BENTON OIL & GAS CO, S-4/A, 1995-10-31

BENTON OIL & GAS CO
S-4/A, 1995-10-31
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1

AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON OCTOBER 31, 1995

REGISTRATION NO. 33-61299
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------

AMENDMENT NO. 3 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)

<TABLE>
<S> <C> <C>
DELAWARE 1311 77-0196707
(STATE OR OTHER JURISDICTION (PRIMARY STANDARD INDUSTRIAL (I.R.S. EMPLOYER
OF INCORPORATION OR
ORGANIZATION) CLASSIFICATION CODE) IDENTIFICATION NUMBER)
</TABLE>

------------------------

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. / /
------------------------

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.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE> 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.

<TABLE>
<CAPTION>
FORM S-4 ITEM LOCATION IN PROSPECTUS
----------------------------------------------- -------------------------------------
<S> <C> <C>
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
9. Disclosure of Commission Position on
Indemnification for Securities Act
Liabilities.................................... Not Applicable
</TABLE>
<PAGE> 3

<TABLE>
<CAPTION>
FORM S-4 ITEM LOCATION IN PROSPECTUS
----------------------------------------------- -------------------------------------
<S> <C> <C>
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
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
</TABLE>
<PAGE> 4

SUBJECT TO COMPLETION

DATED OCTOBER 31, 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.

THE EXCHANGE OFFER INVOLVES VARIOUS RISKS THAT SHOULD BE CONSIDERED BY
INVESTORS. SEE "RISK FACTORS AND MATERIAL CONSIDERATIONS," BEGINNING ON PAGE 29
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. 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.
<PAGE> 5

- 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.

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 43 and
"Method of Determining Exchange Values" at page 48. 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 "Method of Determining Exchange Values." Holders of Units
in the Partnerships who elect to accept the Exchange Offer may choose to receive
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., as described herein, is actually consummated. See "The Exchange Offer and
Proposal -- Election to Receive Cash in Lieu of Common Stock." On October 30,
1995, the last reported sales price of the Common Stock, as reported on NASDAQ
National Market, was $12.00.

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.

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.
<PAGE> 6

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.
<PAGE> 7

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.

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

i
<PAGE> 8

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
<PAGE> 9

TABLE OF CONTENTS

<TABLE>
<S> <C>
SUMMARY................................................................................ 1
Risk Factors and Material Considerations............................................. 1
The Parties.......................................................................... 3
The Exchange Offer and Proposals..................................................... 4
Dissenters' Rights................................................................... 5
Background and Alternatives to the Exchange.......................................... 6
Reasons for the Exchange Offer; Recommendation of the Managing General Partner....... 8
Managing General Partners Determination that Offer is Fair........................... 10
Summary of Tax Consequences.......................................................... 13
Accounting Treatment................................................................. 13
Request For Investor Listing......................................................... 13
Business of Benton and the Partnerships After the Consummation of the Exchange....... 13
Comparative Rights of Security Holders............................................... 13
Resales of Benton Common Stock....................................................... 14
Description of the Warrants.......................................................... 14
Method of Determining Exchange Value for 1989-1 Partnership.......................... 14
Method of Determining Exchange Value for 1990-1 Partnership.......................... 16
Method of Determining Exchange Value for 1991-1 Partnership.......................... 19
Consent Procedures................................................................... 21
Conditions to Exchange............................................................... 22
Regulatory Approvals................................................................. 22
Certain Historical and Pro Forma Financial Data...................................... 22
Certain Comparative Information...................................................... 28
RISK FACTORS AND MATERIAL CONSIDERATIONS............................................... 29
Risks Related to the Exchange Offer.................................................. 29
Risks Related to Benton.............................................................. 32
Risks Related to the Oil and Gas Industry............................................ 35
PRICE RANGE OF COMMON STOCK, DIVIDENDS AND DISTRIBUTIONS............................... 37
BACKGROUND OF EXCHANGE OFFER........................................................... 38
1989-1 Partnership................................................................... 38
1990-1 Partnership................................................................... 39
1991-1 Partnership................................................................... 40
Goldking Offer....................................................................... 41
THE EXCHANGE OFFER AND PROPOSAL........................................................ 43
Description of the Exchange Offer.................................................... 43
The Proposal......................................................................... 43
Dissenters' Rights................................................................... 44
Distribution of Common Stock and Warrants............................................ 45
Election to Receive Cash In Lieu of Common Stock..................................... 45
Interests of Certain Persons in the Exchange and Proposals........................... 45
Resale of Benton Common Stock........................................................ 45
Fractional Shares.................................................................... 46
Stock Exchange Listing............................................................... 46
Accounting Treatment................................................................. 46
Closing Date......................................................................... 46
Operations After the Exchange........................................................ 46
</TABLE>

iii
<PAGE> 10

<TABLE>
<S> <C>
Expenses; Fees....................................................................... 47
Benton's Dividend Policy............................................................. 47
Litigation and Related Matters....................................................... 47
METHOD OF DETERMINING EXCHANGE VALUES.................................................. 48
General.............................................................................. 48
1989-1 Partnership Exchange Value Components......................................... 49
1990-1 Partnership Exchange Value Components......................................... 50
1991-1 Partnership Exchange Value Components......................................... 52
RECOMMENDATION OF THE MANAGING GENERAL PARTNER......................................... 56
Managing General Partner's Reasons for Proposing the Exchange Offer.................. 56
Managing General Partner's Determination that Exchange Offer is Fair................. 58
Benefits of Continued Operations..................................................... 61
Benefits of Liquidation.............................................................. 64
Lack of Independent Representative................................................... 67
Board of Directors of Benton; Benton's Reasons for the Exchange...................... 68
Fiduciary Duties of Benton........................................................... 68
Access to Investor List and Program Records.......................................... 69
FAILURE TO APPROVE THE PROPOSALS....................................................... 69
CONSENT PROCEDURES..................................................................... 70
Written Consent and Vote Required.................................................... 70
Consent Tabulation................................................................... 70
Expiration of Exchange Offer......................................................... 70
Amount Tendered...................................................................... 70
Revocability of Tenders.............................................................. 70
Solicitation of Letters of Transmittal............................................... 70
Acceptance of Tenders................................................................ 71
Special Requirements for Certain Investors........................................... 71
Representations and Covenants........................................................ 71
Validity of Tenders.................................................................. 72
Payments of Fees and Expenses........................................................ 72
Compliance with Tender Offer Practices............................................... 72
CERTAIN FEDERAL TAX CONSEQUENCES....................................................... 73
Material Tax Consequences of the Exchange............................................ 73
Realization of Suspended Passive Losses.............................................. 73
Basis in Stock and Warrants.......................................................... 74
COMPARATIVE RIGHTS OF SECURITY HOLDERS................................................. 75
UNAUDITED PRO FORMA FINANCIAL INFORMATION.............................................. 81
INFORMATION CONCERNING BENTON.......................................................... 87
Business............................................................................. 87
Recent Events........................................................................ 92
INFORMATION CONCERNING 1989-1 PARTNERSHIP.............................................. 93
General.............................................................................. 93
Description of Oil and Gas Properties................................................ 93
Selected Historical Financial Data................................................... 94
Management's Discussion and Analysis of Financial Condition and Results of
Operations........................................................................ 95
</TABLE>

iv
<PAGE> 11

<TABLE>
<S> <C>
INFORMATION CONCERNING 1990-1 PARTNERSHIP.............................................. 97
General.............................................................................. 97
Description of Oil and Gas Properties................................................ 97
Selected Historical Financial Data................................................... 99
Management's Discussion and Analysis of Financial Condition and Results of
Operations........................................................................ 100
INFORMATION CONCERNING 1991-1 PARTNERSHIP.............................................. 102
General.............................................................................. 102
Description of Oil and Gas Properties................................................ 102
Selected Historical Financial Data................................................... 104
Management's Discussion and Analysis of Financial Condition and Results of
Operations........................................................................ 105
DESCRIPTION OF SECURITIES.............................................................. 107
LEGAL MATTERS.......................................................................... 107
EXPERTS................................................................................ 107
GLOSSARY............................................................................... 109
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
EXHIBIT F Warrant Valuation Opinion
</TABLE>

v
<PAGE> 12

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 29.

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 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.

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<PAGE> 13

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. 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.

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<PAGE> 14

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 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."

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.

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<PAGE> 15

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.

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.

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

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<PAGE> 16

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.

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.

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<PAGE> 17

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.

- 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. 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.

Goldking Offer. 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 working interest in the Umbrella Point Field owned by
each of Partnerships represents substantially all of the assets of each of
the Partnerships. At December 31,

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<PAGE> 18

1994, the discounted future net cash flows attributable to the Umbrella
Point Field represented 100%, 89% and 89% of the discounted future net
cash flows for all proved reserves of the 1989-1 Partnership, the 1990-1
Partnership and the 1991-1 Partnership, respectively. 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 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 in the form of
Benton Common Stock and Warrants valued at $370,098, $2,990,728 and
$692,349, respectively. These values for the consideration to be received
by the Partnerships were derived based upon the average closing price of
Benton Common Stock for the twenty trading days ended October 27, 1995
($11.00 per share) and the Warrants to be issued were valued using the
Black-Scholes methodology for valuing options ($3.64 per Warrant). See
"Risk Factors and Material Consideration -- Risks Related to the Exchange
Offer -- Potential Decline in Market Price of Common Stock" and
"-- Necessity for Effective Registration Statement for Exercise of
Warrants."

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."

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<PAGE> 19

Hunter Offer. In October 1994, Benton received an offer to purchase the
working interest in the Umbrella Point Field owned by the Partnerships and
Benton from Hunter Resources, Inc. ("Hunter"). The Hunter offer would have
paid a total of $2,697,575 in cash and $337,197 in the form of a
promissory note for the working interests owned in the Umbrella Point
Field by the Partnerships and the 11.77% working interest owned by Benton.
This offer compared to Goldking's offer of $2,579,555, all of which was
payable in cash. The offers of Goldking and Hunter are not directly
comparable because of the difference in the effective date of each
transaction and thus would need to be adjusted for production, expenses,
change in pricing and other factors. Hunter was unable to secure financing
for the transaction and subsequently withdrew its offer. 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 Umbrella Point Field.

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 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

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<PAGE> 20

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 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. Since the Partnerships are no longer involved in
exploration and development activities, the Investors are no longer subject to
those risks. However, if the Investors become stockholders of Benton, they will
become subject to the risks of exploration and development activities, which if
unsuccessful, could have an adverse affect on the market price of Benton's
Common Stock. 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

9
<PAGE> 21

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 Investors would become subject to the volatility of the market
value of the Benton Common Stock. Since there is currently no market for the
Investors' interests in the Partnerships, their interests are currently not
subject to the volatility of the market value of their interests. 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 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.

10
<PAGE> 22

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 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

<TABLE>
<CAPTION>
TOTAL VALUE PER
VALUATION METHOD INVESTOR VALUE(1) 1989-1 UNIT
--------------------------------------------------------- ----------------- -----------
<S> <C> <C>
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
</TABLE>

- ---------------
(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.

11
<PAGE> 23

1990-1 PARTNERSHIP

<TABLE>
<CAPTION>
TOTAL VALUE PER
VALUATION METHOD INVESTOR VALUE(1) 1990-1 UNIT
--------------------------------------------------------- ----------------- -----------
<S> <C> <C>
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
</TABLE>

1991-1 PARTNERSHIP

<TABLE>
<CAPTION>
TOTAL VALUE PER
VALUATION METHOD INVESTOR VALUE(1) 1991-1 UNIT
------------------------------------------------------- ----------------- -----------
<S> <C> <C>
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
</TABLE>

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.

12
<PAGE> 24

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.

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."

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."

13
<PAGE> 25

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. Benton engaged J.P. Morgan
Securities Inc. ("J.P. Morgan") to render its opinion as to the fair range of
values of the Warrants using the Black-Scholes methodology for pricing options.
J.P. Morgan has delivered its written opinion to the Board of Directors of
Benton, a copy of which is attached hereto as Exhibit F, to the effect that as
of October 23, 1995, the fair range of values of the Warrants based on the
Black-Scholes model is between $3.37 and $3.74 per Warrant. See "Method of
Determining Exchange Values -- Opinion Regarding Warrant Valuation." 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.

