<PAGE> 1
As filed with the Securities and Exchange Commission on July 25, 1995
Registration No. 33-_____
================================================================================
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
-----------------
FORM S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
BENTON OIL AND GAS COMPANY
(Exact name of registrant as specified in Its charter)
DELAWARE 1311 77-0196707
(State or other (Primary Standard Industrial (I.R.S. Employer
jurisdiction Classification Code) Identification Number)
of Incorporation or
organization)
------------------------
1145 EUGENIA PLACE
SUITE 200
CARPINTERIA, CALIFORNIA 93013
(805) 566-5600
(Address, including zip code, and telephone number, including area code
of Registrant's principal executive offices)
-----------------
WITH COPIES TO:
Jack A. Bjerke
Emens, Kegler, Brown, Hill & Ritter Co., L.P.A.
65 East State Street, Suite 1800
Columbus, Ohio 43215
(614) 462-5400
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC:
As soon as practicable after the effective date of this Registration Statement.
If the securities being registered on this Form are to be offered in connection
with the formation of a holding company and there is compliance with General
Information G, check the following box. / /
CALCULATION OF REGISTRATION FEE
<TABLE>
<CAPTION>
===================================================================================================================
Title of Each Class of Amount to be Proposed Maximum Proposed Maximum Amount of
Securities to be Registered Offering Price Per Aggregate Offering Registration Fee
Registered Share Price
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Common Stock, par value 164,513 $12.09257 $7,223,655(1) $2,491(1)
$.01 per share
- -------------------------------------------------------------------------------------------------------------------
Warrants to
Purchase shares of
Common Stock 432,850 (2) (2) (2)
- -------------------------------------------------------------------------------------------------------------------
Common Stock
Underlying Warrants 432,850 (3) (3) (3)
===================================================================================================================
</TABLE>
(1) This Registration Statement relates to securities of the Registrant to
be issued in exchange for partnership interests in the Benton Oil & Gas
Combination Partnership 1989-1, L.P., a California limited partnership
(the "1989-1 Partnership"), Benton Oil and Gas Combination Partnership
1990-1, L.P., a California limited partnership (the "1990-1
Partnership") and the Benton Oil & Gas Combination Partnership 1991-1,
L.P., a California limited partnership (the "1991-1 Partnership")
(collectively referred to as the "Partnerships"). Pursuant to Rule
457(f)(2), the offering price per share, aggregate offering price and
registration fee is calculated based on the book value as of March 31,
1995 of a unit of partnership interest in the 1989-1 Partnership, the
1990-1 Partnership and the 1991-1 Partnership of approximately $1,229,
$837 and $1,189, respectively. There were 281.8182, 1,419.192 and
281.8182 partnership units outstanding in the 1989-1 Partnership, the
1990-1 Partnership and the 1991-1 Partnership, respectively, with an
aggregate book value of $1,869,300. Pursuant to Rule 457(i), the
offering price per share, aggregate offering price and registration fee
additionally includes the maximum amount of consideration which could
be received by the Registrant upon exercise of the Warrants, which have
an exercise price of $12.37, per share, with an aggregate maximum
amount of consideration of $5,354,355.
(2) The offering price per share, aggregate offering price and registration
fee related to the Warrants are included in the calculations for Common
Stock, above, as permitted by Rule 457(f)(2).
(3) Pursuant to Rule 457(i), no additional fees are payable for registering
the Common Stock underlying the Warrants.
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES
AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE
A FURTHER AMENDMENT THAT SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT
SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF THE
SECURITIES ACT OF 1933 OR UNTIL THIS REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(A),
MAY DETERMINE.
===============================================================================
<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>
A. Information About the Transaction
1. Forepart of Registration Statement and Outside Front Forepart of the Registration Statement; Outside Front
Cover Page of Prospectus................................ 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
B. Information About the Registrant
10. Information with Respect to S-3 Registrants............. Available Information; Incorporation of Certain
</TABLE>
<PAGE> 3
<TABLE>
<CAPTION>
Form S-4 Item Location in Prospectus
<S> <C>
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;
</TABLE>
<PAGE> 4
<TABLE>
Form S-4 Item Location in Prospectus
<S> <C>
Information Concerning 1989-1 Partnership; Information
Concerning 1990-1 Partnership; Information Concerning
1991-1 Partnership
</TABLE>
<PAGE> 5
INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. A
REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED WITH THE
SECURITIES AND EXCHANGE COMMISSION. THESE SECURITIES MAY NOT BE SOLD NOR MAY
OFFERS TO BUY BE ACCEPTED PRIOR TO THE TIME THE REGISTRATION STATEMENT BECOMES
EFFECTIVE. THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR THE
SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF THESE SECURITIES
IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION OR SALE WOULD BE UNLAWFUL PRIOR
TO REGISTRATION OR QUALIFICATION UNDER THE SECURITIES LAWS OF ANY SUCH STATE.
SUBJECT TO COMPLETION
DATED JULY 25, 1995
EXCHANGE OFFER
AN AGGREGATE OF 164,513 SHARES OF COMMON STOCK
AND WARRANTS TO PURCHASE AN AGGREGATE OF 432,850 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)
-------------
TOTAL EXCHANGE VALUE IN COMMON STOCK AND WARRANTS:
$1,292 PER 1989-1 PARTNERSHIP UNIT
$1,799 PER 1990-1 PARTNERSHIP UNIT
$2,099 PER 1991-1 PARTNERSHIP UNIT
EXCHANGE RATIO:
104 SHARES OF COMMON STOCK PER 1989-1 PARTNERSHIP UNIT
77 SHARES OF COMMON STOCK AND 249 WARRANTS PER 1990-1 PARTNERSHIP UNIT
92 SHARES OF COMMON STOCK AND 282 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 "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.
1989-1 PARTNERSHIP
Common Stock of Benton is being offered on a proportionate basis to
owners of Partnership Units in the 1989-1 Partnership, on the basis of $5,000
original investment interest (the "1989-1 Units") in exchange for their 1989-1
Units at the rate of 104 shares of Common Stock for each 1989-1 Unit. In
connection with the Exchange Offer, a proposal (the "1989-1 Proposal") is being
submitted to the Investors in the 1989-1 Partnership to amend the partnership
agreement of the 1989-1 Partnership (the "1989-1 Partnership Agreement") to
provide for the transfer of all assets and liabilities of the 1989-1 Partnership
to Benton in exchange for 29,309 shares of Common Stock and the pro rata
distribution of the Common Stock in liquidation of the 1989-1 Partnership. EACH
INVESTOR IN THE 1989-1 PARTNERSHIP WHO TENDERS HIS 1989-1 UNITS WILL, BY THAT
TENDER, CONSENT TO THE 1989-1 PROPOSAL.
<PAGE> 6
1990-1 PARTNERSHIP
Common Stock and Warrants of Benton are being offered on a
proportionate basis to owners of Partnership Units in the 1990-1 Partnership, on
the basis of $5,000 original investment interest (the "1990-1 Units") in
exchange for their 1990-1 Units at the rate of 77 shares of Common Stock and
Warrants to purchase 249 shares of Common Stock with an exercise price of $12.37
per share for each 1990-1 Unit. In connection with the Exchange Offer, a
proposal (the "1990-1 Proposal") is being submitted to the Investors in the
1990-1 Partnership to amend the partnership agreement of the 1990-1 Partnership
(the "1990-1 Partnership Agreement") to provide for the transfer of all assets
and liabilities of the 1990-1 Partnership to Benton in exchange for 109,277
shares of Common Stock and 353,378 Warrants and the pro rata distribution of the
Common Stock and Warrants in liquidation of the 1990-1 Partnership. EACH
INVESTOR IN THE 1990-1 PARTNERSHIP WHO TENDERS HIS 1990-1 UNITS WILL, BY THAT
TENDER, CONSENT TO THE 1990-1 PROPOSAL.
1991-1 PARTNERSHIP
Common Stock and Warrants of Benton are being offered on a
proportionate basis to owners of Partnership Units in the 1991-1 Partnership, on
the basis of $5,000 original investment interest (the "1991-1 Units") in
exchange for their 1991-1 Units at the rate of 92 shares of Common Stock and
Warrants to purchase 282 shares of Common Stock with an exercise price of $12.37
per share for each 1991-1 Unit. In connection with the Exchange Offer, a
proposal (the "1991-1 Proposal") is being submitted to the Investors in the
1991-1 Partnership to amend the partnership agreement of the 1991-1 Partnership
(the "1991-1 Partnership Agreement") to provide for the transfer of all assets
and liabilities of the 1991-1 Partnership to Benton in exchange for 25,927
shares of Common Stock and 79,472 Warrants and the pro rata distribution of the
Common Stock and Warrants in liquidation of the 1991-1 Partnership. EACH
INVESTOR IN THE 1991-1 PARTNERSHIP WHO TENDERS HIS 1991-1 UNITS WILL, BY THAT
TENDER, CONSENT WITH THE 1991-1 PROPOSAL.
ADOPTION OF EACH OF THE PROPOSALS REQUIRES THE CONSENT OF INVESTORS OF
SUCH PARTNERSHIP HOLDING 75% OF THE PARTNERSHIP UNITS. BENTON OIL AND GAS
COMPANY, IN ADDITION TO BEING MANAGING GENERAL PARTNER OF THE THREE
PARTNERSHIPS, OWNS 2.8182 1989-1 UNITS, 14.192 1990-1 UNITS AND 2.8182 1991-1
UNITS AND WILL VOTE SUCH UNITS THE SAME AS A MAJORITY OF INVESTORS VOTE THEIR
UNITS. INVESTORS WILL RECEIVE THE CONSIDERATION SET FORTH HEREIN, AND THE
RESPECTIVE PARTNERSHIP WILL BE DISSOLVED.
ASSUMING CONSUMMATION OF THE EXCHANGE OFFER, ALL OF THE INVESTORS IN A
PARTNERSHIP WHICH HAS APPROVED THE PROPOSAL PRESENTED TO SUCH PARTNERSHIP,
WHETHER OR NOT THEY TENDER THEIR UNITS AND THUS VOTE IN FAVOR OF THE PROPOSAL,
WILL RECEIVE THE SAME NUMBER OF SHARES OF COMMON STOCK AND WARRANTS AS THEY
WOULD HAVE RECEIVED HAD THEY TENDERED THEIR PARTNERSHIP UNITS AND THE RESPECTIVE
PARTNERSHIP WILL BE DISSOLVED.
THE EXCHANGE OFFER INVOLVES VARIOUS RISKS THAT SHOULD BE CONSIDERED BY
INVESTORS. SEE "RISK FACTORS AND MATERIAL CONSIDERATIONS," BEGINNING ON PAGE 34
OF THIS PROSPECTUS. IN PARTICULAR, INVESTORS SHOULD CONSIDER THE FOLLOWING
FACTORS:
* INVESTORS HAD RECEIVED CASH DISTRIBUTIONS FROM THE PARTNERSHIPS,
BUT WILL RECEIVE NO CASH DISTRIBUTIONS OR DIVIDENDS IN THE
FORESEEABLE FUTURE FROM BENTON.
<PAGE> 7
* 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, AND AN INDEPENDENT OFFER FOR THE PURCHASE OF
SUBSTANTIALLY ALL OF THE ASSETS OF EACH OF THE PARTNERSHIPS.
* 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 has determined that the Total Exchange Value of all (i) 1989-1
Units is $364,226 or $1,292 per 1989-1 Unit; (ii) 1990-1 Units is $2,553,119 or
$1,799 per 1990-1 Unit; and (iii) 1991-1 Units is $591,623 or $2,099 per 1991-1
Unit (collectively, the "Exchange Values"). The number of shares of Common Stock
offered in exchange for Partnership Units has been determined by dividing the
estimated cash proceeds from the offer for the purchase of the Umbrella Point
Field, as described herein, plus the estimated fair value of the remaining
tangible Partnership assets by a Common Stock price of $12.37, subject to
rounding adjustments. The Common Stock price of $12.37 is the closing price of
the Common Stock on the National Association of Securities Dealers,
Inc.-National Market System ("NASDAQ-NMS") on July 17, 1995. The number of
Warrants to be issued in exchange for Partnership Units has been determined by
dividing the estimated value of the General Intangibles of the Partnership, as
described herein, by the estimated present value per Warrant. Benton has used
the Black-Scholes
<PAGE> 8
option pricing model to calculate the present value of the Warrants, which
yielded a present value of $3.38 per Warrant. The Warrants are exercisable at a
price of $12.37 per share and will expire three years from the date of issuance.
See "Method of Determining Exchange Values." On July 24, 1995, the last reported
sales prices of the Common Stock, as reported on NASDAQ-NMS, was $12.375.
The Exchange may be withdrawn at any time prior to its scheduled
expiration date if Benton 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> 9
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.
Statements contained in this Prospectus or in any document incorporated in this
Prospectus by reference as to the contents of any contract or document referred
to herein or therein are not necessarily complete, and in each instance,
reference is made to the copy of such contract or other document filed as an
exhibit to the Registration Statement or such other document, each such
statement being qualified in all respects by such reference.
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; (ii) Benton's
quarterly report on Form 10-Q for the quarter ended March 31, 1995; (iii)
Benton's Current Report on Form 8-K filed on April 17, 1995; (iv) Benton's
Current Report on Form 8-K filed May 31, 1995; (v) Benton's Registration
Statement on Form 8-A filed on May 19, 1995; (vi) Benton's proxy statement on
Schedule 14A for the annual meeting of stockholders to be held July 26, 1995;
and (vii) the description of Common Stock set forth in Benton's Registration
Statements pursuant to the Exchange Act, and any amendment or report filed for
the purpose of updating any such description.
All documents and reports filed by Benton with the SEC pursuant to
Section 13(a), 13(c), 14 or 15(d) of the Exchange Act after the date of this
Prospectus and prior to the date of consummation of the transaction and
expiration of the Exchange Offer shall be deemed to be incorporated by reference
in this Prospectus and to be a part hereof from the dates of filing of such
documents or reports. Any statement contained in a document incorporated or
deemed to be incorporated by reference herein shall be deemed to be modified or
superseded for purposes of this Prospectus to the extent that a statement
contained herein or in any other subsequently filed document which also is or is
deemed to be incorporated by reference herein modifies or supersedes such
statement. Any such statement so modified or superseded shall not be deemed,
except as so modified or superseded, to constitute a part of this Prospectus.
i
<PAGE> 10
THIS PROSPECTUS INCORPORATES DOCUMENTS BY REFERENCE WHICH ARE NOT
PRESENTED HEREIN OR DELIVERED HEREWITH. SUCH DOCUMENTS (OTHER THAN EXHIBITS TO
SUCH DOCUMENTS, UNLESS SUCH EXHIBITS ARE SPECIFICALLY INCORPORATED BY REFERENCE
TO SUCH DOCUMENTS) ARE AVAILABLE, WITHOUT CHARGE, TO ANY PERSON, INCLUDING ANY
BENEFICIAL OWNER, TO WHOM THIS PROSPECTUS IS DELIVERED, ON WRITTEN OR ORAL
REQUEST TO: BENTON OIL AND GAS COMPANY, 1145 EUGENIA PLACE, SUITE 200,
CARPINTERIA, CALIFORNIA 93013, ATTENTION: CORPORATE SECRETARY, TELEPHONE (805)
566-5600. IN ORDER TO ENSURE DELIVERY OF THE DOCUMENTS PRIOR TO THE EXPIRATION
OF THE EXCHANGE OFFER, REQUESTS MUST BE RECEIVED BY ________, 1995.
No person is authorized to give any information or to make any
representation not contained in this Prospectus or in the documents incorporated
herein by reference in connection with the solicitation and the offering made
hereby and, if given or made, such information or representation should not be
relied upon as having been authorized by Benton. This Prospectus does not
constitute an offer to sell, or a solicitation of an offer to purchase, the
securities offered by this Prospectus, or the solicitation of a tender from any
person, in any jurisdiction in which it is unlawful to make such offer,
solicitation of an offer or tender solicitation. Neither the delivery of this
Prospectus nor any distribution of the securities made under this Prospectus
shall, under any circumstances, create an implication that there has been no
change in the affairs of Benton and the Partnerships since the date of this
Prospectus other than as set forth in the documents incorporated herein by
reference.
ii
<PAGE> 11
TABLE OF CONTENTS
SUMMARY................................................................. 1
The Parties.......................................................... 1
The Exchange Offer and Proposals..................................... 9
Risk Factors and Material Considerations............................. 11
Background and Alternatives to the Exchange.......................... 14
Reasons for the Exchange Offer; Recommendation of the
Managing General Partner.......................................... 16
Summary of Tax Consequences.......................................... 17
Accounting Treatment................................................. 17
Business of Benton and the Partnerships After the
Consummation of the Exchange...................................... 17
Comparative Rights of Security Holders............................... 18
Dissenters' Rights................................................... 18
Resales of Benton Common Stock....................................... 18
Description of the Warrants.......................................... 18
Material Advantages and Disadvantages of the Exchange and
Proposals......................................................... 19
Offer to Purchase Interests In The Umbrella Point Field.............. 20
Method of Determining Exchange Value for 1989-1 Partnership.......... 20
Method of Determining Exchange Value for 1990-1 Partnership.......... 22
Method of Determining Exchange Value for 1991-1 Partnership.......... 24
Consent Procedures................................................... 26
Conditions to Exchange............................................... 27
Regulatory Approvals................................................. 27
Certain Historical and Pro Forma Financial Data...................... 28
Certain Comparative Information...................................... 33
Risks Related to the Exchange Offer.................................. 34
Risks Related to Benton.............................................. 37
Risks Related to the Oil and Gas Industry............................ 41
PRICE RANGE OF COMMON STOCK, DIVIDENDS AND DISTRIBUTIONS................ 43
BACKGROUND OF EXCHANGE OFFER............................................ 45
1989-1 Partnership................................................... 45
1990-1 Partnership................................................... 46
1991-1 Partnership................................................... 47
Goldking Offer....................................................... 49
THE EXCHANGE OFFER AND PROPOSAL......................................... 50
Description of the Exchange Offer.................................... 50
The Proposal......................................................... 50
Dissenters' Rights................................................... 52
Distribution of Common Stock and Warrants............................ 52
Election to Receive Cash In Lieu of Common Stock..................... 52
Interests of Certain Persons in the Exchange and Proposals........... 53
Resale of Benton Common Stock........................................ 53
Fractional Shares.................................................... 53
Stock Exchange Listing............................................... 53
Accounting Treatment................................................. 54
Closing Date......................................................... 54
iii
<PAGE> 12
Operations After the Exchange........................................ 54
Expenses; Fees....................................................... 54
Benton's Dividend Policy............................................. 55
Litigation and Related Matters....................................... 55
METHOD OF DETERMINING EXCHANGE VALUES................................... 56
General.............................................................. 56
1989-1 Partnership Exchange Value Components......................... 57
1990-1 Partnership Exchange Value Components......................... 57
1991-1 Partnership Exchange Value Components......................... 60
REASONS FOR THE EXCHANGE OFFER.......................................... 62
Recommendation of the Managing General Partner....................... 62
Alternatives to the Exchange......................................... 64
Benefits of Continued Operations..................................... 67
Benefits of Liquidation.............................................. 70
Lack of Independent Representative................................... 76
Board of Directors of Benton; Benton's Reasons for the Exchange...... 77
Fiduciary Duties of Benton........................................... 77
Access to Investor List and Program Records.......................... 78
FAILURE TO APPROVE THE PROPOSALS........................................ 78
CONSENT PROCEDURES...................................................... 79
Written Consent and Vote Required.................................... 79
Consent Tabulation................................................... 79
Expiration of Exchange Offer......................................... 79
Amount Tendered...................................................... 79
Revocability of Tenders.............................................. 79
Solicitation of Letters of Transmittal............................... 80
Acceptance of Tenders................................................ 80
Special Requirements for Certain Investors........................... 80
Representations and Covenants........................................ 81
Validity of Tenders.................................................. 81
Payments of Fees and Expenses........................................ 81
Compliance with Tender Offer Practices............................... 82
CERTAIN FEDERAL TAX CONSEQUENCES........................................ 83
Tax Consequences of the Exchange..................................... 83
Realization of Suspended Passive Losses.............................. 84
Basis in Stock and Warrants.......................................... 84
COMPARATIVE RIGHTS OF SECURITY HOLDERS.................................. 85
UNAUDITED PRO FORMA FINANCIAL INFORMATION............................... 93
INFORMATION CONCERNING BENTON...........................................100
Incorporation of Certain Information by Reference....................100
Business.............................................................100
iv
<PAGE> 13
Recent Events..................................................108
INFORMATION CONCERNING 1989-1 PARTNERSHIP..............................109
General........................................................109
Description of Oil and Gas Properties..........................109
Selected Historical Financial Data.............................111
Management Discussion and Analysis of Financial Condition
and Results of Operation ...................................112
INFORMATION CONCERNING 1990-1 PARTNERSHIP..............................114
General........................................................114
Description of Oil and Gas Properties..........................114
Selected Historical Financial Data.............................116
Management Discussion and Analysis of Financial Condition
and Results of Operation ...................................118
INFORMATION CONCERNING 1991-1 PARTNERSHIP..............................121
General........................................................121
Description of Oil and Gas Properties..........................121
Selected Historical Financial Data.............................122
Management Discussion and Analysis of Financial Condition
and Results of Operation ...................................124
DESCRIPTION OF SECURITIES..............................................127
LEGAL MATTERS..........................................................128
EXPERTS................................................................128
GLOSSARY...............................................................129
INDEX TO FINANCIAL STATEMENTS..........................................F-1
v
<PAGE> 14
SUMMARY
The following is a brief 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.
THE PARTIES
BENTON OIL AND GAS COMPANY
Benton Oil and Gas Company ("Benton" or the "Company") is primarily
engaged in the development and production of oil and gas properties. The
Company's operations are focused on the eastern region of Venezuela, the Gulf
Coast region of Louisiana and the West Siberia region of Russia. Benton's
business strategy is to seek new reserves in areas of low geologic risk and to
exploit underdeveloped existing oil and gas fields. The Company implements the
exploitation strategy through the in-house design and interpretation of 3-D
seismic surveys and through workovers, recompletions, redrilling and exploration
and development drilling.
Internationally, the Company seeks projects with significant reserve
potential in areas with low geologic risk and known proved reserves where, in
certain situations, the Company can add value by employing modern exploration,
drilling, completion and production techniques. To reduce risk, control costs,
and facilitate local transactions, the Company has formed ventures with local
foreign partners.
Domestically, the Company integrates 3-D seismic technology with
subsurface geologic data from previously drilled wells. This geophysical
evaluation enables the Company to discover previously undetected reserves in
existing fields. The Company believes that it enjoys a competitive advantage in
finding and developing reserves on an economic basis because of its
concentration on 3-D seismic technology, the training and qualifications of its
in-house technical team and the practical experience and knowledge which this
team has acquired over past years. The Company's recognized technical expertise
has afforded it access to projects it otherwise would not have enjoyed.
In the ordinary course of its business, the Company continues to
evaluate acquisition, joint venture and other opportunities that would enable it
to further its business strategy.
Principal Areas of Activity
The following table summarizes the Company's proved reserves at
December 31, 1994 by principal geographic area:
1
<PAGE> 15
<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.
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
2
<PAGE> 16
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 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,
3
<PAGE> 17
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.
4
<PAGE> 18
Rabbit Island Field
Rabbit Island is located in state waters in Iberia and St. Mary
Parishes, approximately 95 miles southwest of New Orleans. The dome was
discovered in 1939 by Texaco which continues to operate the field. Compared to
West Cote Blanche Bay, on whose 5,892 acres more than 800 wells have been
drilled, just over 200 wells have been drilled on the 27,909 acres of the Rabbit
Island Field. Cumulative production through December 31, 1994 was 48 MMBbl of
oil and 1.2 Tcf of gas from 51 productive zones.
In 1992, the Company signed an agreement with Texaco to fund and
conduct a 3-D seismic program covering approximately 105 square miles over the
Rabbit Island project area. The estimated cost to the Company of this program is
approximately $6.0 million, substantially all of which has been expended. The
seismic survey has been shot, processed and is currently being interpreted.
Pursuant to the agreement, the Company may drill five wells over a
period of up to five years. As identified below, the first well has been
drilled. Assuming the remaining four wells are drilled in accordance with the
terms set forth in the agreement, the Company will earn a 50% working interest
in the entire field (other than among other things, wells previously drilled by
Texaco). The first well in the drilling program was successfully completed in
January 1995 and is currently producing approximately 9.5 MMcf of natural gas
per day. The Company expects to drill up to four additional wells during 1995 at
Rabbit Island at a cost of up to $4 million.
Certain of the Company's rights and 50% of its interest in the Field
were sold to Tenneco in July 1993. In May, 1995, the Company and Tenneco signed
an agreement in principle with Texaco to expand the acreage under the Rabbit
Island Field agreement by 10,452 acres in exchange for an increase in the number
of earning wells to be drilled by the Company from 5 to 8 wells.
Belle Isle Field
The Belle Isle Field is located on the shore of the Atchafalaya Bay,
approximately 75 miles southwest of New Orleans, in St. Mary Parish. The field
was discovered in 1941 and developed by Sun Oil Company. Currently, 12,000 acres
on the north portion of the field are operated by Oryx, and 6,400 acres on the
south portion of the field are operated by Apache Corporation (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,
5
<PAGE> 19
Oryx has granted the Company a right of first refusal to participate in such
drilling and receive a 33% working interest in the resulting wells.
In 1991, the Company reached an agreement with Texaco to evaluate 5,500
acres on the southern portion of the field by extending the 3-D seismic survey.
Pursuant to this agreement, upon the Company's completion of the seismic survey
and its drilling of an initial test well in accordance with the terms set forth
in the agreement, Texaco assigned to the Company a 50% working interest in its
entire 6,400 acre portion of the Belle Isle Field (other than, among other
things, existing wells previously drilled by Texaco).
In 1992, the Company completed a 55.75 square mile 3-D seismic survey
over the Belle Isle Field, thereby satisfying the survey obligations that are
prerequisites for earning working interests in the Texaco portion of the Field
and the Oryx wells. The survey was reprocessed in 1993 and is being evaluated on
an ongoing basis. In 1993, the Company satisfied the drilling requirements under
the agreement with Texaco, thereby earning its 50% working interest on the
Texaco portion of the field.
In October 1994, the Company completed the Belle Isle State Lease 340
No. 1 well. This well is currently producing at rates of approximately 6 MMcf of
natural gas per day. The Company has until September 1, 1997 to exercise its
right to participate in any future Oryx wells. If the Company has participated
in the drilling of a producing well by that time, the Company's right to
participate in future wells will continue. Certain of the Company's rights and
50% of its interest in the Field were sold to Tenneco in July 1993.
In January 1995 Texaco sold its interest in Belle Isle to Apache
Corporation. The Company is unable at this time to assess the impact on the
development of the field as a result of this sale.
Tenneco Agreements
In June 1993, the Company entered into an agreement with Tenneco which
provided for payments to the Company of approximately $6.7 million in exchange
for a 50% interest in the Company's operations at the Rabbit Island and Belle
Isle Fields. The agreement also provided Tenneco with a five year option to
participate on a promoted basis as a 50% partner in any future ventures that the
Company acquired in the Gulf Coast area, except for the West Cote Blanche Bay
Field. The Company also has granted an option in favor of Tenneco to purchase,
at a market price, all of the Company's gas produced from the Gulf Coast.
Tenneco has exercised its option to purchase the Company's share of natural gas
production from all three fields.
In November 1994, the Company sold to Tenneco a 10.8% working interest
(24.9% of the Company's 43.3% working interest) in the West Cote Blanche Bay
Field for approximately $5.8 million and future consideration of up to $3.7
million.
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.
6
<PAGE> 20
OTHER PROPERTIES
At December 31, 1994, the Company had proved reserves of 180 MBOE and 6
MBOE in the Umbrella Point Field in Texas and certain fields in Louisiana and
Mississippi, respectively. In July 1995, the Company sold its interest in the
Umbrella Point Field.
Actual exploration and development activities in the United States
could ultimately vary from those currently projected by the Company, depending,
among other factors, on the availability of drilling rigs, the availability of
financing, the success of the activities and the continued concurrence of
working interest partners as to the timing and extent of such activities.
RUSSIA
In December 1991, the joint venture agreement forming GEOILBENT among
the Company (34% interest) and two Russian partners, Purneftegasgeologia and
Purneftegas (each having a 33% interest), was registered with the Ministry of
Finance of the USSR. The Company's partners are the official exploration and
production bodies which have been discovering and operating fields in the region
covered by the joint venture for many years, and which have access to pipelines,
railroads and other vital infrastructure. GEOILBENT develops, produces and
markets oil and condensate from the North Gubkinskoye Field in the West Siberia
region of Russia, approximately 2,000 miles northeast of Moscow. The field,
which covers an area approximately 15 miles long and 4 miles wide, has been
delineated with over 60 exploratory wells (which tested 26 zones) and is
surrounded by large proven fields. Before commencement of GEOILBENT's
operations, North Gubkinskoye was one of the largest non-producing fields in the
region. At December 31, 1994, the Proved Reserves attributable to the North
Gubkinskoye Field were 17.5 MMBOE, which represented 22% of the Company's Proved
Reserves.
During the third quarter of 1992, GEOILBENT commenced initial
operations which included the construction of a 37 mile oil pipeline and
installation of temporary production facilities. Completed in April 1993, with a
design capacity of 75,000 Bbl of oil per day, the pipeline transports oil from
the North Gubkinskoye Field south to the main Russian oil pipeline network. The
venture has been exporting oil since the fourth quarter of 1993.
GEOILBENT identified nine previously existing delineation wells that
were capable of being reentered and placed these on production. These
delineation wells were not originally intended by Purneftegasgeologia to be
commercial producers. Therefore, completion procedures for optimum production
were not employed. The Company believes that production rates from future wells
using western completion technologies will be significantly greater. GEOILBENT
has commenced drilling a series of development wells in the North Gubkinskoye
Field. Three Russian drilling rigs are drilling development wells offsetting
previously drilled exploration wells.
GEOILBENT is utilizing Russian equipment and personnel whenever
feasible. Supervision is provided jointly by an American and Russian management
team. Russian equipment, including Russian rigs, are being upgraded by certain
western technology and materials including shaker screens, monitoring equipment
and drilling and completion fluids. Such measures, along with paying for Russian
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
7
<PAGE> 21
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 31, 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 $7 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.
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.
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 is the Managing
General Partner of the 1989-1 Partnership.
Benton Oil and Gas Company is the Managing General Partner of the
Benton Oil & Gas Combination Partnership 1989-1, L.P. 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.
8
<PAGE> 22
1990-1 PARTNERSHIP
The 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 is the Managing
General Partner of the 1990-1 Partnership.
