of aggregate cost or market. At December 31, 1993, the cost of marketable equity securities was $14,420 with a valuation allowance of $9,013 for an approximate market value of $5,407. Marketable equity securities were sold in November 1994 for $7,699 for a realized gain of $2,292. Oil and Gas Properties Oil and gas properties are accounted for using the successful efforts method. Under this method, costs of drilling exploratory wells are initially capitalized pending determination of whether the well can produce proved reserves. All costs relating to nonproductive exploratory wells are expensed. Costs relating to productive exploratory wells and all development wells are capitalized and depleted on a units-of-production basis over the life of the remaining proved developed reserves. Delay rentals and geological and geophysical costs are expensed as incurred. Proved properties are reviewed periodically on a property-by-property basis for impairment by comparing capitalized costs to undiscounted estimated future cash flows from the properties. Unproved oil and gas properties are periodically assessed for impairment of value and a loss is recognized as appropriate. Organization Costs Organization costs are amortized over a period of five years using the straight-line method. Income Taxes No provision has been made for income taxes as the liability for such taxes is that of the partners rather than of the Partnership. At December 31, 1993 and 1994, the financial statement bases of the Partnership's assets exceeded their tax bases by $76,407 and $28,601, respectively. Interim Reporting In the opinion of the Partnership, the accompanying unaudited consolidated financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly the financial position as of June 30, 1995, and the results of operations for the six month periods ended June 30, 1994 and 1995. The results of operations for the six month period ended June 30, 1995 are not necessarily indicative of the results to be expected for the full year. NOTE 2 -- PARTICIPATION IN COSTS AND REVENUES Under the terms of the Partnership agreement, the general and limited partners (Participants) pay 99% of the lease acquisition, geophysical and seismic costs, well costs, and organization and offering expenses, F-55 205 BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) including commissions, while the Co-Managing General Partners pay 1% of such costs. For the first twelve months of the Partnership, general and administrative expenses are covered by a fee, equal to 3% of initial capital raised, paid by the Partnership to Benton. The fee is paid 99% by the Participants and 1% by the Co-Managing General Partners. General and administrative expenses after the first twelve months and lease operating expenses are shared 74.25% by the Participants and 25.75% by the Co-Managing General Partners. Revenues and production taxes are allocated 73.944% to the Participants, 25.6438% to the Co-Managing General Partners, and .4122% to broker/dealers (Special Limited Partners) who met certain minimum sales requirements in the initial offering of the Partnership units. NOTE 3 -- RELATED PARTY TRANSACTIONS The Partnership pays the Co-Managing General Partners for syndication costs, organization costs, general and administrative expenses, lease operating expenses and well costs incurred on behalf of the Partnership. Benton pays the Partnership for revenues collected on behalf of the Partnership. NOTE 4 -- OIL AND GAS PROPERTIES In April 1992, a working interest in a California well was sold. Proceeds from the sale of the Partnership's interest were $17,881 consisting of cash and stock of the company purchasing the well. In addition, the Partnership retained a production payment of $8,845 to be paid from monthly net income from the well. In March 1995, the Partnership sold its 0.06% working interest in certain depths (above approximately 10,575 feet) in the West Cote Blanche Bay Field for a purchase price of $29,200. The sales price has been reflected as property held for sale at December 31, 1994. Impairment of $34,371 has been recorded to reflect the anticipated loss in connection with the sale of the property. In June 1995, the Partnership entered into an agreement to sell its principal oil and gas properties. The sales price is subject to adjustments for revenues, expenses and capital expenditures related to the properties until the closing date. The agreement is subject to the approval of 75% of the partners. A provision for impairment was made during the six months ended June 30, 1995 to reflect the excess of book value over the sales price of $185,282. The adjusted sales price has been reflected as property held for sale at June 30, 1995. NOTE 5 -- COMMITMENTS AND CONTINGENCIES On June 13, 1994 certain limited partners of the Partnership, with limited partners of other Benton and partnerships, brought an action against Benton in connection with its operation of the partnerships as managing general partner. The parties have agreed to submit the dispute to arbitration and the lawsuit has been dismissed. The plaintiffs seek actual and punitive damages for alleged actions and omissions of Benton in connection with operating the partnerships and alleged misrepresentations made by Benton in selling the limited partnership interests. At this time, the Partnership has not been named a defendant in this action. However, if the Partnership is added as a defendant, the Partnership would be forced to expend financial resources to defend or resolve any such matters. Benton does not believe that the Partnership will be adversely affected by this action. NOTE 6 -- OIL AND GAS ACTIVITIES Total costs incurred in oil and gas exploration and development were:
1992 1993 1994 -------- --------- --------- Development costs................................ $ 32,154 $ 35,786 $ 23,323 Exploration costs................................ 5,513 1,284 769 -------- --------- --------- $ 37,667 $ 37,070 $ 24,092 ======== ========= =========
F-56 206 BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) The Partnership's aggregate amount of capitalized costs related to oil and gas producing activities consists of the following at December 31:
1992 1993 1994 -------- --------- --------- Proved property costs............................ $543,794 $ 579,580 $ 533,679 Less accumulated depletion....................... (78,812) (138,392) (192,942) -------- --------- --------- $464,982 $ 441,188 $ 340,737 ======== ========= =========
QUANTITIES OF OIL AND GAS RESERVES (UNAUDITED) Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. The evaluations of the oil and gas reserves were prepared by J.C. White, an independent petroleum engineer until January 1, 1993, when he became an employee of Benton.
1992 1993 1994 ------- -------- ------- PROVED RESERVES -- CRUDE OIL, CONDENSATE (BBLS) BALANCE, JANUARY 1............................... 45,659 51,079 33,564 Revisions of previous estimates............... 7,730 (13,829) (140) Extensions, discoveries and improved recovery.................................... 3,346 182 Production.................................... (4,727) (3,686) (3,420) Sales of reserves in place.................... (929) (16,090) ------- -------- ------- BALANCE, DECEMBER 31............................. 51,079 33,564 14,096 ======= ======== ======= PROVED DEVELOPED RESERVES AT DECEMBER 31........... 47,808 30,517 13,871 ======= ======== ======= PROVED RESERVES -- NATURAL GAS (MCF) BALANCE, JANUARY 1............................... 162,291 313,037 145,219 Revisions of previous estimates............... 165,388 (149,562) (853) Extensions, discoveries and improved recovery.................................... 4,580 6,787 Production.................................... (19,222) (18,256) (19,815) ------- -------- ------- BALANCE, DECEMBER 31............................. 313,037 145,219 131,338 ======= ======== ======= PROVED DEVELOPED RESERVES AT DECEMBER 31........... 299,325 128,656 109,362 ======= ======== =======
- --------------- (1) The Securities and Exchange Commission requires the reserve presentation to be calculated using year-end prices and costs and assuming a continuation of existing economic conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgmental determinations. Reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The above estimates are based on current technology and economic conditions, and Benton considers such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The estimates include only those amounts considered to be Proved Reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place. (2) Proved Developed Reserves are reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. This classification includes: F-57 207 BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) (a) Proved developed producing reserves which are reserves expected to be recovered through existing completion intervals now open for production in existing wells; and (b) Proved developed nonproducing reserves which are reserves that exist behind the casing of existing wells which are expected to be produced in the predictable future, where the cost of making such oil and gas available for production should be relatively small compared to the cost of a new well. Any reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing primary recovery methods are included as Proved Developed Reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. (3) Proved Undeveloped Reserves are Proved Reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units, which are reasonably certain of production when drilled. Proved Reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. No estimates for Proved Undeveloped Reserves are attributable to or included in this table for any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless proved effective by actual tests in the area and in the same reservoir. (4) Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors. Also, additional production data at West Cote Blanche Bay enabled Benton to better conform estimates of future production to historical trends. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVE QUANTITIES (UNAUDITED) The standardized measure of discounted future net cash flows is presented in accordance with the provisions of SFAS No. 69. In preparing this data, assumptions and estimates have been used, and Benton cautions against viewing this information as a forecast of future economic conditions. Future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations provided by contract, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs to determine pre-tax cash inflows. The resultant future net cash inflows are discounted using a ten percent discount rate.
DECEMBER 31 -------------------------------------- 1992 1993 1994 ---------- --------- --------- STANDARDIZED MEASURE Future cash inflow.................................... $1,486,000 $ 818,000 $ 439,000 Future production costs............................... (539,000) (279,000) (155,000) Other related future costs............................ (102,000) (88,000) (11,000) ---------- --------- --------- Future net revenue.................................... 845,000 451,000 273,000 10% annual discount for estimated timing of cash flows.............................................. (402,000) (113,000) (63,000) ---------- --------- --------- Standardized measure of discounted future net cash flows......................................... $ 443,000 $ 338,000 $ 210,000 ========= ========= =========
F-58 208 BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P. NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
YEARS ENDED DECEMBER 31, -------------------------------------- 1992 1993 1994 ---------- --------- --------- CHANGES IN STANDARDIZED MEASURE Balance, January 1 ................................... $ 382,000 $ 443,000 $ 338,000 Changes resulting from: Sales of oil and gas, net of related costs............ (90,000) (71,000) (58,000) Revisions to estimates of proved reserves: Pricing............................................ 8,000 (6,000) (63,000) Quantities......................................... 45,000 (83,000) (2,000) Sales of reserves in place............................ 10,000 (23,000) Extensions, discoveries and improved recovery, net of future costs....................................... 18,000 7,000 Accretion of discount................................. 38,000 44,000 34,000 Development costs incurred............................ 32,000 11,000 11,000 Changes in timing and other........................... (34,000) ---------- --------- --------- Balance, December 31 ................................. $ 443,000 $ 338,000 $ 210,000 ========= ========= =========
F-59 209 Exhibit A WARRANT AGREEMENT BETWEEN BENTON OIL AND GAS COMPANY and Dated as of , 1995 ----------------- 210 WARRANT AGREEMENT dated as of________________, 1995 (the "Agreement"), between Benton Oil and Gas Company, a Delaware corporation (the "Company") and ____________________("Holder"). WHEREAS, the Company proposes to issue to the Holder common stock purchase warrants (the "Warrants") to purchase up to _______shares (the "Warrant Shares") of the Company's Common Stock, par value $.01 per share (the "Common Stock"), each Warrant entitling the holder thereof to purchase one share of Common Stock. NOW, THEREFORE, in consideration of the premises and the mutual agreements herein and for other good and valuable consideration, the parties hereto agree as follows: 1. ISSUANCE OF WARRANTS; FORM OF WARRANT. The Company will issue and deliver the Warrants to Holder, in consideration for, and as part of the compensation to Holder in connection with the sale of the assets of the Partnership. The number of Warrants to be issued and delivered shall be____. No cash consideration will be paid by Holder for the Warrants. The text of each Warrant, of the purchase form and of each assignment form to be printed on the reverse thereof shall be substantially as set forth in Exhibit A attached hereto. The Warrants shall be executed on behalf of the Company by the manual or facsimile signature of the present or any future Chairman of the Board, President, Treasurer or Vice President of the Company, under its corporate seal, affixed or in facsimile, attested by the manual or facsimile signature of the present or future Secretary or an Assistant Secretary of the Company. A Warrant bearing the manual or facsimile signature of individuals who were at any time the proper officers of the Company shall bind the Company notwithstanding that such individuals or any of them shall have ceased to hold such offices prior to the delivery of such Warrant or did not hold such offices on the date of this Agreement. Warrants shall be dated as of the date of execution thereof by the Company either upon initial issuance or upon division, exchange, substitution or transfer. 2. REGISTRATION. The Warrants shall be numbered and shall be registered on the books of the Company (the "Warrant Register") as they are issued. The Company shall be entitled to treat the registered holder of any Warrant on the Warrant Register (the "Holder") as the owner in fact thereof for all purposes and shall not be bound to recognize any equitable or other claim to or interest in such Warrant on the part of any other person, and shall not be liable for any registration or transfer of Warrants which are registered or to be registered in the name of a fiduciary or 1 211 the nominee of a fiduciary unless made with the actual knowledge that a fiduciary or nominee is committing a breach of trust in requesting such registration or transfer, or with knowledge of such facts that its participation therein amounts to bad faith. The Warrants shall be registered initially in the name of Holder in such denominations as Holder may request in writing to the Company. 3. EXCHANGE OF WARRANT CERTIFICATES. Subject to any restriction upon transfer set forth in this Agreement, each Warrant certificate may be exchanged at the option of the Holder thereof for another certificate or certificates of different denominations entitling the Holder thereof to purchase upon surrender to the Company or its duly authorized agent a like aggregate number of Warrant Shares as the certificate or certificates surrendered then entitle such Holder to purchase. Any Holder desiring to exchange a Warrant certificate or certificates shall make such request in writing delivered to the Company, and shall surrender, properly endorsed, the certificate or certificates to be so exchanged. Thereupon, the Company shall execute and deliver to the person entitled thereto a new Warrant certificate or certificates, as the case may be, as so requested. Any Warrant issued upon exchange, transfer or partial exercise of the Warrants shall be the valid obligation of the Company, evidencing the same generic rights and entitled to the same generic benefits under this Agreement as the Warrants surrendered for such exchange, transfer or exercise. 4. WARRANT TERMS. 4.1. TERM OF WARRANTS; EXERCISE OF WARRANTS. (a) Each Warrant entitles the Holder thereof to purchase one share of Common Stock subject to adjustment in accordance with Section 8 hereof at any time from 9:00 A.M., Los Angeles time, on , 1995 until 5:00 P.M., Los Angeles time, on , 1998 (the "Expiration Date") at a purchase price of $ per share. (b) The Warrant Price and the number of shares issuable upon exercise of Warrants are subject to adjustment upon the occurrence of certain events, pursuant to the provisions of Section 8 of this Agreement. Subject to the provisions of this Agreement, each Holder shall have the right, which may be exercised as expressed in such Warrants, to purchase from the Company (and the Company shall issue and sell to such Holder) the number of fully paid and nonassessable shares of Common Stock specified in such Warrants, upon surrender to the Company, or its duly authorized agent, of such Warrants, with the purchase form on the reverse thereof duly filled in and signed, and upon payment to the Company of the Warrant Price, 2 212 as adjusted in accordance with the provisions of Section 8 of this Agreement, for the number of shares in respect of which such Warrants are then exercised. Payment of such Warrant Price may be made only in cash, or by certified or official bank check. Upon such surrender of Warrants, and payment of the Warrant Price as aforesaid, the Company shall issue and cause to be delivered with all reasonable dispatch to or upon the written order of the Holder and (subject to receipt of evidence of compliance with the act in accordance with the provisions of Section 10 of this Agreement) in such name or names as the Holder may designate, a certificate or certificates for the number of full shares of Common Stock so purchased upon the exercise of such Warrants, together with cash, as provided in Section 9 of this Agreement, in respect of any fraction of a share of such stock otherwise issuable upon such surrender. Such certificate or certificates shall be deemed to have been issued and any person so designated to be named therein shall be deemed to have become a holder of record of such shares as of the date of the surrender of such Warrants and payment of the Warrant Price as aforesaid; PROVIDED, HOWEVER, that if, at the time of surrender of the Warrant and payment of such Warrant Price, the transfer books for the Common Stock or other class of stock purchasable upon the exercise of the Warrants shall be closed, the certificates for the shares in respect of which the Warrants are then exercised shall be issuable as of the date on which such books shall next be opened whether before, on or after the Expiration Date and until such date the Company shall be under no duty to deliver any certificate for such shares; provided, further, however, that the transfer books shall not be closed at any one time for a period longer than five days unless otherwise required by law. The rights of purchase represented by the Warrants shall be exercisable, at the election of the Holders thereof, either in full or from time to time in part and, in the event that any Warrant is exercised in respect of less than all of the shares purchasable on such exercise at any time prior to the Expiration Date, a new certificate evidencing the remaining Warrant or Warrants will be issued. 4.2. COMPLIANCE WITH GOVERNMENT REGULATIONS. The Company covenants that if any shares of Common Stock required to be reserved for purposes of exercise or conversion of Warrants require, under any Federal or state law or applicable governing rule or regulation of any national securities exchange, registration with or approval of any governmental authority, or listing on any such national securities exchange, before such shares may be issued upon exercise, the Company will in good faith and as expeditiously as possible endeavor to cause such shares to be duly registered, approved or listed on the relevant national 3 213 securities exchange, as the case may be, PROVIDED, HOWEVER, that in no event shall such shares of Common Stock be issued, and the Company is hereby authorized to suspend the exercise of all Warrants, for the period during which such registration, approval or listing is required but not in effect. 5. PAYMENT OF TAXES. The Company will pay all documentary stamp taxes, if any, attributable to the initial issuance of Warrant Shares upon the exercise of Warrants and any securities issued pursuant to Section 8 hereof; PROVIDED, HOWEVER, that the Company shall not be required to pay any tax or taxes which may be payable in respect of any transfer involved in the issue or delivery of any Warrants or certificates for Warrant Shares and any securities issued pursuant to Section 8 hereof in a name other than that of the Holder of such Warrants. 6. MUTILATED OR MISSING WARRANTS. In case any of the Warrants shall be mutilated, lost, stolen or destroyed, the Company may in its discretion issue and deliver in exchange and substitution for and upon cancellation of the mutilated Warrant, or in lieu of and in substitution for the Warrant lost, stolen or destroyed, a new Warrant of like tenor and representing an equivalent right or interest; but only upon receipt of evidence reasonably satisfactory to the Company of such loss, theft or destruction of such Warrant and indemnity or bond, if requested, also reasonably satisfactory to the Company. An applicant for such substitute Warrants shall also comply with such other reasonable regulations and pay such other reasonable charges as the Company may prescribe. 7. RESERVATION OF WARRANT SHARES; PURCHASE AND CANCELLATION OF WARRANTS. There have been reserved out of the authorized and unissued shares of Common Stock, a number of shares sufficient to provide for the exercise of the rights of purchase represented by the Warrants, and the transfer agent for the Common Stock ("Transfer Agent") and every subsequent transfer agent for any shares of the Company's capital stock issuable upon the exercise of any of the rights of purchase aforesaid are hereby irrevocably authorized and directed at all times until the Expiration Date to reserve such number of authorized and unissued shares as shall be requisite for such purpose. The Company will keep a copy of this Agreement on file with the Transfer Agent and with every subsequent transfer agent for any shares of the Company's capital stock issuable upon the exercise of the rights of purchase represented by the Warrants. The Company will supply the Transfer Agent and any such subsequent transfer agent with duly executed stock certificates for such purpose and will itself provide or otherwise 4 214 make available any cash which may be issuable as provided in Section 9 of this Agreement. The Company will furnish to the Transfer Agent and any such subsequent transfer agent a copy of all notices of adjustments, and certificates related thereto, transmitted to each Holder pursuant to Section 8.3 hereof. All Warrants surrendered in the exercise of the rights thereby evidenced shall be cancelled, and such cancelled Warrants shall constitute sufficient evidence of the number of shares of stock which have been issued upon the exercise of such Warrants (subject to adjustment as herein provided). No shares of stock shall be subject to reservation in respect of the Warrants subsequent to the Expiration Date except to the extent necessary to comply with the terms of this Agreement. 8. ADJUSTMENT OF WARRANT PRICE AND NUMBER OF WARRANT SHARES. The number and kind of securities purchasable upon the exercise of each Warrant and the Warrant Price shall be subject to adjustment from time to time upon the occurrence of certain events, as hereafter defined. 8.1. MECHANICAL ADJUSTMENTS. The number of Warrant Shares purchasable upon the exercise of each Warrant and the Warrant Price shall be subject to adjustment as follows: (a) In case the Company shall (i) pay a dividend in shares of Common Stock or make a distribution in shares of Common Stock, (ii) subdivide its outstanding shares of Common Stock, (iii) combine its outstanding shares of Common Stock into a smaller number of shares of Common Stock or (iv) issue by reclassification of its shares of Common Stock other securities of the Company (including any such reclassification in connection with a consolidation or merger in which the Company is the surviving corporation), the number of Warrant Shares purchasable upon exercise of each Warrant immediately prior thereto shall be adjusted so that the Holder of each Warrant shall be entitled to receive the kind and number of Warrant Shares or other securities of the Company which he would have owned or have been entitled to receive after the happening of any of the events described above, had such Warrant been exercised immediately prior to the happening of such event or any record date with respect thereto regardless of whether the Warrants are exercisable at the time of the happening of such event or at the time of any record date with respect thereto. An adjustment made pursuant to this paragraph (a) shall become effective immediately after the effective date of such event retroactive to the record date, if any, for such event. 5 215 (b) In case the Company shall issue rights, options or warrants to all holders of its outstanding Common Stock, without any charge to such holders, entitling them (for a period expiring within 60 days after the record date mentioned below) to subscribe for or purchase shares of Common Stock at a price per share which is lower at the record date mentioned below than the then current market price per share of Common Stock (as determined in accordance with paragraph (e) below), the number of Warrant Shares thereafter purchasable upon the exercise of each Warrant shall be determined by multiplying the number of Warrant Shares theretofore purchasable upon exercise of each Warrant by a fraction, of which the numerator shall be the number of shares of Common Stock outstanding on the date of issuance of such rights, options or warrants plus the number of additional shares of Common Stock offered for subscription or purchase, and of which the denominator shall be the number of shares of Common Stock outstanding on the date of issuance of such rights, options or warrants plus the number of shares which the aggregate offering price of the total number of shares of common stock so offered would purchase at the current market price per share of Common Stock at such record date. Such adjustment shall be made whenever such rights, options or warrants are issued, and shall become effective immediately after the record date for the determination of stockholders entitled to receive such rights, options or warrants. (c) In case the Company shall distribute to all holders of its shares of Common Stock evidences of its indebtedness or assets (excluding cash dividends or distributions payable out of consolidated earnings or earned surplus and dividends or distributions referred to in paragraph (a) above or in the paragraph immediately following this paragraph) or rights, options or warrants, or convertible or exchangeable securities containing the right to subscribe for or purchase shares of Common Stock (excluding those referred to in paragraph (b) above), then in each case the number of Warrant Shares thereafter purchasable upon the exercise of each Warrant shall be determined by multiplying the number of Warrant Shares theretofore purchasable upon the exercise of each Warrant by a fraction, of which the numerator shall be the then current market price per share of Common Stock (as determined in accordance with paragraph (e) below) on the date of such distribution, and of which the denominator shall be the then current market price per share of Common Stock, less the then fair value (as determined in good faith by the Board of Directors of the Company, whose determination shall be conclusive) of the portion of the assets or evidences of indebtedness so distributed or of such subscription rights, options or warrants, or of such convertible or exchangeable 6 216 securities applicable to one share of Common Stock. Such adjustment shall be made whenever any such distribution is made, and shall become effective on the date of distribution retroactive to the record date for the determination of stockholders entitled to receive such distribution. In the event of distribution by the Company to all holders of its shares of Common Stock of stock of a subsidiary or securities convertible into or exercisable for such stock, then in lieu of an adjustment in the number of Warrant Shares purchasable upon the exercise of each Warrant, the Holder of each Warrant, upon the exercise thereof at any time after such distribution, shall be entitled to receive from the Company, such subsidiary or both, as the Company shall determine, the stock or other securities to which such Holder would have been entitled if such Holder had exercised such Warrant immediately prior thereto regardless of whether the Warrants are exercisable at such time, all subject to further adjustment as provided in this subsection 8.1; PROVIDED, HOWEVER, that no adjustment in respect of cash dividends or interest on such stock or other securities shall be made during the term of a Warrant or upon the exercise of a Warrant. (d) In case the Company shall sell and issue shares of Common Stock (other than pursuant to rights, options, warrants, or convertible securities initially issued before the date of this Agreement) or rights, options, warrants or convertible securities containing the right to subscribe for or purchase shares of Common Stock (excluding shares, rights, options, warrants or convertible securities issued in any of the transactions described in paragraphs (a), (b) or (c) above) at a price per share of Common Stock (determined, in the case of such rights, options, warrants or convertible securities, by dividing (w) the total of the amount received or receivable by the Company (determined as provided below) in consideration of the sale and issuance of such rights, options, warrants or convertible securities, by (x) the total number of shares of Common Stock covered by such rights, options, warrants or convertible securities) lower than the then current market price per share of Common Stock (as determined in accordance with paragraph (e) below) in effect immediately prior to such sale and issuance, then the number of Warrant Shares thereafter purchasable upon the exercise of the Warrants shall be determined by multiplying the number of Warrant Shares theretofore purchasable upon exercise by a fraction, of which the numerator shall be the number of shares of Common Stock outstanding on the date of issuance of such shares, rights, options, warrants or convertible securities plus the number of additional shares of Common Stock sold or subject to issuance pursuant to such rights, options, warrants 7 217 or convertible securities, and of which the denominator shall be the number of shares of Common Stock outstanding on the date of issuance of such shares, rights, options, warrants or convertible securities plus the number of shares of Common Stock which the aggregate consideration received or receivable (determined as provided below) for such sale or issuance would purchase at such current market price per share. Such adjustment shall be made successively whenever such an issuance is made. For the purposes of such adjustments, the consideration received or receivable by the Company for rights, options, warrants or convertible securities shall be deemed to be the consideration received by the Company for such rights, options, warrants or convertible securities, plus the consideration or premiums stated in such rights, options, warrants or convertible securities to be paid for the shares of Common Stock covered thereby. In case the Company shall sell and issue shares of Common Stock, or rights, options, warrants or convertible securities containing the right to subscribe for or purchase shares of Common Stock, for a consideration consisting, in whole or in part, of property other than cash or its equivalent, then in determining the "price per share of Common Stock" and the "consideration received or receivable by the Company" for purposes of the first sentence of this paragraph (d), the Board of Directors shall determine, in its discretion, the fair value of said property, and such determination, if made in good faith, shall be binding upon all Holders. (e) For the purpose of any computation under paragraphs (b), (c) and (d) of this Section, the current market price per share of Common Stock at any date shall be the daily closing price of the Company's Common Stock, as reported by the Nasdaq National Market. The closing price for such day shall be the last such reported sales price regular way or, in case no such reported sale takes place on such day, the average of the closing bid and asked prices regular way for such day, in each case on the principal national securities exchange on which the shares of Common Stock are listed or admitted to trading or, if not listed or admitted to trading, the average of the closing bid and asked prices of the Common Stock in the over-the-counter market as reported by NASDAQ or any comparable system. In the absence of one or more such quotations, the Board of Directors of the Company shall determine the current market price, in good faith, on the basis of such quotations as it considers appropriate. Notwithstanding the foregoing, for the purpose of any calculation under paragraph (d) above (A) with respect to any issuance of options under the Company's employee or director compensation stock option plans as in effect or as adopted by the Board of Directors of the Company on the date hereof, the term "current market price" in 8 218 such instances shall mean the fair market price on the date of the issuance of any such option determined in accordance with the Company's employee compensation stock option plans as in effect or as adopted by the Board of Directors of the Company on the date hereof; (B) with respect to any issuances of Common Stock (or rights, options, warrants or convertible securities containing the right to subscribe for or purchase shares of Common Stock) in connection with bona fide corporate transactions (other than issuances in such transactions for cash or similar consideration), the term "fair market price" shall mean the fair market price per share as determined in arm's-length negotiations by the Company and such other parties (other than affiliates or subsidiaries of the Company) to such transactions as reflected in the definitive documentation with respect thereto, unless such determination is not reasonably related to the closing market price on the date of such determination; and (c) with respect to any issuance of the Company's common stock for cash or similar consideration in a firm commitment underwriting, the current fair market price shall be the price the shares are sold at, regardless of whether such price is higher or lower than the quoted price on the date of the sale and therefore no adjustment will be made. (f) In any case in which this Section 8.1 shall require that any adjustment in the number of Warrant Shares be made effective as of immediately after a record date for a specified event, the Company may elect to defer until the occurrence of the event the issuing to the Holder of any Warrant exercised after that record date the shares of Common Stock and other securities of the Company, if any, issuable upon the exercise of any Warrant over and above the shares of Common Stock and other securities of the Company, if any, issuable upon the exercise of any Warrant prior to such adjustment; PROVIDED, HOWEVER, that the Company shall deliver to the holder a due bill or other appropriate instrument evidencing the holder's right to receive such additional shares or securities upon the occurrence of the event requiring such adjustment. (g) No adjustment in the number of Warrant Shares purchasable hereunder shall be required unless such adjustment would require an increase or decrease of at least one percent (1%) in the number of Warrant Shares purchasable upon the exercise of each Warrant; PROVIDED, HOWEVER, that any adjustments which by reason of this paragraph (g) are not required to be made shall be carried forward and taken into account in any subsequent adjustment. All calculations shall be made to the nearest one-thousandth of a share. 9 219 (h) Whenever the number of Warrant Shares purchasable upon the exercise of each Warrant is adjusted, as herein provided, the Warrant Price payable upon the exercise of each Warrant shall be adjusted by multiplying such Warrant Price immediately prior to such adjustment by a fraction, of which the numerator shall be the number of Warrant Shares purchasable upon the exercise of such Warrant immediately prior to such adjustment, and of which the denominator shall be the number of Warrant Shares purchasable immediately thereafter. (i) No adjustment in the number of Warrant Shares purchasable upon the exercise of each Warrant need be made under paragraphs (b), (c) and (d) if the Company issues or distributes to each Holder of Warrants the rights, options, warrants, or convertible or exchangeable securities, or evidences of indebtedness or assets referred to in those paragraphs which each Holder of Warrants would have been entitled to receive had the Warrants been exercised prior to the happening of such event or the record date with respect thereto regardless of whether the Warrants are exercisable at the time of the happening of such event or at the time of any record date with respect thereto. No adjustment need be made for a change in the par value of the Warrant Shares. (j) For the purpose of this Section 8.1, the term "shares of Common Stock" shall mean (i) the class of stock designated as the Common Stock of the Company at the date of this Agreement, or (ii) any other class of stock resulting from successive changes or reclassifications of such shares consisting solely of changes in par value, or from par value to no par value, or from no par value to par value. In the event that at any time, as a result of an adjustment made pursuant to paragraph (a) above, the Holders shall become entitled to purchase any securities of the Company other than shares of Common Stock, thereafter the number of such other securities so purchasable upon exercise of each Warrant and the Warrant Price of such securities shall be subject to adjustment from time to time in a manner and on terms as nearly equivalent as practicable to the provisions with respect to the Warrant Shares contained in paragraphs (a) through (i), inclusive, above, and the provisions of Section 4 and Sections 8.2 through 8.5, inclusive, with respect to the Warrant Shares, shall apply on like terms to any such other securities. (k) Upon the expiration of any rights, options, warrants or conversion or exchange privileges, if any thereof shall not have been exercised, the Warrant Price and the number of shares of Common Stock purchasable upon the exercise 10 220 of each Warrant shall, upon such expiration, be readjusted and shall thereafter be such as it would have been had it been originally adjusted (or had the original adjustment not been required, as the case may be) as if (A) the only shares of Common Stock so issued were the shares of Common Stock, if any, actually issued or sold upon the exercise of such rights, options, warrants or conversion or exchange rights and (B) such shares of Common Stock, if any, were issued or sold for the consideration actually received by the Company upon such exercise plus the aggregate consideration, if any, actually received by the Company for the issuance, sale or grant of all such rights, options, warrants or conversion or exchange rights whether or not exercised; PROVIDED, HOWEVER, that no such readjustment shall have the effect of increasing the Warrant Price or decreasing the number of Warrant Shares by an amount in excess of the amount of the adjustment initially made with respect to the issuance, sale or grant of such rights, options, warrants or conversion or exchange rights. 8.2. VOLUNTARY ADJUSTMENT BY THE COMPANY. The Company may, at its option, at any time during the term of the Warrants, reduce the then current Warrant Price to any amount determined appropriate by the Board of Directors of the Company. 8.3. NOTICE OF ADJUSTMENT. Whenever the number of Warrant Shares purchasable upon the exercise of each Warrant or the Warrant Price of such Warrant Shares is adjusted, as herein provided, the Company shall promptly mail by first class, postage prepaid, to each Holder notice of such adjustment or adjustments and a certificate of a firm of independent public accountants selected by the Board of Directors of the Company (who may be the regular accountants employed by the Company) setting forth the number of Warrant Shares purchasable upon the exercise of each Warrant and the Warrant Price of such Warrant Shares after such adjustment and setting forth a brief statement of the facts requiring such adjustment and setting forth the computation by which such adjustment was made. Such certificate, absent manifest error, shall be conclusive evidence of the correctness of such adjustment. 8.4. NO ADJUSTMENT FOR DIVIDENDS. Except as provided in Section 8.1, no adjustment in respect of any dividends shall be made during the term of a Warrant or upon the exercise of a Warrant. 8.5. PRESERVATION OF PURCHASE RIGHTS UPON MERGER, CONSOLIDATION, ETC. In case of any consolidation of the Company 11 221 with or merger of the Company into another corporation or in case of any sale, transfer or lease to another corporation of all or substantially all the property of the Company, the Company or such successor or purchasing corporation, as the case may be, shall execute with each Holder an agreement that each Holder shall have the right thereafter upon payment of the Warrant Price in effect immediately prior to such action to purchase upon exercise of each Warrant the kind and amount of shares and other securities and property which he would have owned or have been entitled to receive after the happening of such consolidation, merger, sale, transfer or lease had such Warrant been exercised immediately prior to such action regardless of whether the Warrants are exercisable at the time of such action; PROVIDED, HOWEVER, that no adjustment in respect of cash dividends, interest or other income on or from such shares or other securities and property shall be made during the term of a Warrant or upon the exercise of a Warrant. Such agreement shall provide for adjustments, which shall be as nearly equivalent as may be practicable to the adjustments provided for in this Section 8. The provisions of this Section 8.5 shall similarly apply to successive consolidations, mergers, sales, transfers or leases. 8.6. STATEMENT ON WARRANTS. Irrespective of any adjustments in the Warrant Price or the number or kind of shares purchasable upon the exercise of the Warrants, Warrants theretofore or thereafter issued may continue to express the same price and number and kind of shares as are stated in the Warrants initially issuable pursuant to this Agreement. 9. FRACTIONAL INTERESTS. The Company shall not be required to issue fractional Warrant Shares on the exercise of Warrants. If more than one Warrant shall be presented for exercise in full at the same time by the same Holder, the number of full Warrant Shares which shall be issuable upon the exercise thereof shall be computed on the basis of the aggregate number of Warrant Shares purchasable on exercise of the Warrants so presented. If any fraction of a Warrant Share would, except for the provisions of this Section 9, be issuable on the exercise of any Warrant (or specified portion thereof), the Company shall pay an amount in cash equal to the closing price for one share of the Common Stock, as determined in accordance with paragraph (e) of Section 8.1, on the trading day immediately preceding the date the Warrant is presented for exercise, multiplied by such fraction. 10. REGISTRATION UNDER THE SECURITIES ACT OF 1933. Holder represents and warrants to the Company that Holder will not dispose of any such Warrants or Warrant Shares except pursuant to (i) an 12 222 effective registration statement, or (ii) an applicable exemption from registration under the Securities Act of 1933 (the "Act"). In connection with any sale by Holder pursuant to clause (ii) of the preceding sentence, Holder shall furnish to the Company an opinion of counsel reasonably satisfactory to the Company to the effect that such exemption from registration is available in connection with such sale. The Company hereby agrees to file a registration statement with the Securities anc Exchange Commission within 90 days of the issuance of the Warrants to permit the holders of the Warrants to exercise the Warrants pursuant to the terms hereof. The Company agrees to ake all reasonable stpes to ensure that such registration statement will be promptly ordered effective by the Securities and Exchange Commission. Further, the Company agrees to make such filings pursuant to state securities laws to permit a holder to exerecise the Warrants within the time frame set forth in this paragraph. 11. NO RIGHTS AS STOCKHOLDERS; NOTICE TO HOLDERS. Nothing contained in this Agreement or in any of the Warrants shall be construed as conferring upon the Holders or their transferees the right to vote or to receive dividends or to consent or to receive notice as stockholders in respect of any meeting of stockholders for the election of directors of the Company or any other matter, or any rights whatsoever as stockholders of the Company. If, however, at any time prior to the expiration of the Warrants and prior to their exercise, any of the following events shall occur: (a) the Company shall declare any dividend payable in any securities upon its shares of Common Stock or make any distribution (other than a cash dividend) to the holders of its shares of Common Stock; or (b) the Company shall offer to the holders of its shares of Common Stock any additional shares of Common Stock or securities convertible into or exchangeable for shares of Common Stock or any right to subscribe to or purchase any thereof; or (c) a dissolution, liquidation or winding up of the Company (other than in connection with a consolidation, merger, sale, transfer or lease of all or substantially all of its property, assets, and business as an entirety) shall be proposed, then in any one or more of said events the Company shall (a) give notice in writing of such event to the Holders as provided in Section 12 hereof and (b) if there are more than 100 Holders, cause notice of such event to be published once in The Wall Street 13 223 Journal (national edition), such giving of notice and publication to be completed at least 15 days prior to the date fixed as a record date or the date of closing the transfer books for the determination of the stockholders entitled to such dividend, distribution, or subscription rights, or for the determination of stockholders entitled to vote on such proposed dissolution, liquidation or winding up. Such notice shall specify such record date or the date of closing the transfer books, as the case may be. Failure to publish, mail or receive such notice or any defect therein or in the publication or mailing thereof shall not affect the validity of any action taken in connection with such dividend, distribution or subscription rights, or such proposed dissolution, liquidation or winding up. 12. NOTICES. Any notice pursuant to this Agreement to be given or made by the Holder of any Warrant or Warrant Shares to or on the Company shall be sufficiently given or made if sent by first-class mail, postage prepaid, addressed as follows: Benton Oil and Gas Company 1145 Eugenia Place Suite 200 Carpinteria, California 93013 Attention: Gregory S. Grabar Notices or demands authorized by this Agreement to be given or made to or on the Holder of any Warrant or Warrant Shares shall be sufficiently given or made (except as otherwise provided in this Agreement) if sent by registered mail, return receipt requested, postage prepaid, addressed to such Holder at the address of such Holder as shown on the Warrant Register or the Common Stock Register, as the case may be. 13. GOVERNING LAW. This Agreement shall be governed by and construed in accordance with the laws of the State of California, without giving effect to principles of conflict of laws. 14. SUPPLEMENTS AND AMENDMENTS. The Company and the Holders may from time to time supplement or amend this Agreement in order to cure any ambiguity or to correct or supplement any provision contained herein which may be defective or inconsistent with any other provision herein, or to make any other provisions in regard to matters or questions arising hereunder which the Company and the Holder may deem necessary or desirable and which shall not be inconsistent with the provisions of the Warrants and which shall not adversely affect the interests of the Holders. Any amendment to this Agreement may be effected with the consent of Holders of at 14 224 least 66 2/3% of the Warrants (for this purpose Warrant Shares shall be deemed to be Warrants in the proportion that Warrant Shares are then issuable upon the exercise of Warrants); provided that, any amendment which shall have the effect of materially adversely affecting the interests of any Holder shall not be effective with respect to such Holder if such Holder shall not have consented thereto. 15. SUCCESSORS. All the covenants and provisions of this Agreement by or for the benefit of the Company or the Holders shall bind and inure to the benefit of their respective successors and assigns hereunder. 16. MERGER OR CONSOLIDATION OF THE COMPANY. So long as this Agreement remains in effect, the Company will not merge or consolidate with or into, or sell, transfer or lease all or substantially all of its property to, any other corporation unless the successor or purchasing corporation, as the case may be (if not the Company), shall expressly assume, by supplemental agreement executed and delivered to the Holders, the due and punctual performance and observance of each and every covenant and condition of this Agreement to be performed and observed by the Company. 17. BENEFITS OF THIS AGREEMENT. Nothing in this Agreement shall be construed to give to any person or corporation other than the Company and the Holders, any legal or equitable right, remedy or claim under this Agreement, but this Agreement shall be for the sole and exclusive benefit of the Company and the Holders of the Warrants and Warrant Shares. 18. CAPTIONS. The captions of the sections and subsections of this Agreement have been inserted for convenience and shall have no substantive effect. 19. COUNTERPARTS. This Agreement may be executed in any number of counterparts, each of which so executed shall be deemed to be an original; but such counterparts together shall constitute but one and the same instrument. 15 225 IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed on the day, month and year first above written. BENTON OIL AND GAS COMPANY By: ------------------------- Gregory S. Grabar Vice President-Corporate Development (CORPORATE SEAL) Attest: - ------------------------- Toni L. Jackson 16 226 EXHIBIT B Huddleston & Co., Inc. Petroleum and Geological Engineers 1111 Fannin-Suite 1700 Houston, Texas 77002 ____________ (713) 658-0248 March 8, 1995 Mr. A.E. Benton Benton Oil and Gas Company 1145 Eugenia Place Drive, Suite 200 Carpinteria, California 93013 Re: Benton Oil & Gas Combination Partnership 1989-1 L.P. Audit of Estimated Reserves and Revenues As of January 1, 1995 Dear Mr. Benton: Pursuant to your request, we have audited estimates of future reserves and associated revenues for certain properties owned by the Benton Oil & Gas Combination Partnership 1989-1 L.P. (the Partnership). These projections were originally prepared by the Benton Oil and Gas Company (Benton) engineering staff and have been audited by Huddleston & Co., Inc. (Huddleston). Properties reviewed in detail by our firm for the purposes of this audit include Umbrella Point Field located in Chambers County, Texas. These properties represent 100% of the total Proved revenues discounted at 10% attributable to the Partnership. A summary of the estimated reserves and revenues attributable to the subject properties, as of January 1, 1995, is as follows:
Net to Benton Oil and Gas Combination Partnership 1989-1 -------------------------------------------------------- Proved Developed ---------------- Constant Product Prices Producing Shut-in Behind Pipe Total - ----------------------- --------- ------- ----------- ----- Estimated Net Oil, bbl 19,662 353 4,115 24,130 Estimated Net Gas, MMcf 164.4 18.7 .1 183.2 Estimated Future Net Revenue (FNR), $ 354,558 18,385 37,212 410,155 Present Worth FNR, Disc. @ 10%, $ 289,842 14,128 21,570 325,540
REPORTING REQUIREMENTS - ---------------------- Securities and Exchange Commission (SEC) Regulation S-K, Item 102 and Regulation S-X, Rule 4-10 and Financial Accounting Standards Board (FASB) Statement No. 69 require oil and gas reserve information to be reported by publicly held entities as supplemental financial data. These regulations and standards provide for estimates of Proved reserves and associated revenues discounted at 10% based on product prices being received on the effective date of the report. 227 Mr. A.E. Benton Benton Oil and Gas Company March 8, 1995 Page Two The Society of Petroleum Engineers (SPE) requires Proved reserves to be economically recoverable with costs and prices in effect on the "as of" date of the report. In addition, the SPE has issued Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information which sets standards for the qualification and independence of reserve estimators and auditors and accepted methods for estimating and scheduling future reserves. In our opinion, both the audit performed by Huddleston and the estimates prepared by Benton have been performed in accordance with all applicable SEC, FASB, and SPE regulations and requirements. It should be noted that the reserve estimates shown herein are consistent with estimates prepared by Benton as of January 1, 1995. REPORT PREPARATION - ------------------ The estimated reserves and revenues provided for this review were initially prepared by Benton and have been reviewed in detail by our firm for the purposes of this audit. Where there were significant differences in the estimated reserves and revenues, Huddleston has suggested revisions in the Benton estimates and Benton has revised its projections accordingly. In our opinion, estimates for the properties, individually and in aggregate, are not materially different from those which would have been rendered by Huddleston had we independently projected the reserve volumes. In performing our audit we have utilized certain geological and petrophysical studies which were prepared by Benton and representatives of the current and previous operators. We have reviewed these studies and have found them to be reasonable with respect to the subject reservoirs; however, we have not attempted to independently prepare geological interpretations or estimates of reservoir parameters. In some cases we have utilized information from our files relating to previous studies of certain properties shown herein. The projections which were reviewed for the purposes of this audit represent 100% of the total future revenues as projected by Benton. Huddleston has not attempted to review projections for the remaining properties in detail; however, these properties have not been assigned any future reserves. We do not believe that a review of these properties would result in a material revision of the total estimated reserves and revenues. The projections shown herein were based on performance data from public sources available in June 1994; however, data of this type is subject to delays as a result of regulatory reporting requirements and the timing of the commercial sources providing such data. The cash flow projections were prepared utilizing a commercially available software package marketed by David P. Cook & Associates. We have generally reviewed the output of the calculation procedures utilized by the program and believe them to be mathematically correct for the purposes of this audit. PRODUCT PRICES - -------------- It is our understanding that SEC regulations require future revenues to be projected on the basis of product prices in effect on the "as of" date of the report without further escalations or reductions. However, certain variations in product prices, attributable to contractual provisions, may be utilized in the preparation of the cash flows where the prices are specified by the contract. 228 Mr. A.E. Benton Benton Oil and Gas Company March 8, 1995 Page Three The projections shown herein have been based on actual prices being received on December 31, 1994. These prices were held constant over the life of the properties. Market prices for both oil and gas continue to be subject to a significant degree of variation in both domestic and international markets and reductions in the market prices for oil volumes have materially affected the value of our previous reserve estimates. A comparison of the average product prices, weighted as a composite for all properties, is as follows:
Constant Product Prices Oil, $/bbl Gas, $/Mcf ----------------------- ---------- ---------- 1995 15.94 1.60 Maximum 15.94 1.60 Average Over Life 15.94 1.60
PROJECTIONS - ----------- The estimated reserves and revenues have been projected on a calendar year basis with the first time period being January 1, 1995, through December 31, 1995. RESERVES ESTIMATES - ------------------ Reserve estimates for the properties reviewed for the purpose of this audit have been prepared with consideration of the available data and the nature of the producing horizons. The projections have been based on performance data for the existing completions, analogy to other completions in the subject reservoirs, and volumetric calculations. Estimates prepared on the basis of analogy and volumetric calculations will be subject to much greater variation than those prepared for depletion drive reservoirs having established production trends. UMBRELLA POINT FIELD - This property operated by French Production, Incorporated, is located in state waters offshore Chambers County, Texas, and produces from multiple reservoirs. Projections for this property were based primarily on the extrapolation of production data with consideration for water cut and pressure information, where available. We have also utilized information from our files from previous studies prepared by our firm relating to this property. In general, the productive reservoirs for this property are in the latter stages of depletion and future recoveries may be influenced by both mechanical and reservoir factors. OTHER PROPERTIES - We have not attempted to independently prepare estimates of future reserves for the remaining properties located in East Cameron Block 229 Field; however, we have reviewed the projections with consideration for historical production levels. The Benton estimates are consistent with recent performance and Benton has projected that the properties do not have any future economically recoverable reserves. GENERAL CONCLUSIONS - On an overall basis, we have not encountered materials differences in our reserve estimates and those prepared by Benton. However, the projected reserves shown herein have been extracted from the total Benton report and represent minor values relative to all properties owned by Benton. The properties shown have therefore been studied to a much lesser extent than if reserves had been prepared separately. In cases where we have encountered significant differences in estimated recoveries, Benton has consented to the revision of its reserve estimates to be consistent with projections by Huddleston. 229 Mr. A.E. Benton Benton Oil and Gas Company March 8, 1995 Page Four The reserve estimates for the properties owned by the Partnership will be subject to a significant degree of variation due to the nature of the producing reservoirs and the stage of depletion of the properties. OPERATING AND CAPITAL COSTS - --------------------------- Huddleston has reviewed operating costs utilized by Benton and believes they are appropriate for the subject properties. Severance and ad valorem taxes were deducted from gross revenues in accordance with statutory rates. All taxes (excluding income taxes) were estimated by Benton and have been deducted from future revenues. All capital costs were based on information provided by Benton. Huddleston has generally reviewed these costs and believes they are reasonable with respect to the proposed operations and properties. All capital and operating expenditures were held constant over the life of the properties. FACTORS NOT INCLUDED - -------------------- Values were not assigned to nonproducing acreage or to the salvage of surface and subsurface equipment. General office overhead, income taxes, and allowances for depletion, depreciation, and amortization have not been deducted from future revenues. REPORT QUALIFICATIONS - --------------------- THE ESTIMATED REVENUES AND PRESENT VALUE OF THESE REVENUES ARE NOT REPRESENTED AS MARKET VALUE. Estimates for individual completions should be considered in context with the overall or total estimated revenues. Actual individual lease performances will vary considerably from the projections particularly in comparison to the total estimated production from all properties. We did not inspect the properties or conduct independent well tests. Ownership, product prices, and other factual data have been accepted as represented by Benton. We have generally tested these data and believe the information is correct. Respectfully submitted, Peter D. Huddleston, P.E. PDH:JPK:dbw 230 Huddleston & Co., Inc. Petroleum and Geological Engineers 1111 Fannin-Suite 1700 Houston, Texas 77002 ____________ (713) 658-0248 March 8, 1995 Mr. A.E. Benton Benton Oil and Gas Company 1145 Eugenia Place, Suite 200 Carpinteria, California 93013 Re: Benton Oil & Gas Combination Partnership 1990-1 L.P. Audit of Estimated Reserves and Revenues As of January 1, 1995 Dear Mr. Benton: Pursuant to your request, we have audited estimates of future reserves and associated revenues for certain properties owned by the Benton Oil & Gas Combination Partnership 1990-1 L.P. These projections were originally prepared by the Benton Oil & Gas Company (Benton) engineering staff and have been audited by Huddleston & Co., Inc. (Huddleston). The reviewed properties are located in West Cote Blanche Bay Field, St. Mary Parish, Louisiana, and Umbrella Point Field, Chambers County, Texas. Estimates of future reserves and revenues for 100% of the discounted future revenues were audited by our firm. A summary of the estimated reserves and revenues attributable to the subject properties is as follows:
Net to Benton Oil and Gas Combination Partnership 1990-1 -------------------------------------------------------- Proved -------------------------------------------------- Constant Product Prices Producing Nonproducing Undeveloped Total - ----------------------- --------- ------------ ----------- ----- West Cote Blanche Bay Field - --------------------------- Estimated Net Oil, bbl 4 190 1,128 1,322 Estimated Net Gas, MMcf 2.9 19.1 110.5 132.5 Estimated Future Net Revenue (FNR),$ 4,900 30,384 157,868 193,152 Present Worth FNR, Disc. at 10%, $ 4,794 23,787 91,113 119,694 Umbrella Point Field - -------------------- Estimated Net Oil, bbl 56,617 12,871 0 69,488 Estimated Net Gas, MMcf 473.2 54.2 0.0 527.4 Estimated Future Net Revenue (FNR), $ 1,020,956 160,192 0 1,181,148 Present Worth FNR, Disc. at 10%, $ 834,576 102,853 0 937,429 Total - ----- Estimated Net Oil, bbl 56,621 13,061 1,128 70,810 Estimated Net Gas, MMcf 476.2 73.3 110.5 659.9 Estimated Future Net Revenue (FNR), $ 1,025,856 190,575 157,868 1,374,299 Present Worth FNR, Disc. at 10%, $ 839,370 126,640 91,113 1,057,123 Note: The nonproducing category includes behind pipe and shut-in categories.
231 Mr. A.E. Benton Benton Oil and Gas Company March 8, 1995 Page Two REPORTING REQUIREMENTS - ---------------------- Securities and Exchange Commission (SEC) Regulation S-K, Item 102 and Regulation S-X, Rule 4-10 and Financial Accounting Standards Board (FASB) Statement No. 69 require oil and gas reserve information to be reported by publicly held entities as supplemental financial data. These regulations and standards provide for estimates of Proved reserves and associated revenues discounted at 10% based on product prices being received on the effective date of the report. The Society of Petroleum Engineers (SPE) requires Proved reserves to be economically recoverable with costs and prices in effect on the "as of" date of the report. In addition, the SPE has issued Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information which sets standards for the qualifications and independence of reserve estimators and auditors and accepted methods for estimating and scheduling future reserves. In our opinion, both the audit performed by Huddleston, and the estimates prepared by Benton have been performed in accordance with all applicable SEC, FASB, and SPE regulations and requirements. It should be noted that the reserve estimates shown herein are consistent with estimates prepared by Benton as of January 1, 1995. REPORT PREPARATION - ------------------ The estimated reserves and revenues provided for this review were initially prepared by Benton and have been reviewed in detail by our firm for the purposes of this audit. Where there were significant differences in the estimated reserves and revenues, Huddleston has suggested revisions in the Benton estimates and Benton has revised its projections accordingly. In our opinion, estimates for the properties, individually and in aggregate, are not materially different from those which would have been rendered by Huddleston had we independently projected the reserve volumes. In performing our audit we have utilized certain geological and petrophysical studies which were prepared by Benton and representatives of the current and previous operators. We have reviewed these studies and have found them to be reasonable with respect to the subject reservoirs; however, we have not attempted to independently prepare geological interpretations or estimates of reservoir parameters. In some cases we have utilized information from our files relating to previous studies of certain properties shown herein. The projections which were reviewed for the purposes of this audit represent 100% of the total future revenues as projected by Benton. The projections shown herein were based on performance data derived from public sources available in January 1995; however, data of this type is subject to delays as a result of regulatory reporting requirements and the timing of the commercial sources providing such data. The cash flow projections were prepared utilizing a commercially available software package marketed by David P. Cook & Associates. We have generally reviewed the output of the calculation procedures utilized by the program and believe them to be mathematically correct for the purposes of this audit. 232 Mr. A.E. Benton Benton Oil and Gas Company March 8, 1995 Page Three PRODUCT PRICES - -------------- It is our understanding that SEC regulations require future revenues to be projected on the basis of product prices in effect on the "as of" date of the report without further escalations or reductions. However, certain variations in product prices, attributable to contractual provisions, may be utilized in the preparation of the cash flows where the prices are specified by the contract. The projections shown herein were based on actual product prices being received on December 31, 1994. These prices were held constant over the life of the properties. Market prices for both oil and gas continue to be subject to a significant degree of variation in both domestic and international markets. Future variations in the projected prices may materially affect our projections of economically recoverable reserves and associated revenues. A comparison of the average product prices, weighted as a composite for all properties, is a follows:
Constant Product Prices Oil, $/bbl Gas, $/Mcf ----------------------- ---------- ---------- 1995 15.94 1.60 Maximum 15.94 1.60 Average Over Life 15.94 1.60
PROJECTIONS - ----------- The estimated reserves and revenues have been projected on a calendar year basis with the first time period being January 1, 1995, through December 31, 1995. PROPERTY SALE - ------------- The projections shown herein reflect the divestiture of interests owned by the partnership in the Shallow Oil Reservoirs in West Cote Blanche Bay Field which was effective January 1, 1995. The partnership retained interests in the Gas Cap Reservoirs in this property. RESERVE ESTIMATES - ----------------- Reserve estimates for the properties reviewed for the purpose of this audit have been prepared with consideration of the available data and the nature of the producing horizons. The projections have been based on performance data for the existing completions, analogy to other completions in the subject reservoirs, and volumetric calculations. Estimates prepared on the basis of analogy and volumetric calculations will be subject to much greater variation than those prepared for depletion drive reservoirs having established production trends. UMBRELLA POINT FIELD - This property operated by French Production, Incorporated, is located in state waters offshore Chambers County, Texas, and produces from multiple reservoirs. Projections for this property were based primarily on the extrapolation of production data with consideration for water cut and pressure information where available. We have also utilized information from our files from previous studies prepared by our firm relating to this property. In general, the productive reservoirs for this property are in the latter stages of depletion and future recoveries may be influenced by both mechanical and reservoir factors. 233 Mr. A.E. Benton Benton Oil and Gas Company March 8, 1995 Page Four WEST COTE BLANCHE BAY FIELD - Estimated reserves for the gas cap reservoirs have been assigned on the basis of volumetric calculations for eight horizons ranging in depth from 9,000 to 12,000 feet in three fault blocks. The volumetric calculations have been based on log-derived parameters and geological interpretations prepared on the basis of subsurface information, pressure information, and geophysical interpretations based on 3-D seismic data. Subsequent to our previous review, revised geological interpretations have resulted in the transfer of reserves for the 12,600' reservoir to location 1-A (#868) from well #720 with no change in the estimated recoverable reserves. Additional recoverable reserves have been assigned to the 38 and 38A reservoirs based on geologic interpretations with consideration for historical performance data. The projected reserves for the #831 gas well, 13,900' reservoir, have been revised relative to our July 1, 1994, evaluation on the basis of performance data to reflect an ultimate recovery of 6,400 MMcf. The remaining reserves for this reservoir have been transferred to location 1- A (#868). OTHER PROPERTIES - We have not attempted to independently prepare estimates of future reserves for the remaining properties located in East Cameron Block 229 Field. However, we have reviewed the projections with consideration for historical production levels. The Benton estimates are consistent with recent rates of production and Benton has projected that the properties do not have any additional economically recoverable reserves. GENERAL CONCLUSIONS - On an overall basis, we have not encountered material differences in our reserve estimates and those prepared by Benton. In cases where we have encountered significant differences in estimated recoveries, Benton has consented to the revision of its reserve estimates to be consistent with projections by Huddleston. The projected reserves shown herein will be subject to a significant level of variation due to the nature of the subject reservoirs, the stage of depletion of the producing horizons, the reserve estimation techniques, and the actual schedule of future remedial and development operations. Huddleston has relied on Benton to provide development schedules. The scheduling of future operations will be influenced by a variety of factors including economic and market conditions, political considerations, availability of funds, alternative investment opportunities, leasehold obligations, and internal decision making. Variations in the execution of these development plans may have a material impact on the economic value of both the discounted and undiscounted revenue streams. OPERATING AND CAPITAL COSTS - --------------------------- Huddleston has reviewed operating costs utilized by Benton and believes they are appropriate for the subject properties. Costs for all properties were consistent with historical levels. Severance and ad valorem taxes were deducted from gross revenues in accordance with statutory rates. All taxes (excluding income taxes) were estimated by Benton and have been deducted from future revenues. All capital costs were based on information provided by Benton. Huddleston has generally reviewed these costs and believes they are reasonable. The capital costs shown for the remedial operations for West Cote Blanche Bay Field have been adjusted to reflect the statistical success rates of remedial operations and variations in the depth of the historical and proposed operations. All capital and operating expenditures were held constant over the life of the properties. 234 Mr. A.E. Benton Benton Oil and Gas Company March 8, 1995 Page Five FACTORS NOT INCLUDED - -------------------- Values were not assigned to nonproducing acreage or to the salvage of surface and subsurface equipment. General office overhead, income taxes, and allowances for depletion, depreciation, and amortization have not been deducted from future revenues. REPORT QUALIFICATIONS - --------------------- THE ESTIMATED REVENUES AND PRESENT VALUE OF THESE REVENUES ARE NOT REPRESENTED AS MARKET VALUE. Estimates for individual completions should be considered in context with the overall or total estimated revenues. Actual individual lease performances will vary considerably from the projections particularly in comparison to the total estimated production from all properties. We did not inspect the properties or conduct independent well tests. Ownership, product prices, and other factual data have been accepted as represented by Benton. We have generally tested these data and believe the information is correct. Respectfully submitted, Peter D. Huddleston, P.E. PDH:JPK:dbw 235 Huddleston & Co., Inc. Petroleum and Geological Engineers 1111 Fannin-Suite 1700 Houston, Texas 77002 --------------------- (713) 658-0248 March 8, 1995 Mr. A.E. Benton Benton Oil and Gas Company 1145 Eugenia Place Drive, Suite 200 Carpinteria, California 93013 Re: Benton Oil & Gas Combination Partnership 1991-1 L.P. Audit of Estimated Reserves and Revenues As of January 1, 1995 Dear Mr. Benton: Pursuant to your request, we have audited estimates of future reserves and associated revenues for certain properties owned by the Benton Oil & Gas Combination Partnership 1991-1 L.P. These projections were originally prepared by the Benton Oil & Gas Company (Benton) engineering staff and have been audited by Huddleston & Co., Inc. (Huddleston). The reviewed properties are located in West Cote Blanche Bay Field, St. Mary Parish, Louisiana, and Umbrella Point Field, Chambers County, Texas. Estimates of future reserves and revenues for 100% of the discounted future revenues were audited by our firm. A summary of the estimated reserves and revenues attributable to the subject properties is as follows:
Net to Benton Oil and Gas Combination Partnership 1991-1 -------------------------------------------------------- Proved ------ Constant Product Prices Producing Nonproducing Undeveloped Total - ----------------------- --------- ------------ ----------- ------ West Cote Blanche Bay Field - --------------------------- Estimated Net Oil, bbl 1 38 225 264 Estimated Net Gas, MMcf .6 3.8 22.0 26.4 Estimated Future Net Revenue (FNR),$ 979 6,056 31,456 38,491 Present Worth FNR, Disc. @ 10%, $ 958 4,743 18,155 23,856 Umbrella Point Field - -------------------- Estimated Net Oil, bbl 11,269 2,563 0 13,832 Estimated Net Gas, MMcf 94.2 10.8 0.0 105.0 Estimated Future Net Revenue (FNR), $ 203,203 31,907 0 235,110 Present Worth FNR, Disc. at 10%, $ 166,097 20,492 0 186,589 Total - ----- Estimated Net Oil, bbl 11,270 2,601 225 14,096 Estimated Net Gas, MMcf 94.8 14.6 22.0 131.3 Estimated Future Net Revenue (FNR), $ 204,182 37,963 31,456 273,601 Present Worth FNR, Disc. at 10%, $ 167,055 25,235 18,155 210,445 Note: The nonproducing category includes behind pipe and shut-in categories.