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

14
<PAGE> 26

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.

1989-1 PARTNERSHIP

EXCHANGE VALUE TABLE

<TABLE>
<CAPTION>
PARTICIPANTS EXCHANGE VALUE PER
TOTAL PARTNERSHIP
EXCHANGE VALUE(1) UNIT(2)
----------------- ------------------
<S> <C> <C>
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
</TABLE>

- ---------------
(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.

15
<PAGE> 27

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. Assuming the
market price of the Common Stock remains in the range of $11.00 per share and
that the Warrants could be sold at their estimated present value of $3.64 per
Warrant, the Investors in the 1989-1 Partnership would receive consideration in
the form of cash distributions, Common Stock and cash proceeds from the sale of
the Warrants equal to approximately 86% of their initial investment. Assuming
that the market price of the Common Stock declines to $7.50 per share, its
lowest price during the 52 weeks preceding the date of this Prospectus, the
Investors in the 1989-1 Partnership will have received consideration in the form
of cash distributions and Common Stock equal to approximately 76% of their
initial investment. On October 30, 1995, the last sales price of the Benton
Common Stock on NASDAQ National Market was $12.00 per share. The assumed market
price of the Common Stock of $16.75 per share discussed above represents a 40%
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

16
<PAGE> 28

and liabilities (reflected on the unaudited balance sheet) of the 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.

1990-1 PARTNERSHIP

EXCHANGE VALUE TABLE

<TABLE>
<CAPTION>
PARTICIPANTS EXCHANGE VALUE PER
TOTAL PARTNERSHIP
EXCHANGE VALUE(1) UNIT(2)
----------------- ------------------
<S> <C> <C>
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
</TABLE>

- ---------------
(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.

(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.

17
<PAGE> 29

(6) Obtained by dividing the Exchange Value attributable to stock by the Common
Stock price of $11.00, subject to rounding adjustments.

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.

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. Assuming the
market price of the Common Stock remains in the range of $11.00 per share and
that the Warrants could be sold at their estimated present value of $3.64 per
Warrant, the Investors in the 1990-1 Partnership would receive consideration in
the form of cash distributions, Common Stock and cash proceeds from the sale of
the Warrants equal to approximately 77% of their initial investment. Assuming
that the market price of the Common Stock declines to $7.50 per share, its
lowest price during the 52 weeks preceding the date of this Prospectus, the
Investors in the 1990-1 Partnership will have received consideration in the form
of cash distributions and Common Stock equal to approximately 47% of their
initial investment. On October 30, 1995, the last sales price of the Benton
Common Stock on NASDAQ National Market was $12.00 per share. The assumed market
price of the Common Stock of $16.75 per share discussed above represents a 40%
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

18
<PAGE> 30

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.

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.

19
<PAGE> 31

1991-1 PARTNERSHIP

EXCHANGE VALUE TABLE

<TABLE>
<CAPTION>
PARTICIPANTS EXCHANGE VALUE PER
TOTAL PARTNERSHIP
EXCHANGE VALUE(1) UNIT(2)
----------------- ------------------
<S> <C> <C>
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
</TABLE>

- ---------------
(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.

(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.

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.

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.

20
<PAGE> 32

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. Assuming the
market price of the Common Stock remains in the range of $11.00 per share and
that the Warrants could be sold at their estimated present value of $3.64 per
Warrant, the Investors in the 1991-1 Partnership would receive consideration in
the form of cash distributions, Common Stock and cash proceeds from the sale of
the Warrants equal to approximately 73% of their initial investment. Assuming
that the market price of the Common Stock declines to $7.50 per share, its
lowest price during the 52 weeks preceding the date of this Prospectus, the
Investors in the 1991-1 Partnership will have received consideration in the form
of cash distributions and Common Stock equal to approximately 38% of their
initial investment. On October 30, 1995, the last sales price of the Benton
Common Stock on NASDAQ National Market was $12.00 per share. The assumed market
price of the Common Stock of $16.75 per share discussed above represents a 40%
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.

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."

21
<PAGE> 33

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 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

22
<PAGE> 34

Financial Condition and Results of Operations, and Pro Forma Financial
Information included elsewhere herein or incorporated by reference herein.

<TABLE>
<CAPTION>
SIX MONTHS
ENDED
YEARS ENDED DECEMBER 31, JUNE 30,
------------------------------------------------ ------------------
1990(3) 1991(3) 1992 1993 1994 1994 1995
------- ------- ------- ------- -------- -------- -------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
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
</TABLE>

<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS
DECEMBER 31, ENDED JUNE 30,
1994 1995
------------ ----------------
<S> <C> <C>
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
</TABLE>

23
<PAGE> 35

<TABLE>
<CAPTION>
AT JUNE 30, 1995
AT DECEMBER 31, ---------------------
-------------------------------------------------- PRO
1990 1991 1992 1993 1994 HISTORICAL FORMA
------- -------- ------- -------- -------- ---------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
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).... 10,063 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
</TABLE>

- ---------------
(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.

24
<PAGE> 36

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.

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEARS ENDED DECEMBER 31, JUNE 30,
----------------------------------------------------------- -------------------
1990 1991 1992 1993 1994 1994 1995
---------- ---------- --------- --------- --------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
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 --
</TABLE>

<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
----------------------------------------------------------- -------------------
1990 1991 1992 1993 1994 1994 1995
---------- ---------- --------- --------- --------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
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
</TABLE>

- ---------------
(1) Per unit data is based on indicated amounts allocable to limited partners
other than Benton divided by 279 limited partner units outstanding.

25
<PAGE> 37

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.

<TABLE>
<CAPTION>
SIX MONTHS
ENDED
INCEPTION TO YEARS ENDED DECEMBER 31, JUNE 30,
DECEMBER 31, --------------------------------------------------- -----------------------
1990 1991 1992 1993 1994 1994 1995
------------ ----------- ----------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
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 --
</TABLE>

<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
------------------------------------------------------------------ -----------------------
1990 1991 1992 1993 1994 1994 1995
------------ ----------- ----------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
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
</TABLE>

- ---------------
(1) Per unit data is based on indicated amounts allocable to limited partners
other than Benton divided by 1,405 limited partner units outstanding.

26
<PAGE> 38

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.

<TABLE>
<CAPTION>
SIX MONTHS ENDED
INCEPTION TO YEARS ENDED DECEMBER 31, JUNE 30,
DECEMBER 31, --------------------------------- --------------------
1991 1992 1993 1994 1994 1995
------------ --------- --------- --------- -------- ---------
<S> <C> <C> <C> <C> <C> <C>
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 --
</TABLE>

<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
------------------------------------------------ --------------------
1991 1992 1993 1994 1994 1995
------------ --------- --------- --------- -------- ---------
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>

- ---------------
(1) Per unit data is based on indicated amounts allocable to limited partners
other than Benton divided by 279 limited partner units outstanding.

27
<PAGE> 39

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.

<TABLE>
<CAPTION>
AT OR FOR THE SIX MONTHS AT AND FOR THE YEAR ENDED
ENDED JUNE 30, 1995 DECEMBER 31, 1994
--------------------------- ---------------------------
EQUIVALENT EQUIVALENT
HISTORICAL PRO FORMA(1) HISTORICAL PRO FORMA(1)
---------- ------------ ---------- ------------
<S> <C> <C> <C> <C>
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................ -- -- -- --
</TABLE>

- ---------------
(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.

28
<PAGE> 40

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 October 2, 1995 through October 27, 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 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.

29
<PAGE> 41

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 $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

30
<PAGE> 42

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.

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'

31
<PAGE> 43

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 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.

32
<PAGE> 44

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 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

33
<PAGE> 45

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 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.

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

34
<PAGE> 46

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, 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.

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<PAGE> 47

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.

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<PAGE> 48

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.

<TABLE>
<CAPTION>
YEAR HIGH LOW
------------------------------------------------------------------- ------ ------
<S> <C> <C>
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.................................................... 13.88 9.50
Fourth Quarter (through October 30).............................. 12.00 10.13
</TABLE>

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.

<TABLE>
<CAPTION>
PARTNERSHIP 1989 1990 1991 1992 1993 1994 1995
- ----------- ---- ---- ---- ------ ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
</TABLE>

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.

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<PAGE> 49

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.

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.

38
<PAGE> 50

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. 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

39
<PAGE> 51

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 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

40
<PAGE> 52

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.

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.

HUNTER OFFER

In October 1994, Benton received an offer to purchase the working interest
in the Umbrella Point Field owned by the Partnerships and Benton from Hunter
Resources, Inc. ("Hunter"). The Hunter offer would have paid a total of
$2,697,575 in cash and $337,197 in the form of a promissory note for the working

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<PAGE> 53

interests owned in the Umbrella Point Field by the Partnerships and the 11.77%
working interest owned by Benton. This offer compared to Goldking's offer of
$2,579,555, all of which was payable in cash. The offers of Goldking and Hunter
are not directly comparable because of the difference in the effective date of
each transaction and thus would need to be adjusted for production, expenses,
change in pricing and other factors. Hunter was unable to secure financing for
the transaction and subsequently withdrew its offer. 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 Umbrella Point Field.

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<PAGE> 54

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.

- 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

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<PAGE> 55

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.

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

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<PAGE> 56

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 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

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<PAGE> 57

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.

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

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<PAGE> 58

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.

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 be awarded. Benton
expects to present this Exchange Offer to the arbitrator to be considered in
determining the extent of damages, if any.

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<PAGE> 59

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
ended October 27, 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 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.

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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

<TABLE>
<S> <C>
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
========
</TABLE>

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, 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 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.

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<PAGE> 61

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, 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 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.
Assuming the market price of the Common Stock remains in the range of $11.00 per
share and that the Warrants could be sold at their estimated present value of
$3.64 per Warrant, the Investors in the 1989-1 Partnership would receive
consideration in the form of cash distributions, Common Stock and cash proceeds
from the sale of the Warrants equal to approximately 86% of their initial
investment. Assuming that the market price of the Common Stock declines to $7.50
per share, its lowest price during the 52 weeks preceding the date of this
Prospectus, the Investors in the 1989-1 Partnership will have received
consideration in the form of cash distributions and Common Stock equal to
approximately 76% of their initial investment. On October 30, 1995, the last
sales price of the Benton Common Stock on NASDAQ National Market was $12.00 per
share. The assumed market price of the Common Stock of $16.75 per share
discussed above represents a 40% 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.

1990-1 PARTNERSHIP EXCHANGE VALUE COMPONENTS

General. The following table sets forth each of the Exchange Value
components, estimated on an interim basis.

EXCHANGE VALUE COMPONENTS

<TABLE>
<S> <C>
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
==========
</TABLE>

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

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<PAGE> 62

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.

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.

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<PAGE> 63

tive 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.
Assuming the market price of the Common Stock remains in the range of $11.00 per
share and that the Warrants could be sold at their estimated present value of
$3.64 per Warrant, the Investors in the 1990-1 Partnership would receive
consideration in the form of cash distributions, Common Stock and cash proceeds
from the sale of the Warrants equal to approximately 77% of their initial
investment. Assuming that the market price of the Common Stock declines to $7.50
per share, its lowest price during the 52 weeks preceding the date of this
Prospectus, the Investors in the 1990-1 Partnership will have received
consideration in the form of cash distributions and Common Stock equal to
approximately 47% of their initial investment. On October 30, 1995, the last
sales price of the Benton Common Stock on NASDAQ National Market was $12.00 per
share. The assumed market price of the Common Stock of $16.75 per share
discussed above represents a 40% 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.

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

<TABLE>
<S> <C>
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
========
</TABLE>

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

52
<PAGE> 64

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 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.