Benton Oil and Gas Company is the Managing General Partner of the
Benton Oil & Gas Combination Partnership 1990-1, L.P. 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
The 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 is the Managing
General Partner of the 1991-1 Partnership.
Benton Oil and Gas Company is the Managing General Partner of the
Benton Oil & Gas Combination Partnership 1991-1, L.P. 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
General. Benton is offering to exchange Common Stock for Partnership
Units in the 1989-1 Partnership. Benton is offering to exchange Common Stock and
Warrants for Partnership Units in 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 in
exchange for the Partnership Units. 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
9
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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 its sole discretion,
that a material change affecting the Partnerships has occurred. See "The
Exchange Offer and Proposal."
1989-1 Partnership. Each holder of a 1989-1 Unit who tenders his Units
in connection with the Exchange Offer will receive 104 shares of Common Stock,
$.01 par value per share, of Benton (the "Common Stock"). No Warrants will be
issued in exchange for 1989-1 Units. 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.
In connection with the Exchange Offer, Benton is submitting a Proposal
to Investors in the 1989-1 Partnership to amend the 1989-1 Partnership Agreement
to provide for the transfer of all of the assets and liabilities of the 1989-1
Partnership to Benton as of the December 31, 1994 Effective Date in exchange for
Common Stock in the amount set forth above and the pro rata distribution of such
consideration in liquidation of the 1989-1 Partnership. EACH INVESTOR WHO
TENDERS HIS 1989-1 UNITS PURSUANT TO THE EXCHANGE OFFER WILL, BY THAT TENDER,
CONSENT TO THE 1989-1 PROPOSAL. If the 1989-1 Partnership adopts the Proposal by
the consent of 75% of the 1989-1 Units, all Investors in the 1989-1 Partnership,
whether or not they tendered their 1989-1 Units in the Exchange Offer, will
receive the same amount of Common Stock they would have received had they
tendered their 1989-1 Units. CONSUMMATION OF THE EXCHANGE OFFER FOR INVESTORS
WHO HAVE TENDERED THEIR 1989-1 UNITS IS CONDITIONED UPON APPROVAL OF THE 1989-1
PROPOSAL. APPROVAL OF THE 1989-1 PROPOSAL AND ADOPTION OF THE EXCHANGE OFFER IS
NOT CONDITIONED UPON APPROVAL AND ACCEPTANCE BY ANY OTHER PARTNERSHIP. See "The
Exchange Offer and Proposal."
1990-1 Partnership. Each holder of a 1990-1 Unit who tenders his Units
in connection with the Exchange Offer will receive (i) 77 shares of Common
Stock, and (ii) Warrants to purchase 249 shares of Common Stock with an exercise
price of $12.37 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.
In connection with the Exchange Offer, Benton is submitting a Proposal
to Investors in the 1990-1 Partnership to amend the 1990-1 Partnership Agreement
to provide for the transfer of all of the assets and liabilities of the 1990-1
Partnership to Benton as of the December 31, 1994 Effective Date in exchange for
Common Stock and Warrants in the amount set forth above and the pro rata
distribution of such consideration in liquidation of the 1990-1 Partnership.
EACH INVESTOR WHO TENDERS HIS 1990-1 UNITS PURSUANT TO THE EXCHANGE OFFER WILL,
BY THAT TENDER, CONSENT TO THE 1990-1 PROPOSAL. If the 1990-1 Partnership adopts
the Proposal by the consent of 75% of the 1990-1 Units, all Investors in the
1990-1 Partnership, whether or not they tendered their 1990-1 Units in the
Exchange Offer, will receive
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<PAGE> 24
the same amount of Common Stock and Warrants they would have received had they
tendered their 1990-1 Units. CONSUMMATION OF THE EXCHANGE OFFER FOR INVESTORS
WHO HAVE TENDERED THEIR 1990-1 UNITS IS CONDITIONED UPON APPROVAL OF THE 1990-1
PROPOSAL. APPROVAL OF THE 1990-1 PROPOSAL AND ADOPTION OF THE EXCHANGE OFFER IS
NOT CONDITIONED UPON APPROVAL AND ACCEPTANCE BY ANY OTHER PARTNERSHIP. See "The
Exchange Offer and Proposal."
1991-1 Partnership. Each holder of a 1991-1 Unit who tenders his Units
in connection with the Exchange Offer will receive (i) 92 shares of Common
Stock, and (ii) Warrants to purchase 282 shares of Common Stock with an exercise
price of $12.37 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.
In connection with the Exchange Offer, Benton is submitting a Proposal
to Investors in the 1991-1 Partnership to amend the 1991-1 Partnership Agreement
to provide for the transfer of all of the assets and liabilities of the 1991-1
Partnership to Benton as of the December 31, 1994 Effective Date in exchange for
Common Stock and Warrants in the amount set forth above and the pro rata
distribution of such consideration in liquidation of the 1991-1 Partnership.
EACH INVESTOR WHO TENDERS HIS 1991-1 UNITS PURSUANT TO THE EXCHANGE OFFER WILL,
BY THAT TENDER, CONSENT TO THE 1991-1 PROPOSAL. If the 1991-1 Partnership adopts
the Proposal by the consent of 75% of the 1991-1 Units, all Investors in the
1991-1 Partnership, whether or not they tendered their 1991-1 Units in the
Exchange Offer, will receive the same amount of Common Stock and Warrants they
would have received had they tendered their 1991-1 Units. CONSUMMATION OF THE
EXCHANGE OFFER FOR INVESTORS WHO HAVE TENDERED THEIR 1991-1 UNITS IS CONDITIONED
UPON APPROVAL OF THE 1991-1 PROPOSAL. APPROVAL OF THE 1991-1 PROPOSAL AND
ADOPTION OF THE EXCHANGE OFFER IS NOT CONDITIONED UPON APPROVAL AND ACCEPTANCE
BY ANY OTHER PARTNERSHIP. See "The Exchange Offer and Proposal."
RISK FACTORS AND MATERIAL CONSIDERATIONS
The Exchange Offer. In addition to the information included in this
Prospectus, the Investors should carefully consider the following factors in
determining whether to accept the Exchange Offer and consent to the Proposal.
The risks and effects of the Exchange will not be different for investors based
solely upon the Partnership in which he has invested. The risk factors
summarized below are described in further detail elsewhere in this Prospectus at
"Risk Factors and Material Considerations," beginning at page 34.
Lack of Arm's Length Negotiations and Uncertainties in the Method of
Determining Exchange Values. The Exchange Values were determined by
Benton, based in part on an offer for the purchase of substantially all
of the assets of the Partnerships from an unaffiliated third party, but
may not reflect the actual value of the net assets of the respective
Partnerships. The primary assets of each of the Partnerships considered
by Benton when determining the Exchange Value were the proved oil and
gas reserves of that Partnership (the "Proved Reserves") and the
present value of associated future net cash flow as of December 31,
1994, as well as the offer to purchase the Umbrella Point Field,
described herein. There are many uncertainties inherent in estimating
quantities of Proved Reserves, and the present value attributed to each
Partnership's Proved Reserves may be less than the discounted 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
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<PAGE> 25
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 " Reasons for the Exchange Offer --Recommendation of
the Managing General Partner" and "--Alternatives to the Exchange."
Lack of Independent Representatives for Investors; No Fairness Opinion.
No independent representative was selected or hired to represent the
interests of the Investors in negotiating the terms of the Exchange
Offer. The Exchange Values and other terms of the Exchange Offer may
therefore be inferior to those that could have been negotiated by an
independent representative. Benton did not retain an independent third
party to render an opinion regarding the fairness of the terms of the
Exchange Offer to the Investors.
Limited Dissenters' Rights or Appraisal 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.
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 than they would otherwise receive in the
Exchange Offer. 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 the number of shares of Common Stock
issued by Benton in connection with the Exchange Offer.
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<PAGE> 26
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.
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 "Reasons for the Exchange Offer--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.
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.
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<PAGE> 27
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."
Retention and Attraction of Key Personnel. Benton depends to a large
extent on the abilities and continued participation of certain key
employees, the loss of whose services could have a material adverse
effect on Benton's business.
Regulation. The oil and gas industry is subject to broad and frequently
changing regulations that could adversely affect the operations of
Benton.
In spite of the foregoing risks, Benton initiated and proposed the
Exchange Offer and recommends adoption of the Proposals by each of the
Partnerships to enable Benton to acquire the assets and liabilities of each of
the Partnerships and to provide Investors with the potential benefits summarized
below under the caption "Reasons for the Exchange Offer."
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:
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<PAGE> 28
* 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 natural
acquisition candidate 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 assets of each of the Partnerships. The
interest in purchasing the assets of the Partnerships was limited. As
discussed herein, Benton has received an offer to purchase the working
interest of each of the Partnerships in the Umbrella Point Field from
Goldking, for cash. The estimated cash proceeds to the 1989-1
Partnership, the 1990-1 Partnership and the 1991-1 Partnership are
$375,643,
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<PAGE> 29
$1,081,589 and $215,280, respectively, as of March 31, 1995 subject to
adjustments. In addition to the Goldking offer, Benton had received an
offer to purchase the working interests in the Umbrella Point Field
from Hunter Resources, Inc. ("Hunter") in October 1994. Pursuant to the
terms of that offer, Hunter would have paid a total of $8,000,000 in
cash and $1,000,000 in the form of a promissory note. Pursuant to this
offer, the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1
Partnership would have received aggregate cash consideration in the
amount of $394,313, $1,135,346 and $225,980, respectively, and a
promissory note in the aggregate amount of $49,289, $141,918 and
$28,248, respectively. The offer was subsequently withdrawn due to
Hunter's inability to secure financing for the transaction. 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.
* Lack of Partnership Resources and Declining Reserves. 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.
* Management's Conclusions Regarding Likelihood of Unaffiliated Bidders
at Comparable Values. Benton has solicited bidders for the assets of
the Partnerships, and none of the bids were in excess of the
liquidation values of the Partnerships. Benton has concluded that,
while an asset sale in liquidation might generate limited third party
interest, a sale of the assets of the Partnerships would not provide
immediate cash returns to Investors in excess of the liquidation value
of the Partnerships and would likely result in valuations by a third
party bidder below the Total Exchange Values of the Partnership Units.
Benton has undertaken an analysis of the current liquidation value of
each of the Partnerships. Results of that liquidation analysis reflect
liquidation values for the 1989-1 Partnership, the 1990-1 Partnership
and the 1991-1 Partnership estimated at $1,152, $807 and $946,
respectively, or approximately 11%, 55% and 55%, respectively, less
than the Total Exchange Values. In view of the uncertainties inherent
in the Managing General Partner's analysis and the lack of an
independent appraisal of the value, however, there can be no assurance
that obtaining additional bids for arm's length sales of assets of the
Partnerships would not result in valuations that would be comparable to
or higher than the Total Exchange Values, while also avoiding the risks
associated with ownership of the Common Stock.
REASONS FOR THE EXCHANGE OFFER; RECOMMENDATION OF THE MANAGING
GENERAL PARTNER
1989-1 Partnership. The Managing General Partner believes that the
Exchange Offer is fair to and in the best interests of the 1989-1 Partnership
and its Investors, and recommends that the Investors in the 1989-1 Partnership
consent to the Proposal and accept the Exchange Offer. See "Background of
Exchange Offer." The recommendation is based on a number of factors discussed in
this Prospectus. See "Reasons for the Exchange Offer--Recommendation of the
Managing General Partner." If the Exchange is not consummated, the 1989-1
Partnership will continue to operate its properties and the Managing General
Partner will review alternatives that may come available from time to time.
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<PAGE> 30
1990-1 Partnership. The Managing General Partner believes that the
Exchange is fair to and in the best interests of the 1990-1 Partnership and its
Investors, and recommends that the Investors in the 1990-1 Partnership consent
to the Proposal and accept the Exchange Offer. See "Background of Exchange
Offer." The recommendation is based on a number of factors discussed in this
Prospectus. See "Reasons for the Exchange Offer--Recommendation of the Managing
General Partner." If the Exchange is not consummated, the 1990-1 Partnership
will continue to operate its properties and the Managing General Partner will
review alternatives that may come available from time to time.
1991-1 Partnership. The Managing General Partner believes that the
Exchange Offer is fair to and in the best interests of the 1991-1 Partnership
and its Investors, and recommends that the Investors in the 1991-1 Partnership
consent to the Proposal and accept the Exchange Offer. See "Background to
Exchange Offer." The recommendation is based on a number of factors discussed in
this Prospectus. See "Reasons for the Exchange Offer--Recommendation of the
Managing General Partner." If the Exchange is not consummated, the 1991-1
Partnership will continue to operate its properties and the Managing General
Partner will review alternatives that may come available from time to time.
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.
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. Upon consummation of the
Exchange Transactions, Benton will operate the acquired Partnership assets as it
operates its oil and gas properties or may sell such assets to third parties at
any time. See "Background of Exchange Offer--Goldking Offer."
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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."
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 than they would otherwise receive in
the Exchange Offer. 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 the number of shares of Common Stock issued by Benton in
connection with the Exchange Offer.
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.
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 holders of 1990-1 Units and 1991-1 Units 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 $12.37 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
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<PAGE> 32
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 1990-1 Units and the 1991-1 Units, Benton will issue to
all holders of such Units, Warrants to purchase an aggregate of 432,850 shares
of Common Stock. On July 17, 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 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 $3.38 per
Warrant. Benton has used the Black-Scholes option pricing model to calculate the
present value of the Warrants. THE ACTUAL VALUE, IF ANY, A HOLDER MAY REALIZE
FROM THE WARRANTS WILL DEPEND ON THE EXCESS OF THE MARKET PRICE OF THE COMMON
STOCK OVER THE EXERCISE PRICE OF THE WARRANT ON THE DATE THE WARRANT IS
EXERCISED, SO THAT THERE IS NO ASSURANCE THE VALUE REALIZED BY A HOLDER WILL BE
AT OR NEAR THE VALUE ESTIMATED BY THE BLACK-SCHOLES OPTION PRICING MODEL. The
estimated values under the model for the Warrants are based on assumptions that
include (i) a stock price volatility of 30%, (ii) a risk-free rate of return
based on a three-year swap curve rate of 5.88%, 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.
MATERIAL ADVANTAGES AND DISADVANTAGES OF THE EXCHANGE AND PROPOSALS
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 total consideration to be received by each of the Partnerships
represents a premium over the standardized measure of discounted net cash flows
relating to each of the Partnerships Proved Reserves at December 31, 1994 plus
working capital;
(b) Benton's historical financial results and future prospects;
(c) the consideration to be received by each of the Partnerships in
connection with the Exchange represents consideration to the Investors in excess
of that which could be expected from continued cash distributions;
(d) 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;
(e) liquidity of the Common Stock of Benton compared to the lack of
liquidity of the Partnership Units; and
19
<PAGE> 33
(f) the ability of the investors to choose to receive cash in lieu of
Common Stock of Benton, if the sale of Umbrella Point Field to Goldking is
consummated.
The Managing General Partner also considered certain disadvantages that
included:
(a) the possibility that the price of oil and gas could increase,
thereby increasing the value of the assets of the Partnerships, which could have
a more direct effect to the Investors if owned by the Partnerships rather than
Benton;
(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 Partnerships;
(c) tax consequences to the Investors in connection with the Exchange
and liquidation of the Partnerships;
(d) the possibility that the reserve estimates for the Partnerships
could be undervalued; and
(e) risks associated with the market value of Benton Common Stock.
See "Reasons for the Exchange Offer." For other relevant factors, see
also "Risk Factors and Material Considerations."
OFFER TO PURCHASE INTERESTS IN THE UMBRELLA POINT FIELD
In June 1995, Benton received an offer from Goldking Trinity Bay Corp.
("Goldking") to purchase all of the right, title and interest owned by each of
the Partnerships and Benton in the Umbrella Point Field. The financing of the
Goldking acquisition was subject to the ability of Goldking to acquire at least
75% of the working interests in the Field, and therefore, to preserve the offer
for the Partnerships, Benton sold its corporate interest in the Umbrella Point
Field (11.77% working interest) to Goldking for $756,872. Benton entered into
agreements, on behalf of each of the Partnerships, with Goldking for the sale of
the Partnerships' interests in the Umbrella Point Field, subject to approval of
the Partnerships. In consideration of the sale, the 1989-1 Partnership, the
1990-1 Partnership and the 1991-1 Partnership would receive anticipated net
proceeds in the aggregate of $375,643, $1,081,589 and $215,280, respectively, if
the sale were consummated as of March 31, 1995.
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
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 March 31, 1995. These components represent all of the assets
and liabilities of the 1989-1 Partnership and were determined as of March 31,
1995 to conform with the SEC reporting requirements for unaudited financial
information.
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 three months ended March 31, 1995.
20
<PAGE> 34
1989-1 PARTNERSHIP
EXCHANGE VALUE TABLE
<TABLE>
<CAPTION>
Participants Total Exchange Value Per
Exchange Value(1) Partnership Unit(2)
------------------ ------------------
<S> <C> <C>
COMPONENTS OF EXCHANGE VALUES:
Estimated Cash Proceeds-Umbrella Point Field Sale ....... $ 375,643 $ 1,333
Estimated Value of Proved Reserves of Other Properties at
12/31/94(3) .......................................... 0 0
Current assets less current liabilities at 3/31/95(4) ... (15,980) (57)
Value Of Equipment At 12/31/94(5) ....................... 4,563 16
--------- ---------
Subtotal-Exchange Value attributable to stock ....... 364,226 1,292
--------- ---------
TOTAL EXCHANGE VALUE .................................... $ 364,226 $ 1,292
========= =========
NUMBER OF SHARES OF COMMON STOCK TO BE ISSUED PER
PARTNERSHIP UNIT(6)............................. 104
</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 March 31, 1995.
(5) Tax-basis balances of equipment, excluding Umbrella Point Field
equipment, at December 31, 1994.
(6) Obtained by dividing the Total Exchange Value by the Common Stock price
of $12.37, subject to rounding adjustments.
21
<PAGE> 35
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. Subject to closing adjustments, as of March 31, 1995 the
Partnership's estimated cash proceeds from the sale would be $375,643, or $1,333
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.
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 & 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 1990-1 Partnership as of March
31, 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 March 31, 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.
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
three months ended March 31, 1995.
1990-1 PARTNERSHIP
EXCHANGE VALUE TABLE
<TABLE>
<CAPTION>
Participants Total Exchange Value Per
Exchange Value(1) Partnership Unit(2)
------------------- -------------------
<S> <C> <C>
COMPONENTS OF EXCHANGE VALUES:
$1,081,589 $762
Estimated Cash Proceeds-Umbrella Point Field Sale.............
Estimated Value Of Proved Reserves of Other Properties at 84
12/31/94(3)................................................ 119,694
Current assets less current liabilities at 3/31/95(4)......... 143,839 102
Value of equipment at 12/31/94(5)............................. 13,037 9
---------- ----
Subtotal--Exchange Value attributable to stock............ 1,358,159 957
========== ====
</TABLE>
22
<PAGE> 36
<TABLE>
<CAPTION>
Participants Total Exchange Value Per
Exchange Value(1) Partnership Unit(2)
------------------- --------------------
<S> <C> <C>
General Intangibles........................................... 1,194,960 842
---------- ------
Subtotal--Exchange Value attributable to warrants......... 1,194,960 842
---------- ------
TOTAL EXCHANGE VALUE.......................................... $2,553,119 $1,799
========== ======
NUMBER OF SHARES OF COMMON STOCK TO BE ISSUED PER
PARTNERSHIP UNIT(6).................................... 77
NUMBER OF WARRANTS TO BE ISSUED FOR
PARTNERSHIP UNIT(7).................................... 249
</TABLE>
- ----------------------
(1) No exchange value is attributable to Managing General Partner's
interest.
(2) Obtained by dividing the Total Exchange Value by 1,419.129 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 March 31, 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 $12.37, subject to rounding adjustments.
(7) Obtained by dividing the estimated value of General Intangibles by the
estimated present value of the Warrants ($3.38 per Warrant). Benton has
determined the value attributed to General Intangibles based solely
upon its evaluation of the success to date of the Partnership, total
consideration paid to date to the participants and the value to Benton
in dissolving and liquidating the Partnership.
Anticipated Sales Proceeds. In July 1995, Benton, on behalf of the
1990-1 Partnership, and Goldking executed an agreement whereby Goldking will
purchase a 14.19% working interest in the Umbrella Point Field from the 1990-1
Partnership, subject to approval of the participants of the Partnership. Upon
execution of the agreement, Goldking made an earnest money deposit in favor of
the partnership. Subject to closing adjustments, as of March 31, 1995 the
Partnership's estimated cash proceeds from the sale would be $1,081,589, or $762
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.
23
<PAGE> 37
From inception through July 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
$19.50 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. 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 & 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 1991-1 Partnership as of March
31, 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 March 31, 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.
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
three months ended March 31, 1995.
24
<PAGE> 38
1991-1 PARTNERSHIP
EXCHANGE VALUE TABLE
<TABLE>
<CAPTION>
Participants Total Exchange Value Per
Exchange Value(1) Partnership Unit(2)
<S> <C> <C>
COMPONENTS OF EXCHANGE VALUES:
Estimated Cash Proceeds--Umbrella Point Field Sale............ $215,280 $ 764
Estimated Value of Proved Reserves of Other Properties at
12/31/94(3)............................................... 23,856 84
Current Assets Less Current Liabilities At 3/31/95(4)........ 81,359 289
Value Of Equipment At 12/31/94(5)............................ 2,555 9
-------- ------
Subtotal--Exchange Value attributable to stock............ 323,050 1,146
-------- ------
General Intangibles.......................................... 268,573 953
-------- ------
Subtotal--Exchange Value attributable to warrants......... 268,573 953
-------- ------
TOTAL EXCHANGE VALUE......................................... $591,623 $2,099
======== ======
NUMBER OF SHARES OF COMMON STOCK TO BE ISSUED PER
PARTNERSHIP UNIT(6)............................... 92
NUMBER OF WARRANTS TO BE ISSUED PER PARTNERSHIP
UNIT(7)........................................... 282
</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 March 31, 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 $12.37, subject to rounding adjustments.
(7) Obtained by dividing the estimated value of General Intangibles by the
estimated present value of the Warrants ($3.38 per Warrant). Benton has
determined the value attributed to General Intangibles based solely
upon its evaluation of the success to date of the Partnership, total
consideration paid to date to the participants and the value to Benton
in dissolving and liquidating the Partnership.
Anticipated Sales Proceeds. In July 1995, Benton, on behalf of the
1991-1 Partnership, and Goldking executed an agreement whereby Goldking will
purchase a 2.83% working interest in the Umbrella Point Field from the 1991-1
Partnership, subject to approval of the participants of the Partnership. Upon
execution of the agreement, Goldking made an earnest money deposit in favor of
the Partnership. Subject to closing adjustments, as of March 31, 1995 the
Partnership's estimated cash proceeds from the sale would be $215,280, or $764
per 1991-1 Unit. Benton has made this Exchange
25
<PAGE> 39
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.
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. 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
$19.50 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. The value of
the General Intangibles of the Partnership is not subject to valuation by third
parties since 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,
26
<PAGE> 40
although no extension is presently contemplated. Benton will not accept tenders
of less than all of the Partnership Units held by an Investor. Tenders of Units
and consents to the Proposals may be withdrawn upon written notice to Benton at
any time prior to the Expiration Date. See "Consent Procedures."
CONDITIONS TO EXCHANGE
Closing Date. The Exchange Offer is expected to be consummated on the
Closing Date, which will be no more than five days following the Expiration
Date, as extended.
1989-1 Partnership. The Exchange Offer to the 1989-1 Partnership is
conditioned upon consent of 75% of the 1989-1 Units to the 1989-1 Proposal and
the absence of any material adverse development affecting the 1989-1
Partnership, as determined by Benton in 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.
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.
27
<PAGE> 41
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 three months ended
March 31, 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 three months ended
March 31, 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 March 31,
1995, respectively. The selected consolidated financial data below should be
read in conjunction with Benton's consolidated financial statements and related
notes thereto, Management's Discussion and Analysis of Financial Condition and
Results of Operations, and Pro Forma Financial Information included elsewhere
herein or incorporated by reference herein.
<TABLE>
<CAPTION>
In thousands, except per Three Months Ended
share amounts Years Ended December 31 March 31
----------------------------------------------------------------- ------------------
1990(3) 1991(3) 1992 1993 1994 1994 1995
------ ------ ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C>
OPERATING DATA
Total revenues ...... $ 4,677 $ 11,513 $ 8,622 $ 7,503 $ 34,705 $ 3,682 $ 12,661
Lease operating
costs and
production taxes.. 1,609 4,209 4,414 5,110 9,531 1,766 2,246
Depletion,
depreciation and
amortization .... 882 3,058 3,041 2,633 10,298 1,173 3,145
General and
administrative
expense ......... 1,709 1,998 2,245 2,631 5,242 1,142 1,669
Interest expense .... 318 1,736 1,831 1,958 3,888 680 1,618
-------- -------- -------- -------- -------- -------- --------
Income (loss) before
income taxes and
minority interest.. 159 512 (2,909) (4,829) 5,746 (1,079) 3,983
Income tax expense .. -- -- -- -- 698 -- 1,079
--------- -------- --------- -------- -------- -------- --------
Income (loss) before
minority interest .. 159 512 (2,909) (4,829) 5,048 (1,079) 2,904
Minority interest ... -- -- -- -- 2,094 63 863
-------- -------- -------- -------- -------- -------- --------
Net income (loss) ... $ 159 $ 512 $ (2,909) $ (4,829) $ 2,954 $ (1,142) $ 2,041
======== ======== ======== ======== ======== ======== ========
Net income (loss)
per common
share(1).......... $ 0.02 $ 0.04 $ (0.22) $ (0.26) $ 0.12 $ (0.05) $ 0.08
======== ======== ======== ======== ======== ======== ========
Weighted average
common shares
outstanding(1)(2).. 10,357 11,838 12,981 18,609 24,851 24,737 26,037
Ratio of earnings to
fixed charges(5) .. 1.47x 1.29x -- -- 1.92x -- 2.90x
</TABLE>
28
<PAGE> 42
<TABLE>
<CAPTION>
Year Ended Three Months Ended
December 31, March 31,
1994 1995
---- ----
<S> <C> <C>
PRO FORMA
Before roll-up expenses and payments:
Net income .......................... $2,779 $1,961
Income per common share ............. $ 0.11 $ 0.07
Ratio of earnings to fixed
charges(5)......................... 1.88x 2.86x
After roll-up expenses and payments:
Net income .......................... $ 770 $1,961
Income per common share ............. $ 0.03 $ 0.07
Ratio of earnings to fixed
charges(5)......................... 1.37x 2.86x
</TABLE>
<TABLE>
<CAPTION>
In thousands, except per
share amounts At December 31 At March 31, 1995
-------------------------------------------------------------- -----------------
1990 1991 1992 1993 1994
---- ---- ---- ---- ---- PRO
HISTORICAL FORMA
---------- -----
BALANCE SHEET DATA
<S> <C> <C> <C> <C> <C> <C> <C>
Working capital (deficit) ... $ (1,861) $(14,777) $ 10,486 $ 26,635 $ 21,785 $ 13,479 $ 14,816
Total assets ................ 27,253 49,386 68,217 108,635 162,561 166,525 167,938
Long-term obligations, net of
current portion ........... 7,251 7,422 11,288 11,788 31,911 31,188 31,188
Stockholders' equity(4) ..... 10,064 20,209 50,468 84,021 88,259 90,489 91,980
</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, 1991 and 1990 and for the three months ended March
31, 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 carryforward 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 and the three months ended March
31, 1994, earnings did not cover fixed charges by $4,829,000,
$2,909,000 and $1,142,000, respectively.
29
<PAGE> 43
1989-1 Partnership Selected Historical Financial Data. The following
selected financial data for the 1989-1 Partnership as of and for each of the
years in the five year period ended December 31, 1994 are derived from the
1989-1 Partnership's audited financial statements. The selected consolidated
financial data for the three months ended March 31, 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 three months ended March 31, 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>
Three Months Ended
Years Ended December 31, March 31,
---------------------------------------------------------------- ------------------
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 $ 41,522 $ 30,781
Lease operating costs and
production taxes ......... 60,471 85,894 73,309 76,855 79,479 14,433 15,203
Exploration costs .......... 1,627 1,891 789
Depletion, impairment and
amortization ............. 46,224 74,122 111,050 72,453 77,895 21,880 42,934
General and administrative.. 31,086 17,428 32,110 38,432 33,654 18,469 17,752
-------- -------- -------- -------- -------- -------- --------
Net income (loss) ....... $ 75,000 $ 39,579 $ 7,364 $ 13,749 ($ 31,404) ($ 13,260) ($ 45,108)
======== ======== ======== ======== ======== ======== ========
Net increase (decrease) in
cash and cash equivalents.. ($100,529) ($ 82,547) ($241,781) ($127,320) ($106,355) ($ 6,257) $ 3,552
Net cash provided by
operating activities ..... 187,669 111,201 117,414 86,202 46,491 8,620 (2,174)
Distributions .............. 140,064 211,364 281,818 169,936 135,615 15,218 --
Per Unit Operating Data (1)
Net income (loss) .......... 192 61 (70) (16) (149) (59) (169)
Distributions of earnings .. 192 61 -- -- -- -- --
Distributions representing a
return of capital ......... 308 686 1,003 600 162 54 --
</TABLE>
<TABLE>
<CAPTION>
December 31, March 31,
------------------------------------------------------------------ ------------------------
Balance Sheet Data 1990 1991 1992 1993 1994 1994 1995
---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C>
Cash and cash equivalents... $ 564,404 $ 481,857 $ 240,076 $ 112,756 $ 6,401 $ 106,499 $ 9,953
Total assets at book value.. 1,177,716 1,016,060 727,977 571,790 407,052 543,312 385,596
Total assets at the value
assigned for purposes of
roll-up transaction....... 390,159
Total liabilities .......... 3,500 13,629 -- -- 2,281 -- 25,933
General and limited partners'
equity:
Managing General Partner.. 34,706 54,437 79,213 94,780 14,658 97,963 16,776
Participants ............. 1,139,510 947,994 648,764 477,010 390,113 445,349 342,887
---------- ---------- ---------- ---------- ---------- ---------- ----------
$1,174,216 $1,002,431 $ 727,977 $ 571,790 $ 404,771 $ 543,312 $ 359,663
========== ========== ========== ========== ========== ========== ==========
Per Unit Balance Sheet
Data(1)
Book value ............... $ 4,084 $ 3,398 $ 2,325 $ 1,710 $ 1,398 $ 1,596 $ 1,229
Value assigned for purpose
of the roll-up transaction 1,292
<FN>
(1) Per unit data is based on indicated amounts allocable to limited
partners divided by 279 limited partner units outstanding.