236 Mr. A.E. Benton Benton Oil and Gas Company March 8, 1995 Page Two REPORTING REQUIREMENTS - ---------------------- Securities and Exchange Commission (SEC) Regulation S-K, Item 102 and Regulation S-X, Rule 4-10 and Financial Accounting Standards Board (FASB) Statement No. 69 require oil and gas reserve information to be reported by publicly held entities as supplemental financial data. These regulations and standards provide for estimates of Proved reserves and associated revenues discounted at 10% based on product prices being received on the effective date of the report. The Society of Petroleum Engineers (SPE) requires Proved reserves to be economically recoverable with costs and prices in effect on the "as of" date of the report. In addition, the SPE has issued Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information which sets standards for the qualification and independence of reserve estimators and auditors and accepted methods for estimating and scheduling future reserves. In our opinion, both the audit performed by Huddleston, and the estimates prepared by Benton have been performed in accordance with all applicable SEC, FASB, and SPE regulations and requirements. It should be noted that the reserve estimates shown herein are consistent with estimates prepared by Benton as of January 1, 1995. REPORT PREPARATION - ------------------ The estimated reserves and revenues provided for this review were initially prepared by Benton and have been reviewed in detail by our firm for the purposes of this audit. Where there were significant differences in the estimated reserves and revenues, Huddleston has suggested revisions in the Benton estimates and Benton has revised its projections accordingly. In our opinion, estimates for the properties, individually and in aggregate, are not materially different from those which would have been rendered by Huddleston had we independently projected the reserve volumes. In performing our audit we have utilized certain geological and petrophysical studies which were prepared by Benton and representatives of the current and previous operators. We have reviewed these studies and have found them to be reasonable with respect to the subject reservoirs; however, we have not attempted to independently prepare geological interpretations or estimates of reservoir parameters. In some cases we have utilized information from our files relating to previous studies of certain properties shown herein. The projections which were reviewed for the purposes of this audit represent 100% of the total future revenues as projected by Benton. The projections shown herein were based on performance data derived from public sources available in January 1995; however, data of this type is subject to delays as a result of regulatory reporting requirements and the timing of the commercial sources providing such data. The cash flow projections were prepared utilizing a commercially available software package marketed by David P. Cook & Associates. We have generally reviewed the output of the calculation procedures utilized by the program and believe them to be mathematically correct for the purposes of this audit. 237 Mr. A.E. Benton Benton Oil and Gas Company March 8, 1995 Page Three PRODUCT PRICES - -------------- It is our understanding that SEC regulations require future revenues to be projected on the basis of product prices in effect on the "as of" date of the report without further escalations or reductions. However, certain variations in product prices, attributable to contractual provisions, may be utilized in the preparation of the cash flows where the prices are specified by the contract. The projections shown herein have been based on actual prices being received on December 31, 1994. These prices were held constant over the life of the properties. Market prices for both oil and gas continue to be subject to a significant degree of variation in both domestic and international markets. Future variations in the projected prices may materially affect our projections of economically recoverable reserves and associated revenues. A comparison of the average product prices, weighted as a composite for all properties, is as follows:
Constant Product Prices Oil, $/bbl Gas, $/Mcf ----------------------- ---------- ---------- 1995 15.95 1.63 Maximum 16.00 1.75 Average Over Life 15.94 1.63
PROJECTIONS - ----------- The estimated reserves and revenues have been projected on a calendar year basis with the first time period being January 1, 1995, through December 31, 1995. PROPERTY SALE - ------------- The projections shown herein reflect the divestiture of interests owned by the partnership in the Shallow Oil Reservoirs in West Cote Blanche Bay Field which was effective January 1, 1995. The partnership retained interests in the Gas Cap Reservoirs in this property. RESERVES ESTIMATES - ------------------ Reserve estimates for the properties reviewed for the purpose of this audit have been prepared with consideration of the available data and the nature of the producing horizons. The projections have been based on performance data for the existing completions, analogy to other completions in the subject reservoirs, and volumetric calculations. Estimates prepared on the basis of analogy and volumetric calculations will be subject to much greater variation than those prepared for depletion drive reservoirs having established production trends. UMBRELLA POINT FIELD - This property operated by French Production, Incorporated, is located in state waters offshore Chambers County, Texas, and produces from multiple reservoirs. Projections for this property were based primarily on the extrapolation of production data with consideration for water cut and pressure information, where available. We have also utilized information from our files from previous studies prepared by our firm relating to this property. In general, the productive reservoirs for this property are in the latter stages of depletion and future recoveries may be influenced by both mechanical and reservoir factors. 238 Mr. A.E. Benton Benton Oil and Gas Company March 8, 1995 Page Four WEST COTE BLANCHE BAY FIELD - Estimated reserves for the gas cap reservoirs have been assigned on the basis of volumetric calculations for eight horizons ranging in depth from 9,000 to 12,000 feet in three fault blocks. The volumetric calculations have been based on log-derived parameters and geological interpretations prepared on the basis of subsurface information, pressure information, and geophysical interpretations based on 3-D seismic data. Subsequent to our previous review, revised geological interpretations have resulted in the transfer of reserves for the 12,600' reservoir to location 1-A (#868) from well #720 with no change in the estimated recoverable reserves. Additional recoverable reserves have been assigned to the 38 and 38A reservoirs based on geologic interpretations with consideration for historical performance data. The projected reserves for the #831 gas well, 13,900' reservoir, have been revised relative to our July 1, 1994, evaluation on the basis of performance data to reflect an ultimate recovery of 6,400 MMcf. The remaining reserves for this reservoir have been transferred to location 1- A (#868). GENERAL CONCLUSIONS - On an overall basis, we have not encountered materials differences in our reserve estimates and those prepared by Benton. In cases where we have encountered significant differences in estimated recoveries, Benton has consented to the revision of its reserve estimates to be consistent with projections by Huddleston. The projected reserves shown herein will be subject to a significant level of variation due to the nature of the subject reservoirs, the stage of depletion of the producing horizons, the reserve estimation techniques, and the actual schedule of future remedial and development operations. Huddleston has relied on Benton to provide development schedules. The scheduling of future operations will be influenced by a variety of factors including economic and market conditions, political considerations, availability of funds, alternative investment opportunities, leasehold obligations, and internal decision making. Variations in the execution of these development plans may have a material impact on the economic value of both the discounted and undiscounted revenue streams. OPERATING AND CAPITAL COSTS - --------------------------- Huddleston has reviewed operating costs utilized by Benton and believes they are appropriate for the subject properties. Costs for all properties were consistent with historical levels. Severance and ad valorem taxes were deducted from gross revenues in accordance with statutory rates. all taxes (excluding income taxes) were estimated by Benton and have been deducted from future revenues. All capital costs were based on information provided by Benton. Huddleston has generally reviewed these costs and believes they are reasonable. The capital costs shown for the remedial operations for West Cote Blanche Bay Field have been adjusted to reflect the statistical success rates of remedial operations and variations in the depth of the historical and proposed operations. All capital and operating expenditures were held constant over the life of the properties. FACTORS NOT INCLUDED - -------------------- Values were not assigned to nonproducing acreage or to the salvage of surface and subsurface equipment. General office overhead, income taxes, and allowances for depletion, depreciation, and amortization have not been deducted from future revenues. 239 Mr. A.E. Benton Benton Oil and Gas Company March 8, 1995 Page Five REPORT QUALIFICATIONS - --------------------- THE ESTIMATED REVENUES AND PRESENT VALUE OF THESE REVENUES ARE NOT REPRESENTED AS MARKET VALUE. Estimates for individual completions should be considered in context with the overall or total estimated revenues. Actual individual lease performances will vary considerably from the projections particularly in comparison to the total estimated production from all properties. We did not inspect the properties or conduct independent well tests. Ownership, product prices, and other factual data have been accepted as represented by Benton. We have generally tested these data and believe the information is correct. Respectfully submitted, Peter D. Huddleston, P.E. PDH:JPK:dbw 240 EXHIBIT C THE PROPOSAL Set forth below is a proposed amendment ("Amendment") to the Agreement of Limited Partnership (the "Partnership Agreement") of Benton Oil and Gas Combination Partnership 1989-1 Limited Partnership (the "Partnership"). This Amendment shall be effective upon the acceptance pursuant to the Exchange Offer of written consents from Investors holding not less than 75% of the Interests in the Partnership. If the Amendment becomes effective, it will become a separate article of the Partnership Agreement and shall be placed immediately after the last article contained in the Partnership Agreement. PROPOSED AMENDMENT Notwithstanding any provisions of this Agreement to the contrary, it is hereby agreed as follows: 1. Definitions. Except as defined in the Partnership Agreement or this article, each capitalized term used herein shall, for the purposes of this article, have the meaning ascribed to it in the Prospectus of Benton Oil and Gas Company, a Delaware corporation ("Benton"), dated ________________, 1995. 2. Elimination of Restrictions. No provision of this Agreement shall prohibit, limit or prevent (i) the transfer and conveyance of all the assets and liabilities of the limited partnership formed by this Agreement (the "Partnership") to Benton in exchange for Interests pursuant to and in accordance with the terms of the Exchange Offer or otherwise, or (ii) the distribution of Interests to partners of the Partnership ("Partners") upon dissolution of the Partnership. In addition, no consent of the Partnership or any Partner, opinion of counsel or other procedure shall be required in order to enable any Partner, the Partnership or Benton to effect any such transfer, Exchange Offer or distribution. 3. Exchange of Partnership Assets and Liabilities for Interests. Effective as of the Effective Date, the Partnership shall transfer and convey all Partnership's assets and liabilities to Benton in exchange for Interests pursuant to and in accordance with the terms of the Exchange Offer. 4. Election to Dissolve. Immediately after consummation of the Exchange Offer, the Partnership shall be dissolved. Upon its dissolution, the business and affairs of the Partnership shall be terminated and wound up and, as soon as practicable thereafter, any and all Interests held by the Partnership shall be distributed in kind to the Partners (or their assignees) with each Partner (or his assignee) to receive a whole number of Common Stock and Warrants equal to the Exchange Value of his Interest divided by the Exchange Price. 5. Authority of General Partner. Benton, in its capacity as managing general partner of the Partnership, shall execute, acknowledge, verify, deliver, file and record, for and in the name of the Partnership, any and all documents and shall do and perform all acts required by applicable law or that it deems necessary or desirable in order to give effect to this article and the transactions contemplated herein, including by not limited to thedissolution, termination, winding-up and distribution contemplated by paragraph 4 of this article. 6. This Article Controlling. The provisions of this article shall control over all other provisions of this Agreement. Except as herein expressly amended, all other terms and provisions of the Certificate and this Agreement shall remain in full force and effect. 241 EXHIBIT C THE PROPOSAL Set forth below is a proposed amendment ("Amendment") to the Agreement of Limited Partnership (the "Partnership Agreement") of Benton Oil and Gas Combination Partnership 1990-1 Limited Partnership (the "Partnership"). This Amendment shall be effective upon the acceptance pursuant to the Exchange Offer of written consents from Investors holding not less than 75% of the Interests in the Partnership. If the Amendment becomes effective, it will become a separate article of the Partnership Agreement and shall be placed immediately after the last article contained in the Partnership Agreement. PROPOSED AMENDMENT Notwithstanding any provisions of this Agreement to the contrary, it is hereby agreed as follows: 1. Definitions. Except as defined in the Partnership Agreement or this article, each capitalized term used herein shall, for the purposes of this article, have the meaning ascribed to it in the Prospectus of Benton Oil and Gas Company, a Delaware corporation ("Benton"), dated ________________, 1995. 2. Elimination of Restrictions. No provision of this Agreement shall prohibit, limit or prevent (i) the transfer and conveyance of all the assets and liabilities of the limited partnership formed by this Agreement (the "Partnership") to Benton in exchange for Interests pursuant to and in accordance with the terms of the Exchange Offer or otherwise, or (ii) the distribution of Interests to partners of the Partnership ("Partners") upon dissolution of the Partnership. In addition, no consent of the Partnership or any Partner, opinion of counsel or other procedure shall be required in order to enable any Partner, the Partnership or Benton to effect any such transfer, Exchange Offer or distribution. 3. Exchange of Partnership Assets and Liabilities for Interests. Effective as of the Effective Date, the Partnership shall transfer and convey all Partnership's assets and liabilities to Benton in exchange for Interests pursuant to and in accordance with the terms of the Exchange Offer. 4. Election to Dissolve. Immediately after consummation of the Exchange Offer, the Partnership shall be dissolved. Upon its dissolution, the business and affairs of the Partnership shall be terminated and wound up and, as soon as practicable thereafter, any and all Interests held by the Partnership shall be distributed in kind to the Partners (or their assignees) with each Partner (or his assignee) to receive a whole number of Common Stock and Warrants equal to the Exchange Value of his Interest divided by the Exchange Price. 5. Authority of General Partner. Benton, in its capacity as managing general partner of the Partnership, shall execute, acknowledge, verify, deliver, file and record, for and in the name of the Partnership, any and all documents and shall do and perform all acts required by applicable law or that it deems necessary or desirable in order to give effect to this article and the transactions contemplated herein, including by not limited to the dissolution, termination, winding-up and distribution contemplated by paragraph 4 of this article. 6. This Article Controlling. The provisions of this article shall control over all other provisions of this Agreement. Except as herein expressly amended, all other terms and provisions of the Certificate and this Agreement shall remain in full force and effect. 242 EXHIBIT C THE PROPOSAL Set forth below is a proposed amendment ("Amendment") to the Agreement of Limited Partnership (the "Partnership Agreement") of Benton Oil and Gas Combination Partnership 1991-1 Limited Partnership (the "Partnership"). This Amendment shall be effective upon the acceptance pursuant to the Exchange Offer of written consents from Investors holding not less than 75% of the Interests in the Partnership. If the Amendment becomes effective, it will become a separate article of the Partnership Agreement and shall be placed immediately after the last article contained in the Partnership Agreement. PROPOSED AMENDMENT Notwithstanding any provisions of this Agreement to the contrary, it is hereby agreed as follows: 1. Definitions. Except as defined in the Partnership Agreement or this article, each capitalized term used herein shall, for the purposes of this article, have the meaning ascribed to it in the Prospectus of Benton Oil and Gas Company, a Delaware corporation ("Benton"), dated ________________, 1995. 2. Elimination of Restrictions. No provision of this Agreement shall prohibit, limit or prevent (i) the transfer and conveyance of all the assets and liabilities of the limited partnership formed by this Agreement (the "Partnership") to Benton in exchange for Interests pursuant to and in accordance with the terms of the Exchange Offer or otherwise, or (ii) the distribution of Interests to partners of the Partnership ("Partners") upon dissolution of the Partnership. In addition, no consent of the Partnership or any Partner, opinion of counsel or other procedure shall be required in order to enable any Partner, the Partnership or Benton to effect any such transfer, Exchange Offer or distribution. 3. Exchange of Partnership Assets and Liabilities for Interests. Effective as of the Effective Date, the Partnership shall transfer and convey all Partnership's assets and liabilities to Benton in exchange for Interests pursuant to and in accordance with the terms of the Exchange Offer. 4. Election to Dissolve. Immediately after consummation of the Exchange Offer, the Partnership shall be dissolved. Upon its dissolution, the business and affairs of the Partnership shall be terminated and wound up and, as soon as practicable thereafter, any and all Interests held by the Partnership shall be distributed in kind to the Partners (or their assignees) with each Partner (or his assignee) to receive a whole number of Common Stock and Warrants equal to the Exchange Value of his Interest divided by the Exchange Price. 5. Authority of General Partner. Benton, in its capacity as managing general partner of the Partnership, shall execute, acknowledge, verify, deliver, file and record, for and in the name of the Partnership, any and all documents and shall do and perform all acts required by applicable law or that it deems necessary or desirable in order to give effect to this article and the transactions contemplated herein, including by not limited to the dissolution, termination, winding-up and distribution contemplated by paragraph 4 of this article. 6. This Article Controlling. The provisions of this article shall control over all other provisions of this Agreement. Except as herein expressly amended, all other terms and provisions of the Certificate and this Agreement shall remain in full force and effect. 243 EXHIBIT D BENTON OIL AND GAS COMPANY LETTER OF TRANSMITTAL FOR INVESTORS IN BENTON OIL AND GAS COMBINATION PARTNERSHIP 1989 - 1 L.P. Capitalized terms used but not defined herein have the meanings given to them in the Prospectus of Benton Oil and Gas Company, as supplemented or amended (the "Prospectus"). General instructions are included in Part VI. This Letter of Transmittal must be received by the Exchange Agent on or before 5:00 p.m. Eastern Time, on ______________, 1995 unless the Exchange Offer is extended. To accept the Exchange Offer or withhold consent to the related Proposal, please complete this Letter in accordance with the Instructions in Items IV and VI, and send or deliver the completed Letter of Transmittal to the Exchange Agent. Neither accepting the Exchange Offer nor withholding consent to the Proposal will prevent an Investor from challenging the fairness of the Exchange Offer. Adoption of the Proposal requires consent by Investors holding 75% of the units in the Partnership. Assuming consummation of the Exchange Offer, all of the partners of the Partnership, whether or not they tender their Interests, will receive the same number of shares of Common Stock and Warrants they would have received had they tendered their Interests, except that California investors exercising their limited dissenters' rights may receive a higher or lower number of shares or warrants. See Part V below and "The Exchange Offer and Proposal" in the Prospectus. Exchange Agent: Benton Oil and Gas Company By Mail or By Hand: ------------------- Benton Oil and Gas Company 1145 Eugenia Place, Suite 200 Carpenteria, California 93013 Attention: Investor Relations Department Delivery of this Form is at the risk of the Investor. If sent by U.S. Mail, it is recommended that an Investor use certified mail, return receipt requested. PART I NAME AND ADDRESS OF INVESTOR --------------------------------------------------------- --------------------------------------------------------- ---------------------------------------------------------- 244 PART II DESCRIPTION OF INTERESTS Set forth below with respect to your Interest are (i) the number of Partnership Interests held of record, (ii) the Exchange Value attributable to your Interest and (iii) the number of shares of Common Stock and Warrants offered for your Interest. Partnership Exchange Common Interests Value Shares Warrants --------- ----- ------ --------
PART III REPRESENTATIONS, WARRANTIES, COVENANTS AND POWER OF ATTORNEY An Investor checking the "Tender and Consent" box and signing Part IV below ("Consenting Investor") hereby (i) accepts the Exchange Offer on the terms and subject to the conditions set forth in the Prospectus, receipt of a copy of which is hereby acknowledged, and tenders to Benton Oil and Gas Company ("Benton") all of his Interest in the Partnership, thereby consenting to the Proposal, and (ii) subject to acceptance of the tender made hereby, sells, transfers, contributes and assigns to Benton all right, title and interest in the Interest tendered hereby. Tenders of Interests are revocable upon written notice to Benton at any time prior to the Expiration Date. An Investor checking the "Withhold Consent" box and signing Part IV below or Part V for California residents ("Non-consenting Investor") hereby (i) acknowledges receipt of the Prospectus and (ii) assuming adoption of the Proposal, accept the Common Stock and Warrants offered in exchange for all right, title and interest in the Interest represented by the Partnership Interests set forth above. The undersigned Investor represents and warrants to Benton that, as of the Closing Date, (i) he has not disposed of or agreed to dispose of his Interest other than pursuant to the Exchange Offer, (ii) upon exchange of his Interest pursuant to the Exchange Offer, Benton will acquire good and marketable title to the Interest, free and clear of all liens, encumbrances and adverse claims, (iii) he has full legal right, power and authority to convey his Interest pursuant to the Exchange Offer, (iv) he has received and reviewed a copy of the Prospectus and (v) he is qualified to make decisions with respect to investments presenting an investment decision similar to that involved in the Exchange Offer. All representations, warranties and covenants contained herein shall survive the Closing Date and all other transactionscontemplated by this Letter and the Prospectus. In connection with the solicitation of written consents of Investors in the Partnership, each Consenting Investor below hereby (i) represents and warrants to Benton that he has full legal right, power and authority to execute a written consent with respect to the Proposal and (ii) consents to the adoption of the Proposal to amend the Partnership Agreement, as described in the Prospectus. 245 The undersigned Investor hereby irrevocably appoints Benton or any designee of Benton, with full power of substitution, as his true and lawful attorney-in-fact, in his name, place and stead, to execute on behalf of the Investor any additional documents necessary to consummate the Exchange and the withdrawal and transfer of the assets underlying his Interest. This power of attorney shall become effective upon acceptance by Benton of his Interest, shall be deemed coupled with an interest, shall be irrevocable (except in the event of a withdrawal of a Consenting Investor's tender of his Interest following a modification or amendment of the Exchange Offer), is granted in consideration of the acceptance of his Interest, shall survive the death, incapacity, dissolution or termination of the existence of the Investor and shall be binding upon the Investor's heirs, legal representatives or assigns. The following information must be completed in order to entitle the Soliciting Dealer to receive a fee in connection with the Exchange Offer. ---------------------------------------- Name of Soliciting Dealer (Please Print) ---------------------------------------- Name of Account Executive (Please Print) ---------------------------------------- City and State of Account Executive 246 PART IV ALL INVESTORS (EXCEPT NON-CONSENTING CALIFORNIA RESIDENTS. SEE PART V) CALIFORNIA INVESTORS ELECTING TO EXERCISE DISSENTERS' RIGHTS SHOULD INSTEAD COMPLETE PART V. Consent to the Proposal being submitted by Benton to adopt the Amendment to the Partnership Agreement: [ ] Tender and Consent [ ] Withhold Consent CASH ELECTION Subject to the availability to elect a cash payment in lieu of Benton Common Stock, I hereby elect to receive Cash rather than Benton Common Stock. [ ] SIGNATURE BOX (NOT FOR NON-CONSENTING CALIFORNIA RESIDENTS. SEE PART V) Please sign exactly as your name is printed in Part I above, unless printed incorrectly. When signing as partner, a general corporate officer, attorney-in-fact, executor, administrator, trustee or guardian, please give full title and send proper evidence of authority with this consent. For joint owners, each joint owner must sign. - ----------------------------------------------------- Full Name of Investor (Please Print) - ----------------------------------------------------- Full Name of Co-owner, if any (Please Print) - ----------------------------------------------------- Signature of Investor (Please Print) - ----------------------------------------------------- Signature of Co-owner, if any (Please Print) Business Telephone: (_____) ____________________ Home Telephone: (_____) _____________________ Dated ______________________________________,1995 IF THE INVESTOR FAILS TO INDICATE WHETHER CONSENT TO THE PROPOSAL IS GIVEN OR WITHHELD, CONSENT WILL BE DEEMED TO BE GIVEN. 247 PART V NON-CONSENTING CALIFORNIA INVESTORS COMPLETE ONLY IF YOU DO NOT WISH TO TENDER YOUR INTEREST PURSUANT TO THE EXCHANGE OFFER AND WISH TO EXERCISE YOUR DISSENTERS' RIGHTS. The Non-consenting Investor signing in this Part V represents that California is the Investor's state of residence and withholds his consent to the Proposal to approve and adopt the Amendment to the Program Agreement. By withholding consent, a Non-consenting California Investor will exercise his dissenters' rights and will be deemed to have made the representations, warranties and covenants (other than the consent to the adoption of the Proposal) set forth in Part III above, and he will receive, pursuant to those dissenters' rights, the number of shares of Common Stock equal to the Exchange Value of his Interest divided by the average closing prices of the Units on NASDAQ-NMS during the twenty trading days immediately after the Closing Date. SIGNATURE BOX (ONLY FOR NON-CONSENTING CALIFORNIA RESIDENTS) Please sign exactly as your name is printed in Part I above, unless printed incorrectly. When signing as general partner, corporate officer, attorney-in-fact, executor, administrator, trustee or guardian, please give full title and send proper evidence of with this consent. For join ---------------------------------------- owners, each joint owner must sign. Full Name of Investor authority (Please Print) ---------------------------------------- Full Name of Co-owner, if any (Please Print) ---------------------------------------- Signature of Investor ---------------------------------------- Signature of Co-owner, if any Business Telephone: ( ) ---- -------- Home Telephone: ( ) ---- -------- Dated , 1995 -------------------------- 248 PART VI INSTRUCTIONS 1. Previously Transferred Interests. If an Investor has transferred, whether by sale, gift, death or otherwise, the beneficial ownership of any Interest of which he has been named a holder of record in the accompanying Letter of Transmittal without previously notifying Benton or complying with the procedures set forth in the Partnership Agreement for transferring his Interest in the Partnership, he should notify Benton of that fact and identify the Interest transferred, the date of transfer and the name, address and tax identification number of the assignee. Benton will then send the Investor and the assignee revised Letters of Transmittal and request from the Investor or assignee such other documents as it may require in order to facilitate the tender, if desired, of an assignee's interest in the Partnership. 2. Participation in Exchange. To be entitled to receive the Common Stock and Warrants in the Exchange, even if consent to the Proposal is withheld, an Investor must deliver one copy of the Letter of Transmittal, completed, dated and signed in the Signature Box in Part IV or the Signature Box in Part V for Non-consenting California residents. Delivery is at the risk of the Investor. A tender will be effective only when the Letter is actually received by the Exchange Agent. The Letter must be received by the Exchange Agent on or before 5:00 p.m. Eastern Time, on ________________ unless the Exchange Offer is extended, in which event the Letter must be received by the latest time and date on which the Exchange Offer, as so extended, will expire. 3. Signatures. The Letter must be signed by the Investor whose name appears in Part I of the Letter. If the Interest is held in the names of two or more persons, all such persons must sign the Letter. With respect to Interests held by entities such as trusts, joint ventures, limited partnerships or general partnerships, Benton may require that the Letter of Transmittal be accompanied by evidence acceptable to Benton that the entity has met all requirements of its governing instruments, such as applicable partnership or joint venture agreements, and that the person signing the Letter is authorized to sign for the Investor under the laws of the jurisdiction in which the entity was organized. TO PARTICIPATE IN THE EXCHANGE OFFER, AN INVESTOR MUST SIGN IN THE SIGNATURE BLOCK IN PART IV (OR PART V FOR CALIFORNIA INVESTORS), EVEN IF HE OBJECTS TO THE EXCHANGE OFFER AND ELECTS TO WITHHOLD HIS CONSENT TO THE PROPOSAL. INVESTORS WILL NOT RECEIVE UNITS IN THE EXCHANGE UNTIL A SIGNED LETTER OF TRANSMITTAL IS RETURNED. 4. Conditional Tenders. No alternative, conditional or contingent tenders will be accepted. 5. Withdrawal of Tenders. Tenders of Interests and consents to the Proposal are revocable at any time prior to the Expiration Date by delivering a notice of withdrawal to Benton. 6. Validity of Tenders. All questions on the validity, form, eligibility (including time of receipt) and acceptance of Interests will be determined by Benton, and its determination will be final and binding. Interpretation by Benton of the terms and conditions of the Exchange Offer (including the instructions to the Letter of Transmittal) will also be final and binding. Benton reserves the right to waive any irregularities or conditions on the manner of tender, and the interpretation by Benton of the terms and conditions of the Exchange Offer (including the instructions in the Letter of Transmittal) shall be final and binding. Any irregularities in connection with tenders must be cured within such time as Benton shall determine unless waived by it. 249 Tenders will be deemed not to have been made until any irregularities have been cured or waived. Any Letter of Transmittal which is not properly completed and executed, and as to which irregularities are not cured or waived, will be returned by Benton to the Investor as soon as practicable. Benton is under no duty to give notification of defects in tenders and will not incur any liability for failure to give notification. Benton will not accept tenders of less than all of an Investor's Interest in the Partnership. 7. Consents to Proposal. A tender of an Interest constitutes a consent to the Proposal. Only persons who are holders of record of Partnership Interests on the date of the Prospectus may vote on the Proposal. 8. Dissenters' Rights for California Residents. Investors residing in California have limited dissenters' rights in accordance with the requirements for rollup transactions. By signing Part V and thereby withholding consent to the Proposal, Investors in that State will be deemed to exercise their dissenters' rights and will receive the number of Shares of Common Stock equal to the Exchange Value of their Interests divided by the average closing prices of the Units on NASDAQ-NMS during the twenty trading days immediately after the Closing Date. Each California Investor withholding consent to the Proposal will also be deemed to have tendered his Interest for that number of Units and therefore will not be required to separately submit an executed Transfer Application. If the average price of the Units during the specified period after the Closing Date is lower than the Exchange Price, dissenting California Investors will receive more for their Interests than they would otherwise receive in the Exchange Offer. Any increase in the market price of the Common Stock during that period relative to the Exchange Price, however, would reduce the number of shares that dissenting California Investors will receive in the Exchange Offer. Although the rollup requirements for California residents entitle them to an appraisal in rollup transactions involving their investments, Investors residing in California who exercise these dissenters' rights will not be entitled to a separate appraisal for their Interests because the Exchange Value of the Common Stock determined by Benton exceeds the liquidation value assigned to the Partnership's net assets in an independent appraisal already performed in accordance with the Partnership Agreement. 250 EXHIBIT D BENTON OIL AND GAS COMPANY LETTER OF TRANSMITTAL FOR INVESTORS IN BENTON OIL AND GAS COMBINATION PARTNERSHIP 1990 - 1 L.P. Capitalized terms used but not defined herein have the meanings given to them in the Prospectus of Benton Oil and Gas Company, as supplemented or amended (the "Prospectus"). General instructions are included in Part VI. This Letter of Transmittal must be received by the Exchange Agent on or before 5:00 p.m. Eastern Time, on ______________, 1995 unless the Exchange Offer is extended. To accept the Exchange Offer or withhold consent to the related Proposal, please complete this Letter in accordance with the Instructions in Items IV and VI, and send or deliver the completed Letter of Transmittal to the Exchange Agent. Neither accepting the Exchange Offer nor withholding consent to the Proposal will prevent an Investor from challenging the fairness of the Exchange Offer. Adoption of the Proposal requires consent by Investors holding 75% of the units in the Partnership. Assuming consummation of the Exchange Offer, all of the partners of the Partnership, whether or not they tender their Interests, will receive the same number of shares of Common Stock and Warrants they would have received had they tendered their Interests, except that California investors exercising their limited dissenters' rights may receive a higher or lower number of shares or warrants. See Part V below and "The Exchange Offer and Proposal" in the Prospectus. Exchange Agent: Benton Oil and Gas Company By Mail or By Hand: ------------------ Benton Oil and Gas Company 1145 Eugenia Place, Suite 200 Carpenteria, California 93013 Attention: Investor Relations Department Delivery of this Form is at the risk of the Investor. If sent by U.S. Mail, it is recommended that an Investor use certified mail, return receipt requested. PART I NAME AND ADDRESS OF INVESTOR _________________________________________________________ _________________________________________________________ _________________________________________________________ 251 PART II DESCRIPTION OF INTERESTS Set forth below with respect to your Interest are (i) the number of Partnership Interests held of record, (ii) the Exchange Value attributable to your Interest and (iii) the number of shares of Common Stock and Warrants offered for your Interest. Partnership Exchange Common Interests Value Shares Warrants ------------ -------- ------- --------
PART III REPRESENTATIONS, WARRANTIES, COVENANTS AND POWER OF ATTORNEY An Investor checking the "Tender and Consent" box and signing Part IV below ("Consenting Investor") hereby (i) accepts the Exchange Offer on the terms and subject to the conditions set forth in the Prospectus, receipt of a copy of which is hereby acknowledged, and tenders to Benton Oil and Gas Company ("Benton") all of his Interest in the Partnership, thereby consenting to the Proposal, and (ii) subject to acceptance of the tender made hereby, sells, transfers, contributes and assigns to Benton all right, title and interest in the Interest tendered hereby. Tenders of Interests are revocable upon written notice to Benton at any time prior to the Expiration Date. An Investor checking the "Withhold Consent" box and signing Part IV below or Part V for California residents ("Non-consenting Investor") hereby (i) acknowledges receipt of the Prospectus and (ii) assuming adoption of the Proposal, accept the Common Stock and Warrants offered in exchange for all right, title and interest in the Interest represented by the Partnership Interests set forth above. The undersigned Investor represents and warrants to Benton that, as of the Closing Date, (i) he has not disposed of or agreed to dispose of his Interest other than pursuant to the Exchange Offer, (ii) upon exchange of his Interest pursuant to the Exchange Offer, Benton will acquire good and marketable title to the Interest, free and clear of all liens, encumbrances and adverse claims, (iii) he has full legal right, power and authority to convey his Interest pursuant to the Exchange Offer, (iv) he has received and reviewed a copy of the Prospectus and (v) he is qualified to make decisions with respect to investments presenting an investment decision similar to that involved in the Exchange Offer. All representations, warranties and covenants contained herein shall survive the Closing Date and all other transactions contemplated by this Letter and the Prospectus. In connection with the solicitation of written consents of Investors in the Partnership, each Consenting Investor below hereby (i) represents and warrants to Benton that he has full legal right, power and authority to execute a written consent with respect to the Proposal and (ii) consents to the adoption of the Proposal to ament the Partnership Agreement, as described in the Prospectus. 252 The undersigned Investor hereby irrevocably appoints Benton or any designee of Benton, with full power of substitution, as his true and lawful attorney-in-fact, in his name, place and stead, to execute on behalf of the Investor any additional documents necessary to consummate the Exchange and the withdrawal and transfer of the assets underlying his Interest. This power of attorney shall become effective upon acceptance by Benton of his Interest, shall be deemed coupled with an interest, shall be irrevocable (except in the event of a withdrawal of a Consenting Investor's tender of his Interest following a modification or amendment of the Exchange Offer), is granted in consideration of the acceptance of his Interest, shall survive the death, incapacity, dissolution or termination of the existence of the Investor and shall be binding upon the Investor's heirs, legal representatives or assigns. The following information must be completed in order to entitle the Soliciting Dealer to receive a fee in connection with the Exchange Offer. ________________________________________ Name of Soliciting Dealer (Please Print) ________________________________________ Name of Account Executive (Please Print) ________________________________________ City and State of Account Executive 253 PART IV ALL INVESTORS (EXCEPT NON-CONSENTING CALIFORNIA RESIDENTS. SEE PART V) CALIFORNIA INVESTORS ELECTING TO EXERCISE DISSENTERS' RIGHTS SHOULD INSTEAD COMPLETE PART V. Consent to the Proposal being submitted by Benton to adopt the Amendment to the Partnership Agreement: [ ] Tender and Consent [ ] Withhold Consent CASH ELECTION Subject to the availability to elect a cash payment in lieu of Benton Common Stock, I hereby elect to receive Cash rather than Benton Common Stock. [ ] SIGNATURE BOX (NOT FOR NON-CONSENTING CALIFORNIA RESIDENTS. SEE PART V) Please sign exactly as your name is printed in Part I above, unless printed incorrectly. When signing as a general partner, corporate officer, attorney-in-fact, executor, administrator, trustee or guardian, please give full title and send proper evidence of authority with this consent. For joint owners, each joint owner must sign. _____________________________________________________ Full Name of Investor (Please Print) _____________________________________________________ Full Name of Co-owner, if any (Please Print) _____________________________________________________ Signature of Investor (Please Print) _____________________________________________________ Signature of Co-owner, if any (Please Print) Business Telephone: (_____) ____________________ Home Telephone: (_____) _____________________ Dated __________________________________________, 1995 IF THE INVESTOR FAILS TO INDICATE WHETHER CONSENT TO THE PROPOSAL IS GIVEN OR WITHHELD, CONSENT WILL BE DEEMED TO BE GIVEN. 254 PART V NON-CONSENTING CALIFORNIA INVESTORS COMPLETE ONLY IF YOU DO NOT WISH TO TENDER YOUR INTEREST PURSUANT TO THE EXCHANGE OFFER AND WISH TO EXERCISE YOUR DISSENTERS' RIGHTS. The Non-consenting Investor signing in this Part V represents that California is the Investor's state of residence and withholds his consent to the Proposal to approve and adopt the Amendment to the Program Agreement. By withholding consent, a Non-consenting California Investor will exercise his dissenters' rights and will be deemed to have made the representations, warranties and covenants (other than the consent to the adoption of the Proposal) set forth in Part III above, and he will receive, pursuant to those dissenters' rights, the number of shares of Common Stock equal to the Exchange Value of his Interest divided by the average closing prices of the Units on NASDAQ-NMS during the twenty trading days immediately after the Closing Date. SIGNATURE BOX (ONLY FOR NON-CONSENTING CALIFORNIA RESIDENTS) Please sign exactly as your name is printed in Part I above, unless printed incorrectly. When signing as general partner, corporate officer, attorney-in-fact, executor,administrator, trustee or guardian, please give full ------------------------------------- title and send proper evidence of Full Name of Investor authority with this consent. For (Please Print) joint owners, each joint owner must sign. ------------------------------------- Full Name of Co-owner, if any (Please Print) ------------------------------------- Signature of Investor ------------------------------------- Signature of Co-owner, if any Business Telephone: ( ) ---- ------------------ Home Telephone: ( ) ---- ------------------ Dated -----------------------------------, 1995 255 PART VI INSTRUCTIONS 1. Previously Transferred Interests. If an Investor has transferred, whether by sale, gift, death or otherwise, the beneficial ownership of any Interest of which he has been named a holder of record in the accompanying Letter of Transmittal without previously notifying Benton or complying with the procedures set forth in the Partnership Agreement for transferring his Interest in the Partnership, he should notify Benton of that fact and identify the Interest transferred, the date of transfer and the name, address and tax identification number of the assignee. Benton will then send the Investor and the assignee revised Letters of Transmittal and request from the Investor or assignee such other documents as it may require in order to facilitate the tender, if desired, of an assignee's interest in the Partnership. 2. Participation in Exchange. To be entitled to receive the Common Stock and Warrants in the Exchange, even if consent to the Proposal is withheld, an Investor must deliver one copy of the Letter of Transmittal, completed, dated and signed in the Signature Box in Part IV or the Signature Box in Part V for Non-consenting California residents. Delivery is at the risk of the Investor. A tender will be effective only when the Letter is actually received by the Exchange Agent. The Letter must be received by the Exchange Agent on or before 5:00 p.m. Eastern Time, on ________________ unless the Exchange Offer is extended, in which event the Letter must be received by the latest time and date on which the Exchange Offer, as so extended, will expire. 3. Signatures. The Letter must be signed by the Investor whose name appears in Part I of the Letter. If the Interest is held in the names of two or more persons, all such persons must sign the Letter. With respect to Interests held by entities such as trusts, joint ventures, limited partnerships or general partnerships, Benton may require that the Letter of Transmittal be accompanied by evidence acceptable to Benton that the entity has met all requirements of its governing instruments, such as applicable partnership or joint venture agreements, and that the person signing the Letter is authorized to sign for the Investor under the laws of the jurisdiction in which the entity was organized. TO PARTICIPATE IN THE EXCHANGE OFFER, AN INVESTOR MUST SIGN IN THE SIGNATURE BLOCK IN PART IV (OR PART V FOR CALIFORNIA INVESTORS), EVEN IF HE OBJECTS TO THE EXCHANGE OFFER AND ELECTS TO WITHHOLD HIS CONSENT TO THE PROPOSAL. INVESTORS WILL NOT RECEIVE UNITS IN THE EXCHANGE UNTIL A SIGNED LETTER OF TRANSMITTAL IS RETURNED. 4. Conditional Tenders. No alternative, conditional or contingent tenders will be accepted. 5. Withdrawal of Tenders. Tenders of Interests and consents to the Proposal are revocable at any time prior to the Expiration Date by delivering a notice of withdrawal to Benton. 6. Validity of Tenders. All questions on the validity, form, eligibility (including time of receipt) and acceptance of Interests will be determined by Benton, and its determination will be final and binding. Interpretation by Benton of the terms and conditions of the Exchange Offer (including the instructions to the Letter of Transmittal) will also be final and binding. Benton reserves the right to waive any irregularities or conditions on the manner of tender, and the interpretation by Benton of the terms and conditions of the Exchange Offer (including the instructions in the Letter of Transmittal) shall be final and binding. Any irregularities in connection with tenders must be cured within such time as Benton shall determine unless waived by it. 256 Tenders will be deemed not to have been made until any irregularities have been cured or waived. Any Letter of Transmittal which is not properly completed and executed, and as to which irregularities are not cured or waived, will be returned by Benton to the Investor as soon as practicable. Benton is under no duty to give notification of defects in tenders and will not incur any liability for failure to give notification. Benton will not accept tenders of less than all of an Investor's Interest in the Partnership. 7. Consents to Proposal. A tender of an Interest constitutes a consent to the Proposal. Only persons who are holders of record of Partnership Interests on the date of the Prospectus may vote on the Proposal. 8. Dissenters' Rights for California Residents. Investors residing in California have limited dissenters' rights in accordance with the requirements for rollup transactions. By signing Part V and thereby withholding consent to the Proposal, Investors in that State will be deemed to exercise their dissenters' rights and will receive the number of Shares of Common Stock equal to the Exchange Value of their Interests divided by the average closing prices of the Units on NASDAQ-NMS during the twenty trading days immediately after the Closing Date. Each California Investor withholding consent to the Proposal will also be deemed to have tendered his Interest for that number of Units and therefore will not be required to separately submit an executed Transfer Application. If the average price of the Units during the specified period after the Closing Date is lower than the Exchange Price, dissenting California Investors will receive more for their Interests than they would otherwise receive in the Exchange Offer. Any increase in the market price of the Common Stock during that period relative to the Exchange Price, however, would reduce the number of shares that dissenting California Investors will receive in the Exchange Offer. Although the rollup requirements for California residents entitle them to an appraisal in rollup transactions involving their investments, Investors residing in California who exercise these dissenters' rights will not be entitled to a separate appraisal for their Interests because the Exchange Value of the Common Stock determined by Benton exceeds the liquidation value assigned to the Partnership's net assets in an independent appraisal already performed in accordance with the Partnership Agreement. 257 EXHIBIT D BENTON OIL AND GAS COMPANY LETTER OF TRANSMITTAL FOR INVESTORS IN BENTON OIL AND GAS COMBINATION PARTNERSHIP 1991 - 1 L.P. Capitalized terms used but not defined herein have the meanings given to them in the Prospectus of Benton Oil and Gas Company, as supplemented or amended (the "Prospectus"). General instructions are included in Part VI. This Letter of Transmittal must be received by the Exchange Agent on or before 5:00 p.m. Eastern Time, on ______________, 1995 unless the Exchange Offer is extended. To accept the Exchange Offer or withhold consent to the related Proposal, please complete this Letter in accordance with the Instructions in Items IV and VI, and send or deliver the completed Letter of Transmittal to the Exchange Agent. Neither accepting the Exchange Offer nor withholding consent to the Proposal will prevent an Investor from challenging the fairness of the Exchange Offer. Adoption of the Proposal requires consent by Investors holding 75% of the units in the Partnership. Assuming consummation of the Exchange Offer, all of the partners of the Partnership, whether or not they tender their Interests, will receive the same number of shares of Common Stock and Warrants they would have received had they tendered their Interests, except that California investors exercising their limited dissenters' rights may receive a higher or lower number of shares or warrants. See Part V below and "The Exchange Offer and Proposal" in the Prospectus. Exchange Agent: Benton Oil and Gas Company By Mail or By Hand: ------------------- Benton Oil and Gas Company 1145 Eugenia Place, Suite 200 Carpenteria, California 93013 Attention: Investor Relations Department Delivery of this Form is at the risk of the Investor. If sent by U.S. Mail, it is recommended that an Investor use certified mail, return receipt requested. PART I NAME AND ADDRESS OF INVESTOR ----------------------------- ----------------------------- ----------------------------- 258 PART II DESCRIPTION OF INTERESTS Set forth below with respect to your Interest are (i) the number of Partnership Interests held of record, (ii) the Exchange Value attributable to your Interest and (iii) the number of shares of Common Stock and Warrants offered for your Interest. Partnership Exchange Common Interests Value Shares Warrants - --------- ----- ------ --------
PART III REPRESENTATIONS, WARRANTIES, COVENANTS AND POWER OF ATTORNEY An Investor checking the "Tender and Consent" box and signing Part IV below ("Consenting Investor") hereby (i) accepts the Exchange Offer on the terms and subject to the conditions set forth in the Prospectus, receipt of a copy of which is hereby acknowledged, and tenders to Benton Oil and Gas Company ("Benton") all of his Interest in the Partnership, thereby consenting to the Proposal, and (ii) subject to acceptance of the tender made hereby, sells, transfers, contributes and assigns to Benton all right, title and interest in the Interest tendered hereby. Tenders of Interests are revocable upon written notice to Benton at any time prior to the Expiration Date. An Investor checking the "Withhold Consent" box and signing Part IV below or Part V for California residents ("Non-consenting Investor") hereby (i) acknowledges receipt of the Prospectus and (ii) assuming adoption of the Proposal, accept the Common Stock and Warrants offered in exchange for all right, title and interest in the Interest represented by the Partnership Interests set forth above. The undersigned Investor represents and warrants to Benton that, as of the Closing Date, (i) he has not disposed of or agreed to dispose of his Interest other than pursuant to the Exchange Offer, (ii) upon exchange of his Interest pursuant to the Exchange Offer, Benton will acquire good and marketable title to the Interest, free and clear of all liens, encumbrances and adverse claims, (iii) he has full legal right, power and authority to convey his Interest pursuant to the Exchange Offer, (iv) he has received and reviewed a copy of the Prospectus and (v) he is qualified to make decisions with respect to investments presenting an investment decision similar to that involved in the Exchange Offer. All representations, warranties and covenants contained herein shall survive the Closing Date and all other transactions contemplated by this Letter and the Prospectus. In connection with the solicitation of written consents of Investors in the Partnership, each Consenting Investor below hereby (i) represents and warrants to Benton that he has full legal right, power and authority to execute a written consent with respect to the Proposal and (ii) consents to the adoption of the Proposal to amend the Partnership Agreement, as described in the Prospectus. 259 The undersigned Investor hereby irrevocably appoints Benton or any designee of Benton, with full power of substitution, as his true and lawful attorney-in-fact, in his name, place and stead, to execute on behalf of the Investor any additional documents necessary to consummate the Exchange and the withdrawal and transfer of the assets underlying his Interest. This power of attorney shall become effective upon acceptance by Benton of his Interest, shall be deemed coupled with an interest, shall be irrevocable (except in the event of a withdrawal of a Consenting Investor's tender of his Interest following a modification or amendment of the Exchange Offer), is granted in consideration of the acceptance of his Interest, shall survive the death, incapacity, dissolution or termination of the existence of the Investor and shall be binding upon the Investor's heirs, legal representatives or assigns. The following information must be completed in order to entitle the Soliciting Dealer to receive a fee in connection with the Exchange Offer. ---------------------------------------- Name of Soliciting Dealer (Please Print) ---------------------------------------- Name of Account Executive (Please Print) --------------------------------------- City and State of Account Executive 260 PART IV ALL INVESTORS (EXCEPT NON-CONSENTING CALIFORNIA RESIDENTS. SEE PART V) CALIFORNIA INVESTORS ELECTING TO EXERCISE DISSENTERS' RIGHTS SHOULD INSTEAD COMPLETE PART V. Consent to the Proposal being submitted by Benton to adopt the Amendment to the Partnership Agreement: [ ] Tender and Consent [ ] Withhold Consent CASH ELECTION Subject to the availability to elect a cash payment in lieu of Benton Common Stock, I hereby elect to receive Cash rather than Benton Common Stock. [ ] SIGNATURE BOX (NOT FOR NON-CONSENTING CALIFORNIA RESIDENTS. SEE PART V) Please sign exactly as you name is printed When signing as a general in Part I above, unless printed incorrectly. partner, corporate officer, attorney-in-fact, executor, administrator, trustee or guardian, please give full title and send proper evidence of authority with this consent. For joint owners, each joint owner must sign. --------------------------------------------------- Full Name of Investor (Please Print) --------------------------------------------------- Full Name of Co-owner, if any (Please Print) --------------------------------------------------- Signature of Investor (Please Print) --------------------------------------------------- Signature of Co-owner, if any (Please Print) Business Telephone: ( ) ----- ------------------------ Home Telephone: ( ) ----- ------------------------ Dated ,1995 ----------------------------------------- IF THE INVESTOR FAILS TO INDICATE WHETHER CONSENT TO THE PROPOSAL IS GIVEN OR WITHHELD, CONSENT WILL BE DEEMED TO BE GIVEN. 261 PART V NON-CONSENTING CALIFORNIA INVESTORS COMPLETE ONLY IF YOU DO NOT WISH TO TENDER YOUR INTEREST PURSUANT TO THE EXCHANGE OFFER AND WISH TO EXERCISE YOUR DISSENTERS' RIGHTS. The Non-consenting Investor signing in this Part V represents that California is the Investor's state of residence and withholds his consent to the Proposal to approve and adopt the Amendment to the Program Agreement. By withholding consent, a Non-consenting California Investor will exercise his dissenters' rights and will be deemed to have made the representations, warranties and covenants (other than the consent to the adoption of the Proposal) set forth in Part III above, and he will receive, pursuant to those dissenters' rights, the number of shares of Common Stock equal to the Exchange Value of his Interest divided by the average closing prices of the Units on NASDAQ-NMS during the twenty trading days immediately after the Closing Date. SIGNATURE BOX (ONLY FOR NON-CONSENTING CALIFORNIA RESIDENTS) Please sign exactly as your name is printed in Part I above, unless printed incorrectly. When signing as general partner, corporate officer, attorney-in-fact, executor, ---------------------------- administrator, trustee or guardian, please give Full Name of Investor full title and send proper evidence of authority (Please Print) with this consent. For joint owner must sign. ---------------------------- Full Name of Co-owner, if any (Please Print) ----------------------------- Signature of Investor ------------------------------ Signature of Co-owner, if any Business Telephone: ( ) --- ------------ Home Telephone: ( ) --- ------------ Dated ,1995 ---------------------------- 262 PART VI INSTRUCTIONS 1. Previously Transferred Interests. If an Investor has transferred, whether by sale, gift, death or otherwise, the beneficial ownership of any Interest of which he has been named a holder of record in the accompanying Letter of Transmittal without previously notifying Benton or complying with the procedures set forth in the Partnership Agreement for transferring his Interest in the Partnership, he should notify Benton of that fact and identify the Interest transferred, the date of transfer and the name, address and tax identification number of the assignee. Benton will then send the Investor and the assignee revised Letters of Transmittal and request from the Investor or assignee such other documents as it may require in order to facilitate the tender, if desired, of an assignee's interest in the Partnership. 2. Participation in Exchange. To be entitled to receive the Common Stock and Warrants in the Exchange, even if consent to the Proposal is withheld, an Investor must deliver one copy of the Letter of Transmittal, completed, dated and signed in the Signature Box in Part IV or the Signature Box in Part V for Non-consenting California residents. Delivery is at the risk of the Investor. A tender will be effective only when the Letter is actually received by the Exchange Agent. The Letter must be received by the Exchange Agent on or before 5:00 p.m. Eastern Time, on ________________ unless the Exchange Offer is extended, in which event the Letter must be received by the latest time and date on which the Exchange Offer, as so extended, will expire. 3. Signatures. The Letter must be signed by the Investor whose name appears in Part I of the Letter. If the Interest is held in the names of two or more persons, all such persons must sign the Letter. With respect to Interests held by entities such as trusts, joint ventures, limited partnerships or general partnerships, Benton may require that the Letter of Transmittal be accompanied by evidence acceptable to Benton that the entity has met all requirements of its governing instruments, such as applicable partnership or joint venture agreements, and that the person signing the Letter is authorized to sign for the Investor under the laws of the jurisdiction in which the entity was organized. TO PARTICIPATE IN THE EXCHANGE OFFER, AN INVESTOR MUST SIGN IN THE SIGNATURE BLOCK IN PART IV (OR PART V FOR CALIFORNIA INVESTORS), EVEN IF HE OBJECTS TO THE EXCHANGE OFFER AND ELECTS TO WITHHOLD HIS CONSENT TO THE PROPOSAL. INVESTORS WILL NOT RECEIVE UNITS IN THE EXCHANGE UNTIL A SIGNED LETTER OF TRANSMITTAL IS RETURNED. 4. Conditional Tenders. No alternative, conditional or contingent tenders will be accepted. 5. Withdrawal of Tenders. Tenders of Interests and consents to the Proposal are revocable at any time prior to the Expiration Date by delivering a notice of withdrawal to Benton. 6. Validity of Tenders. All questions on the validity, form, eligibility (including time of receipt) and acceptance of Interests will be determined by Benton, and its determination will be final and binding. Interpretation by Benton of the terms and conditions of the Exchange Offer (including the instructions to the Letter of Transmittal) will also be final and binding. Benton reserves the right to waive any irregularities or conditions on the manner of tender, and the interpretation by Benton of the terms and conditions of the Exchange Offer (including the instructions in the Letter of Transmittal) shall be final and binding. Any irregularities in connection with tenders must be cured within such time as Benton shall determine unless waived by it. 263 Tenders will be deemed not to have been made until any irregularities have been cured or waived. Any Letter of Transmittal which is not properly completed and executed, and as to which irregularities are not cured or waived, will be returned by Benton to the Investor as soon as practicable. Benton is under no duty to give notification of defects in tenders and will not incur any liability for failure to give notification. Benton will not accept tenders of less than all of an Investor's Interest in the Partnership. 7. Consents to Proposal. A tender of an Interest constitutes a consent to the Proposal. Only persons who are holders of record of Partnership Interests on the date of the Prospectus may vote on the Proposal. 8. Dissenters' Rights for California Residents. Investors residing in California have limited dissenters' rights in accordance with the requirements for rollup transactions. By signing Part V and thereby withholding consent to the Proposal, Investors in that State will be deemed to exercise their dissenters' rights and will receive the number of Shares of Common Stock equal to the Exchange Value of their Interests divided by the average closing prices of the Units on NASDAQ-NMS during the twenty trading days immediately after the Closing Date. Each California Investor withholding consent to the Proposal will also be deemed to have tendered his Interest for that number of Units and therefore will not be required to separately submit an executed Transfer Application. If the average price of the Units during the specified period after the Closing Date is lower than the Exchange Price, dissenting California Investors will receive more for their Interests than they would otherwise receive in the Exchange Offer. Any increase in the market price of the Common Stock during that period relative to the Exchange Price, however, would reduce the number of shares that dissenting California Investors will receive in the Exchange Offer. Although the rollup requirements for California residents entitle them to an appraisal in rollup transactions involving their investments, Investors residing in California who exercise these dissenters' rights will not be entitled to a separate appraisal for their Interests because the Exchange Value of the Common Stock determined by Benton exceeds the liquidation value assigned to the Partnership's net assets in an independent appraisal already performed in accordance with the Partnership Agreement. 264 EXHIBIT E California Corporations Code Section 25014.7. "Eligible rollup transaction" (a) "Eligible rollup transaction" means a rollup transaction in which the new securities issued are either listed or approved for listing on a national securities exchange or designated or approved for designation upon notice of issuance as a national market system security on an interdealer quotation system by the National Association of Securities Dealers, Inc., where the national securities exchange and the interdealer quotation system have been certified by the commissioner under subdivision (o) of Section 25100, if the exchange or association requires as a condition to listing or designation that the rollup transaction be conducted in accordance with procedures to protect the rights of limited partners. (b) The rights of limited partners will be presumed to be protected if the rollup transaction provides for the right of dissenting limited partners: (1) To receive compensation for their limited partnership units based on an appraisal of the limited partnership assets performed by an independent appraiser unaffiliated with the sponsor or general partner of the limited partnership and which value the assets as if sold in an orderly manner in a reasonable period of time, plus or minus other balance sheet items, and less the cost of sale or refinancing. Compensation to dissenting limited partners of rollup transactions may be cash, secured debt instruments, unsecured debt instruments, or freely tradeable securities; provided, however, that: (A) Rollups which utilize debt instruments as compensation provide for a trustee and an indenture to protect the rights of the debt holders and provide a rate of interest based upon, but not less than, the then applicable federal rate as determined in accordance with Section 1274 of the Internal Revenue Code of 1986. (B) Rollups which utilize unsecured debt instruments as compensation, in addition to the requirements of subparagraph (A) of paragraph (1), limit total leverage to 70 percent of the appraised value of the assets. (C) All debt securities have a term no greater than seven years and provide for prepayment with 80 percent of the net proceeds of any sale or refinancing of the assets previously owned by the entity or any part thereof. (D) Freely tradeable securities utilized as compensation to dissenting limited partners must be issued by an issuer whose securities are listed on a certified national securities exchange or designated as a national market system security on an interdealer quotation system by the National Association of 265 Securities Dealers, Inc., for at least one year prior to the transaction, and the number of securities to be received in return for limited partnership interests must be determined by an appraisal of limited partnership assets, conducted in a manner consistent with paragraph (1) of subdivision (b), in relation to the average last sale price of the freely tradeable securities in the 20-day period following the transaction. If the issuer of the freely tradeable securities is affiliated with the sponsor or general partner, newly issued securities to be utilized as compensation to dissenting limited partners shall not represent more than 20 percent of the issued and outstanding shares of that class of securities after giving effect to the issuance. For the purposes of the preceding sentence, a sponsor or general partner is "affiliated" with the issuer of the freely tradeable securities if the sponsor or general partner receives any material compensation from the issuer or its affiliates in conjunction with the rollup transaction or the purchase of the general partner's interest; provided, however, that nothing herein shall restrict the ability of a sponsor or general partner to receive any payment for its equity interests and compensation as otherwise provided by this section. (2) To receive or retain a security with substantially the same terms and conditions as the security originally held, provided that the receipt or retention of that security is not a step in a series of subsequent transactions that directly or indirectly through acquisition or otherwise involves future combinations or reorganizations of one or more rollup participants. Securities received or retained will be considered to have the same terms and conditions as the security originally held if: (A) There is no material adverse change to dissenting limited partners' rights, including, but not limited to, rights with respect to voting, the business plan, or the investment, distribution, management compensation and liquidation policies of the limited partnership or resulting entity. (B) The dissenting limited partners receive the same preferences, privileges, and priorities as they had pursuant to the security originally held. The rights set forth in paragraphs (1) and (2) are the only rights of dissenting limited partners to which the presumption under subdivision (b) applies. A general partner or sponsor shall file an application for qualification pursuant to Section 25110 or Section 25120 with respect to any other rights proposed to be offered to dissenting limited partners. At the time a registration statement is filed with the Securities and Exchange Commission with respect to an eligible rollup transaction, a general partner or sponsor shall notify, to the maximum extent permitted by the federal securities laws, each limited partner who has an address in this state by certified mail of the following: That a registration statement has been filed with the Securities and Exchange Commission with respect to a rollup transaction; that the general partner or sponsor claims an exemption from the review process under the law by virtue of Section 25014.7, which defines "eligible rollup transaction"; that the general partner or sponsor has the burden of proof under the law that the transaction meets the definition of eligible rollup transaction; and that the commissioner does not recommend or endorse the transaction. (c) The rights of limited partners shall be presumed not to be protected if the general partner: 266 (1) Converts an equity interest in the limited partnerships subject to a rollup for which consideration was not paid and which was not otherwise provided for in the limited partnership agreement and disclosed to limited partners, into a voting interest in the new entity, provided, however, an interest originally obtained in order to comply with the provisions of Internal Revenue Service Revenue Proclamation 89-12 may be converted. (2) Fails to follow the valuation provisions in the limited partnership agreements of the subject limited partners when valuing their limited partnership interests. (3) Utilizes a future value of their equity interest rather than the current value of their equity interest, as determined by an appraisal conducted in a manner consistent with paragraph (1) of subdivision (b), when determining their interest in the new entity. (d) The rights of limited partners shall be presumed not to be protected as to voting rights, if: (1) The voting rights in the entity resulting from a rollup do not generally follow the original voting rights of the limited partnerships participating in the rollup transaction. (2) A majority of the interest in an entity resulting from a rollup transaction may not, without concurrence by the sponsor, general partners, board of directors or trustee, depending on the form of entity, vote to: (A) Amend the limited partnership agreement, articles of incorporation or bylaws, or indenture. (B) Dissolve the entity. (C) Remove management and elect new management. (D) Approve or disapprove the sale of substantially all of the assets of the entity. (3) The general partner or sponsor proposing a rollup is not required to provide each person whose equity interest is subject to the rollup transaction with a document which instructs the person on the proper procedure for voting against or dissenting from the rollup transaction. (4) The general partner or sponsor does not utilize an independent third party to receive and tabulate all votes and dissents, and require that the third party make the tabulation available to the general partner and any limited partner upon request at any time during and after voting occurs. (e) The rights of limited partners shall be presumed not to be protected as to transaction costs if: (1) Limited partners bear an unfair portion of the transaction costs of a proposed rollup transaction that is rejected. For purposes of this provision, transaction costs are defined as the costs of printing and mailing the proxy, prospectus, or other documents; legal fees not related to the solicitation of votes or tenders; financial advisory fees; investment banking fees; appraisal 267 fees; accounting fees; independent committee expenses; travel expenses; and all other fees related to the preparatory work of the transaction, but not including costs that would have otherwise been incurred by the subject limited partnerships in the ordinary course of business, or solicitation expenses. (2) Transaction costs of a rejected rollup transaction are not apportioned between general and limited partners of the subject limited partnerships according to the final vote on the proposed transaction as follows: (A) The general partner or sponsor bears all rollup transaction costs in proportion to the number of votes to reject the rollup transaction. (B) Limited partners bear transactions costs in proportion to the number of votes to approve the rollup transaction. (3) The dissenting limited partnership is required to pay any of the costs of the rollup transaction and the general partner or sponsor is not required to pay the rollup transaction costs on behalf of the dissenting limited partnerships in a rollup in which one or more limited partnerships determines not to approve the transaction, but where the rollup transaction is consummated with respect to one or more approving limited partnerships. (f) The rights of limited partners shall be presumed not to be protected as to fees of general partners and sponsors, if: (1) General partners and sponsors are not prevented from receiving both unearned management fees discounted to a present value, if those fees were not previously provided for in the limited partnership agreement and disclosed to limited partners, and new asset-based fees. (2) Property management fees and other management fees are not appropriate, not reasonable and greater than what would be paid to third parties for performing similar services. (3) Changes in fees which are substantial and adverse to limited partners are not approved by an independent committee according to the facts and circumstances of each transaction. (g) A general partner or sponsor proposing a rollup transaction shall pay all solicitation expenses related to the transaction, including all preparatory work related thereto, in the event the rollup transaction is not approved. For purposes of this section, "solicitation expenses" include direct marketing expenses such as telephone calls, broker-dealer fact sheets, legal and other fees related to the solicitation, as well as direct solicitation compensation to brokers and dealers. (h) A broker or dealer may not receive compensation for soliciting votes or tenders from limited partners in connection with a rollup transaction unless that compensation: (1) Is payable and equal in amount regardless of whether the limited partner votes affirmatively or negatively in the proposed rollup. (2) In the aggregate, does not exceed 2 percent of the exchange value of the newly created securities. 268 (3) Is paid regardless of whether the limited partners reject the proposed rollup transaction. (i) As used in this section, the following terms have the following meanings: (1) "Limited partnership" includes any entity determined to be a "partnership" pursuant to Section 14((h) (4) (B) of the Securities Exchange Act of 1934 or such other entity having a substantially economically equivalent form of ownership instrument. (2) "Dissenting limited partner" means a holder or a beneficial interest in a limited partnership that is the subject of a rollup transaction who casts a vote against the rollup transaction, except that for purposes of an exchange or tender offer dissenting limited partner means any person who files a dissent from the terms of the transaction with the party responsible for tabulating the votes or tenders, to be received in connection with the transaction during the period in which the offer is outstanding. (3) "Management fee" means a fee paid to the sponsor, general partner, their affiliates, or other persons for management and administration of the limited partnership. 269 PART II ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS. Under provisions of the Certificate of Incorporation and Bylaws of the Company, each person who is or was a director or officer of the Company shall be indemnified by the Company as a matter of right to the full extent permitted or authorized by law. The effects of the Certificate of Incorporation, Bylaws and General Corporation Law of Delaware may be summarized as follows: (a) Under Delaware law, to the extent that such a person is successful on the merits in defense of a suit or proceeding brought against him by reason of the fact that he is a director or officer of the Company, he shall be indemnified against expenses (including attorneys' fees) reasonably incurred in connection with such action. (b) If unsuccessful in defense of a third-party civil suit or a criminal suit, or if such a suit is settled, such a person shall be indemnified under such law against both (1) expenses (including attorneys' fees) and (2) judgments, fines and amounts paid in settlement if he acted in good faith and in a manner he reasonably believed to be in, or not opposed to, the best interests of the Company, and with respect to any criminal action, had no reasonable cause to believe his conduct was unlawful. (c) If unsuccessful in defense of a suit brought by or in the right of the Company, or if such suit is settled, such a person shall be indemnified under such law only against expenses (including attorneys' fees) incurred in the defense or settlement of such suit if he acted in good faith and in a manner he reasonably believed to be in, or not opposed to, the best interests of the Company except that if such a person is adjudged to be liable in a suit in the performance of his duty to the Company, he cannot be made whole even for expenses unless the court determines that he is fairly and reasonably entitled to indemnity for such expenses. (d) The Company may not indemnify a person in respect of a proceeding described in (b) or (c) above unless it is determined that indemnification is permissible because the person has met the prescribed standard of conduct by any one of the following: (i) the Board of Directors, by a majority vote of a quorum consisting of directors not at the time parties to the proceeding, (ii) if a quorum of directors not parties to the proceeding cannot be obtained, or, if obtainable but the quorum so directs, by independent legal counsel selected by the Board of Directors or the committee thereof; or (iii) by the stockholders. ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES. (a) Exhibits. 1.1 Form of Soliciting Agent Agreement.* 2.1 Asset Purchase Agreement between Benton Oil & Gas Combination Partnership 1989-1, L.P. and Goldking Trinity Bay Corp. dated June 30, 1995. 2.2 Asset Purchase Agreement between Benton Oil & Gas Combination Partnership 1990-1, L.P. and Goldking Trinity Bay Corp. dated June 30, 1995. 2.3 Asset Purchase Agreement between Benton Oil & Gas Combination Partnership 1991-1, L.P. and Goldking Trinity Bay Corp. dated June 30, 1995. II-1 270 4.1 Form of Stock Certificate (incorporated by reference to Exhibit 4.1 to the Company's Form S-1 Registration Statement, Registration No. 33-26333). 4.2 Benton Oil & Gas Combination Partnership 1989-1, L.P. Limited Partnership Agreement dated July 31, 1989.* 4.3 Benton Oil & Gas Combination Partnership 1990-1, L.P. Limited Partnership Agreement dated May 15, 1990.* 4.4 Benton Oil & Gas Combination Partnership 1991-1, L.P. Limited Partnership Agreement dated July 29, 1991.* 5.1 Opinion of Emens, Kegler, Brown, Hill & Ritter Co., LPA as to the legality of the securities being registered. 8.1 Opinion of Emens, Kegler, Brown, Hill & Ritter Co., L.P.A. as to tax matters. 11.1 Statement regarding computation of per share earnings (incorporated by reference to Exhibit 11.1 to the Company's 10-K for the year ended December 31, 1994 and to Exhibit 11.1 to the Company's Form 10-Q for the quarter ended March 31, 1995). 23.1 Consent of Deloitte & Touche LLP. 23.2 Consent of Emens, Kegler, Brown, Hill & Ritter Co., LPA. (Included in Exhibits 5.1 and 8.1) 23.3 Consents of Huddleston & Co., Inc. 24.1 Power of Attorney (included on signature page). 24.2 Power of Attorney of the Company.* - --------------- * Filed previously as an exhibit to this Registration Statement No. 33-61299. (b) Financial Statement Schedules. All schedules have been omitted because the required information is not significant or included in the financial statements or the notes thereto, or is not applicable. ITEM 22. UNDERTAKINGS. a. The undersigned registrant hereby undertakes: (1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement: (i) To include any prospectus required by Section 10(a)(3) of the Securities Act of 1993; (ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represents a fundamental change in the information set forth in the registration statement; (iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement; II-2 271 (2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. (3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering. (4) If the registrant is a foreign private issuer, to file a post-effective amendment to the registration statement to include any financial statements required by section 210.3-19 of this chapter at the start of any delayed offering of throughout a continuous offering. Financial statements and information otherwise required by Section 10(a)(3) of the Act need not be furnished, provided that the registrant includes in the prospectus, by means of a post-effective amendment, financial statements required pursuant to this paragraph (a)(4) and other information necessary to ensure that all other information in the prospectus is at least as current as the date of those financial statements. b. The undersigned registrant hereby undertakes that, for purposes of determining any liability under the Securities Act of 1933, each filing of the registrant's annual report pursuant to Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plans' annual report pursuant to Section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the Registration Statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. c. The undersigned registrant hereby undertakes to respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11, or 13 of this Form, within one business day of receipt of such request and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request. d. The undersigned registrant hereby undertakes to supply by means of a post-effective amendment all information concerning a transaction and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective. e. Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, offer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling II-3 272 precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. II-4 273 SIGNATURES Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Carpinteria, State of California, on the 29th day of September, 1995. BENTON OIL AND GAS COMPANY By: /s/ A. E. Benton ------------------------- A. E. Benton, President Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed on September 29th, 1995 by the following persons in the capacities indicated: /s/ A. E. Benton President, Chief Executive Officer and Director - ------------------------------ A.E. Benton /s/ David H. Pratt* Vice President -- Finance, Principal Financial Officer - ------------------------------ David H. Pratt /s/Chris C. Hickok* Principal Accounting Officer - ------------------------------ Chris C. Hickok /s/ Michael B. Wray* Director - ------------------------------ Michael B. Wray /s/ William H. Gumma* Director - ------------------------------ William H. Gumma /s/ Richard W. Fetzner* Director - ------------------------------ Richard W. Fetzner /s/ Bruce M. McIntyre* Director - ------------------------------ Bruce M. McIntyre *Signed pursuant to a Power of Attorney /s/ A. E. Benton - ------------------------------ A. E. Benton, Attorney-In-Fact