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<PAGE> 65

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, 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.
Assuming the market price of the Common Stock remains in the range of $11.00 per
share and that the Warrants could be sold at their estimated present value of
$3.64 per Warrant, the Investors in the 1991-1 Partnership would receive
consideration in the form of cash distributions, Common Stock and cash proceeds
from the sale of the Warrants equal to approximately 73% of their initial
investment. Assuming that the market price of the Common Stock declines to $7.50
per share, its lowest price during the 52 weeks preceding the date of this
Prospectus, the Investors in the 1991-1 Partnership will have received
consideration in the form of cash distributions and Common Stock equal to
approximately 38% of their initial investment. On October 30, 1995, the last
sales price of the Benton Common Stock on NASDAQ National Market was $12.00 per
share. The assumed market price of the Common Stock of $16.75 per share
discussed above represents a 40% 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.

OPINION REGARDING WARRANT VALUATION

Benton engaged J.P. Morgan to render its opinion as to the fair range of
values of the Warrants using the Black-Scholes methodology for valuing options.
J.P. Morgan has delivered its written opinion to the Board of Directors of
Benton to the effect that, as of October 23, 1995, the fair range of values of
the Warrants based on the Black-Scholes methodology for valuing options is
between $3.35 and $3.72 per share of Common Stock.

A copy of J.P. Morgan's written opinion dated as of October 23, 1995, which
sets forth the assumptions made, matters considered, and limits on the review
undertaken, is attached as Exhibit F to this Prospectus and is incorporated
herein by reference. Investors are urged to read the opinion in its entirety.
The description of the opinion set forth herein is qualified in its entirety by
reference to the full text of such opinion. J.P. Morgan's opinion is addressed
only to the Board of Directors, is directed only to the fair range of value of

54
<PAGE> 66

the Warrants based on the Black-Scholes model, and does not constitute a
recommendation to any Investor with respect to the Exchange.

In arriving at its written opinion, J.P. Morgan considered the current
market price for Benton's Common Stock and the risk free rate of return based on
a three year interest rate swap curve, estimated the volatility of Benton's
Common Stock, estimated the impact of dilution caused by the Warrants, assessed
any impact associated with the number of shares of Common Stock referenced by
the Warrants, and reviewed the terms of the Warrant Agreement attached as
Exhibit A to the Prospectus. In addition, J.P. Morgan reviewed (i) publicly
available information concerning the trading history and current price of
Benton's Common Stock and (ii) the terms of the Warrants as provided by Benton.

J.P. Morgan has relied upon and assumed, without independent verification,
the accuracy and completeness of all information that was publicly available or
was furnished to J.P. Morgan by Benton or otherwise reviewed by J.P. Morgan, and
J.P. Morgan has not assumed any responsibility or liability therefor. J.P.
Morgan has not conducted any valuation or appraisal of any assets or
liabilities.

J.P. Morgan's opinion is based on economic, market and other conditions as
in effect on, and the information made available to J.P. Morgan as of, the date
hereof. Subsequent developments may affect J.P. Morgan's opinion and J.P. Morgan
does not have any obligation to update, revise, or reaffirm its opinion.

J.P. Morgan was not requested to, and did not, express an opinion as to the
fairness of the Exchange pursuant to which the Warrants are being issued.

The summary set forth above does not purport to be a complete description
of the analyses or data presented by J.P. Morgan. The preparation of a valuation
opinion is a complex process and is not necessarily susceptible to partial
analysis or summary description. J.P. Morgan believes that the summary set forth
above and their analyses must be considered as a whole and that selecting
portions thereof, without considering all of their analyses, could create an
incomplete view of the processes underlying its analyses and opinion. J.P.
Morgan based its analyses on assumptions that it deemed reasonable, including
assumptions concerning general business and economic conditions. J.P. Morgan's
analyses are not necessarily indicative of actual values or actual future
results that might be achieved, which values may be higher or lower than those
indicated. Moreover, J.P. Morgan's analyses are not and do not purport to be
appraisals or otherwise reflective of the prices at which securities actually
could be bought or sold.

As part of its investment banking business, J.P. Morgan and its affiliates
are continually engaged in valuation of businesses and their securities in
connection with mergers and acquisitions, investments for passive and control
purposes, negotiated underwritings, secondary distributions of listed and
unlisted securities, private placements, and valuation for estate, corporate,
and other purposes. J.P. Morgan was selected to render its valuation opinion
with respect to the Warrants on the basis of such experience and its familiarity
with Benton.

J.P. Morgan was not requested to and did not provide advice concerning the
structure, the specific amount of the consideration, or any other aspects of the
Exchange, or to provide services other than the delivery of its opinion. J.P.
Morgan did not participate in negotiations with respect to the terms of the
Exchange and related transactions.

For rendering its valuation opinion, Benton has agreed to pay J.P. Morgan
$100,000. In addition, Benton has agreed to reimburse J.P. Morgan for its
out-of-pocket expenses incurred in connection with its services, including
attorneys' fees and disbursements, and will indemnify J.P. Morgan against
certain liabilities, including liabilities arising under the securities laws.

J.P. Morgan and its affiliates maintain banking and other business
relationships with Benton, including the extension of credit and other financial
advisory services and has received fees from Benton and its affiliates during
the last two years in the amount of $375,000. In the ordinary course of their
businesses, affiliates of J.P. Morgan may actively trade the debt and equity
securities of Benton for their own account or for the accounts of customers and,
accordingly, they may at any time hold long or short positions in such
securities.

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<PAGE> 67

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 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.

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<PAGE> 68

(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 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

57
<PAGE> 69

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 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 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

58
<PAGE> 70

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 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.

59
<PAGE> 71

1989-1 PARTNERSHIP

<TABLE>
<CAPTION>
TOTAL VALUE PER
VALUATION METHOD INVESTOR VALUE(1) 1989-1 UNIT
- ----------------------------------------------------------------- ----------------- -----------
<S> <C> <C>
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
</TABLE>

1990-1 PARTNERSHIP

<TABLE>
<CAPTION>
TOTAL VALUE PER
VALUATION METHOD INVESTOR VALUE(1) 1989-1 UNIT
- ----------------------------------------------------------------- ----------------- -----------
<S> <C> <C>
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
</TABLE>

60
<PAGE> 72

1991-1 PARTNERSHIP

<TABLE>
<CAPTION>
TOTAL VALUE PER
VALUATION METHOD INVESTOR VALUE(1) 1991-1 UNIT
- ----------------------------------------------------------------- ----------------- -----------
<S> <C> <C>
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
</TABLE>

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.

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

61
<PAGE> 73

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

<TABLE>
<CAPTION>
YEAR TOTAL CASH FLOW(1) CASH FLOW PER UNIT(2)
----------------------------------------------- ------------------ ---------------------
<S> <C> <C>
1995........................................... $30,640 $109
1996........................................... 37,445 133
1997........................................... 21,150 75
1998........................................... 1,426 5
-------
Total(3)............................. $90,661 $322
=======
</TABLE>

- ---------------
(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.

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.

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

62
<PAGE> 74

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

<TABLE>
<CAPTION>
YEAR TOTAL CASH FLOW(1) CASH FLOW PER UNIT(2)
----------------------------------------------- ------------------ ---------------------
<S> <C> <C>
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
======== ====
</TABLE>

- ---------------
(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.

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

63
<PAGE> 75

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

<TABLE>
<CAPTION>
YEAR TOTAL CASH FLOW(1) CASH FLOW PER UNIT(2)
----------------------------------------------- ------------------ ---------------------
<S> <C> <C>
1995........................................... $16,472 $ 58
1996........................................... 21,258 75
1997........................................... 9,342 34
------- ----
Total(3)............................. $47,072 $167
======= ====
</TABLE>

- ---------------
(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 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

64
<PAGE> 76

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.

1989-1 PARTNERSHIP

LIQUIDATION ANALYSIS

<TABLE>
<S> <C>
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
========
</TABLE>

- ---------------
(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 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

65
<PAGE> 77

1990-1 PARTNERSHIP

LIQUIDATION ANALYSIS

<TABLE>
<S> <C>
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
==========
</TABLE>

- ---------------
(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 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

66
<PAGE> 78

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.

1991-1 PARTNERSHIP

LIQUIDATION ANALYSIS

<TABLE>
<S> <C>
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
========
</TABLE>

- ---------------
(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
Values and other term of the Exchange Offer may not be as favorable as the terms
that an independent representative might have obtained.

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<PAGE> 79

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 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

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<PAGE> 80

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. Benton and Goldking have verbally agreed to a 30-day
extension of such date, so that the seller or purchaser may terminate the
agreement if the closing has not occurred on or before January 30, 1996. 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.

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<PAGE> 81

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.

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.

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<PAGE> 82

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.

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, 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.

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<PAGE> 83

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.

<TABLE>
<S> <C>
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................................................... 170,000
Blue sky expenses......................................................... 5,000
Printing costs............................................................ 125,000
Investment Banker fees.................................................... 100,000
Engineering fees.......................................................... 10,000
Accounting fees........................................................... 50,000
Miscellaneous............................................................. 5,644
--------
Total........................................................... $545,000
========
</TABLE>

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.

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<PAGE> 84

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 offer) 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.

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.

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<PAGE> 85

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.

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<PAGE> 86

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.

<TABLE>
<CAPTION>
PARTNERSHIPS BENTON OIL AND GAS COMPANY
<S> <C>
Distributions and Dividends

Each of the Partnership Agreements Although holders of Common Stock are
provides for cash distributions in the entitled to receive any dividends declared
discretion of the Managing General Partner thereon by Benton's Board of Directors out
in an amount equal to approximately the of legally available funds, no dividends
difference between revenues allocated to are expected to be paid on the Common
the respective partners and costs charged Stock for the foreseeable future. Under
to the partners. The Partnership Agree- Delaware law, dividends may be paid out of
ment states that the provisions do not the Company's surplus or out of its net
serve as a limitation on the right of the profits for the fiscal year in which the
Managing General Partner to retain, pledge dividend is declared and/or the preceding
or use so much of the revenues or other fiscal year. In addition, the Company's
assets of the Partnerships to conduct credit agreements restrict the Company's
additional operations, establish reserves ability to pay cash dividends.
for anticipated expenditures or 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
federal or state income taxes. Each tax on its consolidated income after
partner is allocated his pro rata share of allowable deductions and credits.
the Partnership's taxable income. Stockholders will not 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.
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 them for a vote, including the election
of all or substantially all of the assets, and removal of directors, amendments to
dissolution of the Partnership and removal the Certificate of Incorporation, certain
of the Managing General Partner. Each of mergers and share exchanges, dissolution
these matters requires the consent of a and the sale of all or substantially all
majority of the outstanding Units. of the assets of 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.
</TABLE>

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<PAGE> 87

<TABLE>
<CAPTION>
PARTNERSHIPS BENTON OIL AND GAS COMPANY
<S> <C>
Right to Call Meetings

Meetings of the participants of the Special meetings of the Company's
Partnerships may be called by the stockholders may be called by the
Managing General Partner or by holders of President, Board of Directors or by
at least 10% of the outstanding Units. holders of not less than 10% of the Common
Actions requiring a vote of the holders of Stock. Actions requiring a vote may be
Units may be taken without a meeting upon taken without a meeting upon written
written consent by the same percentage of consent by the same percentage of
Unitholders required to approve the action stockholders required to approve the
at a meeting. action at a meeting.
Right to Investor List

Under California law, a holder of Units The Company is required to maintain a list
has the right to examine or copy a of the names and addresses of all
listing of the names and addresses and stockholders at its principal office
record ownership positions of the holders during normal business hours for any
of Units. proper purpose and, in certain
circumstances, to provide a copy of the
list to any stockholder upon request.
Assessments and Limited Liability

Under the terms of the Partnership The Company's stockholders will not be
Agreements, Unitholders are not subject subject to assessments or to personal
to additional assessments. The liability liability for obligations of the Company.
of the Unitholders 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 The Company's Certificate of Incorporation
Agreements, the participants pay 99% of authorizes the issuance of up to
the lease acquisition, geophysical and 40,000,000 shares of Common Stock and
seismic costs, well costs, general and 5,000,000 shares of Preferred Stock,
administrative expenses and organization including shares that may be divided into
and offering expenses, including one or more additional series with rights
commissions, while the co-managing general and preferences to be determined by the
partners pay 1% of such costs. Company's Board of Directors without any
stockholder action. An Investor's
Under the terms of the 1989-1 Partnership percentage interest in the Company is
Agreement, Revenues, production taxes and subject to dilution upon issuance of
lease operating expenses on proven additional securities by the Company.
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-manag-
</TABLE>