</TABLE>
30
<PAGE> 44
1990-1 Partnership Selected Historical Financial Data. The following
selected financial data for the 1990-1 Partnership as of and for each of the
years in the five year period ended December 31, 1994 are derived from the
1990-1 Partnership's audited financial statements. The selected consolidated
financial data for the three months ended March 31, 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 three months ended March 31, 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>
Inception to
December Three Months Ended
31, Years Ended December 31, March 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 $129,996 $96,623
Lease operating costs and
production taxes 155,247 440,434 285,840 254,903 263,957 48,007 50,961
Exploration costs 29,089 887,842 8,952 9,570 6,607 1,169 893
Loss on sale of oil and gas
properties 57,586 1,328
Depletion, impairment and
amotization 142,600 425,583 1,560,665 189,309 224,635 56,795 68,276
General and administrative 36,753 176,317 69,510 99,967 78,547 29,314 37,251
----------- ---------- ---------- ---------- ---------- ---------- ----------
Net income (loss) $114,117 ($825,495) ($1,212,036) $91,710 ($48,960) ($5,289) ($62,086)
=========== ========== ========== ========== ========== ========== ==========
Net increase (decrease) in
cash and cash equivalents $3,057,412 ($1,780,352) ($399,559) ($457,675) ($401,967) ($3,505) $39,157
Net cash provided by
operating activities 124,336 356,853 407,453 290,032 173,410 51,506 7,518
Distributions -- 706,351 1,071,312 604,582 463,345 31,222 --
Per Unit Operating Data(1)
Net income (loss) 24 (703) (935) 9 (68) (14) (46)
Distributions of earnings -- -- -- -- -- -- --
Distributions representing a
return of capital -- 500 762 400 66 22 --
</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 $ 416,321 $ 57,016
Total assets at book value 6,719,035 4,713,665 2,380,317 1,867,445 1,355,140 1,830,934 $1,293,054
Total assets at the value
assigned for purposes of
roll-up transaction 2,553,119
Total liabilities 523,524 50,000 -- -- -- -- --
General and limited partners'
equity:
Managing General Partner 137,695 291,366 386,815 436,921 111,441 449,318 112,695
Participants 6,053,875 4,363,866 1,978,692 1,429,384 1,240,417 1,379,409 1,176,276
Special Limited Partners 3,941 8,433 14,810 1,140 3,282 2,207 4,083
---------- ---------- ---------- ---------- ---------- ---------- ----------
$6,195,511 $4,663,665 $2,380,317 $1,867,445 $1,355,140 $1,830,934 $1,293,054
========== ========== ========== ========== ========== ========== ==========
Per Unit Balance Sheet Data(1)
Book value $ 4,309 $ 3,106 $ 1,408 $ 1,017 $ 883 $ 982 $ 837
Value assigned for purpose of
the roll-up transaction 1,799
<FN>
(1) Per unit data is based on indicated amounts allocable to limited
partners divided by 1,405 limited partner units outstanding.
</TABLE>
31
<PAGE> 45
1991-1 Partnership Selected Historical Financial Data. The following
selected financial data for the 1991-1 Partnership as of and for each of the
years in the four year period ended December 31, 1994 are derived from the
1991-1 Partnership's audited financial statements. The selected consolidated
financial data for the three months ended March 31, 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 three months ended March 31, 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>
Inception to
December Three Months Ended
31 Years Ended December 31, March 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 $23,753 $18,430
Lease operating costs and
production taxes 54,069 40,093 36,276 38,002 6,264 6,596
Exploration costs 158,016 7,245 1,284 769 233 178
Loss on sale of oil and gas
properties 61,225 225
Depletion, impairment and
amortization 125,742 65,241 60,503 95,497 16,350 92,063
General and administrative 20,925 28,876 45,195 28,823 18,395 14,602
---------- -------- -------- -------- ------- -------
Net income (loss) ($ 250,464) ($ 42,359) ($ 30,734) ($ 64,447) ($17,489) ($95,234)
========== ======== ======== ======== ======= =======
Net increase (decrease) in
cash and cash equivalents $1,233,019 ($955,826) ($100,013) ($117,010) ($25,401) $ 3,729
Net cash provided by
operating activities (7,849) 85,839 38,782 28,758 (1,139) (2,946)
Distributions 27,900 111,600 115,292 127,205 28,183 --
Per Unit Operating Data (1)
Net income (loss) (914) (243) (146) (256) (61) (336)
Distributions of earnings -- -- -- -- -- --
Distributions representing a
return of capital 100 400 400 300 100 --
</TABLE>
<TABLE>
<CAPTION>
December 31, March 31,
----------------------------------------------- -------------------
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 $151,779 $ 63,899
Total assets at book value 1,815,157 777,067 631,041 439,389 587,296 344,155
Total assets at the value
assigned for purposes of
roll-up transaction 591,623
Total liabilities 884,131 -- -- -- 1,927
General and limited partners'
equity:
Managing General Partner 18,413 43,394 50,358 13,601 49,654 11,946
Participants 912,292 732,846 580,591 425,503 535,534 331,854
Special Limited Partners 321 827 92 285 181 355
---------- -------- -------- -------- -------- --------
$ 931,026 $777,067 $631,041 $439,389 $585,369 $344,155
========== ======== ======== ======== ======== ========
Per Unit Balance Sheet Data(1)
Book value $ 3,270 $ 2,627 $ 2,081 $ 1,525 $ 1,919 $ 1,189
Value assigned for purpose of
the roll-up transaction 2,099
</TABLE>
(1) Per unit data is based on indicated amounts allocable to limited
partners divided by 279 limited partner units outstanding.
32
<PAGE> 46
CERTAIN COMPARATIVE INFORMATION
The following table sets forth certain unaudited comparative per Unit
and per share data based on (i) the Financial Statements of the 1989-1
Partnership, the 1990-1 Partnership, the 1991-1 Partnership and Benton at and
for the three months ended March 31, 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 104 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 77 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 92 shares
of Common Stock issuable per 1991-1 Unit.
<TABLE>
<CAPTION>
At or for the Three Months At and for the Year Ended
Ended March 31, 1995 December 31, 1994
-------------------- -----------------
Equivalent Equivalent Pro
Historical Pro Forma(1) Historical Forma(1)
---------- ----------- ---------- -------
<S> <C> <C> <C> <C>
1989-1 PARTNERSHIP:
Book value per 1989-1 Unit.............. $1,229 $ 382 $1,398 N/A
Cash distributions per 1989-1 Unit...... -- -- 162 --
Net income (loss) per 1989-1 Unit....... (169) 7 (149) $ 11(2)
1990-1 PARTNERSHIP:
Book value per 1990-1 Unit............... $ 837 $ 283 $883 N/A
Cash distributions per 1990-1 Unit...... -- -- 66 --
Net income (loss) per 1990-1 Unit....... (46) 5 (68) $ 8(2)
1991-1 PARTNERSHIP:
Book value per 1991-1 Unit............... $1,189 $ 338 $1,525 N/A
Cash distributions per 1991-1 Unit...... -- -- 300 --
Net income (loss) per 1991-1 Unit....... (336) 6 (256) $ 10(2)
BENTON OIL AND GAS:
Book value per common share............. $ 3.63 $3.67 $3.54 N/A
Net income per share.................... 0.08 0.07 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 $3 per 1989-1 Unit, $2
per 1990-1 Unit, $3 per 1991-1 Unit and $0.03 per Benton common share.
33
<PAGE> 47
RISK FACTORS AND MATERIAL CONSIDERATIONS
In addition to the material contained elsewhere herein, the following
factors should be carefully considered.
RISKS RELATED TO THE EXCHANGE OFFER
Elimination of Cash Distributions. The Exchange will result in the
Investors holding shares of Common Stock of Benton. Benton has paid no cash
dividends on its Common Stock and does not anticipate paying cash dividends on
its Common Stock in the foreseeable future. The cash distributions paid by the
1989-1 Partnership, the 1990-1 Partnership and the 1991-1 Partnership were $54,
$22 and $100 per $5,000 Unit, respectively, for each of the first three quarters
of 1994. 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 $696, $1,473 and $1,701
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 $12.37, subject to rounding
adjustments. The Common Stock Exchange Price is based upon the closing price of
the Common Stock July 17, 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 ($1,292 for 1989-1 Units,
$1,799 for 1990-1 Units and $2,099 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
34
<PAGE> 48
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
($324,663 for the 1989-1 Partnership, $1,145,428 for the 1990-1 Partnership and
$266,638 for the 1991-1 Partnership), these liquidation values were determined
by Benton, without an independent appraisal of such liquidation values.
Uncertainties in the Method of Determining Exchange Values. While
Benton believes that the method of determining the Exchange Values represents a
fair, reasonable and proper method of valuing the Partnership Units, the method
of determining the Exchange Values is subject to various uncertainties and may
have resulted in a valuation that would differ from offers made by independent
bidders. The components of the Exchange Value and the factors underlying these
uncertainties are described below.
Other Assets and Liabilities. The method of determining the
Exchange Values takes into account the estimated value of other assets
and liabilities of each of the Partnerships as of March 31, 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 March 31, 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
35
<PAGE> 49
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.
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' or Appraisal 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.
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 than they would otherwise receive in
the Exchange Offer. California Investors hold a substantial portion of the
interests in the 1989-1 Partnership, the 1990-
36
<PAGE> 50
1 Partnership and the 1991-1 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.
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 $1,142,126 for the three months ended March 31,
1994, and net income of $2,954,161 for the year ended December 31, 1994, and
$2,041,108 for the three months ended March 31, 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 $3,682,173 and $12,661,166 for the three months
ended March 31, 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, 1993 to December 31, 1994. 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.
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
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<PAGE> 51
affected by the recent political or economic instability in Russia. However,
there can be no assurance that Benton's operations will not be materially
adversely affected by political or economic instability or burdensome taxation
in the future. Benton currently carries no insurance against political
instability. However, Benton has applied for insurance to cover the risk of
currency inconvertibility for its Venezuelan operations with the Overseas
Private Investment Corporation ("OPIC"), an agency of the United States
government. There can be no assurance that Benton will be able to obtain this
insurance.
Benton has limited experience in conducting oil and gas operations in
Venezuela and Russia. Benton formed ventures with local partners in Venezuela
and Russia in an attempt to reduce some of the risks associated with conducting
operations in such countries and to facilitate local transactions. Benton may
encounter unforeseen difficulties in Venezuela and Russia, including problems
related to production and deliverability of oil and gas, and any such
difficulties could have a material adverse effect on Benton.
Furthermore, the timing and extent of Benton's development activities
in Venezuela are subject to the approval of Lagoven and the Ministry of Energy
and Mines. There can be no assurance that the development activities proposed by
Benton-Vinccler will receive the necessary approval. In addition, pursuant to
the Articles of Incorporation/By-Laws of Benton-Vinccler, the consent of both
Benton and Vinccler is a prerequisite to certain corporation transactions and
other matters relating to Benton-Vinccler, including, without limitation, any
sale of corporate assets, any assignment or sub-contracting of the operating
service agreement with Lagoven, any change in Benton-Vinccler's corporate
capital, duration or corporate purpose, any merger between Benton-Vinccler and
another company as well as 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 then required under the license
during the next few years, which could result in GEOILBENT paying significantly
higher royalties under the license.
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<PAGE> 52
Benton will not receive distributions from GEOILBENT until it has
expended its capital requirements under the terms of the joint venture
agreement. As of March 31, 1995, Benton has spent approximately $20.1 million of
the $25.8 million it has committed to spend by the end of 1995. However, oil and
gas production in Russia has been adversely affected by recent volatility of net
wellhead oil prices and the oil export tariff. If these conditions continue,
Benton believes that the joint venture agreement may be modified to reduce that
amount or to extend the due date of its obligation and modify other terms.
Benton believes that after it has satisfied such capital commitments, it will
not receive any significant distributions from GEOILBENT for several years
because substantially all of the money received by GEOILBENT from the North
Gubkinskoye Field will be reinvested to fund future development activities.
Properties Under Development. As of December 31, 1994, approximately
79% of Benton's Proved Reserves were undeveloped and required development
activities consisting primarily of recompletions, drilling of replacement wells
and other development drilling. In addition, approximately 3% of Benton's Proved
Reserves were proved developed behind-pipe or shut-in, requiring additional
development work. As a result, Benton will require substantial capital
expenditures to develop all of its proved reserves. At December 31, 1994, the
anticipated future development costs for Proved Reserves in Venezuela, Russia
and the United States were $79.5 million, $25.4 million and $2.0 million,
respectively. Benton does not have the capital to develop all of these reserves.
Benton expects to finance these future development costs through cash flow from
operations, sales of property interests, non-recourse project financing and the
offering of debt or equity securities. If such capital is not available, Benton
will either enter into joint ventures to develop the projects, which will result
in Benton retaining a smaller interest, or not develop the reserves. There can
be no certainty regarding the commercial 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,
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<PAGE> 53
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. In 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. 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
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<PAGE> 54
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.
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
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<PAGE> 55
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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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 (through July 18) 13.88 11.88
</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.
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<TABLE>
<CAPTION>
PARTNERSHIP 1989 1990 1991 1992 1993 1994 1995
- ----------- ---- ---- ---- ---- ---- ---- ----
<S> <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 four months
of 1995, natural gas prices at Umbrella Point Field have continued to decline to
a range of $1.43 to $1.61 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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BACKGROUND OF EXCHANGE OFFER
1989 - 1 PARTNERSHIP
The 1989-1 Partnership commenced business on September 1, 1989, the
effective date the 1989-1 Partnership was formed. Benton, as managing general
partner and sponsor of the 1989-1 Partnership, sold an aggregate of $1,409,091
in 1989-1 Units. At March 31, 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 April 1995, the Umbrella Point Field had ten wells
producing at combined average daily rates of 342 Bbl of oil and 3.4 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 December 31,
1994, the 1989-1 Partnership has produced and sold approximately 215,196 Mcf
of natural gas and 29,044 Bbl of oil.
Since 1993, the Partnerships' 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 Partnerships' most significant asset. Production volumes are expected to
decline further in subsequent periods due to ongoing depletion of the
Partnerships' 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 four months of 1995, prices received for the sale of natural gas from the
Umbrella Point Field has continued to decline to a range of $1.43 to $1.61 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 "Reasons for the Exchange
Offer--Recommendation of the Managing General Partner--Alternatives to the
Exchange" for a discussion of the third party bids received by the Managing
General Partner.
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<PAGE> 59
As the Private Placement Memorandum used to sell the 1989-1 Units
explained, oil and gas exploration and production have many risks, including the
risk that exploring for and producing natural gas and oil is highly speculative.
The search for oil and gas can result in unprofitable efforts not only from the
drilling of dry holes but from wells which, although initially productive, do
not produce oil and gas in sufficient amounts to return a profit on the costs
expended. In addition, there is a risk that oil and gas prices could decline and
the quantities of oil and gas discovered might not be sufficient to return the
initial investment. Based on the geological and geophysical information
available prior to the drilling and acquisition of the 1989-1 Partnership's
properties, the Managing General Partner believed that the 1989-1
Partnership's wells would be able to provide economic benefit. However, based on
the current evaluation of the 1989-1 Partnership reserves and future
prospects, the Managing General Partner believes the most logical economic
course is to exchange the remaining assets as soon as possible pursuant to the
terms of the Exchange Offer.
1990 - 1 PARTNERSHIP
The Partnership commenced business on November 29, 1990, the effective
date the 1990-1 Partnership was formed. Benton, as managing general partner
and sponsor of the 1990-1 Partnership, sold an aggregate of $7,095,960 of 1990-1
Units. Through March 31, 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 April 1995, the Umbrella Point Field had ten wells producing at combined
average daily rates of 342 Bbl of oil and 3.4 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 April 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 7 MMcf of natural gas per day. See
"Information Concerning 1990-1 Partnership - Description of Oil and Gas
Properties."
Since 1993, the Partnerships' 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 Partnerships' most significant asset. Production
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<PAGE> 60
volumes are expected to decline further in subsequent periods due to ongoing
depletion of the Partnerships' wells.
The 1990-1 Partnership has paid cumulatively $1,728 in cash
distributions per 1990-1 Unit to date. Since inception through December 31,
1994, the 1990-1 Partnership has produced and sold approximately 615,027 Mcf
of natural gas and 102,165 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 four months of 1995, prices received for the sale of natural gas from the
Umbrella Point Field has continued to decline to a range of $1.43 to $1.61 per
Mcf. During these periods of declining natural gas prices, the 1990-1
Partnership's cash flow was reduced while operating costs and third party costs
did not decline. Also as a result of lower natural gas prices, the amount of the
1990-1 Partnership's reserves that can be produced economically is reduced
substantially.
In addition, many of the Investors in the 1990-1 Partnership have
expressed concern regarding the historical performance and continued operation
of the 1990-1 Partnership and its properties. See "The Exchange Offer and
Proposal -- Litigation and Related Matters." In response to these concerns, the
Managing General Partner analyzed and evaluated the 1990-1 Partnership's
original objectives, current status and future prospects. The Managing General
Partner retained an independent petroleum engineer to prepare an updated
estimate of the remaining reserves of the 1990-1 Partnership properties and
the value of such reserves. In addition, the Managing General Partner made
available to third parties the 1990-1 Partnership well, production, reserve
and property information for the purpose of soliciting third party bids for the
purchase of the 1990-1 Partnership's assets. See "Reasons for the Exchange
Offer -- Recommendation of the Managing General Partner -- Alternatives to the
Exchange" 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, the effective date
the 1991-1 Partnership was formed. Benton, as managing general partner and
sponsor of the 1991-1 Partnership, sold an aggregate of $1,409,091 of 1991-1
Units. At March 31, 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
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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
April 1995, the Umbrella Point Field had 10 wells producing at combined average
daily rates of 342 Bbl of oil and 3.4 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 7 MMcf of natural gas per day. See
"Information Concerning 1991-1 Partnership -- Description of Oil and Gas
Properties."
Since 1993, the Partnerships' 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
Partnerships' most significant asset. Production volumes are expected to decline
further in subsequent periods due to ongoing depletion of the Partnerships'
wells.
The 1991-1 Partnership has paid cumulatively $1,200 in cash
distributions per 1991-1 Unit to date. Since inception through December 31,
1994, the 1991-1 Partnership has produced and sold approximately 69,222 Mcf of
natural gas and 15,109 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 four months of 1995, prices received for the sale of natural gas from the
Umbrella Point Field has continued to decline to a range of $1.43 to $1.61 per
Mcf. During these periods of declining natural gas prices, the 1991-1
Partnership's cash flow was reduced while operating costs and third party costs
did not decline. Also as a result of lower natural gas prices, the amount of the
1991-1 Partnership's reserves that can be produced economically is reduced
substantially.
In addition, many of the Investors in the 1991-1 Partnership have
expressed concern regarding the historical performance and continued operation
of the 1991-1 Partnership and its properties. See "The Exchange Offer and
Proposal -- Litigation and Related Matters." In response to these concerns, the
Managing General Partner analyzed and evaluated the 1991-1 Partnership's
original objectives, current status and future prospects. The Managing General
Partner retained an independent petroleum engineer to prepare an updated
estimate of the remaining reserves of the 1991-1 Partnership properties and
the value of such reserves. In addition, the Managing General Partner made
available to third parties the 1991-1 Partnership well, production, reserve
and property information for the purpose of soliciting third party bids for the
purchase of the 1991-1 Partnership's assets. See "Reasons for the Exchange
Offer -- Recommendation of the Managing General Partner -- Alternatives to the
Exchange" for a discussion of the third party bids received by the Managing
General Partner.
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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 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 March 31,
1995 in the aggregate of $375,643, $1,081,589 and $215,280, respectively, if the
sale were consummated, subject to adjustments for revenues, expenses and capital
expenditures after that date.
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<PAGE> 63
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 104 shares of Common Stock. 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.
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) 77 shares of Common Stock and (ii) Warrants to purchase 249
shares of Common Stock with an exercise price of $12.37 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) 92 shares of Common Stock and (ii) Warrants to purchase 282
shares of Common Stock with an exercise price of $12.37 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.
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* The dissolution of each of the Partnerships and the distribution to
the Investors of the Common Stock and Warrants allocable to their
interests in liquidation promptly following the Closing Date.
Each Investor who tenders his Partnership Units pursuant to the
Exchange Offer will by that tender, consent to the proposal for that
Partnership. If a Partnership adopts the proposal by the consent of 75% of the
Partnership Units for the respective Partnership, all Investors in that
Partnership, whether or not they tendered their Units in the Exchange Offer,
will receive the same amount of Common Stock and Warrants as they would have
received had they tendered their Partnership Units. Consummation of the Exchange
Offer for a partnership is conditioned upon approval by that partnership of the
proposal. Approval of the proposal and adoption of the Exchange Offer is not
conditioned upon approval or acceptance by any other partnership. Investors who
do not return a completed Letter of Transmittal will not receive Benton Common
Stock or Warrants until Benton has distributed immediately after the closing
date and investors have return an executed Transfer Application issuable to them
in the exchange, which may result in a delay in receiving the Common Stock and
Warrants if the transfer application is not properly returned.
Timing of Common Stock Issuance. Assuming that the proposal is adopted
and the Exchange Offer is consummated, Benton will have the benefit of each of
the Partnership's assets and associated cash flows commencing on the effective
date of December 31, 1994. The Common Stock and Warrants issued in the exchange
will be freely transferable immediately following issuance.
On the Closing Date, Benton will cause certificates representing the
Common Stock and the Warrants issuable in the Exchange to be registered in the
name of the holders who have accepted the Exchange Offer. Benton will also cause
a certificate representing the shares of Common Stock and Warrants that will be
issued to participants upon liquidation of each of the Partnerships to be issued
in the name of the Partnership, pending dissolution, liquidation and winding-up
of the Partnerships. Immediately thereafter, Benton will cause the shares of
Common Stock and Warrants issued in the name of the Partnership to be
transferred into certificates representing Common Stock and Warrants, registered
in the names of the individual participants remaining in the Partnerships
following liquidation.
Conditions. Benton may, in it sole discretion, at any time on or prior
to the closing date, refuse to consummate, abandon or terminate the exchange
offer and withdraw the proposal if after the date of this prospectus, in the
sole judgment of Benton, a material change shall have occurred or been
threatened (or any development shall have occurred or been threatened involving
a prospective material change) affecting (or likely to affect) the business or
properties of Benton or the partnerships or if Benton shall have become aware of
any facts or circumstances that have or may have material significance with
respect to Benton's operations. If any event shall occur or any matter shall
have been brought to the attention of Benton, that, in the sole judgment of
Benton materially affects the partnerships, whether adversely or otherwise, or
the exchange offer for interest in the partnerships, Benton may refuse to accept
tenders of interest in the partnerships, or may modify or amend the Exchange
Offer to take the event or matter into account.
The absence of the material change affecting Benton or the Partnerships
is the only material condition to the exchange offer. If that condition has not
been fulfilled or the exchange offer is withdrawn by Benton, each letter of
transmittal tendering an interest or consenting to the proposal will be void and
no Common Stock or Warrants will be issued in exchange for the interests in the
respective partnership.
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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 than they would otherwise receive in
the Exchange Offer. 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 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 $1,292 for each 1989-1 Unit, $957 for each 1990-1 Unit and
$1,146 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
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<PAGE> 66
Goldking will be consummated, and therefore, an Investor should make a decision
to accept the Exchange Offer based solely upon a decision to receive Common
Stock and Warrants in the amounts set forth herein.
INTERESTS OF CERTAIN PERSONS IN THE EXCHANGE AND PROPOSALS
In considering the recommendation of the Managing General Partner, the
Investors should be aware that the Managing General Partner has interests in the
Exchange that are in addition to the interests of the Partnerships and the
Investors generally. Benton is the Managing General Partner of each of the
Partnerships and its determination of the Exchange Values involves an inherent
conflict of interest. As Managing General Partner, Benton owes fiduciary duties
to the Investors in the Partnerships. In addition, it owes a duty to its
stockholders. While Benton believes that it has fulfilled these obligations in
its determination of the Exchange Values, which is supported, in part, by a
reserve report audited by an independent petroleum engineer, no degree of
objectivity or professional competence can eliminate the inherent conflict of
interest.
RESALE OF BENTON COMMON STOCK
The issuance of the Benton Common Stock to be received by the Investors
who tender their Partnership Units and the shares to be received by Investors in
liquidation of the Partnerships, as well as the issuance of the Common Stock
upon exercise of the Warrants, has been registered under the Securities Act.
Such shares may be traded freely and without restriction by those Investors of
the Partnerships not deemed to be "affiliates" of the Partnerships, as that term
is defined in the rules under the Securities Act. "Affiliates" are generally
defined as persons who control, are controlled by or are under common control
with the Partnership at the time of the Exchange. Accordingly, "affiliates"
generally will include the Managing General Partner and any Investor who owns in
excess of 10% of the Partnership interests. Benton Common Stock received by
those Investors who are deemed to be "affiliates" of a Partnership may be resold
without registration as provided by Rules 144 and 145, or as otherwise
permitted, under the Securities Act. This Prospectus does not cover any resales
of Benton Common Stock received by affiliates of the Partnerships or by certain
family members or related interests. Any Investor who becomes an affiliate of
Benton will be subject to similar restrictions under Rule 144.
FRACTIONAL SHARES
No fractional shares of Benton Common Stock will be issued. Fractional
share interests which would otherwise be issuable shall entitle the holder
thereof to receive, in lieu of such fractional interest, an amount of cash equal
to the product of such fraction multiplied by the closing price of the Benton
Common Stock on the NASDAQ-NMS on the Closing Date. Warrants to be issued will
be rounded to the nearest whole number of Warrants and no fractional interests
will be issued.
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.
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ACCOUNTING TREATMENT
The Exchange will be accounted for as a purchase by Benton.
Accordingly, the purchase price will be allocated to assets and liabilities
based on their estimated fair values as of the date of acquisition.
CLOSING DATE
The Exchange Offer is expected to be consummated on the Closing Date,
which will be no more than five days following the Expiration Date. Benton may
withdraw the Exchange Offer at any time prior to the Expiration Date under
certain circumstances, including the existence of any state or federal statute,
rule, regulation or order, or entry of any judicial or administrative order that
would prohibit the transactions contemplated by the Exchange Offer and the
Proposals.
1989-1 Partnership. The Exchange Offer to the 1989-1 Partnership is
conditioned upon consent of 75% of the 1989-1 Units to the 1989-1 Proposal
and the absence of any material adverse development affecting the 1989-1
Partnership, as determined by Benton in its sole discretion. On the Closing
Date, subject to satisfaction of these conditions, Benton intends to accept all
1989-1 Units validly tendered and not withdrawn pursuant to the Exchange
Offer.
1990-1 Partnership. The Exchange Offer to the 1990-1 Partnership is
conditioned upon consent of 75% of the 1990-1 Units to the 1990-1 Proposal
and the absence of any material adverse development affecting the 1990-1
Partnership, as determined by Benton in its sole discretion. On the Closing
Date, subject to satisfaction of these conditions, Benton intends to accept all
1990-1 Units validly tendered and not withdrawn pursuant to the Exchange
Offer.
1991-1 Partnership. The Exchange Offer to the 1991-1 Partnership is
conditioned upon consent of 75% of the 1991-1 Units to the 1991-1 Proposal
and the absence of any material adverse development affecting the 1991-1
Partnership, as determined by Benton in its sole discretion. On the Closing
Date, subject to satisfaction of these conditions, Benton intends to accept all
1991-1 Units validly tendered and not withdrawn pursuant to the Exchange
Offer.
OPERATIONS AFTER THE EXCHANGE
Benton is an independent oil and gas company engaged in the acquisition
of producing properties and exploration, development and production of oil and
gas, primarily in the eastern region of Venezuela, the Gulf Coast of Louisiana
and the West Siberia region of Russia. Upon consummation of the Exchange, Benton
intends to sell the working interests in the Umbrella Point Field to Goldking on
the terms described herein. If, however, such sale is not consummated, Benton
will operate the acquired Partnership assets as it operates its oil and gas
properties, or may sell those assets to another third party.
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.
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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 a note agreement 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. Benton 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 net proceeds from 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 YOUR
RIGHTS 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.
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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. 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.
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 $364,226, $2,553,119, and $591,623,
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 $12.37, subject to
rounding adjustments. The Common Stock price is based upon the closing price of
the Common Stock on NASDAQ-NMS on July 17, 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 $3.38 per Warrant. The Warrants are
exercisable at a price of $12.37 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,
(iii) the net book value of current assets and liabilities of the Partnership as
of March 31, 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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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........................................ $375,643
Present Value of Proved Reserves of other properties (SEC PV 10)..................... 0
Cash................................................................................. 9,953
Intercompany payable--Benton Oil and Gas Company..................................... (25,933)
Value of equipment................................................................... 4,563
--------
Exchange Value....................................................................... $364,226
========
</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 March 31, 1995 reflect a deficit of $15,980 after deducting
1994 distributions aggregating $45,655. The equipment value and current net
assets are based upon the 1989-1 Partnership's 1994 year-end tax accounting
records and March 31, 1995 unaudited financial statements, respectively,
maintained in accordance with the applicable provisions of the 1989-1
Partnership Agreement.
Benton believes that valuing the 1989-1 Partnership's equipment
(comprised of oil and gas production and transportation facilities) at its tax-
basis balances is favorable to the sellers of the producing properties since
many purchasers in transactions evaluated by Benton, as part of its on-going
involvement in the production area, allocate nominal value to well equipment on
the theory that its salvage value at the end of the commercial lives of acquired
wells will approximate the cost of plugging and abandoning the wells. Benton
believes that the original cost of the equipment less the deductions computed
through 1994 year end for tax purposes represents a reasonable approximation of
the fair market value of the equipment to Benton. Benton also believes that
valuing the current assets and liabilities of the 1989-1 Partnership
(comprised of cash and intercompany payable) at their book value as of March 31,
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.
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......................................... $1,081,589
Present value of Proved Reserves of other properties (SEC PV 10)..................... 119,694
Cash................................................................................. 57,016
Intercompany receivable--Benton Oil and Gas Company.................................. 86,823
Value of equipment................................................................... 13,037
General Intangibles.................................................................. 1,194,960
----------
Exchange Value....................................................................... $2,553,119
==========
</TABLE>
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Proved Reserves. The calculation of the present value of the 1990-1
Partnership's Proved Reserves for the purpose of determining the Exchange Value
complies with the rules and regulations of the SEC relating to the calculation
of the present value of future net cash flows determined as of December 31, 1994
attributable to proved oil and gas reserves for disclosure and financial
reporting purposes. The regulations governing these reserves do not permit the
use of escalated prices and costs except in accordance with existing contractual
arrangements, and the resulting SEC PV 10 calculations may overestimate or
underestimate the actual future cash flows from the production and sale of oil
and gas and, consequently, the present value thereof.