II-5 274 PROSPECTUS SUPPLEMENT 1989-1 PARTNERSHIP SUBJECT TO COMPLETION DATED OCTOBER 3, 1995 EXCHANGE OFFER OF AN AGGREGATE OF 30,154 SHARES OF COMMON STOCK AND WARRANTS TO PURCHASE AN AGGREGATE OF 9,863 SHARES OF COMMON STOCK FOR PARTNERSHIP UNITS IN BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P. (281.8182 PARTNERSHIP UNITS) --------------- EXCHANGE RATIO: 107 SHARES OF COMMON STOCK AND 35 WARRANTS PER 1989-1 PARTNERSHIP UNIT This Supplement accompanies a Prospectus (the "Prospectus") and is being furnished to the Investors ("Investors") in the Benton Oil & Gas Combination Partnership 1989-1, L.P., a California limited partnership (the "Partnership") in connection with the offer by Benton Oil and Gas Company, a Delaware corporation and the managing general partner of the Partnership ("Benton," or "Company," or "Managing General Partner") to exchange shares of Common Stock, $.01 par value of Benton ("Common Stock") and Warrants ("Warrants") to purchase shares of Common Stock of Benton (the "Exchange Offer") for all of the right, title and interest to units of Partnership interest in the Partnerships ("Partnership Units") held by Investors, at the exchange rate outlined below. Benton has offered to exchange shares of Common Stock and Warrants for all of the right, title and interest to units of partnership interest in the Benton Oil & Gas Combination Partnership 1990-1, L.P. (the "1990-1 Partnership") and the Benton Oil & Gas Combination Partnership 1991-1, L.P. (the "1991-1 Partnership") on the terms and at the exchange rates set forth in the Prospectus. A separate supplement has been prepared for each of the Partnerships. THE EFFECTS OF THE EXCHANGE OFFER MAY BE DIFFERENT FOR INVESTORS IN THE VARIOUS PARTNERSHIPS. UPON RECEIPT OF A WRITTEN REQUEST BY AN INVESTOR OR HIS REPRESENTATIVE WHO HAS BEEN DESIGNATED IN WRITING, A COPY OF ANY SUPPLEMENT WILL BE TRANSMITTED PROMPTLY, WITHOUT CHARGE, BY BENTON. ANY SUCH REQUEST SHOULD BE FORWARDED TO THE ATTENTION OF TONI L. JACKSON, BENTON OIL AND GAS COMPANY, 1145 EUGENIA PLACE, SUITE 200, CARPENTERIA, CALIFORNIA 93013. Benton is offering to exchange shares of Common Stock and Warrants to owners of Partnership Units in the 1989-1 Partnership (the "1989-1 Units") on the basis of $5,000.00 original investment on the terms and in the amounts set forth herein. The Warrants to be issued in connection with the Exchange Offer are exercisable at a price of $11.00 per share and will expire three years form the date of issuance. For detailed information regarding the determination of the Total Exchange Values for each of the Partnerships, see "Determination of Exchange Value." On 275 October 2, 1995, the last reported sales price of the Common Stock, as reported on NASDAQ National Market, was $11.13. In connection with the Exchange Offer, Benton is submitting a Proposal to Investors in the Partnership to amend the Partnership Agreement to provide for the transfer of all of the assets and liabilities of the Partnership to Benton as of the December 31, 1994 Effective Date in exchange for Common Stock and Warrants in the amounts set forth herein and the pro rata distribution of such consideration in liquidation of the Partnership. Each Investor who tenders his Partnership Units pursuant to the Exchange Offer will, by that tender, consent to the Proposal. ADOPTION OF THE PROPOSAL REQUIRES THE CONSENT OF INVESTORS OF THE PARTNERSHIP HOLDING 75% OF THE PARTNERSHIP UNITS. IF INVESTORS IN THE PARTNERSHIP HOLDING NOT LESS THAN 75% OF THE PARTNERSHIP UNITS ACCEPT THE EXCHANGE OFFER AND CONSENT TO THE PROPOSAL, ALL NON-DISSENTING HOLDERS OF UNITS IN THE PARTNERSHIP WILL BE BOUND BY THE TERMS OF THE EXCHANGE AND PROPOSAL AND WILL RECEIVE THE NUMBER OF SHARES OF COMMON STOCK AND WARRANTS DESCRIBED HEREIN. A SIMILAR EXCHANGE OFFER AND PROPOSAL IS BEING OFFERED TO INVESTORS IN TWO OTHER PARTNERSHIPS. EACH OF THE EXCHANGE OFFERS TO THE PARTNERSHIPS IS INDEPENDENT OF THE EXCHANGE OFFER TO THE OTHER PARTNERSHIPS. THE EXCHANGE WILL ONLY BE CONSUMMATED FOR THE PARTNERSHIP IF THE PROPOSAL HAS BEEN APPROVED BY THE INVESTORS. BENTON OIL AND GAS COMPANY, IN ADDITION TO BEING MANAGING GENERAL PARTNER OF THE THREE PARTNERSHIPS, OWNS 2.8182 1989-1 UNITS AND WILL VOTE SUCH UNITS THE SAME AS A MAJORITY OF INVESTORS VOTE THEIR UNITS. INVESTORS WILL RECEIVE THE CONSIDERATION SET FORTH HEREIN, AND THE RESPECTIVE PARTNERSHIP WILL BE DISSOLVED. ASSUMING CONSUMMATION OF THE EXCHANGE OFFER, ALL OF THE INVESTORS IN THE PARTNERSHIP, WHETHER OR NOT THEY TENDER THEIR UNITS AND THUS VOTE IN FAVOR OF THE PROPOSAL, WILL RECEIVE THE SAME NUMBER OF SHARES OF COMMON STOCK AND WARRANTS AS THEY WOULD HAVE RECEIVED HAD THEY TENDERED THEIR PARTNERSHIP UNITS AND THE PARTNERSHIP WILL BE DISSOLVED. THE EXCHANGE OFFER INVOLVES VARIOUS RISKS THAT SHOULD BE CONSIDERED BY INVESTORS. SEE "RISK FACTORS AND MATERIAL CONSIDERATIONS," BEGINNING ON PAGE 4 OF THIS SUPPLEMENT. IN PARTICULAR, INVESTORS SHOULD CONSIDER THE FOLLOWING FACTORS: - INVESTORS HAD RECEIVED CASH DISTRIBUTIONS FROM THE PARTNERSHIP, BUT WILL RECEIVE NO CASH DISTRIBUTIONS OR DIVIDENDS IN THE FORESEEABLE FUTURE FROM BENTON. - THE MARKET PRICE OF THE COMMON STOCK COULD DECLINE BELOW THE MARKET PRICE USED FOR CALCULATION OF THE EXCHANGE RATES, EXPOSING INVESTORS TO A REDUCED RETURN ON THEIR INVESTMENT. - THE EXCHANGE VALUE OF THE PARTNERSHIP UNITS WAS DETERMINED BY BENTON, WHICH HAS INHERENT CONFLICTS OF INTEREST, AND MAY NOT REFLECT THE VALUE OF THE NET ASSETS OF THE PARTNERSHIP IF SOLD TO AN UNAFFILIATED THIRD PARTY IN AN ARM'S LENGTH TRANSACTION. - BENTON HAS ATTRIBUTED A PRESENT VALUE TO THE WARRANTS, USING THE BLACK-SCHOLES OPTION PRICING MODEL. HOWEVER, THE ACTUAL VALUE, IF ANY, A HOLDER MAY REALIZE FROM THE WARRANTS WILL DEPEND ON THE EXCESS OF THE MARKET PRICE OF THE 2 276 COMMON STOCK OVER THE EXERCISE PRICE OF THE WARRANT ON THE DATE THE WARRANT IS EXERCISED. - BENTON'S DETERMINATIONS OF THE EXCHANGE VALUES WERE BASED PRIMARILY ON THE ESTIMATED PRESENT VALUE OF THE PARTNERSHIP'S PROVED OIL AND GAS RESERVES, WHICH INVOLVES MANY UNCERTAINTIES AND COULD RESULT IN AN UNDERVALUATION OF PARTNERSHIP UNITS. ALTHOUGH SUPPORTED BY AN INDEPENDENT OFFER FOR THE PURCHASE OF SUBSTANTIALLY ALL OF THE ASSETS OF THE PARTNERSHIP, THERE CAN BE NO ASSURANCE THAT THE EXCHANGE VALUE REPRESENTS THE VALUE THE PARTNERSHIP COULD RECEIVE IN THE SALE OF THE ASSETS OF THE PARTNERSHIP. - THE ALTERNATIVES OF CONTINUING THE PARTNERSHIP OR LIQUIDATING ITS ASSETS COULD POTENTIALLY BE MORE BENEFICIAL TO INVESTORS THAN THE EXCHANGE OFFER. - NO INDEPENDENT REPRESENTATIVE WAS ENGAGED TO REPRESENT THE UNAFFILIATED INVESTORS IN NEGOTIATING THE TERMS OF THE EXCHANGE OFFER, WHICH MAY BE INFERIOR TO THOSE THAT COULD HAVE BEEN NEGOTIATED BY AN INDEPENDENT REPRESENTATIVE. - INVESTORS HAVE NO DISSENTER'S RIGHTS IN THE EXCHANGE OFFER, OTHER THAN LIMITED DISSENTERS' RIGHTS FOR CALIFORNIA RESIDENTS, AND THEREFORE CANNOT ELECT TO RECEIVE CASH FOR THEIR PARTNERSHIP UNITS. - OWNERSHIP OF COMMON STOCK MAY INVOLVE GREATER RISK THAN AN INVESTMENT IN THE PARTNERSHIP UNITS BECAUSE OF BENTON'S BROADER OPERATIONS, INCLUDING FOREIGN OPERATIONS, AND ITS USE OF DEBT TO FINANCE ONGOING OPERATIONS. - FUTURE EQUITY OFFERINGS BY BENTON COULD POTENTIALLY BE DILUTIVE TO INVESTORS HOLDING COMMON STOCK OR WARRANTS. The Exchange may be withdrawn at any time prior to its scheduled expiration date if Benton reasonably determines that a material change affecting the Partnership or the Company has occurred. THE EXCHANGE WILL ONLY BE CONSUMMATED IF THE PROPOSAL HAS BEEN APPROVED BY THE INVESTORS. The assets and liabilities of the Partnership, if the Proposal is approved and the Exchange Offer is accepted, will be transferred to Benton effective as of December 31, 1994 (the "Effective Date"). THE EXCHANGE OFFER EXPIRES AT 5:00 P.M. PACIFIC TIME ON , 1995 UNLESS EXTENDED. ------------------------------------------------------ THE SHARES OF COMMON STOCK AND WARRANTS TO BE ISSUED IN CONNECTION WITH THE EXCHANGE HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. THE DATE OF THIS SUPPLEMENT IS , 1995. 3 277 The information contained in this Supplement is being provided to Investors in the Benton Oil & Gas Combination Partnership 1989-1, L.P. (the "Partnership"). The information contained in this Supplement is not intended to be a complete description of all matters covered in the Prospectus, and Investors are encouraged to review all information set forth in the Prospectus. RISK FACTORS AND MATERIAL CONSIDERATIONS The Exchange Offer. In addition to the information included in this Supplement and the Prospectus, the Investors should carefully consider the following factors in determining whether to accept the Exchange Offer and consent to the Proposal. The risk factors summarized below are described in further detail elsewhere in the Prospectus at "Risk Factors and Material Considerations," beginning at page 34. Lack of Arm's Length Negotiations and Uncertainties in the Method of Determining Exchange Values. The Exchange Value was determined by Benton, based in part on an offer for the purchase of substantially all of the assets of the Partnership from an unaffiliated third party, but may not reflect the actual value of the net assets of the Partnership. The primary assets of the Partnership considered by Benton when determining the Exchange Value were the proved oil and gas reserves of the Partnership (the "Proved Reserves") and the present value of associated future net cash flow as of December 31, 1994, as well as the offer to purchase the Umbrella Point Field by Goldking, described herein and in the Prospectus. There are many uncertainties inherent in estimating quantities of Proved Reserves, and the present value attributed to the Partnership's Proved Reserves may be less than the discounted future net cash flows actually received from the Partnership's interest in its wells. In that event, the use of this valuation methodology will have resulted in an undervaluation of the Partnership Units. See "Recommendation of the Managing General Partner" in the Prospectus. Potential Decline in Market Price of Common Stock. Access to an active trading market by exchanging Investors may result in a relatively large number of shares of Common Stock offered for sale immediately after the Closing Date. This may tend to lower the market price for the Common Stock. Future market conditions in the oil and gas industry in general or the effect of the conditions on Benton in particular could also adversely affect the market price of the Common Stock and thus the value of the Warrants. There can be no assurance regarding the potential appreciation in the market price of the Common Stock. Any decline in the market price of the Common Stock could reduce the Investor's return on investment or increase the loss on the Investor's original investment. Potential Benefits of Alternatives to the Exchange. The alternatives to the Exchange Offer are the continuation of the Partnership or the liquidation of the Partnership's assets and distribution of the liquidation proceeds to Investors, either of which could potentially be 4 278 more beneficial to Investors than the Exchange by avoiding the risks associated with ownership of Benton Common Stock and, in the case of a liquidation of the Partnership, by providing an immediate cash return to Investors. See "Recommendation of the Managing General Partner--Managing General Partner's Determination that Exchange Offer is Fair--Alternatives to the Exchange" contained in the Prospectus. Lack of Independent Representatives for Investors; No Fairness Opinion. No independent representative was selected or hired to represent the interests of the Investors in negotiating the terms of the Exchange Offer. The Exchange Values and other terms of the Exchange Offer may therefore be inferior to those that could have been negotiated by an independent representative. Benton did not retain an independent third party to render an opinion regarding the fairness of the terms of the Exchange Offer to the Investors. Limited Dissenters' Rights. Investors who are California residents and who oppose the Proposal will have limited dissenters' rights. Other Investors who oppose the Proposal will have no dissenters' rights or appraisal rights, and therefore, no option to receive cash based on a separate appraisal of the Partnership assets in lieu of the Common Stock and Warrants based on the Exchange Values determined by Benton. The Managing General Partner could have provided all Investors with appraisal rights in structuring the Exchange Offer but elected not to do so, primarily because such rights are not provided for in the Partnership Agreements. The absence of these rights limit the options that would otherwise be available to Investors opposing the Exchange Offer. Effect of Dissenters' Rights on California Investors. Investors residing in California will be afforded limited dissenters' rights in accordance with the requirements for roll-up transactions under the California Code. By voting against the Proposal, Investors in the State of California will be deemed to exercise their dissenters' rights and will receive the number of shares of Common Stock and Warrants equal to the Exchange Value of their interests divided by the closing price of the Common Stock on the NASDAQ-National Market during the twenty days immediately after the Closing Date. If that average price is lower than the Exchange Price, dissenting California Investors will receive more shares of Common Stock than they would otherwise receive in the Exchange Offer. If, however, the average price is higher than the Exchange Price, dissenting California Investors will receive fewer shares of Common Stock and Warrants. California Investors hold a substantial portion of the interests in the Partnership, and the impact of the exercise of dissenters' rights could materially increase the number of shares of Common Stock issued by Benton in connection with the Exchange Offer. Conflicts of Interest of Benton. Benton is the Managing General Partner of the Partnership and its determination of the Exchange Value involves an inherent conflict of interest. As Managing General Partner, Benton owes fiduciary duties to the Investors in the Partnership. In addition, it owes a duty to its stockholders. While Benton believes that it has fulfilled these obligations in its determination of the Exchange Value, which is supported, in part, by a reserve report audited by an independent petroleum engineer, no degree of objectivity or professional competence can eliminate the inherent conflict of 5 279 interest. See "Recommendation of the Managing General Partner--Fiduciary Duties of Benton" contained in the Prospectus. Benton Dividend Policy. Benton's policy is to retain its earnings to support the growth of Benton's business. Accordingly, the Board of Directors of Benton has never declared cash dividends on its Common Stock and does not plan to do so in the foreseeable future. Furthermore, the terms of Benton's debt agreements prohibit Benton from paying cash dividends on its Common Stock. Thus, upon consummation of the Exchange, Investors will no longer receive cash distributions and it is unlikely that cash dividends will be paid on the Benton Common Stock at any time in the foreseeable future. No Fractional Shares. No fractional shares will be issued in connection with the Exchange Offer. An Investor who would otherwise be entitled to a fractional share of Common Stock will be paid cash in lieu of such fractional shares. Warrants issued in connection with the Exchange Offer will be rounded to the nearest whole number of Warrants and no fractional interest will be issued. Risks Associated with Ownership of Common Stock of Benton. In addition to the information included in this Supplement and the Prospectus, the Investors should carefully consider the following factors related to Benton in determining whether to accept the Exchange Offer. The risk factors summarized below are described in further detail in the Prospectus at "Risk Factors and Material Considerations." Losses From Benton's Operations. The historical financial data for Benton reflects net losses and decreased revenues for the years ended December 31, 1992 and 1993. Benton's ability to maintain its financing arrangements, produce its oil and gas reserves and service its debt obligations would be adversely affected by a lack of profitability. Foreign Operations. Almost all of Benton's oil and gas revenues and Proved Reserves are attributable to its operations in Venezuela and Russia. Benton's Venezuelan and Russian operations are subject to political, economic and other uncertainties inherent in the development of foreign properties. Properties Under Development. A substantial amount of Benton's Proved Reserves are undeveloped and require development activities and/or are proved developed behind-pipe or shut-in and require additional development activities. As a result, Benton will require substantial capital expenditures to develop all of its Proved Reserves. Engineers' Estimates of Reserves and Future Net Revenue. This Prospectus contains, and incorporates by reference, estimates of Benton's and the Partnerships' oil and gas reserves and future net revenues therefrom. Estimates of commercially recoverable oil and gas and the future net cash flows derived therefrom are based upon a number of variable factors and assumptions. Estimates to some degree are speculative and estimates of the commercially recoverable reserves of oil and natural gas, and the future net cash flows therefrom, prepared by different engineers or by the same engineer at different times, may 6 280 vary substantially. The difficulty of making precise estimates is accentuated because most of Benton's Proved Reserves were non-producing at December 31, 1994. Development of Additional Reserves. Benton's future success may also depend upon its ability to find or acquire additional oil and gas reserves that are economically recoverable. There can be no assurance that Benton will be able to discover additional commercial quantities of oil and gas, or that Benton will be able to continue to acquire interests in underdeveloped oil and gas fields and enhance production and reserves therefrom. Partnership Litigation. Certain limited partners in Benton's oil and gas limited partnerships, including the Partnerships that are the subject of this Exchange Offer, filed suit against Benton and others alleging breaches of contract, fiduciary duty and fraud. This suit has been voluntarily dismissed, subject to an agreement among the parties to arbitrate the issues and claims which were the subject of the claim. See "The Exchange Offer and Proposal--Litigation and Related Matters." In addition, Investors in partnerships which were sponsored by a third party have sued Benton on the theory that since it provided oil and gas drilling prospects to those partnerships and operated substantially all of their properties, it was responsible for alleged violations of securities laws in connection with the offer and sale of interests, contractual breach of fiduciary duty and fraud. See "The Exchange Offer and Proposal--Litigation and Related Matters." Retention and Attraction of Key Personnel. Benton depends to a large extent on the abilities and continued participation of certain key employees, the loss of whose services could have a material adverse effect on Benton's business. Regulation. The oil and gas industry is subject to broad and frequently changing regulations that could adversely affect the operations of Benton. In spite of the foregoing risks, Benton initiated and proposed the Exchange Offer and recommends adoption of the Proposal by the Partnership to enable Benton to acquire the assets and liabilities of the Partnership and to provide Investors with the potential benefits summarized in the Prospectus under the caption "Reasons for the Exchange Offer." MANAGING GENERAL PARTNER'S DETERMINATION THAT EXCHANGE OFFER IS FAIR THE MANAGING GENERAL PARTNER OF THE PARTNERSHIP HAS DETERMINED THAT THE EXCHANGE IS FAIR AND IS IN THE BEST INTERESTS OF THE PARTNERSHIP AND ITS PARTNERS AND HAS RECOMMENDED THAT THE PARTNERS OF THE PARTNERSHIP TENDER THEIR PARTNERSHIP UNITS AND CONSENT TO THE PARTNERSHIP PROPOSAL. THE EXCHANGE OFFER IS NOT CONDITIONED UPON ACCEPTANCE AND APPROVAL BY ALL OF THE PARTNERSHIPS AND THE MANAGING GENERAL PARTNER BELIEVES THAT THE OFFER IS FAIR 7 281 TO ALL INVESTORS, REGARDLESS OF WHICH OR THE NUMBER OF PARTNERSHIPS WHICH ACCEPT THE EXCHANGE OFFER FOR THE REASONS SET FORTH BELOW. General. The Managing General Partner has analyzed the terms of the Exchange Offer, the consideration and value offered to the Investors in exchange for their Partnership Units and the value of consideration an Investor could expect to receive under various alternatives to the Exchange. In determining that the Exchange Offer is fair to the Investors, the Managing General Partner considered that the Investors who do not accept the Exchange Offer or who do not elect to receive cash in lieu of Benton Common Stock will receive Common Stock and Warrants of Benton, and could receive cash if the Partnership was continued or liquidated. However, the Managing General Partner believes that because an Investor may elect to receive cash in lieu of Common Stock if the sale to Goldking is consummated, the Investors will receive consideration in excess of the alternatives to the Exchange if the Exchange Offer is accepted. The Managing General Partner's analysis of the consideration an Investor could receive under the alternatives to the Exchange are discussed below. The Managing General Partner believes that those Investors who receive Benton Common Stock will have access to a public trading market if such Investor elects to liquidate his investment for cash. The average daily trading volume for the Benton Common Stock on the NASDAQ National Market for the 30 trading days ended September 27, 1995 was 259,000 shares. The Managing General Partner believes that since the maximum aggregate number of shares of Benton Common Stock that will be issued in the Exchange Offer for all three Partnerships is 171,880, the issuance will have no material effect on the market value of the Benton Common Stock, and may allow all Investors receiving shares of Benton Common Stock in connection with the Exchange Offer and liquidation of the Partnerships to liquidate their investment in the market. Alternatives to the Exchange. The Managing General Partner's analysis of the most probable results of continuing the Partnership indicate that, while continuing the Partnership would avoid the risks associated with the ownership of Common Stock in Benton, Investors will receive potentially greater values by participating in the Exchange than the values they would derive from this alternative. Benton estimates that continuing the 1990-1 Partnership under market and operating conditions prevailing in 1994 would likely generate decreasing annual distributions of $114 per 1989-1 Unit in 1995, $146 in 1996, $91 in 1997 and $7 in 1998. Benton estimates that the remaining economic life of the 1989-1 Partnership is 3.5 years. Benton believes that the Partnership will have no residual value in its assets at the end of the economic life of the Partnership. The Managing General Partner also believes that, while liquidating the Partnership would provide an immediate cash return and avoid the risks associated with owning Benton Common Stock, the Exchange will provide Investors with greater values than they would likely receive in liquidation of the Partnership. Benton's liquidation analysis reflects an estimated liquidation value of approximately $294,634 of the 1989-1 Partnership, or $1,045 per Unit. Benton received an independent offer from Goldking to purchase the Partnership's interest in the Umbrella Point Field (which represents 99.3% of the total Proved Reserves of the Partnership) for an estimated total purchase price in cash of $323,296 as of June 30, 1995, subject to adjustments. This estimated 8 282 purchase price would represent potential cash distributions to the Investors equal to $1,147 per Unit. Benton's liquidation analysis is based on the anticipated proceeds from the sale of the Umbrella Point Field to Goldking, plus working capital for the Partnership at June 30, 1995, less estimated general and administrative costs involved in liquidation of the Partnership. For purposes of determining the general and administrative costs to the Partnership, Benton estimated that general and administrative expenses would approximate the general and administrative expenses incurred by the Partnership during the year ended December 31, 1994. The following table summarizes the results of Benton's liquidation analysis in comparison to the Exchange Values for the Partnership Units determined by Benton. The table also includes valuation data derived from Benton's analysis of continuing the Partnership. Benton did not undertake its continuation analysis for the purpose of valuing the Partnership, but solely to illustrate the likelihood of decreasing distributions based on oil and gas prices at December 31, 1994. However, because SEC disclosure standards for roll up transactions require a comparison of the value of the consideration offered in the transaction with the value of the consideration estimated for each alternative to the transaction, the tables also reflect the results of extending Benton's continuation analysis for the balance of the estimated life of the Partnership's Proved Reserves, and discounting the projected stream of distributions to present value at the same 10% discount rate used in Benton's liquidation analysis to account for the timing of cash flows as well as production and concentration risks.
VALUATION METHOD TOTAL VALUE PER - ---------------- INVESTOR VALUE(1) 1989-1 UNIT ----------------- ----------- Exchange Value................................................... $370,098 $1,312 Liquidation value estimated by Benton............................ 294,634 1,045 Continuation analysis by Benton assuming natural gas prices of $1.63 per Mcf and oil prices of $15.94 per Bbl(2)................................................... 90,661 322 Value of Proved Reserves at December 31, 1994(3)................. 325,540 1,155
(1) The Exchange Value and liquidation value attribute no value to Managing General Partners' interests. The continuation analysis assumes continued distributions to the Managing General Partner pursuant to the terms of the Partnership Agreement. (2) The assumed natural gas and oil prices are the prices used for preparation of the Partnership's reserve report at December 31, 1994. The continuation analysis was calculated based upon Benton's estimate of the remaining economic life of the Partnership, estimated to be 3.5 years. (3) Based on the Partnership's December 31, 1994 reserve report prepared by the Company and audited by Huddleston. The reserves are valued at December 31 of each year, based on oil and natural gas prices as of that date. Market prices for both oil and gas are subject to a significant degree of variation, and this variation will affect the calculation of future net cash flows reported by the Partnership at any specific date. 9 283 The actual amount that Investors would receive if the Partnership continued its operations would depend on production levels, which cannot be predicted with certainty. In addition, the actual amount that Investors would receive under either of the alternatives to the Exchange would depend on future oil and gas prices. To the extent that future prices for those commodities are materially higher or lower than the pricing assumptions made by the Managing General Partner, those fluctuations would likely have a similar effect on the operating results, distribution rates and market value of the Partnership Units, largely negating the effect of price changes on a comparison between the Exchange and either alternative of continuing the Partnership or liquidating its assets. In addition, Benton believes that liquidating the Partnership would deprive Investors of the opportunity to benefit from any future upturn in oil and gas prices. For a more detailed discussion of the bases for the Managing General Partner's determination that the Exchange Offer is fair to Investors, see "Recommendation of the Managing General Partner" contained at page 65 of the Prospectus. DETERMINATION OF EXCHANGE VALUE Components of the Exchange Value. The most significant assets considered in determining the Exchange Values were the anticipated cash proceeds from the sale of Umbrella Point Field and Proved Reserves of the Partnership. The Exchange Values reflect these oil and gas assets and all other assets and liabilities of the Partnership. These components reflect (i) the estimated cash proceeds from the sale of Umbrella Point Field to Goldking, (ii) the estimated present value of future net cash flows from the Proved Reserves of the Partnership as of December 31, 1994, discounted at 10% per year and calculated without escalation of prices and costs, (iii) the net book value of current assets and liabilities of the Partnership as of June 30, 1995, and (iv) the tax-basis balances of equipment as of December 31, 1994, and (v) the General Intangibles of the Partnership. Based on management's experience in evaluating reserve acquisition opportunities and transactions in the Partnership's production areas, Benton believes that the components of the Exchange Values reflect all appropriate valuation criteria for the Partnership in accordance with industry practice. Each component of the Exchange Value, estimated on the basis of interim data, is presented for the Partnership in the tables and discussions herein. In determining the Exchange Value, Benton considered the total distributions paid to date to participants in the respective Partnerships. For each of the Partnerships, Benton assigned a Total Exchange Value to the Partnership which, based upon certain assumptions described below, and in addition to the distributions paid to date, would provide Investors with consideration valued at 100% of their initial contribution to the Partnership. The estimated cash proceeds from the sale of the working interests in the Umbrella Point Field to Goldking and the value of other tangible assets of the Partnership are attributable to shares of Benton Common Stock, or cash if the Investor makes the cash election described herein. The remaining dollar value, if any, is referred to herein as General Intangibles. Pursuant to the Exchange Offer, value attributed to General Intangibles will be distributed to Investors in the form of Warrants. 10 284 The number of shares of Common Stock and Warrants to be issued pursuant to the Exchange Offer has been determined relative to a Total Exchange Value assigned to the 1989-1 Partnership Units, aggregating $370,098. The number of shares of Common Stock offered in exchange for Partnership Units has been determined by dividing the Exchange Value of the tangible assets of the Partnership by a Common Stock price of $11.00, subject to rounding adjustments. The Common Stock price is based upon the average closing price of the Common Stock on NASDAQ-National Market for the 20 trading days immediately preceding September 12, 1995 and will not reflect any subsequent increase or decrease in the market price for the Common Stock after that date, except to the extent required by dissenters' rights for California residents. The number of Warrants to be assigned to each Partnership Unite was determined by dividing the estimated value of the General Intangibles of the Partnership by the estimated present value per Warrant. Benton has used the Black-Scholes option pricing model to calculate the present value of the Warrants, which yielded a value of $3.64 per Warrant. The Warrants are exerciseable at a price of $11.00 per share and will expire three years from the date of issuance. The following unaudited table sets forth (i) the components of the Exchange Values of the Units and (ii) the Exchange Value per Unit held by an Investor. This information was compiled by Benton from the Partnership's reserve report as of December 31, 1994 (a summary of which is included in Exhibit B to this Prospectus) and the Partnership's tax records for the year ended December 31, 1994 and financial statements for the six months ended June 30, 1995. The following table sets forth each of the Exchange Value components, estimated on an interim basis. EXCHANGE VALUE COMPONENTS Estimated Cash Proceeds-Umbrella Point Field.......................................... $323,263 Present value of Proved Reserves of other properties (SEC PV 10)...................... 0 Cash.................................................................................. 5,717 Intercompany receivable--Benton Oil and Gas Company................................... 621 Value of equipment.................................................................... 4,563 General Intangibles................................................................... 35,901 Exchange Value........................................................................ $370,098 --------
Anticipated Sales Proceeds. In July 1995, Benton, on behalf of the Partnership, and Goldking executed an agreement whereby Goldking will purchase a 4.93% working interest in the Umbrella Point Field from the Partnership, subject to approval of the participants of the Partnership. Upon execution of the agreement, Goldking made an earnest money deposit in favor of the Partnership in the amount of $4,929, included as current assets of the Partnership (the "Deposit"). Subject to closing adjustments and excluding the Deposit, as of June 30, 1995 the Partnership's estimated cash proceeds from the sale would be $323,263, or $1,147 per 1989-1 Unit. Benton has made this Exchange Offer in contemplation of such sale, but the Exchange Offer is not conditioned upon consummation of such sale. Other Assets and Liabilities. The tax-basis balances of the 1989-1 Partnership's equipment, excluding Umbrella Point Field equipment, aggregated $4,563 at December 31, 1994, 11 285 and the net book value of its current assets and liabilities as of June 30, 1995 reflect a balance of $6,338, excluding property held for sale. The equipment value and current net assets are based upon the 1989-1 Partnership's 1994 year-end tax accounting records and June 30, 1995 unaudited financial statements, respectively, maintained in accordance with the applicable provisions of the 1989-1 Partnership Agreement. Benton believes that valuing the 1989-1 Partnership's equipment (comprised of oil and gas production and transportation facilities) at its tax-basis balances is favorable to the sellers of the producing properties since many purchasers in transactions evaluated by Benton, as part of its on-going involvement in the production area, allocate nominal value to well equipment on the theory that its salvage value at the end of the commercial lives of acquired wells will approximate the cost of plugging and abandoning the wells. Benton believes that the original cost of the equipment less the deductions computed through 1994 year end for tax purposes represents a reasonable approximation of the fair market value of the equipment to Benton. Benton also believes that valuing the current assets and liabilities of the 1989-1 Partnership (comprised of cash and intercompany receivable) at their book value as of June 30, 1995 is appropriate to reflect the fair market value of these items, which are expected to be collected and paid to Benton, to the extent outstanding, in the stated amounts reflected in the 1989-1 Partnership's unaudited balance sheet as of that date. General Intangibles. In determining the value attributed to General Intangibles, Benton evaluated the success to date of the 1989-1 Partnership, total consideration paid to date to the participants and the value to Benton of dissolving and liquidation the 1989-1 Partnership so that Benton can focus on its current operations and reduce the administrative burdens associated with operating the Partnership. Based upon Benton's evaluation of historical administrative costs for the 1989-1 Partnership, Benton estimates that the administrative costs for operating the Partnership will be approximately $35,000 per year. From inception through July 1995, the 1989-1 Partnership has made cash distributions to participants aggregating $848,836, or $3,012 per 1989-1 Unit. In forming the 1989-1 Partnership, Benton sold an aggregate of $1,409,091 in 1989-1 Units. Benton acknowledges the concerns raised by the Investors in the 1989-1 Partnership with regard to operations of the Partnership, the lack of success and thus the disappointing returns on investment by the Investors. Because many of the Investors are or were stockholders of Benton, Benton desires to maintain a good relationship with these stockholders, many of whom have been strong supporters of Benton from inception, and Benton desires to avoid future claims against it by participants relating to the management of the Partnership. See "The Exchange Offer and Proposal--Litigation and Related Matters" in the Prospectus. Assuming that the Investor in the 1989-1 Partnership elects to hold his or her shares of Common Stock and exercises his or her Warrants at the end of the three-year term, and the market price of the Common Stock is at or above approximately $16.75 per share, Benton believes that the Investors in the 1989-1 Partnership, will have received consideration in the form of cash distributions, Common Stock and Warrants in excess of the initial investment in the 1989-1 Partnership, without regard to any tax benefits received by the participants. On October 2, 1995, the last sales price of the Benton Common Stock on NASDAQ National Market was $11.13 per share. The assumed market price of the Common Stock of $16.75 per share discussed above represents a 33% increase in the market value of the Benton Common Stock during the three year term of the Warrants. There can be no assurance that the market price of the Benton Common Stock will increase 12 286 or that such price will be achieved. The value of the General Intangibles of the Partnership is not subject to valuation by third parties since the General Intangibles do not represent actual assets of the Partnership. Benton believes that the participants in the Partnership will not receive any value for the General Intangibles in any alternative to the Exchange. 13 287 COMPENSATION PAID TO MANAGING GENERAL PARTNER The following table sets forth the amount of compensation paid, and cash distributions made, to the Managing General Partner and its affiliates by the Partnership for each of the last three fiscal years and the six months ended June 30, 1995.
PERIOD CASH DISTRIBUTIONS PAID COMPENSATION PAID - ------ ----------------------- ----------------- Year Ended December 31, 1994 Year Ended December 31, 1993 Year Ended December 31, 1992 Six Months Ended June 30, 1995
None of the compensation paid or cash distributions made to the Managing General Partner by the Partnership would have been paid by the Partnership during the periods set forth above if the Exchange Offer had been in effect during such period. It is anticipated that substantially all of the assets of the Partnership will be sold to Goldking immediately following consummation of the Exchange Offer. If such sale is consummated, Benton will receive cash proceeds of approximately $323,296 for the sale of the working interest in the Umbrella Point Field as of June 30, 1995, and subject to adjustments. If all Investors in the Partnership elect to receive cash in lieu of Common Stock in connection with the Exchange, Benton will receive no cash proceeds from the sale. CASH DISTRIBUTIONS TO INVESTORS The following table sets forth the cash distributions paid to Investors for during each of the years in the five year period ended December 31, 1994, and during the six months ended June 30, 1995. None of the distributions represent a return of capital, unless noted.
1990 1991 1992 1993 1994 1995 - ---- ---- ---- ---- ---- ---- $500(1) $747(2) $1,003 $600 $162 $0
(1) Of these distributions, $192 represents distributions of earnings. (2) Of these distributions, $61 represents distributions of earnings. For additional financial information concerning the Partnership and Benton, see "Information Concerning the 1989-1 Partnership - Selected Historical Financial Data" and "Unaudited Pro Forma Financial Information" contained in the Prospectus. 14 288 PROSPECTUS SUPPLEMENT 1990-1 PARTNERSHIP SUBJECT TO COMPLETION DATED OCTOBER 3, 1995 EXCHANGE OFFER OF AN AGGREGATE OF 114,954 SHARES OF COMMON STOCK AND WARRANTS TO PURCHASE AN AGGREGATE OF 474,010 SHARES OF COMMON STOCK FOR PARTNERSHIP UNITS IN BENTON OIL & GAS COMBINATION PARTNERSHIP 1990 - 1, L.P. (1,419.192 PARTNERSHIP UNITS) --------------- EXCHANGE RATIO: 81 SHARES OF COMMON STOCK AND 334 WARRANTS PER 1990-1 PARTNERSHIP UNIT This Supplement accompanies a Prospectus (the "Prospectus") and is being furnished to the Investors ("Investors") in the Benton Oil & Gas Combination Partnership 1990-1, L.P., a California limited partnership (the "Partnership") in connection with the offer by Benton Oil and Gas Company, a Delaware corporation and the managing general partner of the Partnership ("Benton," or "Company," or "Managing General Partner") to exchange shares of Common Stock, $.01 par value of Benton ("Common Stock") and Warrants ("Warrants") to purchase shares of Common Stock of Benton (the "Exchange Offer") for all of the right, title and interest to units of Partnership interest in the Partnerships ("Partnership Units") held by Investors, at the exchange rate outlined below. Benton has offered to exchange shares of Common Stock and Warrants for all of the right, title and interest to units of partnership interest in the Benton Oil & Gas Combination Partnership 1989-1, L.P. (the "1989-1 Partnership") and the Benton Oil & Gas Combination Partnership 1991-1, L.P. (the "1991-1 Partnership") on the terms and at the exchange rates set forth in the Prospectus. A separate supplement has been prepared for each of the Partnerships. THE EFFECTS OF THE EXCHANGE OFFER MAY BE DIFFERENT FOR INVESTORS IN THE VARIOUS PARTNERSHIPS. UPON RECEIPT OF A WRITTEN REQUEST BY AN INVESTOR OR HIS REPRESENTATIVE WHO HAS BEEN DESIGNATED IN WRITING, A COPY OF ANY SUPPLEMENT WILL BE TRANSMITTED PROMPTLY, WITHOUT CHARGE, BY BENTON. ANY SUCH REQUEST SHOULD BE FORWARDED TO THE ATTENTION OF TONI L. JACKSON, BENTON OIL AND GAS COMPANY, 1145 EUGENIA PLACE, SUITE 200, CARPENTERIA, CALIFORNIA 93013. Benton is offering to exchange shares of Common Stock and Warrants to owners of Partnership Units in the 1990-1 Partnership (the "1990-1 Units") on the basis of $5,000.00 original investment on the terms and in the amounts set forth herein. The Warrants to be issued in connection with the Exchange Offer are exercisable at a price of $11.00 per share and will expire three years form the date of issuance. For detailed information regarding the determination of the Total Exchange Values for each of the Partnerships, see " Determination of 1 289 Exchange Value." On October 2, 1995, the last reported sales price of the Common Stock, as reported on NASDAQ National Market, was $11.13. In connection with the Exchange Offer, Benton is submitting a Proposal to Investors in the Partnership to amend the Partnership Agreement to provide for the transfer of all of the assets and liabilities of the Partnership to Benton as of the December 31, 1994 Effective Date in exchange for Common Stock and Warrants in the amounts set forth herein and the pro rata distribution of such consideration in liquidation of the Partnership. Each Investor who tenders his Partnership Units pursuant to the Exchange Offer will, by that tender, consent to the Proposal. ADOPTION OF THE PROPOSAL REQUIRES THE CONSENT OF INVESTORS OF THE PARTNERSHIP HOLDING 75% OF THE PARTNERSHIP UNITS. IF INVESTORS IN THE PARTNERSHIP HOLDING NOT LESS THAN 75% OF THE PARTNERSHIP UNITS ACCEPT THE EXCHANGE OFFER AND CONSENT TO THE PROPOSAL, ALL NON-DISSENTING HOLDERS OF UNITS IN THE PARTNERSHIP WILL BE BOUND BY THE TERMS OF THE EXCHANGE AND PROPOSAL AND WILL RECEIVE THE NUMBER OF SHARES OF COMMON STOCK AND WARRANTS DESCRIBED HEREIN. A SIMILAR EXCHANGE OFFER AND PROPOSAL IS BEING OFFERED TO INVESTORS IN TWO OTHER PARTNERSHIPS. EACH OF THE EXCHANGE OFFERS TO THE PARTNERSHIPS IS INDEPENDENT OF THE EXCHANGE OFFER TO THE OTHER PARTNERSHIPS. THE EXCHANGE WILL ONLY BE CONSUMMATED FOR THE PARTNERSHIP IF THE PROPOSAL HAS BEEN APPROVED BY THE INVESTORS. BENTON OIL AND GAS COMPANY, IN ADDITION TO BEING MANAGING GENERAL PARTNER OF THE THREE PARTNERSHIPS, OWNS 14.192 1990 - 1 UNITS AND WILL VOTE SUCH UNITS THE SAME AS A MAJORITY OF INVESTORS VOTE THEIR UNITS. INVESTORS WILL RECEIVE THE CONSIDERATION SET FORTH HEREIN, AND THE RESPECTIVE PARTNERSHIP WILL BE DISSOLVED. ASSUMING CONSUMMATION OF THE EXCHANGE OFFER, ALL OF THE INVESTORS IN THE PARTNERSHIP, WHETHER OR NOT THEY TENDER THEIR UNITS AND THUS VOTE IN FAVOR OF THE PROPOSAL, WILL RECEIVE THE SAME NUMBER OF SHARES OF COMMON STOCK AND WARRANTS AS THEY WOULD HAVE RECEIVED HAD THEY TENDERED THEIR PARTNERSHIP UNITS AND THE PARTNERSHIP WILL BE DISSOLVED. THE EXCHANGE OFFER INVOLVES VARIOUS RISKS THAT SHOULD BE CONSIDERED BY INVESTORS. SEE "RISK FACTORS AND MATERIAL CONSIDERATIONS," BEGINNING ON PAGE 4 OF THIS SUPPLEMENT. IN PARTICULAR, INVESTORS SHOULD CONSIDER THE FOLLOWING FACTORS: - INVESTORS HAD RECEIVED CASH DISTRIBUTIONS FROM THE PARTNERSHIP, BUT WILL RECEIVE NO CASH DISTRIBUTIONS OR DIVIDENDS IN THE FORESEEABLE FUTURE FROM BENTON. - THE MARKET PRICE OF THE COMMON STOCK COULD DECLINE BELOW THE MARKET PRICE USED FOR CALCULATION OF THE EXCHANGE RATES, EXPOSING INVESTORS TO A REDUCED RETURN ON THEIR INVESTMENT. - THE EXCHANGE VALUE OF THE PARTNERSHIP UNITS WAS DETERMINED BY BENTON, WHICH HAS INHERENT CONFLICTS OF INTEREST, AND MAY NOT REFLECT THE VALUE OF THE NET ASSETS OF THE PARTNERSHIP IF SOLD TO AN UNAFFILIATED THIRD PARTY IN AN ARM'S LENGTH TRANSACTION. - BENTON HAS ATTRIBUTED A PRESENT VALUE TO THE WARRANTS, USING THE BLACK - SCHOLES OPTION PRICING MODEL. HOWEVER, THE ACTUAL VALUE, IF ANY, A HOLDER MAY REALIZE 2 290 FROM THE WARRANTS WILL DEPEND ON THE EXCESS OF THE MARKET PRICE OF THE COMMON STOCK OVER THE EXERCISE PRICE OF THE WARRANT ON THE DATE THE WARRANT IS EXERCISED. - BENTON'S DETERMINATIONS OF THE EXCHANGE VALUES WERE BASED PRIMARILY ON THE ESTIMATED PRESENT VALUE OF THE PARTNERSHIP'S PROVED OIL AND GAS RESERVES, WHICH INVOLVES MANY UNCERTAINTIES AND COULD RESULT IN AN UNDERVALUATION OF PARTNERSHIP UNITS. ALTHOUGH SUPPORTED BY AN INDEPENDENT OFFER FOR THE PURCHASE OF SUBSTANTIALLY ALL OF THE ASSETS OF THE PARTNERSHIP, THERE CAN BE NO ASSURANCE THAT THE EXCHANGE VALUE REPRESENTS THE VALUE THE PARTNERSHIP COULD RECEIVE IN THE SALE OF THE ASSETS OF THE PARTNERSHIP. - THE ALTERNATIVES OF CONTINUING THE PARTNERSHIP OR LIQUIDATING ITS ASSETS COULD POTENTIALLY BE MORE BENEFICIAL TO INVESTORS THAN THE EXCHANGE OFFER. - NO INDEPENDENT REPRESENTATIVE WAS ENGAGED TO REPRESENT THE UNAFFILIATED INVESTORS IN NEGOTIATING THE TERMS OF THE EXCHANGE OFFER, WHICH MAY BE INFERIOR TO THOSE THAT COULD HAVE BEEN NEGOTIATED BY AN INDEPENDENT REPRESENTATIVE. - INVESTORS HAVE NO DISSENTER'S RIGHTS IN THE EXCHANGE OFFER, OTHER THAN LIMITED DISSENTERS' RIGHTS FOR CALIFORNIA RESIDENTS, AND THEREFORE CANNOT ELECT TO RECEIVE CASH FOR THEIR PARTNERSHIP UNITS. - OWNERSHIP OF COMMON STOCK MAY INVOLVE GREATER RISK THAN AN INVESTMENT IN THE PARTNERSHIP UNITS BECAUSE OF BENTON'S BROADER OPERATIONS, INCLUDING FOREIGN OPERATIONS, AND ITS USE OF DEBT TO FINANCE ONGOING OPERATIONS. - FUTURE EQUITY OFFERINGS BY BENTON COULD POTENTIALLY BE DILUTIVE TO INVESTORS HOLDING COMMON STOCK OR WARRANTS. The Exchange may be withdrawn at any time prior to its scheduled expiration date if Benton reasonably determines that a material change affecting the Partnership or the Company has occurred. THE EXCHANGE WILL ONLY BE CONSUMMATED IF THE PROPOSAL HAS BEEN APPROVED BY THE INVESTORS. The assets and liabilities of the Partnership, if the Proposal is approved and the Exchange Offer is accepted, will be transferred to Benton effective as of December 31, 1994 (the "Effective Date"). -------------------------------------------------- THE EXCHANGE OFFER EXPIRES AT 5:00 P.M. PACIFIC TIME ON , 1995 UNLESS EXTENDED. -------------------------------------------------- THE SHARES OF COMMON STOCK AND WARRANTS TO BE ISSUED IN CONNECTION WITH THE EXCHANGE HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. THE DATE OF THIS SUPPLEMENT IS , 1995. 3 291 The information contained in this Supplement is being provided to Investors in the Benton Oil & Gas Combination Partnership 1990-1, L.P. (the "Partnership"). The information contained in this Supplement is not intended to be a complete description of all matters covered in the Prospectus, and Investors are encouraged to review all information set forth in the Prospectus. RISK FACTORS AND MATERIAL CONSIDERATIONS The Exchange Offer. In addition to the information included in this Supplement and the Prospectus, the Investors should carefully consider the following factors in determining whether to accept the Exchange Offer and consent to the Proposal. The risk factors summarized below are described in further detail elsewhere in the Prospectus at "Risk Factors and Material Considerations," beginning at page 34. Lack of Arm's Length Negotiations and Uncertainties in the Method of Determining Exchange Values. The Exchange Value was determined by Benton, based in part on an offer for the purchase of substantially all of the assets of the Partnership from an unaffiliated third party (Goldking Trinity Bay Corp.), but may not reflect the actual value of the net assets of the Partnership. The primary assets of the Partnership considered by Benton when determining the Exchange Value were the proved oil and gas reserves of the Partnership (the "Proved Reserves") and the present value of associated future net cash flow as of December 31, 1994, as well as the offer to purchase the Umbrella Point Field by Goldking, described herein and in the Prospectus. There are many uncertainties inherent in estimating quantities of Proved Reserves, and the present value attributed to the Partnership's Proved Reserves may be less than the future net cash flows actually received from the Partnership's interest in its wells. In that event, the use of this valuation methodology will have resulted in an undervaluation of the Partnership Units. See "Method of Determining Exchange Value." Potential Decline in Market Price of Common Stock. Access to an active trading market by exchanging Investors may result in a relatively large number of shares of Common Stock offered for sale immediately after the Closing Date. This may tend to lower the market price for the Common Stock. Future market conditions in the oil and gas industry in general or the effect of the conditions on Benton in particular could also adversely affect the market price of the Common Stock and thus the value of the Warrants. There can be no assurance regarding the potential appreciation in the market price of the Common Stock. Any decline in the market price of the Common Stock could reduce the Investor's return on investment or increase the loss on the Investor's original investment. Potential Benefits of Alternatives to the Exchange. The alternatives to the Exchange Offer are the continuation of the Partnership or the liquidation of the Partnership's assets and distribution of the liquidation proceeds to Investors, either of which could potentially be 4 292 more beneficial to Investors than the Exchange by avoiding the risks associated with ownership of Benton Common Stock and, in the case of a liquidation of the Partnership, by providing an immediate cash return to Investors. See "Recommendation of the Managing General Partner -- Managing General Partner's Determination that Exchange Offer is Fair -- Alternatives to the Exchange" contained in the Prospectus. Lack of Independent Representatives for Investors; No Fairness Opinion. No independent representative was selected or hired to represent the interests of the Investors in negotiating the terms of the Exchange Offer. The Exchange Values and other terms of the Exchange Offer may therefore be inferior to those that could have been negotiated by an independent representative. Benton did not retain an independent third party to render an opinion regarding the fairness of the terms of the Exchange Offer to the Investors. Limited Dissenters' Rights. Investors who are California residents and who oppose the Proposal will have limited dissenters' rights. Other Investors who oppose the Proposal will have no dissenters' rights or appraisal rights, and therefore, no option to receive cash based on a separate appraisal of the Partnership assets in lieu of the Common Stock and Warrants based on the Exchange Values determined by Benton. The Managing General Partner could have provided all Investors with appraisal rights in structuring the Exchange Offer but elected not to do so, primarily because such rights are not provided for in the Partnership Agreements. The absence of these rights limit the options that would otherwise be available to Investors opposing the Exchange Offer. Effect of Dissenters' Rights on California Investors. Investors residing in California will be afforded limited dissenters' rights in accordance with the requirements for roll-up transactions under the California Code. By voting against the Proposal, Investors in the State of California will be deemed to exercise their dissenters' rights and will receive the number of shares of Common Stock and Warrants equal to the Exchange Value of their interests divided by the closing price of the Common Stock on the NASDAQ National Market during the twenty days immediately after the Closing Date. If that average price is lower than the Exchange Price, dissenting California Investors will receive more shares of Common Stock than they would otherwise receive in the Exchange Offer. If, however, the average price is higher than the Exchange Price, a dissenting California Investor would receive fewer shares of Common Stock and Warrants. California Investors hold a substantial portion of the interests in the Partnership, and the impact of the exercise of dissenters' rights could materially increase the number of shares of Common Stock issued by Benton in connection with the Exchange Offer. Conflicts of Interest of Benton. Benton is the Managing General Partner of the Partnership and its determination of the Exchange Value involves an inherent conflict of interest. As Managing General Partner, Benton owes fiduciary duties to the Investors in the Partnership. In addition, it owes a duty to its stockholders. While Benton believes that it has fulfilled these obligations in its determination of the Exchange Value, which is supported, in part, by a reserve report audited by an independent petroleum engineer, no degree of objectivity or professional competence can eliminate the inherent conflict of 5 293 interest. See "Recommendation of the Managing General Partner -- Fiduciary Duties of Benton" contained in the Prospectus. Benton Dividend Policy. Benton's policy is to retain its earnings to support the growth of Benton's business. Accordingly, the Board of Directors of Benton has never declared cash dividends on its Common Stock and does not plan to do so in the foreseeable future. Furthermore, the terms of Benton's debt agreements prohibit Benton from paying cash dividends on its Common Stock. Thus, upon consummation of the Exchange, Investors will no longer receive cash distributions and it is unlikely that cash dividends will be paid on the Benton Common Stock at any time in the foreseeable future. No Fractional Shares. No fractional shares will be issued in connection with the Exchange Offer. An Investor who would otherwise be entitled to a fractional share of Common Stock will be paid cash in lieu of such fractional shares. Warrants issued in connection with the Exchange Offer will be rounded to the nearest whole number of Warrants and no fractional interest will be issued. Risks Associated with Ownership of Common Stock of Benton. In addition to the information included in this Supplement and the Prospectus, the Investors should carefully consider the following factors related to Benton in determining whether to accept the Exchange Offer. The risk factors summarized below are described in further detail in the Prospectus at "Risk Factors and Material Considerations." Losses From Benton's Operations. The historical financial data for Benton reflects net losses and decreased revenues for the years ended December 31, 1992 and 1993. Benton's ability to maintain its financing arrangements, produce its oil and gas reserves and service its debt obligations would be adversely affected by a lack of profitability. Foreign Operations. Almost all of Benton's oil and gas revenues and Proved Reserves are attributable to its operations in Venezuela and Russia. Benton's Venezuelan and Russian operations are subject to political, economic and other uncertainties inherent in the development of foreign properties. Properties Under Development. A substantial amount of Benton's Proved Reserves are undeveloped and require development activities and/or are proved developed behind - pipe or shut - in and require additional development activities. As a result, Benton will require substantial capital expenditures to develop all of its Proved Reserves. Engineers' Estimates of Reserves and Future Net Revenue. This Prospectus contains, and incorporates by reference, estimates of Benton's and the Partnerships' oil and gas reserves and future net revenues therefrom. Estimates of commercially recoverable oil and gas and the future net cash flows derived therefrom are based upon a number of variable factors and assumptions. Estimates to some degree are speculative and estimates of the commercially recoverable reserves of oil and natural gas, and the future net cash flows therefrom, prepared by different engineers or by the same engineer at different 6 294 times, may vary substantially. The difficulty of making precise estimates is accentuated because most of Benton's Proved Reserves were non-producing at December 31, 1994. Development of Additional Reserves. Benton's future success may also depend upon its ability to find or acquire additional oil and gas reserves that are economically recoverable. There can be no assurance that Benton will be able to discover additional commercial quantities of oil and gas, or that Benton will be able to continue to acquire interests in underdeveloped oil and gas fields and enhance production and reserves therefrom. Partnership Litigation. Certain limited partners in Benton's oil and gas limited partnerships, including the Partnerships that are the subject of this Exchange Offer, filed suit against Benton and others alleging breaches of contract, fiduciary duty and fraud. This suit has been voluntarily dismissed, subject to an agreement among the parties to arbitrate the issues and claims which were the subject of the claim. See "The Exchange Offer and Proposal -- Litigation and Related Matters." In addition, Investors in partnerships which were sponsored by a third party have sued Benton on the theory that since it provided oil and gas drilling prospects to those partnerships and operated substantially all of their properties, it was responsible for alleged violations of securities laws in connection with the offer and sale of interests, contractual breach of fiduciary duty and fraud. See "The Exchange Offer and Proposal -- Litigation and Related Matters" in the Prospectus. Retention and Attraction of Key Personnel. Benton depends to a large extent on the abilities and continued participation of certain key employees, the loss of whose services could have a material adverse effect on Benton's business. Regulation. The oil and gas industry is subject to broad and frequently changing regulations that could adversely affect the operations of Benton. In spite of the foregoing risks, Benton initiated and proposed the Exchange Offer and recommends adoption of the Proposal by the Partnership to enable Benton to acquire the assets and liabilities of the Partnership and to provide Investors with the potential benefits summarized in the Prospectus under the caption "Reasons for the Exchange Offer." MANAGING GENERAL PARTNER'S DETERMINATION THAT EXCHANGE OFFER IS FAIR THE MANAGING GENERAL PARTNER OF THE PARTNERSHIP HAS DETERMINED THAT THE EXCHANGE IS FAIR AND IS IN THE BEST INTERESTS OF THE PARTNERSHIP AND ITS PARTNERS AND HAS RECOMMENDED THAT THE PARTNERS OF THE PARTNERSHIP TENDER THEIR PARTNERSHIP UNITS AND CONSENT TO THE PARTNERSHIP PROPOSAL. THE EXCHANGE OFFER IS NOT CONDITIONED UPON ACCEPTANCE AND APPROVAL BY ALL OF THE PARTNERSHIPS AND THE MANAGING GENERAL PARTNER BELIEVES THAT THE OFFER IS FAIR TO ALL 7 295 INVESTORS, REGARDLESS OF WHICH OR THE NUMBER OF PARTNERSHIPS WHICH ACCEPT THE EXCHANGE OFFER FOR THE REASONS SET FORTH BELOW. General. The Managing General Partner has analyzed the terms of the Exchange Offer, the consideration and value offered to the Investors in exchange for their Partnership Units and the value of consideration an Investor could expect to receive under various alternatives to the Exchange. In determining that the Exchange Offer is fair to the Investors, the Managing General Partner considered that the Investors who do not accept the Exchange Offer or who do not elect to receive cash in lieu of Benton Common Stock will receive Common Stock and Warrants of Benton, and could receive cash if the Partnership was continued or liquidated. However, the Managing General Partner believes that because an Investor may elect to receive cash in lieu of Common Stock if the sale to Goldking is consummated, the Investors will receive consideration in excess of the alternatives to the Exchange if the Exchange Offer is accepted. The Managing General Partner's analysis of the consideration an Investor could receive under the alternatives to the Exchange are discussed below. The Managing General Partner believes that those Investors who receive Benton Common Stock will have access to a public trading market if such Investor elects to liquidate his investment for cash. The average daily trading volume for the Benton Common Stock on the NASDAQ National Market for the 30 trading days ended September 27, 1995 was 259,000 shares. The Managing General Partner believes that since the maximum aggregate number of shares of Benton Common Stock that will be issued in the Exchange Offer for all three Partnerships is 171,880, the issuance will have no material effect on the market value of the Benton Common Stock, and may allow all Investors receiving shares of Benton Common Stock in connection with the Exchange Offer and liquidation of the Partnerships to liquidate their investment in the market. Alternatives to the Exchange. The Managing General Partner's analysis of the most probable results of continuing the Partnership indicate that, while continuing the Partnership would avoid the risks associated with the ownership of Common Stock in Benton, Investors will receive potentially greater values by participating in the Exchange than the values they would derive from this alternative. Benton estimates that continuing the 1990-1 Partnership under market and operating conditions prevailing in 1994 would likely generate decreasing annual distributions of $97 per 1990-1 Unit in 1995, $119 in 1996, $76 in 1997, $30 in 1998, $10 in 1999 and $1 in 2,000. Benton estimates that the remaining economic life of the 1990-1 Partnership is 5.5 years. Benton believes that the Partnership will have no residual value in its assets at the end of the economic life of the Partnership. The Managing General Partner also believes that, while liquidating the Partnership would provide an immediate cash return and avoid the risks associated with owning Benton Common Stock, the Exchange will provide Investors with greater values than they would likely receive in liquidation of the Partnership. Benton's liquidation analysis reflects an estimated liquidation value of approximately $1,052,601 of the 1990-1 Partnership, or $742 per Unit. Benton received an independent offer from Goldking to purchase the Partnership's interest in the Umbrella Point Field (which represents 88.1% of the total Proved Reserves of the Partnership) for an estimated total purchase price in cash of $930,865 as of June 30, 1995, subject to adjustments. This 8 296 estimated purchase price would represent potential cash distributions to the Investors equal to $656 per Unit. Benton's liquidation analysis is based on the anticipated proceeds from the sale of the Umbrella Point Field to Goldking, plus working capital for the Partnership at June 30, 1995, less estimated general and administrative costs involved in liquidation of the Partnership. For purposes of determining the general and administrative costs to the Partnership, Benton estimated that general and administrative expenses would approximate the general and administrative expenses incurred by the Partnership during the year ended December 31, 1994. The following table summarizes the results of Benton's liquidation analysis in comparison to the Exchange Values for the Partnership Units determined by Benton. The table also includes valuation data derived from Benton's analysis of continuing the Partnership. Benton did not undertake its continuation analysis for the purpose of valuing the Partnership, but solely to illustrate the likelihood of decreasing distributions based on oil and gas prices at December 31, 1994. However, because SEC disclosure standards for roll up transactions require a comparison of the value of the consideration offered in the transaction with the value of the consideration estimated for each alternative to the transaction, the tables also reflect the results of extending Benton's continuation analysis for the balance of the estimated life of the Partnership's Proved Reserves, and discounting the projected stream of distributions to present value at the same 10% discount rate used in Benton's liquidation analysis to account for the timing of cash flows as well as production and concentration risks.