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<PAGE> 88

<TABLE>
<CAPTION>
PARTNERSHIPS BENTON OIL AND GAS COMPANY
<S> <C>
ing general partners. Revenues and
production taxes are allocated 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 re-
quirements 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 bro-
ker/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 The Common Stock is not redeemable or con-
convertible into other securities. vertible. The Warrants can be exercised
for Common Stock upon payment of the
exercise price ($11.00 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
reserve reports for the Partnerships. files periodic reports as well as proxy
statements with the SEC, copies of which
are provided or are available to its
stockholders.
</TABLE>

77
<PAGE> 89

<TABLE>
<CAPTION>
PARTNERSHIPS BENTON OIL AND GAS COMPANY
<S> <C>
Operating Strategy

The Partnerships were formed to invest in Benton is primarily engaged in the
oil and natural gas activities by development and production of oil and gas
acquiring proven producing properties that properties. Benton's operations are
have additional development potential, focused on the Eastern Region of
recompleting previously drilled wells and Venezuela, the Gulf Coast Region of
drilling new wells. The Partnerships' Louisiana and the West Siberia Region of
properties are all located in a small Russia. Benton's business strategy is to
number of fields within the United States. seek new reserves in areas of low geologic
Although each of the Partnership risk and to exploit underdeveloped
Agreements permits the Managing General existing oil and gas fields. Benton imple-
Partners to borrow money on behalf of such ments the exploitation strategy through
Partnership, Benton's policy as Managing the in- house design and interpretation of
General Partner has been to refrain from 3-D seismic surveys and through workovers,
financing oil and gas activities through recompletions, redrilling and exploration
credit. 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 arrange-
ments.

Management and Compensation

Benton and a wholly owned subsidiary, The stockholders of Benton Oil and Gas
Benton Oil and Gas Company of Louisiana, directors elect officers of the Company to
are the Co-Managing General Partners of serve at the discretion of the Board.
each of the Partnerships. Benton makes all Officer salaries and incentive
decisions regarding the business and compensation are determined annually by
operations of the Partnerships, including the Board of Directors and/or the
production, development and other ac- President of Benton.
tivities, and any sale of properties and
the acquisition of additional properties.
The Co-Managing General Partners do not
receive any management fees or other 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
duties to the Unitholders include legal of Benton to its stockholders under the
responsibilities of loyalty, care and Delaware General Corporation law and
good faith. Benton may not profit from remedies available for a breach of those
drilling in contravention of its fiduciary responsibilities are similar to those
obligation to the Partners. applicable to the Partnerships 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.
</TABLE>

78
<PAGE> 90

<TABLE>
<CAPTION>
PARTNERSHIPS BENTON OIL AND GAS COMPANY
<S> <C>
Limits on Management's Liability

The Partnership Agreements provide that in Benton's Certificate of Incorporation and
any threatened, pending or completed Bylaws provide for the elimination of
action, suit or proceeding to which the directors' liability for monetary damages
Co-Managing General Partners were or are a arising from a breach of certain fiduciary
party or are threatened to be made a party obligations and for the indemnification of
by reason of the fact that they were or directors, officers and agents to the full
are a Co-Managing General Partner of the extent permitted by the Delaware General
Partnership involving any alleged cause of Corporation Law. These provisions
action for damages arising from the generally provide for indemnification in
performance of oil and gas activities, the absence of gross negligence or willful
including exploration, development, misconduct and cannot be amended without
completion, operation, or other ac- the affirmative vote of a majority of the
tivities relative to management and outstanding shares of Common Stock.
disposition of oil and gas properties or
production 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
Partnership, the 1990-1 Partnership and to dissolution upon the occurrence of
the 1991-1 Partnership provides for a term specified events.
ending 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 Benton is subject to the anti-takeover
the Partnership Agreements or under protections of the Delaware General
California Partnership law. Corporation Law, which prohibit business
combinations with interested stockholders
under certain circumstances.
</TABLE>

79
<PAGE> 91

<TABLE>
<CAPTION>
PARTNERSHIPS BENTON OIL AND GAS COMPANY
<S> <C>
In addition, Benton has adopted a
shareholder rights plan, or 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 In the event of liquidation, holders of
are entitled to a distribution in Common Stock would be entitled to share
proportion to their positive capital ratably in any assets of the Company
account balances after the creditors, remaining after satisfaction of
including Partners, who are creditors (to obligations to its creditors and
the extent permitted by law), have been liquidation preferences on any series of
paid. If the liabilities of the Preferred Stock of the Company then
partnership exceed the assets upon outstanding. The Company currently has no
liquidation, or otherwise if any General shares of Preferred Stock outstanding and
Partner then has a negative balance in its has no plans to issue any shares of
capital account, the General Partners must Preferred Stock in the foreseeable future.
contribute funds to the Partnership in the
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
representing a majority of the outstanding of the Company without prior action by its
units. Board of Directors.
</TABLE>

80
<PAGE> 92

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.

81
<PAGE> 93

PRO FORMA CONSOLIDATED BALANCE SHEET

JUNE 30, 1995

<TABLE>
<CAPTION>
CONSOLIDATED MINIMUM REMAINING
BENTON OIL AND PRO FORMA MINIMUM PRO FORMA MAXIMUM
GAS COMPANY ADJUSTMENTS NOTES PRO FORMA ADJUSTMENTS NOTES PRO FORMA
-------------- ----------- ----- ----------- ----------- ----- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
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 and 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
============ ============ ============
</TABLE>

- ---------------
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.

(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.

82
<PAGE> 94

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE SIX MONTHS ENDED JUNE 30, 1995

- ---------------
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.

(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.

83
<PAGE> 95

PRO FORMA CONSOLIDATED STATEMENT OF CASH FLOWS

FOR THE SIX MONTHS ENDED JUNE 30, 1995

<TABLE>
<CAPTION>
CONSOLIDATED MINIMUM REMAINING
BENTON OIL AND PRO FORMA MINIMUM PRO FORMA MAXIMUM
GAS COMPANY ADJUSTMENTS NOTES PRO FORMA ADJUSTMENTS NOTES PRO FORMA
-------------- ----------- ----- ------------ ----------- ----- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (loss)...................... $ 3,151,601 $ (19,141) (a) $ 3,132,460 $ (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:...................... 6,473,402 20,849 (a) 6,494,251 157,869 (b) 6,652,120
Net earnings from limited
partnerships....................... (20,435) (270) (c) (20,705) 20,705 (c)
Amortization of financing costs...... 90,640 90,640 90,640
Loss on disposal of assets........... 10,632 10,632 10,632
Minority interest in undistributed
earnings of subsidiary............. 1,742,573 1,742,573 1,742,573
(Increase) decrease in accounts
receivable......................... (1,919,152) (1,919,152) (1,919,152)
(Increase) decrease in prepaid
expenses and other................. (1,339,986) (1,339,986) (1,339,986)
Increase in accounts payable......... (1,562,974) 4,728 (a) (1,558,246) (22,301) (b) (1,580,547)
Increase (decrease) in accrued
interest payable, payroll and
related taxes...................... (25,497) (25,497) (25,497)
Increase in income taxes payable..... 1,586,616 1,586,616 1,586,616
----------- --------- ------------ --------- ------------
TOTAL ADJUSTMENTS............. 5,035,819 25,307 5,061,126 156,273 5,217,399
----------- --------- ------------ --------- ------------
NET CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES........ 8,187,420 6,166 8,193,586 58,975 8,252,561
----------- --------- ------------ --------- ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of property and
equipment.......................... 14,708,863 29,200 (a) 14,738,063 146,900 (b) 14,884,963
Additions of property and
equipment.......................... (27,130,397) (12,989) (a) (27,143,386) (78,963) (b) (27,222,349)
----------- --------- ------------ --------- ------------
NET CASH PROVIDED BY (USED IN)
INVESTING ACTIVITIES........ (12,421,534) 16,211 (12,405,323) 67,937 (12,337,386)
----------- --------- ------------ --------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from exercise of stock
options and warrants............... 611,738 611,738 611,738
Proceeds from issuance of notes
payable............................ 22,040,000 22,040,000 22,040,000
Payments on commercial paper, other
short term borrowings and notes
payable............................ (6,980,406) (6,980,406) (6,980,406)
Increase in other assets............. (213,664) (213,664) (213,664)
----------- --------- ------------ --------- ------------
NET CASH PROVIDED BY (USED IN)
FINANCING ACTIVITIES........ 15,457,668 15,457,668 15,457,668
----------- --------- ------------ --------- ------------
NET DECREASE IN CASH.......... 11,223,554 22,377 11,245,931 126,912 11,372,843
CASH AND CASH EQUIVALENTS AT BEGINNING
OF PERIOD............................ 14,192,568 (484,830) 13,707,738 24,260 13,731,998
----------- --------- ------------ --------- ------------
CASH AND CASH EQUIVALENTS AT END OF
PERIOD............................... $ 25,416,122 $(462,453) $ 24,953,669 $ 151,172 $ 25,104,841
=========== ========= ============ ========= ============
</TABLE>

- ---------------
Notes:

(a) Combine cash flow of the 1991-1 Partnership.

(b) Combine cash flows of the 1989-1 Partnership and 1990-1 Partnership.

84
<PAGE> 96

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 1994

- ---------------
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.

(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.

85
<PAGE> 97

PRO FORMA CONSOLIDATED STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 1994

<TABLE>
<CAPTION>
CONSOLIDATED MINIMUM REMAINING
BENTON OIL AND PRO FORMA MINIMUM PRO FORMA MAXIMUM
GAS COMPANY ADJUSTMENTS NOTES PRO FORMA ADJUSTMENTS NOTES PRO FORMA
-------------- ----------- ----- ------------ ----------- ----- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
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)
Payments 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 warrants............................ 83,740 83,740 83,740
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)
Payments 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
=========== ========= ============ ========= ============
</TABLE>

- ---------------
Notes:

(a) Combine cash flow of the 1991-1 Partnership.

(b) Combine cash flows of the 1989-1 Partnership and 1990-1 Partnership.

(d) Record issuance costs associated with the acquisition of partnership units.

86
<PAGE> 98

INFORMATION CONCERNING BENTON

BUSINESS

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.

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:

<TABLE>
<CAPTION>
PROVED RESERVES
------------------------------------------------
CRUDE OIL AND
CONDENSATE NATURAL GAS OIL EQUIVALENT
(MBBL) (MMCF) (MBOE)
------------- ----------- --------------
<S> <C> <C> <C>
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
====== ====== ======
</TABLE>

- ---------------
(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.

(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.

87
<PAGE> 99

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.

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

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<PAGE> 100

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.

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.

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<PAGE> 101

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 (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.

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<PAGE> 102

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.

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

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<PAGE> 103

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
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.

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<PAGE> 104

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.

<TABLE>
<CAPTION>
PROVED RESERVES AT JANUARY 1, 1995
---------------------------------------
PRESENT VALUE OF 1994
ESTIMATED FUTURE NET PRODUCTION
OIL GAS CASH FLOWS --------------
PROPERTY (BBLS) (MCF) DISCOUNTED AT 10% (BBLS) (MCF)
- --------------------------------------------- ------ ------- -------------------- ----- ------
<S> <C> <C> <C> <C> <C>
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
====== ======= ======== ===== ======
</TABLE>

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.

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<PAGE> 105

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.

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEARS ENDED DECEMBER 31, JUNE 30,
---------------------------------------------------------------- ---------------------
1990 1991 1992 1993 1994 1994 1995
--------- -------- --------- --------- --------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
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 --
</TABLE>

<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
----------------------------------------------------------------- ---------------------
1990 1991 1992 1993 1994 1994 1995
---------- ---------- --------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
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
</TABLE>

- ---------------
(1) Per unit data is based on indicated amounts allocable to limited partners
divided by 279 limited partner units outstanding.