The gross quantities of Proved Reserves attributable to the 1990-1
Partnership's interest in its wells, together with the estimated present value
of those reserves, were estimated on an SEC PV 10 basis as of December 31, 1994
in a reserve report prepared by Benton and audited by Huddleston. A summary of
the report and a copy of the audit letter, setting forth the criteria and
assumptions used in evaluating the 1990-1 Partnership's Proved Reserves, are
included in Exhibit B.
There are numerous uncertainties inherent in estimating quantities of
Proved Reserves. Huddleston audited the data and computations used by Benton's
petroleum engineer in their evaluation of the total Proved Reserves attributable
to all of the wells in which the 1990-1 Partnership had an interest as of
December 31, 1994. Estimates by other independent petroleum engineers could vary
from Benton's estimates and could result in higher or lower valuations.
The estimates of the 1990-1 Partnership's future gross revenues
attributable to its estimated Proved Reserves as of December 31, 1994 were
calculated based on natural gas and crude oil prices in effect on that date.
Those prices had a weighted average of $1.63 per Mcf for natural gas and $15.94
per Bbl for oil.
Future operating and development costs were based on the 1990-1
Partnership's operating and development costs as of December 31, 1994 and were
used without escalation. Future severance (production) and ad valorem (property)
taxes were calculated using rates prevailing at December 31, 1994. The estimated
future gross revenues, future operating and development costs and production
taxes were allocated to the 1990-1 Partnership in accordance with its interest
in oil and gas properties, taking into account applicable reversionary and
overriding royalty interests.
The present values of the estimated net cash flows attributable to the
1990-1 Partnership's Proved Reserves of other properties were calculated by
discounting the future net cash flows to present value at the rate of 10% per
year, as prescribed by SEC regulations covering reserve reporting for financial
disclosure purposes. The discount factor is intended to reflect the timing of
future net cash flows. No further discount or risk adjustment was applied.
Present value, regardless of the discount rate used, is materially affected by
assumptions as to timing of future production, which may prove to have been
inaccurate.
A summary of the reserve report for the 1990-1 Partnership and a copy
of the related audit letter are included in Exhibit B to this Prospectus.
Estimates of the 1990-1 Partnership's Proved Reserves and of the present value
of future net cash flows from the reserves are estimates only and are based on
numerous assumptions and conditions of these estimates.
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 March 31, 1995 reflect a balance of $143,839 after
58
<PAGE> 72
deducting 1994 distributions aggregating $93,667. The equipment value and
current net assets are based upon the 1990-1 Partnership's 1994 year-end tax
accounting records and March 31, 1995 unaudited financial statements,
respectively, maintained in accordance with the applicable provisions of the
1990-1 Partnership Agreement.
Benton believes that valuing the 1990-1 Partnership's equipment
(comprised of oil and gas production and transportation facilities) at its tax-
basis balances is favorable to the sellers of the producing properties since
many purchasers in transactions evaluated by Benton, as part of its on-going
involvement in the production area, allocate nominal value to well equipment on
the theory that its salvage value at the end of the commercial lives of acquired
wells will approximate the cost of plugging and abandoning the wells. Benton
believes that the original cost of the equipment less the deductions computed
through 1994 year end for tax purposes represents a reasonable approximation of
the fair market value of the equipment to Benton. Benton also believes that
valuing the current assets and liabilities of the 1990-1 Partnership
(comprised of cash and intercompany receivable) at their book value as of March
31, 1995 is appropriate to reflect the fair market value of these items, which
are expected to be collected and paid to Benton, to the extent outstanding, in
the stated amounts reflected in the 1990-1 Partnership's unaudited balance
sheet as of that date.
General Intangibles. In determining the value attributed to General
Intangibles, Benton evaluated the success to date of the 1990-1 Partnership,
total consideration paid to date to the participants and the value to Benton of
dissolving and liquidation the 1990-1 Partnership so that Benton can focus on
its current operations and reduce the administrative burdens associated with
operating the Partnership. From inception through July 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 $19.50 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. 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.
59
<PAGE> 73
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.......................................... $215,280
Present Value of Proved Reserves of other properties (SEC PV 10)....................... 23,856
Cash................................................................................... 63,899
Intercompany Receivable--Benton Oil and Gas Company.................................... 17,460
Value of Equipment..................................................................... 2,555
General Intangibles.................................................................... 268,573
--------
Exchange Value......................................................................... $591,623
========
</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 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.
60
<PAGE> 74
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.
A summary of the reserve report for the 1991-1 Partnership and a copy
of the related audit letter are included in Exhibit B to this Prospectus.
Estimates of the 1991-1 Partnership's Proved Reserves and of the present value
of future net cash flows from the reserves are estimates only and are based on
numerous assumptions and conditions of these estimates.
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 March 31, 1995 reflect a balance of $81,359 after
deducting 1994 distributions aggregating $84,545. The equipment value and
current net assets are based upon the 1991-1 Partnership's 1994 year-end tax
accounting records and March 31, 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 March
31, 1995 is appropriate to reflect the fair market value of these items, which
are expected to be collected and paid to Benton, to the extent outstanding, in
the stated amounts reflected in the 1991-1 Partnership's unaudited balance
sheet as of that date.
General Intangibles. In determining the value attributed to General
Intangibles, Benton evaluated the success to date of the 1991-1 Partnership,
total consideration paid to date to the participants and the value to Benton of
dissolving and liquidation the 1991-1 Partnership so that Benton can focus on
its current operations and reduce the administrative burdens associated with
operating the Partnership. 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 $19.50 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,
61
<PAGE> 75
without regard to any tax benefits received by the participants. 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.
REASONS FOR THE EXCHANGE OFFER
RECOMMENDATION OF THE MANAGING GENERAL PARTNER
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 consideration to be received by each of the Partnerships
represents a premium over the standardized measure of discounted net cash flows
relating to each of the Partnership's proved reserves at December 31, 1994.
(b) The financial condition, results of operations and cash flows
of Benton and each of the Partnerships, both on a historical and a prospective
basis. In this regard, the Managing General Partner believes that Benton
historically, and on a pro forma basis after acquisition of the Partnerships'
assets, has been and is likely to continue in the future to be a strong company,
with prospects that could continue to show significant increases in results of
operations and cash flow.
(c) The consideration to be received by each of the Partnership's
Investors in connection with the Exchange Offer, and the distributions to the
Investors in liquidation, represents a significantly higher distribution to the
Investors than could be expected from continued total cash distributions.
Specifically, the Managing General Partner estimates that cash distributions for
the life of the respective Partnerships, if such Partnerships were to continue
operations, would be $358, $332 and $184 per Unit for the 1989-1 Partnership,
the 1990-1 Partnership and the 1991-1 Partnership, respectively.
(d) 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
62
<PAGE> 76
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.
(e) Distributions to the Investors now 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.
(f) 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.
(g) 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.
(h) 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. 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.
(i) The uncertainties and risks in the oil and gas industry and
the possibility that changes in the industry or continued volatility of oil and
gas prices could have a significantly greater effect on the Partnerships due to
the size of the Partnerships compared to Benton and the greater diversification
of oil
63
<PAGE> 77
and gas properties and prospects of Benton. The Managing General Partner also
considered the possibility that such uncertainties could be disadvantages to
Benton and advantages to the Partnerships.
(j) 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.
(k) The tax consequences to the Partners in connection with the
Exchange Offer and liquidation of the Partnerships.
(l) 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.
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.
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 ABOVE.
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 the values 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 and $30 in 1998. 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.
The Managing General Partner also believes that, while liquidating the
Partnerships 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
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<PAGE> 78
Partnerships. Benton's liquidation analysis reflects an estimated liquidation
value of approximately $324,663, $1,145,428 and $266,639 of the 1989-1
Partnership, the 1990-1 Partnership and the 1991-1 Partnership,
respectively, or $1,152, $807 and $946 per 1989-1 Unit, 1990-1 Unit and 1991-1
Unit, respectively. Benton received an independent offer to purchase each of
the Partnership's interest in the Umbrella Point Field (which represents 115.4%,
102.3% and 102.3% of the total Proved Reserves of the 1989-1 Partnership, the
1990-1 Partnership and the 1991-1 Partnership, respectively) for an
estimated total purchase price in cash of $1,672,512 as of March 31, 1995,
subject to adjustments. This estimated purchase price would represent potential
cash distributions to the Investors equal to $1,333, $762 and $764 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 March 31,
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.
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<PAGE> 79
1989-1 PARTNERSHIP
<TABLE>
<CAPTION>
TOTAL VALUE PER
VALUATION METHOD INVESTOR VALUE(1) 1989-1 UNIT
- ---------------- ----------------- -------------
<S> <C> <C>
Exchange Value................................................... $ 364,226 $ 1,292
Liquidation value estimated by Benton............................ 324,663 1,152
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
</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.
1990-1 PARTNERSHIP
<TABLE>
<CAPTION>
TOTAL VALUE PER
VALUATION METHOD INVESTOR VALUE(1) 1990-1 UNIT
- ---------------- ----------------- -------------
<S> <C> <C>
Exchange Value................................................... $ 2,553,119 $ 1,799
Liquidation value estimated by Benton............................ 1,145,428 807
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
</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 5.5 years.
1991-1 PARTNERSHIP
<TABLE>
<CAPTION>
TOTAL VALUE PER
VALUATION METHOD INVESTOR VALUE(1) 1991-1 UNIT
- ---------------- ---------------- -------------
<S> <C> <C>
Exchange Value.................................................. $ 591,623 $ 2,099
Liquidation value estimated by Benton........................... 266,639 946
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
</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 2.5 years.
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<PAGE> 80
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 $970 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 Partners' 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 Partners in the percentages set forth in
the 1989-1 Partnership Agreement. Based upon these assumptions, and further
discounted at 10%, the cash flow to the participants for the years indicated are
as follows:
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<PAGE> 81
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
Partners' 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
March 31, 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 $1,506 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.
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<PAGE> 82
The Managing General Partners' 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 Partners in the percentages set forth in
the 1990-1 Partnership Agreement. Based upon these assumptions, and further
discounted at 10%, the cash flow to the participants for the years indicated are
as follows:
1990-1 PARTNERSHIP
CONTINUATION ANALYSIS
<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
Partners' 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
March 31, 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 $1,932 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.
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<PAGE> 83
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 Partners' 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 Partners in the percentages set forth in
the 1991-1 Partnership Agreement. Based upon these assumptions, and further
discounted at 10%, the cash flow to the participants for the years indicated are
as follows:
1991-1 PARTNERSHIP
CONTINUATION ANALYSIS
<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
Partners' 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
March 31, 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 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
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<PAGE> 84
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 $324,663 or $1,152 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 (which represents 115.4% of the total Proved Reserves of
the 1989-1 Partnership) for a total purchase price in cash of $375,643. This
purchase price would represent cash distributions to the Investors, following
satisfaction of current liabilities, equal to $1,276 per 1989-1 Unit. Based on
these factors, Benton has concluded that, while an asset sale in liquidation of
the 1989-1 Partnership might result in limited third-party interest in the
1989-1 Partnership's most significant asset, and a sale of the Partnership's
properties as a whole would provide an immediate cash return to Investors, it
would likely result in valuations by an unaffiliated bidder below the Total
Exchange Value, and further, any cash received would likely be equal to or less
than the liquidation value after payment of transaction costs and costs
associated with liquidation and dissolution, if another third party was willing
to purchase only the assets of the 1989-1 Partnership. Benton has not
conditioned this Exchange Offer on approval by the other Partnerships described
herein, but believes that a third party would significantly discount the value
of the Partnership's properties if it could not purchase the working interests
owned by all three Partnerships. Additionally, Benton has assumed sale
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.
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<PAGE> 85
1989-1 PARTNERSHIP
LIQUIDATION ANALYSIS
<TABLE>
<S> <C>
Estimated Cash Proceeds from Sale of Umbrella Point Field............................. $375,643
Working Capital (Deficit)(1).......................................................... (15,980)
General and Administrative Expense(2)................................................. (35,000)
--------
Net Aggregate Liquidation Value.............................................. $324,663
========
Liquidation Value Per Unit(3)................................................ $ 1,152
========
</TABLE>
- --------------------------------
(1) At March 31, 1995, the 1989-1 Partnership had current assets,
less property held for sale of $9,953 and liabilities of
$25,933, resulting in a working capital deficit of $15,980,
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 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 $1,145,428 or $807 per 1990-1 Unit. It is further
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<PAGE> 86
supported by an independent offer to purchase the 1990-1 Partnership's
interest in the Umbrella Point Field (which represents 102.3% of the total
Proved Reserves of the 1990-1 Partnership) for an estimated total purchase
price in cash of $1,081,589. This purchase price would represent cash
distributions to the Investors equal to $762 per 1990-1 Unit. Based on these
factors, Benton has concluded that, while an asset sale in liquidation of the
1990-1 Partnership might result in limited third-party interest in the 1990-1
Partnership's most significant asset, a sale of the Partnership's properties
as a whole would provide an immediate cash return to Investors but would likely
result in valuations by an unaffiliated bidder below the total Exchange Value,
and further, any cash received would likely be equal to or less than the
liquidation value after payment of transaction costs and costs associated with
liquidation and dissolution. Benton has not conditioned this Exchange Offer on
approval by the other Partnerships described herein, but believes that a third
party would significantly discount the value of the Partnership's properties if
it could not purchase the working interests owned by all three Partnerships.
Additionally, Benton has assumed sale 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.
73
<PAGE> 87
1990-1 PARTNERSHIP
LIQUIDATION ANALYSIS
<TABLE>
<S> <C>
Estimated Cash Proceeds from Sale of Umbrella Point Field............................ $1,081,589
Working Capital(1)................................................................... 143,839
General and Administrative Expense(2)................................................ (80,000)
----------
Net Aggregate Liquidation Value............................................. $1,145,428
==========
Liquidation Value Per Unit(3)............................................... $ 807
==========
</TABLE>
- --------------------------------
(1) At March 31, 1995, the 1990-1 Partnership had current assets,
less property held for sale, of $143,839 and liabilities of
$0, resulting in a working capital balance of $143,839,
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.
Material changes in 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 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
74
<PAGE> 88
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 $266,639 or $946 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 (which represents 102.3% of the total Proved Reserves of the 1991-1
Partnership) for a total purchase price in cash of $215,280. This purchase price
would represent cash distributions to the Investors equal to $764 per 1991-1
Unit. Based on these factors, Benton has concluded that, while an assets sale in
liquidation of the 1991-1 Partnership might result in limited third-party
interest in the 1991-1 Partnership's most significant asset, a sale of the
Partnership's properties as a whole would provide an immediate cash return to
Investors but would likely result in valuations by an unaffiliated bidder below
the total Exchange Value, and further, any cash received would likely be equal
to or less than the liquidation value after payment of transaction costs and
costs associated with liquidation and dissolution. Benton has not conditioned
this Exchange Offer on approval by the other Partnerships described herein, but
believes that a third party would significantly discount the value of the
Partnership's properties if it could not purchase the working interests owned by
all three Partnerships. Additionally, Benton has assumed sole responsibility for
payment of all transaction costs associated with the Exchange Offer, allowing
distribution of consideration without deduction for such costs. Benton believes
it unlikely that a third party would offer to purchase the Partnership's assets,
and also assume responsibility for payment of transaction costs.
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<PAGE> 89
1991-1 PARTNERSHIP
LIQUIDATION ANALYSIS
<TABLE>
<S> <C>
Estimated Cash Proceeds from Sale of Umbrella Point Field............................ $215,280
Working Capital(1)................................................................... 81,359
General and Administrative Expense(2)................................................ (30,000)
--------
Net Aggregate Liquidation Value............................................. $266,639
========
Liquidation Value Per Unit(3)............................................... $ 946
========
</TABLE>
- --------------------------------
(1) At March 31, 1995, the 1991-1 Partnership had current assets,
less property held for sale, of $81,359 and liabilities of $0
resulting in a working capital balance of $81,359, 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
provide fees to a third party to negotiate the terms of the Exchange. As a
result, the Exchange
76
<PAGE> 90
Values and other term of the Exchange Offer may not be as favorable as the terms
that an independent representative might have obtained.
BOARD OF DIRECTORS OF BENTON; BENTON'S REASONS FOR THE EXCHANGE
At a meeting held on April 26, 1995, the Board of Directors of Benton
unanimously approved the Exchange Offer and the issuance of Benton Common Stock
and Warrants in connection with the Exchange. The Delaware Corporation Law does
not require that the Benton stockholders approve the Exchange Offer or the
issuance of Benton Common Stock or Warrants, and no such approval is being
sought.
In reaching its conclusion to approve the Exchange Offer, the Board of
Directors of Benton determined that the purchase of the Partnership assets by
Benton is consistent with and in furtherance of the long-term business
strategy of Benton. In addition, the Board believes that the Exchange Offer
provides the Investors in the Partnerships, many of whom are Benton
stockholders, the opportunity to benefit from the continued growth of Benton and
consideration in excess of the liquidation value of each of the Partnerships.
The Board understands the significant risks associated with the oil and gas
industry and drilling for oil and natural gas, but acknowledges the concerns
raised by the Investors in the Partnerships with regard to the disappointing
returns on investment by the Investors. Because many of the Investors are also
stockholders of Benton, the Board believes it prudent to maintain a good
relationship with these stockholders, who have been strong supporters of Benton
from inception, and the consideration to be given under the Exchange Offer is
indicative of Benton's desire to address the concerns of its Investors and
stockholders. The Board of Directors believes that the Exchange Offer may serve
to resolve the issues and claims made by certain Investors in the Litigation and
may forestall any further litigation surrounding or arising from the
Partnerships. In addition, the Board believes that dissolution of the
Partnerships upon consummation of the Exchange and adoption of the Proposals by
each of the Partnerships will allow Benton to focus its resources on the core
assets and projects of Benton.
FIDUCIARY DUTIES OF BENTON
General. Benton's fiduciary duties to the Investors include legal
responsibilities of loyalty, care and good faith. As Managing General Partner of
the Partnerships, Benton may not profit by any conduct or transaction in
contravention of its fiduciary obligations to the Investors. Rights of action by
or on behalf of the Investors for any breach of these duties are provided under
most state limited partnership or other laws. Under California law, which is the
choice of law provided in the Partnership Agreements, a limited partner may
bring action against a general partner, upon a showing of the breach of its
fiduciary duty, to recover his capital contribution or to seek an accounting and
dissolution of the partnership. While a general partner would have the burden of
dispelling all doubts concerning its conduct, simple negligence or an error in
judgment not amounting to a breach of fiduciary duty would constitute a defense
to the limited partner's actions under California law. Benton believes that it
has complied with its fiduciary duties in the management of each of the
Partnerships and in connection with the Exchange Offer.
Remedies for Breach of Fiduciary Duties. Under California law, except
as described below, if a non-consenting Investor believes that adoption of the
Proposal or consummation of the Exchange would constitute a breach of the
General Partner's fiduciary duties, the Investor could institute legal action
against the General Partner to enjoin the Exchange or implementation of the
Amendments contemplated by the Proposal or to recover damages resulting from the
consummation of the Exchange. In appropriate
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<PAGE> 91
circumstances, a limited partner may institute a class action against its
general partner on behalf of himself and the other similarly situated limited
partners or a derivative action against a general partner on behalf of the
partnership to recover damages for a breach of a general partner's fiduciary
duties. This is a developing area of the law, and Investors who have questions
concerning the General Partner's duties should consult with their own legal
counsel.
Limitations on Investors' Remedies. The Partnership Agreements provide
that the General Partner and its affiliates will not be liable to the
Partnership or the Investors for errors of judgment or any acts or omissions
that do not constitute negligence or misconduct. In addition, the Partnership
Agreements provide generally that, to the extent permitted by law, the
Partnership will indemnify the General Partner and its affiliates providing
services on behalf of the Partnerships against judgments and amounts paid in
settlement, plus costs and expenses (including reasonable attorneys' fees and
expenses) actually and reasonably incurred, if the indemnitee acted in good
faith and in a manner reasonably believed to be in, or not opposed to, the best
interests of the Partnership. In the opinion of the SEC, indemnification for
liabilities arising under the Securities Act is against public policy and
therefore unenforceable.
ACCESS TO INVESTOR LIST AND PROGRAM RECORDS.
Benton will provide free of charge to any Investor, upon written
request, a current alphabetized listing of all Investors' names and addresses of
the Investors in a Partnership in which the requesting Investor owns a
Partnership Unit. Investors are afforded this right under the Partnership
Agreement and federal and state law. Investors also have the right under the
Partnership Agreement to inspect the books and records of his Partnership at all
reasonable times.
FAILURE TO APPROVE THE PROPOSALS
In the event that the Investors of any of the Partnerships fail to
approve the Proposal, as set forth in this Prospectus, the Exchange of
Partnership Units tendered pursuant to the Exchange offer will not be
consummated and the assets of that Partnership will not be transferred to
Benton. However, the assets of any Partnership whose Investors do approve the
Proposal and accept the Exchange will be transferred to Benton. In the event the
Investors of a Partnership fail to approve the Proposal, that Partnership would
continue in its business as heretofore operated. However, it is possible that a
new offer might be negotiated between such Partnership and Benton. No such other
terms have been discussed or agreed upon. In addition, the Managing General
Partner may also explore other alternatives, such as the sale of that
Partnership's assets to a third party. However, there is no assurance that the
Managing General Partner could find a third party interested in purchasing such
assets or that the terms and conditions of such a purchase and sale agreement
would be as favorable as the terms offered pursuant to the Exchange Offer.
Pursuant to the terms of the purchase agreements with Goldking, the
seller or purchaser may terminate the agreement if the closing has not occurred
on or before December 31, 1995. If the Partnerships do not approve the
Proposals, there can be no assurance that a sale of the Partnerships' assets for
cash pursuant to the Goldking Agreement can be accomplished prior to such
termination date.
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<PAGE> 92
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.
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<PAGE> 93
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 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 $70,179), as evidenced by the appearance of its name on the
Letter of Transmittal in the space provided for that purpose. Total fee and
expense reimbursements to the Solicitating Dealers will not exceed 2% of the
Total Exchange Value.
Benton has agreed to indemnity Solicitating Dealers against certain
civil liabilities, including liabilities under the Securities Act. The
Solicitating Dealers may be deemed to be underwriters within the meaning of the
Securities Act.
Holders of Units in the Partnerships who elect to accept the Exchange
Offer may elect to receive cash in lieu of shares of Common Stock to be issued,
BUT CASH WILL BE DISTRIBUTED TO HOLDERS MAKING SUCH ELECTION ONLY IF THE SALE OF
THE UMBRELLA POINT FIELD TO GOLDKING, AS DESCRIBED HEREIN, IS ACTUALLY
CONSUMMATED. A holder who wishes to accept the Exchange Offer and make an
election to receive cash in lieu of shares of Common Stock should properly
indicate such election on the Letter of Transmittal. If the sale of the Umbrella
Point Field working interests to Goldking in consummated, a holder who elects to
receive cash in lieu of Common Stock will receive $1,292 for each 1989-1 Unit,
$957 for each 1990-1 Unit and $1,146 for each 1991-1 Unit, with Warrants in the
amounts described herein. There can be no assurance from Benton that the sale of
the Umbrella Point Field to Goldking will be consummated, and therefore, an
Investor should make a decision to accept the Exchange Offer based solely upon a
decision to receive Common Stock and Warrants in the amounts set forth herein.
ACCEPTANCE OF TENDERS
On the Closing Date, subject to the satisfaction or waiver of the
conditions to the Exchange Offer, Benton will accept all Partnership Units
properly tendered pursuant to the Exchange Offer. If the Partnerships accept the
Proposals, Benton will, on behalf of the approving Partnerships, cause the
assets of such Partnerships, subject to associated liabilities, to be withdrawn
from the Partnership and contributed to Benton, effective as of the Effective
Date, in exchange for the Common Stock and Warrants which will be issued and
delivered promptly after the Closing Date.
On the Closing Date, Benton will cause certificates representing the
Common Stock and the Warrants issuable in the Exchange to be registered in the
name of the holders who have accepted the Exchange Offer. Benton will also cause
a certificate representing the shares of Common Stock and Warrants that will be
issued to participants upon liquidation of each of the Partnerships to be issued
in the name of the Partnership, pending dissolution, liquidation and winding-up
of the Partnerships. Immediately thereafter, Benton will cause the shares of
Common Stock and Warrants issued in the name of the Partnership to be
transferred into certificates representing Common Stock and Warrants, registered
in the names of the individual participants remaining in the Partnerships
following liquidation.
SPECIAL REQUIREMENTS FOR CERTAIN INVESTORS
Some of the Investors are entities such as estates, trusts,
corporations, limited partnerships or general partnerships. With respect to a
Partnership Unit tendered by an Investor other than an individual,
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<PAGE> 94
Benton may elect, at its option, to require that each Letter of Transmittal be
accompanied by evidence that the Investor has met all requirements of its
governing instruments, such as applicable partnership or joint venture
agreements, and is authorized to tender its Partnership Units under the laws of
the jurisdiction in which the entity was organized. With respect to most trusts,
including individual retirement accounts, Benton expects to require only that
the named trustee (or authorized representative thereof) execute the Letter of
Transmittal.
REPRESENTATIONS AND COVENANTS
Each Investor represents in the Letter of Transmittal that he has, and
will have as of the Closing Date, the right and authority to transfer his
Partnership Unit, and that his Partnership Unit is free and clear of all liens,
encumbrances and adverse claims. The Letter of Transmittal also contains a
covenant by the Investor to execute any additional documents and instruments
that may be reasonably required to more effectively transfer to and to vest in
Benton the assets underlying the tendered Partnership Units and a power of
attorney to Benton to permit Benton, as Managing General Partner, to execute on
his behalf any additional documents necessary to consummate the Exchange,
including any documents on behalf of the Investors that may be necessary to
withdraw the assets of the Partnership and contribute those assets to Benton.
VALIDITY OF TENDERS
All questions concerning the validity, form, eligibility (including
time of receipt) and acceptance of the Partnership Units tendered will be
determined by Benton, whose determination will be final and binding. The
interpretation by Benton of the terms and conditions of the Exchange Offer
(including the instructions to the Letter of Transmittal) will also be final and
binding. Benton reserves the right to waive any irregularities or conditions
regarding the manner of tender. Any irregularities in connection with such
tenders must be cured within such time as Benton determines unless waived by
Benton.
Tenders will be deemed not to have been made until irregularities have
been cured or waived. Any Letter of Transmittal not properly completed and
executed will be returned by Benton to the tendering Investor as soon as
practicable unless the irregularities are cured or waived. Benton is under no
duty to give notification of defects in tenders, and will not incur liability
for failure to give such notification. Delivery of the Transmittal Letter is at
the risk of the Investor. A tender will be effective only when the Letter of
Transmittal is actually received by Benton. To ensure receipt of the Letter of
Transmittal and all other required documents, if any, when sent by the U.S.
Mail, Investors should use certified or registered mail, return receipt
requested.
PAYMENTS OF FEES AND EXPENSES
Fees and expenses incurred in connection with the Exchange Offer will
be paid by Benton, whether or not the Proposals are accepted. Fees and expenses
incident to the Exchange Offer are estimated to be approximately $545,000, all
of which will be funded from Benton's working capital. The estimated fees and
expenses for the Exchange Offer are itemized below.
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<PAGE> 95
<TABLE>
<S> <C>
SEC registration fee............................... $ 2,491
NASD filing fee.................................... 1,223
NASDAQ-NMS listing fees............................ 5,000
Soliciting Agent fees.............................. 70,000
Legal fees and expenses............................ 200,000
Blue sky expenses.................................. 5,000
Printing costs..................................... 175,000
Engineering fees................................... 10,000
Accounting fees.................................... 50,000
Miscellaneous...................................... 26,286
--------
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> 96
CERTAIN FEDERAL TAX CONSEQUENCES
The following tax discussion summarizes certain federal income tax
consequences of the Exchange. This summary reflects the advice of Emens, Kegler,
Brown, Hill & Ritter Co., L.P.A., counsel to Benton in connection with the
Exchange. 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.
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.
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.
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<PAGE> 97
REALIZATION OF SUSPENDED PASSIVE LOSSES
Upon disposition of the Partnership Units, the Investors will have
completely disposed of their Interest in the Partnerships. Any Investor who has
any suspended passive losses resulting from the ownership of Partnership Units
will realize those suspended passive losses upon consummation of the Exchange.
BASIS IN STOCK AND WARRANTS
Upon consummation of the Exchange, the basis of the Investors in the
Common Stock and Warrants received by them shall be equal to the fair market
value of such securities as of the date of consummation of the Exchange.
THE PRECEDING DISCUSSION IS INTENDED ONLY AS A SUMMARY OF CERTAIN
FEDERAL INCOME TAX CONSEQUENCES OF THE EXCHANGE AND DOES NOT PURPORT TO BE A
COMPLETE ANALYSIS OR DISCUSSION OF ALL POTENTIAL TAX EFFECTS RELEVANT THERETO.
THUS, INVESTORS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS AS TO THE SPECIFIC
TAX CONSEQUENCES TO THEM OF THE EXCHANGE, INCLUDING TAX RETURN REPORTING
REQUIREMENTS, THE APPLICABILITY AND EFFECT OF FEDERAL, STATE, LOCAL AND OTHER
APPLICABLE TAX LAWS AND THE EFFECT OF ANY PROPOSED CHANGES IN THE TAX LAWS.
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<PAGE> 98
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
Distributions and Dividends
<S> <C>
Each of the Partnership Agreements provides Although holders of Common Stock are entitled
for cash distributions in the discretion of to receive any dividends declared thereon by
the Managing General Partner in an amount Benton's Board of Directors out of legally
equal to approximately the difference between available funds, no dividends are expected to
revenues allocated to the respective partners be paid on the Common Stock for the
and costs charged to the partners. The foreseeable future. Under Delaware law,
Partnership Agreement states that the dividends may be paid out of the Company's
provisions do not serve as a limitation on the surplus or out of its net profits for the
right of the Managing General Partner to fiscal year in which the dividend is declared
retain, pledge or use so much of the revenues and/or the preceding fiscal year. In
or other assets of the Partnerships to conduct addition, the Company's credit agreements
additional operations, establish reserves for restrict the Company's ability to pay cash
anticipated expenditures or repay any amounts dividends
borrowed by the Partnerships to finance the
conduct of such operations.
Tax Matters
None of the Partnerships are subject to The Company is subject to federal income tax
federal or state income taxes. Each partner is on its consolidated income after allowable
allocated his pro rata share of the deductions and credits. Stockholders will not
Partnership's taxable income. be taxed on the Company's income but will
generally be subject to federal and state
income taxes on dividends received from the
Company.