VALUATION METHOD TOTAL VALUE PER - ---------------- INVESTOR VALUE(1) 1990 - 1 UNIT ----------------- ------------- Exchange Value...................................................... $2,990,728 $2,107 Liquidation value estimated by Benton............................... 1,052,601 742 Value of Proved Reserves at December 31, 1994 (2)................... 1,057,123 745 Continuation analysis by Benton assuming natural gas prices of $1.63 per Mcf and oil prices of $15.94 per Bbl(3)............. 415,355 293
(1) The Exchange Value and liquidation value attribute no value to Managing General Partners' interests. The continuation analysis assumes continued distributions to the Managing General Partner pursuant to the terms of the Partnership Agreement. (2) Based on the Partnership's December 31, 1994 reserve report prepared by the Company and audited by Huddleston. The reserves are valued as of December 31 of each year, based on oil and gas prices as of that date. Market prices for both oil and natural gas are subject to a significant degree of variation, and this variation will effect the calculation of future net cash flows by the Partnership at nay specific date. (3) The assumed natural gas and oil prices are the prices used for preparation of the Partnership's reserve report at December 31, 1994. The continuation analysis was calculated based upon Benton's estimate of the remaining economic life of the Partnership, estimated to be 5.5 years. 9 297 The actual amount that Investors would receive if the Partnership continued its operations would depend on production levels, which cannot be predicted with certainty. In addition, the actual amount that Investors would receive under either of the alternatives to the Exchange would depend on future oil and gas prices. To the extent that future prices for those commodities are materially higher or lower than the pricing assumptions made by the Managing General Partner, those fluctuations would likely have a similar effect on the operating results, distribution rates and market value of the Partnership Units, largely negating the effect of price changes on a comparison between the Exchange and either alternative of continuing the Partnership or liquidating its assets. In addition, Benton believes that liquidating the Partnership would deprive Investors of the opportunity to benefit from any future upturn in oil and gas prices. For a more detailed discussion of the bases for the Managing General Partner's determination that the Exchange Offer is fair to Investors, see "Recommendation of the Managing General Partner" contained at page 65 of the Prospectus. DETERMINATION OF EXCHANGE VALUE Components of the Exchange Value. The most significant assets considered by Benton in determining the Exchange Value of the Units were the anticipated net proceeds from the sale of the Umbrella Point Field and Proved Reserves of the Partnership. The Exchange Values represent the sum of (i) the estimated cash proceeds from the anticipated sale of Umbrella Point Field to Goldking, (ii) the estimated present value of future net cash flows from the Proved Reserves of the Partnership as of December 31, 1994, discounted at 10% per year and calculated without escalation of prices and costs, as reflected in the reserve report for the Partnership as of that date prepared by Benton and audited by Huddleston & Co., Inc., independent petroleum engineers ("Huddleston"), (iii) the tax - basis balances of equipment as of December 31, 1994 and the net book value of current assets and liabilities (reflected on the unaudited balance sheet) of the Partnership as of June 30, 1995, and (iv) the value of General Intangibles. These components represent all of the assets and liabilities of the Partnership and were determined as of the year end and June 30, 1995 to conform with the SEC reporting requirements for reserve information and unaudited financial information, respectively. Since the year-end reserve information is audited, the Exchange Values were derived from that information. In determining the Exchange Value, Benton considered the total distributions paid to date to participants in the Partnership. For the Partnership, and each of the other Partnerships, Benton assigned a Total Exchange Value to the Partnership which, based upon certain assumptions described herein, and in addition to the distributions paid to date, would provide Investors with consideration valued at 100% of their initial contribution to the Partnership. See " -- General Intangibles" for a discussion of the assumptions used by Benton. The estimated cash proceeds from the sale of the working interest in the Umbrella Point Field to Goldking and the value of other tangible assets of the Partnership are attributable to shares of Benton Common Stock, or cash if the Investor makes the cash election described herein. The remaining dollar value is 10 298 referred to herein as General Intangibles. Pursuant to the Exchange Offer, value attributed to General Intangibles will be distributed to Investors in the form of Warrants. The number of shares of Common Stock and Warrants to be issued pursuant to the Exchange Offer has been determined relative to a Total Exchange Value assigned to the Partnership aggregating $2,990,728. The number of shares of Common Stock offered in exchange for Partnership Units has been determined by dividing the Exchange Value of the tangible assets by a Common Stock price of $11.00, subject to rounding adjustments. The Common Stock price is based upon the average closing price of the Common Stock on the NASDAQ National Market for the 20 trading days immediately preceding September 12, 1995 and will not reflect any subsequent increase or decrease in the market price for the Common Stock after that date, except to the extent required by dissenters' rights for California residents. The number of Warrants to be assigned to the Partnership was determined by dividing the estimated value of the General Intangibles of the Partnership by the estimated present value per Warrant. Benton has used the Black-Scholes option pricing model to calculate the present value of the Warrants, which yielded a value of $3.64 per Warrant. The Warrants are exercisable at a price of $11.00 per share and will expire three years from the date of issuance. The following unaudited table sets forth (i) the components of the Exchange Values of the Units and (ii) the Exchange Value per Unit held by an Investor. This information was compiled by Benton from the Partnership's reserve report as of December 31, 1994 (a summary of which is included in Exhibit B to this Prospectus) and the Partnership's tax records for the year ended December 31, 1994 and financial statements for the six months ended June 30, 1995. The following table sets forth each of the Exchange Value components, estimated on an interim basis. EXCHANGE VALUE COMPONENTS Estimated Cash Proceeds - Umbrella Point Field . . . . . . . . . . . . . . . . . . $ 930,865 Present value of Proved Reserves of other properties (SEC PV 10) . . . . . . . . . 119,694 Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145,455 Intercompany payable -- Benton Oil and Gas Company . . . . . . . . . . . . . . . . (56,281) Value of equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,037 General Intangibles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,725,396 ---------- Exchange Value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,990,728 ==========
Anticipated Sales Proceeds. In July 1995, Benton, on behalf of the Partnership, and Goldking executed an agreement whereby Goldking will purchase a 14.19% working interest in the Umbrella Point Field from the Partnership, subject to approval of the participants of the Partnership. Upon execution of the agreement, Goldking made an earnest money deposit in favor of the Partnership of $14,192, included as current assets of the Partnership (the "Deposit"). Subject to closing adjustments and excluding the Deposit, as of June 30, 1995 the Partnership's estimated cash proceeds from the sale would be $930,865, or $656 per 1990-1 Unit. Benton has 11 299 made this Exchange Offer in contemplation of such sale, but the Exchange Offer is not conditioned upon consummation of such sale. Proved Reserves. The calculation of the present value of the 1990-1 Partnership's Proved Reserves for the purpose of determining the Exchange Value complies with the rules and regulations of the SEC relating to the calculation of the present value of future net cash flows determined as of December 31, 1994 attributable to proved oil and gas reserves for disclosure and financial reporting purposes. The regulations governing these reserves do not permit the use of escalated prices and costs except in accordance with existing contractual arrangements, and the resulting SEC PV 10 calculations may overestimate or underestimate the actual future cash flows from the production and sale of oil and gas and, consequently, the present value thereof. The gross quantities of Proved Reserves attributable to the 1990-1 Partnership's interest in its wells, together with the estimated present value of those reserves, were estimated on an SEC PV 10 basis as of December 31, 1994 in a reserve report prepared by Benton and audited by Huddleston. A summary of the report and a copy of the audit letter, setting forth the criteria and assumptions used in evaluating the 1990-1 Partnership's Proved Reserves, are included in Exhibit B. There are numerous uncertainties inherent in estimating quantities of Proved Reserves. Huddleston audited the data and computations used by Benton's petroleum engineer in their evaluation of the total Proved Reserves attributable to all of the wells in which the 1990-1 Partnership had an interest as of December 31, 1994. Estimates by other independent petroleum engineers could vary from Benton's estimates and could result in higher or lower valuations. The estimates of the 1990-1 Partnership's future gross revenues attributable to its estimated Proved Reserves as of December 31, 1994 were calculated based on natural gas and crude oil prices in effect on that date. Those prices had a weighted average of $1.63 per Mcf for natural gas and $15.94 per Bbl for oil. Future operating and development costs were based on the 1990-1 Partnership's operating and development costs as of December 31, 1994 and were used without escalation. Future severance (production) and ad valorem (property) taxes were calculated using rates prevailing at December 31, 1994. The estimated future gross revenues, future operating and development costs and production taxes were allocated to the 1990-1 Partnership in accordance with its interest in oil and gas properties, taking into account applicable reversionary and overriding royalty interests. The present values of the estimated net cash flows attributable to the 1990-1 Partnership's Proved Reserves of other properties were calculated by discounting the future net cash flows to present value at the rate of 10% per year, as prescribed by SEC regulations covering reserve reporting for financial disclosure purposes. The discount factor is intended to reflect the timing of future net cash flows. No further discount or risk adjustment was applied. Present value, regardless of the discount rate used, is materially affected by assumptions as to timing of future production, which may prove to have been inaccurate. 12 300 Other Assets and Liabilities. The tax-basis balances of the 1990-1 Partnership's equipment, excluding Umbrella Point Field equipment, aggregated $13,037 at December 31, 1994, and the net book value of its current assets and liabilities as of June 30, 1995 reflect a balance of $201,736 after deducting 1994 distributions aggregating $93,667. The equipment value and current net assets are based upon the 1990-1 Partnership's 1994 year-end tax accounting records and June 30, 1995 unaudited financial statements, respectively, maintained in accordance with the applicable provisions of the 1990-1 Partnership Agreement. Benton believes that valuing the 1990-1 Partnership's equipment (comprised of oil and gas production and transportation facilities) at its tax-basis balances is favorable to the sellers of the producing properties since many purchasers in transactions evaluated by Benton, as part of its on-going involvement in the production area, allocate nominal value to well equipment on the theory that its salvage value at the end of the commercial lives of acquired wells will approximate the cost of plugging and abandoning the wells. Benton believes that the original cost of the equipment less the deductions computed through 1994 year end for tax purposes represents a reasonable approximation of the fair market value of the equipment to Benton. Benton also believes that valuing the current assets and liabilities of the 1990-1 Partnership (comprised of cash and intercompany receivable) at their book value as of June 30, 1995 is appropriate to reflect the fair market value of these items, which are expected to be collected and paid to Benton, to the extent outstanding, in the stated amounts reflected in the 1990-1 Partnership's unaudited balance sheet as of that date. General Intangibles. In determining the value attributed to General Intangibles, Benton evaluated the success to date of the 1990-1 Partnership, total consideration paid to date to the participants and the value to Benton of dissolving and liquidation the 1990-1 Partnership so that Benton can focus on its current operations and reduce the administrative burdens associated with operating the Partnership. Based upon Benton's evaluation of historical administrative costs for the 1990-1 Partnership, Benton estimates that the administrative costs for operating the Partnership will be approximately $80,000 per year. From inception through September 1995, the 1990-1 Partnership has made cash distributions to participants aggregating $2,452,364, or $1,728 per 1990-1 Unit. In forming the 1990-1 Partnership, Benton sold an aggregate of $7,095,960 of 1990-1 Units. Benton acknowledges the concerns raised by the Investors in the 1990-1 Partnership with regard to operations of the Partnership, the lack of success and thus the disappointing returns on investment by the Investors. Because many of the Investors are or were stockholders of Benton, Benton desires to maintain a good relationship with these stockholders, many of whom have been strong supporters of Benton from inception, and Benton desires to avoid future claims against it by participants relating to the management of the Partnership. See "The Exchange Offer and Proposal -- Litigation and Related Matters." Assuming that the Investor in the 1990-1 Partnership elects to hold his or her shares of Common Stock and exercises his or her Warrants at the end of the three-year term, and the market price of the Common Stock is at or above approximately $16.75 per share, Benton believes that the Investors in the 1990-1 Partnership, will have received consideration in the form of cash distributions, Common Stock and Warrants in excess of the initial investment in the 1990-1 Partnership, without regard to any tax benefits received by the 13 301 participants. On October 2, 1995, the last sales price of the Benton Common Stock on NASDAQ National Market was $11.13 per share. The assumed market price of the Common Stock of $16.75 per share discussed above represents a 34% increase in the market value of the Benton Common Stock during the three year term of the Warrants. There can be no assurance that the market price of the Benton Common Stock will increase or that such price will be achieved. The value of the General Intangibles of the Partnership is not subject to valuation by third parties since the General Intangibles do not represent actual assets of the Partnership. Benton believes that the participants in the Partnership will not receive any value for the General Intangibles in any alternative to the Exchange. Subsequent Adjustments. The Exchange Values will not be adjusted to reflect changes after December 31, 1994 in the present value of the estimated future net cash flows attributable to the 1990-1 Partnership's Proved Reserves. No adjustments will be made to the Exchange Values on account of changes in demand for or costs or prices of oil and gas that differ from the assumptions employed or other market related events after December 31, 1994, although those could affect the value of the 1990-1 Units. COMPENSATION PAID TO MANAGING GENERAL PARTNER The following table sets forth the amount of compensation paid, and cash distributions made, to the Managing General Partner and its affiliates by the Partnership for each of the last three fiscal years and the six months ended June 30, 1995.
PERIOD CASH DISTRIBUTIONS PAID COMPENSATION PAID - ------ ----------------------- ----------------- Year Ended December 31, 1994 Year Ended December 31, 1993 Year Ended December 31, 1992 Six Months Ended June 30, 1995
None of the compensation paid or cash distributions made to the Managing General Partner by the Partnership would have been paid by the Partnership during the periods set forth above if the Exchange Offer had been in effect during such period. It is anticipated that substantially all of the assets of the Partnership will be sold to Goldking immediately following consummation of the Exchange Offer. If such sale is consummated, Benton will receive cash proceeds of approximately $930,865 for the sale of the working interest in the Umbrella Point Field as of June 30, 1995, and subject to adjustments. If all Investors in the Partnership elect to receive cash in lieu of Common Stock in connection with the Exchange, Benton will receive no cash proceeds from the sale. 14 302 CASH DISTRIBUTIONS TO INVESTORS The following table sets forth the cash distributions paid to Investors for during each of the years in the five year period ended December 31, 1994, and during the six months ended June 30, 1995. All of the distributions represent a return of capital, unless noted.
1990 1991 1992 1993 1994 1995 - ---- ---- ---- ---- ---- ---- $0 $500 $762 $400 $66 $0
For additional financial information concerning the Partnership and Benton, see "Information Concerning the 1990-1 Partnership - Selected Historical Financial Data" and "Unaudited Pro Forma Financial Information" contained in the Prospectus. 15 303 PROSPECTUS SUPPLEMENT 1991-1 PARTNERSHIP SUBJECT TO COMPLETION DATED OCTOBER 3, 1995 EXCHANGE OFFER OF AN AGGREGATE OF 26,772 SHARES OF COMMON STOCK AND WARRANTS TO PURCHASE AN AGGREGATE OF 108,500 SHARES OF COMMON STOCK FOR PARTNERSHIP UNITS IN BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P. (281.8182 PARTNERSHIP UNITS) ------------- EXCHANGE RATIO: 95 SHARES OF COMMON STOCK AND 385 WARRANTS PER 1991-1 PARTNERSHIP UNIT This Supplement accompanies a Prospectus (the "Prospectus") and is being furnished to the Investors ("Investors") in the Benton Oil & Gas Combination Partnership 1991-1, L.P., a California limited partnership (the "Partnership") in connection with the offer by Benton Oil and Gas Company, a Delaware corporation and the managing general partner of the Partnership ("Benton," or "Company," or "Managing General Partner") to exchange shares of Common Stock, $.01 par value of Benton ("Common Stock") and Warrants ("Warrants") to purchase shares of Common Stock of Benton (the "Exchange Offer") for all of the right, title and interest to units of Partnership interest in the Partnerships ("Partnership Units") held by Investors, at the exchange rate outlined below. Benton has offered to exchange shares of Common Stock and Warrants for all of the right, title and interest to units of partnership interest in the Benton Oil & Gas Combination Partnership 1989-1, L.P. (the "1989-1 Partnership") and the Benton Oil & Gas Combination Partnership 1990-1, L.P. (the "1990-1 Partnership") on the terms and at the exchange rates set forth in the Prospectus. A separate supplement has been prepared for each of the Partnerships. THE EFFECTS OF THE EXCHANGE OFFER MAY BE DIFFERENT FOR INVESTORS IN THE VARIOUS PARTNERSHIPS. UPON RECEIPT OF A WRITTEN REQUEST BY AN INVESTOR OR HIS REPRESENTATIVE WHO HAS BEEN DESIGNATED IN WRITING, A COPY OF ANY SUPPLEMENT WILL BE TRANSMITTED PROMPTLY, WITHOUT CHARGE, BY BENTON. ANY SUCH REQUEST SHOULD BE FORWARDED TO THE ATTENTION OF TONI L. JACKSON, BENTON OIL AND GAS COMPANY, 1145 EUGENIA PLACE, SUITE 200, CARPENTERIA, CALIFORNIA 93013. Benton is offering to exchange shares of Common Stock and Warrants to owners of Partnership Units in the 1991-1 Partnership (the "1991-1 Units") on the basis of $5,000.00 original investment on the terms and in the amounts set forth herein. The Warrants to be issued in connection with the Exchange Offer are exercisable at a price of $11.00 per share and will expire three years form the date of issuance. For detailed information regarding the determination of the Total Exchange Values for each of the Partnerships, see "Determination of 1 304 Exchange Value." On October 2, 1995, the last reported sales price of the Common Stock, as reported on NASDAQ National Market, was $11.13. In connection with the Exchange Offer, Benton is submitting a Proposal to Investors in the Partnership to amend the Partnership Agreement to provide for the transfer of all of the assets and liabilities of the Partnership to Benton as of the December 31, 1994 Effective Date in exchange for Common Stock and Warrants in the amounts set forth herein and the pro rata distribution of such consideration in liquidation of the Partnership. Each Investor who tenders his Partnership Units pursuant to the Exchange Offer will, by that tender, consent to the Proposal. ADOPTION OF THE PROPOSAL REQUIRES THE CONSENT OF INVESTORS OF THE PARTNERSHIP HOLDING 75% OF THE PARTNERSHIP UNITS. IF INVESTORS IN THE PARTNERSHIP HOLDING NOT LESS THAN 75% OF THE PARTNERSHIP UNITS ACCEPT THE EXCHANGE OFFER AND CONSENT TO THE PROPOSAL, ALL NON-DISSENTING HOLDERS OF UNITS IN THE PARTNERSHIP WILL BE BOUND BY THE TERMS OF THE EXCHANGE AND PROPOSAL AND WILL RECEIVE THE NUMBER OF SHARES OF COMMON STOCK AND WARRANTS DESCRIBED HEREIN. A SIMILAR EXCHANGE OFFER AND PROPOSAL IS BEING OFFERED TO INVESTORS IN TWO OTHER PARTNERSHIPS. EACH OF THE EXCHANGE OFFERS TO THE PARTNERSHIPS IS INDEPENDENT OF THE EXCHANGE OFFER TO THE OTHER PARTNERSHIPS. THE EXCHANGE WILL ONLY BE CONSUMMATED FOR THE PARTNERSHIP IF THE PROPOSAL HAS BEEN APPROVED BY THE INVESTORS. BENTON OIL AND GAS COMPANY, IN ADDITION TO BEING MANAGING GENERAL PARTNER OF THE THREE PARTNERSHIPS, OWNS 2.812 1991-1 UNITS AND WILL VOTE SUCH UNITS THE SAME AS A MAJORITY OF INVESTORS VOTE THEIR UNITS. INVESTORS WILL RECEIVE THE CONSIDERATION SET FORTH HEREIN, AND THE RESPECTIVE PARTNERSHIP WILL BE DISSOLVED. ASSUMING CONSUMMATION OF THE EXCHANGE OFFER, ALL OF THE INVESTORS IN THE PARTNERSHIP, WHETHER OR NOT THEY TENDER THEIR UNITS AND THUS VOTE IN FAVOR OF THE PROPOSAL, WILL RECEIVE THE SAME NUMBER OF SHARES OF COMMON STOCK AND WARRANTS AS THEY WOULD HAVE RECEIVED HAD THEY TENDERED THEIR PARTNERSHIP UNITS AND THE PARTNERSHIP WILL BE DISSOLVED. THE EXCHANGE OFFER INVOLVES VARIOUS RISKS THAT SHOULD BE CONSIDERED BY INVESTORS. SEE "RISK FACTORS AND MATERIAL CONSIDERATIONS," BEGINNING ON PAGE 4 OF THIS SUPPLEMENT. IN PARTICULAR, INVESTORS SHOULD CONSIDER THE FOLLOWING FACTORS: - INVESTORS HAD RECEIVED CASH DISTRIBUTIONS FROM THE PARTNERSHIP, BUT WILL RECEIVE NO CASH DISTRIBUTIONS OR DIVIDENDS IN THE FORESEEABLE FUTURE FROM BENTON. - THE MARKET PRICE OF THE COMMON STOCK COULD DECLINE BELOW THE MARKET PRICE USED FOR CALCULATION OF THE EXCHANGE RATES, EXPOSING INVESTORS TO A REDUCED RETURN ON THEIR INVESTMENT. - THE EXCHANGE VALUE OF THE PARTNERSHIP UNITS WAS DETERMINED BY BENTON, WHICH HAS INHERENT CONFLICTS OF INTEREST, AND MAY NOT REFLECT THE VALUE OF THE NET ASSETS OF THE PARTNERSHIP IF SOLD TO AN UNAFFILIATED THIRD PARTY IN AN ARM'S LENGTH TRANSACTION. - BENTON HAS ATTRIBUTED A PRESENT VALUE TO THE WARRANTS, USING THE BLACK-SCHOLES OPTION PRICING MODEL. HOWEVER, THE ACTUAL VALUE, IF ANY, A HOLDER MAY REALIZE 2 305 FROM THE WARRANTS WILL DEPEND ON THE EXCESS OF THE MARKET PRICE OF THE COMMON STOCK OVER THE EXERCISE PRICE OF THE WARRANT ON THE DATE THE WARRANT IS EXERCISED. - BENTON'S DETERMINATIONS OF THE EXCHANGE VALUES WERE BASED PRIMARILY ON THE ESTIMATED PRESENT VALUE OF THE PARTNERSHIP'S PROVED OIL AND GAS RESERVES, WHICH INVOLVES MANY UNCERTAINTIES AND COULD RESULT IN AN UNDERVALUATION OF PARTNERSHIP UNITS. ALTHOUGH SUPPORTED BY AN INDEPENDENT OFFER FOR THE PURCHASE OF SUBSTANTIALLY ALL OF THE ASSETS OF THE PARTNERSHIP, THERE CAN BE NO ASSURANCE THAT THE EXCHANGE VALUE REPRESENTS THE VALUE THE PARTNERSHIP COULD RECEIVE IN THE SALE OF THE ASSETS OF THE PARTNERSHIP. - THE ALTERNATIVES OF CONTINUING THE PARTNERSHIP OR LIQUIDATING ITS ASSETS COULD POTENTIALLY BE MORE BENEFICIAL TO INVESTORS THAN THE EXCHANGE OFFER. - NO INDEPENDENT REPRESENTATIVE WAS ENGAGED TO REPRESENT THE UNAFFILIATED INVESTORS IN NEGOTIATING THE TERMS OF THE EXCHANGE OFFER, WHICH MAY BE INFERIOR TO THOSE THAT COULD HAVE BEEN NEGOTIATED BY AN INDEPENDENT REPRESENTATIVE. - INVESTORS HAVE NO DISSENTER'S RIGHTS IN THE EXCHANGE OFFER, OTHER THAN LIMITED DISSENTERS' RIGHTS FOR CALIFORNIA RESIDENTS, AND THEREFORE CANNOT ELECT TO RECEIVE CASH FOR THEIR PARTNERSHIP UNITS. - OWNERSHIP OF COMMON STOCK MAY INVOLVE GREATER RISK THAN AN INVESTMENT IN THE PARTNERSHIP UNITS BECAUSE OF BENTON'S BROADER OPERATIONS, INCLUDING FOREIGN OPERATIONS, AND ITS USE OF DEBT TO FINANCE ONGOING OPERATIONS. - FUTURE EQUITY OFFERINGS BY BENTON COULD POTENTIALLY BE DILUTIVE TO INVESTORS HOLDING COMMON STOCK OR WARRANTS. The Exchange may be withdrawn at any time prior to its scheduled expiration date if Benton reasonably determines that a material change affecting the Partnership or the Company has occurred. THE EXCHANGE WILL ONLY BE CONSUMMATED IF THE PROPOSAL HAS BEEN APPROVED BY THE INVESTORS. The assets and liabilities of the Partnership, if the Proposal is approved and the Exchange Offer is accepted, will be transferred to Benton effective as of December 31, 1994 (the "Effective Date"). THE EXCHANGE OFFER EXPIRES AT 5:00 P.M. PACIFIC TIME ON ____________, 1995 UNLESS EXTENDED. ------------------------------------------------------ THE SHARES OF COMMON STOCK AND WARRANTS TO BE ISSUED IN CONNECTION WITH THE EXCHANGE HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. THE DATE OF THIS SUPPLEMENT IS ____________, 1995. 3 306 The information contained in this Supplement is being provided to Investors in the Benton Oil & Gas Combination Partnership 1991-1, L.P. (the "Partnership"). The information contained in this Supplement is not intended to be a complete description of all matters covered in the Prospectus, and Investors are encouraged to review all information set forth in the Prospectus. RISK FACTORS AND MATERIAL CONSIDERATIONS The Exchange Offer. In addition to the information included in this Supplement and the Prospectus, the Investors should carefully consider the following factors in determining whether to accept the Exchange Offer and consent to the Proposal. The risk factors summarized below are described in further detail elsewhere in the Prospectus at "Risk Factors and Material Considerations," beginning at page 34. Lack of Arm's Length Negotiations and Uncertainties in the Method of Determining Exchange Values. The Exchange Value was determined by Benton, based in part on an offer for the purchase of substantially all of the assets of the Partnership from an unaffiliated third party (Goldking Trinity Bay Corp.), but may not reflect the actual value of the net assets of the Partnership. The primary assets of the Partnership considered by Benton when determining the Exchange Value were the proved oil and gas reserves of the Partnership (the "Proved Reserves") and the present value of associated future net cash flow as of December 31, 1994, as well as the offer to purchase the Umbrella Point Field by Goldking, described herein and in the Prospectus. There are many uncertainties inherent in estimating quantities of Proved Reserves, and the present value attributed to the Partnership's Proved Reserves may be less than the future net cash flows actually received from the Partnership's interest in its wells. In that event, the use of this valuation methodology will have resulted in an undervaluation of the Partnership Units. See "Method of Determining Exchange Values." Potential Decline in Market Price of Common Stock. Access to an active trading market by exchanging Investors may result in a relatively large number of shares of Common Stock offered for sale immediately after the Closing Date. This may tend to lower the market price for the Common Stock. Future market conditions in the oil and gas industry in general or the effect of the conditions on Benton in particular could also adversely affect the market price of the Common Stock and thus the value of the Warrants. There can be no assurance regarding the potential appreciation in the market price of the Common Stock. Any decline in the market price of the Common Stock could reduce the Investor's return on investment or increase the loss on the Investor's original investment. Potential Benefits of Alternatives to the Exchange. The alternatives to the Exchange Offer are the continuation of the Partnership or the liquidation of the Partnership's assets and distribution of the liquidation proceeds to Investors, either of which could potentially be 4 307 more beneficial to Investors than the Exchange by avoiding the risks associated with ownership of Benton Common Stock and, in the case of a liquidation of the Partnership, by providing an immediate cash return to Investors. See "Recommendation of the Managing General Partner -- Managing General Partner's Determination that Exchange Offer is Fair -- Alternatives to the Exchange" contained in the Prospectus. Lack of Independent Representatives for Investors; No Fairness Opinion. No independent representative was selected or hired to represent the interests of the Investors in negotiating the terms of the Exchange Offer. The Exchange Values and other terms of the Exchange Offer may therefore be inferior to those that could have been negotiated by an independent representative. Benton did not retain an independent third party to render an opinion regarding the fairness of the terms of the Exchange Offer to the Investors. Limited Dissenters' Rights. Investors who are California residents and who oppose the Proposal will have limited dissenters' rights. Other Investors who oppose the Proposal will have no dissenters' rights or appraisal rights, and therefore, no option to receive cash based on a separate appraisal of the Partnership assets in lieu of the Common Stock and Warrants based on the Exchange Values determined by Benton. The Managing General Partner could have provided all Investors with appraisal rights in structuring the Exchange Offer but elected not to do so, primarily because such rights are not provided for in the Partnership Agreements. The absence of these rights limit the options that would otherwise be available to Investors opposing the Exchange Offer. Effect of Dissenters' Rights on California Investors. Investors residing in California will be afforded limited dissenters' rights in accordance with the requirements for roll-up transactions under the California Code. By voting against the Proposal, Investors in the State of California will be deemed to exercise their dissenters' rights and will receive the number of shares of Common Stock and Warrants equal to the Exchange Value of their interests divided by the closing price of the Common Stock on the NASDAQ - National Market during the twenty days immediately after the Closing Date. If that average price is lower than the Exchange Price, dissenting California Investors will receive more shares of Common Stock than they would otherwise receive in the Exchange Offer. If, however, the average price is higher than the Exchange Price, a dissenting California Investor would receive fewer shares of Common Stock and Warrants. California Investors hold a substantial portion of the interests in the Partnership, and the impact of the exercise of dissenters' rights could materially increase the number of shares of Common Stock issued by Benton in connection with the Exchange Offer. Conflicts of Interest of Benton. Benton is the Managing General Partner of the Partnership and its determination of the Exchange Value involves an inherent conflict of interest. As Managing General Partner, Benton owes fiduciary duties to the Investors in the Partnership. In addition, it owes a duty to its stockholders. While Benton believes that it has fulfilled these obligations in its determination of the Exchange Value, which is supported, in part, by a reserve report audited by an independent petroleum engineer, no degree of objectivity or professional competence can eliminate the inherent conflict of 5 308 interest. See "Recommendations of the Managing General Partner -- Fiduciary Duties of Benton" contained in the Prospectus. Benton Dividend Policy. Benton's policy is to retain its earnings to support the growth of Benton's business. Accordingly, the Board of Directors of Benton has never declared cash dividends on its Common Stock and does not plan to do so in the foreseeable future. Furthermore, the terms of Benton's debt agreements prohibit Benton from paying cash dividends on its Common Stock. Thus, upon consummation of the Exchange, Investors will no longer receive cash distributions and it is unlikely that cash dividends will be paid on the Benton Common Stock at any time in the foreseeable future. No Fractional Shares. No fractional shares will be issued in connection with the Exchange Offer. An Investor who would otherwise be entitled to a fractional share of Common Stock will be paid cash in lieu of such fractional shares. Warrants issued in connection with the Exchange Offer will be rounded to the nearest whole number of Warrants and no fractional interest will be issued. Risks Associated with Ownership of Common Stock of Benton. In addition to the information included in this Supplement and the Prospectus, the Investors should carefully consider the following factors related to Benton in determining whether to accept the Exchange Offer. The risk factors summarized below are described in further detail in the Prospectus at "Risk Factors and Material Considerations." Losses From Benton's Operations. The historical financial data for Benton reflects net losses and decreased revenues for the years ended December 31, 1992 and 1993. Benton's ability to maintain its financing arrangements, produce its oil and gas reserves and service its debt obligations would be adversely affected by a lack of profitability. Foreign Operations. Almost all of Benton's oil and gas revenues and Proved Reserves are attributable to its operations in Venezuela and Russia. Benton's Venezuelan and Russian operations are subject to political, economic and other uncertainties inherent in the development of foreign properties. Properties Under Development. A substantial amount of Benton's Proved Reserves are undeveloped and require development activities and/or are proved developed behind-pipe or shut-in and require additional development activities. As a result, Benton will require substantial capital expenditures to develop all of its Proved Reserves. Engineers' Estimates of Reserves and Future Net Revenue. This Prospectus contains, and incorporates by reference, estimates of Benton's and the Partnerships' oil and gas reserves and future net revenues therefrom. Estimates of commercially recoverable oil and gas and the future net cash flows derived therefrom are based upon a number of variable factors and assumptions. Estimates to some degree are speculative and estimates of the commercially recoverable reserves of oil and natural gas, and the future net cash flows therefrom, prepared by different engineers or by the same engineer at different 6 309 times, may vary substantially. The difficulty of making precise estimates is accentuated because most of Benton's Proved Reserves were non-producing at December 31, 1994. Development of Additional Reserves. Benton's future success may also depend upon its ability to find or acquire additional oil and gas reserves that are economically recoverable. There can be no assurance that Benton will be able to discover additional commercial quantities of oil and gas, or that Benton will be able to continue to acquire interests in underdeveloped oil and gas fields and enhance production and reserves therefrom. Partnership Litigation. Certain limited partners in Benton's oil and gas limited partnerships, including the Partnerships that are the subject of this Exchange Offer, filed suit against Benton and others alleging breaches of contract, fiduciary duty and fraud. This suit has been voluntarily dismissed, subject to an agreement among the parties to arbitrate the issues and claims which were the subject of the claim. See "The Exchange Offer and Proposal -- Litigation and Related Matters." In addition, Investors in partnerships which were sponsored by a third party have sued Benton on the theory that since it provided oil and gas drilling prospects to those partnerships and operated substantially all of their properties, it was responsible for alleged violations of securities laws in connection with the offer and sale of interests, contractual breach of fiduciary duty and fraud. See "The Exchange Offer and Proposal --Litigation and Related Matters." Retention and Attraction of Key Personnel. Benton depends to a large extent on the abilities and continued participation of certain key employees, the loss of whose services could have a material adverse effect on Benton's business. Regulation. The oil and gas industry is subject to broad and frequently changing regulations that could adversely affect the operations of Benton. In spite of the foregoing risks, Benton initiated and proposed the Exchange Offer and recommends adoption of the Proposal by the Partnership to enable Benton to acquire the assets and liabilities of the Partnership and to provide Investors with the potential benefits summarized in the Prospectus under the caption "Reasons for the Exchange Offer." MANAGING GENERAL PARTNER'S DETERMINATION THAT EXCHANGE OFFER IS FAIR THE MANAGING GENERAL PARTNER OF THE PARTNERSHIP HAS DETERMINED THAT THE EXCHANGE IS FAIR AND IS IN THE BEST INTERESTS OF THE PARTNERSHIP AND ITS PARTNERS AND HAS RECOMMENDED THAT THE PARTNERS OF THE PARTNERSHIP TENDER THEIR PARTNERSHIP UNITS AND CONSENT TO THE PARTNERSHIP PROPOSAL. THE EXCHANGE OFFER IS NOT CONDITIONED UPON ACCEPTANCE AND APPROVAL BY ALL OF THE PARTNERSHIPS AND THE MANAGING GENERAL PARTNER BELIEVES THAT THE OFFER IS FAIR TO ALL 7 310 INVESTORS, REGARDLESS OF WHICH OR THE NUMBER OF PARTNERSHIPS WHICH ACCEPT THE EXCHANGE OFFER FOR THE REASONS SET FORTH BELOW. General. The Managing General Partner has analyzed the terms of the Exchange Offer, the consideration and value offered to the Investors in exchange for their Partnership Units and the value of consideration an Investor could expect to receive under various alternatives to the Exchange. In determining that the Exchange Offer is fair to the Investors, the Managing General Partner considered that the Investors who do not accept the Exchange Offer or who do not elect to receive cash in lieu of Benton Common Stock will receive Common Stock and Warrants of Benton, and could receive cash if the Partnership was continued or liquidated. However, the Managing General Partner believes that because an Investor may elect to receive cash in lieu of Common Stock if the sale to Goldking is consummated, the Investors will receive consideration in excess of the alternatives to the Exchange if the Exchange Offer is accepted. The Managing General Partner's analysis of the consideration an Investor could receive under the alternatives to the Exchange are discussed below. The Managing General Partner believes that those Investors who receive Benton Common Stock will have access to a public trading market if such Investor elects to liquidate his investment for cash. The average daily trading volume for the Benton Common Stock on the NASDAQ National Market for the 30 trading days ended September 27, 1995 was 259,000 shares. The Managing General Partner believes that since the maximum aggregate number of shares of Benton Common Stock that will be issued in the Exchange Offer for all three Partnerships is 171,880, the issuance will have no material effect on the market value of the Benton Common Stock, and may allow all Investors receiving shares of Benton Common Stock in connection with the Exchange Offer and liquidation of the Partnerships to liquidate their investment in the market. Alternatives to the Exchange. The Managing General Partner's analysis of the most probable results of continuing the Partnership indicate that, while continuing the Partnership would avoid the risks associated with the ownership of Common Stock in Benton, Investors will receive potentially greater values by participating in the Exchange than the values they would derive from this alternative. Benton estimates that continuing the 1990-1 Partnership under market and operating conditions prevailing in 1994 would likely generate decreasing annual distributions of $61 per 1991-1 Unit in 1995, $83 in 1996, $40 in 1997, and $0 in 1998. Benton estimates that the remaining economic life of the 1991-1 Partnership is 2.5 years. Benton believes that the Partnership will have no residual value in its assets at the end of the economic life of the Partnership. The Managing General Partner also believes that, while liquidating the Partnership would provide an immediate cash return and avoid the risks associated with owning Benton Common Stock, the Exchange will provide Investors with greater values than they would likely receive in liquidation of the Partnership. Benton's liquidation analysis reflects an estimated liquidation value of approximately $240,998 of the 1991 - 1 Partnership, or $855 per Unit. Benton received an independent offer from Goldking to purchase the Partnership's interest in the Umbrella Point Field (which represents 88.0% of the total Proved Reserves of the Partnership) for an estimated total purchase price in cash of $185,282 as of June 30, 1995, subject to adjustments. This 8 311 estimated purchase price would represent potential cash distributions to the Investors equal to $657 per Unit. Benton's liquidation analysis is based on the anticipated proceeds from the sale of the Umbrella Point Field to Goldking, plus working capital for the Partnership at June 30, 1995, less estimated general and administrative costs involved in liquidation of the Partnership. For purposes of determining the general and administrative costs to the Partnership, Benton estimated that general and administrative expenses would approximate the general and administrative expenses incurred by the Partnership during the year ended December 31, 1994. The following table summarizes the results of Benton's liquidation analysis in comparison to the Exchange Values for the Partnership Units determined by Benton. The table also includes valuation data derived from Benton's analysis of continuing the Partnership. Benton did not undertake its continuation analysis for the purpose of valuing the Partnership, but solely to illustrate the likelihood of decreasing distributions based on oil and gas prices at December 31, 1994. However, because SEC disclosure standards for roll up transactions require a comparison of the value of the consideration offered in the transaction with the value of the consideration estimated for each alternative to the transaction, the tables also reflect the results of extending Benton's continuation analysis for the balance of the estimated life of the Partnership's Proved Reserves, and discounting the projected stream of distributions to present value at the same 10% discount rate used in Benton's liquidation analysis to account for the timing of cash flows as well as production and concentration risks.
VALUATION METHOD TOTAL VALUE PER - ---------------- INVESTOR VALUE(1) 1991 - 1 UNIT ----------------- ------------- Exchange Value ..................................... $692,349 $2,457 Liquidation value estimated by Benton .............. 240,998 855 Value of Proved Reserves at December 31, 1994 (2) ....................................... 210,445 747 Continuation analysis by Benton assuming natural gas prices of $1.63 per Mcf and oil prices of $15.94 per Bbl(3) .................... 47,072 167
(1) The Exchange Value and liquidation value attribute no value to Managing General Partners' interests. The continuation analysis assumes continued distributions to the Managing General Partner pursuant to the terms of the Partnership Agreement. (2) Based on the Partnership's December 31, 1994 reserve report prepared by the Company and audited by Huddleston. The reserves are valued as of December 31 of each year, based on oil and gas prices as of that date. Market prices for both oil and natural gas are subject to a significant degree of variation, and this variation will effect the calculation of future net cash flows by the Partnership at any specific date. (3) The assumed natural gas and oil prices are the prices used for preparation of the Partnership's reserve report at December 31, 1994. The continuation analysis was calculated based upon Benton's estimate of the remaining economic life of the Partnership, estimated to be 2.5 years. 9 312 The actual amount that Investors would receive if the Partnership continued its operations would depend on production levels, which cannot be predicted with certainty. In addition, the actual amount that Investors would receive under either of the alternatives to the Exchange would depend on future oil and gas prices. To the extent that future prices for those commodities are materially higher or lower than the pricing assumptions made by the Managing General Partner, those fluctuations would likely have a similar effect on the operating results, distribution rates and market value of the Partnership Units, largely negating the effect of price changes on a comparison between the Exchange and either alternative of continuing the Partnership or liquidating its assets. In addition, Benton believes that liquidating the Partnership would deprive Investors of the opportunity to benefit from any future upturn in oil and gas prices. For a more detailed discussion of the bases for the Managing General Partner's determination that the Exchange Offer is fair to Investors, see "Recommendation of the Managing General Partner" contained at page 65 of the Prospectus. DETERMINATION OF EXCHANGE VALUE Components of the Exchange Value. The most significant assets considered by Benton in determining the Exchange Value of the Units were the anticipated net proceeds from the sale of the Umbrella Point Field and Proved Reserves of the Partnership. The Exchange Values represent the sum of (i) the estimated cash proceeds from the anticipated sale of Umbrella Point Field to Goldking, (ii) the estimated present value of future net cash flows from the Proved Reserves of the Partnership as of December 31, 1994, discounted at 10% per year and calculated without escalation of prices and costs, as reflected in the reserve report for the Partnership as of that date prepared by Benton and audited by Huddleston & Co., Inc., independent petroleum engineers ("Huddleston"), (iii) the tax-basis balances of equipment as of December 31, 1994 and the net book value of current assets and liabilities (reflected on the unaudited balance sheet) of the Partnership as of June 30, 1995, and (iv) the value of General Intangibles. These components represent all of the assets and liabilities of the Partnership and were determined as of the year end and June 30, 1995 to conform with the SEC reporting requirements for reserve information and unaudited financial information, respectively. Since the year-end reserve information is audited, the Exchange Values were derived from that information. In determining the Exchange Value, Benton considered the total distributions paid to date to participants in the Partnership. For the Partnership, and each of the other Partnerships, Benton assigned a Total Exchange Value to the Partnership which, based upon certain assumptions described herein, and in addition to the distributions paid to date, would provide Investors with consideration valued at 100% of their initial contribution to the Partnership. See " -- General Intangibles" for a discussion of the assumptions used by Benton. The estimated cash proceeds from the sale of the working interest in the Umbrella Point Field to Goldking and the value of other tangible assets of the Partnership are attributable to shares of Benton Common Stock, or cash if the Investor makes the cash election described herein. The remaining dollar value is referred to herein as General Intangibles. Pursuant to the Exchange Offer, value attributed to General Intangibles will be distributed to Investors in the form of Warrants. 10 313 The number of shares of Common Stock and Warrants to be issued pursuant to the Exchange Offer has been determined relative to a Total Exchange Value assigned to the Partnership aggregating $692,349. The number of shares of Common Stock offered in exchange for Partnership Units has been determined by dividing the Exchange Value of the tangible assets by a Common Stock price of $11.00, subject to rounding adjustments. The Common Stock price is based upon the average closing price of the Common Stock on the NASDAQ National Market for the 20 trading days immediately preceding September 12, 1995 and will not reflect any subsequent increase or decrease in the market price for the Common Stock after that date, except to the extent required by dissenters' rights for California residents. The number of Warrants to be assigned to the Partnership was determined by dividing the estimated value of the General Intangibles of the Partnership by the estimated present value per Warrant. Benton has used the Black-Scholes option pricing model to calculate the present value of the Warrants, which yielded a value of $3.64 per Warrant. The Warrants are exercisable at a price of $11.00 per share and will expire three years from the date of issuance. The following unaudited table sets forth (i) the components of the Exchange Values of the Units and (ii) the Exchange Value per Unit held by an Investor. This information was compiled by Benton from the Partnership's reserve report as of December 31, 1994 (a summary of which is included in Exhibit B to this Prospectus) and the Partnership's tax records for the year ended December 31, 1994 and financial statements for the six months ended June 30, 1995. The following table sets forth each of the Exchange Value components, estimated on an interim basis. EXCHANGE VALUE COMPONENTS Estimated Cash Proceeds - Umbrella Point Field ................. $185,282 Present value of Proved Reserves of other properties (SEC PV 10) 23,856 Cash ........................................................... 82,547 Intercompany receivable -- Benton Oil and Gas Company .......... 3,169 Value of equipment ............................................. 2,555 General Intangibles ............................................ 394,940 -------- Exchange Value ................................................. $692,349 ========
Anticipated Sales Proceeds. In July 1995, Benton, on behalf of the Partnership, and Goldking executed an agreement whereby Goldking will purchase a 2.83% working interest in the Umbrella Point Field from the Partnership, subject to approval of the participants of the Partnership. Upon execution of the agreement, Goldking made an earnest money deposit in favor of the Partnership in the amount of $2,824, included as current assets of the Partnership (the "Deposit"). Subject to closing adjustments and excluding the Deposit, as of June 30, 1995 the Partnership's estimated cash proceeds from the sale would be $185,282, or $657 per 1991 - 1 Unit. Benton has made this Exchange Offer in contemplation of such sale, but the Exchange Offer is not conditioned upon consummation of such sale. 11 314 Proved Reserves. The calculation of the present value of the 1991 - 1 Partnership's Proved Reserves for the purpose of determining the Exchange Value complies with the rules and regulations of the SEC relating to the calculation of the present value of future net cash flows determined as of December 31, 1994 attributable to proved oil and gas reserves for disclosure and financial reporting purposes. The regulations governing these reserves do not permit the use of escalated prices and costs except in accordance with existing contractual arrangements, and the resulting SEC PV 10 calculations may overestimate or underestimate the actual future cash flows from the production and sale of oil and gas and, consequently, the present value thereof. The gross quantities of Proved Reserves attributable to the 1991 - 1 Partnership's interest in its wells, together with the estimated present value of those reserves, were estimated on an SEC PV 10 basis as of December 31, 1994 in a reserve report prepared by Benton and audited by Huddleston. A summary of the report and a copy of the audit letter, setting forth the criteria and assumptions used in evaluating the 1991 - 1 Partnership's Proved Reserves, are included in Exhibit B. There are numerous uncertainties inherent in estimating quantities of Proved Reserves. Huddleston audited the data and computations used by Benton's petroleum engineer in their evaluation of the total Proved Reserves attributable to all of the wells in which the 1991 - 1 Partnership had an interest as of December 31, 1994. Estimates by other independent petroleum engineers could vary from Benton's estimates and could result in higher or lower valuations. The estimates of the 1991 - 1 Partnership's future gross revenues attributable to its estimated Proved Reserves as of December 31, 1994 were calculated based on natural gas and crude oil prices in effect on that date. Those prices had a weighted average of $1.63 per Mcf for natural gas and $15.94 per Bbl for oil. Future operating and development costs were based on the 1991 - 1 Partnership's operating and development costs as of December 31, 1994 and were used without escalation. Future severance (production) and ad valorem (property) taxes were calculated using rates prevailing at December 31, 1994. The estimated future gross revenues, future operating and development costs and production taxes were allocated to the 1991 - 1 Partnership in accordance with its interest in oil and gas properties, taking into account applicable reversionary and overriding royalty interests. The present values of the estimated net cash flows attributable to the 1991 - 1 Partnership's Proved Reserves of other properties were calculated by discounting the future net cash flows to present value at the rate of 10% per year, as prescribed by SEC regulations covering reserve reporting for financial disclosure purposes. The discount factor is intended to reflect the timing of future net cash flows. No further discount or risk adjustment was applied. Present value, regardless of the discount rate used, is materially affected by assumptions as to timing of future production, which may prove to have been inaccurate. Other Assets and Liabilities. The tax-basis balances of the 1991 - 1 Partnership's equipment, excluding Umbrella Point Field equipment, aggregated $2,555 at December 31, 12 315 1994, and the net book value of its current assets and liabilities as of June 30, 1995 reflect a balance of $85,716, excluding property held for sale. The equipment value and current net assets are based upon the 1991 - 1 Partnership's 1994 year-end tax accounting records and June 30, 1995 unaudited financial statements, respectively, maintained in accordance with the applicable provisions of the 1991 - 1 Partnership Agreement. Benton believes that valuing the 1991 - 1 Partnership's equipment (comprised of oil and gas production and transportation facilities) at its tax- basis balances is favorable to the sellers of the producing properties since many purchasers in transactions evaluated by Benton, as part of its on-going involvement in the production area, allocate nominal value to well equipment on the theory that its salvage value at the end of the commercial lives of acquired wells will approximate the cost of plugging and abandoning the wells. Benton believes that the original cost of the equipment less the deductions computed through 1994 year end for tax purposes represents a reasonable approximation of the fair market value of the equipment to Benton. Benton also believes that valuing the current assets and liabilities of the 1991 - 1 Partnership (comprised of cash and intercompany receivable) at their book value as of June 30, 1995 is appropriate to reflect the fair market value of these items, which are expected to be collected and paid to Benton, to the extent outstanding, in the stated amounts reflected in the 1991 - 1 Partnership's unaudited balance sheet as of that date. General Intangibles. In determining the value attributed to General Intangibles, Benton evaluated the success to date of the 1991 - 1 Partnership, total consideration paid to date to the participants and the value to Benton of dissolving and liquidation the 1991 - 1 Partnership so that Benton can focus on its current operations and reduce the administrative burdens associated with operating the Partnership. Based upon Benton's evaluation of historical administrative costs for the 1991-1 Partnership, Benton estimates that the administrative costs for operating the Partnership will be approximately $30,000 per year. From inception through September 1995, the 1991-1 Partnership has made cash distributions to participants aggregating $338,182, or $1,200 per 1991 - 1 Unit. In forming the Partnership, Benton sold an aggregate of $1,409,091 in 1991-1 Units. Benton acknowledges the concerns raised by the Investors in the 1991 - 1 Partnership with regard to operations of the Partnership, the lack of success and thus the disappointing returns on investment by the Investors. Because many of the Investors are or were stockholders of Benton, Benton desires to maintain a good relationship with these stockholders, many of whom have been strong supporters of Benton from inception, and Benton desires to avoid future claims against it by participants relating to the management of the Partnership. See "The Exchange Offer and Proposal -- Litigation and Related Matters." Assuming that the Investor in the 1991 - 1 Partnership elects to hold his or her shares of Common Stock and exercises his or her Warrants at the end of the three-year term, and the market price of the Common Stock is at or above approximately $16.75 per share, Benton believes that the Investors in the 1991 - 1 Partnership, will have received consideration in the form of cash distributions, Common Stock and Warrants in excess of the initial investment in the 1991 - 1 Partnership, without regard to any tax benefits received by the participants. On October 2, 1995, the last sales price of the Benton Common Stock on NASDAQ National Market was $11.13 per share. The assumed market price of the Common Stock of $16.75 per share discussed above represents a 34% increase in the market value of the Benton Common Stock during the three year term of the Warrants. There can be no assurance that the market price 13 316 of the Benton Common Stock will increase or that such price will be achieved. The value of the General Intangibles of the Partnership is not subject to valuation by third parties since the General Intangibles do not represent actual assets of the Partnership. Benton believes that the participants in the Partnership will not receive any value for the General Intangibles in any alternative to the Exchange. Subsequent Adjustments. The Exchange Values will not be adjusted to reflect changes after December 31, 1994 in the present value of the estimated future net cash flows attributable to the 1991 - 1 Partnership's Proved Reserves. No adjustments will be made to the Exchange Values on account of changes in demand for or costs or prices of oil and gas that differ from the assumptions employed or other market related events after December 31, 1994, although those could affect the value of the 1991 - 1 Units. COMPENSATION PAID TO MANAGING GENERAL PARTNER The following table sets forth the amount of compensation paid, and cash distributions made, to the Managing General Partner and its affiliates by the Partnership for each of the last three fiscal years and the six months ended June 30, 1995.