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<PAGE> 106

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 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

95
<PAGE> 107

$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.

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.

96
<PAGE> 108

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
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.

<TABLE>
<CAPTION>
PROVED RESERVES AT JANUARY 1, 1995
---------------------------------------
PRESENT VALUE OF
ESTIMATED FUTURE NET 1994 PRODUCTION
OIL GAS CASH FLOWS ----------------
PROPERTY (BBLS) (MCF) DISCOUNTED AT 10% (BBLS) (MCF)
- ------------------------------------------- ------ ------- -------------------- ------ -------
<S> <C> <C> <C> <C> <C>
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
====== ======= ========== ====== =======
</TABLE>

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.

97
<PAGE> 109

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 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.

98
<PAGE> 110

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 Prospectus.

<TABLE>
<CAPTION>
SIX MONTHS ENDED
INCEPTION TO YEARS ENDED DECEMBER 31, JUNE 30,
DECEMBER 31, --------------------------------------------------- -----------------------
1990 1991 1992 1993 1994 1994 1995
------------ ----------- ----------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
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 --
</TABLE>

<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31,
------------------------------------------------------------------ -----------------------
1990 1991 1992 1993 1994 1994 1995
------------ ----------- ----------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
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
</TABLE>

- ---------------
(1) Per unit data is based on indicated amounts allocable to limited partners
divided by 1,405 limited partner units outstanding.

99
<PAGE> 111

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.

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.

100
<PAGE> 112

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 quantities 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.

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

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.

101
<PAGE> 113

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.

<TABLE>
<CAPTION>
PROVED RESERVES AT JANUARY 1, 1995
---------------------------------------
PRESENT VALUE OF
ESTIMATED FUTURE NET 1994 PRODUCTION
OIL GAS CASH FLOWS ---------------
PROPERTY (BBLS) (MCF) DISCOUNTED AT 10% (BBLS) (MCF)
- -------------------------------------------- ------ ------- -------------------- ------ ------
<S> <C> <C> <C> <C> <C>
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
====== ======= ======== ===== ======
</TABLE>

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 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.

102
<PAGE> 114

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.

103
<PAGE> 115

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 Prospectus.

<TABLE>
<CAPTION>
SIX MONTHS ENDED
INCEPTION TO YEARS ENDED DECEMBER 31, JUNE 30,
DECEMBER 31, ------------------------------------- ----------------------
1991 1992 1993 1994 1994 1995
------------ --------- --------- --------- -------- ---------
<S> <C> <C> <C> <C> <C> <C>
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 --
</TABLE>

<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
------------------------------------------------------ ----------------------
1991 1992 1993 1994 1994 1995
------------ --------- --------- --------- -------- ---------
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>

- ---------------
(1) Per unit data is based on indicated amounts allocable to limited partners
divided by 279 limited partner units outstanding.

104
<PAGE> 116

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 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.

105
<PAGE> 117

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.

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

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.

106
<PAGE> 118

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.

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

107
<PAGE> 119

& 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.

108
<PAGE> 120

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.

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.

109
<PAGE> 121

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.

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.

110
<PAGE> 122

INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
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
</TABLE>

F-1
<PAGE> 123

INDEX TO BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
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
</TABLE>

F-2
<PAGE> 124

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
<PAGE> 125

BENTON OIL AND GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------- JUNE 30,
1993 1994 1995
------------ ------------ ------------
(UNAUDITED)
<S> <C> <C> <C>
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
=========== =========== ===========
</TABLE>

See notes to consolidated financial statements.

F-4
<PAGE> 126

BENTON OIL AND GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
YEARS ENDED DECEMBER 31,
--------------------------------------- -------------------------
1992 1993 1994 1994 1995
----------- ----------- ----------- ----------- -----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
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
========== ========== ========== ========== ==========
</TABLE>

See notes to consolidated financial statements.

F-5
<PAGE> 127

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

<TABLE>
<CAPTION>
COMMON ADDITIONAL
SHARES COMMON PAID-IN ACCUMULATED
ISSUED STOCK CAPITAL DEFICIT TOTAL
---------- -------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
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
========= ======== ========== ========== ==========
</TABLE>

See notes to consolidated financial statements.

F-6
<PAGE> 128

BENTON OIL AND GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
YEARS ENDED DECEMBER 31,
------------------------------------------ -----------------------------
1992 1993 1994 1994 1995
------------ ------------ ------------ ------------ ------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
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)
Amortization of financing costs.............. 376,609 139,444 114,311 57,156 90,640
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
=========== =========== =========== =========== ===========
</TABLE>

F-7
<PAGE> 129

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
<PAGE> 130

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
<PAGE> 131

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
<PAGE> 132

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
<PAGE> 133

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:

<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------- JUNE 30,
1993 1994 1995
----------- ----------- -----------
(UNAUDITED)
<S> <C> <C> <C>
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
========== ========== ==========
</TABLE>

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
<PAGE> 134

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
<PAGE> 135

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:

<TABLE>
<S> <C>
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
==========
</TABLE>

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
<PAGE> 136

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:

<TABLE>
<CAPTION>
RENTAL
COMMITMENTS SUB-LEASES
----------- ----------
<S> <C> <C>
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)
========== =========
</TABLE>

Rental expense was $222,279, $233,934 and $255,650 for the years ended
December 31, 1992, 1993 and 1994, respectively.

F-15
<PAGE> 137

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:

<TABLE>
<CAPTION>
1993 1994
----------- -----------
<S> <C> <C>
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................................ $ -- $ --
========== ==========
</TABLE>

A comparison of the income tax expense at the federal statutory rate to the
Company's provision for income taxes is as follows:

<TABLE>
<CAPTION>
1992 1993 1994
----------- ----------- -----------
<S> <C> <C> <C>
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
========== ========== ==========
</TABLE>

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
<PAGE> 138

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.

<TABLE>
<CAPTION>
1989 NONSTATUTORY
1988 STOCK OPTION PLAN STOCK OPTION PLAN
------------------------------------- ----------------------------------------
OPTION OPTION CURRENTLY OPTION OPTION CURRENTLY
PRICES SHARES EXERCISABLE PRICES SHARES EXERCISABLE
--------------- -------- ----------- ---------------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C>
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
========= ========== ========== ==========
</TABLE>

F-17
<PAGE> 139

BENTON OIL AND GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

<TABLE>
<CAPTION>
1991-1992 STOCK OPTION PLAN DIRECTORS' STOCK OPTION PLAN
---------------------------------------- -------------------------------------
OPTION OPTION CURRENTLY OPTION OPTION CURRENTLY
PRICES SHARES EXERCISABLE PRICES SHARES EXERCISABLE
----------------- --------- ----------- ---------------- ------- -----------
<S> <C> <C> <C> <C> <C> <C>
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
========= ========== ======== ==========
</TABLE>

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
<PAGE> 140

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:

<TABLE>
<CAPTION>
DATE ISSUED EXPIRATION DATE EXERCISE PRICE ISSUED OUTSTANDING
- -------------- --------------- -------------- --------- -----------
<S> <C> <C> <C> <C>
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
======== =========
</TABLE>

- ---------------
* 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
<PAGE> 141

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
<PAGE> 142

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.

<TABLE>
<CAPTION>
1993 1994
----------- -----------
<S> <C> <C>
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
========== ==========
</TABLE>

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
<PAGE> 143

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:

<TABLE>
<CAPTION>
VENEZUELA UNITED STATES RUSSIA TOTAL
----------- ------------- ----------- ------------
<S> <C> <C> <C> <C>
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
========== =========== ========== ===========
</TABLE>

The Company's aggregate amount of capitalized costs related to oil and gas
producing activities consists of the following at December 31:

<TABLE>
<CAPTION>
VENEZUELA UNITED STATES RUSSIA TOTAL
----------- ------------- ----------- ------------
<S> <C> <C> <C> <C>
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
=========== ============ =========== ============
</TABLE>

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:

<TABLE>
<CAPTION>
PRIOR TO 1992 1992 1993 1994 TOTAL
------------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C>
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
========== ========= ========= ========= ==========
</TABLE>

F-22
<PAGE> 144

BENTON OIL AND GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Results of operations for oil and gas producing activities were:

<TABLE>
<CAPTION>
VENEZUELA UNITED STATES RUSSIA TOTAL
----------- ------------- ---------- -----------
<S> <C> <C> <C> <C>
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
========== ========== ========= ==========
</TABLE>

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
<PAGE> 145

BENTON OIL AND GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

<TABLE>
<CAPTION>
MINORITY
UNITED INTEREST IN
VENEZUELA STATES RUSSIA TOTAL VENEZUELA NET TOTAL
--------- ------- ------ ------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>

F-24
<PAGE> 146

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
<PAGE> 147

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

<TABLE>
<CAPTION>
MINORITY
UNITED INTEREST IN
VENEZUELA STATES RUSSIA TOTAL VENEZUELA NET TOTAL
--------- -------- -------- --------- ----------- ---------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
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
========= ======== ======== ========= ========= =========
</TABLE>

F-26
<PAGE> 148

BENTON OIL AND GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------
1992 1993 1994
-------- -------- --------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>

NOTE 16 -- QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly financial data is as follows:

<TABLE>
<CAPTION>
QUARTER ENDED
---------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
--------- -------- ------------- ------------
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
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
======= ====== ========== ==========
</TABLE>

- ---------------
(1) The sum of the quarters for 1993 does not equal the total year net income
per share due to rounding.

F-27
<PAGE> 149

BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P.

INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
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
</TABLE>

F-28
<PAGE> 150

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
<PAGE> 151

BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P.

BALANCE SHEETS

<TABLE>
<CAPTION>
DECEMBER 31,
--------------------- JUNE 30,
1993 1994 1995
-------- -------- ---------
(UNAUDITED)
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>

See accompanying notes to financial statements.

F-30
<PAGE> 152

BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P.

STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
SIX MONTHS
YEARS ENDED DECEMBER 31, ENDED JUNE 30,
------------------------------ -------------------
1992 1993 1994 1994 1995
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
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)
======== ======== ======== ======== ========
</TABLE>

See accompanying notes to financial statements.

F-31
<PAGE> 153

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

<TABLE>
<CAPTION>
CO-MANAGING
GENERAL
PARTNERS PARTICIPANTS TOTAL
----------- ------------ ----------
<S> <C> <C> <C>
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
========== ========= =========
</TABLE>

See accompanying notes to financial statements.

F-32
<PAGE> 154

BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P.

STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
SIX MONTHS
YEARS ENDED DECEMBER 31, ENDED JUNE 30,
--------------------------------- ---------------------
1992 1993 1994 1994 1995
--------- --------- --------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
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
========= ========= ========= ======== ========
</TABLE>

See accompanying notes to financial statements.

F-33
<PAGE> 155

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
<PAGE> 156

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:

<TABLE>
<CAPTION>
1992 1993 1994
--------- --------- ---------
<S> <C> <C> <C>
Development costs............................... $ 38,469 $ 56,330 $ 33,047
Exploration costs............................... 1,627 1,891 789
--------- --------- ---------
$ 40,096 $ 58,221 $ 33,836
========= ========= =========
</TABLE>

The Partnership's aggregate amount of capitalized costs related to oil and
gas producing activities consisted of the following at December 31:

<TABLE>
<CAPTION>
1992 1993 1994
--------- --------- ---------
<S> <C> <C> <C>
Proved property costs........................... $ 726,150 $ 782,480 $ 815,527
Less accumulated depletion...................... (268,757) (338,673) (414,876)
--------- --------- ---------
$ 457,393 $ 443,807 $ 400,651
========= ========= =========
</TABLE>

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
<PAGE> 157

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.

<TABLE>
<CAPTION>
1992 1993 1994
------- -------- -------
<S> <C> <C> <C>
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
======= ======== =======
</TABLE>

- ---------------
(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
<PAGE> 158

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.