</TABLE>
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<PAGE> 99
<TABLE>
<CAPTION>
Voting Rights
<S> <C>
Holders of Units in the Partnerships are Stockholders of Benton are entitled to one
entitled to one vote per Unit on matters vote per share on all matters submitted to
submitted to them for a vote, on any sale of them for a vote, including the election and
all or substantially all of the assets, removal of directors, amendments to the
dissolution of the Partnership and removal of Certificate of Incorporation, certain mergers
the Managing General Partner. Each of these and share exchanges, dissolution and the sale
matters requires the consent of a majority of of all or substantially all of the assets of
the outstanding Units. the Company. These matters require the
approval of a majority of the outstanding
Common Stock. Accordingly, the holders of
Units will not receive a security with
significantly different voting rights, other
than eliminating the right to compel
dissolution and adding the right to
participate in annual elections of directors.
However, former holders of Units will own a
smaller percentage interest in the Company
than they currently own in the respective
Partnerships, resulting in a corresponding
decrease in their voting power.
Right to Call Meetings
Meetings of the participants of the Special meetings of the Company's
Partnerships may be called by the Managing stockholders may be called by the President,
General Partner or by holders of at least 10% Board of Directors or by holders of not less
of the outstanding Units. Actions requiring a than 10% of the Common Stock. Actions
vote of the holders of Units may be taken requiring a vote may be taken without a
without a meeting upon written consent by the meeting upon written consent by the same
same percentage of Unitholders required to percentage of stockholders required to
approve the action at a meeting. approve the action at a meeting.
Right to Investor List
Under California law, a holder of Units has The Company is required to maintain a
the right to examine or copy a listing of the list of the names and addresses of all
names and addresses and record ownership stockholders at its principal office during
positions of the holders of Units. normal hours for any proper purpose and,
in certain circumstances, to provide a copy
of the list to any stockholder upon request.
</TABLE>
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<PAGE> 100
<TABLE>
<CAPTION>
Assessments and Limited Liability
<S> <C>
Under the terms of the Partnership Agreements, The Company's stockholders will not be
Unitholders are not subject to additional subject to assessments or to personal
assessments. The liability of the Unitholders liability for obligations of the Company.
is generally limited to their capital
contributions and, in certain circumstances,
the amount of any capital distributed or
returned to them.
Allocations and Dilution
Under the terms of the Partnership Agreements, The Company's Certificate of Incorporation
the participants pay 99% of the lease authorizes the issuance of up to 40,000,000
acquisition, geophysical and seismic costs, shares of Common Stock and 5,000,000 shares
well costs, general and administrative of Preferred Stock, including shares that may
expenses and organization and offering be divided into one or more additional series
expenses, including commissions, while the with rights and preferences to be determined
co-managing general partners pay 1% of such by the Company's Board of Directors without
costs. any stockholder action. An investor's
percentage interest in the Company is subject
to dilution upon issuance of additional
securities by the Company.
Under the terms of the 1989-1 Partnership
securities by the Company. Agreement, Revenues,
production taxes and lease operating expenses on
proven producing wells are allocated 99% to the
participants and 1% to the co-managing general
partners. Revenues, production taxes and lease
operating expenses on recompleted wells are
allocated 74.25% to the participants and 25.75%
to the co-managing general partners. On new
wells drilled, revenues, production taxes and
lease operating expenses are allocated 64.35% to
the participants and 35.65% to the co-managing
general partners.
Under the terms of the 1990-1 Partnership
Agreement, general and administrative expenses
and lease operating expenses are shared 74.25%
by the participants and 25.75% by the
co-managing general partners. Revenues and
production taxes are allocated
</TABLE>
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<PAGE> 101
<TABLE>
<S> <C>
73.5974% to the participants, 25.5236% to the
co-managing general partners, and .879% to
broker/dealers (special limited partners) who
met certain minimum sales requirements in the
initial offering in the 1990-1 Units.
Under the terms of the 1991-1 Partnership
Agreement, for the first 12 months of the
Partnership, general and administrative expenses
were covered by a fee, equal to 3% of the
initial capital raised, paid by the 1991-1
Partnership to Benton. The fee was payable 99%
by the participants and 1% by the co-managing
general partners. General and administrative
expenses after the first 12 months and lease
operating expenses are shared 74.25% by the
participants and 25.75% by the co-managing
general partners. Revenues and production taxes
are allocated 73.944% to the participants,
25.6438% to the co-managing general partners and
.4122% to broker/dealers (special limited
partners) who met certain minimum sales
requirements in the initial offering of the
1991-1 Units. Allocations outlined above are
made to Unitholders in proportion to the number
of Units owned.
Liquidity
There is no trading market for the Units. The Company's Common Stock is traded on the
NASDAQ - NMS and the shares issued pursuant
to this Exchange Offer will be freely
tradable by non-affiliates of the Company.
There is no trading market for the Warrants.
Redemption and Conversion
The Units are not redeemable or convertible The Common Stock is not redeemable or
into other securities. convertible. The Warrants can be exercised
for Common Stock upon payment of the exercise
price ($12.37 per share) prior to expiration
of the
</TABLE>
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<PAGE> 102
<TABLE>
<S> <C>
Warrant.
Financial Reporting
The Unitholders are entitled to receive The Company is subject to the reporting
audited annual financial statements and requirements of the Exchange Act and files
reserve reports for the Partnerships. periodic reports as well as proxy statements
with the SEC, copies of which are provided to
its stockholders.
Operating Strategy
The Partnerships were formed to invest in oil Benton is primarily engaged in the
and natural gas activities by acquiring proven development and production of oil and gas
producing properties that have additional properties. Benton's operations are focused
development potential, recompleting previously on the Eastern Region of Venezuela, the Gulf
drilled wells and drilling new wells. The Coast Region of Louisiana and the West
Partnerships' properties are all located in a Siberia Region of Russia. Benton's business
small number of fields within the United strategy is to seek new reserves in areas of
States. Although each of the Partnership low geologic risk and to exploit
Agreements permits the Managing General underdeveloped existing oil and gas fields.
Partners to borrow money on behalf of such Benton implements the exploitation strategy
Partnership, Benton's policy as Managing through the in-house design and
General Partner has been to refrain from interpretation of 3-D seismic surveys and
financing oil and gas activities through through workovers, recompletions, redrilling
credit. and exploration and development drilling.
Benton has, and will continue to, finance a
portion of its oil and gas activities through
issuance of debt instruments or under credit
arrangements.
Management and Compensation
Benton and a wholly owned subsidiary, Benton The stockholders of Benton Oil and Gas
Oil and Gas Company of Louisiana, are the Company elect directors annually and the
Co-Managing General Partners of each of the directors elect officers of the Company to
Partnerships. Benton makes all decisions serve at the discretion of the Board.
regarding the business and operations of the Officer salaries and incentive compensation
Partnerships, including production, are determined annually by the Board of
development and other activities, and any sale Directors and/or the President of Benton.
of properties and the acquisition of
additional properties. The Co-Managing
General Partners do not receive any management
fees or other fees from any of the
Partnerships. The Partnerships pay the
Co-Managing
</TABLE>
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<PAGE> 103
<TABLE>
<S> <C>
General Partners for lease operating expenses,
well costs and general and administrative
expenses incurred on behalf of the Partnerships.
Fiduciary Duties
The Co-Managing General Partners fiduciary The fiduciary duties owed by the directors of
duties to the Unitholders include legal its stockholders under the Delaware General
responsibilities of loyalty, care and good Corporation law and remedies available for a
faith. Benton may not profit from drilling in breach of those responsibilities are similar
contravention of its fiduciary obligation to to those applicable to the Partnerships and
the Partners. 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, as
Managing General Partner, should remove most
of the conflicts of interest inherent in the
current structure.
Limits on Management's Liability
The Partnership Agreements provide that in any Benton's Certificate of Incorporation and
threatened, pending or completed action, suit Bylaws provide for the elimination of
or proceeding to which the Co-Managing General directors' liability from monetary damages
Partners were or are a party or is threatened arising from a breach of certain fiduciary
to be made a party by reason of the fact that obligations and for the indemnification of
they were or are a Co-Managing General Partner directors, officers and agents to the full
of the Partnership involving any alleged cause extent permitted by the Delaware General
of action for damages arising from the Corporation Law. These provisions generally
performance of oil and gas activities, provide for indemnification in the absence of
including exploration, development, gross negligence or willful misconduct and
completion, operation, or other activities cannot be amended without the affirmative
relative to management and disposition of oil vote of a majority of the outstanding shares
and gas properties or production from such of Common Stock.
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
</TABLE>
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<PAGE> 104
<TABLE>
<S> <C>
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 shown of the liabilities and
obligations of the Partnership, and any
Unitholder who incurs liability in excess of his
pro rata share shall be entitled to contribution
from the other Unitholders each Co-Managing
General Partner agrees to indemnify each
Unitholder from paying any liabilities or
obligations of the Partnership in excess of such
Unitholders capital contribution.
Continuation of Existence
The Partnership Agreement for the 1989-1 The Company has a perpetual term, subject to
Partnership, the 1990-1 Partnership and the dissolution upon the occurrence of specified
1991-1 Partnership provides for a term ending events.
on December 31, 2039, December 31, 2039 and
December 31, 2040, respectively, or until an
earlier dissolution upon specified events, but
contemplates continuing operations in
accordance with its objectives.
Anti-Takeover Provisions
There are no anti-takeover provisions in the Benton is subject to the anti-takeover
Partnership Agreements or under California protections of the Delaware General
Partnership law. Corporation Law, which prohibit business
combinations with interested stockholders
under certain circumstances. In addition,
Benton has adopted a shareholder rights plan,
or poison pill, which could have the effect if
delaying or impeding an unfriendly takeover of
the Company.
</TABLE>
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<PAGE> 105
<TABLE>
<CAPTION>
Liquidation Rights
<S> <C>
In the event of liquidation, the partners are In the event of liquidation, holders of
entitled to a distribution in proportion to Common Stock would be entitled to share
their positive capital account balances after ratably in any assets of the Company
the creditors, including Partners, who are remaining after satisfaction of obligations
creditors (to the extent permitted by law), to its creditors and liquidation preferences
have been paid. If the liabilities of the on any series of Preferred Stock of the
partnership exceed the assets upon Company then outstanding. The Company
liquidation, or otherwise if any General currently has no shares of Preferred Stock
Partner then has a negative balance in its outstanding and has no plans to issue any
capital account, the General Partners must shares of Preferred Stock in the foreseeable
contribute funds to the Partnership in the future.
ratio of their negative capital accounts until
the negative capital accounts are eliminated.
Right to Compel Dissolution
The Partnership may be dissolved by the Under Delaware law, stockholders of the
written vote or consent by Participants Company may not vote to compel dissolution of
representing a majority of the outstanding the Company without prior action by its Board
units. of Directors.
</TABLE>
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<PAGE> 106
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 March 31, 1995 is prepared
assuming the acquisition of the Partnerships and the sale of the Partnerships'
interest in Umbrella Point field occurred on March 31, 1995. The pro forma
statements of operations and cash flows for the year ended December 31, 1994 and
the three months ended March 31, 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 noes thereto included elsewhere in the Proxy
Statement/Prospectus.
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<PAGE> 107
PRO FORMA CONSOLIDATED BALANCE SHEET
MARCH 31, 1995
<TABLE>
<CAPTION>
Consolidated
Benton Oil Minimum Pro Remaining
and Gas Forma Minimum Pro Forma Maximum
Company Adjustments Notes Pro Forma Adjustments Notes Pro Forma
---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
ASSETS:
Current Assets:
Cash and cash equivalents $ 21,208,775 ($265,821) (a), (g), (i) $ 20,942,954 $1,524,201 (d), (i) $ 22,467,155
Restricted Cash 19,550,000 19,550,000 19,550,000
Accounts receivable:
Accrued oil and gas
revenue 11,633,485 11,633,485 11,633,485
Joint interest and other 2,188,769 2,188,769 2,188,769
Prepaid expense & other 1,140,632 1,140,632 1,140,632
------------ --------- ----------- --------- ------------
Total Current Assets 55,721,661 (265,821) 55,455,840 1,524,201 56,980,041
Other Assets 1,431,512 1,431,512 1,431,512
Property and Equipment,
net 109,372,034 24,208 (a), (b) 109,396,242 129,910 (d), (e) 109,526,152
------------ --------- ------------ ---------- ------------
Total Assets $166,525,207 ($241,613) $166,283,594 $1,654,111 $167,937,705
============ ========== ============ ========== ============
LIABILITIES:
Current Liabilities:
Accounts Payable
Revenue distribution $ 658,823 $ 658,823 $ 658,823
Trade and other 11,429,594 (17,460) (a) 11,412,134 (60,890) (d) 11,351,244
Accrued interest payable,
payroll and related
taxes 808,100 808,100 808,100
Income taxes payable 788,068 788,068 788,068
Short term borrowings 23,561,868 23,561,868 23,561,868
Current portion or long
term debt 4,996,053 4,996,053 4,996,053
------------- ------- ------------ ------- ------------
Total Current 42,242,506 (17,460) 42,225,046 (60,890) 42,164,156
Liabilities
Long Term Debt 31,187,571 31,187,571 31,187,571
Minority Interest 2,606,335 2,606,335 2,606,335
STOCKHOLDERS' EQUITY:
Common stock 249,319 259 (c) 249,578 1,386 (f) 250,964
Additional paid-in-capital 93,109,684 44,161 (c),(g) 93,153,845 2,908,575 (f) 96,062,420
Accumulated Deficit (2,870,208) (268,573) (h) (3,138,781) (1,194,960) (h) (4,333,741)
------------- -------- ------------- ---------- ------------
Total Stockholders' 90,488,795 (224,153) 90,264,642 1,715,001 91,979,643
Equity
------------ -------- ------------ --------- ------------
Total Liabilities and
Stockholders' Equity $166,525,207 ($241,613) $166,283,594 $1,654,111 $167,937,705
============ ========= ============ ========== ============
Book value per share $3.63 $3.62 $3.67
============ ============ ============
Common shares outstanding 24,931,862 24,957,789 25,096,375
============ ============ ============
</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 25,927 shares and 79,472 warrants to the
participants in the acquisition of the 1991-1 Partnership at
the July 17, 1995 market value of $12.375 per share and $3.38
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 138,586 shares and 353,378 warrants to the
participants in the acquisition of the 1989-1 Partnership and
the 1990-1 Partnership at the July 17, 1995 market value of
$12.375 per share and $3.38 per warrant.
(g) Record payment of stock issuance fees and distribution
expenses.
(h) Record roll-up expenses associated with acquiring the
Partnership units.
(i) Record the cash proceeds from the sale of the Partnerships'
interest in Umbrella Point Field.
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<PAGE> 108
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 the participants accept cash rather than shares,
cash would be reduced to $20,619,904 and $20,421,720 for the minimum and maximum
pro forma balance sheets, respectively. Common shares outstanding would be
reduced to 24,931,862, common stock would be reduced to $249,319 and additional
paid in capital would be reduced to $92,833,257 and $94,028,217 in the minimum
and maximum pro forma balance sheets, respectively.
95
<PAGE> 109
PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 1995
<TABLE>
<CAPTION>
Consolidated
Benton Oil Minimum Pro Remaining
and Gas Forma Minimum Pro Forma Maximum
Company Adjustments Notes Pro Forma Adjustments Notes Pro Forma
----------------------------------------------------------------------------------------------------
REVENUES:
<S> <C> <C> <C> <C> <C> <C> <C>
Oil and gas sales $12,080,479 $13,418 (a) $12,093,897 $97,168 (b) $12,191,065
Gain on exchange rates 131,717 131,717 131,717
Investment earnings 424,234 286 (a) 424,520 145 (b) 424,665
Partnership fees,
reimbursements and other 24,736 (3,469) (c) 21,267 (18,215) (c) 3,052
----------- ------- ----------- ------- -----------
12,661,166 10,235 12,671,401 79,098 12,750,499
----------- ------- ----------- ------- -----------
EXPENSES:
Lease operating costs and
production taxes 2,246,002 5,075 (a) 2,251,077 51,235 (b) 2,302,312
Depletion, depreciation,
and amortization 3,145,067 9,352 (d) 3,154,419 69,179 (d) 3,223,598
General and administrative 1,668,772 7,373 (a), (c) 1,676,145 27,018 (b), (c) 1,703,163
Interest 1,618,126 1,618,126 1,618,126
Minority Interest in net
income 862,675 862,675 862,675
----------- ------- ----------- ------- -----------
9,540,642 21,800 9,562,442 147,432 9,709,874
Income before income taxes
and roll-up expenses and
payments 3,120,524 (11,565) 3,108,959 (68,334) 3,040,625
Income taxes 1,079,416 1,079,416 1,079,416
----------- ------- ----------- ------- -----------
Income before roll-up
expenses and payments 2,041,108 (11,565) 2,029,543 (68,334) 1,961,209
Roll-up expenses and
payments
----------- ------- ----------- -------- -----------
Income (loss) after
roll-up expenses $ 2,041,108 ($11,565) $ 2,029,543 ($68,334) $ 1,961,209
=========== ======== =========== ======== ===========
Income per common share:
Before roll-up expenses
and payments $0.08 $0.08 $0.07
----- ----- -----
After roll-up expenses
and payments $0.08 $0.08 $0.07
----- ----- -----
Weighted average common
shares outstanding 26,037,055 26,062,982 26,201,568
----------- ----------- -----------
Ratio of earnings to fixed
charges:
Before roll-up expenses
and payments 2.90x 2.90x 2.86x
After roll-up expenses ---- ---- ----
and payments 2.90x 2.90x 2.86x
---- ---- ----
</TABLE>
Notes: (a) Record the participants' share of the 1991-1 Partnership.
(b) Record the participants' share of the 1989-1 Partnership and
1990-1 Partnership.
(c) Eliminate allocated overhead costs from partnerships.
(d) Record depletion on oil and gas properties acquired from
partnerships.
The participants are given the option of accepting either cash or shares of the
Company's common stock in exchange for their partnership units. The pro-forma
statements of operations above assume that the participants accept stock in
exchange for their partnership units. If the participants accept cash rather
than shares, the weighted average number of shares would be 26,037,055 for both
the minimum and maximum pro-forma statements of operations.
96
<PAGE> 110
PRO FORMA CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE MONTHS ENDED MARCH 31, 1995
<TABLE>
<CAPTION>
Consolidated
Benton Oil Minimum Pro Remaining
and Gas Forma Minimum Pro Forma Maximum
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) $ 2,041,108 ($ 11,565) (a) $ 2,029,543 ($68,334) (b) $ 1,961,209
Adjustments to reconcile net income
(loss) to net cash provided by
(used in) operating activities
Depletion, depreciation and 3,145,067 9,352 (a) 3,154,419 69,179 (b) 3,223,598
amortization:
Compensation expense attributed to
stock options
Net earnings from limited partnerships (3,511) (731) (c) (4,242) 4,242 (c) 0
Amortization of financing costs 28,578 28,578 28,578
Loss on disposal of assets 10,632 10,632 10,632
Minority interest in undistributed
earnings of subsidiary 862,675 862,675 862,675
(Increase) decrease in accounts
receivable (583,664) (583,664) (583,664)
(Increase) decrease in prepaid
expenses and other (576,793) (576,793) (576,793)
Increase in accounts payable 67,530 19,637 (a) 87,167 120,610 (b) 207,777
Increase (decrease) in accrued
interest payable, payroll and
related taxes (390,996) (390,996) (390,996)
Increase in income taxes payable 788,068 788,068 788,068
----------- --------- ----------- ---------- -----------
TOTAL ADJUSTMENTS 3,347,586 28,258 3,375,844 194,031 3,569,875
----------- --------- ----------- ---------- -----------
NET CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES 5,388,694 16,693 5,405,387 125,697 5,531,084
----------- --------- ----------- ---------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of property and
equipment 14,713,894 215,280 (a),(d) 14,929,174 1,457,232 (b),(d) 16,386,406
Additions of property and equipment (11,130,286) (12,964) (a) (11,143,250) (82,988) (b) (11,226,238)
----------- --------- ----------- ---------- -----------
NET CASH PROVIDED BY (USED IN)
INVESTING ACTIVITIES 3,583,608 202,316 3,785,924 1,374,244 5,160,168
----------- --------- ----------- ---------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from exercise of stock
options and warrants 188,890 188,890 188,890
Proceeds from issuance of notes
payable 2,040,000 2,040,000 2,040,000
Payments on commercial paper, other
short term borrowings and notes
payable (4,025,520) (4,025,520) (4,025,520)
Increase in other assets (159,465) (159,465) (159,465)
----------- --------- ----------- ---------- -----------
NET CASH PROVIDED BY (USED IN)
FINANCING ACTIVITIES (1,956,095) (1,956,095) (1,956,095)
----------- --------- ----------- ---------- -----------
NET DECREASE IN CASH 7,016,207 219,009 7,235,216 1,499,941 8,735,157
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 $21,208,775 ($265,821) $20,942,954 $ 1,524,201 $22,467,155
=========== ========= =========== =========== ===========
</TABLE>
Notes: (a) Combine cash flow of the 1991-1 Partnership.
(b) Combine cash flows of the 1989-1 Partnership and 1990-1 Partnership.
(c) Eliminate intercompany items.
(d) Record cash proceeds from sale of Umbrella Point Field.
97
<PAGE> 111
PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1994
<TABLE>
<CAPTION>
Consolidated
Benton Oil Minimum Remaining
and Gas Pro Forma Minimum Pro Forma Maximum
Company Adjustments Notes Pro Forma Adjustments Notes Pro Forma
----------------------------------------------------------------------------------------
REVENUES:
<S> <C> <C> <C> <C> <C> <C> <C>
Oil and gas sales $31,942,810 $ 71,407 (a) $32,014,217 $ 519,381 (b) $32,533,598
Gain on exchange rates 1,445,307 1,445,307 1,445,307
Investment earnings 1,180,824 1,938 (a) 1,182,762 5,640 (b) 1,188,402
Partnership fees, reimbursement and
other 135,865 (6,792) (c) 129,073 (35,657) (c) 93,416
----------- --------- ----------- ----------- -----------
34,704,806 66,553 34,771,359 489,364 35,260,723
----------- --------- ----------- ----------- -----------
EXPENSES
Lease operating costs and
production taxes 9,531,264 28,991 (a) 9,560,255 268,121 (b) 9,828,376
Depletion, depreciation and
amortization 10,298,112 40,276 (d) 10,338,388 324,693 (d) 10,663,081
General and administrative 5,241,295 14,032 (a),(c) 5,255,327 55,381 (b),(c) 5,310,708
Interest 3,887,961 3,887,961 3,887,961
Minority interest in net income 2,094,211 2,094,211 2,094,211
----------- --------- ----------- ----------- -----------
31,052,843 83,299 31,136,142 648,195 31,784,337
----------- --------- ----------- ----------- -----------
Income before income taxes and roll-up
expenses and payments 3,651,963 (16,746) 3,635,217 (158,831) 3,476,386
Income taxes (697,802) (697,802) (697,802)
----------- --------- ----------- ----------- -----------
Income before roll-up expenses and
payments 2,954,161 (16,746) 2,937,415 (158,831) 2,778,584
Roll-up expenses and payments 813,573 (e) 813,573 1,194,960 (e) 2,008,533
----------- --------- ----------- ----------- -----------
Income after roll-up expenses and
payments $ 2,954,161 $(830,319) $ 2,123,842 $(1,353,791) $ 770,051
=========== ========= =========== =========== ===========
Income per common share:
Before roll-up expenses and payments $0.12 $0.12 $0.11
----------- ----------- -----------
After roll-up expenses and payments $0.12 $0.09 $0.03
----------- ----------- -----------
Weighted average common shares
outstanding 24,850,922 24,876,849 25,015,435
----------- ----------- -----------
Ratio of earnings to fixed charges:
Before roll-up expenses and payments 1.92x 1.92x 1.88x
----------- ----------- -----------
After roll-up expenses and payments 1.92x 1.71x 1.37x
----------- ----------- -----------
</TABLE>
Notes: (a) Record the participants' shares of the 1991-1 Partnership.
(b) Record the participants' share of the 1989-1 Partnership and
1990-1 Partnership.
(c) Eliminate allocated overhead costs from partnerships.
(d) Record depletion on oil and gas properties acquired from
partnerships.
(e) Record roll-up expenses and payments associated with the
acquisition of partnership units. Included as roll-up expenses
and payments are the value of the warrants issued to the
participants 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 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.
98
<PAGE> 112
PRO FORMA CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1994
<TABLE>
<CAPTION>
Consolidated
Benton Oil Minimum Remaining
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 $ (16,746) (a) $ 2,937,415 $(158,831) (b) $ 2,778,584
Adjustments to reconcile net income (loss)
to net cash provided by (used in)
operating activities:
Depletion, depreciation and amortization 10,298,112 40,276 (a) 10,338,388 324,693 (b) 10,663,081
Compensation expense attributed to stock
options
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
Loss on disposal of assets
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
Increase in income taxes payable
------------------------- ----------------------- -----------
TOTAL ADJUSTMENTS 10,508,628 45,504 10,554,132 378,394 10,932,526
------------------------- ----------------------- -----------
NET CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES 13,462,789 28,758 13,491,547 219,563 13,711,110
------------------------- ----------------------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of property and
equipment 5,803,215 7,699 (a) 5,810,914 7,672 (b) 5,818,586
Additions of property and equipment (38,403,322) (23,323) (a) (38,426,645) (155,822) (b) (38,582,467)
Increase in restricted cash (19,250,000) (19,250,000) (19,250,000)
Distributions from limited partnerships 502,167 (127,205) (c) 374,962 (598,960) (c) (223,998)
Payment for purchase of Benton-Vinccler,
net of cash acquired (2,501,973) (2,501,973) (2,501,973)
------------------------- ----------------------- -----------
NET CASH PROVIDED BY (USED IN)
INVESTING ACTIVITIES (53,849,913) (142,829) (53,992,742) (747,110) (54,739,852)
------------------------- ----------------------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from exercise of stock options
and 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)
Payment of stock issuance costs (545,000) (d) (545,000) (545,000)
------------------------- ----------------------- -----------
NET CASH PROVIDED BY (USED IN)
FINANCING ACTIVITIES 18,271,574 (547,939) 17,723,635 19,225 17,742,860
------------------------- ----------------------- -----------
NET DECREASE IN CASH (22,115,550) (662,010) (22,777,560) (508,322) (23,285,882)
CASH AND CASH EQUIVALENTS AT BEGINNING OF
PERIOD 36,308,118 177,180 36,485,298 532,582 37,017,880
------------------------- ----------------------- -----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $14,192,568 $(484,830) $13,707,738 $ 24,260 $13,731,998
========================= ======================= ===========
</TABLE>
Notes: (a) Combine cash flow of the 1991-1 Partnership.
(b) Combine cash flows of the 1989-1 Partnership and 1990-1
Partnership.
(c) Eliminate intercompany items.
(d) Record issuance costs associated with the acquisition of
partnership units.
99
<PAGE> 113
INFORMATION CONCERNING BENTON
INCORPORATION OF CERTAIN INFORMATION BY REFERENCE
The following information set forth in Benton's Annual Report on Form
10-K for the year ended December 31, 1994, as amended on Forms 10-K/A (the "Form
10-K") and in Benton's Form 10-Q for the quarter ended March 31, 1995 (the "Form
10-Q") and in Benton's proxy statement on Schedule 14A to be used in connection
with its Annual Meeting of Stockholders to be held July 26, 1995 (the "Proxy
Statement") is incorporated herein by reference:
(a) description of Benton's business in the Form 10-K and Form 10-Q;
(b) selected financial data contained in the Form 10-K;
(c) management's discussion and analysis of financial condition and
results of operations contained in the Form 10-K and the Form
10-Q;
(d) the consolidated financial statements and notes thereto
contained in the Form 10-K and the Form 10-Q;
(e) information with respect to beneficial ownership of Benton
common stock contained in the Proxy Statement;
(f) information concerning the directors and executive officers of
Benton contained in the Form 10-K and Proxy Statement;
(g) information regarding executive compensation contained in the
Form 10-K and Proxy Statement; and
(h) information regarding certain relationships and related
transactions contained in the Form 10-K and Proxy Statement
BUSINESS
Benton Oil and Gas Company ("Benton" or the "Company") is primarily
engaged in the development and production of oil and gas properties. The
Company's operations are focused on the eastern region of Venezuela, the Gulf
Coast region of Louisiana and the West Siberia region of Russia. Benton's
business strategy is to seek new reserves in areas of low geologic risk and to
exploit underdeveloped existing oil and gas fields. The Company implements the
exploitation strategy through the in-house design and interpretation of 3-D
seismic surveys and through workovers, recompletions, redrilling and exploration
and development drilling.
Internationally, the Company seeks projects with significant reserve
potential in areas with low geologic risk and known proved reserves where, in
certain situations, the Company can add value by employing modern exploration,
drilling, completion and production techniques. To reduce risk, control costs,
and facilitate local transactions, the Company has formed ventures with local
foreign partners.
100
<PAGE> 114
Domestically, the Company integrates 3-D seismic technology with
subsurface geologic data from previously drilled wells. This geophysical
evaluation enables the Company to discover previously undetected reserves in
existing fields. The Company believes that it enjoys a competitive advantage in
finding and developing reserves on an economic basis because of its
concentration on 3-D seismic technology, the training and qualifications of
its in-house technical team and the practical experience and knowledge which
this team has acquired over past years. The Company's recognized technical
expertise has afforded it access to projects it otherwise would not have
enjoyed.
In the ordinary course of its business, the Company continues to
evaluate acquisition, joint venture and other opportunities that would enable it
to further its business strategy.
Principal Areas of Activity
The following table summarizes the Company's proved reserves at
December 31, 1994 by principal geographic area:
<TABLE>
<CAPTION>
PROVED RESERVES
----------------------------------------------------------
CRUDE OIL AND NATURAL GAS (MMcf) OIL EQUIVALENT
CONDENSATE (MBbl) (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.
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, 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
101
<PAGE> 115
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 repatriation and
inconvertibility, expropriation and interference with operations for its
102
<PAGE> 116
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 and 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 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.
103
<PAGE> 117
West Cote Blanche Bay Field
The West Cote Blanche Bay Field is located on 5,892 acres in a shallow
bay in St. Mary Parish, approximately 125 miles southwest of New Orleans with
water depths averaging seven to eight feet. The field was discovered in 1938 by
Texaco, which continues to operate the field. The Company believes that, at
approximately 3.5 miles long and two miles wide, the West Cote Blanche Bay Field
contains one of the largest salt domes in the Gulf Coast. More than 300 separate
oil and gas reservoirs have been identified by Texaco and the Company from a
total of approximately 680 wellbores in 180 different sandstone formations, at
depths from 1,700 to 13,000 feet. At December 31, 1994, the field had
cumulatively produced over 181 MMBbl of oil and 225 Bcf of natural gas.