PERIOD CASH DISTRIBUTIONS PAID COMPENSATION PAID - ------ ----------------------- ----------------- Year Ended December 31, 1994 Year Ended December 31, 1993 Year Ended December 31, 1992 Six Months Ended June 30, 1995
None of the compensation paid or cash distributions made to the Managing General Partner by the Partnership would have been paid by the Partnership during the periods set forth above if the Exchange Offer had been in effect during such period. It is anticipated that substantially all of the assets of the Partnership will be sold to Goldking immediately following consummation of the Exchange Offer. If such sale is consummated, Benton will receive cash proceeds of approximately $185,282 for the sale of the working interest in the Umbrella Point Field as of June 30, 1995, and subject to adjustments. If all Investors in the Partnership elect to receive cash in lieu of Common Stock in connection with the Exchange, Benton will receive no cash proceeds from the sale. CASH DISTRIBUTIONS TO INVESTORS The following table sets forth the cash distributions paid to Investors for during each of the years in the five year period ended December 31, 1994, and during the six months ended June 30, 1995. All of the distributions represent a return of capital, unless noted. 14 317
1990 1991 1992 1993 1994 1995 - ---- ---- ---- ---- ---- ---- N/A $100 $400 $400 $300 $0
For additional financial information concerning the Partnership and Benton, see "Information Concerning the 1991-1 Partnership - Selected Historical Financial Data" and "Unaudited Pro Forma Financial Information" contained in the Prospectus. 15 EX-2.1 2 EX-2.1 1 EXHIBIT 2.1 ASSET PURCHASE AGREEMENT BETWEEN BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P., A CALIFORNIA LIMITED PARTNERSHIP SELLER AND GOLDKING TRINITY BAY CORP. PURCHASER FOR THE SELLER'S INTEREST IN THE PROPERTIES KNOWN AS UMBRELLA POINT FIELD JUNE 30, 1995 2 ASSET PURCHASE AGREEMENT This ASSET PURCHASE AGREEMENT (this "Agreement") dated as of June 30, 1995 by and between Goldking Trinity Bay Corp., a Texas corporation, ("Purchaser") and Benton Oil & Gas Combination Partnership 1989-1, L.P., a California limited partnership ("Seller"); W I T N E S S E T H: WHEREAS, Seller owns the working interest and net revenue interest set forth opposite such Seller's name on Schedule 1.2.2; WHEREAS, Seller desires to sell to Purchaser the Transferred Assets, and Purchaser desires to purchase from Seller the Transferred Assets, upon the terms and subject to the conditions hereinafter set forth; and NOW, THEREFORE, in consideration of the premises and of the respective representations, warranties, covenants, agreements and conditions contained herein, the parties hereto hereby agree as follows. ARTICLE I PURCHASE AND SALE Unless defined elsewhere in this Agreement, all capitalized terms used herein shall have the respective meanings given them in Appendix A hereto, which is incorporated herein by reference and shall be deemed to be a part of this Agreement for all purposes. 1.1. CONVEYANCE AND TRANSFER OF TRANSFERRED ASSETS. Seller and Purchaser hereby agree that, at the Closing, upon the terms and subject to the conditions of this Agreement, Seller shall convey, transfer and assign to Purchaser, the Transferred Assets. For purposes of this Agreement, the term "Transferred Assets" shall mean all of each Seller's right, title and interest in certain oil and gas properties located in Galveston Bay, including all of each Seller's right, title and interest in and to the following assets: (a) All of the oil and gas leases, oil, gas and mineral leases as described in Exhibit A attached hereto and incorporated herein (collectively referred to hereinafter as the "Leases" and individually as a "Lease"), and the leasehold estates created thereby, and the fee, mineral, royalty and overriding royalty interests, net profits interests, payments out of production and other real property interests described in Exhibit A, together with each and every kind and character of right, title, claim or interest that Seller has in and to the lands covered thereby, even though the interests of Seller therein may be incorrectly described, stated or limited on Exhibit A (collectively the "Properties", or singularly, a "Property"), together with all of each Seller's right, title and interest in and to all the property and rights incident thereto, including without limitation all of Seller's right, title and interest in and to: (i) the rights, privileges, benefits and powers conferred upon the holder of any Property with respect to the use and occupation of the surface of, and the subsurface depths under, the land covered by such Property that may be necessary, convenient or incidental to the possession and enjoyment of such Property; 1 3 (ii) the rights in any pooled, communitized or unitized acreage included in whole or in part in any Property, including all production from the unit, pool or communitized area allocated to any such Property, and all interests in any wells within the unit, pool or communitized area allocated to such Property, whether such unit or pool production comes from wells located within or without the areas covered by a Property; and (iii) all tenements, hereditaments and appurtenances belonging to such Properties; (b) All of each Seller's right, title and interest in and to the rights-of-way, easements, servitudes, permits, licenses, franchises, certificates of public convenience and necessity and similar rights and privileges, and other rights and interests in land primarily owned or used in connection with the Properties; (c) All of each Seller's right, title and interest in and to all real, personal and mixed property and fixtures located at the Closing on the Properties or the aforesaid rights-of-way, easements and other related properties, or primarily used or held for use in connection with the ownership, management, development, exploration or operation of the Transferred Assets, including without limitation all of each Seller's right, title and interest in and to all wells, well equipment, platforms, pipes, valves, boilers, compressors, separators, heaters, dehydrators, gauges, meters and other measuring equipment, regulators, extractors, communication equipment, gas gathering systems, casing, tubing, pipelines, power lines, fuel lines, generators, pumps, motors, buildings, storage tanks and facilities, improvements, fittings, machinery, equipment (including, without limitation, personal computers and related peripheral equipment located in the field and software that is legally transferable without cost), supplies, spare parts, materials and inventories, other than inventories of Hydrocarbons in storage tanks or other facilities above the pipeline connection to each such storage tank or facility, and in gas pipelines downstream from the delivery point sales meters on such pipelines existing as of the Effective Time; (d) All of each Seller's right, title and interest in and to all contracts, agreements, leases, and/or other arrangements, presently owned or acquired as a result of any agreement in existence prior to the Closing, including all causes of action pursuant thereto, to the extent used in connection with the ownership, management, development, exploration or operation of the Transferred Assets, including without limitation, all gas purchase and sale agreements, crude purchase and sale agreements, natural gas liquids purchase and sale agreements, farmin or farmout agreements, exchange agreements, bottom hole agreements, dry hole agreements, acreage contribution agreements, support agreements, seismic agreements, exploration agreements, joint venture agreements, operating agreements, unit agreements, pooling and communitization agreements, orders or declarations, balancing agreements, gas and natural gas liquids processing agreements, gathering and transportation agreements, construction and operation agreements, options, liens, security interests, vendor financing agreements, surface leases, subleases and leases of equipment or facilities to the extent used or primarily useful in connection with the ownership, management, development, exploration or operation of the Transferred Assets and reasonably separable from Seller's other material rights in the contracts not used in connection with the Transferred Assets; provided, however, that no insurance 2 4 contract or other insurance arrangement shall be included in the Transferred Assets (collectively, the "Contracts"); (e) All of each Seller's right, title and interest in and to all Hydrocarbons produced from or attributable to, the Properties and proceeds attributable thereto, at and after the Effective Time (subject to the provision of Section 1.3); provided, however, that all Hydrocarbons in storage tanks and other facilities above the pipeline connection to each such storage tank or facility, or in gas pipelines downstream from the delivery point sale meters on such pipelines at the Effective Time, shall remain the property of Seller; and (f) All of each Seller's right, title and interest in and to all property and rights incident or attributable to the foregoing interests, including, without limitation all of each Seller's right, title and interest in and to: (i) subject to the limitations of Section 13.2.8, originals (or, to the extent that originals are not available, copies) of all books, records, files, contracts, muniments of title, reports, surveys and similar documents or materials, including computer tapes, disks and data with respect to any of the foregoing records, that relate to the foregoing interests, including without limitation, the purchase, exchange, operation, administration, sale or marketing thereof, or that constitute evidence of ownership thereof, to the extent such records are reasonably separable from Seller's corporate records, and excluding work product of Seller's legal counsel (other than title opinions) and documents relating to the negotiation and consummation of the transactions contemplated by this Agreement (collectively, the "Records"); (ii) (A) the proprietary geological, geophysical and seismic data, materials and information (the "Proprietary Data"), (B) the non-proprietary geological, geophysical and seismic data, materials and information the transfer of which is not prohibited by any copyright or validly existing third party agreement, that is transferable to Purchaser without payment of a transfer fee or other consideration, (C) the maps, interpretations, records and other technical information related to or based upon the Proprietary Data and not related to or based upon the Non-Proprietary Data (the "Proprietary Information") and (D) the maps, interpretations, records and other technical information related to or based upon any combination of the Proprietary Data and the Non-Proprietary Data (the "Combined Information" and collectively, the "Evaluation Data"); and (iii) all division orders, purchase orders, invoices, storage or warehouse receipts, bills of lading and certificates of title to the extent the same are attributable or relate to any of the Transferred Assets, and all documents, instruments, general intangibles and chattel paper primarily related to any of the Transferred Assets (other than the bonds, letters of credit and guarantees posted with governmental agencies, which are expressly reserved by Seller) and all estimated prepayments of royalty obligations of Seller with any federal or state authorities that are directly related to the Transferred Assets and that are transferable to Purchaser; 3 5 provided, however, that the Transferred Assets shall not include (i) any rights and causes of action by Seller to receive amounts (or rights to production from the Properties prior to the Effective Time) pursuant to the Retained Liabilities and (ii) rights and causes of action with respect to the Lawsuits and the facts and circumstances giving rise to such Lawsuits as retained by Seller and more particularly described in Section 14. 1.2. PURCHASE PRICE AND PURCHASE PRICE ALLOCATION. 1.2.1. PURCHASE PRICE. The aggregate purchase price (the "Purchase Price") for the Transferred Assets shall be THREE HUNDRED SEVENTY-SEVEN THOUSAND SIXTY-TWO DOLLARS ($377,062)) subject to adjustments as set forth in Section 1.3., of which FOUR THOUSAND NINE HUNDRED TWENTY-NINE DOLLARS ($4,929) ("Initial Payment") shall be paid to the Seller in immediately available funds upon delivery to Purchaser by Seller of counterparts of this Agreement executed by Seller. At the Closing, the Purchase Price, less the amount of the Initial Payment (the "Cash at Closing") and as adjusted as provided in the Purchase Price Adjustment Certificate described in Section 1.3.2, shall be paid to Seller by wire transfer in federal or otherwise immediately available funds. Simultaneously therewith, Seller shall execute and deliver, effective as of the Effective Time, the Instruments of Transfer. 1.2.2. PURCHASE PRICE ALLOCATION. The Purchase Price shall be allocated among the types and classes of assets constituting the Transferred Assets as set forth on a schedule to be provided by Purchaser and Seller at Closing. 1.3. ADJUSTMENTS TO PURCHASE PRICE. 1.3.1. ADJUSTMENTS. In addition to any adjustments pursuant to Article VI, the Cash at Closing shall be adjusted as follows: (i) The Cash at Closing shall be increased by the following: (a) An agreed upon amount representing the value of all merchantable oil in storage above the pipeline connection at the Effective Time that is credited to the Properties; (b) Solely to the extent related to the Transferred Assets, the amount of (I) all actual direct operating expenditures, (2) all capital expenditures and (3) all costs and expenses that are incurred by Seller in connection with, or are otherwise allocable to, the operation of the Transferred Assets under the terms of the joint operating agreement during the period of time after the Effective Time; (c) The amount of any Taxes that have been paid by Seller on or prior to the Closing that are attributable to the time after the Effective Time and for which Purchaser is liable pursuant to Article VIII. (ii) The Cash at Closing shall be decreased by the following: 4 6 (a) The proceeds that are received by, or payable to, Seller or any other person and that are attributable to the operation of the Transferred Assets for the period of time between the Effective Time and the Closing; and (b) Any amount agreed upon by Purchaser and Seller as the value of any Title Defects, less any amount agreed upon by Purchasers and Seller as the value of any Title Benefits. 1.3.2. CLOSING ESTIMATE. At least three (3) business days prior to the Closing Date, Seller on behalf of Seller, shall estimate the Purchase Price Adjustment Amount and deliver to Purchaser a certificate of an officer of Seller setting forth in reasonable detail the calculation thereof. The Cash at Closing shall be adjusted as set forth in such certificate. The Purchase Price Adjustment Certificate shall include a computation of any reduction in the Purchase Price caused by the failure of one or more Seller's to deliver on the Closing Date their respective interests in the Transferred Assets. 1.3.3. PURCHASE PRICE ADJUSTMENT CERTIFICATE. As soon as reasonably practicable, and in any event within sixty (60) days following the Closing Date, Seller shall deliver to Purchaser the Purchase Price Adjustment Certificate. Within thirty (30) days after delivery of the Purchase Price Adjustment Certificate, Purchaser shall notify Seller on behalf of Seller, whether Purchaser agrees or disagrees with the determination of the Purchase Price Adjustment Amount set forth in the Purchase Price Adjustment Certificate. If Purchaser disagrees with such determination, representatives of Purchaser and Seller shall meet and endeavor to resolve their differences regarding the determination of the Purchase Price Adjustment Amount. If the representatives of Purchaser and Seller are unable to agree upon such determination of the Purchase Price Adjustment Amount within twenty (20) business days after Purchaser's receipt of such notification, Seller shall select an independent accounting firm from a list of three (3) such firms provided by Purchaser, which firm shall audit the Purchase Price Adjustment Certificate and determine the Purchase Price Adjustment Amount. The decision of such independent accounting firm shall be binding on Seller and Purchaser, and the fees and expenses of such independent accounting firm shall be borne one-half by Seller and one-half by Purchaser. 1.3.4. PAYMENT OF PURCHASE PRICE ADJUSTMENT AMOUNT. If the Purchase Price Adjustment Amount as finally determined pursuant to Section 1.3.3 is a smaller upward adjustment or a larger downward adjustment than that estimated pursuant to Section 1.3.2, Seller shall pay to Purchaser the amount of such excess plus interest thereon at the Agreed Interest Rate from (and including) the Closing Date to (but excluding) the date of payment. If the Purchase Price Adjustment Amount as finally determined pursuant to Section 1.3.3 is a larger upward adjustment or a smaller downward adjustment than that estimated pursuant to Section 1.3.2, Purchaser shall pay to Seller the amount of such deficiency plus interest thereon at the Agreed Interest Rate from (and including) the Closing Date to (but excluding) the date of payment. Any payments contemplated by this Section 1.3.4 shall be made by wire transfer in federal or other immediately available funds on or before the fifth business day following the final determination of the amount thereof. 1.4. RETAINED RIGHTS AND CLAIMS. Notwithstanding any provision herein to the contrary, Transferred Assets shall not include any rights or claims of Seller with respect to the facts and circumstances giving rise to those certain proceedings collectively referred to as the "Lawsuits" and filed: 5 7 In the Matter of the Libel and Petition of Exxon Corporation, as Owner of the M/V "Bobcat" and Williamson Boat Works, as Charterer of the M/V "Bobcat," her engines tackle, apparel. etc., in a cause of exoneration from or limitation of liability; C.A. No. C-91-203, United States District Court for the Southern District of Texas, Corpus Christi Division; and French Production Incorporated v. Exxon Corporation d/b/a Exxon Company USA. Williamson Boat Works and Captain B.J. Shirley; No. 91-040865, District Court of Harris County, Texas, 295th Judicial District. 1.5. LIABILITIES ASSUMED AND RETAINED. 1.5.1. ASSUMED LIABILITIES. Purchaser shall assume and agree to pay, perform and discharge in the ordinary course of business, only those liabilities, debts or obligations of Seller that are set forth below (the "Assumed Liabilities"): (i) all liabilities and obligations of or relating to the Transferred Assets accruing after the Effective Time; (ii) all liabilities and obligations that accrue after the Effective Time, pursuant to the Leases that have been properly consented to and assigned; and (iii) all liabilities and obligations that accrue after the Effective Time, pursuant to the Contracts that have been properly consented to and assigned. 1.5.2 RETAINED LIABILITIES. Except for the Assumed Liabilities, Purchaser shall not assume and Seller shall retain and agree to pay, perform and discharge in the ordinary course of business all liabilities, debts or obligations of any nature that arise out of or result from any occurrence, transaction or event occurring prior to the Closing Date relating to the operation, ownership or use of the Transferred Assets, whether accrued, absolute, contingent or otherwise, whether due or to become due, including without limitation any such liability of Seller related to the Lawsuits (the "Retained Liabilities"); provided however, that Retained Liabilities shall not include any liability accruing after the Effective Time based on the violation or alleged violation of any statute, ordinance, rule, regulation, order or other law of any state, federal, county, local or other governmental subdivision, due to any occurrence, transaction or event occurring prior to the Effective Time, which occurrence, transaction or event was not a violation of any laws existing as of the Effective Time. The Retained Liabilities shall include any liabilities with respect to the facts and circumstances giving rise to the Lawsuits. ARTICLE II THE CLOSING 2.1. CLOSING. The Closing shall take place at the offices of Purchaser, in Houston, Texas at 9:00 a.m. on December 31, 1995 or such earlier or later date as provided hereafter. 2.2. INSTRUMENTS OF TRANSFER. Seller shall execute and deliver at Closing the Bill of Sale, Conveyance and Assignment, the form of which is attached as Exhibit "B" and any other instruments of 6 8 transfer sufficient to convey to Purchaser the Transferred Assets, including without limitation the following (the "Instruments of Transfer"): (a) any personal property included in the Transferred Assets; (b) the Leases, assignment of leasehold interests; (c) the Contracts; and (d) the Properties. ARTICLE III REPRESENTATIONS AND WARRANTIES OF SELLER Seller hereby represents, warrants and covenants as follows: 3.1. ORGANIZATION AND GOOD STANDING. Seller is a partnership duly organized, validly existing and in good standing under the laws of its jurisdiction of formation and has all requisite power and authority to own and lease the properties and assets it owns and leases and to carry on its business as such business is conducted. 3.2. SUBSIDIARIES. No Seller has any Subsidiaries that own any of the Transferred Assets. 3.3. AUTHORITY; AUTHORIZATION OF AGREEMENT. Seller at closing will have all requisite power and authority to execute and deliver this Agreement, the Instruments of Transfer and each of the other agreements and documents contemplated, to consummate the transactions contemplated hereby and thereby and to perform all the terms and conditions to be performed by it. The execution and delivery of this Agreement, the Instruments of Transfer and each of the other agreements and documents contemplated, the performance of all the terms and conditions to be performed by Seller and the consummation of the transactions contemplated hereby and thereby will be duly authorized and approved by the partners of Seller. This Agreement, the Instruments of Transfer and each of the other agreements and documents contemplated, have been duly executed and delivered by each Seller and constitutes the valid and binding obligation of each Seller, enforceable against such Seller in accordance with its terms, except as such enforceability may be limited by bankruptcy, insolvency or other laws relating to or affecting the enforcement of creditors' rights generally and general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law). 3.4. NO VIOLATIONS. Subject to Article VIII(7)2.4., this Agreement, the Instruments of Transfer and each of the other agreements and documents contemplated hereby or thereby, and the execution and delivery hereof by Seller does not, and the fulfillment and compliance with the terms and conditions hereof and thereof and the consummation of the transactions contemplated hereby and thereby will not: (i) conflict with, or require the consent of any Person under, any of the terms, conditions or provisions of the partnership agreement of the Seller; 7 9 (ii) violate any provision of the Code, the NGA or the NGPA, or require any filing, consent, authorization or approval under, any Legal Requirement applicable to or binding upon Seller, other than the consent to the transfer and assignment of Leases by the General Land Office of the State of Texas, which consent Seller shall obtain as soon as possible following the Closing; (iii) conflict with, result in a breach of, constitute a default under (without regard to requirements of notice or the lapse of time or both), accelerate or permit the acceleration of the performance required by, or require any consent, authorization or approval under, (a) any mortgage, indenture, loan, credit agreement or other agreement or instrument evidencing indebtedness for borrowed money or any Contract to which Seller is a party or by which Seller is bound or to which any of its properties are subject or (b) any Lease to which Seller is a party or by which it is bound or to which any of its properties are subject; or (iv) result in the creation or imposition of any Encumbrance upon the Transferred Assets; which violation, breach or Encumbrance with respect to the matters specified in clauses (ii) through (iv) of this Section 3.4 have had or would reasonably be expected to have a Material Adverse Effect. 3.5. NO DEFAULT. Seller is not in default under, and no condition exists that with notice or lapse of time or both would constitute a default under, (i) any mortgage, indenture, loan, credit agreement or other agreement or instrument evidencing indebtedness for borrowed money or (ii) any Contract or Lease to which Seller is a party or by which Seller is bound or to which any of the Transferred Assets is subject. 3.6. ABSENCE OF CERTAIN CHANGES. Since the Effective Time, there has not been any material damage, destruction or loss to, or of, the Transferred Assets, that has not been covered by insurance. 3.7. TAXES. All returns, statements and reports with respect to Taxes that are required to be filed by Seller on or before the Closing have been (or will have been by the Closing) timely filed with the appropriate Governmental Authorities and all such Taxes shown thereon as due have been (or will have been by the Closing) paid or deposited. 3.8. DEFENSIBLE TITLE. Seller has, and will have at the Closing Date, Defensible Title to the Oil and Gas Interests. Each Seller represents as to itself only that it is transferring 100% of its interest in the Transferred Assets and that by, through and under it, no event has occurred and no conveyance has been made that would cause such Seller's interest in the Transferred Assets to be less than the Warranted Interest. Each Seller, as to itself only, represents and warrants that it owns the Warranted Interest; provided that the representation and warranty contained in this sentence shall terminate at Closing. Purchaser's exclusive remedy for any breach of the warranties set forth in this Section 3.8 shall be the remedy provided in Article VI. 3.9. LEASES. With respect to the Leases: (i) the Leases have been maintained according to their terms, in compliance with the agreements to which the Leases are subject, during the period in which Seller has owned an interest in such Leases; (ii) Seller has made or caused to be made all payments, including royalties, delay rentals and shut-in royalties (due in respect of the Leases thereunder), during the period in which 8 10 Seller has owned an interest in such Leases and no amounts of such payments due during such period are now being held in suspense; (iii) to the Knowledge of Seller, no other Party to any Lease is in breach or default with respect to any of its obligations thereunder; (iv) there has not occurred any event, fact or circumstance which with the lapse of time or the giving of notice, or both, would constitute such a breach or default on behalf of the Seller or, to the Knowledge of Seller, with respect to any other parties; and (v) neither Seller nor, to the Knowledge of Seller, any other party to any Lease has given or threatened to give notice of any action to terminate, cancel, rescind or procure a judicial reformation of any Lease or any provisions thereof. 3.10. ENVIRONMENTAL MATTERS. (a) To the Knowledge of Seller, since, May 19, 1989, the date that Seller closed the acquisition of its interest in the Properties,: (i) the use of the Transferred Assets has been limited to the conduct of oil and gas exploration and production operations and related activities; (ii) Seller has not received notice that any Governmental Authority has commenced any investigation or inquiry regarding failure of the Transferred Assets and/or the operations conducted thereon to comply with Environmental Laws or any notice under the Comprehensive Environmental Response, Compensation, and Liability Act, or any state or local laws; (iii) Except for the disposal of salt water produced from the wells located on the Leases using practices consistent with those customarily used by the oil and gas industry operating in the Gulf Coast area, the Transferred Assets have not been used for the generation, storage or disposal of Hazardous Substances or as a landfill or other waste disposal site for Hazardous Substances, in any manner that would constitute a violation of the Environmental Laws by such person; and (iv) Seller has not installed and has not discovered, on the Lands, any underground storage tanks other than the ordinary underground pipeline systems used in the conduct of oil and gas operations on the Transferred Assets. (b) To the Knowledge of Seller: (i) the Transferred Assets and the operations conducted thereon are not the subject of any existing, unfulfilled administrative or judicial orders, decrees, judgments, license or permit conditions, or other directives, under any Environmental Law, except as listed on Schedule 3.10; (ii) no equipment or other personal property or improvements owned or used on the Transferred Assets contain asbestos in such amount, concentration or level that would constitute a violation of Environmental Laws, except as listed on Schedule 3.10; (iii) no equipment or other personal property or improvements owned or used on the Transferred Assets contain any polychlorinated biphenyls in such amount, 9 11 concentration or level that would constitute a violation of Environmental Laws, except as listed on Schedule 3.10; (iv) no equipment or other personal property or improvements owned or used on the Transferred Assets contain any naturally occurring radioactive material in such amount, concentration or level that would constitute a violation of Environmental Laws, except as listed on Schedule 3.10; (v) except for violations that would not have a Material Adverse Effect on the Transferred Assets or the operations being conducted thereon, such operations conducted thereon are not in violation of, or non-compliance with, any Environmental Laws, nor are they the subject of any activities under the Comprehensive Environmental Response, Compensation, and Liability Act, or analogous state or local laws; and (vi) neither the execution of this Agreement nor the consummation of the transactions contemplated by this Agreement will violate any Environmental Law or require the consent or approval of any agency charged with enforcing any Environmental Law. (c) Notwithstanding any contrary provision in this Agreement or any document or instrument delivered with respect to this Agreement, (i) Seller makes no representation or warranty with respect to compliance with any Environmental Law of any kind except as provided in this Section 3.10; (ii) All representations and warranties contained in this Section 3.10 are qualified by the knowledge of Seller and Purchaser that the Environmental Protection Agency has not issued permits for the discharge of salt water and other materials from oil and gas exploration and production facilities such as those that are included in the Transferred Assets and that located in the Gulf Coast area, that until recently the Environmental Protection Agency had not provided any written guidance as to the procedures required for application for such permits and that the operator of the Transferred Assets, like other operators of oil and gas exploration and production facilities in the Gulf Coast area, has not been able to obtain such permit; and (iii) All representations and warranties contained in this Section 3.10 shall terminate at the end of the Environmental Indemnity Period, following which the Purchaser agrees not to institute any action or claim for a breach of such representation or warranty; provided, however, that the expiration of the Environmental Indemnity Period shall be extended as to any bona fide claim with respect to the breach of such representation or warranty, solely to the extent that Purchaser asserted such claim according to the procedures provided in Section 10.5 and Section 10.6, if the Purchaser shall have transmitted the Claim Notice with respect to such claim to the Seller prior to the expiration of such Environmental Indemnity Period. 3.11. OPERATIONS AND EXPENDITURES. With respect to the joint, unit or other operating agreements affecting the Transferred Assets, there are no outstanding calls or payments under authorities for expenditures concerning any single expenditure to be made by Seller in excess of $5,000 that are due or which Seller has committed to make and that have not been made, except as set forth on Schedule 3.11 annexed to this Agreement. 3.12. CONTRACTS. All of the Contracts are set forth on Exhibit "A" to this Agreement. 10 12 3.13. TAX PARTNERSHIPS. Except as disclosed on Schedule 3.13 annexed to this Agreement, none of the Transferred Assets are subject to a tax partnership, except Seller's partnership agreement. 3.14. FULL DISCLOSURE. No representation or warranty by Seller in this Article III, in any schedule or exhibit to this Agreement, or in any certificate or document furnished or to be furnished by Seller on the Closing Date, contains or will contain any untrue statement of a material fact, or omits or will omit to state a material fact necessary to make the statements contained therein not misleading. ARTICLE IV REPRESENTATIONS AND WARRANTIES OF PURCHASER Except as otherwise disclosed in this Agreement, Purchaser hereby represents and warrants that: 4.1. ORGANIZATION AND GOOD STANDING. Purchaser is a corporation duly organized, validly existing and in good standing under the laws of its jurisdiction of incorporation. 4.2. CORPORATE AUTHORITY; AUTHORIZATION OF AGREEMENT. Purchaser has all requisite corporate power and authority to execute and deliver this Agreement, to consummate the transactions contemplated hereby and to perform all the terms and conditions hereof to be performed by it. The execution and delivery of this Agreement by Purchaser, the performance by Purchaser of all the terms and conditions hereof to be performed by it and the consummation of the transactions contemplated hereby will have been duly authorized and approved by the Board of Directors of Purchaser. This Agreement has been duly executed and delivered by Purchaser and constitutes the valid and binding obligation of Purchaser, enforceable against it in accordance with its terms, except as such enforceability may be limited by bankruptcy, insolvency or other laws relating to or affecting the enforcement of creditors' rights generally and general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law). 4.3. NO VIOLATIONS. This Agreement and the execution and delivery hereof by Purchaser do not, and the fulfillment and compliance with the terms and conditions hereof and the consummation of the transactions contemplated hereby will not: (i) conflict with, or require the consent of any Person under, any of the terms, conditions or provisions of the certificate of incorporation or bylaws of Purchaser; (ii) violate any provision of, or require any filing, consent, authorization or approval under, any Legal Requirement applicable to or binding upon Purchaser (assuming receipt of all routine governmental consents typically received after consummation of transactions of the nature contemplated by this Agreement); (iii) conflict with, result in a breach of, constitute a default under (without regard to requirements of notice or the lapse of time or both), accelerate or permit the acceleration of the performance required by, or require any consent, authorization or approval under (a) any mortgage, indenture, loan, credit agreement or other agreement or instrument evidencing indebtedness for borrowed money to which Purchaser is a party or by which Purchaser is bound or to which any of its properties is subject or (b) any lease, license, contract or other agreement or instrument to which Purchaser is a party or by which it is bound or to which any of its properties is subject; or 11 13 (iv) result in the creation or imposition of any Encumbrance upon the assets of Purchaser; which violation, breach or encumbrance with respect to the matters specified in clauses (ii) through (iv) of this Section 4.3 might reasonably be expected to have a material adverse effect on the business, financial condition or results of operations of Purchaser, taken as a whole. 4.4. LITIGATION. There is no action, suit, proceeding or governmental investigation or inquiry pending, or, to the Knowledge of Purchaser, threatened against Purchaser or its subsidiaries or any of their respective properties that might delay, prevent or hinder the consummation of the transactions contemplated hereby. ARTICLE V ADDITIONAL AGREEMENTS AND COVENANTS 5.1. COVENANTS OF SELLER. Seller covenants and agrees with Purchaser as follows: 5.1.1. CERTAIN CHANGES. Except as may be expressly permitted by this Agreement or set forth in any Schedule hereto, from the date hereof until the Closing, without first obtaining the written consent of Purchaser (which consent will not be unreasonably withheld), Seller will not: (i) enter into, assign, terminate or amend in any material respect any Contract or Lease; (ii) sell, lease or otherwise dispose of any of the Transferred Assets; (iii) purchase, lease or otherwise acquire any property of any kind whatsoever other than in the ordinary course of business; provided, however, that no such action involving an expenditure of $5,000 or more by Seller shall be taken by Seller without Purchaser's prior written consent; (iv) mortgage, encumber or pledge any of the Transferred Assets; (v) operate the Transferred Assets except diligently and in the usual, regular and ordinary manner, consistent with past practices; or (vi) commit itself to do any of the foregoing. 5.1.2. OPERATION OF PROPERTIES. Except as may be expressly permitted hereunder or as set forth in any Schedule hereto, from the date hereof until the Closing, without first obtaining the written consent of Purchaser (which consent will not be unreasonably withheld), Seller will not: (i) waive any right of material value relating to any of the Transferred Assets; (ii) release or abandon any material part of any of the Transferred Assets; 12 14 (iii) convey, farm out or otherwise dispose of Transferred Assets with a fair market value exceeding either $5,000 on an individual basis or $5,000 in the aggregate; (iv) commence or consent to any material operations on any Property that it has not previously committed to and that may be expected to cost Seller in excess of $5,000 (except for emergency operations, in which case Seller shall promptly notify Purchaser and from the date of Purchaser's response to such notice Seller shall once again be subject to the limitations contained in this clause (iv)); (v) enter into, modify or terminate any Contracts or Lease; or (vi) commit itself to do any of the foregoing; provided, however, that nothing contained in this Section 5.1.2 or elsewhere in this Agreement shall limit the rights of Seller to produce, consume and sell Hydrocarbons from the Properties in the ordinary course of business and to comply with requirements of the NGA, the NGPA and any rules or regulations issued thereunder. 5.1.3. CERTAIN COVENANTS WITH RESPECT TO THE TRANSFERRED ASSETS. Except as may otherwise be expressly provided herein, Seller will, from the date hereof to the Closing, unless otherwise consented to in writing by Purchaser (which consent will not be unreasonably withheld): (i) promptly notify Purchaser of the receipt of any written notice or written claim or written threat of notice or claim of which Seller becomes aware relating to any default or breach under, or of any termination or cancellation or written threat of termination or cancellation of, any of the Leases, Properties or Material Contracts; (ii) promptly notify Purchaser of any loss of or damage to any portion of the Transferred Assets exceeding $5,000 in amount; (iii) cause to be paid all rentals, shut-in royalties, minimum royalties and other payments that are necessary to maintain in force its rights in and to the Properties, and pay timely all costs and expenses incurred by it in connection with the Properties, except such costs and expenses as are being contested in good faith; and (iv) as to the Properties, use its Best Efforts to maintain and operate the Properties in accordance with all applicable Legal Requirements (to the extent consistent with customary practices in the oil and gas industry), in accordance with the Contracts relating thereto, and in substantially the same manner that Seller hereto has operated such properties. 5.1.4. ACCESS. Seller will afford to Purchaser and its authorized representatives upon reasonable notice, reasonable access from the date hereof until the Closing Date, during normal business hours, to its personnel, financial data properties, books and records which are related to the Transferred Assets to the extent that such access and disclosure would not unreasonably interfere with the normal operation of the business of Seller or violate the terms of any agreement by which Seller is bound or any applicable Legal Requirement; provided, however, that the confidentiality of any data or information so acquired shall be maintained by Purchaser and its representatives in accordance with Section 5.2.4. 13 15 5.1.5. BEST EFFORTS. Seller will use its Best Efforts to obtain the satisfaction of the conditions to Closing set forth in Section 7.1. 5.1.6. PUBLIC ANNOUNCEMENTS. Except for communications with its partners, Seller shall not issue any public announcement or statement with respect to the transactions contemplated hereby except upon the consent of Purchaser or upon the advice of counsel that such announcement or statement is legally required; provided, however, that Seller shall, if practical under the circumstances, consult with Purchaser prior to issuing any such public announcement or statement. 5.1.7. PERMISSIONS. Seller will cooperate with Purchaser and take all action reasonably necessary (i) to obtain all such permissions, approvals and consents by Governmental Authorities and others as may be required to consummate the transactions contemplated in this Agreement and (ii) to obtain the transfer to Purchaser of any and all operating rights held by Seller. 5.2. COVENANTS OF PURCHASER. Purchaser covenants and agrees with Seller as follows: 5.2.1. BEST EFFORTS. Purchaser will use its Best Efforts to obtain the satisfaction of the conditions to Closing set forth in Section 7.2. 5.2.2. PUBLIC ANNOUNCEMENTS. Purchaser shall not issue any public announcement or statement with respect to the transactions contemplated hereby except upon the consent of Seller or upon the advice of counsel that such announcement or statement is legally required; provided, however, that Purchaser shall, if practical under the circumstances, consult with Seller prior to issuing any such public announcement or statement. 5.2.3. CONFIDENTIAL INFORMATION. In the event that this Agreement is terminated or, if not terminated, until the Closing, the confidentiality of any data or information received by Purchaser regarding the business and assets of Seller shall be maintained by Purchaser and its representatives in accordance with the Confidentiality Agreement that was executed by Purchaser. 5.2.4. USE OF TRADE NAMES. After the Closing, Purchaser shall not use any logos, trademarks or trade names belonging to Seller, and will, as soon as reasonably practicable after the Closing, remove any such trade names from all signs or labels on the Transferred Assets. ARTICLE VI INSPECTION OF TITLE MATTERS 6.1. TITLE DEFECTS. (a) Any Encumbrances that individually or in the aggregate with other defects could cause the title of Seller in any Property described in Exhibit A to be less than Defensible Title shall be a title defect ("Title Defect"). Purchaser shall be entitled to the remedies set forth in Section 6.3 for any matter that constitutes a Title Defect even though Purchaser could, but for this provision, after Closing obtain indemnification for such matter pursuant to Section 10.2. 14 16 (b) Any circumstances or condition that could operate to cause (i) the Net Revenue Interest of Seller to increase above that set forth on Exhibit A without an increase in the Working Interest of Seller, or (ii) the Working Interest of Seller to decrease below that set forth on Exhibit A without a decrease in the Net Revenue Interest of Seller, shall be a title benefit ("Title Benefit"). 6.2. NOTICE OF TITLE DEFECTS AND TITLE BENEFITS. (a) From time to time during the period from the date of execution of this Agreement until seven (7) days prior to the Closing Date (the "Title Examination Period"), Purchaser shall have the right (but not the obligation) to notify Seller of any Title Defect of which Purchaser becomes aware, providing in such notice a reasonably detailed description of such Title Defect. If the Closing Date is extended beyond the Closing Date stated herein in accordance with the provisions hereof, then the Title Examination Period shall be extended for a similar and parallel length of time. With respect to each notice of a Title Defect given during such period, Seller may, but shall have no obligation to, attempt to cure such Title Defect prior to Closing. Purchaser's failure to give notice of a Title Defect shall not impair Purchaser's rights under any express warranty or indemnification made by Seller under this Agreement or the Instruments of Transfer. (b) From time to time during the Title Examination Period, Purchaser shall notify Seller of any Title Benefits of which Purchaser becomes aware and Seller shall have the right (but not the obligation) to notify Purchaser of any Title Benefit of which they become aware. The value of any such Title Benefits shall be mutually agreed upon by Purchaser and Seller, taking into consideration the allocated value of the Property (asset forth on allocation of the Purchase Price) subject to the Title Benefit, the portion of the Property subject to the Title Benefit, the legal effect of the Title Benefit and the anticipated economic effect of the Title Benefit over the life of the Property subject to such Title Benefit. 6.3. REMEDIES FOR TITLE DEFECTS. In the event that any Title Defects is not cured on or before Closing, Purchaser may, at its own election, (a) waive such Title Defect, (b) elect to terminate this Agreement pursuant to Section 9.1, or (c) reduce the Purchase Price by an amount mutually agreed upon by Purchaser and Seller as being the value of such Title Defect, taking into consideration the allocated value of the Property subject to the Title Defect, the portion of the Property subject to the Title Defect, the legal effect of the Title Defect on the Property and the liability of Purchaser relative to the allocated liabilities related to the Property and/or whether the Title Defect is applicable to a portion of the Property that is not encumbered by the allocated liability, and the anticipated economic effect of the Title Defect over the life of the Property subject to the Title Defect (including the potential amount of reduction of discounted present net worth of net future cash flow on account of such Title Defect), subject to offset for the value of Title Benefits. If the parties are unable to agree as to the amount of any adjustment under Section 6.3 (c), either party may terminate this Agreement. Notwithstanding anything to the contrary in this Section 6.3, in no event shall the reduction in the Purchase Price for all Title Defects affecting any Property exceed the allocated value of such Property. 6.4. SELLER'S WARRANTY OF TITLE. The Conveyances shall contain a special warranty of title whereby Seller binds and obligates itself, its successors and assigns, to warrant and forever defend unto Purchaser, its successors and assigns, title to the Properties and other tangible Transferred Assets against all persons lawfully claiming or to claim the same or any part thereof by, through or under Seller, but not 15 17 otherwise, together with full subrogation of Purchaser, to the extent that Seller is entitled to grant such subrogation, to all representations and warranties of any predecessors of Seller in title. ARTICLE VII CONDITIONS TO CLOSING 7.1. CONDITIONS TO THE OBLIGATIONS OF PURCHASER. The obligations of Purchaser to proceed with the Closing contemplated hereby are subject to the satisfaction on or prior to the Closing of all of the following conditions, any one or more of which may be waived, in whole or in part, in writing by Purchaser: 7.1.1. COMPLIANCE. Except as otherwise contemplated or permitted herein, the representations and warranties made herein by Seller shall be correct at and as of the Closing as though such representations and warranties were made at and as of the Closing, and Seller shall have complied with all the covenants and other agreements hereof required by this Agreement to be performed by it at or prior to the Closing. 7.1.2. OFFICER'S CERTIFICATES. Purchaser shall have received certificates, dated the Closing Date, of an executive officer of Seller certifying as to the matters specified in Section 7.1.1. 7.1.3. NO ORDERS. The Closing hereunder shall not violate any order or decree of any Governmental Authority having competent jurisdiction over the transactions contemplated by this Agreement; provided, however, that if such order or decree is a temporary restraining order or other ex parte order or decree and all other conditions precedent to Closing have been satisfied or waived, the Closing Date shall be extended to a date five (5) business days subsequent to the date on which such temporary restraining order or other ex parte order or decree ceases to be in effect. 7.1.4. CONSENTS TO ASSIGNMENTS. Seller shall have delivered to Purchaser satisfactory consents to the assignment of the Leases and Contracts. 7.1.5. TITLE OPINION. Purchaser shall have received within ten (10) business days prior to Closing a title opinion, in a form reasonably satisfactory to Purchaser, from Purchaser's special title opinion counsel relating to the Transferred Assets. 7.1.6. DAMAGE TO TRANSFERRED ASSETS. Purchaser's obligation to purchase the Seller's interest in the Transferred Assets is conditioned upon the absence of any material damage, destruction or loss to, or of, the platform, platform equipment, pipelines, tankage or related surface equipment, included as part of the Transferred Assets, that has not been covered by insurance. 7.1.7. FRENCH CLOSING. Purchaser's obligation to purchase the Seller's interest in Transferred Assets is conditioned upon Purchaser's closing on the purchase of at least seventy-five percent (75%) of the Working Interest in the Leases pursuant to that certain Asset Purchase Agreement between Purchaser and Pelham, Inc., et al., dated May 15, 1995. 16 18 7.2. CONDITIONS TO THE OBLIGATIONS OF SELLER. The obligation of Seller to proceed with the Closing contemplated hereby is subject to the satisfaction on or prior to the Closing of all of the following conditions, any one or more of which may be waived, in whole or in part, in writing by Seller: 7.2.1. COMPLIANCE. Except for such breaches of representations or warranties by and covenants of Purchaser made herein as would not have a material adverse effect on the business, financial condition and results of operations of Purchaser, taken as a whole, the representations and warranties made herein by Purchaser shall be correct at and as of the Closing as though such representations and warranties were made at and as of the Closing, and Purchaser shall have complied with all the covenants and other agreements required by this Agreement to be performed by it at or prior to the Closing. 7.2.2. OFFICER'S CERTIFICATE. Seller shall have received a certificate dated the Closing Date of an executive officer of Purchaser, certifying as to the matters specified in Section 7.2.1. 7.2.3. NO ORDERS. The Closing hereunder shall not violate any order or decree of any Governmental Authority having competent jurisdiction over the transactions contemplated by this Agreement; provided, however, that if such order or decree is a temporary restraining order or other ex parte order or decree and all other conditions precedent to Closing have been satisfied or waived, the Closing Date shall be extended to a date five (5) business days subsequent to the date on which the temporary restraining order or such other ex parte order or decree ceases to be in effect. 7.2.4. APPROVAL BY PARTNERS. Seller shall have received the affirmative vote of at least 75% of the Seller's partners to ratify and approve this Agreement and the transactions contemplated hereby. ARTICLE VIII TAX MATTERS 8.1. LIABILITY FOR TAXES. 8.1.1. SELLER. Seller shall be liable for (i) all Taxes for any taxable period ending on or before the Effective Time, (ii) any income taxes which are imposed on the gain recognized by Seller on the sale of the Transferred Assets pursuant to this Agreement, (iii) the portion that is determined as described in Section 8.1.4, of any Taxes (other than Taxes described in clause (ii) above) for any taxable period beginning before and ending after the Effective Time and that is allocable to the portion of such period occurring on or before the Effective Time (the "Seller Period") and (iv) any sales, use, transfer or similar taxes arising from the transactions contemplated in this Agreement. 8.1.2. PURCHASER. Purchaser shall be liable for all Taxes attributable to the Transferred Assets and arising after the Effective Time. 8.1.3. INDEMNITY. Seller shall indemnify and hold Purchaser harmless from any liability for amounts for which Seller is liable pursuant to Section 8.1.1. Purchaser shall indemnify and hold Seller harmless from any liability for amounts for which Purchaser is liable pursuant to Section 8.1.2. The amount of any indemnity under this Section 8.1.3 shall include any additional amount necessary to indemnify the recipient of the indemnity payment against any taxes imposed, and any attorneys' fees or other litigation costs incurred, in connection with such indemnity payment. 17 19 8.1.4. AD VALOREM TAXES. Whenever it is necessary for purposes of Section 8.1.1 to determine the portion of any Taxes for a taxable period beginning before and ending after the Effective Time, which portion is allocable to the Seller Period, the determination shall be made for ad valorem Taxes, on a per diem basis and for other Taxes, on the assumption that the Seller Period constitutes a separate taxable period and by taking into account the actual taxable events occurring during such period (except that exemptions, allowances and deductions for a taxable period beginning before and ending after the Effective Time that are calculated on an annual or periodic basis, such as the deduction for depreciation, shall be apportioned to the Seller Period on a per diem basis). 8.1.5. REFUNDS. If any Seller or Purchaser or any affiliate of a Seller or Purchaser receives (whether by payment, credit, offset or otherwise) a refund in respect of any Taxes for which the other party is liable under Section 8.1.1 or 8.1.2, the party receiving such refund shall, within thirty (30) days after receipt of such refund, remit it to the party liable for the Taxes with respect to which the refund was received. The parties shall cooperate with each other in taking all necessary steps to claim any such refund. 8.1.6. ADJUSTMENT. For purposes of this Section 8.1, the amount of any downward adjustment to the Purchase Price pursuant to Section 1.3.1(ii)(b) shall be treated as a payment by Seller of ad valorem taxes imposed with respect to the Transferred Assets for 1994. 8.2. COOPERATION AN EXCHANGE OF INFORMATION. Seller or Purchaser will provide, or cause to be provided, to the other party copies of all correspondence received from any taxing authority by such party or any of its affiliates in connection with the liability for Taxes for any period for which such other party is or may be liable under Section 8.1.1 or 8.1.2. The parties will provide each other with such cooperation and information as they may reasonably request of each other in preparing or filing any return, amended return or claim for refund, in determining a liability or a right to refund or in conducting any audit or other proceeding in respect of Taxes imposed on the parties or their respective affiliates. The parties and their affiliates will preserve and retain all returns, schedules, work papers and other documents relating to any such returns, claims, audits or other proceedings until the expiration of the statutory period of limitations (with regard to waivers and extensions) of the taxable periods to which such documents relate and until the final determination of any payments which may be required with respect to such periods under this Agreement and shall make such documents available to representatives of the other party upon reasonable notice and at reasonable times, it being understood that such representatives shall be entitled to make copies of any such books and records as they shall deem necessary. Seller or Purchaser further agree to permit representatives of the other party to meet with employees of such party on a mutually convenient basis in order to enable such representatives to obtain additional information and explanations of any documents provided pursuant to this Section 8.2. Seller or Purchaser shall make available to the representatives of the other party at the then current administrative headquarters of such party sufficient work space and facilities to perform the activities described in the two preceding sentences. Any information obtained pursuant to this Section 8.2 shall be kept confidential, except as may be otherwise necessary in connection with the filing of returns or claims for refund or in conducting any audit or other proceeding. Each party shall provide the cooperation and information required by this Section 8.2 at its own expense. 8.3. PAYMENT OF TAXES. 8.3.1. PAYMENT. All Taxes shall be paid by the party that, on the date that such Taxes are required to be paid, is legally responsible to pay such Taxes. 18 20 8.3.2. TIME OF PAYMENT. Except as otherwise provided in this Article VIII or in Section 1.3, any amount to which a party is entitled under this Article VIII shall be promptly paid to such party by the party obligated to make such payment following written notice to the party so obligated that the Taxes to which such amount relates are due and that provides details supporting the calculation of such amount. 8.4. SURVIVAL OF OBLIGATIONS. The obligations of the parties set forth in this Article VIII shall be unconditional and absolute and shall remain in effect without limitation as to time. 8.5. CONFLICT. In the event of a conflict between the provisions of this Article VIII and any other provisions of this Agreement, the provisions of this Article VIII shall control. ARTICLE NINE TERMINATION 9.1. GROUNDS FOR TERMINATION. This Agreement may be terminated at any time prior to the Closing: (i) by the mutual written agreement of Seller and Purchaser; (ii) by Seller or Purchaser, if the consummation of the transactions contemplated hereby would violate any nonappealable final order, decree or judgment of any Governmental Authority having competent jurisdiction enjoining, restraining or otherwise preventing the consummation of this Agreement or the transactions contemplated hereby; provided, however, that a party shall not be allowed to exercise any right of termination pursuant to this Section 9.1(ii) if the event giving rise to such right shall be due to the negligent or willful failure of such party to perform or observe in any material respect any of the covenants or agreements set forth herein to be performed or observed by such party; (iii) by Purchaser or Seller if the Closing shall not have occurred prior to 5:00 p.m., December 31, 1995; provided, that the Closing was not delayed as a result of the negligent or willful failure of the terminating party's obligation to perform hereunder; (iv) by Seller or Purchaser if the non-terminating party has breached its representations and warranties, defaulted in the performance of its covenants or not satisfied its conditions to Closing; (v) by Purchaser, or by Seller, as provided in Section 6.3; or (vi) by Seller, if there is a breach of any representation or warranty under Section 3.10 and the cost of curing such breach would exceed $500,000 and such breach is not waived by Purchaser. 9.2. EFFECT OF TERMINATION. The following provisions shall apply in the event of a termination of this Agreement: 19 21 9.2.1. NO LIABILITY. If this Agreement is terminated as permitted under Section 9.1 (i), (ii), (iii), (v) or (vi), such termination shall be without liability of any party to this Agreement or any affiliate, shareholder, director, officer, employee, agent or representative of such party and Seller shall return to Purchaser the Initial Payment. In such event, the representation contained in the second sentence of Section 4.2 shall be of no effect. 9.2.2. PURCHASER'S LIABILITY. If this Agreement is terminated by Seller, as permitted under Section 9.1 (iv), Seller shall retain the Initial Payment, as Seller's sole remedy, and Purchaser shall have no further obligation to Seller for failure to close the transaction. 9.2.3. SELLER'S LIABILITY. If this Agreement is terminated by Purchaser, as permitted under Section 9.1 (iv), Purchaser's sole remedy shall be the right to seek specific performance of Seller's obligation to sell to Purchaser the Transferred Assets in complete satisfaction of any other damages, thereby sustained or incurred by Purchaser. 9.2.4. SURVIVAL. Notwithstanding the foregoing, the provisions of this Article IX and Section 5.2.3 shall survive any termination of this Agreement. ARTICLE X EXTENT AND SURVIVAL OF REPRESENTATIONS AND WARRANTIES; INDEMNIFICATION 10.1. SCOPE OF REPRESENTATIONS OF SELLER. Except as and to the extent expressly set forth herein, Seller makes no representations or warranties whatsoever, and disclaim all liability and responsibility for any representation, warranty, statement or information made or communicated (orally or in writing) to Purchaser (including, but not limited to, any opinion, information or advice that may have been provided to Purchaser by any affiliate, officer, stockholder, director, employee, agent, consultant or representative of Seller, any petroleum engineer or engineering firm, Seller's counsel or any other agent, consultant or representative). Without limiting the generality of the foregoing, except as and to the extent expressly set forth herein and in the Instruments of Transfer, Seller makes no representations or warranties as to (i) the title to any of the properties of Seller, (ii) the amounts of Hydrocarbon reserves attributable to such properties or (iii) any geological or other interpretations or economic evaluations. Purchaser acknowledges and affirms that it has had full access to the records of Seller and the information contained in, or made available or provided with respect to materials contained in, the records of Seller, and that Purchaser has made its own independent investigation, analysis and evaluation of the Transferred Assets, (including its own estimate and appraisal of the extent and value of Seller's Hydrocarbon reserves). Notwithstanding the foregoing, to the Knowledge of Seller, the information contained in the records of Seller and information otherwise made available or furnished in writing to Purchaser by Seller with respect to the Transferred Assets does not contain any untrue statement of a material fact or omit to state any material fact that would make such information not false or misleading. 10.2. INDEMNIFICATION OF PURCHASER. Seller agrees (i) to indemnify Purchaser against, and hold Purchaser harmless from, any loss. damage or expense (including reasonable attorneys' fees) sustained by Purchaser arising out of or resulting from any inaccuracy in or breach of any of the representations, warranties or covenants made by Seller in this Agreement, (ii) to pay, perform, fulfill and discharge all costs, expenses and liabilities incurred in connection with the Transferred Assets prior 20 22 to the Closing Date with respect to the ownership or operation of the Transferred Assets prior to the Closing Date and (iii) to indemnify, defend and hold Purchaser harmless from and against any and all claims, losses, damages, costs, expenses, causes of action and judgments of any kind or character with respect to all liabilities, including the Retained Liabilities, arising out of or in connection with the ownership or operation of the Transferred Assets prior to the Closing Date, including, without limitation, any interest, penalty and other costs and expenses incurred in connection therewith or the defense thereof (provided that any loss, damage or expense sustained by Purchaser arising out of or resulting from any breach or violation of Section 3.10 shall be governed by Section 10.4); provided, however, that Purchaser shall not be entitled to assert rights of indemnification under this Section 10.2 or Section 10.4 unless and until the aggregate of all such losses exceeds $25,000 (it being understood that such losses shall accumulate until such time or times as the aggregate of all such losses exceeds $25,000, whereupon Purchaser shall be entitled to indemnification under this Section 10.2 or Section 10.4 for any such losses); and provided, further, that the maximum aggregate of all losses for which Purchaser shall be entitled to indemnification by any Seller, whether under this Section 10.2, Section 10.4 or otherwise, shall not exceed such Seller's share of the Purchase Price. 10.3. INDEMNIFICATION OF SELLER. Purchaser agrees (i) to indemnify Seller against, and hold Seller harmless from, any loss, damage or expense (including reasonable attorneys' fees) sustained by Seller arising out of or resulting from any inaccuracy in or breach of any of the representations, warranties or covenants made by Purchaser in this Agreement, (ii) to pay, perform, fulfill and discharge all costs, expenses and liabilities incurred from and after the Closing Date with respect to the ownership or operation of the Transferred Assets from and after the Closing Date and (iii) to indemnify, defend and hold Seller harmless from and against any and all claims, losses, damages, costs, expenses, causes of action and judgments of any kind or character with respect to all liabilities to third parties arising out of or in connection with the ownership or operation of the Transferred Assets from and after the Closing Date, including, without limitation, any interest, penalty and other costs and expenses incurred in connection therewith or the defense thereof (provided that any loss, damage or expense sustained by Seller arising out of or resulting from any breach or violation of Article VIII shall be governed by those provisions); provided, however, that Seller shall not be entitled to assert rights of indemnification under this Section 10.3 unless and until the aggregate of all such losses exceeds $25,000 (it being understood that such losses shall accumulate until such time or times as the aggregate of all such losses exceeds $25,000, whereupon Seller shall be entitled to indemnification under this Section 10.3 for any such losses). 10.4. ENVIRONMENTAL INDEMNITY. (a) Subject to the financial limitations regarding the indemnity of Seller described in Section 10.2, Seller agrees, during the Environmental Indemnity Period, to indemnify and save Purchaser harmless from and against, and to reimburse Purchaser with respect to, any and all claims, demands, losses, damages, liabilities, causes of action, judgments, penalties, costs and expenses (including, without limitation, reasonable legal fees and expenses, clean-up costs and disbursements) accrued or incurred by Purchaser at any time and from time to time, during the Environmental Indemnity Period by reason of (i) the breach of any representation or warranty of Seller as set forth in Section 3.10, (ii) any violation with respect to or affecting the Transferred Assets on or before the Closing Date of any Environmental Laws in effect on or before the Closing Date, (iii) the clean-up of the Transferred Assets required under Environmental Laws for any activities prior to the Closing Date, (iv) any act, omission, event or circumstance existing or occurring on or prior to the Closing Date (including without limitation, the presence on the 21 23 Properties of Hazardous Substances or the presence off site of Hazardous Substances generated on the Properties, on or prior to the Closing Date) that result from or that are in connection with the ownership, construction, occupancy, operation, use and/or maintenance of the Properties, regardless of whether the act, omission, event or circumstance constituted a violation of any Environmental Laws at the time of its existence or occurrence, and (v) any and all claims or proceedings (whether brought by private party or Governmental Authority) for bodily injury, property damage, abatement or remediation, environmental damage or impairment or any other injury or damage resulting from or relating to any Hazardous Substances located upon the Properties prior to the Closing Date. Seller shall also indemnify and hold Purchaser harmless from and against any liability, loss, cost or expense, including reasonable attorneys' fees and expenses, arising from or relating to the imposition or recording of a lien on the Properties in connection with any contamination of the Properties or pursuant to any Environmental Laws in the event only that such contamination occurred prior to the Closing Date. Seller shall also hold harmless and indemnify Purchaser from any liability incurred by Purchaser arising out of regulatory action or third-party claims with respect to contamination of the Properties or offsite locations that occurred prior to the Closing Date. (b) Notwithstanding anything contained in this Agreement to the contrary, the indemnities in this Section 10.4 shall survive the Closing Date only until the end of the Environmental Indemnity Period, and shall be limited in scope only to any activities discovered after the Closing Date but before the end of the Environmental Indemnity Period that occurred before the Closing Date. For all purposes with respect to the Transferred Assets, Purchaser agrees that it shall have the burden of proof that any alleged activities, violations, events or conditions occurred before the Closing Date. (c) Seller shall have the right to control any action for which indemnity is required under this Section 10.4 through counsel of its choice, subject to Purchaser's consent, which shall not be unreasonably withheld or delayed, provided, however, at Purchaser's option, Purchaser may participate in such action and appoint its own counsel. If Seller does not notify Purchaser in writing of its intent to control such action within thirty (30) days (or five (5) days less than such lesser time as may be required to respond to such claims) after receipt by Seller of written notice of such claims, Purchaser shall have the right to undertake the control, conduct or settlement of such claims through its own counsel at Seller's expense and may settle such matter without Seller's consent at its sole expense. In the event any proposed settlement includes non-monetary relief, including clean-up, Purchaser may agree to such clean-up and settle such matter only with the consent of Seller, which consent shall not be unreasonably withheld or delayed; provided, however, if Seller fails to respond to such a notification by Purchaser regarding such non-monetary relief within ten (10) days after Purchaser's notification to Seller, Seller shall be deemed to have consented to such non-monetary relief. (d) Purchaser agrees that the rights and remedies provided in this Section 10.4 shall be the exclusive rights and remedies available to it for any matter within the scope of Section 10.4 and that the general indemnification provisions of Section 10.2 and any other rights or remedies of Purchaser with respect to the Seller for any matter within the scope of Section 10.4, whether provided in this Agreement, at law or in equity, shall not be applicable and are hereby waived. Nothing in this Section 10.4 or elsewhere in this Agreement shall limit or impair any rights or remedies of Purchaser against any third party under any Environmental Laws, including, without limitation, any rights of contribution or indemnification available hereunder. 22 24 (e) Any indemnification provided in this Section 10.4 shall terminate at the end of the Environmental Indemnity Period, following which the Purchaser agrees not to institute any action or claim for indemnification or other recovery with respect to the matter within the scope of Section 10.4; provided, however, that the expiration of the Environmental Indemnity Period shall be extended as to any bona fide claim for indemnification within the scope or Section 10.4, solely to the extent that Purchaser asserted such claim according to the procedures provided in Section 10.5 and Section 10.6, if the Purchaser shall have transmitted the Claim Notice with respect to such claim to the Seller prior to the expiration of such Environmental Indemnity Period. 10.5. SURVIVAL. The representations and warranties set forth in this Agreement (other than those set forth in Article VIII) shall survive until the second anniversary of the Closing Date, following which date none of the parties may bring any action or present any claim for a breach of such representations and warranties; provided, however, that there shall be no termination of any representation or warranty as to which a bona fide claim has been asserted if the Indemnified Party shall have transmitted the Claim Notice with respect thereto prior to the anniversary of the Closing Date. The representations and warranties set forth in 3.8.2 shall remain terminate in accordance with the terms of Article VIII. 10.6. INDEMNIFICATION PROCEDURES. All claims for indemnification under this Agreement (other than claims for indemnification under Article VIII) shall be asserted and resolved as follows: 10.6.1. NOTICE. An Indemnified Party shall promptly (i) notify an Indemnifying Party of any Third-Party Claim asserted against the Indemnified Party and (ii) transmit to the Indemnifying Party a Claim Notice relating to such Third-Party Claim, a copy of all papers served with respect to such claim (if any), an estimate of the amount of damages attributable to the Third-Party Claim and the basis of the Indemnified Party's request for indemnification under this Agreement. During the Election Period, an Indemnifying Party shall notify an Indemnified Party (a) whether the Indemnifying Party disputes its potential liability to the Indemnified Party under this Article X with respect to such Third-Party Claim and (b) whether an Indemnifying Party desires, at the sole cost and expense of such Indemnifying Party, to defend the Indemnified Party against such Third-Party Claim. 10.6.2. DEFENSE BY INDEMNIFYING PARTY. If an Indemnifying Party notifies an Indemnified Party within the Election Period that the Indemnifying Party does not dispute its potential liability to the Indemnified Party under this Article X and that the Indemnifying Party elects to assume the defense of the Third-Party Claim, then the Indemnifying Party shall have the right to defend, at its sole cost and expense, such Third-Party Claim by all appropriate proceedings, which proceedings shall be prosecuted diligently by the Indemnifying Party to a final conclusion or settled at the discretion of the Indemnifying Party in accordance with this Section 10.6.2. The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof; provided, however, that any settlement entailing non-monetary consideration must be approved, in advance, by the Indemnified Party, which approval shall not be unreasonably delayed or withheld. The Indemnified Party is hereby authorized, at the sole cost and expense of the Indemnifying Party (but only if the Indemnified Party is actually entitled to indemnification hereunder or if the Indemnifying Party assumes the defense with respect to the Third-Party Claim), to file, during the Election Period, any motion, answer or other pleadings which the Indemnified Party shall deem necessary or appropriate to protect its interests or those of the Indemnifying Party and not prejudicial to the Indemnifying Party (it being understood and agreed that if an Indemnified Party takes any such action that is prejudicial and conclusively causes a 23 25 final adjudication adverse to the Indemnifying Party, the Indemnifying Party shall be relieved of its obligations hereunder with respect to such Third-Party Claim). If requested by the Indemnifying Party, the Indemnified Party agrees, at the sole cost and expense of the Indemnifying Party, to cooperate with the Indemnifying Party and its counsel in contesting any Third-Party Claim that the Indemnifying Party elects to contest, including, without limitation, the making of any related counterclaim against the person asserting the Third-Party Claim or any cross-complaint against any person. The Indemnified Party may participate in, but not control, any defense or settlement of any Third-Party Claim controlled by the Indemnifying Party pursuant to this Section 10.6, and shall bear its own costs and expenses with respect to any such participation. 10.6.3. DEFENSE BY INDEMNIFIED PARTY. If an Indemnifying Party fails to notify an Indemnified Party within the Election Period that the Indemnifying Party elects to defend the Indemnified Party pursuant to Section 10.6.2, or if the Indemnifying Party elects to defend the Indemnified Party pursuant to Section 10.2 but fails diligently and promptly to prosecute or settle the Third-Party Claim, then the Indemnified Party shall have the right to defend, at the sole cost and expense of the Indemnifying Party, the Third-Party Claim by all appropriate proceedings, which proceedings shall be diligently prosecuted by the Indemnified Party to a final conclusion or settled. The Indemnified Party shall have full control of such defense and proceedings; and provided, however, that without the Indemnifying Party's consent, which consent shall not be unreasonably delayed or withheld, the Indemnified Party shall not be authorized by the Indemnifying Party to enter into any compromise or settlement of such Third Party Claim on any non-monetary basis; and provided further, however, that if requested by the Indemnified Party, the Indemnifying Party shall, at the sole cost and expense of the Indemnifying Party, cooperate with the Indemnified Party and its counsel in contesting any Third-Party Claim that the Indemnified Party is contesting, or, if appropriate and related to the Third-Party Claim in question, in making any counterclaim against the person asserting the Third-Party Claim or any cross-complaint against any person. Notwithstanding the foregoing, if the Indemnifying Party has delivered a written notice to the Indemnified Party to the effect that the Indemnifying Party disputes its potential liability to the Indemnified Party under this Article X and if such dispute is resolved in favor of the Indemnifying Party by a final, nonappealable order of a court of competent jurisdiction, the Indemnifying Party shall not be required to bear the costs and expenses of the Indemnified Party's defense pursuant to this Section 10.6 or of the Indemnifying Party's participation therein at the Indemnified Party's request, and the Indemnified Party shall reimburse the Indemnifying Party in full for all costs and expenses of such litigation. The Indemnifying Party may participate in, but not control, any defense or settlement controlled by the Indemnified Party pursuant to this Section 10.6, and the Indemnifying Party shall bear its own costs and expenses with respect to any such participation. 10.6.4. OTHER CLAIMS. In the event any Indemnified Party should have a claim against any Indemnifying Party hereunder that does not involve a Third-Party Claim, the Indemnified Party shall transmit to the Indemnifying Party an Indemnity Notice with respect to such claim. If the Indemnifying Party does not notify the Indemnified Party in writing within Sixty (60) days from its receipt of the Indemnity Notice that the Indemnifying Party disputes such claim, the claim specified by the Indemnified Party in the Indemnity Notice shall be deemed a liability of the Indemnifying Party hereunder. If the Indemnifying Party has timely disputed such claim, as provided above, such dispute shall be resolved by binding arbitration. 10.7. TAX BENEFITS, INSURANCE PROCEEDS AND INDEMNIFICATION PAYMENTS. In determining the amount of any loss, liability or expense for which an Indemnified Party is entitled to indemnification under this Article X, the gross amount thereof will be reduced by any correlative insurance proceeds, if 24 26 any, realized or to be realized by such Indemnified Party, and such correlative insurance benefit shall be net of any insurance premium that becomes due as a result of such claim. 10.8. TAX ON INDEMNIFICATION PAYMENTS. After taking into account any adjustment required by Section 10.6, the amount of each payment by an Indemnifying Party under Section 10.2 and Section 10.3 shall include any additional amount necessary to indemnify the Indemnified Party against any taxes imposed in connection with such payment. ARTICLE XI BROKERS Seller has retained Reid Investments Inc. to assist and advise it in connection with the transactions contemplated by this Agreement Seller will be responsible for any fees payable to Reid. Purchaser and Seller represent to the other that, except as set forth in the preceding sentence, neither has, directly or indirectly, employed any broker, finder or intermediary in connection with such transactions that might be entitled to a fee or commission for which the other party shall have any obligation or responsibility upon the execution of this Agreement or the consummation of such transactions. ARTICLE XII EXPENSES Except as specifically provided herein, all legal and other costs and expenses in connection with this Agreement and the transactions contemplated hereby shall be paid by the party that incurred such costs and expenses. ARTICLE XIII NOTICES; MISCELLANEOUS 0.1. NOTICES. All notices and other communications given hereunder shall be in writing and shall be deemed given if delivered personally, including delivery by a nationally recognized courier service, or mailed by registered or certified mail, return receipt requested, to the parties at the following addresses: (i) If to Purchaser, to: Goldking Trinity Bay Corp. 1221 McKinney Suite 1800 Houston, Texas 77010 Attention: Leonard C. Tallerine, Jr. With a copy to: Looper, Reed, Mark & McGraw 9 East Greenway Plaza Suite 1717 Houston, Texas 77046 Attention: Mark Licata 25 27 (ii) If to Seller to: Benton Oil & Gas Combination Partnership 1989-1, L.P. c/o Benton Oil & Gas Company 1145 Eugenia Place Carpeneria, California 93013 13.2. MISCELLANEOUS. 