<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------------
1992 1993 1994
---------- ----------- ---------
<S> <C> <C> <C>
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
========= ========== =========
</TABLE>

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------------
1992 1993 1994
--------- --------- --------
<S> <C> <C> <C>
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
========= ========= ========
</TABLE>

F-37
<PAGE> 159

BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P.

INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
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
</TABLE>

F-38
<PAGE> 160

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
<PAGE> 161

BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P.

BALANCE SHEETS

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------- JUNE 30,
1993 1994 1995
---------- ---------- -----------
(UNAUDITED)
<S> <C> <C> <C>
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
========= ========= =========
</TABLE>

See accompanying notes to financial statements.

F-40
<PAGE> 162

BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P.

STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
SIX MONTHS
YEARS ENDED DECEMBER 31, ENDED JUNE 30,
------------------------------------- ---------------------
1992 1993 1994 1994 1995
----------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
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)
========== ======== ======== ======== ========
</TABLE>

See accompanying notes to financial statements.

F-41
<PAGE> 163

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

<TABLE>
<CAPTION>
CO-MANAGING SPECIAL LIMITED
GENERAL PARTNERS PARTICIPANTS PARTNERS TOTAL
---------------- ------------ ---------------- ----------
<S> <C> <C> <C> <C>
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
============ ========== ============ =========
</TABLE>

See accompanying notes to financial statements.

F-42
<PAGE> 164

BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P.

STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
SIX MONTHS
YEARS ENDED DECEMBER 31, ENDED JUNE 30,
----------------------------------- -------------------
1992 1993 1994 1994 1995
----------- --------- --------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
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
========== ========= ========= ======== ========
</TABLE>

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
<PAGE> 165

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

Organization Costs

Organization costs are amortized over a period of five years using the
straight-line method.

Income Taxes

Interim Reporting

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
<PAGE> 166

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

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

F-45
<PAGE> 167

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:

<TABLE>
<CAPTION>
1992 1993 1994
----------- ----------- -----------
<S> <C> <C> <C>
Development costs........................... $ 151,217 $ 179,512 $ 123,113
Exploration costs........................... 7,714 9,570 6,607
----------- ----------- -----------
$ 158,931 $ 189,082 $ 129,720
========== ========== ==========
</TABLE>

The Partnership's aggregate amount of capitalized costs related to oil and
gas producing activities consists of the following at December 31:

<TABLE>
<CAPTION>
1992 1993 1994
----------- ----------- -----------
<S> <C> <C> <C>
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
========== ========== ==========
</TABLE>

QUANTITIES OF OIL AND GAS RESERVES (UNAUDITED)

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.

<TABLE>
<CAPTION>
1992 1993 1994
----------- -------- --------
<S> <C> <C> <C>
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
========== ======== ========
</TABLE>

F-46
<PAGE> 168

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.

F-47
<PAGE> 169

BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------------
1992 1993 1994
----------- ----------- ----------
<S> <C> <C> <C>
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
========== ========== =========
</TABLE>

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------------------
1992 1993 1994
----------- ----------- ----------
<S> <C> <C> <C>
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
========== ========== =========
</TABLE>

F-48
<PAGE> 170

BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P.

INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
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
</TABLE>

F-49
<PAGE> 171

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
<PAGE> 172

BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P.

BALANCE SHEETS

<TABLE>
<CAPTION>
DECEMBER 31,
--------------------- JUNE 30,
1993 1994 1995
-------- -------- ---------
(UNAUDITED)
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>

See accompanying notes to financial statements.

F-51
<PAGE> 173
BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P.

STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
SIX MONTHS
YEARS ENDED DECEMBER 31, ENDED JUNE 30,
---------------------------------- ----------------------
1992 1993 1994 1994 1995
-------- -------- -------- -------- ---------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
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)
======== ======== ======== ======== =========
</TABLE>

See accompanying notes to financial statements.

F-52
<PAGE> 174

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

<TABLE>
<CAPTION>
CO-MANAGING SPECIAL
GENERAL LIMITED
PARTNERS PARTICIPANTS PARTNERS TOTAL
----------- ------------ -------- ---------
<S> <C> <C> <C> <C>
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
========== ========= ======= =========
</TABLE>

See accompanying notes to financial statements.

F-53
<PAGE> 175

BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P.

STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
SIX MONTHS
YEARS ENDED DECEMBER 31, ENDED JUNE 30,
--------------------------------------- ----------------------
1992 1993 1994 1994 1995
----------- --------- --------- -------- ---------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
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
========== ========= ========= ======== =========
</TABLE>

Supplemental information on non-cash investing activities

See accompanying notes on financial statements.

F-54
<PAGE> 176

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

Oil and Gas Properties

Organization Costs

Organization costs are amortized over a period of five years using the
straight-line method.

Income Taxes

Interim Reporting

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

F-55
<PAGE> 177

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:

<TABLE>
<CAPTION>
1992 1993 1994
-------- --------- ---------
<S> <C> <C> <C>
Development costs................................ $ 32,154 $ 35,786 $ 23,323
Exploration costs................................ 5,513 1,284 769
-------- --------- ---------
$ 37,667 $ 37,070 $ 24,092
======== ========= =========
</TABLE>

F-56
<PAGE> 178

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:

<TABLE>
<CAPTION>
1992 1993 1994
-------- --------- ---------
<S> <C> <C> <C>
Proved property costs............................ $543,794 $ 579,580 $ 533,679
Less accumulated depletion....................... (78,812) (138,392) (192,942)
-------- --------- ---------
$464,982 $ 441,188 $ 340,737
======== ========= =========
</TABLE>

QUANTITIES OF OIL AND GAS RESERVES (UNAUDITED)

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.

<TABLE>
<CAPTION>
1992 1993 1994
------- -------- -------
<S> <C> <C> <C>
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
======= ======== =======
</TABLE>

(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
<PAGE> 179

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.

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.

<TABLE>
<CAPTION>
DECEMBER 31
--------------------------------------
1992 1993 1994
---------- --------- ---------
<S> <C> <C> <C>
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
========= ========= =========
</TABLE>

F-58
<PAGE> 180

BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------
1992 1993 1994
---------- --------- ---------
<S> <C> <C> <C>
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
========= ========= =========
</TABLE>

F-59
<PAGE> 181

EXHIBIT A

WARRANT AGREEMENT

BETWEEN

BENTON OIL AND GAS COMPANY

AND

DATED AS OF , 1995
<PAGE> 182

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 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.

1
<PAGE> 183

(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, 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
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

2
<PAGE> 184

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 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.

(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

3
<PAGE> 185

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 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 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

4
<PAGE> 186

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 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

5
<PAGE> 187

and taken into account in any subsequent adjustment. All calculations shall
be made to the nearest one-thousandth of a share.

(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 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

6
<PAGE> 188

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 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 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 and 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 make all reasonable steps 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 exercise 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

7
<PAGE> 189

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 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 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.

8
<PAGE> 190

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.

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

9
<PAGE> 191

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:

<TABLE>
<CAPTION>
NET TO BENTON OIL AND GAS COMBINATION
PARTNERSHIP 1989-1
-------------------------------------------
PROVED DEVELOPED
---------------------
CONSTANT PRODUCT PRICES PRODUCING SHUT-IN BEHIND PIPE TOTAL
- -------------------------------------------------------- --------- ------- ----------- -------
<S> <C> <C> <C> <C>
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
</TABLE>

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.
<PAGE> 192

Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995

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.

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.

Page Two
<PAGE> 193

Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995

A comparison of the average product prices, weighted as a composite for all
properties, is as follows:

<TABLE>
<CAPTION>
CONSTANT PRODUCT PRICES OIL, $/BBL GAS, $/MCF
-------------------------------------------------------- ---------- ----------
<S> <C> <C>
1995.................................................... 15.94 1.60
Maximum................................................. 15.94 1.60
Average Over Life....................................... 15.94 1.60
</TABLE>

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.

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.

Page Three
<PAGE> 194

Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995

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.

Page Four
<PAGE> 195

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:

<TABLE>
<CAPTION>
NET TO BENTON OIL AND GAS COMBINATION PARTNERSHIP
1990-1
----------------------------------------------------
PROVED
----------------------------------------
CONSTANT PRODUCT PRICES PRODUCING NONPRODUCING UNDEVELOPED TOTAL
- ---------------------------------------------- --------- ------------ ----------- --------
<S> <C> <C> <C> <C>
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
</TABLE>

- ---------------

Note: The nonproducing category includes behind pipe and shut-in categories.
<PAGE> 196

Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995

REPORTING REQUIREMENTS

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 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.

PRODUCT PRICES

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.

Page Two
<PAGE> 197

Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995

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:

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

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.

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

Page Three
<PAGE> 198

Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995

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.

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.

Page Four
<PAGE> 199

Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995

Respectfully submitted,

Peter D. Huddleston, P.E.

Page Five
<PAGE> 200

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:

<TABLE>
<CAPTION>
NET TO BENTON OIL AND GAS COMBINATION
PARTNERSHIP 1991-1
------------------------------------------------
PROVED
------------------------------------------------
CONSTANT PRODUCT PRICES PRODUCING NONPRODUCING UNDEVELOPED TOTAL
- ---------------------------------------------------- --------- ------------ ----------- -------
<S> <C> <C> <C> <C>
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
</TABLE>

- ---------------

Note: The nonproducing category includes behind pipe and shut-in categories.
<PAGE> 201

Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995

REPORTING REQUIREMENTS

REPORT PREPARATION

The projections which were reviewed for the purposes of this audit represent
100% of the total future revenues as projected by Benton.

PRODUCT PRICES

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.

Page Two
<PAGE> 202

Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995

A comparison of the average product prices, weighted as a composite for all
properties, is as follows:

<TABLE>
<CAPTION>
CONSTANT PRODUCT PRICES OIL, $/BBL GAS, $/MCF
--------------------------------------------------------- ---------- ----------
<S> <C> <C>
1995..................................................... 15.95 1.63
Maximum.................................................. 16.00 1.75
Average Over Life........................................ 15.94 1.63
</TABLE>

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

RESERVES ESTIMATES

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

Page Three
<PAGE> 203

Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995

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.

OPERATING AND CAPITAL COSTS

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.

Respectfully submitted,

Peter D. Huddleston, P.E.

Page Four
<PAGE> 204

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 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.
<PAGE> 205

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
Carpinteria, 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

------------------------------------------------------------

------------------------------------------------------------
<PAGE> 206

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.

<TABLE>
<CAPTION>
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.

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
<PAGE> 207

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
<PAGE> 208

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.
<PAGE> 209

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 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

------------------------------------
Signature of Co-owner, if any

Business Telephone: (____)

Home Telephone: (____)

Dated , 1995
<PAGE> 210

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.

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.
<PAGE> 211

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.
<PAGE> 212

EXHIBIT D

BENTON OIL AND GAS COMPANY

LETTER OF TRANSMITTAL
FOR
INVESTORS IN
BENTON OIL AND GAS COMBINATION PARTNERSHIP 1990 -- 1 L.P.

Exchange Agent: Benton Oil and Gas Company

By Mail or By Hand:

Benton Oil and Gas Company
1145 Eugenia Place, Suite 200
Carpinteria, 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

------------------------------------------------------------

------------------------------------------------------------
<PAGE> 213

PART II

DESCRIPTION OF INTERESTS

<TABLE>
<CAPTION>
PARTNERSHIP EXCHANGE COMMON
INTERESTS VALUE SHARES WARRANTS
- ----------- -------- ------- --------

PART III

REPRESENTATIONS, WARRANTIES, COVENANTS AND POWER OF ATTORNEY

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
<PAGE> 215

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.
<PAGE> 216

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.

SIGNATURE BOX
(ONLY FOR NON-CONSENTING CALIFORNIA RESIDENTS)

- ------------------------------------
Full Name of Investor
(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
<PAGE> 217

PART VI

INSTRUCTIONS

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.