Since the Company's first acquisition of an interest in the West Cote
Blanche Bay Field, it has worked with Texaco in the technical evaluation of the
field. Until late 1994, the prospect evaluations covered all depths and included
the drilling wells and a substantial number of recompletions and replacement
wells in oil reservoirs at depths of 2,000 to 10,500 feet. As a result of
ongoing evaluation, in late 1994 the Company decided to focus almost exclusively
on exploitation of gas and oil reservoirs at depths below 10,000 feet, utilizing
the results of the 3-D seismic interpretations. To mitigate the risk of
concentrating on deeper, more expensive wells, the Company sold approximately
25% of its working interest to Tenneco. Also, in March 1995, the Company and its
affiliates and Tenneco sold their interests in the shallower oil depths (above
approximately 10,575 feet) to WRT Energy Corporation, another working interest
owner in the field.
Rabbit Island Field
Rabbit Island is located in state waters in Iberia and St. Mary
Parishes, approximately 95 miles southwest of New Orleans. The dome was
discovered in 1939 by Texaco which continues to operate the field. Compared to
West Cote Blanche Bay, on whose 5,892 acres more than 800 wells have been
drilled, just over 200 wells have been drilled on the 27,909 acres of the Rabbit
Island Field. Cumulative production through December 31, 1994 was 48 MMBbl of
oil and 1.2 Tcf of gas from 51 productive zones.
In 1992, the Company signed an agreement with Texaco to fund and
conduct a 3-D seismic program covering approximately 105 square miles over the
Rabbit Island project area. The estimated cost to the Company of this program is
approximately $6.0 million, substantially all of which has been expended. The
seismic survey has been shot, processed and is currently being interpreted.
Pursuant to the agreement, the Company may drill five wells over a
period of up to five years. As identified below, the first well has been
drilled. Assuming the remaining four wells are drilled in accordance with the
terms set forth in the agreement, the Company will earn a 50% working interest
in
104
<PAGE> 118
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> 119
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.
106
<PAGE> 120
During the third quarter of 1992, GEOILBENT commenced initial
operations which included the construction of a 37 mile oil pipeline and
installation of temporary production facilities. Completed in April 1993, with a
design capacity of 75,000 Bbl of oil per day, the pipeline transports oil from
the North Gubkinskoye Field south to the main Russian oil pipeline network. The
venture has been exporting oil since the fourth quarter of 1993.
GEOILBENT identified nine previously existing delineation wells that
were capable of being reentered and placed these on production. These
delineation wells were not originally intended by Purneftegasgeologia to be
commercial producers. Therefore, completion procedures for optimum production
were not employed. The Company believes that production rates from future wells
using western completion technologies will be significantly greater. GEOILBENT
has commenced drilling a series of development wells in the North Gubkinskoye
Field. Three Russian drilling rigs are drilling development wells offsetting
previously drilled exploration wells.
GEOILBENT is utilizing Russian equipment and personnel whenever
feasible. Supervision is provided jointly by an American and Russian management
team. Russian equipment, including Russian rigs, are being upgraded by certain
western technology and materials including shaker screens, monitoring equipment
and drilling and completion fluids. Such measures, along with paying for Russian
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.
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<PAGE> 121
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.
108
<PAGE> 122
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.
Benton pays the 1989-1 Partnership for revenues collected 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.
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<PAGE> 123
<TABLE>
<CAPTION>
Proved Reserves at January 1, 1995 1994 Production
---------------------------------- ---------------
Present Value of
Estimated Future Net
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 April 1995, at combined average daily rates of 342 Bbl of
oil and 3.4 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 $145,775. As of January 1, 1995, the 1989-1
Partnership's interest in East Cameron Block 229 was determined to be
uneconomic.
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<PAGE> 124
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 three months ended March 31, 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 three
months ended March 31, 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>
Three Months Ended
Years Ended December 31, March 31,
------------------------------------------------------------- ---------------------
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 $ 41,522 $ 30,781
Lease operating costs and
production taxes 60,471 85,894 73,309 76,855 79,479 14,433 15,203
Exploration costs 1,627 1,891 789
Depletion, impairment and
amortization 46,224 74,122 111,050 72,453 77,895 21,880 42,934
General and administrative 31,086 17,428 32,110 38,432 33,654 18,469 17,752
----------- ----------- --------- --------- --------- --------- ---------
Net income (loss) $ 75,000 $ 39,579 $ 7,364 $ 13,749 ($ 31,404) ($ 13,260) ($ 45,108)
=========== =========== ========= ========= ========= ========= =========
Net increase (decrease)in
cash and cash equivalents ($ 100,529) ($ 82,547) ($241,781) ($127,320) ($106,355) ($ 6,257) $ 3,552
Net cash provided by
operating activities 187,669 111,201 117,414 86,202 46,491 8,620 (2,174)
Distributions 140,064 211,364 281,818 169,936 135,615 15,218 --
Per Unit Operating Data (1)
Net income (loss) 192 61 (70) (16) (149) (59) (169)
Distributions of earnings 192 61 -- -- -- -- --
Distributions representing a
return of capital 308 686 1,003 600 162 54 --
</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 $ 564,404 $ 481,857 $ 240,076 $ 112,756 $ 6,401 $ 106,499 $ 9,953
Total assets at book value 1,177,716 1,016,060 727,977 571,790 407,052 543,312 385,596
Total assets at the value
assigned for purposes of 390,159
roll-up transaction
Total liabilities 3,500 13,629 -- -- 2,281 -- 25,933
General and limited partners'
equity:
Managing General Partner 34,706 54,437 79,213 94,780 14,658 97,963 16,776
Participants 1,139,510 947,994 648,764 477,010 390,113 445,349 342,887
----------- ----------- --------- --------- --------- --------- ---------
$ 1,174,216 $ 1,002,431 $ 727,977 $ 571,790 $ 404,771 $ 543,312 $ 359,663
=========== =========== ========= ========= ========= ========= =========
Per Unit Balance Sheet Data(1)
Book value $ 4,084 $ 3,398 $ 2,325 $ 1,710 $ 1,398 $ 1,596 $ 1,229
Value assigned for purpose of
the roll-up transaction 1,292
</TABLE>
(1) Per unit data is based on indicated amounts allocable to limited
partners divided by 279 limited partner units outstanding.
111
<PAGE> 125
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. One 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
Three Months Ended March 31, 1995 and 1994. For the three months ended
March 31, 1995, the 1989-1 Partnership had revenues of $30,781 compared to
$41,522 for the same period in 1994, representing a decrease of 26%. This
decrease was primarily due to reduced oil and gas sales from the Umbrella Point
Field due to the field's natural production decline. The production for the
three months ended March 31, 1995 was 1,007 Bbl of crude oil and condensate and
8,758 Mcf of natural gas compared to production of 1,476 Bbl of crude oil and
condensate and 9,440 Mcf of natural gas for the comparable period in 1994. For
the three months ended March 31, 1995, crude oil and natural gas prices, net of
severance taxes, averaged $16.89 per Bbl and $1.57 per Mcf, respectively,
compared to $13.24 per Bbl and $2.27 per Mcf, respectively, during the
comparable period.
Lease operating costs and production taxes for the period ended March
31, 1995 were $15,203, an increase of 5% from $14,433 in the comparable period.
The increase was primarily due to increases in associated production overhead
and taxes at the Umbrella Point Field. Depletion, impairment and amortization
expenses were $42,934 for the period ended March 31, 1995, an increase of 96%
from $21,880 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 $17,752 for the period ended March 31, 1995, a
decrease of 4% from $18,469 for the comparable period.
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<PAGE> 126
For the reasons discussed above, the net loss for the three months
ended March 31, 1995 was $45,108, compared to a loss of $13,260 for the period
ended March 31, 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
decreased 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 1994. For the year ended December 31, 1994,
crude oil and natural gas prices, net of severance taxes, averaged $15.47 per
Bbl and $1.95 per Mcf, respectively, compared to $17.09 per Bbl and $2.12 per
Mcf, respectively, during the comparable period.
Lease operating costs and production taxes for the year ended December
31, 1994 were $79,479, an increase of 3% from $76,855 in the comparable period.
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.
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.
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, net of
severance taxes, 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.
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,
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<PAGE> 127
the Partnership will have no further oil and gas activities. If the sale is not
completed, the properties have a remaining economic life of approximately 3.5
years.
Effects of Inflation and Changing Prices
The 1989-1 Partnership's results of operations and cash flow are
affected by changing oil and gas prices. If the price of oil and gas increases,
there could be a corresponding increase in the cost to the Partnership for
drilling and related services as well as an increase in revenues. To date,
inflation has had a minimal effect on the Partnership.
INFORMATION CONCERNING 1990-1 PARTNERSHIP
GENERAL
Objectives. The 1990-1 Partnership is a limited partnership which was
formed to invest in oil and natural gas activities by primarily acquiring proven
producing properties that have additional development potential, recompleting
previously drilled wells and drilling new wells. The primary financial objective
of the 1990-1 Partnership is to make quarterly distributions to its Investors
from available cash flow while replacing and expanding its reserves on a
cost-effective basis. The Partnership made regular cash distributions to
partners through August 1994, but has not made subsequent cash distributions due
to declining oil and gas production combined with higher lease operating costs
and production taxes, continued capital expenditures and lower natural gas
prices.
Management. Benton Oil and Gas Company and a wholly-owned subsidiary,
Benton Oil and Gas Company of Louisiana, are the Co-Managing General Partners.
Benton makes all decisions regarding the business and operations of the 1990-1
Partnership, including production, development and other activities, and any
sale of properties and the acquisition of additional properties.
The Managing General Partners receive 25.5236% of the oil and gas
revenues from the 1990-1 Partnership. In addition, Benton and its subsidiary
own 14.192 Units in the 1990-1 Partnership.
The Co-Managing General Partners do not receive any management fees or
other fees from the 1990-1 Partnership. The 1990-1 Partnership pays the
Co-Managing General Partners for lease operating expenses, well costs and
general and administrative expenses incurred on behalf of the Partnership.
Benton pays the 1990-1 Partnership for revenues collected 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.
114
<PAGE> 128
<TABLE>
<CAPTION>
Proved Reserves at January 1, 1995 1994 Production
---------------------------------- ---------------
Present Value of
Estimated Future Net
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. 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 April 1995, at combined average daily rates of 342 Bbl of
oil and 3.4 MMcf of natural gas.
West Cote Blanche Bay Field. The West Cote Blanche Bay Field is located
on 5,892 acres in a shallow bay in St. Mary Parish, Louisiana, approximately 125
miles southwest of New Orleans with water depths averaging seven to eight feet.
The field was discovered in 1938 by Texaco, which continues to operate the
field. More than 300 separate oil and gas reservoirs have been identified by
Texaco and the Company from a total of approximately 680 wellbores in 180
different sandstone formations, at depths from 1,700 to 13,000 feet. The 1990-1
Partnership originally purchased a 0.38% working interest in the West Cote
Blanche Bay Field in 1990. However, in 1991, it sold a 0.06% working interest to
the 1991-1 Partnership for $94,352 prior to closing adjustments. In March
1995, the Partnership sold a 0.32% working interest in certain depths (above
approximately 10,575 feet), in the West Cote Blanche Bay Field for a purchase
price of $146,900. The 1990-1 Partnership has a 0.32% working interest in three
wells below the depth of approximately 10,575 feet. These wells are currently
producing at a combined rate of approximately 7 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 $946,078. 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.
115
<PAGE> 129
Round Mountain Field. The Round Mountain Field is located on the
southeast flank of the San Joaquin Basin of Kern County, California,
approximately 10 miles northeast of Bakersfield. The field was discovered in
1927 and average drilling depths range from 1,400 feet to 2,100 feet. The
1990-1 Partnership purchased an 8.40% working interest in 32 producing wells
in the Round Mountain Field. However, due to the inability to significantly
increase production and after $787,595 in cumulative expenditures, Benton
determined it was in the best interest of the Partnership to sell its working
interest in Round Mountain Field. In September 1992, the 1990-1 Partnership
sold its interest in Round Mountain to Nahama & Weagant Energy Company for
$19,386.
Hopper Canyon 12-1 Well. The Hopper Canyon 12-1 well is located in
Ventura County, California. This well was successfully drilled and completed in
the fourth quarter of 1991. The well produced at rates of approximately 24 Bbl
of oil and 45 MMcf of gas per day. However, Benton determined it was in the best
interest of the Partnership to sell its 38.0% working interest in the well. In
April 1992, the 1990-1 Partnership sold its interest in the 12-1 well to
Fortune Petroleum. Proceeds from the sale were $17,881, consisting of $3,461 in
cash and stock of Fortune Petroleum with a fair market value of $14,420 (the
stock was subsequently sold in November 1994 with the 1990-1 Partnership
receiving $7,672). In addition, the 1990-1 Partnership retained a production
payment of $8,845 which was paid from monthly net income from the 12-1 well. The
1990-1 Partnership's cumulative expenditures on the Hopper Canyon 12-1 well
were $211,134.
Prather 43-1 Well. This prospect was located in Acadia Parish,
Louisiana. This well was drilled to a total depth of approximately 11,000 feet.
It was determined to be uneconomical and was plugged and abandoned. The 1990-1
Partnership had a 12.5% working interest in this well with total expenditures of
$96,225.
North Fisher Reef #13-16A Well. This prospect was located in Trinity
Bay, Chambers County, Texas. This offshore oil and gas prospect was drilled to a
total depth of 11,000 feet in February 1991. This prospect had multiple
objectives, however, all objectives were determined to be non-commercial and the
well was plugged and abandoned. The 1990-1 Partnership had a 44.67% working
interest in this well with cumulative expenditures of $134,715.
SELECTED HISTORICAL FINANCIAL DATA
The following selected financial data for the 1990-1 Partnership, as of
and for each of the years in the five year period ended December 31, 1994 are
derived from the 1990-1 Partnership's audited financial statements. The
selected consolidated financial data for the three months ended March 31, 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 three months ended
March 31, 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.
116
<PAGE> 130
<TABLE>
<CAPTION>
Inception
to
December Three Months Ended
31, Years Ended December 31, March 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 $ 129,996 $ 96,623
Lease operating costs and
production taxes 155,247 440,434 285,840 254,903 263,957 48,007 50,961
Exploration costs 29,089 887,842 8,952 9,570 6,607 1,169 893
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 56,795 68,276
General and administrative 36,753 176,317 69,510 99,967 78,547 29,314 37,251
----------- ----------- ----------- ----------- ----------- ----------- ------------
Net income (loss) $ 114,117 ($ 825,495) ($1,212,036) $ 91,710 ($ 48,960) ($ 5,289) ($ 62,086)
=========== =========== =========== =========== =========== =========== ============
Net increase (decrease)in
cash and cash equivalents $ 3,057,412 ($1,780,352) ($ 399,559) ($ 457,675) ($ 401,967) ($ 3,505) $ 39,157
Net cash provided by
operating activities 124,336 356,853 407,453 290,032 173,410 51,506 7,518
Distributions 706,351 1,071,312 604,582 463,345 31,222 --
Per Unit Operating Data(1)
Net income (loss) 24 (703) (935) 9 (68) (14) (46)
Distributions of earnings -- -- -- -- -- -- --
Distributions representing a
return of capital -- 500 762 400 66 22 --
</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 $ 416,321 $ 57,016
Total assets at book value 6,719,035 4,713,665 2,380,317 1,867,445 1,355,140 1,830,934 1,293,054
Total assets at the value
assigned for purposes of
roll-up transaction 2,553,119
Total liabilities 523,524 50,000 -- -- -- -- --
General and limited partners'
equity:
Managing General Partner 137,695 291,366 386,815 436,921 111,441 449,318 112,695
Participants 6,053,875 4,363,866 1,978,692 1,429,384 1,240,417 1,379,409 1,176,276
Special Limited Partners 3,941 8,433 14,810 1,140 3,282 2,207 4,083
----------- ----------- ----------- ----------- ----------- ----------- ------------
$ 6,195,511 $ 4,663,665 $ 2,380,317 $ 1,867,445 $ 1,355,140 $ 1,830,934 $ 1,293,054
=========== =========== =========== =========== =========== =========== ============
Per Unit Balance Sheet Data(1)
Book value $ 4,309 $ 3,106 $ 1,408 $ 1,017 $ 883 $ 982 $ 837
Value assigned for
purpose of the
roll-up transaction 1,799
</TABLE>
(1) Per unit data is based on indicated amounts allocable to limited
partners divided by 1,405 limited partner units outstanding.
117
<PAGE> 131
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
Three Months Ended March 31, 1995 and 1994. For the three months ended
March 31, 1995, the 1990-1 Partnership had revenues of $96,623 compared to
$129,996 for the same period in 1994, representing a decrease of 22%. This
decrease was primarily due to reduced oil and gas sales from the Umbrella Point
Field due to the field's natural production decline. The production for the
three months ended March 31, 1995 was 3,151 Bbl of crude oil and condensate and
27,325 Mcf of natural gas compared to production of 4,656 Bbl of crude oil and
condensate and 28,917 Mcf of natural gas for the comparable period in 1994. For
the three months ended March 31, 1995, crude oil and natural gas prices, net of
severance taxes, averaged $16.98 per Bbl and $1.57 per Mcf, respectively,
compared to $13.44 per Bbl and $2.25 per Mcf, respectively, during the
comparable period.
Lease operating costs and production taxes for the period ended March
31, 1995 were $50,961, an increase of 6% from $48,007 in the comparable period.
The increase was primarily due to increases in associated production overhead
and taxes at the Umbrella Point Field. Depletion, impairment and amortization
expenses were $68,276 for the period ended March 31, 1995, an increase of 20%
from $56,795 for the comparable period primarily due to the impairment of the
East Cameron Field as a result of the proposed property sale. General and
administrative expenses were $37,251 for the period ended March 31, 1995, an
increase of 27% from $29,314 for the comparable period.
For the reasons discussed above, the net loss for the three months
ended March 31, 1995 was $62,086, compared to a loss of $5,289 for the period
ended March 31, 1994.
118
<PAGE> 132
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
price decreases. 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, net of severance taxes, averaged $15,83 per
Bbl and $1.93 per Mcf, respectively, compared to $17.31 per Bbl and $2.11 per
Mcf, respectively, during the comparable period.
Lease operating costs and production taxes for the year ended December
31, 1994 were $263,957, an increase of 4% from $254,903 in the comparable
period. 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.
For the reasons discussed above, the net loss for the year ended
December 31, 1994 was $48,960, compared to net income of $91,710 for the year
ended December 31, 1993.
Years Ended December 31, 1993 and 1992. For the year ended December 31,
1993, the 1990-1 Partnership had total revenues of $645,459 compared to $770,517
for the same period in 1992, representing a decrease of 16%. This decrease was
primarily due to reduced oil and gas sales from the Umbrella Point and East
Cameron Fields due to the fields' natural production decline and sales of the
Round Mountain and Hopper Canyon properties. The production for the years ended
December 31, 1993 was 18,518 Bbl of crude oil and condensate and 146,746 Mcf of
natural gas compared to production of 26,184 Bbl of crude oil and condensate and
145,477 Mcf of natural gas for the comparable period in 1992. For the year ended
December 31, 1993, crude oil and natural gas prices, net of severance taxes,
averaged $17.31 per Bbl and $2.11 per Mcf, respectively, compared to $18.02 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.
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
The oil and gas industry is a highly capital intensive business. The
Partnership requires capital principally to fund the following costs: (i)
drilling and completion costs of wells and the cost of production and
transportation facilities; (ii) purchase of leases and other interests in oil
and gas producing properties; and (iii) general and administrative expenses. The
amount of available capital significantly effects the scope of the Partnership's
operations.
119
<PAGE> 133
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.
120
<PAGE> 134
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.
Benton pays the 1991-1 Partnership for revenues collected 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 1994 Production
---------------------------------- ---------------
Present Value of
Estimated Future Net
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>
121
<PAGE> 135
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 April
1995, the Umbrella Point Field had 10 wells producing at combined average daily
rates of 342 Bbl of oil and 3.4 MMcf of natural gas.
West Cote Blanche Bay Field. The West Cote Blanche Bay Field is located
on 5,892 acres in a shallow bay in St. Mary Parish, Louisiana, approximately 125
miles southwest of New Orleans with water depths averaging seven to eight feet.
The field was discovered in 1938 by Texaco, which continues to operate the
field. More than 300 separate oil and gas reservoirs have been identified by
Texaco and the Company from a total of approximately 680 wellbores in 180
different sandstone formations, at depths from 1,700 to 13,000 feet. The 1991-1
Partnership purchased a 0.06% working interest in the West Cote Blanche Bay
Field from the 1990-1 Partnership for $94,352 prior to closing adjustments. In
March 1995, the Partnership sold its 0.06% working interest in certain depths
(above approximately 10,575 feet) in the West Cote Blanche Bay Field for a
purchase price of $29,200. The 1991-1 Partnership has a 0.06% working interest
in three wells below the depth of approximately 10,575 feet. These wells are
currently producing at a combined rate of approximately 7 MMcf of natural gas
per day.
The following is a description of properties the 1991-1 Partnership
at one time had an interest in but subsequently sold or abandoned.
Hopper Canyon 12-1 Well. The Hopper Canyon 12-1 well is located in
Ventura County, California. This well was successfully drilled and completed in
the fourth quarter of 1991. The well produced at rates of approximately 24 Bbl
of oil and 45 MMcf of gas per day. However, Benton determined it was in the best
interest of the Partnership to sell its 38.0% working interest in the well. In
April 1992, the 1991-1 Partnership sold its interest in the 12-1 well to
Fortune Petroleum. Proceeds from the sale were $17,881, consisting of $3,461 in
cash and stock of Fortune Petroleum with a fair market value of $14,420 (the
stock was subsequently sold in November 1994 with the 1991-1 Partnership
receiving $7,699). In addition, the 1991-1 Partnership retained a production
payment of $8,845 which was paid from monthly net income from the 12-1 well. The
1991-1 Partnership's cumulative expenditures on the Hopper Canyon 12-1 well
were $211,132.
Prather 43-1 Well. This prospect was located in Acadia Parish,
Louisiana. This well was drilled to a total depth of approximately 11,000 feet.
It was determined to be uneconomical and was plugged and abandoned. The 1991-1
Partnership had a 17.5% working interest in this well with total cumulative
expenditures of $134,715.
SELECTED HISTORICAL FINANCIAL DATA
The following selected financial data for the 1991-1 Partnership as of
and for each of the years in the four year period ended December 31, 1994 are
derived from the 1991-1 Partnership's audited financial statements. The
selected consolidated financial data for the three months ended March 31, 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
122
<PAGE> 136
of and for the periods presented. Operating results for the three months ended
March 31, 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>
Inception
to
December Three Months Ended
31, Years Ended December 31, March 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 $ 23,753 $ 18,430
Lease operating costs and
production taxes 54,069 40,093 36,276 38,002 6,264 6,596
Exploration costs 158,016 7,245 1,284 769 233 178
Loss on sale of oil and gas
properties 61,225 225
Depletion, impairment and
amortization 125,742 65,241 60,503 95,497 16,350 92,063
General and administrative 20,925 28,876 45,195 28,823 18,395 14,602
------------ --------- --------- --------- --------- ---------
Net income (loss) ($ 250,464) ($ 42,359) ($ 30,734) ($ 64,447) ($ 17,489) ($ 95,234)
============ ========= ========= ========= ========= =========
Net increase (decrease)in
cash and cash equivalents $ 1,233,019 ($955,826) ($100,013) ($117,010) ($ 25,401) $ 3,729
Net cash provided by
operating activities (7,849) 85,839 38,782 28,758 (1,139) (2,946)
Distributions 27,900 111,600 115,292 127,205 28,183 --
Per Unit Operating Data(1)
Net income (loss) (914) (243) (146) (256) (61) (336)
Distributions of earnings -- -- -- -- -- --
Distributions representing a
return of capital 100 400 400 300 100 --
</TABLE>
<TABLE>
<CAPTION>
December 31, March 31,
--------------------------------------------------- ----------------------
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 $ 151,779 $ 63,899
Total assets at book value 1,815,157 777,067 631,041 439,389 587,296 344,155
Total assets at the value
assigned for purposes of
roll-up transaction 591,623
Total liabilities 884,131 -- -- -- 1,927
General and limited partners'
equity:
Managing General Partner 18,413 43,394 50,358 13,601 49,654 11,946
Participants 912,292 732,846 580,591 425,503 535,534 331,854
Special Limited Partners 321 827 92 285 181 355
------------ --------- --------- --------- --------- ---------
$ 931,026 $ 777,067 $ 631,041 $ 439,389 $ 585,369 $ 344,155
============ ========= ========= ========= ========= =========
Per Unit Balance Sheet Data(1)
Book value $ 3,270 $ 2,627 $ 2,081 $ 1,525 $ 1,919 $ 1,189
Value assigned for
purpose of the roll-up
transaction 2,099
</TABLE>
(1) Per unit data is based on indicated amounts allocable to limited
partners divided by 279 limited partner units outstanding.
123
<PAGE> 137
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
Three Months Ended March 31, 1995 and 1994. For the three months ended
March 31, 1995, the 1991-1 Partnership had revenues of $18,430 compared to
$23,753 for the same period in 1994, representing a decrease of 22%. This
decrease was primarily due to reduced oil and gas sales from the Umbrella Point
Field due to the field's natural production decline. The production for the
three months ended March 31, 1995 was 625 Bbl of crude oil and condensate and
4,599 Mcf of natural gas compared to production of 926 Bbl of crude oil and
condensate and 4,155 Mcf of natural gas for the comparable period in 1994. For
the three months ended March 31, 1995, crude oil and natural gas prices, net of
severance taxes, averaged $17.04 per Bbl and $1.61 per Mcf, respectively,
compared to $14.09 per Bbl and $2.35 per Mcf, respectively, during the
comparable period.
Lease operating costs and production taxes for the period ended March
31, 1995 were $6,596, an increase of 5% from $6,264 in the comparable period.
The increase was primarily due to increases in associated production overhead
and taxes at the Umbrella Point Field. Depletion, impairment and amortization
expenses were $92,063 for the period ended March 31, 1995, an increase of 463%
from $16,350 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 $14,602 for the period ended March 31, 1995, a
decrease of 21% from $18,395 for the comparable period. The 1991-1 Partnership
had a loss on sale of oil and gas property of $225 for the period ended March
31, 1995.
124
<PAGE> 138
For the reasons discussed above, the net loss for the three months
ended March 31, 1995 was $95,234, compared to a loss of $17,489 for the period
ended March 31, 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, net of severance taxes, averaged $16.83 per
Bbl and $1.94 per Mcf, respectively, compared to $18.14 per Bbl and $2.21 per
Mcf, respectively, during the comparable period.
Lease operating costs and production taxes for the year ended December
31, 1994 were $38,002, an increase of 5% from $36,276 in the comparable period.
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.
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 1994. For the year ended December 31, 1993,
crude oil and natural gas prices, net of severance taxes, 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%. 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
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
125
<PAGE> 139
producing properties; and (iii) general and administrative expenses. The amount
of available capital significantly effects the scope of the Partnership's
operations.
In June 1995, the Partnership entered into an agreement to sell its
principal remaining oil and gas properties (see Note 4 to the 1991-1
Partnership Financial Statements). Assuming the sale is completed, the
Partnership will have very limited remaining oil and gas activities. If the
sale is not completed, the properties have a remaining economic life of
approximately 2.5 years.
Effects of Inflation and Changing Prices
The 1991-1 Partnership's results of operations and cash flow are
affected by changing oil and gas prices. If the price of oil and gas increases,
there could be a corresponding increase in the cost to the Partnership for
drilling and related services as well as an increase in revenues. To date,
inflation has had a minimal effect on the Partnership.
126
<PAGE> 140
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.
127
<PAGE> 141
LEGAL MATTERS
The validity of the issuance of the Securities to be issued pursuant to
the Exchange Offer will be passed upon for Benton, and certain federal income
tax matters related to the Exchange Offer will be passed upon for Benton, by
Emens, Kegler, Brown, Hill & Ritter, Co., L.P.A., Columbus, Ohio.
EXPERTS
The consolidated financial statements of Benton and the financial
statements of the 1989-1 Partnership, the 1990-1 Partnership and the 1991-1
Partnership as of December 31, 1994 and 1993 and for each of the three years in
the period ended December 31, 1994 included in this Prospectus have been audited
by Deloitte & Touche LLP, independent auditors, as stated in their reports
appearing herein and have been so included in reliance upon the reports of such
firm given upon their authority as experts in accounting and auditing.
The information appearing herein, and incorporated herein by reference,
with respect to proved oil and gas reserves of Benton at December 31, 1992, 1993
and 1994, to the extent stated herein, was estimated by Benton and audited by
Huddleston & Co., Inc., independent petroleum engineers, and is included herein
on the authority of such firm as experts in petroleum engineering.
The information appearing herein with respect to proved oil and gas
reserves of the 1989-1 Partnership at December 31, 1992, 1993 and 1994, to the
extent stated herein, was estimated by Benton and audited by Huddleston & Co.,
Inc., independent petroleum engineers, and is included herein on the authority
of such firm as experts in petroleum engineering.
The information appearing herein with respect to proved oil and gas
reserves of the 1990-1 Partnership at December 31, 1992, 1993 and 1994, to the
extent stated herein, was estimated by Benton and audited by Huddleston & Co.,
Inc., independent petroleum engineers, and is included herein on the authority
of such firm as experts in petroleum engineering.
The information appearing herein with respect to proved oil and gas
reserves of the 1991-1 Partnership at December 31, 1992, 1993 and 1994, to the
extent stated herein, was estimated by Benton and audited by Huddleston & Co.,
Inc., independent petroleum engineers, and is included herein on the authority
of such firm as experts in petroleum engineering.
128
<PAGE> 142
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.
129
<PAGE> 143
LIFTING COSTS. "Lifting Costs" are the expenses of lifting oil from a
producing formation to the surface, consisting of the costs incurred to operate
and maintain wells and related equipment and facilities, including labor costs,
repair and maintenance, supplies, insurance, production, severance and windfall
profit taxes.
MMBTU. "MMBtu" means one million British thermal units. A British
thermal unit is the amount of heat needed to raise the temperature of one pound
of water one degree Fahrenheit.
NET ACRES OR WELLS. A party's "Net Acre" or "Net Wells" are calculated
by multiplying the number of gross acres or gross wells in which that party has
an interest by the fractional interest of the party in each such acre or well.
OIL AND GAS LEASE. An "Oil and Gas Lease" is an agreement whereby the
grantee receives for a period of time the full or partial interest in oil and
gas properties, oil and gas mineral rights, fee rights or other rights of the
grantor granting the grantee the right to drill for, produce and sell oil and
gas upon payment of rentals, bonuses and/or royalties. Oil and Gas Leases are
generally acquired from private landowners and federal and state governments.
PRODUCING PROPERTIES OR RESERVES. "Producing Reserves" are Proved
Developed 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.
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.