13.2.1. EXCLUSIVE AGREEMENT. This Agreement supersedes all prior written or oral agreements between the parties with respect to the transactions contemplated herein, and is intended as a complete and exclusive statement of the terms of the agreement between the parties with respect to the transactions contemplated herein. 13.2.2. CHOICE OF LAW; CHOICE OF FORUM; AMENDMENTS; HEADINGS. This Agreement shall be governed by the internal laws of the State of Texas, without giving effect to principles of conflicts of laws. This Agreement may not be changed or terminated orally. The headings contained in this Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement. Terms such as "herein," "hereby," "hereto" and "hereof" refer to this Agreement as a whole. The term "include" and derivatives thereof are used in an illustrative sense and not a limitative sense. 13.2.3. ASSIGNMENTS AND THIRD PARTIES. No party hereto shall assign this Agreement or any part hereof without the prior written consent of the other parties; provided, however, that Purchaser shall be authorized to assign this Agreement provided that no such assignment shall release Purchaser from any of its obligations under this Agreement. Except as otherwise provided herein, this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and permitted assigns. Nothing in this Agreement shall entitle any Person, other than the parties hereto or their respective permitted successors and assigns, to any claim, cause of action, remedy or right of any kind. 13.2.4. SUBSEQUENT FILINGS. Effective at the Closing Date, Purchaser shall file with General Land Office of the State of Texas and with such other Governmental Authorities such notices or certificates as are necessary to reflect the sale of the Transferred Assets to Purchaser. 13.2.5. SEVERABILITY. If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any manner materially adverse to any party. Upon any binding determination that any term or other provision is invalid, illegal or incapable of being enforced, the parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the parties as closely as possible in an acceptable and legally enforceable manner, to the end that the transactions contemplated hereby may be completed to the extent possible. 13.2.6. COUNTERPARTS. This Agreement may be executed in any number of counterparts, each of which shall be deemed to be an original and all of which together shall constitute but one and the same agreement. 26 28 13.2.7. FURTHER ASSURANCES. (i) The parties each agree to deliver or cause to be delivered to the others on the Closing Date, and at such other times thereafter as shall be reasonably requested, any additional instrument that the other may reasonably request for the purpose of carrying out this Agreement. (ii) After the Closing, Seller and Purchaser shall, and shall cause their affiliates to, execute, acknowledge and deliver all such further conveyances, transfer orders, division orders, notices, assumptions, releases and acquittances, and such other instruments, and shall take such further actions as may be necessary or appropriate to assure fully to Purchaser, its successors or assigns, all of the Transferred Assets intended to be conveyed to Purchaser by the Instruments of Transfer pursuant to this Agreement, and to assure fully to Seller and its affiliates and its successors and assigns, the assumption of the liabilities and obligations intended to be assumed by Purchaser pursuant to this Agreement. 13.2.8. PRESERVATION OF BOOKS AND RECORDS. For a period of seven (7) years (five (5) years with respect to geophysical data related to the Transferred Assets) after the Closing Date, Purchaser and Seller (if and to the extent Seller has retained any of the hereinafter described records not delivered to Purchaser at Closing) shall (i) preserve and retain the corporate, accounting, legal, auditing and other books and records that relate to the conduct of Seller's businesses and operations prior to the Closing Date (including, but not limited to, any documents relating to any governmental or non-governmental actions, suits, proceedings or investigations arising out of the conduct of the business and operations of Seller prior to the Closing Date and including, but not limited to, all financial statements and other data and information necessary or desirable for Purchaser to comply with their public reporting requirements) and (ii) make such books and records available at their then current administrative headquarters to the other party and its officers, employees, agents and affiliates upon reasonable notice and at reasonable times, it being understood that such other party shall be entitled to make and retain copies of any such books and records as it shall deem necessary. Purchaser and Seller agree to permit representatives of the other party to meet with its employees on a mutually convenient basis in order to enable such other party to obtain additional information and explanations of any materials provided pursuant to this Section 13.2.8. -the remainder of this page left blank intentionally- 27 29 IN WITNESS WHEREOF, the undersigned have executed this Agreement as of the date first written above. PURCHASER: GOLDKING TRINITY BAY CORP. By:________________________________________ Name:______________________________________ Title:_____________________________________ SELLER: BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P. By: BENTON OIL AND GAS COMPANY, Managing General Partner By:________________________________________ Name:______________________________________ Title:_____________________________________ 29 30 APPENDIX A Definitions Capitalized terms used in this Agreement shall have the meanings ascribed to them in this Appendix A unless such terms are defined elsewhere in this Agreement: Agreed Interest Rate: Ten percent (10%) per year. Best Efforts: A party's best efforts in accordance with reasonable commercial practices and without the incurrence of unreasonable expense. Claim Notice: A written notice delivered by an Indemnified Party to an Indemnifying Party pursuant to Section 10.6.1 describing in reasonable detail the nature of a Third-Party Claim that could give rise to a right of indemnification under this Agreement. Claimed Interest Additions: The Interest Additions claimed by Seller on the list to be submitted to Purchaser within thirty (30) days after the date of this Agreement pursuant to Section 6.3. Closing: The closing of the transactions contemplated by this Agreement. Closing Date: The date of the Closing. Code: The Internal Revenue Code of 1986, as amended. Data Rooms: The data rooms prepared by Seller to provide information to Persons considering the acquisition of the Transferred Assets. Defensible Title: Such title to the Transferred Interests, free and clear of all Encumbrances other than Permitted Encumbrances, that is deducible of record and free from reasonable doubt to the end that a prudent person engaged in the business of the ownership, development and operation of producing oil and gas properties, with knowledge of all the facts and the legal bearing of such facts and the commercial effect of such facts on the continued control and operation of the Transferred Assets, would be willing to accept such title. Effective Time: The effective time of the transfer of the Transferred Assets to Purchaser, which shall be deemed to be 7:00 a.m., Houston, Texas time, on January 1, 1995. Election Period: The 30-day period following receipt by an Indemnifying Party of a Claim Notice. Encumbrance: Any mortgage, lien, security interest, pledge, charge, encumbrance, claim, limitation, preferential right to purchase, consent to assignment, irregularity, burden or defect or any other claim that Seller does not own the Warranted Interest. Entity: A corporation, partnership, joint venture, trust or unincorporated organization or association or other entity. Environmental Laws: All federal, state and local laws relating to the protection of human health and safety or the environment, including but not limited to the federal Comprehensive Environmental Response, Compensation, and Liability Act, the Resource Conservation and Recovery Act, the Safe Appendix A Page 1 31 Drinking Water Act, the Toxic Substances Control Act, the Clean Water Act, the Coastal Zone Management Act, the Endangered Species Act, the Oil and the Hazardous Materials Transportation Act, all as amended, and all analogous state and local laws. Environmental Indemnity Period: The period beginning on the Closing Date and ending two (2) years after the Closing Date. Governmental Authority: The United States of America, any state, commonwealth, territory or possession thereof and any political subdivision of any of the foregoing, including but not limited to courts, departments, commissions, boards, bureaus, agencies or other instrumentalities. Hazardous Substance: Any substance or material now or hereafter defined as a "hazardous substance", "hazardous material", "hazardous waste", "contaminant", or "pollutant" under any environmental laws, including but not limited to Section 1.01 of the Comprehensive Environmental Response, Compensation and Liability Act, 4-2 U.S.C.A 9601. Hydrocarbons: Oil, gas, minerals (including but not limited to sulfur) and other gaseous and liquid hydrocarbons or any combination thereof. Indemnified Party: A party claiming indemnification under this Agreement (other than a claim for indemnification under Section 10.4, Article VI or Article VIII). Indemnifying Party: A party from whom indemnification under this Agreement (other than indemnification under Section 10.4, Article VI or Article VIII) is sought. Indemnity Notice: A written notice from an Indemnified Party to an Indemnifying Party with respect to a claim for indemnification under this Agreement (other than indemnification under Section 10.4, Article VI or Article VIII) not involving a Third-Party Claim, which notice shall describe in detail the nature of the claim and set forth an estimate of the amount of damages attributable to such claim and the basis of the Indemnified Party's request for such indemnification. Initial Payment: The initial payment of the Purchase Price in the amount of FOUR THOUSAND NINE HUNDRED TWENTY-NINE DOLLARS ($4,929), paid by Purchaser to Seller, on the date this Agreement was executed. Knowledge: The actual knowledge of each executive officer of Seller (assuming such Seller is a corporation, and if not, a Person in a similar capacity) after reasonable inquiry, or Purchaser, as the case may be. Leases: As defined in the Instruments of Transfer. Legal Requirement: Any law, statute, ordinance, decree, requirement, order, judgment, rule or regulation of, including the terms of any license or permit issued by, any Governmental Authority. Material Adverse Effect: Any material adverse effect on or with respect to the Transferred Assets or on the business, operations, prospects or condition of the Transferred Assets, taken as a whole. Net Revenue Interest: The interest (expressed as a percentage) of Seller in and to Hydrocarbons produced from or allocated to a Property after deducting all applicable Production Burdens. NGA: The Natural Gas Act of 1938. NGPA: The Natural Gas Policy Act of 1978. Appendix A Page 2 32 Permitted Encumbrances: Any or all of the following: (i) encumbrances that arise under operating agreements to secure payment of amounts not yet delinquent and are of a type and nature customary in the oil and gas industry; (ii) encumbrances that arise as a result of pooling and unitization agreements, and production sales contracts securing the payment of amounts not yet delinquent; (iii) consents to assignment by Governmental Authorities (a) that are obtained on or prior to the Closing Date or (b) that are customarily obtained after the consummation of transactions of the nature contemplated by this Agreement; (iv) conventional rights of reassignment obligating Seller to reassign its interest in any portion of the Properties to a third party in the event it intends to release or abandon such interest prior to the expiration of the primary term or other termination of such interest; (v) easements, rights-of-way, servitudes, permits, surface leases, surface use restrictions and other surface uses and impediments on, over or in respect of any of the Properties that are not such as to interfere materially with the operation, value or use of any of the Properties; (vi) such Title Defects and Environmental Defects as Purchaser has expressly waived in writing; (viii) such Title Defects for which Purchaser failed to give timely notice according to Section 6.2; (ix) such Environmental Defects (to the extent the Purchaser has Knowledge of such Environmental Defect) for which Purchaser failed to give timely notice according to Section 6.2 or for which Purchaser failed to provide written information as required by Section 6.2; (x) rights reserved to or vested in any municipality or governmental, tribal, statutory or public authority to control or regulate any of the Properties in any manner, and all applicable laws, rules and orders of any municipality or governmental or tribal authority; (xi) all production burdens that do not operate to (A) reduce the Net Revenue Interest below the Warranted Interest or (B) increase the Working Interest above the Warranted Interest; (xii) the preferential purchase rights for which waivers have been obtained prior to the Closing Date; (xiii) the terms and conditions of the Contracts, insofar and only insofar as the Contracts do not operate to (A) reduce the Net Revenue Interest of Seller below that set forth on Exhibit A hereto, (B) increase the Working Interest of Seller above that set forth on Exhibit A hereto without a proportionate increase in the Net Revenue Interest of Seller; (xiv) any other Encumbrance affecting any portion of a Transferred Asset that individually does not materially adversely affect the operation, value or use of any such Transferred Asset; and (xv) solely during the period prior to the Closing, any Encumbrance that is released on or before Closing. Person: shall mean a corporation, an association, a partnership, an organization, a business, an individual, a government or political subdivision thereof, or a governmental agency. Appendix A Page 3 33 Production Burdens: All royalty interests, overriding royalty interests, production payments, net profits interests or other similar interests that constitute a burden on, are measured by or are payable out of the production of Hydrocarbons or the proceeds realized from the sale or other disposition thereof. Purchase Price Adjustment Amount: The net adjustment to the Purchase Price to be made pursuant to Section 1.3.1. Purchase Price Adjustment Certificate: A statement of the Purchase Price Adjustment Amount (specifying whether the Purchase Price is to be increased or decreased by such amount), which shall be certified by an officer of Seller. Seller's Affiliate: Any person that directly or indirectly, through one or more intermediaries, controls, is controlled by or is under common control with, such Seller. Subsidiary: shall mean, as to a Person, any other Person (a) more than 50% of the outstanding voting stock of which is held, directly or indirectly, by such Person, or (b) over which such Person has the power, directly or indirectly, to designate a majority of the directors thereof (if such other Person is a corporation) or the individuals exercising similar functions (if such other Person is unincorporated). Third-Party Claim: A third-party claim asserted against an Indemnified Party that could give rise to a right of indemnification under this Agreement (other than a right of indemnification under Section 10.4, Article VI or Article VIII). Transferred Assets: As defined in Section 1.1. Warranted Interests: Those interests whereby a Seller is (i) entitled to receive not less than the "Net Revenue Interest" set forth on Exhibit A hereto of all oil, gas and associated liquid and gaseous Hydrocarbons produced, saved and marketed from the Properties, without reduction, throughout the productive life of such Properties and (ii) obligated to bear the percentage of the costs and expenses related to the maintenance, development and operation of the Properties in an amount not greater than the "Working Interest" set forth on Exhibit A hereto, without increase, throughout the productive life of such Properties, except increases that result in a proportionate increase in such Seller's Net Revenue Interest and increases that results from contribution requirements with respect to defaulting co-owners. Working Interest: The interest (expressed as a percentage) of a Seller in any Transferred Asset before giving effect to any applicable Production Burdens and the percentage of all costs and expenses associated with the exploration, development and operation of such Transferred Asset required to be borne by such Seller. Appendix A Page 4 34 SCHEDULE 1.2.1 INDIVIDUAL INTEREST VALUATIONS
WORKING NET REVENUE PURCHASE SELLER INTEREST INTEREST PRICE Benton Oil & Gas Combination 4.928910% 4.115640% $377,062.00 Partnership 1989- 1, L. P., a California limited partnership
35 BILL OF SALE, CONVEYANCE AND PARTIAL ASSIGNMENT STATE OF TEXAS Section. Seciton. COUNTY OF CHAMBERS Section. This Bill of Sale, Conveyance and Partial Assignment is from BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P., a California limited partnership, whose mailing address is 1145 Eugenia Place, Carpinteria, California ("Grantor"), to GOLDKING TRINITY BAY CORP., a Texas corporation ("Grantee"), whose mailing address is 1221 McKinney, Suite 1800, Houston, Texas 77002. I. NOW, THEREFORE, for and in consideration of Ten and No/100 Dollars ($10.00) and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Grantor has granted, bargained, sold, transferred, assigned and conveyed, and by these presents does hereby grant, bargain, sell, transfer, assign and convey unto Grantee, its successors and assigns, subject to the hereinafter stated exceptions, restrictions, covenants and conditions, all of Grantor's interest in and to the following described properties, to-wit: (a) The leasehold estate created by each of the Oil, Gas and Mineral Leases listed and described in Exhibit "A", which is annexed hereto and incorporated herein for all purposes, such leases being hereinafter sometimes referred to as "Subject Leases"; (b) All payments out of production, overriding royalty interests, carried interests, reversionary interests, and all other rights and interests, incident to, or held and owned by Grantor in connection with the Subject Leases, save and except the overriding royalty excepted and reserved herein below by Grantor; (c) All oil, gas, condensate, casinghead gas and other related hydrocarbon substances produced and saved subsequent to the Effective Date of this conveyance from lands covered and affected by the Subject Leases. (The interest described under subparagraphs (a) and (b) above, and this subparagraph (c) are hereinafter sometimes collectively referred to as "Subject Properties"); (d) All personal property and facilities located on lands covered by the Subject Leases or the Subject Interests, or both, incident to or held and used in connection with the Subject Interests, including, but not limited to, all tanks, tanks batteries, gas plants, disposal facilities, buildings, structures, platforms, field separators and liquid extractors, treators, dehydrators, compressors, pumps, pumping units, valves, fittings, machinery and parts, engines, boilers, meters, apparatus, implements, tools, appliances, cables, wires, towers, casing, tubing and rods, gathering lines or other pipelines, field gathering systems and any and all other fixtures and equipment of every type and description to the extent that the same are used or held in connection with the ownership or operation of the Subject Interests; (e) All oil, natural gas or water source wells, whether producing, operating, shut-in, or temporarily abandoned; all types of injection wells; and all equipment used or held by Grantor in connection with the production of oil, gas, condensate, casinghead gas and other related hydrocarbon substances from or attributable to lands covered by the Subject Leases; 1 36 (f) All tenements, appurtenances, surface leases, easements, permits, licenses, servitudes, or rights-of-way in any way appertaining, belonging, affixed and used in connection with, or incident to, the ownership and operation of the Subject Interest, including, but not limited to, those tenements, appurtenances, surface leases, easements, permits, licenses, servitudes or rights-of-way listed and described in Exhibit "B", annexed hereto and incorporated herein for all purposes; (g) All leases, options, rights of first refusal, orders, contracts, operating agreements, bottom-hole agreements, farmin/farmout agreements, acreage contribution agreements, unit agreements, processing agreements, maintenance agreements, purchase and sale agreements for gas, oil or other minerals, and other agreements and instruments to the extent that same relate, appertain, belong or are in any way incidental to the ownership of the Subject Interests by Grantor, including, but not limited to, those listed and described in Exhibit "C", annexed hereto and incorporated herein for all purposes; (h) All lease files, land files, well files, abstracts, title opinions, title curative, accounting records, royalty payment records, seismic records and surveys, gravity maps, electric logs, contracts, correspondence, microfiche lists, geological and geophysical maps, pressure date and decline curves, graphical production curves and other geological or geophysical data, records and other documents and records of every kind and description which relate to and are possessed by Grantor in connection with the Subject Interests, to the extent and as provided for or limited by that certain Purchase and Sale Agreement dated effective April 1, 1989 by and between Grantor and Texaco Producing Inc.; and (i) Any and all monies held by any individual, partnership, or corporate entity, whether or not such monies are held in escrow, payable to either Texaco Producing Inc. or Grantor, or both, for oil, gas condensate, casinghead gas or other related hydrocarbon substance produced and saved from or attributable to the Subject Leases and purchased by such individual, partnership or corporate entity subsequent to the Effective Date of this conveyance. The interests described under subparagraphs (a) through (i) hereinabove are herein sometimes collectively referred to as "Subject Interests". II. This Bill of Sale, Conveyance and Assignment is made by Grantor and accepted by Grantee subject to the following: (a) All terms, conditions and obligations contained and provided for in the Subject Leases; (b) The terms and conditions of all existing orders, rules, regulations and ordinances of any federal, state or other governmental agency that are applicable or related to the Subject Interests; (c) The terms and conditions of the Purchase and Sale Agreement, dated the same date as this conveyance instrument, by and between Grantor, as a Seller and Grantee as the Purchaser, concerning the Subject Interests; and (d) Grantee accepting the Subject Interest in its "as is, where is" condition; Grantor disclaiming any and all liability arising in connection with any environmental matters, including, without limitation, any presence of naturally occurring radio-active material on the property; and Grantee expressly waiving the provisions of Chapter XVII, Subchapter E, Sections 17.41 through 17.63, inclusive, except Section 17.555 which is 2 37 not waived, of Vernon's Texas Code Annotated, Business and Commerce Code. In addition, there are no warranties or representations, either express or implied, as to the quality or quantity of the hydrocarbon reserves, if any, attributable to the interest conveyed herein or the ability of the property to produce hydrocarbons. TO HAVE AND TO HOLD all and singular the Subject Interest, as hereinabove described, unto Grantee, its successors and assigns, and Grantor, for itself, its successors and assigns, does hereby WARRANT AND FOREVER DEFEND, all and singular, title to the Subject Interests, free from all liens, claims, assessments and encumbrances, other than the existing burdens, unto Grantee, Grantee's successors and assigns, against every person lawfully claiming or to claim the same, or any part hereof, BY, THROUGH OR UNDER GRANTOR, BUT NOT OTHERWISE. The reference herein to the "existing burdens" is for the purpose of protecting Grantor on Grantor's warranties, and shall not create, nor constitute a recognition of any rights in third parties. Grantor grants unto Grantee full power and right of substitution and subrogation in and to all covenants and warranties by others heretofore given or made in respect of the Subject Interests. III. The provisions hereof shall inure to the benefit of and be binding upon the parties hereto, their respective legal representatives, successors and assigns. IN TESTIMONY WHEREOF, this Conveyance is executed on the dates and at the places indicated in the respective acknowledgments below, but is stipulated herein to be effective as of 7:00 a.m., C.D.S.T., the 1st day of January, 1995. GRANTOR: BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P. By: _______________________________ 3 38 [acknowledgments] 4 EX-2.2 3 EX-2.2 1 EXHIBIT 2.2 ASSET PURCHASE AGREEMENT BETWEEN BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P., A CALIFORNIA LIMITED PARTNERSHIP SELLER AND GOLDKING TRINITY BAY CORP. PURCHASER FOR THE SELLER'S INTEREST IN THE PROPERTIES KNOWN AS UMBRELLA POINT FIELD JUNE 30, 1995 2 ASSET PURCHASE AGREEMENT This ASSET PURCHASE AGREEMENT (this "Agreement") dated as of June 30, 1995 by and between Goldking Trinity Bay Corp., a Texas corporation, ("Purchaser") and Benton Oil & Gas Combination Partnership 1990-1, L.P., a California limited partnership ("Seller"); W I T N E S S E T H: WHEREAS, Seller owns the working interest and net revenue interest set forth opposite such Seller's name on Schedule 1.2.2; WHEREAS, Seller desires to sell to Purchaser the Transferred Assets, and Purchaser desires to purchase from Seller the Transferred Assets, upon the terms and subject to the conditions hereinafter set forth; and NOW, THEREFORE, in consideration of the premises and of the respective representations, warranties, covenants, agreements and conditions contained herein, the parties hereto hereby agree as follows ARTICLE I PURCHASE AND SALE Unless defined elsewhere in this Agreement, all capitalized terms used herein shall have the respective meanings given them in Appendix A hereto, which is incorporated herein by reference and shall be deemed to be a part of this Agreement for all purposes. 1.1 CONVEYANCE AND TRANSFER OF TRANSFERRED ASSETS. Seller and Purchaser hereby agree that, at the Closing, upon the terms and subject to the conditions of this Agreement, Seller shall convey, transfer and assign to Purchaser, the Transferred Assets. For purposes of this Agreement, the term "Transferred Assets" shall mean all of each Seller's right, title and interest in certain oil and gas properties located in Galveston Bay, including all of each Seller's right, title and interest in and to the following assets: (a) All of the oil and gas leases, oil, gas and mineral leases as described in Exhibit A attached hereto and incorporated herein (collectively referred to hereinafter as the "Leases" and individually as a "Lease"), and the leasehold estates created thereby, and the fee, mineral, royalty and overriding royalty interests, net profits interests, payments out of production and other real property interests described in Exhibit A, together with each and every kind and character of right, title, claim or interest that Seller has in and to the lands covered thereby, even though the interests of Seller therein may be incorrectly described, stated or limited on Exhibit A (collectively the "Properties", or singularly, a "Property"), together with all of each Seller's right, title and interest in and to all the property and rights incident thereto, including without limitation all of Seller's right, title and interest in and to: (i) the rights, privileges, benefits and powers conferred upon the holder of any Property with respect to the use and occupation of the surface of, and the subsurface depths under, the land covered by such Property that may be necessary, convenient or incidental to the possession and enjoyment of such Property; 3 (ii) the rights in any pooled, communitized or unitized acreage included in whole or in part in any Property, including all production from the unit, pool or communitized area allocated to any such Property, and all interests in any wells within the unit, pool or communitized area allocated to such Property, whether such unit or pool production comes from wells located within or without the areas covered by a Property; and (iii) all tenements, hereditaments and appurtenances belonging to such Properties; (b) All of each Seller's right, title and interest in and to the rights-of-way, easements, servitudes, permits, licenses, franchises, certificates of public convenience and necessity and similar rights and privileges, and other rights and interests in land primarily owned or used in connection with the Properties; (c) All of each Seller's right, title and interest in and to all real, personal and mixed property and fixtures located at the Closing on the Properties or the aforesaid rights-of-way, easements and other related properties, or primarily used or held for use in connection with the ownership, management, development, exploration or operation of the Transferred Assets, including without limitation all of each Seller's right, title and interest in and to all wells, well equipment, platforms, pipes, valves, boilers, compressors, separators, heaters, dehydrators, gauges, meters and other measuring equipment, regulators, extractors, communication equipment, gas gathering systems, casing, tubing pipelines, power lines, fuel lines, generators, pumps, motors, buildings, storage tanks and facilities, improvements, fittings, machinery, equipment (including, without limitation, personal computers and related peripheral equipment located in the field and software that is legally transferable without cost), supplies, spare parts, materials and inventories, other than inventories of Hydrocarbons in storage tanks or other facilities above the pipeline connection to each such storage tank or facility, and in gas pipelines downstream from the delivery point sales meters on such pipelines existing as of the Effective Time; (d) All of each Seller's right, title and interest in and to all contracts, agreements, leases, and/or other arrangements, presently owned or acquired as a result of any agreement in existence prior to the Closing, including all causes of action pursuant thereto, to the extent used in connection with the ownership, management, development, exploration or operation of the Transferred Assets, including without limitation, all gas purchase and sale agreements, crude purchase and sale agreements, natural gas liquids purchase and sale agreements, farmin or farmout agreements, exchange agreements bottom hole agreements, dry hole agreements, acreage contribution agreements, support agreements, seismic agreements, exploration agreements, joint venture agreements, operating agreements, unit agreements, pooling and communitization agreements, orders or declarations, balancing agreements, gas and natural gas liquids processing agreements, gathering and transportation agreements, construction and operation agreements, options, liens, security interests, vendor financing agreements, surface leases, subleases and leases of equipment or facilities to the extent used or primarily useful in connection with the ownership, management, development, exploration or operation of the Transferred Assets and reasonably separable from Seller's other material rights in the contracts not used in connection with the Transferred Assets; provided, however, that no insurance 2 4 contract or other insurance arrangement shall be included in the Transferred Assets (collectively, the "Contracts"); (e) All of each Seller's right, title and interest in and to all Hydrocarbons produced from or attributable to, the Properties and proceeds attributable thereto, at and after the Effective Time (subject to the provision of Section 1.3); provided, however, that all Hydrocarbons in storage tanks and other facilities above the pipeline connection to each such storage tank or facility, or in gas pipelines downstream from the delivery point sale meters on such pipelines at the Effective Time, shall remain the property of Seller; and (f) All of each Seller's right, title and interest in and to all property and rights incident or attributable to the foregoing interests, including, without limitation all of each Seller's right, title and interest in and to: (i) subject to the limitations of Section 13.2.8, originals (or, to the extent that originals are not available, copies) of all books, records, files, contracts, muniments of title, reports, surveys and similar documents or materials, including computer tapes, disks and data with respect to any of the foregoing records, that relate to the foregoing interests, including without limitation, the purchase, exchange, operation, administration, sale or marketing thereof, or that constitute evidence of ownership thereof, to the extent such records are reasonably separable from Seller's corporate records, and excluding work product of Seller's legal counsel (other than title opinions) and documents relating to the negotiation and consummation of the transactions contemplated by this Agreement (collectively, the "Records"); (ii)(A) the proprietary geological, geophysical and seismic data, materials and information (the "Proprietary Data"), (B) the non-proprietary geological, geophysical and seismic data, materials and information the transfer of which is not prohibited by any copyright or validly existing third party agreement, that is transferable to Purchaser without payment of a transfer fee or other consideration, (C) the maps, interpretations, records and other technical information related to or based upon the Proprietary Data and not related to or based upon the Non-Proprietary Data (the "Proprietary Information") and (D) the maps, interpretations, records and other technical information related to or based upon any combination of the Proprietary Data and the Non-Proprietary Data (the "Combined Information" and collectively, the "Evaluation Data"); and (iii) all division orders, purchase orders, invoices, storage or warehouse receipts, bills of lading and certificates of title to the extent the same are attributable or relate to any of the Transferred Assets, and all documents, instruments, general intangibles and chattel paper primarily related to any of the Transferred Assets (other than the bonds, letters of credit and guarantees posted with governmental agencies, which are expressly reserved by Seller) and all estimated prepayments of royalty obligations of Seller with any federal or state authorities that are directly related to the Transferred Assets and that are transferable to Purchaser; provided, however, that the Transferred Assets shall not include (i) any rights and causes of action by Seller to receive amounts (or rights to production from the Properties prior to the Effective Time) pursuant to the Retained Liabilities and (ii) rights and causes of action with respect to the Lawsuits and 3 5 the facts and circumstances giving rise to such Lawsuits as retained by Seller and more particularly described in Section 1.4. 1.2. PURCHASE PRICE AND PURCHASE PRICE ALLOCATION. 1.2.1 PURCHASE PRICE. The aggregate purchase price (the "Purchase Price") for the Transferred Assets shall be ONE MILLION EIGHTY-FIVE THOUSAND SIX HUNDRED SEVENTY-FIVE DOLLARS ($1,085,675) subject to adjustments as set forth in Section 1.3., of which FOURTEEN THOUSAND ONE HUNDRED NINETY-TWO DOLLARS ($14,192) ("Initial Payment") shall be paid to the Seller in immediately available funds upon delivery to Purchaser by Seller of counterparts of this Agreement executed by Seller at the Closing, The Purchase Price, less the amount of the Initial Payment (the "Cash at Closing") and as adjusted as provided in the Purchase Price Adjustment Certificate described in Section 1 3.2, shall be paid to Seller by wire transfer in federal or otherwise immediately available funds. Simultaneously therewith, Seller shall execute and deliver, effective as of the Effective Time, the Instruments of Transfer. 1.2.2 PURCHASE PRICE ALLOCATION. The Purchase Price shall be allocated among the types and classes of assets constituting the Transferred Assets as set forth on a schedule to be provided by Purchaser and Seller at Closing. 1.3 ADJUSTMENTS TO PURCHASE PRICE. 1.3.1. ADJUSTMENTS. In addition to any adjustments pursuant to Article VI, the Cash at Closing shall be adjusted as follows: (i) The Cash at Closing shall be increased by the following: (a) An agreed upon amount representing the value of all merchantable oil in storage above the pipeline connection at the Effective Time that is credited to the Properties; Solely to the extent related to the Transferred Assets, the amount of (1) all actual direct operating expenditures, (2) all capital expenditures and (3) all costs and expenses that are incurred by Seller in connection with, or are otherwise allocable to, the operation of the Transferred Assets under the terms of the joint operating agreement during the period of time after the Effective Time; The amount of any Taxes that have been paid by Seller on or prior to the Closing that are attributable to the time after the Effective Time and for which Purchaser is liable pursuant to Article VIII. (ii) The Cash at Closing shall be decreased by the following: (a) The proceeds that are received by, or payable to, Seller or any other person and that are attributable to the operation of the Transferred Assets for the period of time between the Effective Time and the Closing; and 4 6 (b) Any amount agreed upon by Purchaser and Seller as the value of any Title Defects, less any amount agreed upon by Purchasers and Seller as the value of any Title Benefits. 1.3.2 CLOSING ESTIMATE. At least three (3) business days prior to the Closing Date, Seller on behalf of Seller, shall estimate the Purchase Price Adjustment Amount and deliver to Purchaser a certificate of an officer of Seller setting forth in reasonable detail the calculation thereof. The Cash at Closing shall be adjusted as set forth in such certificate. The Purchase Price Adjustment Certificate shall include a computation of any reduction in the Purchase Price caused by the failure of one or more Seller's to deliver on the Closing Date their respective interests in the Transferred Assets. 1.3.3 PURCHASE PRICE ADJUSTMENT CERTIFICATE. As soon as reasonably practicable, and in any event within sixty (60) days following the Closing Date, Seller shall deliver to Purchaser the Purchase Price Adjustment Certificate. Within thirty (30) days after delivery of the Purchase Price Adjustment Certificate, Purchaser shall notify Seller on behalf of Seller, whether Purchaser agrees or disagrees with the determination of the Purchase Price Adjustment Amount set forth in the Purchase Price Adjustment Certificate. If Purchaser disagrees with such determination, representatives of Purchaser and Seller shall meet and endeavor to resolve their differences regarding the determination of the Purchase Price Adjustment Amount. If the representatives of Purchaser and Seller are unable to agree upon such determination of the Purchase Price Adjustment Amount within twenty (20) business days after Purchaser's receipt of such notification, Seller shall select an independent accounting firm from a list of three (3) such firms provided by Purchaser, which firm shall audit the Purchase Price Adjustment Certificate and determine the Purchase Price Adjustment Amount. The decision of such independent accounting firm shall be binding on Seller and Purchaser, and the fees and expenses of such independent accounting firm shall be borne one-half by Seller and one-half by Purchaser. 1.3.4 PAYMENT OF PURCHASE PRICE ADJUSTMENT AMOUNT. If the Purchase Price Adjustment Amount as finally determined pursuant to Section 1.3.3 is a smaller upward adjustment or a larger downward adjustment than that estimated pursuant to Section 1.3.2, Seller shall pay to Purchaser the amount of such excess plus interest thereon at the Agreed Interest Rate from (and including) the Closing Date to (but excluding) the date of payment. If the Purchase Price Adjustment Amount as finally determined pursuant to Section 1.3.3 is a larger upward adjustment or a smaller downward adjustment than that estimated pursuant to Section 1.3.2, Purchaser shall pay to Seller the amount of such deficiency plus interest thereon at the Agreed Interest Rate from (and including) the Closing Date to (but excluding) the date of payment. Any payments contemplated by this Section 1.3.4 shall be made by wire transfer in federal or other immediately available funds on or before the fifth business day following the final determination of the amount thereof. 1.4 RETAINED RIGHTS AND CLAIMS. Notwithstanding any provision herein to the contrary, Transferred Assets shall not include any rights or claims of Seller with respect to the facts and circumstances giving rise to those certain proceedings collectively referred to as the "Lawsuits" and filed: In the Matter of the Libel and Petition of Exxon Corporation, as Owner of the M/V "Bobcat," and Williamson Boat Works, as Charterer of the M/V "Bobcat," her engines tackle, apparel, etc., in a cause of exoneration from or limitation of liability; C.A. No. C-91-203, United States District Court for the Southern District of Texas, Corpus Christi Division; and 5 7 French Production Incorporated v. Exxon Corporation d/b/a Exxon Company USA, Williamson Boat Works and Captain B.J. Shirley; No. 91-040865, District Court of Harris County, Texas, 295th Judicial District. 1.5 LIABILITIES ASSUMED AND RETAINED. 1.5.1 ASSUMED LIABILITIES. Purchaser shall assume and agree to pay, perform and discharge in the ordinary course of business, only those liabilities, debts or obligations of Seller that are set forth below (the "Assumed Liabilities"): (i) all liabilities and obligations of or relating to the Transferred Assets accruing after the Effective Time: (ii) all liabilities and obligations that accrue after the Effective Time, pursuant to the Leases that have been properly consented to and assigned; and (iii) all liabilities and obligations that accrue after the Effective Time, pursuant to the Contracts that have been properly consented to and assigned. 1.5.2 RETAINED LIABILITIES. Except for the Assumed Liabilities, Purchaser shall not assume and Seller shall retain and agree to pay, perform and discharge in the ordinary course of business all liabilities, debts or obligations of any nature that arise out of or result from any occurrence, transaction or event occurring prior to the Closing Date relating to the operation, ownership or use of the Transferred Assets, whether accrued, absolute, contingent or otherwise, whether due or to become due, including without limitation any such liability of Seller related to the Lawsuits (the "Retained Liabilities"); provided however, that Retained Liabilities shall not include any liability accruing after the Effective Time based on the violation or alleged violation of any statute, ordinance, rule, regulation, order or other law of any state, federal, county, local or other governmental subdivision, due to any occurrence, transaction or event occurring prior to the Effective Time, which occurrence, transaction or event was not a violation of any laws existing as of the Effective Time. The Retained Liabilities shall include any liabilities with respect to the facts and circumstances giving rise to the Lawsuits. ARTICLE II THE CLOSING 2.1 CLOSING. The Closing shall take place at the offices of Purchaser, in Houston, Texas at 9:00 a.m. on December 31, 1995 or such earlier or later date as provided hereafter. 2.2 INSTRUMENTS OF TRANSFER. Seller shall execute and deliver at Closing the Bill of Sale, Conveyance and Assignment, the form of which is attached as Exhibit "B" and any other instruments of transfer sufficient to convey to Purchaser the Transferred Assets, including without limitation the following (the "Instruments of Transfer"): (a) any personal property included in the Transferred Assets; (b) the Leases, assignment of leasehold interests; (c) the Contracts; and 6 8 (d) the Properties. ARTICLE III REPRESENTATIONS AND WARRANTIES OF SELLER Seller hereby represents, warrants and covenants as follows: 3.1 ORGANIZATION AND GOOD STANDING. Seller is a partnership duly organized, validly existing and in good standing under the laws of its jurisdiction of formation and has all requisite power and authority to own and lease the properties and assets it owns and leases and to carry on its business as such business is conducted. 3.2 SUBSIDIARIES. No Seller has any Subsidiaries that own any of the Transferred Assets. 3.3 AUTHORITY; AUTHORIZATION OF AGREEMENT. Seller at closing will have all requisite power and authority to execute and deliver this Agreement, the Instruments of Transfer and each of the other agreements and documents contemplated, to consummate the transactions contemplated hereby and thereby and to perform all the terms and conditions to be performed by it. The execution and delivery of this Agreement, the Instruments of Transfer and each of the other agreements and documents contemplated, the performance of all the terms and conditions to be performed by Seller and the consummation of the transactions contemplated hereby and thereby will be duly authorized and approved by the partners of Seller. This Agreement, the Instruments of Transfer and each of the other agreements and documents contemplated, have been duly executed and delivered by each Seller and constitutes the valid and binding obligation of each Seller, enforceable against such Seller in accordance with its terms, except as such enforceability may be limited by bankruptcy, insolvency or other laws relating to or affecting the enforcement of creditors' rights generally and general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law). 3.4 NO VIOLATIONS. Subject to Article VII (7) 2.4., this Agreement, the Instruments of Transfer and each of the other agreements and documents contemplated hereby or thereby, and the execution and delivery hereof by Seller does not, and the fulfillment and compliance with the terms and conditions hereof and thereof and the consummation of the transactions contemplated hereby and thereby will not: (i) conflict with, or require the consent of any Person under, any of the terms, conditions or provisions of the partnership agreement of the Seller; (ii) violate any provision of the Code, the NGA or the NGPA, or require any filing, consent, authorization or approval under, any Legal Requirement applicable to or binding upon Seller, other than the consent to the transfer and assignment of Leases by the General Land Office of the State of Texas, which consent Seller shall obtain as soon as possible following the Closing; (iii) conflict with, result in a breach of, constitute a default under (without regard to requirements of notice or the lapse of time or both), accelerate or permit the acceleration of the performance required by, or require any consent, authorization or approval under, (a) any mortgage, indenture, loan, credit agreement or other agreement or instrument evidencing 7 9 indebtedness for borrowed money or any Contract to which Seller is a party, or by which Seller is bound or to which any of its properties are subject or (b) any Lease to which Seller is a party or by which it is bound or to which any of its properties are subject; or (iv) result in the creation or imposition of any Encumbrance upon the Transferred Assets; which violation, breach or Encumbrance with respect to the matters specified in clauses (ii) through (iv) of this Section 3.4 have had or would reasonably be expected to have a Material Adverse Effect. 3.5 NO DEFAULT. Seller is not in default under, and no condition exists that with notice or lapse of time or both would constitute a default under, (i) any mortgage, indenture, loan, credit agreement or other agreement or instrument evidencing indebtedness for borrowed money or (ii) any Contract or Lease to which Seller is a party or by which Seller is bound or to which any of the Transferred Assets is subject. 3.6 ABSENCE OF CERTAIN CHANGES. Since the Effective Time, there has not been any material damage, destruction or loss to, or of, the Transferred Assets, that has not been covered by insurance. 3.7 TAXES. All returns, statements and reports with respect to Taxes that are required to be filed by Seller on or before the Closing have been (or will have been by the Closing) timely filed with the appropriate Governmental Authorities and all such Taxes shown thereon its due have been (or will have been by the Closing) paid or deposited. 3.8 DEFENSIBLE TITLE. Seller has, and will have at the Closing Date, Defensible Title to the Oil and Gas Interests. Each Seller represents as to itself only that it is transferring 100% of its interest in the Transferred Assets and that by, through and under it, no event has occurred and no conveyance has been made that would cause such Seller's interest in the Transferred Assets to be less than the Warranted Interest. Each Seller, as to itself only, represents and warrants that it owns the Warranted Interest; provided that the representation and warranty contained in this sentence shall terminate at Closing. Purchaser's exclusive remedy for any breach of the warranties set forth in this Section 3.8 shall be the remedy provided in Article VI. 3.9 LEASES. With respect to the Leases: (i) the Leases have been maintained according to their terms, in compliance with the agreements to which the Leases are subject, during the period in which Seller has owned an interest in such Leases; (ii) Seller has made or caused to be made all payments, including royalties, delay rentals and shut-in royalties (due in respect of the Leases thereunder), during the period in which Seller has owned an interest in such Leases and no amounts of such payments due during such period are now being held in suspense; (iii) to the Knowledge of Seller, no other Party to any Lease is in breach or default with respect to any of its obligations thereunder; 8 10 (iv) there has not occurred any event, fact or circumstance which with the lapse of time or the giving of notice, or both, would constitute such a breach or default on behalf of the Seller or, to the Knowledge of Seller, with respect to any other parties; and (v) neither Seller nor, to the Knowledge of Seller, any other party to any Lease has given or threatened to give notice of any action to terminate, cancel, rescind or procure a judicial reformation of any Lease or any provisions thereof. 3.10 ENVIRONMENTAL MATTERS. (a) To the Knowledge of Seller, since, May 19, 1989, the date that Seller closed the acquisition of its interest in the Properties,: (i) the use of the Transferred Assets has been limited to the conduct of oil and gas exploration and production operations and related activities; (ii) Seller has not received notice that any Governmental Authority has commenced any investigation or inquiry regarding failure of the Transferred Assets and/or the operations conducted thereon to comply with Environmental Laws or any notice under the Comprehensive Environmental Response, Compensation, and Liability Act, or any state or local laws; (iii) Except for the disposal of salt water produced from the wells located on the Leases using practices consistent with those customarily used by the oil and gas industry operating in the Gulf Coast area, the Transferred Assets have not been used for the generation, storage or disposal of Hazardous Substances or as a landfill or other waste disposal site for Hazardous Substances, in any manner that would constitute a violation of the Environmental Laws by such person; and (iv) Seller has not installed and has not discovered, on the Lands, any underground storage tanks other than the ordinary underground pipeline system used in the conduct of oil and gas operations on the Transferred Assets. (b) To the Knowledge of Seller: (i) the Transferred Assets and the operations conducted thereon are not the subject of any existing, unfulfilled administrative or judicial orders, decrees, judgments, license or permit conditions, or other directives, under any Environmental Law, except as listed on Schedule 3.10; (ii) equipment or other personal property or improvements owned or used on the Transferred Assets contain asbestos in such amount, concentration or level that would constitute a violation of Environmental Laws, except as listed on Schedule 3.10; (iii) no equipment or other personal property or improvements owned or used on the Transferred Assets contain any polychlorinated biphenyls in such amount, 9 11 concentration or level that would constitute a violation of Environmental Laws, except as listed on Schedule 3.10; (iv) no equipment or other personal property or improvements owned or used on the Transferred Assets contain any naturally occurring radioactive material in such amount, concentration or level that would constitute a violation of Environmental Laws, except as listed on Schedule 3.10; (v) except for violations that would not have a Material Adverse Effect on the Transferred Assets or the operations being conducted thereon, such operations conducted thereon are not in violation of, or non-compliance with, any Environmental Laws, nor are they the subject of any activities under the Comprehensive Environmental Response, Compensation, and Liability Act, or analogous state or local laws; and (vi) neither the execution of this Agreement nor the consummation of the transactions contemplated by this Agreement will violate any Environmental Law or require the consent or approval of any agency charged with enforcing any Environmental Law. (c) Notwithstanding any contrary provision in this Agreement or any document or instrument delivered with respect to this Agreement, (i) Seller makes no representation or warranty with respect to compliance with any Environmental Law of any kind except as provided in this Section 3.10; (ii) All representations and warranties contained in this Section 3.10 are qualified by the knowledge of Seller and Purchaser that the Environmental Protection Agency has not issued permits for the discharge of salt water and other materials from oil and gas exploration and production facilities such as those that are included in the Transferred Assets and that located in the Gulf Coast area, that until recently the Environmental Protection Agency had not provided any written guidance as to the procedures required for application for such permits and that the operator of the Transferred Assets, like other operators of oil and gas exploration and production facilities in the Gulf Coast area, has not been able to obtain such permit; and (iii) All representations and warranties contained in this Section 3.10 shall terminate at the end of the Environmental Indemnity Period, following which the Purchaser agrees not to institute any action or claim for a breach of such representation or warranty; provided, however, that the expiration of the Environmental Indemnity Period shall be extended as to any bona fide claim with respect to the breach of such representation or warranty, solely to the extent that Purchaser asserted such claim according to the procedures provided in Section 10.5 and Section 10.6, if the Purchaser shall have transmitted the Claim Notice with respect to such claim to the Seller prior to the expiration of such Environmental Indemnity Period. 3.11 OPERATIONS AND EXPENDITURES. With respect to the joint, unit or other operating agreements affecting the Transferred Assets, there are no outstanding calls or payments under authorities for expenditures concerning any single expenditure to be made by Seller in excess of $5,000 that are due 10 12 or which Seller has committed to make and that have not been made, except as set forth on Schedule 3.11 annexed to this Agreement. 3.12 CONTRACTS. All of the Contracts are set forth on Exhibit "A" to this Agreement. 3.13 TAX PARTNERSHIPS. Except as disclosed on Schedule 3.13 annexed to this Agreement, none of the Transferred Assets are subject to a tax partnership, except Seller's partnership agreement. 3.14 FULL DISCLOSURE. No representation or warranty by Seller in this Article III, in any schedule or exhibit to this Agreement, or in any certificate or document furnished or to be furnished by Seller on the Closing Date, contains or will contain any untrue statement of a material fact, or omits or will omit to state a material fact necessary to make the statements contained therein not misleading. ARTICLE IV REPRESENTATIONS AND WARRANTIES OF PURCHASER Except as otherwise disclosed in this Agreement, Purchaser hereby represents and warrants that: 4.1 ORGANIZATION AND GOOD STANDING. Purchaser is a corporation duly organized, validly existing and in good standing under the laws of its jurisdiction of incorporation. 4.2 CORPORATE AUTHORITY; AUTHORIZATION OF AGREEMENT. Purchaser has all requisite corporate power and authority to execute and deliver this Agreement, to consummate the transactions contemplated hereby and to perform all the terms and conditions hereof to be performed by it. The execution and delivery of this Agreement by Purchaser, the performance by Purchaser of all the terms and conditions hereof to be performed by it and the consummation of the transactions contemplated hereby will have been duly authorized and approved by the Board of Directors of Purchaser. This Agreement has been duly executed and delivered by Purchaser and constitutes the valid and binding obligation of Purchaser, enforceable against it in accordance with its terms, except as such enforceability may be limited by bankruptcy, insolvency or other laws relating to or affecting the enforcement of creditors' rights generally and general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law). 4.3 NO VIOLATIONS. This Agreement and the execution and delivery hereof by Purchaser do not, and the fulfillment and compliance with the terms and conditions hereof and the consummation of the transactions contemplated hereby will not: (i) conflict with, or require the consent of any Person under, any of the terms, conditions or provisions of the certificate of incorporation or bylaws of Purchaser; (ii) violate any provision of, or require any filing, consent, authorization or approval under, any Legal Requirement applicable to or binding upon Purchaser (assuming receipt of all routine governmental consents typically received after consummation of transactions of the nature contemplated by this Agreement); 11 13 (iii) conflict with, result in a breach of, constitute a default under (without regard to requirements of notice or the lapse of time or both), accelerate or permit the acceleration of the performance required by, or require any consent, authorization or approval under (a) any mortgage, indenture, loan, credit agreement or other agreement or instrument evidencing indebtedness for borrowed money to which Purchaser is a party or by which Purchaser is bound or to which any of its properties is subject or (b) any lease, license, contract or other agreement or instrument to which Purchaser is a party or by which it is bound or to which any of its properties is subject; or (iv) result in the creation or imposition of any Encumbrance upon the assets of Purchaser; which violation, breach or encumbrance with respect to the matters specified in clauses (ii) through (iv) of this Section 4.3 might reasonably be expected to have a material adverse effect on the business, financial condition or results of operations of Purchaser, taken as a whole. 4.4 LITIGATION. There is no action, suit, proceeding or governmental investigation or inquiry pending, or, to the Knowledge of Purchaser, threatened against Purchaser or its subsidiaries or any of their respective properties that might delay, prevent or hinder the consummation of the transactions contemplated hereby. ARTICLE V ADDITIONAL AGREEMENTS AND COVENANTS 5.1 COVENANTS OF SELLER. Seller covenants and agrees with Purchaser as follows: 5.1.1 CERTAIN CHANGES. Except as may be expressly permitted by this Agreement or set forth in any Schedule hereto, from the date hereof until the Closing, without first obtaining the written consent of Purchaser (which consent will not be unreasonably withheld), Seller will not: (i) enter into, assign, terminate or amend in any material respect any Contract or Lease; (ii) sell, lease or otherwise dispose of any of the Transferred Assets; (iii) purchase, lease or otherwise acquire any property of any kind whatsoever other than in the ordinary course of business; provided, however, that no such action involving an expenditure of $ 5,000 or more by Seller shall be taken by Seller without Purchaser's prior written consent; (iv) mortgage, encumber or pledge any of the Transferred Assets; (v) operate the Transferred Assets except diligently and in the usual, regular and ordinary manner, consistent with past practices; or (vi) commit itself to do any of the foregoing. 12 14 5.1.2 OPERATION OF PROPERTIES. Except as may be expressly permitted hereunder or as set forth in any Schedule hereto, from the date hereof until the Closing without first obtaining the Written consent of Purchaser (which consent will not be unreasonably withheld), Seller will not: (i) waive any right of material value relating to any of the Transferred Assets; (ii) release or abandon any material part of any of the Transferred Assets; (iii) convey, farm out or otherwise dispose of Transferred Assets with a fair market value exceeding either $5,000 on an individual basis or $5,000 in the aggregate; (iv) commence or consent to any material operations on any Property that it has not previously committed to and that may be expected to cost Seller in excess of $5,000 (except for emergency operations, in which case Seller shall promptly notify Purchaser and from the date of Purchaser's response to such notice Seller shall once again be subject to the limitations contained in this clause (iv)); (v) enter into, modify or terminate any Contracts or Lease; or (vi) commit itself to do any of the foregoing; provided, however, that nothing contained in this Section 5.1.2 or elsewhere in this Agreement shall limit the rights of Seller to produce, consume and sell Hydrocarbons from the Properties in the ordinary course of business and to comply with requirements of the NGA, the NGPA and any rules or regulations issued thereunder. 5.1.3 CERTAIN COVENANTS WITH RESPECT TO THE TRANSFERRED ASSETS. Except as may otherwise be expressly provided herein, Seller will, from the date hereof to the Closing, unless otherwise consented to in writing by Purchaser (which consent will not be unreasonably withheld): (i) promptly notify Purchaser of the receipt of any written notice or written claim or written threat of notice or claim of which Seller becomes aware relating to any default or breach under, or of any termination or cancellation or written threat of termination or cancellation of, any of the Leases, Properties or Material Contracts; (ii) promptly notify Purchaser of any loss of or damage to any portion of the Transferred Assets exceeding $5,000 in amount; (iii) cause to be paid all rentals shut-in royalties, minimum royalties and other payments that are necessary to maintain in force its rights in and to the Properties, and pay timely all costs and expenses incurred by it in connection with the Properties, except such costs and expenses as are being contested in good faith; and (iv) as to the Properties, use its Best Efforts to maintain and operate the Properties in accordance with all applicable Legal Requirements (to the extent consistent with customary practices in the oil and gas industry), in accordance with the Contracts 13 15 relating thereto, and in substantially the same manner that Seller hereto has operated such properties. 5.1.4 ACCESS. Seller will afford to Purchaser and its authorized representatives upon reasonable notice, reasonable access from the date hereof until the Closing Date, during normal business hours, to its personnel, financial data properties, books and records which are related to the Transferred Assets to the extent that such access and disclosure would not unreasonably interfere with the normal operation of the business of Seller or violate the terms of any agreement by which Seller is bound or any applicable Legal Requirement; provided, however, that the confidentiality of any data or information so acquired shall be maintained by Purchaser and its representatives in accordance with Section 5.2.4. 5.1.5 BEST EFFORTS. Seller will use its Best Efforts to obtain the satisfaction of the conditions to Closing set forth in Section 7.1. 5.1.6 PUBLIC ANNOUNCEMENTS. Except for communications with its partners, Seller shall not issue any public announcement or statement with respect to the transactions contemplated hereby except upon the consent of Purchaser or upon the advice of counsel that such announcement or statement is legally required; provided, however, that Seller shall, if practical under the circumstances, consult with Purchaser prior to issuing any such public announcement or statement. 5.1.7 PERMISSIONS. Seller will cooperate with Purchaser and take all action reasonably necessary (i) to obtain all such permissions, approvals and consents by Governmental Authorities and others as may be required to consummate the transactions contemplated in this Agreement and (ii) to obtain the transfer to Purchaser of any and all operating rights held by Seller. 5.2 COVENANTS OF PURCHASER. Purchaser covenants and agrees with Seller as follows: 5.2.1 BEST EFFORTS. Purchaser will use its Best Efforts to obtain the satisfaction of the conditions to Closing set forth in Section 7.2. 5.2.2 PUBLIC ANNOUNCEMENTS. Purchaser shall not issue any public announcement or statement with respect to the transactions contemplated hereby except upon the consent of Seller or upon the advice of counsel that such announcement or statement is legally required; provided, however, that Purchaser shall, if practical under the circumstances, consult with Seller prior to issuing any such public announcement or statement. 5.2.3 CONFIDENTIAL INFORMATION. In the event that this Agreement is terminated or, if not terminated, until the Closing, the confidentiality of any data or information received by Purchaser regarding the business and assets of Seller shall be maintained by Purchaser and its representatives in accordance with the Confidentiality Agreement that was executed by Purchaser. 5.2.4 USE OF TRADE NAMES. After the Closing, Purchaser shall not use any logos, trademarks or trade names belonging to Seller, and will, a soon as reasonably practicable after the Closing, remove any such trade names from all signs or labels on the Transferred Assets. 14 16 ARTICLE VI INSPECTION OF TITLE MATTERS 6.1 TITLE DEFECTS. (a) Any Encumbrances that individually or in the aggregate with other defects could cause the title of Seller in any Property described in Exhibit A to be less than Defensible Title shall be a title defect ("Title Defect"). Purchaser shall be entitled to the remedies set forth in Section 6.3 for any matter that constitutes a Title Defect even though Purchaser could but for this provision, after Closing obtain indemnification for such matter pursuant to Section 10.2. (b) Any circumstances or condition that could operate to cause (i) the Net Revenue Interest of Seller to increase above that set forth on Exhibit A without an increase in the Working Interest of Seller, or (ii) the Working Interest of Seller to decrease below that set forth on Exhibit A without a decrease in the Net Revenue Interest of Seller, shall be a title benefit ("Title Benefit"). 6.2 NOTICE OF TITLE DEFECTS AND TITLE BENEFITS. (a) From time to time during the period from the date of execution of this Agreement until seven (7) days prior to the Closing Date (the "Title Examination Period"), Purchaser shall have the right (but not the obligation) to notify Seller of any Title Defect of which Purchaser becomes aware, providing in such notice a reasonably detailed description of such Title Defect. If the Closing Date is extended beyond the Closing Date stated herein in accordance with the provisions hereof, then the Title Examination Period shall be extended for a similar and parallel length of time. With respect to each notice of a Title Defect given during such period, Seller may, but shall have no obligation to, attempt to cure such Title Defect prior to Closing. Purchaser's failure to give notice of a Title Defect shall not impair Purchaser's rights under any express warranty or indemnification made by Seller under this Agreement or the Instruments of Transfer. (b) From time to time during the Title Examination Period, Purchaser shall notify Seller of any Title Benefits of which Purchaser becomes aware and Seller shall have the right (but not the obligation) to notify Purchaser of any Title Benefit of which they become aware. The value of any such Title Benefits shall be mutually agreed upon by Purchaser and Seller, taking into consideration the allocated value of the Property (as set forth on allocation of the Purchase Price) subject to the Title Benefit, the portion of the Property subject to the Title Benefit, the legal effect of the Title Benefit and the anticipated economic effect of the Title Benefit over the life of the Property subject to such Title Benefit. 6.3 REMEDIES FOR TITLE DEFECTS. In the event that any Title Defects is not cured on or before Closing, Purchaser may. at its own election, (a) waive such Title Defect, (b) elect to terminate this Agreement pursuant to Section 9.1, or (c) reduce the Purchase Price by an amount mutually agreed upon by Purchaser and Seller as being the value of such Title Defect, taking into consideration the allocated value of the Property subject to the Title Defect, the portion of the Property subject to the Title Defect, the legal effect of the Title Defect on the Property and the liability of Purchaser relative to the allocated liabilities related to the Property and/or whether the Title Defect is applicable to a portion of the Property that is not encumbered by the allocated liability, and the anticipated economic effect of the Title Defect 15 17 over the life of the Property subject to the Title Defect (including the potential amount of reduction of discounted present net worth of net future cash flow on account of such Title Defect), subject to offset for the value of Title Benefits. If the parties are unable to agree as to the amount of any adjustment under Section 6.3 (c), either party may terminate this Agreement. Notwithstanding anything to the contrary in this Section 6.3, in no event shall the reduction in the Purchase Price for all Title Defects affecting any Property exceed the allocated value of such Property. 6.4 SELLER'S WARRANTY OF TITLE. The Conveyances shall contain a special warranty of title whereby Seller binds and obligates itself, its successors and assigns, to warrant and forever defend unto Purchaser, its successors and assigns, title to the Properties and other tangible Transferred Assets against all persons lawfully claiming or to claim the same or any part thereof by, through or under Seller, but not otherwise, together with full subrogation of Purchaser, to the extent that Seller is entitled to grant such subrogation, to all representations and warranties of any predecessors of Seller in title. ARTICLE VII CONDITIONS TO CLOSING 7.1 CONDITIONS TO THE OBLIGATIONS OF PURCHASER. The obligations of Purchaser to proceed with the Closing contemplated hereby are subject to the satisfaction on or prior to the Closing of all of the following conditions, any one or more of which may be waived, in whole or in part, in writing by Purchaser: 7.1.1 COMPLIANCE. Except as otherwise contemplated or permitted herein, the representations and warranties made herein by Seller shall be correct at and as of the Closing as though such representations and warranties were made at and as of the Closing, and Seller shall have complied with all the covenants and other agreements hereof required by this Agreement to be performed by it at or prior to the Closing. 7.1.2 OFFICER'S CERTIFICATES. Purchaser shall have received certificates, dated the Closing Date, of an executive officer of Seller certifying as to the matters specified in Section 7.1.1. 7.1.3 NO ORDERS. The Closing hereunder shall not violate any order or decree of any Governmental Authority having competent jurisdiction over the transactions contemplated by this Agreement; provided, however, that if such order or decree is a temporary restraining order or other ex parte order or decree and all other conditions precedent to Closing have been satisfied or waived, the Closing Date shall be extended to a date five (5) business days subsequent to the date on which such temporary restraining order or other ex parte order or decree ceases to be in effect. 7.1.4 CONSENTS TO ASSIGNMENTS. Seller shall have delivered to Purchaser satisfactory consents to the assignment of the Leases and Contracts. 7.1.5 TITLE OPINION. Purchaser shall have received within ten (10) business days prior to Closing a title opinion in a form reasonably satisfactory to Purchaser, from Purchaser's special title opinion counsel relating to the Transferred Assets. 7.1.6 DAMAGE TO TRANSFERRED ASSETS. Purchaser's obligation to purchase the Seller's interest in the Transferred Assets is conditioned upon the absence of any material damage, destruction or loss to, 16 18 or of, the platform, platform equipment pipelines, tankage or related surface equipment, included as part of the Transferred Assets that has not been covered by insurance. 7.1.7 FRENCH CLOSING. Purchaser's obligation to purchase the Seller's interest in Transferred Assets is conditioned upon Purchaser's closing on the purchase of at least seventy-five percent (75%) of the Working Interest in the Leases pursuant to that certain Asset Purchase Agreement between Purchaser and Pelham, Inc., et al., dated May 15, 1995. 7.2 CONDITIONS TO THE OBLIGATIONS OF SELLER. The obligation of Seller to proceed with the Closing contemplated hereby is subject to the satisfaction on or prior to the Closing of all of the following conditions, any one or more of which may be waived, in whole or in part, in writing by Seller: 7.2.1 COMPLIANCE. Except for such breaches of representations or warranties by and covenants of Purchaser made herein as would not have a material adverse effect on the business, financial condition and results of operations of Purchaser, taken as a whole, the representations and warranties made herein by Purchaser shall be correct at and as of the Closing as though such representations and warranties were made at and as of the Closing, and Purchaser shall have complied with all the covenants and other agreements required by this Agreement to be performed by it at or prior to the Closing. 7.2.2 OFFICER'S CERTIFICATE. Seller shall have received a certificate dated the Closing Date of an executive officer of Purchaser, certifying as to the matters specified in Section 7.2.1. 7.2.3 NO ORDERS. The Closing hereunder shall not violate any order or decree of any Governmental Authority having competent jurisdiction over the transactions contemplated by this Agreement; provided, however, that if such order or decree is a temporary restraining order or other ex parte order or decree and all other conditions precedent to Closing have been satisfied or waived, the Closing Date shall be extended to a date five (5) business days subsequent to the date on which the temporary restraining order or such other ex parte order or decree ceases to be in effect. 7.2.4 APPROVAL BY PARTNERS. Seller shall have received the affirmative vote of at least 75% of the Seller's partners to ratify and approve this agreement and the transactions contemplated hereby. ARTICLE VIII TAX MATTERS 8.1 LIABILITY FOR TAXES. 8.1.1 SELLER. Seller shall be liable for (i) all Taxes for any taxable period ending on or before the Effective Time, (ii) any income taxes which are imposed on the gain recognized by Seller on the sale of the Transferred Assets pursuant to this Agreement, (iii) the portion that is determined as described in Section 8.1.4, of any Taxes (other than Taxes described in clause (ii) above) for any taxable period beginning before and ending after the Effective Time and that is allocable to the portion of such period occurring on or before the Effective Time (the "Seller Period") and (iv) any sales, use, transfer or similar taxes arising from the transactions contemplated in this Agreement. 17 19 8.1.2 PURCHASER. Purchaser shall be liable for all Taxes attributable to the Transferred Assets and arising after the Effective Time. 8.1.3 INDEMNITY. Seller shall indemnify and hold Purchaser harmless from any liability for amounts for which Seller is liable pursuant to Section 8.1.1. Purchaser shall indemnify and hold Seller harmless from any liability for amounts for which Purchaser is liable pursuant to Section 8.1.2. The amount of any indemnity under this Section 8.1.3 shall include any additional amount necessary to indemnify the recipient of the indemnity payment against any taxes imposed, and any attorneys' fees or other litigation costs incurred, in connection with such indemnity payment. 8.1.4 AD VALOREM TAXES. Whenever it is necessary for purposes of Section 8.1.1 to determine the portion of any Taxes for a taxable period beginning before and ending after the Effective Time, which portion is allocable to the Seller Period, the determination shall be made for ad valorem Taxes, on a per diem basis and for other Taxes, on the assumption that the Seller Period constitutes a separate taxable period and by taking into account the actual taxable events occurring during such period (except that exemptions, allowances and deductions for a taxable period beginning before and ending after the Effective Time that are calculated on an annual or periodic basis, such as the deduction for depreciation, shall be apportioned to the Seller Period on a per diem basis). 8.1.5 REFUNDS. If any Seller or Purchaser or any affiliate of a Seller or Purchaser receives (whether by payment, credit, offset or otherwise) a refund in respect of any Taxes for which the other party is liable under Section 8.1.1 or 8.1.2, the party receiving such refund shall, within thirty (30) days after receipt of such refund, remit it to the party liable for the Taxes with respect to which the refund was received. The parties shall cooperate with each other in taking all necessary steps to claim any such refund. 8.1.6 ADJUSTMENT. For purposes of this Section 8.1, the amount of any downward adjustment to the Purchase Price pursuant to Section 1.3.1(ii)(b) shall be treated as a payment by Seller of ad valorem taxes imposed with respect to the Transferred Assets for 1994. 8.2 COOPERATION AND EXCHANGE OF INFORMATION. Seller or Purchaser will provide, or cause to be provided, to the other party copies of all correspondence received from any taxing authority by such party or any of its affiliates in connection with the liability for Taxes for any period for which such other party is or may be liable under Section 8.1.1 or 8.1.2. The parties will provide each other with such cooperation and information as they may reasonably request of each other in preparing or filing any return, amended return or claim for refund, in determining a liability or a right to refund or in conducting any audit or other proceeding in respect of Taxes imposed on the parties or their respective affiliates. The parties and their affiliates will preserve and retain all returns, schedules, work papers and other documents relating to any such returns, claims, audits or other proceedings until the expiration of the statutory period of limitations (with regard to waivers and extensions) of the taxable periods to which such documents relate and until the final determination of any payments which may be required with respect to such periods under this Agreement and shall make such documents available to representatives of the other party upon reasonable notice and at reasonable times, it being understood that such representatives shall be entitled to make copies of any such books and records as they shall deem necessary. Seller or Purchaser further agree to permit representatives of the other party to meet with employees of such party on a mutually convenient basis in order to enable such representatives to obtain additional information and explanations of any documents provided pursuant to this Section 8.2. Seller or Purchaser shall make available to the representatives of the other party at the then current administrative 18 20 headquarters of such party sufficient work space and facilities to perform the activities described in the two preceding sentences. Any information obtained pursuant to this Section 8.2 shall be kept confidential, except as may be otherwise necessary in connection with the filing of returns or claims for refund or in conducting any audit or other proceeding. Each party shall provide the cooperation and information required by this Section 8.2 at its own expense. 