Benton will not accept tenders of less than all of an Investor's Interest
in the Partnership.
<PAGE> 218

EXHIBIT D

BENTON OIL AND GAS COMPANY

LETTER OF TRANSMITTAL
FOR
INVESTORS IN
BENTON OIL AND GAS COMBINATION PARTNERSHIP 1991 -- 1 L.P.

Exchange Agent: Benton Oil and Gas Company

By Mail or By Hand:

Benton Oil and Gas Company
1145 Eugenia Place, Suite 200
Carpinteria, 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

------------------------------------------------------------

------------------------------------------------------------
<PAGE> 220

PART II

DESCRIPTION OF INTERESTS

<TABLE>
<CAPTION>
PARTNERSHIP EXCHANGE COMMON
INTERESTS VALUE SHARES WARRANTS
- ----------- -------- ------- --------
<S> <C> <C> <C>

</TABLE>

PART III

REPRESENTATIONS, WARRANTIES, COVENANTS AND POWER OF ATTORNEY

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
<PAGE> 222

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.
<PAGE> 223

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.

SIGNATURE BOX
(ONLY FOR NON-CONSENTING CALIFORNIA RESIDENTS)

- ------------------------------------
Full Name of Investor
(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
<PAGE> 224

PART VI

INSTRUCTIONS

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.

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.

Benton will not accept tenders of less than all of an Investor's Interest
in the Partnership.
<PAGE> 225

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
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
<PAGE> 227

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.

(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.

(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.
<PAGE> 228

(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
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.

(3) Is paid regardless of whether the limited partners reject the proposed
rollup transaction.
<PAGE> 229

(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.
<PAGE> 230

EXHIBIT F

October 20, 1995

The Board of Directors
Benton Oil and Gas Company
1145 Eugenia Place -- Suite 200
Carpinteria, California 93013

Attn: A. E. Benton
Chairman of the Board, CEO and President

Gentlemen:

You have requested our opinion as to the fair range of values for warrants (the
"Warrants") to purchase shares of common stock (the "Common Stock") of Benton
Oil and Gas Company ("Benton"), which Warrants are being issued by Benton in
exchange for partnership interests in certain limited partnerships. It is our
opinion that the Warrants have a fair range of value between $3.35 and $3.72 per
share of Common Stock referenced by the Warrants based on an analysis performed
by J.P. Morgan Securities Inc. ("J.P. Morgan") based on the Black-Scholes
methodology for valuing options. This valuation is based on an assumed share
price of Benton Common Stock of $11.00, and will change with changes in the
share price of Benton's Common Stock. In performing the valuation we have
considered the current market price for Benton's Common Stock and the risk free
rate of return based on a three year interest rate swap curve, estimated the
volatility of Benton's Common Stock, estimated the impact of dilution caused by
the Warrants, assessed any impact associated with the number of shares of Common
Stock referenced by the Warrants, and reviewed the terms of the draft Warrant
Agreement, attached as Exhibit A to Amendment Number 1 to Registration Agreement
on the Form S-4. We express no opinion as to the fairness of the exchange
transaction pursuant to which the Warrants are being issued. Refer to Exhibit A
for a summary of the terms of the Warrants.

The summary set forth above does not purport to be a complete description of the
analyses or data presented by us. The preparation of a valuation letter is a
complex process and is not necessarily susceptible to partial analysis or
summary description. We believe that the summary set forth above and our
analyses must be considered as a whole and that selecting portions thereof,
without considering all of our analyses, could create an incomplete view of the
processes underlying our analyses and views. We based our analyses on
assumptions that we deemed reasonable, including assumptions concerning general
business and economic conditions. Our analyses are not necessarily indicative of
actual values or actual future results that might be achieved, which values may
be higher or lower than those indicated. Moreover, our analyses are not and do
not purport to be appraisals or otherwise reflective of the prices at which
securities actually could be bought or sold.

In arriving at our views expressed in this letter, we have reviewed (i) publicly
available information concerning the trading history and current price of
Benton's Common Stock and (ii) the terms of the Warrants as provided by Benton.

In giving our opinion as expressed in this letter, we have relied upon and
assumed, without independent verification, the accuracy and completeness of all
information that is publicly available and of all information that has been
furnished to us by or otherwise reviewed by J.P. Morgan, and we have not assumed
any responsibility or liability therefor. We have not conducted any valuation or
appraisal of any assets or liabilities.

Our views are necessarily based on economic, market, and other conditions as in
effect on, and the information made available to us as of, the date hereof. It
should be understood that subsequent developments may affect our views and that
we do not have any obligation to update, revise, or reaffirm the views expressed
in this letter.

We have acted as financial advisor to Benton with respect to furnishing this
letter and will receive a fee from Benton for our services. J.P. Morgan and its
affiliates also maintain banking and other business relationships with Benton,
including the extension of credit and other financial advisory services. In the
ordinary course of
<PAGE> 231

their businesses, affiliates of J.P. Morgan may actively trade the debt and
equity securities of Benton for their own accounts or for the accounts of
customers and, accordingly, they may at any time hold long or short positions in
such securities.

This opinion is rendered to the Board of Directors of Benton. This opinion does
not constitute a recommendation to any investor to accept the exchange. This
opinion may not be used, disclosed, referred to or communicated by you (in whole
or in part) to any third party for any purpose whatsoever except with our prior
written consent in each instance. This opinion may be reproduced in full in the
Registration Statement on Form S-4 mailed to investors but may not otherwise be
disclosed publicly in any manner without our prior written approval.

Very Truly yours,

J.P. MORGAN SECURITIES INC.

By: /s/ ADRIAN
DOHERTY

Name: Adrian Doherty

Title: Managing Director

2
<PAGE> 232

SUMMARY OF TERMS OF WARRANTS

<TABLE>
<S> <C>
Reference Underlying: Common Stock of Benton Oil & Gas Company ("BNTN").
Number of Shares: The Warrants allow the holders to purchase 592,373
shares of Common Stock of BNTN.
Term of Warrants: Three years.
Strike Price: $11.00 per share.
Type of Exercise: American; the Warrants can be exercised at any time
during the Term.
</TABLE>

3
<PAGE> 233

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.

<TABLE>
<C> <S>
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.*
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.*
</TABLE>

II-1
<PAGE> 234

<TABLE>
<S> <C>
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.*
99.1 Consent of J.P. Morgan Securities Inc.

- ---------------
<FN>
* Filed previously as an exhibit to this Registration Statement No. 33-61299.
</TABLE>

(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;

(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 sec. 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.

II-2
<PAGE> 235

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 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-3
<PAGE> 236

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the
Registrant has duly caused this Amendment No. 3 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 30th day of October, 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 October 30, 1995 by the following
persons in the capacities indicated:

<TABLE>
<S> <C>
/s/ A. E. Benton President, Chief Executive Officer and
A.E. Benton Director
/s/ David H. Pratt* Vice President -- Finance, Principal
David H. Pratt Financial Officer
/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
</TABLE>

II-4
<PAGE> 237

PROSPECTUS SUPPLEMENT
1989-1 PARTNERSHIP

SUBJECT TO COMPLETION

DATED OCTOBER 31, 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. 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.

THE EXCHANGE OFFER INVOLVES VARIOUS RISKS THAT SHOULD BE CONSIDERED BY
INVESTORS. SEE "RISK FACTORS AND MATERIAL CONSIDERATIONS," BEGINNING ON PAGE 1
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'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. 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.

- 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.

- FUTURE EQUITY OFFERINGS BY BENTON COULD POTENTIALLY BE DILUTIVE TO
INVESTORS HOLDING COMMON STOCK OR WARRANTS.

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." Holders of Units in the Partnership who elect to accept the
Exchange Offer may choose to receive cash in lieu of the Common Stock to be
issued, but cash will be distributed to the holders only if the sale of the
Umbrella Point Field to Goldking Trinity Bay Corp., as described in the
Prospectus, is actually consummated. See "The Exchange Offer and
Proposal -- Election to Receive Cash in Lieu of Common Stock" in the Prospectus.
On October 30, 1995, the last reported sales price of the Common Stock, as
reported on NASDAQ National Market, was $12.00.

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.
<PAGE> 239

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 DATE OF THIS SUPPLEMENT IS , 1995.
<PAGE> 240

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 29.

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 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 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.

1
<PAGE> 241

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 interest. See "Recommendation of the Managing
General Partner -- Fiduciary Duties of Benton" contained in the Prospectus.

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."

2
<PAGE> 242

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.

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 INVESTORS,
REGARDLESS OF WHICH OR THE NUMBER OF PARTNERSHIPS WHICH ACCEPT THE EXCHANGE
OFFER FOR THE REASONS SET FORTH BELOW.

3
<PAGE> 243

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 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.

4
<PAGE> 244

<TABLE>
<CAPTION>
TOTAL VALUE PER
VALUATION METHOD INVESTOR VALUE(1) 1989-1 UNIT
---------------- ----------------- -----------
<S> <C> <C>
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

- ---------------
<FN>
(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.

(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.
</TABLE>

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.

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.

5
<PAGE> 245

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, 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 ended October 27, 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. Benton engaged J.P. Morgan Securities Inc. ("J.P. Morgan")
to render its opinion as to the fair range of values of the Warrants using the
Black-Scholes methodology for pricing options. J.P. Morgan has delivered its
written opinion to the Board of Directors of Benton, a copy of which is attached
to the Prospectus as Exhibit F, to the effect that as of October 23, 1995, the
fair range of values of the Warrants based on the Black Scholes model is between
$3.37 and $3.74 per Warrant. See "Method of Determining Exchange Values --
Opinion Regarding Warrant Valuation" in the Prospectus.

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

<TABLE>
<S> <C>
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
========
</TABLE>

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, and the net book value of its

6
<PAGE> 246

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 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, 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.
Assuming the market price of the Common Stock remains in the range of $11.00 per
share and that the Warrants could be sold at their estimated present value of
$3.64 per Warrant, the Investors in the 1989-1 Partnership would receive
consideration in the form of cash distributions, Common Stock and cash proceeds
from the sale of the Warrants equal to approximately 86% of their initial
investment. Assuming that the market price of the Common Stock declines to $7.50
per share, its lowest price during the 52 weeks preceding the date of this
Prospectus, the Investors in the 1989-1 Partnership will have received
consideration in the form of cash distributions and Common Stock equal to
approximately 76% of their initial investment. On October 30, 1995, the last
sales price of the Benton Common Stock on NASDAQ National Market was $12.00 per
share. The assumed market price of the Common Stock of $16.75 per share
discussed above represents a 40% 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.

7
<PAGE> 247

COMPENSATION PAID TO MANAGING GENERAL PARTNER

Under the terms of the Partnership Agreement, the Managing General Partner
was entitled to certain cash distributions based upon its share of revenues. The
Managing General Partner received cash distributions of $89,961 for the year
ended December 31, 1994. This amount represents cumulative cash distributions
that were allocable to the Managing General Partner from 1990 to 1994, but were
not paid until 1994. No other cash distributions have been received during the
last three fiscal years and for the six months ended June 30, 1995. The Managing
General Partner was also entitled to receive a reimbursement of certain costs
and expenses which it incurred on behalf to the Partnership. Such reimbursements
may be deemed to be compensation to the Managing General Partner. The Managing
General Partner received reimbursement of its general and administrative
expenses allocable to the Partnership in the amounts of $9,386, $9,166, $8,933
and $4,360 for the fiscal years of 1992, 1993, 1994 and the six months ended
June 30, 1995 respectively. No cash distributions or compensation was paid by
the Partnership to affiliates of Benton during such time period.

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. If the Exchange Offer is accepted, neither Benton nor any affiliate of
Benton will receive any further distributions, compensation or reimbursements
from the Partnership.

CASH DISTRIBUTIONS TO INVESTORS

The following table sets forth the cash distributions paid per Unit 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.

- ---------------
(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.

8
<PAGE> 248

PROSPECTUS SUPPLEMENT
1990-1 PARTNERSHIP

SUBJECT TO COMPLETION

DATED OCTOBER 31, 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. 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.

- 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 ALTERNATIVES OF CONTINUING THE PARTNERSHIP OR LIQUIDATING ITS ASSETS
COULD POTENTIALLY BE MORE BENEFICIAL TO INVESTORS THAN THE EXCHANGE
OFFER.