130
<PAGE> 144
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.
131
<PAGE> 145
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-39
Index to Benton Oil & Gas Combination Partnership 1991-1, L.P. Financial
Statements........................................................................ F-50
</TABLE>
F-1
<PAGE> 146
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 March 31, 1995........ F-4
Consolidated Statements of Operations for the Years Ended December 31, 1992, 1993
and 1994 and the Three Months Ended March 31, 1994 and 1995....................... F-5
Consolidated Statements of Stockholders' Equity for the Years Ended December 31,
1992, 1993 and 1994 and the Three Months Ended March 31, 1995..................... F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 1992, 1993
and 1994 and the Three Months Ended March 31, 1994 and 1995....................... F-7
Notes to Consolidated Financial Statements for the Years Ended December 31, 1992,
1993 and 1994 and the Three Months Ended March 31, 1994 and 1995.................. F-9
</TABLE>
F-2
<PAGE> 147
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> 148
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------- MARCH 31,
1993 1994 1995
------------ ------------ ------------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents...................... $ 36,308,118 $ 14,192,568 $ 21,208,775
Restricted cash (Note 4)....................... 300,000 19,550,000 19,550,000
Accounts receivable:
Accrued oil and gas revenue................. 940,618 9,357,782 11,633,485
Joint interest and other (Note 12).......... 1,578,679 3,880,808 2,188,769
Property held for sale (Note 2)................ 14,887,700
Prepaid expenses and other..................... 333,263 563,839 1,140,632
------------ ------------ ------------
TOTAL CURRENT ASSETS................... 39,460,678 62,432,697 55,721,661
OTHER ASSETS..................................... 1,008,452 2,550,607 1,431,512
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 $13,518,734 excluded from amortization
at December 31, 1993 and 1994 and March 31,
1995, respectively)......................... 77,079,977 116,209,554 130,797,283
Furniture and fixtures......................... 673,848 1,439,484 1,746,600
------------ ------------ ------------
77,753,825 117,649,038 132,543,883
Accumulated depletion and depreciation......... (9,587,983) (20,071,223) (23,171,849)
------------ ------------ ------------
68,165,842 97,577,815 109,372,034
------------ ------------ ------------
$108,634,972 $162,561,119 $166,525,207
=========== =========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable:
Revenue distribution........................ $ 10,289 $ 594,782 $ 658,823
Trade and other............................. 3,542,355 11,426,105 11,429,594
Accrued interest payable, payroll and related
taxes....................................... 399,362 1,199,096 808,100
Income taxes payable........................... 788,068
Commercial paper and other short term
borrowings (Note 4)......................... 7,668,588 21,035,401 23,561,868
Current portion of long term debt (Note 3)..... 1,205,107 6,392,114 4,996,053
------------ ------------ ------------
TOTAL CURRENT LIABILITIES.............. 12,825,701 40,647,498 42,242,506
LONG TERM DEBT (Note 3).......................... 11,788,374 31,911,164 31,187,571
MINORITY INTEREST (Note 11)...................... 1,743,660 2,606,335
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
24,931,862 at December 31, 1993 and 1994 and
March 31, 1995 respectively................. 246,768 248,998 249,319
Additional paid-in capital..................... 91,639,606 92,921,115 93,109,684
Accumulated deficit............................ (7,865,477) (4,911,316) (2,870,208)
------------ ------------ ------------
TOTAL STOCKHOLDERS' EQUITY............. 84,020,897 88,258,797 90,488,795
------------ ------------ ------------
$108,634,972 $162,561,119 $166,525,207
=========== =========== ===========
</TABLE>
See notes to consolidated financial statements.
F-4
<PAGE> 149
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH
YEARS ENDED DECEMBER 31, 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 $ 3,498,661 $12,080,479
Net gain (loss) on exchange
rates...................... (206,481) 1,445,307 (69,533) 131,717
Investment earnings........... 185,094 393,843 1,180,824 252,545 424,234
Partnership fees,
reimbursements and other... 227,881 94,124 135,865 500 24,736
----------- ----------- ----------- ----------- -----------
8,622,109 7,503,796 34,704,806 3,682,173 12,661,166
----------- ----------- ----------- ----------- -----------
EXPENSES
Lease operating costs and
production taxes........... 4,413,620 5,110,264 9,531,264 1,766,022 2,246,002
Depletion, depreciation and
amortization............... 3,041,375 2,632,924 10,298,112 1,172,744 3,145,067
General and administrative.... 2,245,236 2,631,445 5,241,295 1,142,042 1,668,772
Interest...................... 1,831,213 1,957,753 3,887,961 680,737 1,618,126
----------- ----------- ----------- ----------- -----------
11,531,444 12,332,386 28,958,632 4,761,545 8,677,967
----------- ----------- ----------- ----------- -----------
INCOME (LOSS) BEFORE INCOME
TAXES AND MINORITY INTEREST... (2,909,335) (4,828,590) 5,746,174 (1,079,372) 3,983,199
INCOME TAX EXPENSE (Note 6)..... 697,802 1,079,416
----------- ----------- ----------- ----------- -----------
INCOME (LOSS) BEFORE MINORITY
INTEREST...................... (2,909,335) (4,828,590) 5,048,372 (1,079,372) 2,903,783
MINORITY INTEREST (Note 11)..... 2,094,211 62,754 862,675
----------- ----------- ----------- ----------- -----------
NET INCOME (LOSS)............... $(2,909,335) $(4,828,590) $ 2,954,161 $(1,142,126) $ 2,041,108
========== ========== ========== ========== ==========
NET EARNINGS (LOSS) PER COMMON
SHARE
(Note 13)..................... $ (0.22) $ (0.26) $ 0.12 $ (0.05) $ 0.08
========== ========== ========== ========== ==========
</TABLE>
See notes to consolidated financial statements.
F-5
<PAGE> 150
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
AND (UNAUDITED) THREE MONTHS ENDED MARCH 31, 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............. 32,014 321 188,569 188,890
Net income for the period............... 2,041,108 2,041,108
---------- -------- ----------- ----------- -----------
Balance at March 31, 1995 (unaudited)... 24,931,862 $249,319 $93,109,684 $(2,870,208) $90,488,795
========= ======== ========== ========== ==========
</TABLE>
See notes to consolidated financial statements.
F-6
<PAGE> 151
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31,
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 $ (1,142,126) $ 2,041,108
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 1,172,744 3,145,067
Compensation expense attributed to stock
options.................................... 329,103 142,420
Net earnings from limited partnerships....... (183,858) (106,230) (63,486) (15,937) (3,511)
Amortization of financing costs.............. 376,609 139,444 114,311 28,578 28,578
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 62,754 862,675
(Increase) decrease in accounts receivable... 1,628,823 (1,465,725) (10,384,670) (2,446,075) (583,664)
(Increase) decrease in prepaid expenses and
other...................................... 44,517 (288,217) (84,905) (216,402) (576,793)
Increase (decrease) in accounts payable...... (2,905,840) 1,759,747 7,974,335 (393,200) 67,530
Increase (decrease) in accrued interest
payable,
payroll and related taxes.................. (114,151) 204,117 560,720 819,996 (390,996)
Increase in income taxes payable............. 788,068
------------ ------------ ------------ ------------ ------------
TOTAL ADJUSTMENTS.......................... 2,261,227 3,038,625 10,508,628 (987,542) 3,347,586
------------ ------------ ------------ ------------ ------------
NET CASH PROVIDED BY (USED IN) OPERATING
ACTIVITIES............................... (648,108) (1,789,965) 13,462,789 (2,129,668) 5,388,694
------------ ------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of property and
equipment.................................. 2,965,820 7,822,120 5,803,215 126,397 14,713,894
Additions of property and equipment.......... (13,951,247) (26,169,581) (38,403,322) (8,294,357) (11,130,286)
Increase in restricted cash.................. (300,000) (19,250,000) (21,000,000)
Distributions from limited partnerships...... 391,540 28,667 502,167 746
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) (31,669,187) 3,583,608
------------ ------------ ------------ ------------ ------------
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 83,740 188,890
Issuance of convertible subordinated
debentures................................. 6,428,000
Proceeds from issuance of notes payable...... 404,776 21,360,000 2,040,000
Proceeds from commercial paper and other
short term borrowings...................... 7,668,588 23,217,775 22,054,000
(Increase) decrease in other assets.......... (806,992) 3,460 (1,683,583) (41,530) (159,465)
Payments on commercial paper, other short
term borrowings and notes payable.......... (14,877,300) (672,230) (24,706,358) (14,824,690) (4,025,520)
Deficiency payments on redeemable common
stock...................................... (287,194) (172,917)
------------ ------------ ------------ ------------ ------------
NET CASH PROVIDED BY (USED IN) FINANCING
ACTIVITIES............................... 21,588,284 43,043,889 18,271,574 7,187,780 (1,956,095)
------------ ------------ ------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH............ 9,996,007 22,635,130 (22,115,550) (26,611,075) 7,016,207
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 $ 9,697,043 $ 21,208,775
=========== =========== =========== =========== ===========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW
INFORMATION:
Cash paid during the period for interest
expense.................................... $ 1,483,585 $ 1,838,848 $ 3,299,189 $ 115,066 $ 1,832,229
=========== =========== =========== =========== ===========
Cash paid during the period for income
taxes...................................... $ 715,507 $ 50,016 $ 176,825
=========== =========== =========== =========== ===========
</TABLE>
F-7
<PAGE> 152
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
During the three months ended March 31, 1995, the Company financed the
purchase of oil and gas equipment in the amount of $2,337,860 and leased office
equipment in the amount of $54,473.
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.
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, 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.
During the year ended December 31, 1992, the Company acquired $43,790 of
fixed assets through capital lease obligations and seller financing.
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 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.
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.
See notes to consolidated financial statements.
F-8
<PAGE> 153
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992 AND (UNAUDITED)
THREE MONTHS ENDED MARCH 31, 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 $1,696,330, $1,736,678 and $1,412,170 for the years
ended December 31, 1994, 1993 and 1992, respectively and $526,161 and $371,530
for the three months ended March 31, 1995 and 1994, 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, 1994, 1993 and 1992 was $4,247,304,
$2,142,133 and $2,937,887 ($7.46, $6.47 and $5.71 per equivalent barrel),
respectively and for the three months ended March 31, 1995 and 1994 was $628,270
and $485,064 ($6.97 and
F-9
<PAGE> 154
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$6.49 per equivalent barrel), respectively. Depletion expense attributable to
the Venezuelan cost center for the years ended December 31, 1994 and 1993 was
$4,998,213 and $229,080 ($1.98 and $1.43 per equivalent barrel), respectively
and for the three months ended March 31, 1995 and 1994 was $2,109,428 and
$549,518 ($1.99 and $1.79 per equivalent barrel), respectively. Depletion
expense attributable to the Russian cost center for the years ended December 31,
1994 and 1993 was $837,818 and $99,207 ($2.85 and $3.51 per equivalent barrel),
respectively and for the three months ended March 31, 1995 and 1994 was $328,136
and $84,324 ($2.76 and $3.13 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 $185,336, $123,623 and $65,213
for the years ended December 31, 1994, 1993 and 1992, respectively and $57,477
and $43,888 for the three months ended March 31, 1995 and 1994, 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
March 31, 1995, and the results of operations for the three month periods ended
March 31, 1995 and 1994.
F-10
<PAGE> 155
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The results of operations for the three month period ended March 31, 1995
are not necessarily indicative of the results to be expected for the full year.
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.
F-11
<PAGE> 156
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,
---------------------------
1993 1994
----------- ----------- MARCH 31,
1995
-----------
(UNAUDITED)
<S> <C> <C> <C>
Senior unsecured note 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 6,428,000
Convertible subordinated notes with interest at 8%.
See description below............................. 4,662,000 4,662,000 4,662,000
Non-interest bearing promissory notes payable with a
face value of $6 million at December 31, 1994 and
$3 million at March 31, 1995, discounted using a
10% interest rate. The notes are due in various
installments through January 1996. See Note 11.... 5,747,878 2,854,962
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 2,040,000
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..................................... 200,399 173,400 198,662
----------- ----------- -----------
12,993,481 38,303,278 36,183,624
Less current portion................................ 1,205,107 6,392,114 4,996,053
----------- ----------- -----------
$11,788,374 $31,911,164 $31,187,571
========== ========== ==========
</TABLE>
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
F-12
<PAGE> 157
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 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 by $3
million to $6 million, with interest only payments on the additional $3 million
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 March 31, 1995, the Company's share of the outstanding balance
was approximately $2.0 million.
F-13
<PAGE> 158
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 October 1993, Benton-Vinccler issued $15 million in commercial paper,
with interest at 8.5%, for project financing. At December 31, 1993, the
Company's share of the commercial paper outstanding was approximately $7.3
million. At the February 1994 maturity date of the commercial paper,
Benton-Vinccler borrowed $15 million from Morgan Guaranty Trust Company of New
York ("Morgan Guaranty") to repay the commercial paper. Benton-Vinccler
subsequently borrowed from the same bank an additional $7 million for working
capital requirements. 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. Under the loan arrangement, Benton-Vinccler may borrow up to
$25 million, of which $10 million may be borrowed on a revolving basis. The loan
arrangement contains no restrictive covenants and no financial ratio covenants.
Benton-Vinccler made a payment of $2.75 million in September 1994, leaving a
balance of $19.25 million. The Company is presently pursuing several options for
long term financing for Benton-Vinccler.
During the fourth quarter of 1994 and the first quarter of 1995,
Benton-Vinccler acquired approximately $4.1 million of drilling and production
equipment from trading companies and suppliers under terms which include
repayment within a 12-month period in monthly and quarterly installments at
interest rates from 6.7% to 10%. The outstanding balances at March 31, 1995 and
December 31, 1994 related to these transactions were approximately $3.0 and $1.5
million, respectively.
In June 1994, GEOILBENT entered into a production 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 March 31, 1995, the Company's share of the unpaid advances was
approximately $1.0 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
affect the Company and certain of its Louisiana properties. The Company believes
that the settlement and the
F-14
<PAGE> 159
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
subsequent sale of the working interest by Texaco to Apache Corporation 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 continuing 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 operation of the limited partnerships 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 Company intends to vigorously defend this action 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 any 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 $255,650, $233,934 and $222,279 for the years ended
December 31, 1994, 1993 and 1992, respectively.
F-15
<PAGE> 160
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> 161
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> 162
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> 163
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> 164
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. 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.
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> 165
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, 1994 and 1993 as though the
acquisition of the 30% interest had been completed and Benton-Vinccler had been
consolidated as of January 1, 1994 and 1993, 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, 1993 and 1992,
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, 1994, 1993 and 1992 were 24,850,922, 18,608,770 and 12,981,105,
respectively. Total weighted average common and common equivalent shares
outstanding during the three months ended March 31, 1995 and 1994 were
26,037,055 and 24,736,848, 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> 166
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> 167
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> 168
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> 169
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> 170
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> 171
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> 172
BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P.
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
Independent Auditors' Report.......................................................... F-27
Balance Sheets at December 31, 1993 and 1994 and March 31, 1995....................... F-28
Statements of Operations for the Years Ended December 31, 1992, 1993 and 1994 and the
Three Months Ended March 31, 1994 and 1995.......................................... F-29
Statements of Partners' Capital for the Years Ended December 31, 1992, 1993 and 1994
and the Three Months Ended March 31, 1995........................................... F-30
Statements of Cash Flows for the Years Ended December 31, 1992, 1993 and 1994 and the
Three Months Ended March 31, 1994 and 1995.......................................... F-31
Notes to Financial Statements for the Years Ended December 31, 1992, 1993 and 1994 and
the Three Months ended March 31, 1994 and 1995...................................... F-32
</TABLE>
F-28
<PAGE> 173
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> 174
BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P.
BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------- MARCH 31,
1993 1994 1995
-------- -------- ---------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
Current Assets:
Cash..................................................... $112,756 $ 6,401 $ 9,953
Receivable from Co-Managing General Partners............. 13,535
Property held for sale (Note 4).......................... 375,643
-------- -------- ---------
Total Current Assets............................. 126,291 6,401 385,596
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 $ 385,596
======== ======== ========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities:
Payable to Co-Managing General Partners.................. $ 2,281 $ 25,933
Commitments and Contingencies (Note 5)
Partners' Capital:
Co-Managing General Partners' capital.................... $ 94,780 14,658 16,776
Participants' capital.................................... 477,010 390,113 342,887
-------- -------- ---------
Total Partners' Capital.......................... 571,790 404,771 359,663
-------- -------- ---------
Total Liabilities and Partners' Capital.......... $571,790 $407,052 $ 385,596
======== ======== ========
</TABLE>
See accompanying notes to financial statements.
F-30
<PAGE> 175
BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P.
STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
THREE MONTHS
YEARS ENDED DECEMBER 31, ENDED MARCH 31,
------------------------------ -------------------
1992 1993 1994 1994 1995
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues
Oil and gas sales......................... $214,854 $199,399 $158,875 $ 40,923 $ 30,766
Other income.............................. 10,606 3,981 1,538 599 15
-------- -------- -------- -------- --------
225,460 203,380 160,413 41,522 30,781
-------- -------- -------- -------- --------
Expenses
Lease operating costs and production
taxes.................................. 73,309 76,855 79,479 14,433 15,203
Exploration costs......................... 1,627 1,891 789
Depletion, impairment and amortization.... 111,050 72,453 77,895 21,880 42,934
General and administrative................ 32,110 38,432 33,654 18,469 17,752
-------- -------- -------- -------- --------
218,096 189,631 191,817 54,782 75,889
-------- -------- -------- -------- --------
Net Income (Loss)...................... $ 7,364 $ 13,749 $(31,404) $(13,260) $(45,108)
======== ======== ======== ======== ========
</TABLE>
See accompanying notes to financial statements.
F-31
<PAGE> 176
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) THREE MONTHS ENDED MARCH 31, 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).............................. 2,118 (47,226) (45,108)
----------- ------------ ----------
Balance, March 31, 1995 (unaudited)........................ $ 16,776 $ 342,887 $ 359,663
========== ========= =========
</TABLE>
See accompanying notes to financial statements.
F-32
<PAGE> 177
BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P.
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
THREE MONTHS
YEARS ENDED DECEMBER 31, ENDED MARCH 31,
--------------------------------- ---------------------
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) $(13,260) $(45,108)
Adjustments to reconcile net income
(loss) to net cash provided by (used
in) operating activities:
Depletion and amortization........ 111,050 72,453 77,895 21,880 42,934
Decrease in accounts payable...... (1,000)
--------- --------- --------- -------- --------
Net cash provided by (used
in) operating activities... 117,414 86,202 46,491 8,620 (2,174)
--------- --------- --------- -------- --------
Cash flows from investing activities:
Expenditures on oil and gas
properties........................ (38,469) (56,330) (33,047) (1,549) (17,925)
--------- --------- --------- -------- --------
Net cash used in investing
activities...................... (38,469) (56,330) (33,047) (1,549) (17,925)
--------- --------- --------- -------- --------
Cash flows from financing activities:
Net (increase) decrease in receivable
from Co-Managing General
Partners.......................... (38,908) 12,744 13,535 1,890
Net increase in payable to
Co-Managing General Partners...... 2,281 23,651
Partner distributions................ (281,818) (169,936) (135,615) (15,218)
--------- --------- --------- -------- --------
Net cash provided by (used in)
financing activities............ (320,726) (157,192) (119,799) (13,328) 23,651
--------- --------- --------- -------- --------
Net increase (decrease) in cash........ (241,781) (127,320) (106,355) (6,257) 3,552
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 $106,499 $ 9,953
========= ========= ========= ======== ========
</TABLE>
See accompanying notes to financial statements.
F-33
<PAGE> 178
BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P.
NOTES TO FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1992, 1993 AND 1994
AND (UNAUDITED) THREE MONTHS ENDED MARCH 31, 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.
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.
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
March 31, 1995, and the results of operations for the three month periods ended
March 31, 1995 and 1994.
The results of operations for the three month period ended March 31, 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.
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.
F-34
<PAGE> 179
BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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 at March 31, 1995 to reflect the excess of
book value at that date over the adjusted sales price of $375,643. The adjusted
sales price has been reflected as property held for sale at March 31, 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>
Results of operations for oil and gas producing activities were:
<TABLE>
<CAPTION>
1992 1993 1994
--------- --------- ---------
<S> <C> <C> <C>
Oil and gas revenues............................ $ 214,854 $ 199,399 $ 158,875
--------- --------- ---------
Expenses:
Lease operating costs and production taxes.... 73,309 76,855 79,479
Depletion..................................... 108,513 69,916 76,203
Exploration costs, including dry hole costs... 1,627 1,891 789
--------- --------- ---------
Total Expenses............................. 183,449 148,662 156,471
--------- --------- ---------
Results of operations from oil and gas producing
activities.................................... $ 31,405 $ 50,737 $ 2,404
========= ========= =========
</TABLE>
F-35
<PAGE> 180
BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
QUANTITIES OF OIL AND GAS RESERVES (UNAUDITED)
Proved reserves are estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable from known reservoirs under existing
economic and operating conditions. Proved developed reserves are those which are
expected to be recovered through existing wells with existing equipment and
operating methods.
The evaluations of the oil and gas reserves were prepared by J.C. White, an
independent petroleum engineer until January 1, 1993, when he became an employee
of Benton.
<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
F-36
<PAGE> 181
BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVE QUANTITIES (UNAUDITED)
The standardized measure of discounted future net cash flows is presented
in accordance with the provisions of SFAS No. 69. In preparing this data,
assumptions and estimates have been used, and Benton cautions against viewing
this information as a forecast of future economic conditions.
Future cash inflows were estimated by applying year-end prices, adjusted
for fixed and determinable escalations provided by contract, to the estimated
future production of year-end proved reserves. Future cash inflows were reduced
by estimated future production and development costs to determine pre-tax cash
inflows. The resultant future net cash inflows are discounted using a ten
percent discount rate.
<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>
F-37
<PAGE> 182
BENTON OIL & GAS COMBINATION PARTNERSHIP 1989-1, 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..................................... $ 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-38
<PAGE> 183
BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P.
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Independent Auditors' Report.......................................................... F-38
Balance Sheets at December 31, 1993 and 1994 and March 31, 1995....................... F-39
Statements of Operations for the Years Ended December 31, 1992, 1993 and 1994 and the
Three Months Ended March 31, 1994 and 1995.......................................... F-40
Statements of Partners' Capital for the Years Ended December 31, 1992, 1993 and 1994
and the Three Months Ended March 31, 1995........................................... F-41
Statements of Cash Flows for the Years Ended December 31, 1992, 1993 and 1994 and the
Three Months Ended March 31, 1994 and 1995.......................................... F-42
Notes to Financial Statements for the Years Ended December 31, 1992, 1993 and 1994 and
the Three Months Ended March 31, 1994 and 1995...................................... F-43
</TABLE>
F-39
<PAGE> 184
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-40
<PAGE> 185
BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P.
BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------- MARCH 31,
1993 1994 1995
---------- ---------- ----------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
Current Assets:
Cash................................................. $ 419,826 $ 17,859 $ 57,016
Receivable from Co-Managing General Partners......... 40,291 36,882 86,823
Marketable equity securities......................... 5,407
Property held for sale (Note 4)...................... 146,900 1,030,154
---------- ---------- ----------
Total Current Assets.............................. 465,524 201,641 1,173,993
Oil and Gas Properties (net of accumulated depletion of
$1,421,548, $1,614,158 and $974,136, respectively)... 1,398,850 1,152,597 118,701
Organization Costs (net of accumulated amortization of
$7,772, $9,941 and $10,483, respectively)............ 3,071 902 360
---------- ---------- ----------
Total Assets...................................... $1,867,445 $1,355,140 $1,293,054
========= ========= =========
PARTNERS' CAPITAL
Commitments and Contingencies (Note 5)
Partners' Capital:
Co-Managing General Partners' capital................ $ 436,921 $ 111,441 $ 112,695
Participants' capital................................ 1,429,384 1,240,417 1,176,276
Special Limited Partners' Capital.................... 1,140 3,282 4,083
---------- ---------- ----------
Total Partners' Capital........................... $1,867,445 $1,355,140 $1,293,054
========= ========= =========
</TABLE>
See accompanying notes to financial statements.
F-41
<PAGE> 186
BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P.
STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
THREE MONTHS
YEARS ENDED DECEMBER 31, ENDED MARCH 31,
------------------------------------- ---------------------
1992 1993 1994 1994 1995
----------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues
Oil and gas sales............... $ 735,886 $630,682 $518,728 $127,692 $ 96,442
Other income.................... 34,631 14,777 6,058 2,304 181
----------- -------- -------- -------- --------
770,517 645,459 524,786 129,996 96,623
----------- -------- -------- -------- --------
Expenses
Lease operating costs and
production taxes............. 285,840 254,903 263,957 48,007 50,961
Exploration costs............... 8,952 9,570 6,607 1,169 893
Loss on sale of oil and gas
properties................... 57,586 1,328
Depletion, impairment and
amortization................. 1,560,665 189,309 224,635 56,795 68,276
General and administrative...... 69,510 99,967 78,547 29,314 37,251
----------- -------- -------- -------- --------
1,982,553 553,749 573,746 135,285 158,709
----------- -------- -------- -------- --------
Net Income (Loss)............ $(1,212,036) $ 91,710 $(48,960) $ (5,289) $(62,086)
========== ======== ======== ======== ========
</TABLE>
See accompanying notes to financial statements.
F-42
<PAGE> 187
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) THREE MONTHS ENDED MARCH 31, 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)....... 1,254 (64,141) 801 (62,086)
---------------- ------------ ---------------- ----------
Balance, March 31, 1995
(unaudited)....................... $ 112,695 $ 1,176,276 $ 4,083 $1,293,054
============ ========== ============ =========
</TABLE>
See accompanying notes to financial statements.
F-43
<PAGE> 188
BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P.
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
THREE MONTHS
YEARS ENDED DECEMBER 31, ENDED MARCH 31,
----------------------------------- -------------------
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) $ (5,289) $(62,086)
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities:
Depletion, impairment and
amortization...................... 1,560,665 189,309 224,635 56,795 68,276
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
----------- --------- --------- -------- --------
Net cash provided by operating
activities........................ 407,453 290,032 173,410 51,506 7,518
----------- --------- --------- -------- --------
Cash flows from investing activities:
Expenditures on oil and gas
properties.......................... (151,217) (179,512) (123,113) (14,894) (65,320)
Proceeds from sale of marketable equity
securities.......................... 7,672
Proceeds from sale of oil and gas
properties.......................... 26,485
----------- --------- --------- -------- --------
Net cash provided by (used in)
investing activities.............. (124,732) (179,512) (115,441) (14,894) (65,320)
----------- --------- --------- -------- --------
Cash flows from financing activities:
Net (increase) decrease in receivable
from Co-Managing General Partners... (12,415) 36,387 3,409 (8,895) 96,959
Decrease in receivable from
Affiliate........................... 451,447
Decrease in payable to Affiliate....... (50,000)
Partner distributions.................. (1,071,312) (604,582) (463,345) (31,222)
----------- --------- --------- -------- --------
Net cash provided by (used in)
financing activities.............. (682,280) (568,195) (459,936) (40,117) 96,959
----------- --------- --------- -------- --------
Net increase (decrease) in cash.......... (399,559) (457,675) (401,967) (3,505) 39,157
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 $416,321 $ 57,016
========== ========= ========= ======== ========
</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-44
<PAGE> 189
BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P.
NOTES TO FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1992, 1993 AND 1994
AND (UNAUDITED) THREE MONTHS ENDED MARCH 31, 1994 AND 1995
NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization
Benton Oil & Gas Combination Partnership 1990-1, L.P. (Partnership) was
formed to invest in oil and natural gas by acquiring proven producing
properties, recompleting previously drilled wells and developing and drilling
new wells.
Benton Oil and Gas Company (Benton) and a wholly owned subsidiary are the
Co-Managing General Partners and as such conduct, direct and exercise full
control over all activities of the Partnership.
Marketable Equity Securities
Marketable equity securities are stated at the lower of aggregate cost or
market. At December 31, 1993, the cost of marketable equity securities was
$14,420 with a valuation allowance of $9,013 for an approximate market value of
$5,407. Marketable equity securities were sold in November 1994 for $7,672 for a
realized gain of $2,265.
Oil and Gas Properties
Oil and gas properties are accounted for using the successful efforts
method. Under this method, costs of drilling exploratory wells are initially
capitalized pending determination of whether the well can produce proved
reserves. All costs relating to nonproductive exploratory wells are expensed.
Costs relating to productive exploratory wells and all development wells are
capitalized and depleted on a units-of-production basis over the life of the
remaining proved developed reserves. Delay rentals and geological and
geophysical costs are expensed as incurred.
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.
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
March 31, 1995, and the results of operations for the three month periods ended
March 31, 1995 and 1994.
The results of operations for the three month period ended March 31, 1995
are not necessarily indicative of the results to be expected for the full year.
NOTE 2 -- PARTICIPATION IN COSTS AND REVENUES
Under the terms of the Partnership agreement, the general and limited
partners (Participants) pay 99% of the lease acquisition, geophysical and
seismic costs, well costs, and organization and offering expenses, 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
F-45
<PAGE> 190
BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Co-Managing General Partners. Revenues and production taxes are allocated
73.5974% to the Participants, 25.5236% to the Co-Managing General Partners and
0.879% to broker/dealers (Special Limited Partners) who met certain minimum
sales requirements in the initial offering of the Partnership units.
NOTE 3 -- RELATED PARTY TRANSACTIONS
The Partnership pays the Co-Managing General Partners for general and
administrative expenses, lease operating expenses and well costs incurred on
behalf of the Partnership. Benton pays the Partnership for revenues collected on
behalf of the Partnership.
NOTE 4 -- OIL AND GAS PROPERTIES
During 1992, a provision for impairment of oil and gas properties was made
to reflect reductions in the estimated value of reserves.
In April 1992, a working interest in a California well was sold. Proceeds
from the sale of the Partnership's interest were $17,881, consisting of cash and
stock of the company purchasing the well. In addition, the Partnership retained
a production payment of $8,845 to be paid from monthly net income from the well.
In September 1992, the Partnership's interest in its remaining California
oil and gas wells were sold for net proceeds of $19,386.
In March 1995, the Partnership sold its 0.32% working interest in certain
depths (above approximately 10,575 feet) in the West Cote Blanche Bay Field for
a purchase price of $146,900. The sales price has been reflected as property
held for sale at December 31, 1994. Impairment of $13,569 has been recorded to
reflect the anticipated loss in connection with the sale of the property.
In June 1995, the Partnership entered into an agreement to sell its
principal oil and gas properties. The sales price is subject to adjustments for
revenues, expenses and capital expenditures related to the properties until the
closing date. The agreement is subject to the approval of 75% of the partners.