8.3 PAYMENT OF TAXES. 8.3.1 PAYMENT. All Taxes shall be paid by the party that, on the date that such Taxes are required to be paid, is legally responsible to pay such Taxes. 8.3.2 TIME OF PAYMENT. Except as otherwise provided in this Article VIII or in Section 1.3, any amount to which a party is entitled under this Article VIII shall be promptly paid to such party by the party obligated to make such payment following written notice to the party so obligated that the Taxes to which such amount relates are due and that provides details supporting the calculation of such amount. 8.4 SURVIVAL OF OBLIGATIONS. The obligations of the parties set forth in this Article VIII shall be unconditional and absolute and shall remain in effect without limitation as to time. 8.5 CONFLICT. In the event of a conflict between the provisions of this Article VIII and any other provisions of this Agreement, the provisions of this Article VIII shall control. ARTICLE IX TERMINATION 9.1 GROUNDS FOR TERMINATION. This Agreement may be terminated at any time prior to the Closing: (i) by the mutual written agreement of Seller and Purchaser; (ii) by Seller or Purchaser, if the consummation of the transactions contemplated hereby would violate any nonappealable final order, decree or judgment of any Governmental Authority having competent jurisdiction enjoining, restraining or otherwise preventing the consummation of this Agreement or the transactions contemplated hereby; provided, however, that a party shall not be allowed to exercise any right of termination pursuant to this Section 9.1(ii) if the event giving rise to such right shall be due to the negligent or willful failure of such party to perform or observe in any material respect any of the covenants or agreements set forth herein to be performed or observed by such party; (iii) by Purchaser or Seller if the Closing shall not have occurred prior to 5:00 p.m., December 31, 1995; provided, that the Closing was not delayed as a result of the negligent or willful failure of the terminating party's obligation to perform hereunder; (iv) by Seller or Purchaser if the non-terminating party has breached its representations and warranties, defaulted in the performance of its covenants or not satisfied its conditions to Closing; 19 21 (v) by Purchaser, or by Seller, as provided in Section 6.3; or (vi) by Seller, if there is a breach of any representation or warranty under Section 3.10 and the cost of curing such breach would exceed $500,000 and such breach is not waived by Purchaser. 9.2 EFFECT OF TERMINATION. The following provisions shall apply in the event of a termination of this Agreement: 9.2.1 NO LIABILITY. If this Agreement is terminated as permitted under Section 9.1 (i), (ii), (iii), (v) or (vi), such termination shall be without liability of any party to this Agreement or any affiliate, shareholder, director, officer, employee, agent or representative of such party and Seller shall return to Purchaser the Initial Payment. In such event, the representation contained in the second sentence of Section 4.2 shall be of no effect. 9.2.2 PURCHASER'S LIABILITY. If this Agreement is terminated by Seller, as permitted under Section 9.1 (iv), Seller shall retain the Initial Payment, as Seller's sole remedy, and Purchaser shall have no further obligation to Seller for failure to close the transaction. 9.2.3 SELLER'S LIABILITY. If this Agreement is terminated by Purchaser, as permitted under Section 9.1 (iv), Purchaser's sole remedy shall be the right to seek specific performance of Seller's obligation to sell to Purchaser the Transferred Assets in complete satisfaction of any other damages, thereby sustained or incurred by Purchaser. 9.2.4 SURVIVAL. Notwithstanding the foregoing, the provisions of this Article IX and Section 5.2.3 shall survive any termination of this Agreement. ARTICLE X EXTENT AND SURVIVAL OF REPRESENTATIONS AND WARRANTIES; INDEMNIFICATION 10.1 SCOPE OF REPRESENTATIONS OF SELLER. Except as and to the extent expressly set forth herein, Seller makes no representations or warranties whatsoever, and disclaim all liability and responsibility for any representation, warranty, statement or information made or communicated (orally or in writing) to Purchaser (including, but not limited to, any opinion, information or advice that may have been provided to Purchaser by any affiliate, officer, stockholder, director, employee, agent, consultant or representative of Seller, any petroleum engineer or engineering firm, Seller's counsel or any other agent, consultant or representative). Without limiting the generality of the foregoing, except as and to the extent expressly set forth herein and in the Instruments of Transfer, Seller makes no representations or warranties as to (i) the title to any of the properties of Seller, (ii) the amounts of Hydrocarbon reserves attributable to such properties or (iii) any geological or other interpretations or economic evaluations. Purchaser acknowledges and affirms that it has had full access to the records of Seller and the information contained in, or made available or provided with respect to materials contained in, the records of Seller, and that Purchaser has made its own independent investigation, analysis and evaluation of the Transferred Assets, (including its own estimate and appraisal of the extent and value of Seller's Hydrocarbon reserves). Notwithstanding the foregoing, to the Knowledge of Seller, the information contained in the records of Seller and information otherwise made available or furnished in writing to Purchaser by Seller with respect to the Transferred Assets does not contain any untrue 20 22 statement of a material fact or omit to state any material fact that would make such information not false or misleading. 10.2 INDEMNIFICATION OF PURCHASER. Seller agrees (i) to indemnify Purchaser against, and hold Purchaser harmless from. any loss. damage or expense (including reasonable attorneys' fees) sustained by Purchaser arising out of or resulting from any inaccuracy in or breach of any of the representations, warranties or covenants made by Seller in this Agreement, (ii) to pay, perform, fulfill and discharge all costs, expenses and liabilities incurred in connection with the Transferred Assets prior to the Closing Date with respect to the ownership or operation of the Transferred Assets prior to the Closing Date and (iii) to indemnify, defend and hold Purchaser harmless from and against any and all claims, losses, damages, costs, expenses, causes of action and judgments of any kind or character with respect to all liabilities, including the Retained Liabilities, arising out of or in connection with the ownership or operation of the Transferred Assets prior to the Closing Date, including, without limitation, any interest, penalty and other costs and expenses incurred in connection therewith or the defense thereof (provided that any loss, damage or expense sustained by Purchaser arising out of or resulting from any breach or violation of Section 3.10 shall be governed by Section 10.4); provided, however, that Purchaser shall not be entitled to assert rights of indemnification under this Section 10.2 or Section 10.4 unless and until the aggregate of all such losses exceeds $25,000 (it being understood that such losses shall accumulate until such time or times as the aggregate of all such losses exceeds $25,000, whereupon Purchaser shall be entitled to indemnification under this Section 10.2 or Section 10.4 for any such losses); and provided, further, that the maximum aggregate of all losses for which Purchaser shall be entitled to indemnification by any Seller, whether under this Section 10.2, Section 10.4 or otherwise, shall not exceed such Seller's share of the Purchase Price. 10.3 INDEMNIFICATION OF SELLER. Purchaser agrees (i) to indemnify Seller against, and hold Seller harmless from, any loss, damage or expense (including reasonable attorneys' fees) sustained by Seller arising out of or resulting from any inaccuracy in or breach of any of the representations, warranties or covenants made by Purchaser in this Agreement, (ii) to pay, perform, fulfill and discharge all costs, expenses and liabilities incurred from and after the Closing Date with respect to the ownership or operation of the Transferred Assets from and after the Closing Date and (iii) to indemnify, defend and hold Seller harmless from and against any and all claims, losses, damages, costs, expenses, causes of action and judgments of any kind or character with respect to all liabilities to third parties arising out of or in connection with the ownership or operation of the Transferred Assets from and after the Closing Date, including, without limitation, any interest, penalty and other costs and expenses incurred in connection therewith or the defense thereof (provided that any loss, damage or expense sustained by Seller arising out of or resulting from any breach or violation of Article VIII shall be governed by those provisions); provided. however, that Seller shall not be entitled to assert rights of indemnification under this Section 10.3 unless and until the aggregate of all such losses exceeds $25,000 (it being understood that such losses shall accumulate until such time or times as the aggregate of all such losses exceeds $25,000, whereupon Seller shall be entitled to indemnification under this Section 10.3 for any such losses). 10.4 ENVIRONMENTAL INDEMNITY. (a) Subject to the financial limitations regarding the indemnity of Seller described in Section 10.2, Seller agrees, during the Environmental Indemnity Period, to indemnify and save Purchaser harmless from and against, and to reimburse Purchaser with respect to, any and all claims, demands, losses, damages, liabilities, causes of action, judgments, penalties, costs and 21 23 expenses (including, without limitation, reasonable legal fees and expenses, clean-up costs and disbursements) accrued or incurred by Purchaser at any time and from time to time, during the Environmental Indemnity Period by reason of (i) the breach of any representation or warranty of Seller as set forth in Section 3.10, (ii) any violation with respect to or affecting the Transferred Assets on or before the Closing Date of any Environmental Laws in effect on or before the Closing Date, (iii) the clean-up of the Transferred Assets required under Environmental Laws for any activities prior to the Closing Date, (iv) any act, omission, event or circumstance existing or occurring on or prior to the Closing Date (including without limitation, the presence on the Properties of Hazardous Substances or the presence off site of Hazardous Substances generated on the Properties, on or prior to the Closing Date) that result from or that are in connection with the ownership, construction, occupancy, operation, use and/or maintenance of the Properties, regardless of whether the act, omission, event or circumstance constituted a violation of any Environmental Laws at the time of its existence or occurrence, and (v) any and all claims or proceedings (whether brought by private party or Governmental Authority) for bodily injury, property damage, abatement or remediation, environmental damage or impairment or any other injury or damage resulting from or relating to any Hazardous Substances located upon the Properties prior to the Closing Date. Seller shall also indemnify and hold Purchaser harmless from and against any liability, loss, cost or expense, including reasonable attorneys' fees and expenses, arising from or relating to the imposition or recording of a lien on the Properties in connection with any contamination of the Properties or pursuant to any Environmental Laws in the event only that such contamination occurred prior to the Closing Date. Seller shall also hold harmless, and indemnify Purchaser from any liability incurred by Purchaser arising out of regulatory action or third-party, claims with respect to contamination of the Properties or offsite locations that occurred prior to the Closing Date. (b) Notwithstanding anything contained in this Agreement to the contrary, the indemnities in this Section 10.4 shall survive the Closing Date only until the end of the Environmental Indemnity Period, and shall be limited in scope only to any activities discovered after the Closing Date but before the end of the Environmental Indemnity Period that occurred before the Closing Date. For all purposes with respect to the Transferred Assets, Purchaser agrees that it shall have the burden of proof that any alleged activities, violations, events or conditions occurred before the Closing Date. (c) Seller shall have the right to control any action for which indemnity is required under this Section 10.4 through counsel of its choice, subject to Purchaser's consent, which shall not be unreasonably withheld or delayed, provided, however, at Purchaser's option, Purchaser may participate in such action and appoint its own counsel. If Seller does not notify Purchaser in writing of its intent to control such action within thirty (30) days (or five (5) days less than such lesser time as may be required to respond to such claims) after receipt by Seller of written notice of such claims, Purchaser shall have the right to undertake the control, conduct or settlement of such claims through its own counsel at Seller's expense and may settle such matter without Seller's consent at its sole expense. In the event any proposed settlement includes non-monetary relief, including clean-up, Purchaser may agree to such clean-up and settle such matter only with the consent of Seller, which consent shall not be unreasonably withheld or delayed; provided, however, if Seller fails to respond to such a notification by Purchaser regarding such non-monetary relief within ten (10) days after Purchaser's notification to Seller, Seller shall be deemed to have consented to such non-monetary relief. 22 24 (d) Purchaser agrees that the rights and remedies provided in this Section 10.4 shall be the exclusive rights and remedies available to it for any matter within the scope of Section 10.4 and that the general indemnification provisions of Section 10.2 and any other rights or remedies of Purchaser with respect to the Seller for any matter within the scope of Section 10.4, whether provided in this Agreement, at law or in equity, shall not be applicable and are hereby waived. Nothing in this Section 10.4 or elsewhere in this Agreement shall limit or impair any rights or remedies of Purchaser against any third party under any Environmental Laws, including, without limitation, any rights of contribution or indemnification available hereunder. (e) Any indemnification provided in this Section 10.4 shall terminate at the end of the Environmental Indemnity Period, following which the Purchaser agrees not to institute any action or claim for indemnification or other recovery with respect to the matter within the scope of Section 10.4; provided, however, that the expiration of the Environmental Indemnity Period shall be extended as to any bona fide claim for indemnification within the scope or Section 10.4, solely to the extent that Purchaser asserted such claim according to the procedures provided in Section 10.5 and Section 10.6, if the Purchaser shall have transmitted the Claim Notice with respect to such claim to the Seller prior to the expiration of such Environmental Indemnity Period. 10.5 SURVIVAL. The representations and warranties set forth in this Agreement (other than those set forth in Article VIII) shall survive until the second anniversary of the Closing Date, following which date none of the parties may bring any action or present any claim for a breach of such representations and warranties; provided, however, that there shall be no termination of any representation or warranty as to which a bona fide claim has been asserted if the Indemnified Party shall have transmitted the Claim Notice with respect thereto prior to the anniversary of the Closing Date. The representations and warranties set forth in 3.8.2 shall remain terminate in accordance with the terms of Article VIII shall terminate in accordance with the terms of Article VIII. 10.6 INDEMNIFICATION PROCEDURES. All claims for indemnification under this Agreement (other than claims for indemnification under Article VIII) shall be asserted and resolved as follows: 10.6.1 NOTICE. An Indemnified Party shall promptly (i) notify an Indemnifying Party of any Third-Party Claim asserted against the Indemnified Party and (ii) transmit to the Indemnifying Party a Claim Notice relating to such Third-Party Claim, a copy of all papers served with respect to such claim (if any), an estimate of the amount of damages attributable to the Third-Party Claim and the basis of the Indemnified Party's request for indemnification under this Agreement. During the Election Period, an Indemnifying Party shall notify an Indemnified Party (a) whether the Indemnifying Party disputes its potential liability to the Indemnified Party under this Article X with respect to such Third-Party Claim and (b) whether an Indemnifying Party desires, at the sole cost and expense of such Indemnifying Party, to defend the Indemnified Party against such Third-Party Claim. 10.6.2 DEFENSE BY INDEMNIFYING PARTY. If an Indemnifying Party notifies an Indemnified Party within the Election Period that the Indemnifying Party does not dispute its potential liability to the Indemnified Party under this Article X and that the Indemnifying Party elects to assume the defense of the Third-Party Claim, then the Indemnifying Party shall have the right to defend, at its sole cost and expense, such Third-Party Claim by all appropriate proceedings, which proceedings shall be prosecuted diligently by the Indemnifying Party to a final conclusion or settled at the discretion of the Indemnifying Party in accordance with this Section 10.6.2. The Indemnifying Party shall have full control of such 23 25 defense and proceedings, including any compromise or settlement thereof; provided, however, that any settlement entailing non-monetary consideration must be approved, in advance, by the Indemnified Party, which approval shall not be unreasonably delayed or withheld. The Indemnified Party is hereby authorized, at the sole cost and expense of the Indemnifying Party (but only if the Indemnified Party is actually entitled to indemnification hereunder or if the Indemnifying Party assumes the defense with respect to the Third-Party Claim), to file, during the Election Period, any motion, answer or other pleadings which the Indemnified Party shall deem necessary or appropriate to protect its interests or those of the Indemnifying Party and not prejudicial to the Indemnifying Party (it being understood and agreed that if an Indemnified Party takes any such action that is prejudicial and conclusively causes a final adjudication adverse to the Indemnifying Party, the Indemnifying Party shall be relieved of its obligations hereunder with respect to such Third-Party Claim). If requested by the Indemnifying Party, the Indemnified Party agrees, at the sole cost and expense of the Indemnifying Party, to cooperate with the Indemnifying Party and its counsel in contesting any Third-Party Claim that the Indemnifying Party elects to contest, including, without limitation, the making of any related counterclaim against the person asserting the Third-Party Claim or any cross-complaint against any person. The Indemnified Party may participate in, but not control, any defense or settlement of any Third-Party Claim controlled by the Indemnifying Party pursuant to this Section 10.6, and shall bear its own costs and expenses with respect to any such participation. 10.6.3 DEFENSE BY INDEMNIFIED PARTY. If an Indemnifying Party fails to notify an Indemnified Party within the Election Period that the Indemnifying Party elects to defend the Indemnified Party pursuant to Section 10.6.2, or if the Indemnifying Party elects to defend the Indemnified Party pursuant to Section 10.2 but fails diligently and promptly to prosecute or settle the Third-Party Claim, then the Indemnified Party shall have the right to defend, at the sole cost and expense of the Indemnifying Party, the Third-Party Claim by all appropriate proceedings, which proceedings shall be diligently prosecuted by the Indemnified Party to a final conclusion or settled. The Indemnified Party shall have full control of such defense and proceedings; and provided, however, that without the Indemnifying Party's consent, which consent shall not be unreasonably delayed or withheld, the Indemnified Party shall not be authorized by the Indemnifying Party to enter into any compromise or settlement of such Third Party Claim on any non-monetary basis; and provided further, however, that if requested by the Indemnified Party, the Indemnifying Party shall, at the sole cost and expense of the Indemnifying Party, cooperate with the Indemnified Party and its counsel in contesting any Third-Party Claim that the Indemnified Party is contesting, or, if appropriate and related to the Third-Party Claim in question, in making any counterclaim against the person asserting the Third-Party Claim or any cross-complaint against any person. Notwithstanding the foregoing, if the Indemnifying Party has delivered a written notice to the Indemnified Party to the effect that the Indemnifying Party disputes its potential liability to the Indemnified Party under this Article X and if such dispute is resolved in favor of the Indemnifying Party by a final, nonappealable order of a court of competent jurisdiction, the Indemnifying Party shall not be required to bear the costs and expenses of the Indemnified Party's defense pursuant to this Section 10.6 or of the Indemnifying Party's participation therein at the Indemnified Party's request, and the Indemnified Party shall reimburse the Indemnifying Party in full for all costs and expenses of such litigation. The Indemnifying Party may participate in, but not control, any defense or settlement controlled by the Indemnified Party pursuant to this Section 10.6, and the Indemnifying Party shall bear its own costs and expenses with respect to any such participation. 10.6.4 OTHER CLAIMS. In the event any Indemnified Party should have a claim against any Indemnifying Party hereunder that does not involve a Third-Party Claim, the Indemnified Party shall transmit to the Indemnifying Party an Indemnity Notice with respect to such claim. If the Indemnifying 24 26 Party does not notify the Indemnified Party in writing within sixty (60) days from its receipt of the Indemnity Notice that the Indemnifying Party disputes such claim, the claim specified by the Indemnified Party in the Indemnity Notice shall be deemed a liability of the Indemnifying Party hereunder. If the Indemnifying Party has timely disputed such claim, as provided above, such dispute shall be resolved by binding arbitration. 10.7 TAX BENEFITS, INSURANCE PROCEEDS AND INDEMNIFICATION PAYMENTS. In determining the amount of any loss, liability or expense for which an Indemnified Party is entitled to indemnification under this Article X, the gross amount thereof will be reduced by any correlative insurance proceeds, if any, realized or to be realized by such Indemnified Party, and such correlative insurance benefit shall be net of any insurance premium that becomes due as a result of such claim. 10.8 TAX ON INDEMNIFICATION PAYMENTS. After taking into account any adjustment required by Section 10.6, the amount of each payment by an Indemnifying Party under Section 10.2 and Section 10.3 shall include any additional amount necessary to indemnify the Indemnified Party against any taxes imposed in connection with such payment. ARTICLE XI BROKERS Seller has retained Reid Investments Inc. to assist and advise it in connection with the transactions contemplated by this Agreement Seller will be responsible for any fees payable to Reid. Purchaser and Seller represent to the other that, except as set forth in the preceding sentence, neither has, directly or indirectly, employed any broker, finder or intermediary in connection with such transactions that might be entitled to a fee or commission for which the other party shall have any obligation or responsibility upon the execution of this Agreement or the consummation of such transactions. ARTICLE XII EXPENSES Except as specifically provided herein, all legal and other costs and expenses in connection with this Agreement and the transactions contemplated hereby shall be paid by the party that incurred such costs and expenses. ARTICLE XIII NOTICES; MISCELLANEOUS 13.1 NOTICES. All notices and other communications given hereunder shall be in writing and shall be deemed given if delivered personally, including delivery by a nationally recognized courier service, or mailed by registered or certified mail, return receipt requested, to the parties at the following addresses: 25 27 (i) If to Purchaser, to: Goldking Trinity Bay Corp. 1221 McKinney Suite 1800 Houston, Texas 77010 Attention: Leonard C. Tallerine, Jr. With a copy to: Looper, Reed, Mark & McGraw 9 East Greenway Plaza Suite 1717 Houston, Texas 77046 Attention: Mark Licata (ii) If to Seller to: Benton Oil & Gas Combination Partnership 1990-1, L.P. c/o Benton Oil & Gas Company 1145 Eugenia Place Carpinteria, California 93013 Attention: Clarence Cottman 13.2 MISCELLANEOUS. 13.2.1 EXCLUSIVE AGREEMENT. This Agreement supersedes all prior written or oral agreements between the parties with respect to the transactions contemplated herein, and is intended as a complete and exclusive statement of the terms of the agreement between the parties with respect to the transactions contemplated herein. 13.2.2 CHOICE OF LAW; CHOICE OF FORUM; AMENDMENTS; HEADINGS. This Agreement shall be governed by the internal laws of the State of Texas, without giving effect to principles of conflicts of laws. This Agreement may not be changed or terminated orally. The headings contained in this Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement. Terms such as "herein," "hereby," "hereto" and "hereof" refer to this Agreement as a whole. The term "include" and derivatives thereof are used in an illustrative sense and not a limitative sense. 13.2.3 ASSIGNMENTS AND THIRD PARTIES. No party hereto shall assign this Agreement or any part hereof without the prior written consent of the other parties; provided, however, that Purchaser shall be authorized to assign this Agreement provided that no such assignment shall release Purchaser from any of its obligations under this Agreement. Except as otherwise provided herein, this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and permitted assigns. Nothing in this Agreement shall entitle any Person, other than the parties hereto or their respective permitted successors and assigns, to any claim, cause of action, remedy or right of any kind. 26 28 13.2.4 SUBSEQUENT FILINGS. Effective at the Closing Date, Purchaser shall file with General Land Office of the state of Texas and with such other Governmental Authorities such notices or certificates as are necessary to reflect the sale of the Transferred Assets to Purchaser. 13.2.5 SEVERABILITY. If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any manner materially adverse to any party. Upon any binding determination that any term or other provision is invalid, illegal or incapable of being enforced, the parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the parties as closely as possible in an acceptable and legally enforceable manner, to the end that the transactions contemplated hereby may be completed to the extent possible. 13.2.6 COUNTERPARTS. This Agreement may be executed in any number of counterparts, each of which shall be deemed to be an original and all of which together shall constitute but one and the same agreement. 13.2.7 FURTHER ASSURANCES. (i) The parties each agree to deliver or cause to be delivered to the others on the Closing Date, and at such other times thereafter as shall be reasonably requested, any additional instrument that the other may reasonably request for the purpose of carrying out this Agreement (ii) After the Closing, Seller and Purchaser shall, and shall cause their affiliates to, execute, acknowledge and deliver all such further conveyances, transfer orders, division orders, notices, assumptions, releases and acquittances, and such other instruments, and shall take such further actions as may be necessary or appropriate to assure fully to Purchaser, its successors or assigns, all of the Transferred Assets intended to be conveyed to Purchaser by the Instruments of Transfer pursuant to this Agreement, and to assure fully to Seller and its affiliates and its successors and assigns, the assumption of the liabilities and obligations intended to be assumed by Purchaser pursuant to this Agreement. 13.2.8 PRESERVATION OF BOOKS AND RECORDS. For a period of seven (7) years (five (5) years with respect to geophysical data related to the Transferred Assets) after the Closing Date, Purchaser and Seller (if and to the extent Seller has retained any of the hereinafter described records not delivered to Purchaser at Closing) shall (i) preserve and retain the corporate, accounting, legal, auditing and other books and records that relate to the conduct of Seller's businesses and operations prior to the Closing Date (including, but not limited to, any documents relating to any governmental or non-governmental actions, suits, proceedings or investigations arising out of the conduct of the business and operations of Seller prior to the Closing Date and including, but not limited to, all financial statements and other data and information necessary or desirable for Purchaser to comply with their public reporting requirements) and (ii) make such books and records available at their then current administrative headquarters to the other party and its officers, employees, agents and affiliates upon reasonable notice and at reasonable times, it being understood that such other party shall be entitled to make and retain copies of any such books and records as it shall deem necessary. Purchaser and Seller agrees to permit representatives of the other party to meet with its employees on a mutually convenient basis in order to enable such other party 27 29 to obtain additional information and explanations of any materials provided pursuant to this Section 13.2.8. IN WITNESS WHEREOF, the undersigned have executed this Agreement as of the date first written above. PURCHASER: GOLDKING TRINITY BAY CORP. By:______________________________________ Name:____________________________________ Title:___________________________________ SELLER: BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P. By:______________________________________ Name:____________________________________ Title:___________________________________ 28 30 APPENDIX A Definitions Capitalized terms used in this Agreement shall have the meanings ascribed to them in this Appendix A unless such terms are defined elsewhere in this Agreement: Agreed Interest Rate: Ten percent (10%) per year. Best Efforts: A party's best efforts in accordance with reasonable commercial practices and without the incurrence of unreasonable expense. Claim Notice: A written notice delivered by an Indemnified Party to an Indemnifying Party pursuant to Section 10.6.1 describing in reasonable detail the nature of a Third-Party Claim that could give rise to a right of indemnification under this Agreement. Claimed Interest Additions: The Interest Additions claimed by Seller on the list to be submitted to Purchaser within thirty (30) days after the date of this Agreement pursuant to Section 6.3. Closing: The closing of the transactions contemplated by this Agreement. Closing Date: The date of the Closing. Code: The Internal Revenue Code of 1986, as amended. Data Rooms: The data rooms prepared by Seller to provide information to Persons considering the acquisition of the Transferred Assets. Defensible Title: Such title to the Transferred Interests, free and clear of all Encumbrances other than Permitted Encumbrances, that is deducible of record and free from reasonable doubt to the end that a prudent person engaged in the business of the ownership, development and operation of producing oil and gas properties, with knowledge of all the facts and the legal bearing of such facts and the commercial effect of such facts on the continued control and operation of the Transferred Assets, would be willing to accept such title. Effective Time: The effective time of the transfer of the Transferred Assets to Purchaser, which shall be deemed to be 7:00 a.m., Houston, Texas time, on January 1, 1995. Election Period: The 30-day period following receipt by an Indemnifying Party of a Claim Notice. Encumbrance: Any mortgage, lien, security interest, pledge, charge, encumbrance, claim, limitation, preferential right to purchase, consent to assignment, irregularity, burden or defect or any other claim that Seller does not own the Warranted Interest. Entity: A corporation, partnership, joint venture, trust or unincorporated organization or association or other entity. Environmental Laws: All federal, state and local laws relating to the protection of human health and safety or the environment, including but not limited to the federal Comprehensive Environmental Appendix A Page 1 31 Response, Compensation, and Liability Act, the Resource Conservation and Recovery Act, the Safe Drinking Water Act, the Toxic Substances Control Act, the Clean Water Act, the Coastal Zone Management Act, the Endangered Species Act, the Oil and the Hazardous Materials Transportation Act, all as amended, and all analogous state and local laws. Environmental Indemnity Period: The period beginning on the Closing Date and ending two (2) years after the Closing Date. Governmental Authority: The United States of America, any state, commonwealth, territory or possession thereof and any political subdivision of any of the foregoing, including but not limited to courts, departments, commissions, boards, bureaus, agencies or other instrumentalities. Hazardous Substance: Any substance or material now or hereafter defined as a "hazardous substance", "hazardous material", "hazardous waste", "contaminant", or "pollutant" under any environmental laws, including but not limited to Section 1.01 of the Comprehensive Environmental Response, Compensation and Liability Act, 4-2 U.S.C.A. 9601. Hydrocarbons: Oil, gas, minerals (including but not limited to sulfur) and other gaseous and liquid hydrocarbons or any combination thereof. Indemnified Party: A party claiming indemnification under this Agreement (other than a claim for indemnification under Section 10.4, Article VI or Article VIII). Indemnifying Party: A party from whom indemnification under this Agreement (other than indemnification under Section 10.4, Article VI or Article VIII) is sought. Indemnity Notice: A written notice from an Indemnified Party to an Indemnifying Party with respect to a claim for indemnification under this Agreement (other than indemnification under Section 10.4, Article VI or Article VIII) not involving a Third-Party Claim, which notice shall describe in detail the nature of the claim and set forth an estimate of the amount of damages attributable to such claim and the basis of the Indemnified Party's request for such indemnification. Initial Payment: The initial payment of the Purchase Price in the amount of FOURTEEN THOUSAND ONE HUNDRED NINETY-TWO DOLLARS ($14,192), paid by Purchaser to Seller, on the date this Agreement was executed. Knowledge: The actual knowledge of each executive officer of Seller (assuming such Seller is a corporation, and if not, a Person in a similar capacity) after reasonable inquiry, or Purchaser, as the case may be. Leases: As defined in the Instruments of Transfer. Legal Requirement: Any law, statute, ordinance, decree, requirement, order, judgment, rule or regulation of, including the terms of any license or permit issued by, any Governmental Authority. Material Adverse Effect: Any material adverse effect on or with respect to the Transferred Assets or on the business, operations, prospects or condition of the Transferred Assets, taken as a whole. Net Revenue Interest: The interest (expressed as a percentage) of Seller in and to Hydrocarbons produced from or allocated to a Property after deducting all applicable Production Burdens. Appendix A Page 2 32 NGA: The Natural Gas Act of 1938. NGPA: The Natural Gas Policy Act of 1978. Permitted Encumbrances: Any or all of the following: (i) encumbrances that arise under operating agreements to secure payment of amounts not yet delinquent and are of a type and nature customary in the oil and gas industry; (ii) encumbrances that arise as a result of pooling and unitization agreements, and production sales contracts securing the payment of amounts not yet delinquent; (iii) consents to assignment by Governmental Authorities (a) that are obtained on or prior to the Closing Date or (b) that are customarily obtained after the consummation of transactions of the nature contemplated by this Agreement; (iv) conventional rights of reassignment obligating Seller to reassign its interest in any portion of the Properties to a third party in the event it intends to release or abandon such interest prior to the expiration of the primary term or other termination of such interest; (v) easements, rights-of-way, servitudes, permits, surface leases, surface use restrictions and other surface uses and impediments on, over or in respect of any of the Properties that are not such as to interfere materially with the operation, value or use of any of the Properties; (vi) such Title Defects and Environmental Defects as Purchaser has expressly waived in writing; (viii) such Title Defects for which Purchaser failed to give timely notice according to Section 6.2; (ix) such Environmental Defects (to the extent the Purchaser has Knowledge of such Environmental Defect) for which Purchaser failed to give timely notice according to Section 6.2 or for which Purchaser failed to provide written information as required by Section 6.2; (x) rights reserved to or vested in any municipality or governmental, tribal, statutory or public authority to control or regulate any of the Properties in any manner, and all applicable laws, rules and orders of any municipality or governmental or tribal authority; (xi) all production burdens that do not operate to (A) reduce the Net Revenue Interest below the Warranted Interest or (B) increase the Working Interest above the Warranted Interest; (xii) the preferential purchase rights for which waivers have been obtained prior to the Closing Date; (xiii) the terms and conditions of the Contracts, insofar and only insofar as the Contracts do not operate to (A) reduce the Net Revenue Interest of Seller below that set forth on Exhibit A hereto, (B) increase the Working Interest of Seller above that set forth on Exhibit A hereto without a proportionate increase in the Net Revenue Interest of Seller; Appendix A Page 3 33 (xiv) any other Encumbrance affecting any portion of a Transferred Asset that individually does not materially adversely affect the operation, value or use of any such Transferred Asset; and (xv) solely during the period prior to the Closing, any Encumbrance that is released on or before Closing. Person: shall mean a corporation, an association, a partnership, an organization, a business, an individual, a government or political subdivision thereof, or a governmental agency. Production Burdens: All royalty interests, overriding royalty interests, production payments, net profits interests or other similar interests that constitute a burden on, are measured by or are payable out of the production of Hydrocarbons or the proceeds realized from the sale or other disposition thereof. Purchase Price Adjustment Amount: The net adjustment to the Purchase Price to be made pursuant to Section 1.3.1. Purchase Price Adjustment Certificate: A statement of the Purchase Price Adjustment Amount (specifying whether the Purchase Price is to be increased or decreased by such amount), which shall be certified by an officer of Seller. Seller's Affiliate: Any person that directly or indirectly, through one or more intermediaries, controls, is controlled by or is under common control with, such Seller. Subsidiary: shall mean, as to a Person, any other Person (a) more than 50% of the outstanding voting stock of which is held, directly or indirectly, by such Person, or (b) over which such Person has the power, directly or indirectly, to designate a majority of the directors thereof (if such other Person is a corporation) or the individuals exercising similar functions (if such other Person is unincorporated). Third-Party Claim: A third-party claim asserted against an Indemnified Party that could give rise to a right of indemnification under this Agreement (other than a right of indemnification under Section 10.4, Article VI or Article VIII). Transferred Assets: As defined in Section 1.1. Warranted Interests: those interests whereby a Seller is (i) entitled to receive not less than the "Net Revenue Interest" set forth on Exhibit A hereto of all oil, gas and associated liquid and gaseous Hydrocarbons produced, saved and marketed from the Properties, without reduction, throughout the productive life of such Properties and (ii) obligated to bear the percentage of the costs and expenses related to the maintenance, development and operation of the Properties in an amount not greater than the "Working Interest" set forth on Exhibit A hereto, without increase, throughout the productive life of such Properties, except increases that result in a proportionate increase in such Seller's Net Revenue Interest and increases that results from contribution requirements with respect to defaulting co-owners. Working Interest: The interest (expressed as a percentage) of a Seller in any Transferred Asset before giving effect to any applicable Production Burdens and the percentage of all costs and expenses associated with the exploration, development and operation of such Transferred Asset required to be borne by such Seller. Appendix A Page 4 34 SCHEDULE 1.2.1 INDIVIDUAL INTEREST VALUATIONS
WORKING NET REVENUE PURCHASE SELLER INTEREST INTEREST PRICE Benton Oil & Gas Combination 14.191819% 11.850164% $1,085,675.00 Partnership 1990-1-L.P., a California limited partnership
35 BILL OF SALE, CONVEYANCE AND PARTIAL ASSIGNMENT STATE OF TEXAS ) ) COUNTY OF CHAMBERS ) This Bill of Sale, Conveyance and Partial Assignment is from BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P., a California limited partnership, whose mailing address is 1145 Eugenia Place, Carpinteria, California ("Grantor"), to GOLDKING TRINITY BAY CORP., a Texas corporation ("Grantee"), whose mailing address is 1221 McKinney, Suite 1800, Houston, Texas 77002. I. NOW, THEREFORE, for and in consideration of Ten and No/100 Dollars ($10.00) and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Grantor has granted, bargained, sold, transferred, assigned and conveyed, and by these presents does hereby grant, bargain, sell, transfer, assign and convey unto Grantee, its successors and assigns, subject to the hereinafter stated exceptions, restrictions, covenants and conditions, all of Grantor's interest in and to the following described properties, to-wit: (a) the leasehold estate created by each of the Oil, Gas and Mineral Leases listed and described in Exhibit "A", which is annexed hereto and incorporated herein for all purposes, such leases being hereinafter sometimes referred to as "Subject Leases"; (b) All payments out of production, overriding royalty interests, carried interests, reversionary interests, and all other rights and interests incident to, or held and owned by Grantor in connection with the Subject Leases, save and except the overriding royalty excepted and reserved herein below by Grantor; (c) All oil, gas, condensate, casinghead gas and other related hydrocarbon substances produced and saved subsequent to the Effective Date of this conveyance from lands covered and affected by the Subject Leases. (The interest described under subparagraphs (a) and (b) above, and this subparagraph (c) are hereinafter sometimes collectively referred to as "Subject Properties"); (d) All personal property and facilities located on lands covered by the Subject Leases or the Subject Interests, or both, incident to or held and used in connection with the Subject Interests, including, but not limited to, all tanks, tank batteries, gas plants, disposal facilities, buildings, structures, platforms, field separators and liquid extractors, treators, dehydrators, compressors, pumps, pumping units, valves, fittings, machinery and parts, engines, boilers, meters, apparatus, implements, tools, appliances, cables, wires, towers, casing, tubing and rods, gathering lines or other pipelines, field gathering systems and any and all other fixtures and equipment of every type and description to the extent that the same are used or held in connection with the ownership or operation of the Subject Interests; 1 36 (e) All oil, natural gas or water source wells, whether producing, operating, shut-in, or temporarily abandoned; all types of injection wells; and all equipment used or held by Grantor in connection with the production of oil, gas, condensate, casinghead gas and other related hydrocarbon substances from or attributable to lands covered by the Subject Leases; (f) All tenements, appurtenances, surface leases, easements, permits, licenses, servitudes, or rights-of-way in any way appertaining, belonging, affixed and used in connection with, or incident to, the ownership and operation of the Subject Interests, including, but not limited to, those tenements, appurtenances, surface leases, easements, permits, licenses, servitudes or rights-of-way listed and described in Exhibit "B", annexed hereto and incorporated herein for all purposes; (g) All leases, options, rights of first refusal, orders, contracts, operating agreements, bottom-hole agreements, farmin/farmout agreements, acreage contribution agreements, unit agreements, processing agreements, maintenance agreements, purchase and sale agreements for gas, oil or other minerals, and other agreements and instruments to the extent that same relate, appertain, belong or are in any way incidental to the ownership of the Subject Interests by Grantor, including, but not limited to, those listed and described in Exhibit "C", annexed hereto and incorporated herein for all purposes; (h) All lease files, land files, well files, abstracts, title opinions, title curative, accounting records, royalty payment records, seismic records and surveys, gravity maps, electric logs, contracts, correspondence, microfiche lists, geological and geophysical maps, pressure date and decline curves, graphical production curves and other geological or geophysical data, records and other documents and records of every kind and description which relate to and are possessed by Grantor in connection with the Subject Interests, to the extent and as provided for or limited by that certain Purchase and Sale Agreement dated effective April 1, 1989 by and between Grantor and Texaco Producing Inc.; and (i) Any and all monies held by any individual, partnership, or corporate entity, whether or not such monies are held in escrow, payable to either Texaco Producing Inc. or Grantor, or both, for oil, gas condensate, casinghead gas or other related hydrocarbon substance produced and saved from or attributable to the Subject Leases and purchased by such individual, partnership or corporate entity subsequent to the Effective Date of this conveyance. The interests described under subparagraph (a) through (i) hereinabove are herein sometimes collectively referred to as "Subject Interests". II. This Bill of Sale, Conveyance and Assignment is made by Grantor and accepted by Grantee subject to the following: 2 37 (a) All the terms, conditions and obligations contained and provided for in the Subject Leases; (b) The terms and conditions of all existing orders, rules, regulations and ordinances of any federal, state or other governmental agency that are applicable or related to the Subject Interests; (c) The terms and conditions of the Purchase and Sale Agreement, dated the same date as this conveyance instrument, by and between Grantor, as a Seller and Grantee as the Purchaser, concerning the Subject Interests; and (d) Grantee accepting the Subject Interest in its "as is, where is" condition; Grantor disclaiming any and all liability arising in connection with any environmental matters, including, without limitation, any presence of naturally occurring radioactive material on the property; and Grantee expressly waiving the provisions of Chapter XVII, Subchapter E, Sections 17.41 through 17.63, inclusive, except Section 17.555 which is not waived, of Vernon's Texas Code Annotated, Business and Commerce Code. In addition, there are no warranties or representations, either express or implied, as to the quality or quantity of the hydrocarbon reserves, if any, attributable to the interest conveyed herein or the ability of the property to produce hydrocarbons. TO HAVE AND TO HOLD all and singular the Subject Interest, as hereinabove described, unto Grantee, its successors and assigns, and Grantor, for itself, its successors and assigns, does hereby WARRANT AND FOREVER DEFEND, all and singular, title to the Subject Interests, free from all liens, claims, assessments and encumbrances, other than the existing burdens, unto Grantee, Grantee's successors and assigns, against every person lawfully claiming or to claim the same, or any part hereof, BY, THROUGH OR UNDER GRANTOR, BUT NOT OTHERWISE. The reference herein to the "existing burdens" is for the purpose of protecting Grantor on Grantor's warranties, and shall not create, nor constitute a recognition of any rights in third parties. Grantor grants unto Grantee full power and right of substitution and subrogation in and to all covenants and warranties by others heretofore given or made in respect of the Subject Interests. III. The provisions hereof shall inure to the benefit of and be binding upon the parties hereto, their respective legal representatives, successors and assigns. IN TESTIMONY WHEREOF, this Conveyance is executed on the dates and at the places indicated in the respective acknowledgments below, but is stipulated herein to be effective as of 7:00 a.m., C.D.S.T., the 1st day of January, 1995. GRANTOR: BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P. By:________________________________ 3 38 IN WITNESS WHEREOF, the undersigned have executed this Agreement as of the date first written above. PURCHASER: GOLDKING TRINITY BAY CORP. By:__________________________________ Name:________________________________ Title:_______________________________ 4 39 IN WITNESS WHEREOF, the undersigned have executed this Agreement as of the date first written above. Seller: BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P. By:_____________________________________ Name:___________________________________ Title:__________________________________ 5 40 [acknowledgements] 6 EX-2.3 4 EX-2.3 1 EXHIBIT 2.3 ASSET PURCHASE AGREEMENT BETWEEN BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P., A CALIFORNIA LIMITED PARTNERSHIP SELLER AND GOLDKING TRINITY BAY CORP. PURCHASER FOR THE SELLER'S INTEREST IN THE PROPERTIES KNOWN AS UMBRELLA POINT FIELD JUNE 30, 1995 2 ASSET PURCHASE AGREEMENT This ASSET PURCHASE AGREEMENT (this "Agreement") dated as of June 30, 1995 by and between Goldking Trinity Bay Corp., a Texas corporation, ("Purchaser") and Benton Oil & Gas Combination Partnership 1991-1, L.P., a California limited partnership ("Seller"); W I T N E S S E T H: WHEREAS, Seller owns the working interest and net revenue interest set forth opposite such Seller's name on Schedule 1.2.2; WHEREAS, Seller desires to sell to Purchaser the Transferred Assets. and Purchaser desires to purchase from Seller the Transferred Assets, upon the terms and subject to the conditions hereinafter set forth; and NOW, THEREFORE, in consideration of the premises and of the respective representations, warranties, covenants, agreements and conditions contained herein, the parties hereto hereby agree as follows. ARTICLE I PURCHASE AND SALE Unless defined elsewhere in this Agreement, all capitalized terms used herein shall have the respective meanings given them in Appendix A hereto, which is incorporated herein by reference and shall be deemed to be a part of this Agreement for all purposes. 1.1. CONVEYANCE AND TRANSFER OF TRANSFERRED ASSETS. Seller and Purchaser hereby agree that, at the Closing, upon the terms and subject to the conditions of this Agreement, Seller shall convey, transfer and assign to Purchaser, the Transferred Assets. For purposes of this Agreement, the term "Transferred Assets" shall mean all of each Seller's right, title and interest in certain oil and gas properties located in Galveston Bay, including all of each Seller's right, title and interest in and to the following assets: (a) All of the oil and gas leases, oil, gas and mineral leases as described in Exhibit A attached hereto and incorporated herein (collectively referred to hereinafter as the "Leases" and individually as a "Lease"), and the leasehold estates created thereby, and the fee, mineral, royalty and overriding royalty interests, net profits interests, payments out of production and other real property interests described in Exhibit A, together with each and every kind and character of right, title, claim or interest that Seller has in and to the lands covered thereby, even though the interests of Seller therein may be incorrectly described, stated or limited on Exhibit A (collectively the "Properties", or singularly, a "Property"), together with all of each Seller's right, title and interest in and to all the property and rights incident thereto, including without limitation all of Seller's right, title and interest in and to: (i) the rights, privileges, benefits and powers conferred upon the holder of any Property with respect to the use and occupation of the surface of, and the subsurface depths under, the land covered by such Property that may be necessary, convenient or incidental to the possession and enjoyment of such Property; (ii) the rights in any pooled, communitized or unitized acreage included in whole or in part in any Property, including all production from the unit, pool or communitized area allocated to any such Property, and all interests in any wells within the unit, pool or communitized area allocated to such Property, whether such unit or pool 3 production comes from wells located within or without the areas covered by a Property; and (iii) all tenements, hereditaments and appurtenances belonging to such Properties; (b) All of each Seller's right, title and interest in and to the rights-of-way, easements. servitudes, permits, licenses, franchises, certificates of public convenience and necessity and similar rights and privileges, and other rights and interests in land primarily owned or used in connection with the Properties; (c) All of each Seller's right, title and interest in and to all real, personal and mixed property and fixtures located at the Closing on the Properties or the aforesaid rights-of-way, easements and other related properties, or primarily used or held for use in connection with the ownership, management, development, exploration or operation of the Transferred Assets, including without limitation all of each Seller's right, title and interest in and to all wells, well equipment, platforms, pipes, valves, boilers, compressors, separators, heaters, dehydrators, gauges, meters and other measuring equipment, regulators, extractors, communication equipment, gas gathering systems, casing, tubing, pipelines, power lines, fuel lines, generators, pumps, motors, buildings, storage tanks and facilities, improvements, fittings, machinery, equipment (including, without limitation, personal computers and related peripheral equipment located in the field and software that is legally transferable without cost), supplies, spare parts, materials and inventories, other than inventories of Hydrocarbons in storage tanks or other facilities above the pipeline connection to each such storage tank or facility, and in gas pipelines downstream from the delivery point sales meters on such pipelines existing as of the Effective Time; (d) All of each Seller's right, title and interest in and to all contracts, agreements, leases, and/or other arrangements, presently owned or acquired as a result of any agreement in existence prior to the Closing, including all causes of action pursuant thereto, to the extent used in connection with the ownership, management, development, exploration or operation of the Transferred Assets, including without limitation, all gas purchase and sale agreements, crude purchase and sale agreements, natural gas liquids purchase and sale agreements, farmin or farmout agreements, exchange agreements, bottom hole agreements, dry hole agreements, acreage contribution agreements, support agreements, seismic agreements, exploration agreements, joint venture agreements, operating agreements, unit agreements, pooling and communitization agreements, orders or declarations, balancing agreements, gas and natural gas liquids processing agreements, gathering and transportation agreements, construction and operation agreements, options, liens, security, interests, vendor financing agreements, surface leases, subleases and leases of equipment or facilities to the extent used or primarily useful in connection with the ownership, management, development, exploration or operation of the Transferred Assets and reasonably separable from Seller's other material rights in the contracts not used in connection with the Transferred Assets; provided, however, that no insurance contract or other insurance arrangement shall be included in the Transferred Assets (collectively, the "Contracts"); (e) All of each Seller's right, title and interest in and to all Hydrocarbons produced from or attributable to, the Properties and proceeds attributable thereto, at and after the Effective Time (subject to the provision of Section 1.3); provided, however, that all Hydrocarbons in storage tanks and other facilities above the pipeline connection to each such storage tank or facility, or in gas pipelines downstream from the delivery point sale meters on such pipelines at the Effective Time, shall remain the property of Seller; and 2 4 (f) All of each Seller's right, title and interest in and to all property and rights incident or attributable to the foregoing interests, including, without limitation all of each Seller's right. title and interest in and to: (i) subject to the limitations of Section 13.2.8, originals (or, to the extent that originals are not available, copies) of all books, records, files, contracts, muniments of title, reports, surveys and similar documents or materials, including computer tapes, disks and data with respect to any of the foregoing records, that relate to the foregoing interests, including without limitation, the purchase, exchange, operation, administration, sale or marketing thereof, or that constitute evidence of ownership thereof, to the extent such records are reasonably separable from Seller's corporate records, and excluding work product of Seller's legal counsel (other than title opinions) and documents relating to the negotiation and consummation of the transactions contemplated by this Agreement (collectively, the "Records"); (ii) (A) the proprietary geological, geophysical and seismic data, materials and information (the "Proprietary Data"), (B) the non-proprietary geological, geophysical and seismic data, materials and information the transfer of which is not prohibited by any copyright or validly existing third party agreement, that is transferable to Purchaser without payment of a transfer fee or other consideration, (C) the maps, interpretations, records and other technical information related to or based upon the Proprietary Data and not related to or based upon the Non-Proprietary Data (the "Proprietary Information") and (D) the maps, interpretations, records and other technical information related to or based upon any combination of the Proprietary Data and the Non-Proprietary Data (the "Combined Information" and collectively, the "Evaluation Data"); and (iii) all division orders, purchase orders, invoices, storage or warehouse receipts, bills of lading and certificates of title to the extent the same are attributable or relate to any of the Transferred Assets, and all documents, instruments, general intangibles and chattel paper primarily related to any of the Transferred Assets (other than the bonds, letters of credit and guarantees posted with governmental agencies, which are expressly reserved by Seller) and all estimated prepayments of royalty obligations of Seller with any federal or state authorities that are directly related to the transferred Assets and that are transferable to Purchaser; provided, however, that the Transferred Assets shall not include (i) any rights and causes of action by Seller to receive amounts (or rights to production from the Properties prior to the Effective Time) pursuant to the Retained Liabilities and (ii) rights and causes of action with respect to the Lawsuits and the facts and circumstances giving rise to such Lawsuits as retained by Seller and more particularly described in Section 1.4. 1.2. PURCHASE PRICE AND PURCHASE PRICE ALLOCATION. 1.2.1. PURCHASE PRICE. The aggregate purchase price (the "Purchase Price") for the Transferred Assets shall be TWO HUNDRED SIXTEEN THOUSAND NINETY-THREE DOLLARS ($216,093) subject to adjustments as set forth in Section 1.3, of which TWO THOUSAND EIGHT HUNDRED TWENTY-FOUR DOLLARS ($2,824) ("Initial Payment") shall be paid to the Seller in immediately available funds upon delivery to Purchaser by Seller of counterparts of this Agreement executed by Seller. At the Closing, the Purchase Price, less the amount of the Initial Payment (the "Cash at Closing") and as adjusted as provided in the Purchase Price Adjustment Certificate described in Section 1.3 2, shall be paid to Seller by wire transfer in federal or otherwise immediately available funds. Simultaneously therewith, Seller shall execute and deliver, effective as of the Effective Time, the Instruments of Transfer. 3 5 1.2.2. PURCHASE PRICE ALLOCATION. The Purchase Price shall be allocated among the types and classes of assets constituting the Transferred Assets as set forth on a schedule to be provided by Purchaser and Seller at Closing. 1.3. ADJUSTMENTS TO PURCHASE PRICE. 1.3.1. ADJUSTMENTS. In addition to any adjustments pursuant to Article VI, the Cash at Closing shall be adjusted as follows: (i) The Cash at Closing shall be increased by the following: (a) An agreed upon amount representing the value of all merchantable oil in storage above the pipeline connection at the Effective Time that is credited to the Properties; (b) Solely to the extent related to the Transferred Assets, the amount of (1) all actual direct operating expenditures, (2) all capital expenditures and (3) all costs and expenses that are incurred by Seller in connection with, or are otherwise allocable to, the operation of the Transferred Assets under the terms of the joint operating agreement during the period of time after the Effective Time; (c) The amount of any Taxes that have been paid by Seller on or prior to the Closing that are attributable to the time after the Effective Time and for which Purchaser is liable pursuant to Article VIII. (ii) The Cash at Closing shall be decreased by the following: (a) The proceeds that are received by, or payable to, Seller or any other person and that are attributable to the operation of the Transferred Assets for the period of time between the Effective Time and the Closing; and (b) Any amount agreed upon by Purchaser and Seller as the value of any Title Defects, less any amount agreed upon by Purchasers and Seller as the value of any Title Benefits. 1.3.2. CLOSING ESTIMATE. At least three (3) business days prior to the Closing Date, Seller on behalf of Seller, shall estimate the Purchase Price Adjustment Amount and deliver to Purchaser a certificate of an officer of Seller setting forth in reasonable detail the calculation thereof. The Cash at Closing shall be adjusted as set forth in such certificate. The Purchase Price Adjustment Certificate shall include a computation of any reduction in the Purchase Price caused by the failure of one or more Seller's to deliver on the Closing Date their respective interests in the Transferred Assets. 1.3.3. PURCHASE PRICE ADJUSTMENT CERTIFICATE. As soon as reasonably practicable, and in any event within sixty (60) days following the Closing Date, Seller shall deliver to Purchaser the Purchase Price Adjustment Certificate. Within thirty (30) days after delivery of the Purchase Price Adjustment Certificate, Purchaser shall notify Seller on behalf of Seller, whether Purchaser agrees or disagrees with the determination of the Purchase Price Adjustment Amount set forth in the Purchase Price Adjustment Certificate. If Purchaser disagrees with such determination, representatives of Purchaser and Seller shall meet and endeavor to resolve their differences regarding the determination of the Purchase Price Adjustment Amount. If the representatives of Purchaser and Seller are unable to agree upon such determination of the Purchase Price Adjustment Amount within twenty (20) business days after Purchaser's receipt of such notification, Seller shall select an independent accounting firm from a list of three (3) such firms provided by Purchaser, which firm shall audit the Purchase Price Adjustment Certificate and determine the Purchase Price Adjustment Amount. The decision of such independent 4 6 accounting firm shall be binding on Seller and Purchaser, and the fees and expenses of such independent accounting firm shall be borne one-half by Seller and one-half by Purchaser. 1.3.4. PAYMENT OF PURCHASE PRICE ADJUSTMENT AMOUNT. If the Purchase Price Adjustment Amount as finally determined pursuant to Section 1.3.3 is a smaller upward adjustment or a larger downward adjustment than that estimated pursuant to Section 1.3.2, Seller shall pay to Purchaser the amount of such excess plus interest thereon at the Agreed Interest Rate from (and including) the Closing Date to (but excluding) the date of payment. If the Purchase Price Adjustment Amount as finally determined pursuant to Section 1.3.3 is a larger upward adjustment or a smaller downward adjustment than that estimated pursuant to Section 1.3.2, Purchaser shall pay to Seller the amount of such deficiency plus interest thereon at the Agreed Interest Rate from (and including) the Closing Date to (but excluding) the date of payment. Any payments contemplated by this Section 1.3.4 shall be made by wire transfer in federal or other immediately available funds on or before the fifth business day following the final determination of the amount thereof. 1.4. RETAINED RIGHTS AND CLAIMS. Notwithstanding any provision herein to the contrary, Transferred Assets shall not include any rights or claims of Seller with respect to the facts and circumstances giving rise to those certain proceedings collectively referred to as the "Lawsuits" and filed: In the Matter of the Libel and Petition of Exxon Corporation. as Owner of the M/V "Bobcat," and Williamson Boat Works, as Charterer of the M/V "Bobcat," her engines tackle, apparel, etc., in a cause of exoneration from or limitation of liability; C.A. No. C-91-203, United States District Court for the Southern District of Texas, Corpus Christi Division; and French Production Incorporated v. Exxon Corporation d/b/a Exxon Company USA. Williamson Boat Works and Captain B.J. Shirley; No. 91-040865, District Court of Harris County, Texas, 295th Judicial District. 1.5. LIABILITIES ASSUMED AND RETAINED. 1.5 1. ASSUMED LIABILITIES. Purchaser shall assume and agree to pay, perform and discharge in the ordinary course of business, only those liabilities, debts or obligations of Seller that are set forth below (the "Assumed Liabilities"): (i) all liabilities and obligations of or relating to the Transferred Assets accruing after the Effective Time; (ii) all liabilities and obligations that accrue after the Effective Time, pursuant to the Leases that have been properly consented to and assigned; and (iii) all liabilities and obligations that accrue after the Effective Time, pursuant to the Contracts that have been properly consented to and assigned. 1.5.2. RETAINED LIABILITIES. Except for the Assumed Liabilities, Purchaser shall not assume and Seller shall retain and agree to pay, perform and discharge in the ordinary course of business all liabilities, debts or obligations of any nature that arise out of or result from any occurrence, transaction or event occurring prior to the Closing Date relating to the operation, ownership or use of the Transferred Assets, whether accrued, absolute, contingent or otherwise, whether due or to become due, including without limitation any such liability of Seller related to the Lawsuits (the "Retained Liabilities"); provided however, that Retained Liabilities shall not include any liability accruing after the Effective Time based on the violation or alleged violation of any statute, ordinance, rule, regulation, order or other law of any state, federal, county, local or other governmental subdivision, due to any occurrence, 5 7 transaction or event occurring prior to the Effective Time, which occurrence, transaction or event was not a violation of any laws existing as of the Effective Time. The Retained Liabilities shall include any liabilities with respect to the facts and circumstances giving rise to the Lawsuits. ARTICLE II THE CLOSING 2.1. CLOSING. The Closing shall take place at the offices of Purchaser, in Houston, Texas at 9:00 a.m on December 31, 1995 or such earlier or later date as provided hereafter. 2.2. INSTRUMENTS OF TRANSFER. Seller shall execute and deliver at Closing the Bill of Sale, Conveyance and Assignment, the form of which is attached as Exhibit "B" and any other instruments of transfer sufficient to convey to Purchaser the Transferred Assets, including without limitation the following (the "Instruments of Transfer"): (a) any personal property included in the Transferred Assets; (b) the Leases, assignment of leasehold interests; (c) the Contracts; and (d) the Properties. ARTICLE III REPRESENTATIONS AND WARRANTIES OF SELLER Seller hereby represents, warrants and covenants as follows: 3.1. ORGANIZATION AND GOOD STANDING. Seller is a partnership duly organized, validly existing and in good standing under the laws of its jurisdiction of formation and has all requisite power and authority to own and lease the properties and assets it owns and leases and to carry on its business as such business is conducted. 3.2. SUBSIDIARIES. No Seller has any Subsidiaries that own any of the Transferred Assets; 3.3. AUTHORITY; AUTHORIZATION OF AGREEMENT. Seller at closing will have all requisite power and authority to execute and deliver this Agreement, the Instruments of Transfer and each of the other agreements and documents contemplated, to consummate the transactions contemplated hereby and thereby and to perform all the terms and conditions to be performed by it. The execution and delivery of this Agreement, the Instruments of Transfer and each of the other agreements and documents contemplated, the performance of all the terms and conditions to be performed by Seller and the consummation of the transactions contemplated hereby and thereby will be duly authorized and approved by the partners of Seller. This Agreement, the Instruments of Transfer and each of the other agreements and documents contemplated, have been duly executed and delivered by each Seller and constitutes the valid and binding obligation of each Seller, enforceable against such Seller in accordance with its terms, except as such enforceability may be limited by bankruptcy, insolvency or other laws relating to or affecting the enforcement of creditors' rights generally and general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law). 3.4. NO VIOLATIONS. Subject to Article VII(7) 2.4., this Agreement, the Instruments of Transfer and each of the other agreements and documents contemplated hereby or thereby, and the execution and delivery hereof by Seller does not, and the fulfillment and compliance with the terms and conditions hereof and thereof and the consummation of the transactions contemplated hereby and thereby will not: 6 8 (i) conflict with, or require the consent of any Person under, any of the terms, conditions or provisions of the partnership agreement of the Seller; (ii) violate any provision of the Code, the NGA or the NGPA, or require any filing, consent, authorization or approval under, any Legal Requirement applicable to or binding upon Seller, other than the consent to the transfer and assignment of Leases by the General Land Office of the State of Texas, which consent Seller shall obtain as soon as possible following the Closing; (iii) conflict with, result in a breach of, constitute a default under (without regard to requirements of notice or the lapse of time or both), accelerate or permit the acceleration of the performance required by, or require any consent, authorization or approval under, (a) any mortgage, indenture, loan, credit agreement or other agreement or instrument evidencing indebtedness for borrowed money or any Contract to which Seller is a party or by which Seller is bound or to which any of its properties are subject or (b) any Lease to which Seller is a party or by which it is bound or to which any of its properties are subject; or (iv) result in the creation or imposition of any Encumbrance upon the Transferred Assets; which violation, breach or Encumbrance with respect to the matters specified in clauses (ii) through (iv) of this Section 3.4 have had or would reasonably be expected to have a Material Adverse Effect. 3.5. NO DEFAULT. Seller is not in default under, and no condition exists that with notice or lapse of time or both would constitute a default under, (i) any mortgage, indenture, loan, credit agreement or other agreement or instrument evidencing indebtedness for borrowed money or (ii) any Contract or Lease to which Seller is a party or by which Seller is bound or to which any of the Transferred Assets is subject. 3.6. ABSENCE OF CERTAIN CHANGES. Since the Effective Time, there has not been any material damage, destruction or loss to, or of, the Transferred Assets, that has not been covered by insurance. 3.7. TAXES. All returns, statements and reports with respect to Taxes that are required to be filed by Seller on or before the Closing have been (or will have been by the Closing) timely filed with the appropriate Governmental Authorities and all such Taxes shown thereon as due have been (or will have been by the Closing) paid or deposited. 3.8. DEFENSIBLE TITLE. Seller has, and will have at the Closing Date, Defensible Title to the Oil and Gas Interests. Each Seller represents as to itself only that it is transferring 100% of its interest in the Transferred Assets and that by, through and under it, no event has occurred and no conveyance has been made that would cause such Seller's interest in the Transferred Assets to be less than the Warranted Interest. Each Seller, as to itself only, represents and warrants that it owns the Warranted Interest; provided that the representation and warranty contained in this sentence shall terminate at Closing. Purchaser's exclusive remedy for any breach of the warranties set forth in this Section 3.8 shall be the remedy provided in Article VI. 3.9. LEASES. With respect to the Leases: (i) the Leases have been maintained according to their terms, in compliance with the agreements to which the Leases are subject, during the period in which Seller has owned an interest in such Leases; (ii) Seller has made or caused to be made all payments, including royalties, delay rentals and shut-in royalties (due in respect of the Leases thereunder), during the period in which 7 9 Seller has owned an interest in such Leases and no amounts of such payments due during such period are now being held in suspense; (iii) to the Knowledge of Seller, no other Party to any Lease is in breach or default with respect to any of its obligations thereunder; (iv) there has not occurred any event, fact or circumstance which with the lapse of time or the giving of notice, or both, would constitute such a breach or default on behalf of the Seller or, to the Knowledge of Seller, with respect to any other parties; and (v) neither Seller nor, to the Knowledge of Seller, any other party to any Lease has given or threatened to give notice of any action to terminate, cancel, rescind or procure a judicial reformation of any Lease or any provisions thereof. 3.10. ENVIRONMENTAL MATTERS. (a) To the Knowledge of Seller, since, May 19, 1989, the date that Seller closed the acquisition of its interest in the Properties,: (i) the use of the Transferred Assets has been limited to the conduct of oil and gas exploration and production operations and related activities; (ii) Seller has not received notice that any Governmental Authority has commenced any investigation or inquiry regarding failure of the Transferred Assets and/or the operations conducted thereon to comply with Environmental Laws or any notice under the Comprehensive Environmental Response, Compensation, and Liability Act, or any state or local laws; (iii) Except for the disposal of salt water produced from the wells located on the Leases using practices consistent with those customarily used by the oil and gas industry operating in the Gulf Coast area, the Transferred Assets have not been used for the generation, storage or disposal of Hazardous Substances or as a landfill or other waste disposal site for Hazardous Substances, in any manner that would constitute a violation of the Environmental Laws by such person; and (iv) Seller has not installed and has not discovered, on the Lands, any underground storage tanks other than the ordinary underground pipeline systems used in the conduct of oil and gas operations on the Transferred Assets. (b) To the Knowledge of Seller: (i) the Transferred Assets and the operations conducted thereon are not the subject of any existing, unfulfilled administrative or judicial orders, decrees, judgments, license or permit conditions, or other directives, under any Environmental Law, except as listed on Schedule 3.10; (ii) no equipment or other personal property or improvements owned or used on the Transferred Assets contain asbestos in such amount, concentration or level that would constitute a violation of Environmental Laws, except as listed on Schedule 3.10; (iii) no equipment or other personal property or improvements owned or used on the Transferred Assets contain any polychlorinated biphenyls in such amount, concentration or level that would constitute a violation of Environmental Laws, except as listed on Schedule 3.10; 8 10 (iv) no equipment or other personal property or improvements owned or used on the Transferred Assets contain any naturally occurring radioactive material in such amount, concentration or level that would constitute a violation of Environmental Laws, except as listed on Schedule 3.10; (v) except for violations that would not have a Material Adverse Effect on the Transferred Assets or the operations being conducted thereon, such operations conducted thereon are not in violation of, or non-compliance with, any Environmental Laws, nor are they the subject of any activities under the Comprehensive Environmental Response, Compensation, and Liability Act, or analogous state or local laws; and (vi) neither the execution of this Agreement nor the consummation of the transactions contemplated by this Agreement will violate any Environmental Law or require the consent or approval of any agency charged with enforcing any Environmental Law. (c) Notwithstanding any contrary provision in this Agreement or any document or instrument delivered with respect to this Agreement, (i) Seller makes no representation or warranty with respect to compliance with any Environmental Law of any kind except as provided in this Section 3.10; (ii) All representations and warranties contained in this Section 3.10 are qualified by the knowledge of Seller and Purchaser that the Environmental Protection Agency has not issued permits for the discharge of salt water and other materials from oil and gas exploration and production facilities such as those that are included in the Transferred Assets and that located in the Gulf Coast area, that until recently the Environmental Protection Agency had not provided any written guidance as to the procedures required for application for such permits and that the operator of the Transferred Assets, like other operators of oil and gas exploration and production facilities in the Gulf Coast area, has not been able to obtain such permit; and (iii) All representations and warranties contained in this Section 3.10 shall terminate at the end of the Environmental Indemnity Period, following which the Purchaser agrees not to institute any action or claim for a breach of such representation or warranty; provided, however, that the expiration of the Environmental Indemnity Period shall be extended as to any bona fide claim with respect to the breach of such representation or warranty, solely to the extent that Purchaser asserted such claim according to the procedures provided in Section 10.5 and Section 10.6, if the Purchaser shall have transmitted the Claim Notice with respect to such claim to the Seller prior to the expiration of such Environmental Indemnity Period. 