- 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.

- FUTURE EQUITY OFFERINGS BY BENTON COULD POTENTIALLY BE DILUTIVE TO
INVESTORS HOLDING COMMON STOCK OR WARRANTS.

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
Exchange Value." Holders of Units in the Partnership who elect to accept the
Exchange Offer may choose to receive cash in lieu of the Common Stock to be
issued, but cash will be distributed to the holders only if the sale of the
Umbrella Point Field to Goldking Trinity Bay Corp., as described in the
Prospectus, is actually consummated. See "The Exchange Offer and
Proposal -- Election to Receive Cash in Lieu of Common Stock" in the Prospectus.
On October 30, 1995, the last reported sales price of the Common Stock, as
reported on NASDAQ National Market, was $12.00.

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.

THE EXCHANGE OFFER EXPIRES AT 5:00 P.M. PACIFIC TIME ON , 1995
UNLESS EXTENDED.
------------------------

THE DATE OF THIS SUPPLEMENT IS , 1995.
<PAGE> 251

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

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."

1
<PAGE> 252

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.

2
<PAGE> 253

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.

Regulation. The oil and gas industry is subject to broad and frequently
changing regulations that could adversely affect the operations of Benton.

MANAGING GENERAL PARTNER'S DETERMINATION THAT EXCHANGE OFFER IS FAIR

3
<PAGE> 254

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 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.

4
<PAGE> 255

discount rate used in Benton's liquidation analysis to account for the timing of
cash flows as well as production and concentration risks.

<TABLE>
<CAPTION>
TOTAL VALUE PER
VALUATION METHOD INVESTOR VALUE(1) 1990-1 UNIT
---------------- ----------------- -----------
<S> <C> <C>
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

(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 5.5 years.

</TABLE>

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

5
<PAGE> 256

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.

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 ended October 27, 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. Benton
engaged J.P. Morgan Securities Inc. ("J.P. Morgan") to render its opinion as to
the fair range of values of the Warrants using the Black-Scholes methodology for
pricing options. J.P. Morgan has delivered its written opinion to the Board of
Directors of Benton, a copy of which is attached to the Prospectus as Exhibit F,
to the effect that as of October 23, 1995, the fair range of values of the
Warrants based on the Black Scholes model is between $3.37 and $3.74 per
Warrant. See "Method of Determining Exchange Values -- Opinion Regarding Warrant
Valuation" in the Prospectus.

The following table sets forth each of the Exchange Value components,
estimated on an interim basis.

EXCHANGE VALUE COMPONENTS

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 made this Exchange Offer in
contemplation of such sale, but the Exchange Offer is not conditioned upon
consummation of such sale.

6
<PAGE> 257

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 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.

7
<PAGE> 258

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" in the
Prospectus. 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.
Assuming the market price of the Common Stock remains in the range of $11.00 per
share and that the Warrants could be sold at their estimated present value of
$3.64 per Warrant, the Investors in the 1990-1 Partnership would receive
consideration in the form of cash distributions, Common Stock and cash proceeds
from the sale of the Warrants equal to approximately 77% of their initial
investment. Assuming that the market price of the Common Stock declines to $7.50
per share, its lowest price during the 52 weeks preceding the date of this
Prospectus, the Investors in the 1990-1 Partnership will have received
consideration in the form of cash distributions and Common Stock equal to
approximately 47% of their initial investment. On October 30, 1995, the last
sales price of the Benton Common Stock on NASDAQ National Market was $12.00 per
share. The assumed market price of the Common Stock of $16.75 per share
discussed above represents a 40% 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.

8
<PAGE> 259

COMPENSATION PAID TO MANAGING GENERAL PARTNER

Under the terms of the Partnership Agreement, the Managing General Partner
was entitled to certain cash distributions based upon its share of revenues. The
Managing General Partner received cash distributions of $367,490 for the year
ended December 31, 1994. This amount represents cumulative cash distributions
that were allocable to the Managing General Partner from 1991 to 1994, but were
not paid until 1994. No other cash distributions have been received during the
last three fiscal years and for the six months ended June 30, 1995. The Managing
General Partner was also entitled to receive a reimbursement of certain costs
and expenses which it incurred on behalf of the Partnership. Such reimbursements
may be deemed to be compensation to the Managing General Partner. The Managing
General Partner received reimbursement of its general and administrative
expenses allocable to the Partnership in the amounts of $32,900, $31,392,
$30,562 and $14,915 for the fiscal years of 1992, 1993, 1994 and the six months
ended June 30, 1995 respectively. In 1992, the Managing General Partner also
received reimbursement of a portion of its geological and geophysical costs
associated with the Partnership properties in the amount of $92,275. No cash
distributions or compensation was paid by the Partnership to affiliates of
Benton during such time period.

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. If the Exchange Offer is accepted, neither Benton nor any affiliate of
Benton will receive any further distributions, compensation or reimbursements
from the Partnership.

CASH DISTRIBUTIONS TO INVESTORS

The following table sets forth the cash distributions paid per Unit 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.

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.

9
<PAGE> 260

PROSPECTUS SUPPLEMENT
1991-1 PARTNERSHIP

SUBJECT TO COMPLETION

DATED OCTOBER 31, 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. 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.

- 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 ALTERNATIVES OF CONTINUING THE PARTNERSHIP OR LIQUIDATING ITS ASSETS
COULD POTENTIALLY BE MORE BENEFICIAL TO INVESTORS THAN THE EXCHANGE
OFFER.

- 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.

- FUTURE EQUITY OFFERINGS BY BENTON COULD POTENTIALLY BE DILUTIVE TO
INVESTORS HOLDING COMMON STOCK OR WARRANTS.

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
Exchange Value." Holders of Units in the Partnership who elect to accept the
Exchange Offer may choose to receive 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., as described in the
Prospectus, is actually consummated. See "The Exchange Offer and
Proposal -- Election to Receive Cash in Lieu of Common Stock" in the Prospectus.
On October 30, 1995, the last reported sales price of the Common Stock, as
reported on NASDAQ National Market, was $12.00.

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.

THE EXCHANGE OFFER EXPIRES AT 5:00 P.M. PACIFIC TIME ON , 1995
UNLESS EXTENDED.
------------------------

THE DATE OF THIS SUPPLEMENT IS , 1995.
<PAGE> 263

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

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."

1
<PAGE> 264

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 interest. See "Recommendations of the Managing
General Partner -- Fiduciary Duties of Benton" contained in the Prospectus.

2
<PAGE> 265

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.

Regulation. The oil and gas industry is subject to broad and frequently
changing regulations that could adversely affect the operations of Benton.

MANAGING GENERAL PARTNER'S DETERMINATION THAT EXCHANGE OFFER IS FAIR

3
<PAGE> 266

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 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.

4
<PAGE> 267

discount rate used in Benton's liquidation analysis to account for the timing of
cash flows as well as production and concentration risks.

<TABLE>
<CAPTION>
TOTAL VALUE PER
VALUATION METHOD INVESTOR VALUE(1) 1991-1 UNIT
---------------- ----------------- -----------
<S> <C> <C>
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

DETERMINATION OF EXCHANGE VALUE

5
<PAGE> 268

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 ended October 27, 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. Benton
engaged J.P. Morgan Securities Inc. ("J.P. Morgan") to render its opinion as to
the fair range of values of the Warrants using the Black-Scholes methodology for
pricing options. J.P. Morgan has delivered its written opinion to the Board of
Directors of Benton, a copy of which is attached to the Prospectus as Exhibit F,
to the effect that as of October 23, 1995, the fair range of values of the
Warrants based on the Black Scholes model is between $3.37 and $3.74 per
Warrant. See "Method of Determining Exchange Values -- Opinion Regarding Warrant
Valuation" in the Prospectus.

The following table sets forth each of the Exchange Value components,
estimated on an interim basis.

EXCHANGE VALUE COMPONENTS

<TABLE>
<S> <C>
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
========
</TABLE>

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.

6
<PAGE> 269

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.

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 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, 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 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 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.

7
<PAGE> 270

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 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" in the
Prospectus. 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.
Assuming the market price of the Common Stock remains in the range of $11.00 per
share and that the Warrants could be sold at their estimated present value of
$3.64 per Warrant, the Investors in the 1991-1 Partnership would receive
consideration in the form of cash distributions, Common Stock and cash proceeds
from the sale of the Warrants equal to approximately 73% of their initial
investment. Assuming that the market price of the Common Stock declines to $7.50
per share, its lowest price during the 52 weeks preceding the date of this
Prospectus, the Investors in the 1991-1 Partnership will have received
consideration in the form of cash distributions and Common Stock equal to
approximately 38% of their initial investment. On October 27, 1995, the last
sales price of the Benton Common Stock on NASDAQ National Market was $11.31 per
share. The assumed market price of the Common Stock of $16.75 per share
discussed above represents a 48% 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.

8
<PAGE> 271

COMPENSATION PAID TO MANAGING GENERAL PARTNER

Under the terms of the Partnership Agreement, the Managing General Partner
was entitled to certain cash distributions based upon its share of revenues. The
Managing General Partner received cash distributions of $42,477 for the year
ended December 31, 1994. This amount represents cumulative cash distributions
that were allocable to the Managing General Partner from 1992 to 1994, but were
not paid until 1994. No other cash distributions have been received during the
last three fiscal years and for the six months ended June 30, 1995. The Managing
General Partner was also entitled to receive a reimbursement of certain costs
and expenses which it incurred on behalf of the Partnership. Such reimbursements
may be deemed to be compensation to the Managing General Partner. The Managing
General Partner received reimbursement of its general and administrative
expenses allocable to the Partnership in the amounts of $4,138, $7,563, $7,523
and $3,671 for the fiscal years of 1992, 1993, 1994 and the six months ended
June 30, 1995 respectively. In addition, the Managing General Partner received a
reimbursement of organizational and due diligence costs of $43,912 and a
reimbursement of geological and geophysical costs associated with Partnership
properties in the amount of $59,539. No cash distributions or compensation was
paid by the Partnership to affiliates of Benton during such time period.

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. If the Exchange Offer is accepted, neither Benton nor any affiliate of
Benton will receive any further distributions, compensation or reimbursements
from the Partnership.

CASH DISTRIBUTIONS TO INVESTORS

The following table sets forth the cash distributions paid per Unit 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.

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.

<PAGE> 1
Exhibit 23.1

INDEPENDENT AUDITORS' CONSENT

We consent to the use in this Amendment No. 3 to 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 part of such Registration
Statement, and to the reference to us under the heading "Experts" in such
Prospectus.

Deloitte & Touche LLP

Los Angeles, California
October 31, 1995

<PAGE> 1
[JP MORGAN LOGO]

EXHIBIT 99.1

CONSENT OF J.P. MORGAN SECURITIES, INC.

We hereby consent to the use of our opinion letter dated October 20,
1995 to the Board of Directors of Benton Oil and Gas Company, included in
Exhibit F to the Prospectus, which forms a part of the Registration Statement
on Form S-4 relating to the proposed exchange of a combination of its common
stock and Warrants for the partnership interest in the Benton Oil & Gas
Combination Partnership 1989-1, L.P., a California limited partnership, the
Benton Oil & Gas Combination Partnership 1990-1, L.P., a California limited
partnership, and the Benton Oil & Gas Combination Partnership 1991-1, a
California limited partnership and to the references to such opinion in such
Prospectus. In giving such consent, we do not admit that we come within the
category of persons whose consent is required under Section 7 of the Securities
Act of 1933, as amended, or the rule and regulations of the Securities and
Exchange Commission thereunder, nor do we hereby admit that we are experts with
respect to any part of such Registration Statement within the meaning of the
term "experts" as used in the Securities Act of 1933, as amended, or the rules
and regulations of the Securities and Exchange Commission thereunder.

J.P. MORGAN SECURITIES INC.

By: /s/ ADRIAN DOHERTY
-----------------------
Name: Adrian Doherty
Title: Managing Director

October 20, 1995