3.11. OPERATIONS AND EXPENDITURES. With respect to the joint, unit or other operating agreements affecting the Transferred Assets, there are no outstanding calls or payments under authorities for expenditures concerning any single expenditure to be made by Seller in excess of $5,000 that are due or which Seller has committed to make and that have not been made, except as set forth on Schedule 3.11 annexed to this Agreement. 3.12. CONTRACTS. All of the Contracts are set forth on Exhibit "A" to this Agreement. 3.13. TAX PARTNERSHIPS. Except as disclosed on Schedule 3.13 annexed to the Agreement, none of the Transferred Assets are subject to a tax partnership, except Seller's partnership agreement. 3.14. FULL DISCLOSURE. No representation or warranty by Seller in this Article III, in any schedule or exhibit to this Agreement, or in any certificate or document furnished or to be furnished by Seller on the Closing Date, contains or will contain any untrue statement of a material fact, or omits or will omit to state a material fact necessary to make the statements contained therein not misleading. 9 11 ARTICLE IV REPRESENTATIONS AND WARRANTIES OF PURCHASER Except as otherwise disclosed in this Agreement, Purchaser hereby represents and warrants that: 4.1. ORGANIZATION AND GOOD STANDING. Purchaser is a corporation duly organized, validly existing and in good standing under the laws of its jurisdiction of incorporation. 4.2. CORPORATE AUTHORITY; AUTHORIZATION OF AGREEMENT. Purchaser has all requisite corporate power and authority to execute and deliver this Agreement, to consummate the transactions contemplated hereby and to perform all the terms and conditions hereof to be performed by it. The execution and delivery of this Agreement by Purchaser, the performance by Purchaser of all the terms and conditions hereof to be performed by it and the consummation of the transactions contemplated hereby will have been duly authorized and approved by the Board of Directors of Purchaser. This Agreement has been duly executed and delivered by Purchaser and constitutes the valid and binding obligation of Purchaser, enforceable against it in accordance with its terms, except as such enforceability may be limited by bankruptcy, insolvency or other laws relating to or affecting the enforcement of creditors' rights generally and general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law). 4.3. NO VIOLATIONS. This Agreement and the execution and delivery hereof by Purchaser do not, and the fulfillment and compliance with the terms and conditions hereof and the consummation of the transactions contemplated hereby will not: (i) conflict with, or require the consent of any Person under, any of the terms, conditions or provisions of the certificate of incorporation or bylaws of Purchaser; (ii) violate any provision of, or require any filing, consent, authorization or approval under, any Legal Requirement applicable to or binding upon Purchaser (assuming receipt of all routine governmental consents typically received after consummation of transactions of the nature contemplated by this Agreement); (iii) conflict with, result in a breach of, constitute a default under (without regard to requirements of notice or the lapse of time or both), accelerate or permit the acceleration of the performance required by, or require any consent, authorization or approval under (a) any mortgage, indenture, loan, credit agreement or other agreement or instrument evidencing indebtedness for borrowed money to which Purchaser is a party or by which Purchaser is bound or to which any of its properties is subject or (b) any lease, license, contract or other agreement or instrument to which Purchaser is a party or by which it is bound or to which any of its properties is subject; or (iv) result in the creation or imposition of any Encumbrance upon the assets of Purchaser; which violation, breach or encumbrance with respect to the matters specified in clauses (ii) through (iv) of this Section 4.3 might reasonably be expected to have a material adverse effect on the business, financial condition or results of operations of Purchaser, taken as a whole. 4.4. LITIGATION. There is no action, suit, proceeding or governmental investigation or inquiry pending, or, to the Knowledge of Purchaser, threatened against Purchaser or its subsidiaries or any of their respective properties that might delay, prevent or hinder the consummation of the transactions contemplated hereby. 10 12 ARTICLE V ADDITIONAL AGREEMENTS AND COVENANTS 5.1. COVENANTS OF SELLER. Seller covenants and agrees with Purchaser as follows: 5.1.1. Certain Changes. Except as may be expressly permitted by this Agreement or set forth in any Schedule hereto, from the date hereof until the Closing, without first obtaining the written consent of Purchaser (which consent will not be unreasonably withheld), Seller will not: (i) enter into, assign, terminate or amend in any material respect any Contract or Lease; (ii) sell, lease or otherwise dispose of any of the Transferred Assets; (iii) purchase, lease or otherwise acquire any property of any kind whatsoever other than in the ordinary course of business; provided, however, that no such action involving an expenditure of $5,000 or more by Seller shall be taken by Seller without Purchaser's prior written consent; (iv) mortgage, encumber or pledge any of the Transferred Assets; (v) operate the Transferred Assets except diligently and in the usual, regular and ordinary manner, consistent with past practices; or (vi) commit itself to do any of the foregoing. 5.1.2. OPERATION OF PROPERTIES. Except as may be expressly permitted hereunder or as set forth in any Schedule hereto, from the date hereof until the Closing, without first obtaining the written consent of Purchaser (which consent will not be unreasonably withheld), Seller will not: (i) waive any right of material value relating to any of the Transferred Assets; (ii) release or abandon any material part of any of the Transferred Assets; (iii) convey, farm out or otherwise dispose of Transferred Assets with a fair market value exceeding either $5,000 on an individual basis or $5,000 in the aggregate; (iv) commence or consent to any material operations on any Property that it has not previously committed to and that may be expected to cost Seller in excess of $5,000 (except for emergency operations, in which case Seller shall promptly notify Purchaser and from the date of Purchaser's response to such notice Seller shall once again be subject to the limitations contained in this clause (iv)); (v) enter into, modify or terminate any Contracts or Lease; or (vi) commit itself to do any of the foregoing; provided, however, that nothing contained in this Section 5.1.2 or elsewhere in this Agreement shall limit the rights of Seller to produce consume and sell Hydrocarbons from the Properties in the ordinary course of business and to comply with requirements of the NGA, the NGPA and any rules or regulations issued thereunder. 11 13 5.1.3. CERTAIN COVENANTS WITH RESPECT TO THE TRANSFERRED ASSETS. Except as may otherwise be expressly provided herein, Seller will, from the date hereof to the Closing, unless otherwise consented to in writing by Purchaser (which consent will not be unreasonably withheld): (i) promptly notify Purchaser of the receipt of any written notice or written claim or written threat of notice or claim of which Seller becomes aware relating to any default or breach under, or of any termination or cancellation or written threat of termination or cancellation of, any of the Leases, Properties or Material Contracts; (ii) promptly notify Purchaser of any loss of or damage to any portion of the Transferred Assets exceeding $5,000 in amount; (iii) cause to be paid all rentals, shut-in royalties, minimum royalties and other payments that are necessary to maintain in force its rights in and to the Properties, and pay timely all costs and expenses incurred by it in connection with the Properties, except such costs and expenses as are being contested in good faith; and (iv) as to the Properties, use its Best Efforts to maintain and operate the Properties in accordance with all applicable Legal Requirements (to the extent consistent with customary practices in the oil and gas industry), in accordance with the Contracts relating thereto, and in substantially the same manner that Seller hereto has operated such properties. 5.1.4. ACCESS. Seller will afford to Purchaser and its authorized representatives upon reasonable notice, reasonable access from the date hereof until the Closing Date, during normal business hours, to its personnel, financial data properties, books and records which are related to the Transferred Assets to the extent that such access and disclosure would not unreasonably interfere with the normal operation of the business of Seller or violate the terms of any agreement by which Seller is bound or any applicable Legal Requirement; provided, however, that the confidentiality of any data or information so acquired shall be maintained by Purchaser and its representatives in accordance with Section 5.2.4. 5.1.5. BEST EFFORTS. Seller will use its Best Efforts to obtain the satisfaction of the conditions to Closing set forth in Section 7.1. 5.1.6. PUBLIC ANNOUNCEMENTS. Except for communications with its partners, Seller shall not issue any public announcement or statement with respect to the transactions contemplated hereby except upon the consent of Purchaser or upon the advice of counsel that such announcement or statement is legally required; provided, however, that Seller shall, if practical under the circumstances, consult with Purchaser prior to issuing any such public announcement or statement. 5.1.7. PERMISSIONS. Seller will cooperate with Purchaser and take all action reasonably necessary (i) to obtain all such permissions approvals and consents by Governmental Authorities and others as may be required to consummate the transactions contemplated in this Agreement and (ii) to obtain the transfer to Purchaser of any and all operating rights held by Seller. 5.2. COVENANTS OF PURCHASER. Purchaser covenants and agrees with Seller as follows: 5.2.1. BEST EFFORTS. Purchaser will use its Best Efforts to obtain the satisfaction of the conditions to Closing set forth in Section 7.2. 5.2.2. PUBLIC ANNOUNCEMENTS. Purchaser shall not issue any public announcement or statement with respect to the transactions contemplated hereby except upon the consent of Seller or upon the advice of counsel that such announcement or statement is legally required; provided, however, that Purchaser shall, if practical under the circumstances, consult with Seller prior to issuing any such public announcement or statement. 12 14 5.2.3. CONFIDENTIAL INFORMATION. In the event that this Agreement is terminated or, if not terminated, until the Closing, the confidentiality of any data or information received by Purchaser regarding the business and assets of Seller shall be maintained by Purchaser and its representatives in accordance with the Confidentiality Agreement that was executed by Purchaser. 5.2.4. USE OF TRADE NAMES. After the Closing, Purchaser shall not use any logos, trademarks or trade names belonging to Seller, and will, a soon as reasonably practicable after the Closing remove any such trade names from all signs or labels on the Transferred Assets. ARTICLE VI INSPECTION OF TITLE MATTERS 6.1. TITLE DEFECTS. (a) Any Encumbrances that individually or in the aggregate with other defects could cause the title of Seller in any Property described in Exhibit A to be less than Defensible Title shall be a title defect ("Title Defect"). Purchaser shall be entitled to the remedies set forth in Section 6.3 for any matter that constitutes a Title Defect even though Purchaser could, but for this provision, after Closing obtain indemnification for such matter pursuant to Section 10.2. (b) Any circumstances or condition that could operate to cause (i) the Net Revenue Interest of Seller to increase above that set forth on Exhibit A without an increase in the Working Interest of Seller, or (ii) the Working Interest of Seller to decrease below that set forth on Exhibit A without a decrease in the Net Revenue Interest of Seller, shall be a title benefit ("Title Benefit"). 6.2. NOTICE OF TITLE DEFECTS AND TITLE BENEFITS. (a) From time to time during the period from the date of execution of this Agreement until seven (7) days prior to the Closing Date (the "Title Examination Period"), Purchaser shall have the right (but not the obligation) to notify Seller of any Title Defect of which Purchaser becomes aware, providing in such notice a reasonably detailed description of such Title Defect. If the Closing Date is extended beyond the Closing Date stated herein in accordance with the provisions hereof, then the Title Examination Period shall be extended for a similar and parallel length of time. With respect to each notice of a Title Defect given during such period, Seller may, but shall have no obligation to, attempt to cure such Title Defect prior to Closing. Purchaser's failure to give notice of a Title Defect shall not impair Purchaser's rights under any express warranty or indemnification made by Seller under this Agreement or the Instruments of Transfer. (b) From time to time during the Title Examination Period, Purchaser shall notify Seller of any Title Benefits of which Purchaser becomes aware and Seller shall have the right (but not the obligation) to notify Purchaser of any Title Benefit of which they become aware. The value of any such Title Benefits shall be mutually agreed upon by Purchaser and Seller, taking into consideration the allocated value of the Property (asset forth on allocation of the Purchase Price) subject to the Title Benefit, the portion of the Property subject to the Title Benefit, the legal effect of the Title Benefit and the anticipated economic effect of the Title Benefit over the life of the Property subject to such Title Benefit. 6.3. REMEDIES FOR TITLE DEFECTS. In the event that any Title Defects is not cured on or before Closing, Purchaser may, at its own election, (a) waive such Title Defect, (b) elect to terminate this Agreement pursuant to Section 9.1, or (c) reduce the Purchase Price by an amount mutually agreed upon by Purchaser and Seller as being the value of such Title Defect, taking into consideration the allocated value of the Property subject to the Title Defect, the portion of the Property subject to the Title Defect, the legal effect of the Title Defect on the Property and the liability of Purchaser relative to the allocated 13 15 liabilities related to the Property and/or whether the Title Defect is applicable to a portion of the Property that is not encumbered by the allocated liability, and the anticipated economic effect of the Title Defect over the life of the Property subject to the Title Defect (including the potential amount of reduction of discounted present net worth of net future cash flow on account of such Title Defect), subject to offset for the value of Title Benefits. If the parties are unable to agree as to the amount of any adjustment under Section 6.3 (c), either party may terminate this Agreement. Notwithstanding anything to the contrary in this Section 6.3, in no event shall the reduction in the Purchase Price for all Title Defects affecting any Property exceed the allocated value of such Property. 6.4. SELLER'S WARRANTY OF TITLE. The Conveyances shall contain a special warranty of title whereby Seller binds and obligates itself, its successors and assigns, to warrant and forever defend unto Purchaser, its successors and assigns, title to the Properties and other tangible Transferred Assets against all persons lawfully claiming or to claim the same or any part thereof by, through or under Seller, but not otherwise, together with full subrogation of Purchaser, to the extent that Seller is entitled to grant such subrogation, to all representations and warranties of any predecessors of Seller in title. ARTICLE VII CONDITIONS TO CLOSING 7.1. CONDITIONS TO THE OBLIGATIONS OF PURCHASER. The obligations of Purchaser to proceed with the Closing contemplated hereby are subject to the satisfaction on or prior to the Closing of all of the following conditions, any one or more of which may be waived, in whole or in part, in writing by Purchaser: 7.1.1. COMPLIANCE. Except as otherwise contemplated or permitted herein, the representations and warranties made herein by Seller shall be correct at and as of the Closing as though such representations and warranties were made at and as of the Closing, and Seller shall have complied with all the covenants and other agreements hereof required by this Agreement to be performed by it at or prior to the Closing. 7.1.2. OFFICER'S CERTIFICATES. Purchaser shall have received certificates, dated the Closing Date, of an executive officer of Seller certifying as to the matters specified in Section 7.1.1. 7.1.3. NO ORDERS. The Closing hereunder shall not violate any order or decree of any Governmental Authority having competent jurisdiction over the transactions contemplated by this Agreement; provided, however, that if such order or decree is a temporary restraining order or other ex parte order or decree and all other conditions precedent to Closing have been satisfied or waived, the Closing Date shall be extended to a date five (5) business days subsequent to the date on which such temporary restraining order or other ex parte order or decree ceases to be in effect. 7.1.4. CONSENTS TO ASSIGNMENTS. Seller shall have delivered to Purchaser satisfactory consents to the assignment of the Leases and Contracts. 7.1.5. TITLE OPINION. Purchaser shall have received within ten (10) business days prior to Closing a title opinion, in a form reasonably satisfactory to Purchaser, from Purchaser's special title opinion counsel relating to the Transferred Assets. 7.1.6. DAMAGE TO TRANSFERRED ASSETS. Purchaser's obligation to purchase the Seller's interest in the Transferred Assets is conditioned upon the absence of any material damage, destruction or loss to, or of, the platform, platform equipment, pipelines, tankage or related surface equipment, included as part of the Transferred Assets, that has not been covered by insurance. 7.1.7. FRENCH CLOSING. Purchaser's obligation to purchase the Seller's interest in Transferred Assets is conditioned upon Purchaser's closing on the purchase of at least seventy-five percent (75%) of 14 16 the Working Interest in the Leases pursuant to that certain Asset Purchase Agreement between Purchaser and Pelharn, Inc., et al., dated May 15, 1995. 7.2. CONDITIONS TO THE OBLIGATIONS OF SELLER. The obligation of Seller to proceed with the Closing contemplated hereby is subject to the satisfaction on or prior to the Closing of all of the following conditions, any one or more of which may be waived, in whole or in part, in writing by Seller: 7.2.1. COMPLIANCE. Except for such breaches of representations or warranties by and covenants of Purchaser made herein as would not have a material adverse effect on the business, financial condition and results of operations of Purchaser, taken as a whole, the representations and warranties made herein by Purchaser shall be correct at and as of the Closing as though such representations and warranties were made at and as of the Closing, and Purchaser shall have complied with all the covenants and other agreements required by this Agreement to be performed by it at or prior to the Closing. 7.2.2. OFFICER'S CERTIFICATE. Seller shall have received a certificate dated the Closing Date of an executive officer of Purchaser, certifying as to the matters specified in Section 7.2.1. 7.2.3. NO ORDERS. The Closing hereunder shall not violate any order or decree of any Governmental Authority having competent jurisdiction over the transactions contemplated by this Agreement; provided, however, that if such order or decree is a temporary restraining order or other ex parte order or decree and all other conditions precedent to Closing have been satisfied or waived, the Closing Date shall be extended to a date five (5) business days subsequent to the date on which the temporary restraining order or such other ex parte order or decree ceases to be in effect. 7.2.4. APPROVAL BY PARTNERS. Seller shall have received the affirmative vote of at least 75% of the Seller's partners to ratify and approve this agreement and the transactions contemplated hereby. ARTICLE VIII TAX MATTERS 8.1. LIABILITY FOR TAXES. 8.1.1. SELLER. Seller shall be liable for (i) all Taxes for any taxable period ending on or before the Effective Time, (ii) any income taxes which are imposed on the gain recognized by Seller on the sale of the Transferred Assets pursuant to this Agreement, (iii) the portion that is determined as described in Section 8.1.4, of any Taxes (other than Taxes described in clause (ii) above) for any taxable period beginning before and ending after the Effective Time and that is allocable to the portion of such period occurring on or before the Effective Time (the "Seller Period") and (iv) any sales, use, transfer or similar taxes arising from the transactions contemplated in this Agreement. 8.1.2. PURCHASER. Purchaser shall be liable for all Taxes attributable to the Transferred Assets and arising after the Effective Time. 8.1.3. INDEMNITY. Seller shall indemnify and hold Purchaser harmless from any liability for amounts for which Seller is liable pursuant to Section 8.1.1. Purchaser shall indemnify and hold Seller harmless from any liability for amounts for which Purchaser is liable pursuant to Section 8.1.2. The amount of any indemnity under this Section 8.1.3 shall include any additional amount necessary to indemnify the recipient of the indemnity payment against any taxes imposed, and any attorneys' fees or other litigation costs incurred, in connection with such indemnity payment. 8.1.4. AD VALOREM TAXES. Whenever it is necessary for purposes of Section 8.1.1 to determine the portion of any Taxes for a taxable period beginning before and ending after the Effective Time, which portion is allocable to the Seller Period, the determination shall be made for ad valorem Taxes, on a per diem basis and for other Taxes, on the assumption that the Seller Period constitutes a separate 15 17 taxable period and by taking into account the actual taxable events occurring during such period (except that exemptions, allowances and deductions for a taxable period beginning before and ending after the Effective Time that are calculated on an annual or periodic basis, such as the deduction for depreciation, shall be apportioned to the Seller Period on a per diem basis). 8.1.5. REFUNDS. If any Seller or Purchaser or any affiliate of a Seller or Purchaser receives (whether by payment. credit, offset or otherwise) a refund in respect of any Taxes for which the other party is liable under Section 8.1.1 or 8.1.2, the party receiving such refund shall, within thirty (30) days after receipt of such refund, remit it to the party liable for the Taxes with respect to which the refund was received. The parties shall cooperate with each other in taking all necessary steps to claim any such refund. 8.1.6. ADJUSTMENT. For purposes of this Section 8.1, the amount of any downward adjustment to the Purchase Price pursuant to Section 1.3.1(ii)(b) shall be treated as a payment by Seller of ad valorem taxes imposed with respect to the Transferred Assets for 1994. 8.2. COOPERATION AND EXCHANGE OF INFORMATION. Seller or Purchaser will provide, or cause to be provided, to the other party copies of all correspondence received from any taxing authority by such party or any of its affiliates in connection with the liability for Taxes for any period for which such other party is or may be liable under Section 8.1.1 or 8.1.2. The parties will provide each other with such cooperation and information as they may reasonably request of each other in preparing or filing any return amended return or claim for refund, in determining a liability or a right to refund or in conducting any audit or other proceeding in respect of Taxes imposed on the parties or their respective affiliates. The parties and their affiliates will preserve and retain all returns, schedules, work papers and other documents relating to any such returns, claims, audits or other proceedings until the expiration of the statutory period of limitations (with regard to waivers and extensions) of the taxable periods to which such documents relate and until the final determination of any payments which may be required with respect to such periods under this Agreement and shall make such documents available to representatives of the other party upon reasonable notice and at reasonable times, it being understood that such representatives shall be entitled to make copies of any such books and records as they shall deem necessary. Seller or Purchaser further agree to permit representatives of the other party to meet with employees of such party on a mutually convenient basis in order to enable such representatives to obtain additional information and explanations of any documents provided pursuant to this Section 8.2. Seller or Purchaser shall make available to the representatives of the other party at the then current administrative headquarters of such party sufficient work space and facilities to perform the activities described in the two preceding sentences. Any information obtained pursuant to this Section 8.2 shall be kept confidential, except as may be otherwise necessary in connection with the filing of returns or claims for refund or in conducting any audit or other proceeding. Each party shall provide the cooperation and information required by this Section 8.2 at its own expense. 8.3. PAYMENT OF TAXES. 8.3.1. PAYMENT. All Taxes shall be paid by the party that, on the date that such Taxes are required to be paid, is legally responsible to pay such Taxes. 8.3.2. TIME OF PAYMENT. Except as otherwise provided in this Article VIII or in Section 1.3, any amount to which a party is entitled under this Article VIII shall be promptly paid to such party by the party obligated to make such payment following written notice to the party so obligated that the Taxes to which such amount relates are due and that provides details supporting the calculation of such amount. 8.4. SURVIVAL OF OBLIGATIONS. The obligations of the parties set forth in this Article VIII shall be unconditional and absolute and shall remain in effect without limitation as to time. 16 18 8.5. CONFLICT. In the event of a conflict between the provisions of this Article VIII and any other provisions of this Agreement, the provisions of this Article VIII shall control. ARTICLE IX TERMINATION 9.1. GROUNDS FOR TERMINATION. This Agreement may be terminated at any time prior to the Closing: (i) by the mutual written agreement of Seller and Purchaser; (ii) by Seller or Purchaser, if the consummation of the transactions contemplated hereby would violate any nonappealable final order, decree or judgment of any Governmental Authority having competent jurisdiction enjoining, restraining or otherwise preventing the consummation of this Agreement or the transactions contemplated hereby; provided, however, that a party shall not be allowed to exercise any right of termination pursuant to this Section 9.1(ii) if the event giving rise to such right shall be due to the negligent or willful failure of such party to perform or observe in any material respect any of the covenants or agreements set forth herein to be performed or observed by such party; (iii) by Purchaser or Seller if the Closing shall not have occurred prior to 5:00 p.m., December 31, 1995; provided, that the Closing was not delayed as a result of the negligent or willful failure of the terminating party's obligation to perform hereunder; (iv) by Seller or Purchaser if the non-terminating party has breached its representations and warranties, defaulted in the performance of its covenants or not satisfied its conditions to Closing; (v) by Purchaser, or by Seller, as provided in Section 6.3; or (vi) by Seller, if there is a breach of any representation or warranty under Section 3.10 and the cost of curing such breach would exceed $500,000 and such breach is not waived by Purchaser. 9.2. EFFECT OF TERMINATION. The following provisions shall apply in the event of a termination of this Agreement: 9.2.1. NO LIABILITY. If this Agreement is terminated as permitted under Section 9.1 (i), (ii), (iii), (v) or (vi), such termination shall be without liability of any party to this Agreement or any affiliate, shareholder, director, officer, employee, agent or representative of such party and Seller shall return to Purchaser the Initial Payment. In such event, the representation contained in the second sentence of Section 4.2 shall be of no effect. 9.2.2. PURCHASER'S LIABILITY. If this Agreement is terminated by Seller, as permitted under Section 9.1 (iv), Seller shall retain the Initial Payment, as Seller's sole remedy, and Purchaser shall have no further obligation to Seller for failure to close the transaction. 9.2.3. SELLER'S LIABILITY. If this Agreement is terminated by Purchaser, as permitted under Section 9.1 (iv), Purchaser's sole remedy shall be the right to seek specific performance of Seller's obligation to sell to Purchaser the Transferred Assets in complete satisfaction of any other damages, thereby sustained or incurred by Purchaser. 9.2.4. SURVIVAL. Notwithstanding the foregoing, the provisions of this Article IX and Section 5.2.3 shall survive any termination of this Agreement. 17 19 ARTICLE X EXTENT AND SURVIVAL OF REPRESENTATIONS AND WARRANTIES; INDEMNIFICATION 10.1. SCOPE OF REPRESENTATIONS OF SELLER. Except as and to the extent expressly set forth herein, Seller makes no representations or warranties whatsoever, and disclaim all liability and responsibility for any representation, warranty, statement or information made or communicated (orally or in writing) to Purchaser (including, but not limited to, any opinion, information or advice that may have been provided to Purchaser by any affiliate, officer, stockholder, director, employee, agent, consultant or representative of Seller, any petroleum engineer or engineering firm, Seller's counsel or any other agent, consultant or representative). Without limiting the generality of the foregoing, except as and to the extent expressly set forth herein and in the Instruments of Transfer, Seller makes no representations or warranties as to (i) the title to any of the properties of Seller, (ii) the amounts of Hydrocarbon reserves attributable to such properties or (iii) any geological or other interpretations or economic evaluations. Purchaser acknowledges and affirms that it has had full access to the records of Seller and the information contained in, or made available or provided with respect to materials contained in, the records of Seller, and that Purchaser has made its own independent investigation, analysis and evaluation of the Transferred Assets, (including its own estimate and appraisal of the extent and value of Seller's Hydrocarbon reserves). Notwithstanding the foregoing, to the Knowledge of Seller, the information contained in the records of Seller and information otherwise made available or furnished in writing to Purchaser by Seller with respect to the Transferred Assets does not contain any untrue statement of a material fact or omit to state any material fact that would make such information not false or misleading. 10 2. INDEMNIFICATION OF PURCHASER. Seller agrees (i) to indemnify Purchaser against, and hold Purchaser harmless from, any loss, damage or expense (including reasonable attorneys' fees) sustained by Purchaser arising out of or resulting from any inaccuracy in or breach of any of the representations, warranties or covenants made by Seller in this Agreement, (ii) to pay, perform, fulfill and discharge all costs, expenses and liabilities incurred in connection with the Transferred Assets prior to the Closing Date with respect to the ownership or operation of the Transferred Assets prior to the Closing Date and (iii) to indemnify, defend and hold Purchaser harmless from and against any and all claims, losses, damages, costs, expenses, causes of action and judgments of any kind or character with respect to all liabilities, including the Retained Liabilities, arising out of or in connection with the ownership or operation of the Transferred Assets prior to the Closing Date, including, without limitation, any interest, penalty and other costs and expenses incurred in connection therewith or the defense thereof (provided that any loss. damage or expense sustained by Purchaser arising out of or resulting from any breach or violation of Section 3.10 shall be governed by Section 10.4); provided, however, that Purchaser shall not be entitled to assert rights of indemnification under this Section 10.2 or Section 10.4 unless and until the aggregate of all such losses exceeds $25,000 (it being understood that such losses shall accumulate until such time or times as the aggregate of all such losses exceeds $25,000, whereupon Purchaser shall be entitled to indemnification under this Section 10.2 or Section 10 4 for any such losses); and provided, further, that the maximum aggregate of all losses for which Purchaser shall be entitled to indemnification by any Seller, whether under this Section 10 2, Section 10.4 or otherwise, shall not exceed such Seller's share of the Purchase Price. 10.3. INDEMNIFICATION OF SELLER. Purchaser agrees (i) to indemnify Seller against, and hold Seller harmless from, any loss, damage or expense (including reasonable attorneys' fees) sustained by Seller arising out of or resulting from any inaccuracy in or breach of any of the representations, warranties or covenants made by Purchaser in this Agreement, (ii) to pay, perform, fulfill and discharge all costs, expenses and liabilities incurred from and after the Closing Date with respect to the ownership or operation of the Transferred Assets from and after the Closing Date and (iii) to indemnify, defend and hold Seller harmless from and against any and all claims, losses, damages, costs, expenses, causes of action and judgments of any kind or character with respect to all liabilities to third parties arising out of or in connection with the ownership or operation of the Transferred Assets from and after the Closing 18 20 Date, including, without limitation, any interest, penalty and other costs and expenses incurred in connection therewith or the defense thereof (provided that any loss, damage or expense sustained by Seller arising out of or resulting from any breach or violation of Article VIII shall be governed by those provisions); provided, however, that Seller shall not be entitled to assert rights of indemnification under this Section 10.3 unless and until the aggregate of all such losses exceeds $25,000 (it being understood that such losses shall accumulate until such time or times as the aggregate of all such losses exceeds $25,000, whereupon Seller shall be entitled to indemnification under this Section 10.3 for any such losses). 10 4. ENVIRONMENTAL INDEMNITY. (a) Subject to the financial limitations regarding the indemnity of Seller described in Section 10.2, Seller agrees, during the Environmental Indemnity Period, to indemnify and save Purchaser harmless from and against, and to reimburse Purchaser with respect to, any and all claims, demands, losses, damages, liabilities, causes of action, judgments, penalties, costs and expenses (including, without limitation, reasonable legal fees and expenses, clean-up costs and disbursements) accrued or incurred by Purchaser at any time and from time to time, during the Environmental Indemnity Period by reason of (i) the breach of any representation or warranty of Seller as set forth in Section 3.10, (ii) any violation with respect to or affecting the Transferred Assets on or before the Closing Date of any Environmental Laws in effect on or before the Closing Date, (iii) the clean-up of the Transferred Assets required under Environmental Laws for any activities prior to the Closing Date, (iv) any act, omission, event or circumstance existing or occurring on or prior to the Closing Date (including without limitation, the presence on the Properties of Hazardous Substances or the presence off site of Hazardous Substances generated on the Properties, on or prior to the Closing Date) that result from or that are in connection with the ownership, construction, occupancy, operation, use and/or maintenance of the Properties, regardless of whether the act, omission, event or circumstance constituted a violation of any Environmental Laws at the time of its existence or occurrence, and (v) any and all claims or proceedings (whether brought by private party or Governmental Authority) for bodily injury, property damage, abatement or remediation, environmental damage or impairment or any other injury or damage resulting from or relating to any Hazardous Substances located upon the Properties prior to the Closing Date. Seller shall also indemnify and hold Purchaser harmless from and against any liability, loss, cost or expense, including reasonable attorneys' fees and expenses, arising from or relating to the imposition or recording of a lien on the Properties in connection with any contamination of the Properties or pursuant to any Environmental Laws in the event only that such contamination occurred prior to the Closing Date. Seller shall also hold harmless and indemnify Purchaser from any liability incurred by Purchaser arising out of regulatory action or third-party, claims with respect to contamination of the Properties or offsite locations that occurred prior to the Closing Date. (b) Notwithstanding anything contained in this Agreement to the contrary, the indemnities in this Section 10.4 shall survive the Closing Date only until the end of the Environmental Indemnity Period, and shall be limited in scope only to any activities discovered after the Closing Date but before the end of the Environmental Indemnity Period that occurred before the Closing Date. For all purposes with respect to the Transferred Assets, Purchaser agrees that it shall have the burden of proof that any alleged activities, violations, events or conditions occurred before the Closing Date. (c) Seller shall have the right to control any action for which indemnity is required under this Section 10.4 through counsel of its choice, subject to Purchaser's consent, which shall not be unreasonably withheld or delayed, provided, however, at Purchaser's option, Purchaser may participate in such action and appoint its own counsel. If Seller does not notify Purchaser in writing of its intent to control such action within thirty (30) days (or five (5) days less than such lesser time as may be required to respond to such claims) after receipt by Seller of written notice of such claims, Purchaser shall have the right to undertake the control, conduct or settlement of such claims through its own counsel at Seller's expense and may settle such matter without Seller's consent at its sole expense. In the event any proposed settlement includes nonmonetary relief, including clean-up, Purchaser may agree to such 19 21 clean-up and settle such matter only with the consent of Seller, which consent shall not be unreasonably withheld or delayed; provided, however, if Seller fails to respond to such a notification by Purchaser regarding such non-monetary relief within ten (10) days after Purchaser's notification to Seller, Seller shall be deemed to have consented to such non-monetary relief. (d) Purchaser agrees that the rights and remedies provided in this Section 10.4 shall be the exclusive rights and remedies available to it for any matter within the scope of Section 10.4 and that the general indemnification provisions of Section 10.2 and any other rights or remedies of Purchaser with respect to the Seller for any matter within the scope of Section 10.4, whether provided in this Agreement, at law or in equity, shall not be applicable and are hereby waived. Nothing in this Section 10.4 or elsewhere in this Agreement shall limit or impair any rights or remedies of Purchaser against any third party under any Environmental Laws, including, without limitation, any rights of contribution or indemnification available hereunder. (e) Any indemnification provided in this Section 10.4 shall terminate at the end of the Environmental Indemnity Period, following which the Purchaser agrees not to institute any action or claim for indemnification or other recovery with respect to the matter within the scope of Section 10.4; provided, however, that the expiration of the Environmental Indemnity Period shall be extended as to any bona fide claim for indemnification within the scope or Section 10.4, solely to the extent that Purchaser asserted such claim according to the procedures provided in Section 10.5 and Section 10.6, if the Purchaser shall have transmitted the Claim Notice with respect to such claim to the Seller prior to the expiration of such Environmental Indemnity Period. 10.5. SURVIVAL. The representations and warranties set forth in this Agreement (other than those set forth in Article VIII) shall survive until the second anniversary of the Closing Date, following which date none of the parties may bring any action or present any claim for a breach of such representations and warranties; provided, however, that there shall be no termination of any representation or warranty as to which a bona fide claim has been asserted if the Indemnified Party shall have transmitted the Claim Notice with respect thereto prior to the anniversary of the Closing Date. The representations and warranties set forth in 3.8.2 shall remain terminate in accordance with the terms of Article VIII shall terminate in accordance with the terms of Article VIII. 10.6. INDEMNIFICATION PROCEDURES. All claims for indemnification under this Agreement (other than claims for indemnification under Article VIII) shall be asserted and resolved as follows: 10 6.1. NOTICE. An Indemnified Party shall promptly (i) notify an Indemnifying Party of any Third-Party Claim asserted against the Indemnified Party and (ii) transmit to the Indemnifying Party a Claim Notice relating to such Third-Party Claim, a copy of all papers served with respect to such claim (if any), an estimate of the amount of damages attributable to the Third-Party Claim and the basis of the Indemnified Party's request for indemnification under this Agreement. During the Election Period, an Indemnifying Party shall notify an Indemnified Party (a) whether the Indemnifying Party disputes its potential liability to the Indemnified Party under this Article X with respect to such Third-Party Claim and (b) whether an Indemnifying Party desires, at the sole cost and expense of such Indemnifying Party, to defend the Indemnified Party against such Third-Party Claim. 10.6.2. DEFENSE BY INDEMNIFYING PARTY. If an Indemnifying Party notifies an Indemnified Party within the Election Period that the Indemnifying Party does not dispute its potential liability to the Indemnified Party under this Article X and that the Indemnifying Party elects to assume the defense of the Third-Party Claim, then the Indemnifying Party shall have the right to defend, at its sole cost and expense, such Third-Party Claim by all appropriate proceedings, which proceedings shall be prosecuted diligently by the Indemnifying Party to a final conclusion or settled at the discretion of the Indemnifying Party in accordance with this Section 10.6.2. The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof; provided, however, that any settlement entailing non-monetary consideration must be approved, in advance, by the Indemnified 20 22 Party, which approval shall not be unreasonably delayed or withheld. The Indemnified Party is hereby authorized, at the sole cost and expense of the Indemnifying Party (but only if the Indemnified Party is actually entitled to indemnification hereunder or if the Indemnifying Party assumes the defense with respect to the Third-Party Claim), to file, during the Election Period, any motion, answer or other pleadings which the Indemnified Party shall deem necessary or appropriate to protect its interests or those of the Indemnifying Party and not prejudicial to the Indemnifying Party (it being understood and agreed that if an Indemnified Party takes any such action that is prejudicial and conclusively causes a final adjudication adverse to the Indemnifying Party, the Indemnifying Party shall be relieved of its obligations hereunder with respect to such Third-Party Claim). If requested by the Indemnifying Party, the Indemnified Party agrees, at the sole cost and expense of the Indemnifying Party, to cooperate with the Indemnifying Party and its counsel in contesting any Third-Party Claim that the Indemnifying Party elects to contest, including, without limitation, the making of any related counterclaim against the person asserting the Third-Party Claim or any cross-complaint against any person. The Indemnified Party may participate in, but not control, any defense or settlement of any Third-Party Claim controlled by the Indemnifying Party pursuant to this Section 10.6., and shall bear its own costs and expenses with respect to any such participation. 10 6.3. DEFENSE BY INDEMNIFIED PARTY. If an Indemnifying Party fails to notify an Indemnified Party within the Election Period that the Indemnifying Party elects to defend the Indemnified Party pursuant to Section 10.6.2, or if the Indemnifying Party elects to defend the Indemnified Party pursuant to Section 10..2 but fails diligently and promptly to prosecute or settle the Third-Party Claim, then the Indemnified Party shall have the right to defend, at the sole cost and expense of the Indemnifying Party, the Third-Party Claim by all appropriate proceedings, which proceedings shall be diligently prosecuted by the Indemnified Party to a final conclusion or settled. The Indemnified Party shall have full control of such defense and proceedings; and provided, however, that without the Indemnifying Party's consent, which consent shall not be unreasonably delayed or withheld, the Indemnified Party shall not be authorized by the Indemnifying Party to enter into any compromise or settlement of such Third Party Claim on any non-monetary basis; and provided further, however, that if requested by the Indemnified Party, the Indemnifying Party shall, at the sole cost and expense of the Indemnifying Party, cooperate with the Indemnified Party and its counsel in contesting any Third-Party Claim that the Indemnified Party is contesting, or, if appropriate and related to the Third-Party Claim in question, in making any counterclaim against the person asserting the Third-Party Claim or any cross-complaint against any person. Notwithstanding the foregoing, if the Indemnifying Party has delivered a written notice to the Indemnified Party to the effect that the Indemnifying Party disputes its potential liability to the Indemnified Party under this Article X and if such dispute is resolved in favor of the Indemnifying Party by a final, nonappealable order of a court of competent jurisdiction, the Indemnifying Party shall not be required to bear the costs and expenses of the Indemnified Party's defense pursuant to this Section 10.6 or of the Indemnifying Party's participation therein at the Indemnified Party's request, and the Indemnified Party shall reimburse the Indemnifying Party in full for all costs and expenses of such litigation. The Indemnifying Party may participate in, but not control, any defense or settlement controlled by the Indemnified Party pursuant to this Section 10.6, and the Indemnifying Party shall bear its own costs and expenses with respect to any such participation. 10.6.4. OTHER CLAIMS. In the event any Indemnified Party should have a claim against any Indemnifying Party hereunder that does not involve a Third-Party Claim, the Indemnified Party shall transmit to the Indemnifying Party an Indemnity Notice with respect to such claim. If the Indemnifying Party does not notify the Indemnified Party in writing within Sixty (60) days from its receipt of the Indemnity Notice that the Indemnifying Party disputes such claim, the claim specified by the Indemnified Party in the Indemnity Notice shall be deemed a liability of the Indemnifying Party hereunder. If the Indemnifying Party has timely disputed such claim, as provided above, such dispute shall be resolved by binding arbitration. 10.7. TAX BENEFITS, INSURANCE PROCEEDS AND INDEMNIFICATION PAYMENTS. In determining the amount of any loss, liability or expense for which an Indemnified Party is entitled to indemnification 21 23 under this Article X, the gross amount thereof will be reduced by any correlative insurance proceeds, if any, realized or to be realized by such Indemnified Party, and such correlative insurance benefit shall be net of any insurance premium that becomes due as a result of such claim. 10.8. TAX ON INDEMNIFICATION PAYMENTS. After taking into account any adjustment required by Section 10.6, the amount of each payment by an Indemnifying Party under Section 10.2 and Section 10.3 shall include any additional amount necessary to indemnify the Indemnified Party against any taxes imposed in connection with such payment. ARTICLE XI BROKERS Seller has retained Reid Investments Inc. to assist and advise it in connection with the transactions contemplated by this Agreement Seller will be responsible for any fees payable to Reid. Purchaser and Seller represent to the other that, except as set forth in the preceding sentence, neither has, directly or indirectly, employed any broker, finder or intermediary in connection with such transactions that might be entitled to a fee or commission for which the other party shall have any obligation or responsibility upon the execution of this Agreement or the consummation of such transactions. ARTICLE XII EXPENSES Except as specifically provided herein, all legal and other costs and expenses in connection with this Agreement and the transactions contemplated hereby shall be paid by the party that incurred such costs and expenses. ARTICLE XIII NOTICES; MISCELLANEOUS 13.1. NOTICES. All notices and other communications given hereunder shall be in writing and shall be deemed given if delivered personally, including delivery by a nationally recognized courier service, or mailed by registered or certified mail, return receipt requested, to the parties at the following addresses: (i) If to Purchaser, to: Goldking Trinity Bay Corp. 1221 McKinney Suite 1800 Houston, Texas 77010 Attention: Leonard C. Tallerine, Jr. With a copy to: Looper, Reed, Mark & McGraw 9 East Greenway Plaza Suite 1717 Houston, Texas 77046 Attention: Mark Licata 22 24 (ii) If to Seller to: Benton Oil & Gas Combination Partnership 1991-1, L.P. c/o Benton Oil & Gas Company 1145 Eugenia Place Carpinteria, Califomia 93013 Attention: Clarence Cottman 13.2. MISCELLANEOUS. 13.2.1. EXCLUSIVE AGREEMENT. This Agreement supersedes all prior written or oral agreements between the parties with respect to the transactions contemplated herein, and is intended as a complete and exclusive statement of the terms of the agreement between the parties with respect to the transactions contemplated herein. 13.2.2. CHOICE OF LAW; CHOICE OF FORUM; AMENDMENTS; HEADINGS. This Agreement shall be governed by the internal laws of the State of Texas, without giving effect to principles of conflicts of laws. This Agreement may not be changed or terminated orally. The headings contained in this Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement. Terms such as "herein," "hereby," "hereto" and "hereof" refer to this Agreement as a whole. The term "include" and derivatives thereof are used in an illustrative sense and not a limitative sense. 13.2.3. ASSIGNMENTS AND THIRD PARTIES. No party hereto shall assign this Agreement or any part hereof without the prior written consent of the other parties; provided, however, that Purchaser shall be authorized to assign this Agreement provided that no such assignment shall release Purchaser from any of its obligations under this Agreement. Except as otherwise provided herein, this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and permitted assigns. Nothing in this Agreement shall entitle any Person, other than the parties hereto or their respective permitted successors and assigns, to any claim, cause of action, remedy or right of any kind. 13.2.4. SUBSEQUENT FILINGS. Effective at the Closing Date, Purchaser shall file with General Land Office of the state of Texas and with such other Governmental Authorities such notices or certificates as are necessary to reflect the sale of the Transferred Assets to Purchaser. 13.2.5. SEVERABILITY. If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any manner materially adverse to any party. Upon any binding determination that any term or other provision is invalid, illegal or incapable of being enforced, the parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the parties as closely as possible in an acceptable and legally enforceable manner, to the end that the transactions contemplated hereby may be completed to the extent possible. 13.2.6. COUNTERPARTS. This Agreement may be executed in any number of counterparts, each of which shall be deemed to be an original and all of which together shall constitute but one and the same agreement. 23 25 13.2.7. FURTHER ASSURANCES. (i) The parties each agree to deliver or cause to be delivered to the others on the Closing Date, and at such other times thereafter as shall be reasonably requested, any additional instrument that the other may reasonably request for the purpose of carrying out this Agreement. (ii) After the Closing, Seller and Purchaser shall, and shall cause their affiliates to, execute, acknowledge and deliver all such further conveyances, transfer orders, division orders, notices, assumptions, releases and acquittances, and such other instruments, and shall take such further actions as may be necessary or appropriate to assure fully to Purchaser, its successors or assigns, all of the Transferred Assets intended to be conveyed to Purchaser by the Instruments of Transfer pursuant to this Agreement, and to assure fully to Seller and its affiliates and its successors and assigns, the assumption of the liabilities and obligations intended to be assumed by Purchaser pursuant to this Agreement. 13.2.8 PRESERVATION OF BOOKS AND RECORDS. For a period of seven (7) years (five (5) years with respect to geophysical data related to the Transferred Assets) after the Closing Date, Purchaser and Seller (if and to the extent Seller has retained any of the hereinafter described records not delivered to Purchaser at Closing) shall (i) preserve and retain the corporate, accounting, legal, auditing and other books and records that relate to the conduct of Seller's businesses and operations prior to the Closing Date (including, but not limited to, any documents relating to any governmental or non-governmental actions, suits, proceedings or investigations arising out of the conduct of the business and operations of Seller prior to the Closing Date and including, but not limited to, all financial statements and other data and information necessary or desirable for Purchaser to comply with their public reporting requirements) and (ii) make such books and records available at their then current administrative headquarters to the other party and its officers, employees, agents and affiliates upon reasonable notice and at reasonable times, it being understood that such other party shall be entitled to make and retain copies of any such books and records as it shall deem necessary. Purchaser and Seller agrees to permit representatives of the other party to meet with its employees on a mutually convenient basis in order to enable such other party to obtain additional information and explanations of any materials provided pursuant to this Section 13.2.8. -the remainder of this page left blank intentionally- 24 26 IN WITNESS WHEREOF, the undersigned have executed this Agreement as of the date first written above. PURCHASER: GOLDKING TRINITY BAY CORP. By:___________________________________ Name:_________________________________ Title:________________________________ SELLER: BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P. By: BENTON OIL AND GAS COMPANY, Managing General Partner By:___________________________________ Name:_________________________________ Title:________________________________ 25 27 APPENDIX A Definitions Capitalized terms used in this Agreement shall have the meanings ascribed to them in this Appendix A unless such terms are defined elsewhere in this Agreement: Agreed Interest Rate: Ten percent (10%) per year. Best Efforts: A party's best efforts in accordance with reasonable commercial practices and without the incurrence of unreasonable expense. Claim Notice: A written notice delivered by an Indemnified Party to an Indemnifying Party pursuant to Section 10.6.1 describing in reasonable detail the nature of a Third-Party Claim that could give rise to a right of indemnification under this Agreement. Claimed Interest Additions: The Interest Additions claimed by Seller on the list to be submitted to Purchaser within thirty (30) days after the date of this Agreement pursuant to Section 6 3. Closing: The closing of the transactions contemplated by this Agreement. Closing Date: The date of the Closing. Code: The Internal Revenue Code of 1986, as amended. Data Rooms: The data rooms prepared by Seller to provide information to Persons considering the acquisition of the Transferred Assets Defensible Title: Such title to the Transferred Interests, free and clear of all Encumbrances other than Permitted Encumbrances, that is deducible of record and free from reasonable doubt to the end that a prudent person engaged in the business of the ownership, development and operation of producing oil and gas properties, with knowledge of all the facts and the legal bearing of such facts and the commercial effect of such facts on the continued control and operation of the Transferred Assets, would be willing to accept such title. Effective Time: The effective time of the transfer of the Transferred Assets to Purchaser, which shall be deemed to be 7:00 a.m., Houston, Texas time, on January 1, 1995. Election Period: The 30-day period following receipt by an Indemnifying Party of a Claim Notice. Encumbrance: Any mortgage, lien, security interest, pledge, charge, encumbrance, claim, limitation, preferential right to purchase, consent to assignment, irregularity, burden or defect or any other claim that Seller does not own the Warranted Interest. Entity: A corporation, partnership, joint venture, trust or unincorporated organization or association or other entity. Appendix A Page 1 28 Environmental Laws: All federal, state and local laws relating to the protection of human health and safety or the environment, including but not limited to the federal Comprehensive Environmental Response, Compensation, and Liability Act, the Resource Conservation and Recovery Act, the Safe Drinking Water Act, the Toxic Substances Control Act, the Clean Water Act, the Coastal Zone Management Act, the Endangered Species Act, the Oil and the Hazardous Materials Transportation Act, all as amended, and all analogous state and local laws. Environmental Indemnity Period: The period beginning on the Closing Date and ending two (2) years after the Closing Date. Governmental Authority: The United States of America, any state, commonwealth, territory or possession thereof and any political subdivision of any of the foregoing, including but not limited to courts, departments, commissions, boards, bureaus, agencies or other instrumentalities. Hazardous Substance: Any substance or material now or hereafter defined as a "hazardous substance", "hazardous material", "hazardous waste", "contaminant", or "pollutant" under any environmental laws, including but not limited to Section 1.01 of the Comprehensive Environmental Response, Compensation and Liability Act, 4-2 U.S.C.A. 9601. Hydrocarbons: Oil, gas, minerals (including but not limited to sulfur) and other gaseous and liquid hydrocarbons or any combination thereof. Indemnified Party: A party claiming indemnification under this Agreement (other than a claim for indemnification under Section 10.4, Article VI or Article VIII). Indemnifying Party: A party from whom indemnification under this Agreement (other than indemnification under Section 10.4, Article VI or Article VIII) is sought. Indemnity Notice: A written notice from an Indemnified Party to an Indemnifying Party with respect to a claim for indemnification under this Agreement (other than indemnification under Section 10.4, Article VI or Article VIII) not involving a Third-Party Claim, which notice shall describe in detail the nature of the claim and set forth an estimate of the amount of damages attributable to such claim and the basis of the Indemnified Party's request for such indemnification. Initial Payment: The initial payment of the Purchase Price in the amount of TWO THOUSAND EIGHT HUNDRED TWENTY-FOUR DOLLARS ($2,824), paid by Purchaser to Seller, on the date this Agreement was executed. Knowledge: The actual knowledge of each executive officer of Seller (assuming such Seller is a corporation, and if not, a Person in a similar capacity) after reasonable inquiry, or Purchaser, as the case may be. Leases: As defined in the Instruments of Transfer. Legal Requirement: Any law, statute, ordinance, decree, requirement, order, judgment rule or regulation of, including the terms of any license or permit issued by, any Governmental Authority. Material Adverse Effect: Any material adverse effect on or with respect to the Transferred Assets or on the business, operations, prospects or condition of the Transferred Assets, taken as a whole. Appendix A Page 2 29 Net Revenue Interest: The interest (expressed as a percentage) of Seller in and to Hydrocarbons produced from or allocated to a Property after deducting all applicable Production Burdens. NGA: The Natural Gas Act of 1938. NGPA: The Natural Gas Policy Act of 1978. Permitted Encumbrances: Any or all of the following: (i) encumbrances that arise under operating agreements to secure payment of amounts not yet delinquent and are of a type and nature customary in the oil and gas industry; (ii) encumbrances that arise as a result of pooling and unitization agreements, and production sales contracts securing the payment of amounts not yet delinquent; (iii) consents to assignment by Governmental Authorities (a) that are obtained on or prior to the Closing Date or (b) that are customarily obtained after the consummation of transactions of the nature contemplated by this Agreement; (iv) conventional rights of reassignment obligating Seller to reassign its interest in any portion of the Properties to a third party in the event it intends to release or abandon such interest prior to the expiration of the primary term or other termination of such interest; (v) easements, rights-of-way, servitudes, permits, surface leases, surface use restrictions and other surface uses and impediments on, over or in respect of any of the Properties that are not such as to interfere materially with the operation, value or use of any of the Properties; (vi) such Title Defects and Environmental Defects as Purchaser has expressly waived in writing; (viii) such Title Defects for which Purchaser failed to give timely notice according to Section 6.2; (ix) such Environmental Defects (to the extent the Purchaser has Knowledge of such Environmental Defect) for which Purchaser failed to give timely notice according to Section 6.2 or for which Purchaser failed to provide written information as required by Section 6.2; (x) rights reserved to or vested in any municipality or governmental, tribal, statutory or public authority to control or regulate any of the Properties in any manner, and all applicable laws, rules and orders of any municipality or governmental or tribal authority; (xi) all production burdens that do not operate to (A) reduce the Net Revenue Interest below the Warranted Interest or (B) increase the Working Interest above the Warranted Interest; (xii) the preferential purchase rights for which waivers have been obtained prior to the Closing Date; Appendix A Page 3 30 (xiii) the terms and conditions of the Contracts, insofar and only insofar as the Contracts do not operate to (A) reduce the Net Revenue Interest of Seller below that set forth on Exhibit A hereto, (B) increase the Working Interest of Seller above that set forth on Exhibit A hereto without a proportionate increase in the Net Revenue Interest of Seller. (xiv) any other Encumbrance affecting any portion of a Transferred Asset that individually does not materially adversely affect the operation, value or use of any such Transferred Asset; and (xv) solely during the period prior to the Closing, any Encumbrance that is released on or before Closing. Person: shall mean a corporation, an association, a partnership, an organization, a business, an individual, a government or political subdivision thereof, or a governmental agency. Production Burdens: All royalty interests, overriding royalty interests, production payments, net profits interests or other similar interests that constitute a burden on, are measured by or are payable out of the production of Hydrocarbons or the proceeds realized from the sale or other disposition thereof. Purchase Price Adjustment Amount: The net adjustment to the Purchase Price to be made pursuant to Section 1.3.1. Purchase Price Adjustment Certificate: A statement of the Purchase Price Adjustment Amount (specifying whether the Purchase Price is to be increased or decreased by such amount), which shall be certified by an officer of Seller. Seller's Affiliate: Any person that directly or indirectly, through one or more intermediaries, controls, is controlled by or is under common control with, such Seller. Subsidiary: shall mean, as to a Person, any other Person (a) more than 50% of the outstanding voting stock of which is held, directly or indirectly, by such Person, or (b) over which such Person has the power, directly or indirectly, to designate a majority of the directors thereof (if such other Person is a corporation) or the individuals exercising similar functions (if such other Person is unincorporated). Third-Party Claim: A third-party claim asserted against an Indemnified Party that could give rise to a right of indemnification under this Agreement (other than a right of indemnification under Section 10.4, Article VI or Article VIII). Transferred Assets: As defined in Section 1.1. Warranted Interests: those interests whereby a Seller is (i) entitled to receive not less than the "Net Revenue Interest" set forth on Exhibit A hereto of all oil, gas and associated liquid and gaseous Hydrocarbons produced, saved and marketed from the Properties, without reduction, throughout the productive life of such Properties and (ii) obligated to bear the percentage of the costs and expenses related to the maintenance, development and operation of the Properties in an amount not greater than the "Working Interest" set forth on Exhibit A hereto, without increase, throughout the productive life of such Properties, except increases that result in a proportionate increase in such Seller's Net Revenue Interest and increases that results from contribution requirements with respect to defaulting co-owners. Appendix A Page 4 31 Working Interest: The interest (expressed as a percentage) of a Seller in any Transferred Asset before giving effect to any applicable Production Burdens and the percentage of all costs and expenses associated with the exploration, development and operation of such Transferred Asset required to be borne by such Seller. Appendix A Page 5 32 SCHEDULE 1.2.1 INDIVIDUAL INTEREST VALUATIONS
WORKING NET REVENUE PURCHASE SELLER INTEREST INTEREST PRICE Benton Oil & Gas Combination 2.824751% 2.358666% $216,093.00 Partnership 1991 -1, L.P., a California limited partnership
Appendix A Page 6 33 BILL OF SALE, CONVEYANCE AND PARTIAL ASSIGNMENT STATE OF TEXAS ) ) COUNTY OF CHAMBERS ) This Bill of Sale, Conveyance and Partial Assignment is from BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1 L.P., a California limited partnership, whose mailing address is 1145 Eugenia Place, Carpinteria, California ("Grantor"), to GOLDKING TRINITY BAY CORP., a Texas corporation ("Grantee"), whose mailing address is 1221 McKinney, Suite 1800, Houston, Texas 77002. I. NOW, THEREFORE, for and in consideration of Ten and No/100 Dollars ($10.00) and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Grantor has granted, bargained, sold, transferred, assigned and conveyed, and by these presents does hereby grant, bargain, sell, transfer, assign and convey unto Grantee, its successors and assigns, subject to the hereinafter stated exceptions, restrictions, covenants and conditions, all of Grantor's interest in and to the following described properties, to-wit: (a) the leasehold estate created by each of the Oil, Gas and Mineral Leases listed and described in Exhibit "A", which is annexed hereto and incorporated herein for all purposes, such leases being hereinafter sometimes referred to as "Subject Leases:' (b) All payments out of production, overriding royalty interests, carried interests, reversionary interests, and all other rights and interests incident to, or held and owned by Grantor in connection with the Subject Leases, save and except the overriding royalty excepted and reserved hereinbelow by Grantor; (c) All oil, gas, condensate, casinghead gas and other related hydrocarbon substances produced and saved subsequent to the Effective Date of this conveyance from lands covered and affected by the Subject Leases. (The interest described under subparagraphs (a) and (b) above, and this subparagraph (c) are hereinafter sometimes collectively referred to as "Subject Properties"); (d) All personal property and facilities located on lands covered by the Subject Leases or the Subject Interests, or both, incident to or held and used in connection with the Subject Interests, including, but not limited to, all tanks, tank batteries, gas plants, disposal facilities, buildings, structure, platforms, field separators and liquid extractors, treators, dehydrators, compressors, pumps, pumping units, valves, fittings, machinery and parts, engines, boilers, meters, apparatus, implements, tools, appliances, cables, wires, towers, casing, tubing and rods, gathering lines or other pipelines, field gathering systems and any and all other fixtures and equipment of every type and description to the extent that the same are used or held in connection with the ownership or operation of the Subject Interests; 34 (e) All oil, natural gas or water source wells, whether producing, operating, shut-in, or temporarily abandoned; all types of injection wells; and all equipment used or held by Grantor in connection with the production of oil, gas, condensate, casinghead gas and other related hydrocarbon substances from or attributable to lands covered by the Subject Leases; (f) All tenements, appurtenances, surface leases, easements, permits, licenses, servitudes, or rights-of-way in any way appertaining, belonging, affixed and used in connection with, or incident to, the ownership and operation of the Subject Interests, including, but not limited to, those tenements, appurtenances, surface leases, easements, permits, licenses, servitudes or rights-of-way listed and described in Exhibit "B", annexed hereto and incorporated herein for all purposes; (g) All leases, options, rights of first refusal, orders, contracts, operating agreements, bottom-hole agreements, farmin/farmout agreements, acreage contribution agreements, unit agreements, processing agreements, maintenance agreements, purchase and sale agreements for gas, oil or other minerals, and other agreements and instruments to the extent that same relate, appertain, belong or are in any way incidental to the ownership of the Subject Interests by Grantor, including, but not limited to, those listed and described in Exhibit "C", annexed hereto and incorporated herein for all purposes; (h) All lease files, land files, well files, abstracts, title opinions, title curative, accounting records, royalty payment records, seismic records and surveys, gravity maps, electric logs, contracts, correspondence, microfiche lists, geological and geophysical maps, pressure date and decline curves, graphical production curves and other geological or geophysical data, records and other documents and records of every kind and description which relate to and are possessed by Grantor in connection with the Subject Interests, to the extent and as provided for or limited by that certain Purchase and Sale Agreement dated effective April 1, 1989 by and between Grantor and Texaco Producing Inc.; and (i) Any and all monies held by any individual, partnership, or corporate entity, whether or not such monies are held in escrow, payable to either Texaco Producing Inc. or Grantor, or both, for oil, gas condensate, casinghead gas or other related hydrocarbon substance produced and saved from or attributable to the Subject Leases and purchased by such individual, partnership or corporate entity subsequent to the Effective Date of this conveyance. The interests described under subparagraph (a) through (i) hereinabove are herein sometimes collectively referred to as "Subject Interests". II. This Bill of Sale, Conveyance and Assignment is made by Grantor and accepted by Grantee subject to the following: (a) All the terms, conditions and obligations contained and provided for in the Subject Leases; 2 35 (b) The terms and conditions of all existing orders, rules, regulations and ordinances of any federal, state or other governmental agency that are applicable or related to the Subject Interests; (c) The terms and conditions of the Purchase and Sale Agreement, dated the same date as this conveyance instrument, by and between Grantor, as a Seller and Grantee as the Purchaser, concerning the Subject Interests; and (d) Grantee accepting the Subject Interest in its "as is, where is" condition; Grantor disclaiming any and all liability arising in connection with any environmental matters, including, without limitation, any presence of naturally occurring radioactive material on the property; and Grantee expressly waiving the provisions of Chapter XVII, Subchapter E, Sections 17.41 through 17.63, inclusive, except Section 17.555 which is not waived, of Vernon's Texas Code Annotated, Business and Commerce Code. In addition, there are no warranties or representations, either express or implied, as to the quality or quantity of the hydrocarbon reserves, if any, attributable to the interest conveyed herein or the ability of the property to produce hydrocarbons. TO HAVE AND TO HOLD all and singular the Subject Interest, as hereinabove described, unto Grantee, its successors and assigns, and Grantor, for itself, its successors and assigns, does hereby WARRANT AND FOREVER DEFEND, all and singular, title to the Subject Interests, free from all liens, claims, assessments and encumbrances, other than the existing burdens, unto Grantee, Grantee's successors and assigns, against every person lawfully claiming or to claim the same, or any part hereof, BY, THROUGH OR UNDER GRANTOR, BUT NOT OTHERWISE. The reference herein to the "existing burdens" is for the purpose of protecting Grantor on Grantor's warranties, and shall not create, nor constitute a recognition of any rights in third parties. Grantor grants unto Grantee full power and right of substitution and subrogation in and to all covenants and warranties by others heretofore given or made in respect of the Subject Interests. III. The provisions hereof shall inure to the benefit of and be binding upon the parties hereto, their respective legal representatives, successors and assigns. IN TESTIMONY WHEREOF, this Conveyance is executed on the dates and at the places indicated in the respective acknowledgments below, but is stipulated herein to be effective as of 7:00 a.m., C.D.S.T., the 1st day of January, 1995. GRANTOR: BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P. By:_______________________________ 3 36 [acknowledgments] 4 EX-5.1 5 EX-5.1 1 EXHIBIT 5.1 [EMENS, KEGLER, BROWN, HILL & RITTER LETTERHEAD] October 3, 1995 Benton Oil and Gas Company 1145 Eugenia Place Suite 200 Carpinteria, California 93013 Gentlemen: We have acted as counsel for Benton Oil and Gas Company (the "Company") in connection with the registration under the Securities Act of 1933, as amended, of up to 189,068 shares of common stock, $0.01 par value per share (the "Shares"), and 651,610 Warrants to purchase shares of common stock (the "Warrants"), and the 651,610 shares of Common Stock issuable upon exercise of the Warrants to be offered to holders of partnership interests in the Benton Oil & Gas Combination Partnership 1989-1 L.P., the Benton Oil & Gas Combination Partnership 1990-1 L.P., and the Benton Oil & Gas Combination Partnership 1991-1 L.P. (the "Partnerships") in exchange for such partnership interests. In this connection, we have examined the Certificate of Incorporation, the Bylaws and the respective amendments thereto, the directors' and stockholders' minutes, and the Registration Statement filed with the Securities and Exchange Commission, and exhibits thereto, and such other documents that we have deemed necessary to the opinion hereinafter expressed. We are of the opinion that the Shares are validly authorized and upon their issuance in exchange for partnership interests in the Benton Oil & Gas Combination Partnership 1989-1 L.P., the Benton Oil & Gas Combination Partnership 1990-1 L.P., and the Benton Oil & Gas Combination Partnership 1991-1 L.P. as contemplated by the Registration Statement, will be legally issued, fully paid, and non-assessable. We are of the opinion that the Warrants are validly authorized and upon their issuance in exchange for partnership interests in the Partnerships will be legally issued. 2 [EMENS, KEGLER, BROWN, HILL & RITTER LETTERHEAD] We are of the opinion that the Shares to be issued upon exercise of the Warrants as contemplated by the Warrant Agreement will be validly authorized, legally issued, fully paid, and non-assessable. We hereby consent to the reference to Emens, Kegler, Brown, Hill & Ritter Co., L.P.A. appearing under the heading "Legal Matters" in the Registration Statement and any amendments thereto and the Prospectus of the Company relating to the proposed exchange of the Shares and Warrants. Very truly yours, EMENS, KEGLER, BROWN, HILL & RITTER CO., L.P.A. By: /s/ Jack A. Bjerke _______________________________________ Jack A. Bjerke, Vice President EX-8.1 6 EX-8.1 1 Exhibit 8.1 EMENS, KEGLER, BROWN, HILL & RITTER A Legal Professional Association ATTORNEYS AND COUNSELORS AT LAW CAPITOL SQUARE SUITE 1800 65 EAST STATE STREET COLUMBUS, OHIO 43215-4294 _____________________ October 2, 1995 Benton Oil and Gas Company Attention: Gregory S. Grabar 1145 Eugenia Place, Suite 200 Carpinteria, California 93013 Re: Form S-4 Registration Statement under Securities Act of 1933 SEC File Number 33-61299-Federal Tax Consequences Dear Mr. Grabar: We have acted as counsel to Benton Oil and Gas Company, a Delaware corporation (the "Company"), in connection with the registration under the Securities Act of 1933 of the Company's Common Stock and Warrants. In this connection, we have examined the registration statement on Form S-4 (the "Registration Statement"), including the proxy statement-prospectus which forms a part of the Registration Statement (the "Prospectus") and such other documents as we deem necessary for the purposes of this opinion. Based on the foregoing and subject to the limitations set forth herein, it is our opinion that the description of federal income tax consequences included in the Prospectus under the heading "Certain Federal Tax Consequences" accurately sets forth the federal income tax consequences under existing law relating to the Exchange to which such discussion refers. We hereby consent to the filing of this opinion as an exhibit to the Registration Statement. In giving this consent, we do not admit that we are within the category of persons whose consent is required by Section 7 of the Securities Act of 1933, as amended. Sincerely yours, EMENS, KEGLER, BROWN, HILL & RITTER By: /s/ Jack A. Bjerke ------------------------------- Jack A. Bjerke, Vice President EX-23.1 7 EX-23.1 1 Exhibit 23.1 INDEPENDENT AUDITORS' REPORT We consent to the use in this Registration Statement of Benton Oil and Gas Company on Form S-4 of our reports dated March 31, 1995 relating to the financial statements of Benton Oil and Gas Company, Benton Oil & Gas Combination Partnership 1989 - 1, L.P., Benton Oil & Gas Combination Partnership 1990 - 1, L.P. and Benton Oil & Gas Combination Partnership 1991 - 1, L.P., appearing in the Prospectus, which is a part of such Registration Statement, and to the reference to us under the heading "Experts" in such Prospectus. Deloitte & Touche LLP Deloitte & Touche LLP Los Angeles, California September 28, 1995 EX-23.3 8 EX-23.3 1 Exhibit 23.3 Huddleston & Co., Inc. Petroleum and Geological Engineers 1111 FANNIN-SUITE 1700 HOUSTON, TEXAS 77002 _________________ (713) 658-0248 CONSENT OF INDEPENDENT PETROLEUM ENGINEER ----------------------------------------- Gentlemen: Huddleston & Co., Inc., hereby consents to the use of its name, use of its audit reports, and reference to it regarding its audit of the Benton Oil and Gas Company reserve reports, prepared by Benton Oil and Gas Company, dated March 8, 1995, included in Amendment No. 1 to the Form S-4 Registration Statement, or included therein by reference to the Form 10-K for the year ended December 31, 1994, of Benton Oil and Gas Company registering shares of its common stock for exchange to holders of partnership interests in Benton Oil & Gas Combination Partnership 1989-1, L.P., Benton Oil & Gas Combination Partnership 1990-1, L.P., and Benton Oil & Gas Combination Partnership 1991-1, L.P. HUDDLESTON & CO., INC. /s/ Peter D. Huddleston ------------------------------------- Peter D. Huddleston, P.E. President Date: September 28, 1995 -----END PRIVACY-ENHANCED MESSAGE-----