The adjusted sales price as of March 31, 1995 is $1,081,589 and the net book
value of the property has been reflected as property held for sale at March 31,
1995.
NOTE 5 -- COMMITMENTS AND CONTINGENCIES
On June 13, 1994, certain limited partners of the Partnership, with limited
partners of other Benton partnerships, brought an action against Benton in
connection with its operation of the partnerships as managing general partner.
The parties have agreed to submit the dispute to arbitration and the lawsuit has
been dismissed. The plaintiffs seek actual and punitive damages for alleged
actions and omissions of Benton in connection with operating the partnerships
and alleged misrepresentations made by Benton in selling the limited partnership
interests. At this time, the Partnership has not been named a defendant in this
action. However, if the Partnership is added as a defendant, the Partnership
would be forced to expend financial resources to defend or resolve any such
matters. Benton does not believe that the Partnership will be adversely affected
by this action.
F-46
<PAGE> 191
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>
Results of operations for oil and gas producing activities were:
<TABLE>
<CAPTION>
1992 1993 1994
----------- -------- --------
<S> <C> <C> <C>
Oil and gas revenues............................. $ 735,886 $630,682 $518,728
----------- -------- --------
Expenses:
Lease operating costs and production taxes..... 285,840 254,903 263,957
Depletion...................................... 809,273 187,140 208,897
Impairment..................................... 749,223 13,569
Exploration costs, including dry hole costs.... 8,952 9,570 6,607
----------- -------- --------
Total Expenses.............................. 1,853,288 451,613 493,030
----------- -------- --------
Results of operations from oil and gas producing
activities..................................... $(1,117,402) $179,069 $ 25,698
========== ======== ========
</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-47
<PAGE> 192
BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, 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 ............................ 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>
- ---------------
(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 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
F-48
<PAGE> 193
BENTON OIL & GAS COMBINATION PARTNERSHIP 1990-1, 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. Also,
additional production data at West Cote Blanche Bay enabled Benton to better
conform estimates of future production to historical trends.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVE QUANTITIES (UNAUDITED)
The standardized measure of discounted future net cash flows is presented
in accordance with the provisions of SFAS No. 69. In preparing this data,
assumptions and estimates have been used, and Benton cautions against viewing
this information as a forecast of future economic conditions.
Future cash inflows were estimated by applying year-end prices, adjusted
for fixed and determinable escalations provided by contract, to the estimated
future production of year-end proved reserves. Future cash inflows were reduced
by estimated future production and development costs to determine pre-tax cash
inflows. The resultant future net cash inflows are discounted using a ten
percent discount rate.
<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-49
<PAGE> 194
BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P.
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Independent Auditors' Report........................................................ F-49
Balance Sheets at December 31, 1993 and 1994 and March 31, 1995..................... F-50
Statements of Operations for the Years Ended December 31, 1992, 1993 and 1994 and
the Three Months Ended March 31, 1994 and 1995.................................... F-51
Statements of Partners' Capital for the Years Ended December 31, 1992, 1993 and 1994
and the Three Months Ended March 31, 1995......................................... F-52
Statements of Cash Flows for the Years Ended December 31, 1992, 1993 and 1994 and
the Three Months Ended March 31, 1994 and 1995.................................... F-53
Notes to Financial Statements for the Years Ended December 31, 1992, 1993 and 1994
and the Three Months Ended March 31, 1994 and 1995................................ F-54
</TABLE>
F-50
<PAGE> 195
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-51
<PAGE> 196
BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P.
BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------- MARCH 31,
1993 1994 1995
-------- -------- ---------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
Current Assets:
Cash..................................................... $177,180 $ 60,170 $ 63,899
Receivable from Co-Managing General Partners............. 4,958 7,897 17,460
Marketable equity securities............................. 5,407
Property held for sale (Note 4).......................... 29,200 215,280
-------- -------- ---------
Total Current Assets.................................. 187,545 97,267 296,639
Oil and Gas Properties (net of accumulated depletion of
$138,392, $192,942 and $23,031, respectively)............ 441,188 340,737 46,361
Organization Costs (net of accumulated amortization of
$2,308, $3,231 and $3,462, respectively)................. 2,308 1,385 1,155
-------- -------- ---------
Total Assets.......................................... $631,041 $439,389 $ 344,155
======== ======== ========
PARTNERS' CAPITAL
Commitments and Contingencies (Note 5)
Partners' Capital:
Co-Managing General Partners' capital.................... $ 50,358 $ 13,601 $ 11,946
Participants' capital.................................... 580,591 425,503 331,854
Special Limited Partners' Capital........................ 92 285 355
-------- -------- ---------
Total Partners' Capital............................... $631,041 $439,389 $ 344,155
======== ======== ========
</TABLE>
See accompanying notes to financial statements.
F-52
<PAGE> 197
BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P.
STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
THREE MONTHS
YEARS ENDED DECEMBER 31, ENDED MARCH 31,
---------------------------------- ---------------------
1992 1993 1994 1994 1995
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues
Oil and gas sales................. $129,990 $107,181 $ 96,034 $ 22,815 $ 18,045
Other income...................... 30,331 5,343 2,610 938 385
-------- -------- -------- -------- --------
160,321 112,524 98,644 23,753 18,430
-------- -------- -------- -------- --------
Expenses
Lease operating costs and
production taxes............... 40,093 36,276 38,002 6,264 6,596
Exploration costs................. 7,245 1,284 769 233 178
Loss on sale of oil and gas
property....................... 61,225 225
Depletion, impairment and
amortization................... 65,241 60,503 95,497 16,350 92,063
General and administrative........ 28,876 45,195 28,823 18,395 14,602
-------- -------- -------- -------- --------
202,680 143,258 163,091 41,242 113,664
-------- -------- -------- -------- --------
Net Loss....................... $(42,359) $(30,734) $(64,447) $(17,489) $(95,234)
======== ======== ======== ======== ========
</TABLE>
See accompanying notes to financial statements.
F-53
<PAGE> 198
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) THREE MONTHS ENDED MARCH 31, 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)................ (1,655) (93,649) 70 (95,234)
----------- ------------ -------- ---------
Balance, March 31, 1995 (unaudited).......... $ 11,946 $ 331,854 $ 355 $ 344,155
========== ========= ======= =========
</TABLE>
See accompanying notes to financial statements.
F-54
<PAGE> 199
BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P.
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
THREE MONTHS
YEARS ENDED DECEMBER 31, ENDED MARCH 31,
--------------------------------------- ---------------------
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) $(17,489) $(95,234)
Adjustments to reconcile net
loss to net cash provided
by (used in) operating
activities:
Depletion, impairment and
amortization............. 65,241 60,503 95,497 16,350 92,063
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
----------- --------- --------- -------- --------
Net cash provided by (used
in) operating
activities............... 85,839 38,782 28,758 (1,139) (2,946)
----------- --------- --------- -------- --------
Cash flows from investing
activities:
Expenditures on oil and gas
properties................. (32,154) (35,786) (23,323) (2,965) (12,962)
Proceeds from sale of
marketable equity
securities................. 7,699
Proceeds from sale of oil and
gas properties............. 3,461
----------- --------- --------- -------- --------
Net cash provided by (used in)
investing activities....... (28,693) (35,786) (15,624) (2,965) (12,962)
----------- --------- --------- -------- --------
Cash flows from financing
activities:
Net (increase) decrease in
receivable from Co-Managing
General Partners........... (449,926) 12,283 (2,939) 6,886 19,637
Decrease in payable to
Affiliate.................. (451,446)
Partner distributions......... (111,600) (115,292) (127,205) (28,183)
----------- --------- --------- -------- --------
Net cash used in financing
activities............... (1,012,972) (103,009) (130,144) (21,297) 19,637
----------- --------- --------- -------- --------
Net increase (decrease) in
cash.......................... (955,826) (100,013) (117,010) (25,401) 3,729
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 $151,779 $ 63,899
========== ========= ========= ======== ========
</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 on financial statements.
F-55
<PAGE> 200
BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P.
NOTES TO FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1992, 1993 AND 1994
AND (UNAUDITED) THREE MONTHS ENDED MARCH 31, 1994 AND 1995
NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization
Benton Oil & Gas Combination Partnership 1991-1, L.P. (Partnership) was
formed to invest in oil and natural gas by acquiring proven producing
properties, enhancing production of previously drilled wells and drilling new
wells.
Benton Oil and Gas Company (Benton) and a wholly owned subsidiary are the
Co-Managing General Partners and as such conduct, direct and exercise full
control over all activities of the Partnership.
Marketable Equity Securities
Marketable equity securities are stated at the lower of aggregate cost or
market. At December 31, 1993, the cost of marketable equity securities was
$14,420 with a valuation allowance of $9,013 for an approximate market value of
$5,407. Marketable equity securities were sold in November 1994 for $7,699 for a
realized gain of $2,292.
Oil and Gas Properties
Oil and gas properties are accounted for using the successful efforts
method. Under this method, costs of drilling exploratory wells are initially
capitalized pending determination of whether the well can produce proved
reserves. All costs relating to nonproductive exploratory wells are expensed.
Costs relating to productive exploratory wells and all development wells are
capitalized and depleted on a units-of-production basis over the life of the
remaining proved developed reserves. Delay rentals and geological and
geophysical costs are expensed as incurred.
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.
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
March 31, 1995, and the results of operations for the three month periods ended
March 31, 1995 and 1994.
The results of operations for the three month period ended March 31, 1995
are not necessarily indicative of the results to be expected for the full year.
NOTE 2 -- PARTICIPATION IN COSTS AND REVENUES
Under the terms of the Partnership agreement, the general and limited
partners (Participants) pay 99% of the lease acquisition, geophysical and
seismic costs, well costs, and organization and offering expenses, 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-
F-56
<PAGE> 201
BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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 at March 31, 1995 to reflect the excess of
book value at that date over the sales price of $215,280. The adjusted sales
price has been reflected as property held for sale at March 31, 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-57
<PAGE> 202
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>
Results of operations for oil and gas producing activities were:
<TABLE>
<CAPTION>
1992 1993 1994
-------- -------- --------
<S> <C> <C> <C>
Oil and gas revenues............................... $129,990 $107,181 $ 96,034
-------- -------- --------
Expenses:
Lease operating costs and production taxes....... 40,093 36,276 38,002
Depletion........................................ 64,318 59,580 60,203
Impairment....................................... 34,371
Exploration costs, including dry hole costs...... 7,245 1,284 769
-------- -------- --------
Total Expenses................................ 111,656 97,140 133,345
-------- -------- --------
Results of operations from oil and gas producing
activities....................................... $ 18,334 $ 10,041 $(37,311)
======== ======== ========
</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-58
<PAGE> 203
BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, 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............................... 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>
- ---------------
(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 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
F-59
<PAGE> 204
BENTON OIL & GAS COMBINATION PARTNERSHIP 1991-1, 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. Also,
additional production data at West Cote Blanche Bay enabled Benton to better
conform estimates of future production to historical trends.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVE QUANTITIES (UNAUDITED)
The standardized measure of discounted future net cash flows is presented
in accordance with the provisions of SFAS No. 69. In preparing this data,
assumptions and estimates have been used, and Benton cautions against viewing
this information as a forecast of future economic conditions.
Future cash inflows were estimated by applying year-end prices, adjusted
for fixed and determinable escalations provided by contract, to the estimated
future production of year-end proved reserves. Future cash inflows were reduced
by estimated future production and development costs to determine pre-tax cash
inflows. The resultant future net cash inflows are discounted using a ten
percent discount rate.
<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>
<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-60
<PAGE> 205
EXHIBIT A
WARRANT AGREEMENT
BETWEEN
BENTON OIL AND GAS COMPANY
AND
DATED AS OF , 1995
-------------------
<PAGE> 206
WARRANT AGREEMENT dated as of __________________, 1995, 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 in the Agreement set forth 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
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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. 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
9 hereof at any time from 9:00 A.M., Los Angeles time,
on __________________, 1995 until 5:00 P.M., Los Angeles time,
on _________________, 1998 (the "Expiration Date") at a purchase
price of $_________ per share.
(b) The Warrant Price and the number of shares issuable
upon exercise of Warrants are subject to adjustment upon the
occurrence of certain events, pursuant to the provisions of Section 9
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.
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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 11 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 10 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.
4.1. 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.
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5. PAYMENT OF TAXES. The Company will pay all documentary stamp
taxes, if any, attributable to the initial issuance of Warrant Shares upon the
exercise of Warrants and any securities issued pursuant to Section 8 hereof;
PROVIDED, HOWEVER, that the Company shall not be required to pay any tax or
taxes which may be payable in respect of any transfer involved in the issue or
delivery of any Warrants or certificates for Warrant Shares and any securities
issued pursuant to Section 8 hereof in a name other than that of the Holder of
such Warrants.
6. MUTILATED OR MISSING WARRANTS. In case any of the Warrants
shall be mutilated, lost, stolen or destroyed, the Company may in its
discretion issue and deliver in exchange and substitution for and upon
cancellation of the mutilated Warrant, or in lieu of and in substitution for
the Warrant lost, stolen or destroyed, a new Warrant of like tenor and
representing an equivalent right or interest; but only upon receipt of evidence
reasonably satisfactory to the Company of such loss, theft or destruction of
such Warrant and indemnity or bond, if requested, also reasonably satisfactory
to the Company. An applicant for such substitute Warrants shall also comply
with such other reasonable regulations and pay such other reasonable charges as
the Company may prescribe.
7. RESERVATION OF WARRANT SHARES; PURCHASE AND CANCELLATION OF
WARRANTS. There have been reserved out of the authorized and unissued shares
of Common Stock, a number of shares sufficient to provide for the exercise of
the rights of purchase represented by the Warrants, and the transfer agent for
the Common Stock ("Transfer Agent") and every subsequent transfer agent for any
shares of the Company's capital stock issuable upon the exercise of any of the
rights of purchase aforesaid are hereby irrevocably authorized and directed at
all times until the Expiration Date to reserve such number of authorized and
unissued shares as shall be requisite for such purpose. The Company will keep
a copy of this Agreement on file with the Transfer Agent and with every
subsequent transfer agent for any shares of the Company's capital stock
issuable upon the exercise of the rights of purchase represented by the
Warrants. The Company will supply the Transfer Agent and any such subsequent
transfer agent with duly executed stock certificates for such purpose and will
itself provide or otherwise 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 9.3 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
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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
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exercise of each Warrant by a fraction, of which the numerator
shall be the number of shares of Common Stock outstanding on the date
of issuance of such rights, options or warrants plus the number of
additional shares of Common Stock offered for subscription or
purchase, and of which the denominator shall be the number of shares
of Common Stock outstanding on the date of issuance of such rights,
options or warrants plus the number of shares which the aggregate
offering price of the total number of shares of common stock so
offered would purchase at the current market price per share of Common
Stock at such record date. Such adjustment shall be made whenever
such rights, options or warrants are issued, and shall become
effective immediately after the record date for the determination of
stockholders entitled to receive such rights, options or warrants.
(c) In case the Company shall distribute to all holders
of its shares of Common Stock evidences of its indebtedness or assets
(excluding cash dividends or distributions payable out of consolidated
earnings or earned surplus and dividends or distributions referred to
in paragraph (a) above or in the paragraph immediately following this
paragraph) or rights, options or warrants, or convertible or
exchangeable securities containing the right to subscribe for or
purchase shares of Common Stock (excluding those referred to in
paragraph (b) above), then in each case the number of Warrant Shares
thereafter purchasable upon the exercise of each Warrant shall be
determined by multiplying the number of Warrant Shares theretofore
purchasable upon the exercise of each Warrant by a fraction, of which
the numerator shall be the then current market price per share of
Common Stock (as determined in accordance with paragraph (e) below) on
the date of such distribution, and of which the denominator shall be
the then current market price per share of Common Stock, less the then
fair value (as determined in good faith by the Board of Directors of
the Company, whose determination shall be conclusive) of the portion
of the assets or evidences of indebtedness so distributed or of such
subscription rights, options or warrants, or of such convertible or
exchangeable 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,
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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 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 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
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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 American Stock Exchange.
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 reasonably related to the closing market price on the date of
such
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determination; and (c) with respect to any issuance of the
Company's common stock for cash or similar consideration in a firm
commitment underwriting, the current fair market price shall be the
price the shares are sold at, regardless of whether such price is
higher or lower than the quoted price on the date of the sale and
therefore no adjustment will be made.
(f) In any case in which this Section 8.1 shall require
that any adjustment in the number of Warrant Shares be made effective
as of immediately after a record date for a specified event, the
Company may elect to defer until the occurrence of the event the
issuing to the Holder of any Warrant exercised after that record date
the shares of Common Stock and other securities of the Company, if
any, issuable upon the exercise of any Warrant over and above the
shares of Common Stock and other securities of the Company, if any,
issuable upon the exercise of any Warrant prior to such adjustment;
PROVIDED, HOWEVER, that the Company shall deliver to the holder a due
bill or other appropriate instrument evidencing the holder's right to
receive such additional shares or securities upon the occurrence of
the event requiring such adjustment.
(g) No adjustment in the number of Warrant Shares
purchasable hereunder shall be required unless such adjustment would
require an increase or decrease of at least one percent (1%) in the
number of Warrant Shares purchasable upon the exercise of each
Warrant; PROVIDED, HOWEVER, that any adjustments which by reason of
this paragraph (g) are not required to be made shall be carried
forward and taken into account in any subsequent adjustment. All
calculations shall be made to the nearest one-thousandth of a share.
(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
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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 5 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.
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8.2. VOLUNTARY ADJUSTMENT BY THE COMPANY. The Company may, at its
option, at any time during the term of the Warrants, reduce the then current
Warrant Price to any amount determined appropriate by the Board of Directors of
the Company.
8.3. NOTICE OF ADJUSTMENT. Whenever the number of Warrant Shares
purchasable upon the exercise of each Warrant or the Warrant Price of such
Warrant Shares is adjusted, as herein provided, the Company shall promptly mail
by first class, postage prepaid, to each Holder notice of such adjustment or
adjustments and a certificate of a firm of independent public accountants
selected by the Board of Directors of the Company (who may be the regular
accountants employed by the Company) setting forth the number of Warrant Shares
purchasable upon the exercise of each Warrant and the Warrant Price of such
Warrant Shares after such adjustment and setting forth a brief statement of the
facts requiring such adjustment and setting forth the computation by which such
adjustment was made. Such certificate, absent manifest error, shall be
conclusive evidence of the correctness of such adjustment.
8.4. NO ADJUSTMENT FOR DIVIDENDS. Except as provided in Section
8.1, no adjustment in respect of any dividends shall be made during the term of
a Warrant or upon the exercise of a Warrant.
8.5. PRESERVATION OF PURCHASE RIGHTS UPON MERGER, CONSOLIDATION,
ETC. In case of any consolidation of the Company 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 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.
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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.
11. NO RIGHTS AS STOCKHOLDERS; NOTICE TO HOLDERS. Nothing
contained in this Agreement or in any of the Warrants shall be construed as
conferring upon the Holders or their transferees the right to vote or to
receive dividends or to consent or to receive notice as stockholders in respect
of any meeting of stockholders for the election of directors of the Company or
any other matter, or any rights whatsoever as stockholders of the Company. If,
however, at any time prior to the expiration of the Warrants and prior to their
exercise, any of the following events shall occur:
(a) the Company shall declare any dividend payable in any
securities upon its shares of Common Stock or make any distribution
(other than a cash dividend) to the holders of its shares of Common
Stock; or
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(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 15 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
<PAGE> 219
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.
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.
14
<PAGE> 220
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
15
<PAGE> 221
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> 222
Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995
Page Two
The Society of Petroleum Engineers (SPE) requires Proved reserves to be
economically recoverable with costs and prices in effect on the "as of" date of
the report. In addition, the SPE has issued Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserve Information which sets standards
for the qualification and independence of reserve estimators and auditors and
accepted methods for estimating and scheduling future reserves.
In our opinion, both the audit performed by huddleston and the estimates
prepared by Benton have been performed in accordance with all applicable SEC,
FASB, and SPE regulations and requirements. It should be noted that the
reserve estimates shown herein are consistent with estimates prepared by Benton
as of January 1, 1995.
REPORT PREPARATION
- ------------------
The estimated reserves and revenues provided for this review were initially
prepared by Benton and have been reviewed in detail by our firm for the
purposes of this audit. Where there were significant differences in the
estimated reserves and revenues, Huddleston has suggested revisions in the
Benton estimates and Benton has revised its projections accordingly. In our
opinion, estimates for the properties, individually and in aggregate, are not
materially different from those which would have been rendered by Huddleston
had we independently projected the reserve volumes.
In performing our audit we have utilized certain geological and petrophysical
studies which were prepared by Benton and representatives of the current and
previous operators. We have reviewed these studies and have found them to be
reasonable with respect to the subject reservoirs; however, we have not
attempted to independently prepare geological interpretations or estimates of
reservoir parameters. In some cases we have utilized information from our
files relating to previous studies of certain properties shown herein.
The projections which were reviewed for the purposes of this audit represent
100% of the total future revenues as projected by Benton. Huddleston has not
attempted to review projections for the remaining properties in detail;
however, these properties have not been assigned any future reserves. We do
not believe that a review of these properties would result in a material
revision of the total estimated reserves and revenues.
The projections shown herein were based on performance data from public sources
available in June 1994; however, data of this type is subject to delays as a
result of regulatory reporting requirements and the timing of the commercial
sources providing such data.
The cash flow projections were prepared utilizing a commercially available
software package marketed by David P. Cook & Associates. We have generally
reviewed the output of the calculation procedures utilized by the program and
believe them to be mathematically correct for the purposes of this audit.
PRODUCT PRICES
- --------------
It is our understanding that SEC regulations require future revenues to be
projected on the basis of product prices in effect on the "as of" date of the
report without further escalations or reductions. However, certain variations
in product prices, attributable to contractual provisions, may be utilized in
the preparation of the cash flows where the prices are specified by the
contract.
<PAGE> 223
Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995
Page Three
The projections shown herein have been based on actual prices being received on
December 31, 1994. These prices were held constant over the life of the
properties.
Market prices for both oil and gas continue to be subject to a significant
degree of variation in both domestic and international markets and reductions
in the market prices for oil volumes have materially affected the value of our
previous reserve estimates.
A comparison of the average product prices, weighted as a composite for all
properties, is as follows:
<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.
<PAGE> 224
Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995
Page Four
The reserve estimates for the properties owned by the Partnership will be
subject to a significant degree of variation due to the nature of the producing
reservoirs and the stage of depletion of the properties.
OPERATING AND CAPITAL COSTS
- ---------------------------
Huddleston has reviewed operating costs utilized by Benton and believes they
are appropriate for the subject properties. Severance and ad valorem taxes
were deducted from gross revenues in accordance with statutory rates. All
taxes (excluding income taxes) were estimated by Benton and have been deducted
from future revenues.
All capital costs were based on information provided by Benton. Huddleston has
generally reviewed these costs and believes they are reasonable with respect to
the proposed operations and properties.
All capital and operating expenditures were held constant over the life of the
properties.
FACTORS NOT INCLUDED
- --------------------
Values were not assigned to nonproducing acreage or to the salvage of surface
and subsurface equipment.
General office overhead, income taxes, and allowances for depletion,
depreciation, and amortization have not been deducted from future revenues.
REPORT QUALIFICATIONS
- ---------------------
THE ESTIMATED REVENUES AND PRESENT VALUE OF THESE REVENUES ARE NOT REPRESENTED
AS MARKET VALUE.
Estimates for individual completions should be considered in context with the
overall or total estimated revenues. Actual individual lease performances will
vary considerably from the projections particularly in comparison to the total
estimated production from all properties.
We did not inspect the properties or conduct independent well tests.
Ownership, product prices, and other factual data have been accepted as
represented by Benton. We have generally tested these data and believe the
information is correct.
Respectfully submitted,
Peter D. Huddleston, P.E.
PDH:JPK:dbw
<PAGE> 225
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
<FN>
Note: The nonproducing category includes behind pipe and shut-in categories.
</TABLE>
<PAGE> 226
Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995
Page Two
REPORTING REQUIREMENTS
- ----------------------
Securities and Exchange Commission (SEC) Regulation S-K, Item 102 and
Regulation S-X, Rule 4-10 and Financial Accounting Standards Board (FASB)
Statement No. 69 require oil and gas reserve information to be reported by
publicly held entities as supplemental financial data. These regulations and
standards provide for estimates of Proved reserves and associated revenues
discounted at 10% based on product prices being received on the effective date
of the report.
The Society of Petroleum Engineers (SPE) requires Proved reserves to be
economically recoverable with costs and prices in effect on the "as of" date of
the report. In addition, the SPE has issued Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserve Information which sets standards
for the qualifications and independence of reserve estimators and auditors and
accepted methods for estimating and scheduling future reserves.
In our opinion, both the audit performed by Huddleston, and the estimates
prepared by Benton have been performed in accordance with all applicable SEC,
FASB, and SPE regulations and requirements. It should be noted that the
reserve estimates shown herein are consistent with estimates prepared by Benton
as of January 1, 1995.
REPORT PREPARATION
- ------------------
The estimated reserves and revenues provided for this review were initially
prepared by Benton and have been reviewed in detail by our firm for the
purposes of this audit. Where there were significant differences in the
estimated reserves and revenues, Huddleston has suggested revisions in the
Benton estimates and Benton has revised its projections accordingly. In our
opinion, estimates for the properties, individually and in aggregate, are not
materially different from those which would have been rendered by Huddleston
had we independently projected the reserve volumes.
In performing our audit we have utilized certain geological and petrophysical
studies which were prepared by Benton and representatives of the current and
previous operators. We have reviewed these studies and have found them to be
reasonable with respect to the subject reservoirs; however, we have not
attempted to independently prepare geological interpretations or estimates of
reservoir parameters. In some cases we have utilized information from our
files relating to previous studies of certain properties shown herein.
The projections which were reviewed for the purposes of this audit represent
100% of the total future revenues as projected by Benton.
The projections shown herein were based on performance data derived from public
sources available in January 1995; however, data of this type is subject to
delays as a result of regulatory reporting requirements and the timing of the
commercial sources providing such data.
The cash flow projections were prepared utilizing a commercially available
software package marketed by David P. Cook & Associates. We have generally
reviewed the output of the calculation procedures utilized by the program and
believe them to be mathematically correct for the purposes of this audit.
<PAGE> 227
Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995
Page Three
PRODUCT PRICES
- --------------
It is our understanding that SEC regulations require future revenues to be
projected on the basis of product prices in effect on the "as of" date of the
report without further escalations or reductions. However, certain variations
in product prices, attributable to contractual provisions, may be utilized in
the preparation of the cash flows where the prices are specified by the
contract.
The projections shown herein were based on actual product prices being received
on December 31, 1994. These prices were held constant over the life of the
properties.
Market prices for both oil and gas continue to be subject to a significant
degree of variation in both domestic and international markets. Future
variations in the projected prices may materially affect our projections of
economically recoverable reserves and associated revenues.
A comparison of the average product prices, weighted as a composite for all
properties, is a follows:
<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.
PROPERTY SALE
- -------------
The projections shown herein reflect the divestiture of interests owned by the
partnership in the Shallow Oil Reservoirs in West Cote Blanche Bay Field which
was effective January 1, 1995. The partnership retained interests in the Gas
Cap Reservoirs in this property.
RESERVE ESTIMATES
- -----------------
Reserve estimates for the properties reviewed for the purpose of this audit
have been prepared with consideration of the available data and the nature of
the producing horizons. The projections have been based on performance data
for the existing completions, analogy to other completions in the subject
reservoirs, and volumetric calculations. Estimates prepared on the basis of
analogy and volumetric calculations will be subject to much greater variation
than those prepared for depletion drive reservoirs having established
production trends.
UMBRELLA POINT FIELD - This property operated by French Production,
Incorporated, is located in state waters offshore Chambers County, Texas, and
produces from multiple reservoirs. Projections for this property were based
primarily on the extrapolation of production data with consideration for water
cut and pressure information where available. We have also utilized
information from our files from previous studies prepared by our firm relating
to this property. In general, the productive reservoirs for this property are
in the latter stages of depletion and future recoveries may be influenced by
both mechanical and reservoir factors.
<PAGE> 228
Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995
Page Four
WEST COTE BLANCHE BAY FIELD - Estimated reserves for the gas cap reservoirs
have been assigned on the basis of volumetric calculations for eight horizons
ranging in depth from 9,000 to 12,000 feet in three fault blocks. The
volumetric calculations have been based on log-derived parameters and
geological interpretations prepared on the basis of subsurface information,
pressure information, and geophysical interpretations based on 3-D seismic
data. Subsequent to our previous review, revised geological interpretations
have resulted in the transfer of reserves for the 12,600' reservoir to location
1-A (#868) from well #720 with no change in the estimated recoverable reserves.
Additional recoverable reserves have been assigned to the 38 and 38A reservoirs
based on geologic interpretations with consideration for historical performance
data.
The projected reserves for the #831 gas well, 13,900' reservoir, have been
revised relative to our July 1, 1994, evaluation on the basis of performance
data to reflect an ultimate recovery of 6,400 MMcf. The remaining reserves for
this reservoir have been transferred to location 1- A (#868).
OTHER PROPERTIES - We have not attempted to independently prepare estimates of
future reserves for the remaining properties located in East Cameron Block 229
Field. However, we have reviewed the projections with consideration for
historical production levels. The Benton estimates are consistent with recent
rates of production and Benton has projected that the properties do not have
any additional economically recoverable reserves.
GENERAL CONCLUSIONS - On an overall basis, we have not encountered material
differences in our reserve estimates and those prepared by Benton. In cases
where we have encountered significant differences in estimated recoveries,
Benton has consented to the revision of its reserve estimates to be consistent
with projections by Huddleston. The projected reserves shown herein will be
subject to a significant level of variation due to the nature of the subject
reservoirs, the stage of depletion of the producing horizons, the reserve
estimation techniques, and the actual schedule of future remedial and
development operations.
Huddleston has relied on Benton to provide development schedules. The
scheduling of future operations will be influenced by a variety of factors
including economic and market conditions, political considerations,
availability of funds, alternative investment opportunities, leasehold
obligations, and internal decision making. Variations in the execution of
these development plans may have a material impact on the economic value of
both the discounted and undiscounted revenue streams.
OPERATING AND CAPITAL COSTS
- ---------------------------
Huddleston has reviewed operating costs utilized by Benton and believes they
are appropriate for the subject properties. Costs for all properties were
consistent with historical levels. Severance and ad valorem taxes were
deducted from gross revenues in accordance with statutory rates. All taxes
(excluding income taxes) were estimated by Benton and have been deducted from
future revenues.
All capital costs were based on information provided by Benton. Huddleston has
generally reviewed these costs and believes they are reasonable. The capital
costs shown for the remedial operations for West Cote Blanche Bay Field have
been adjusted to reflect the statistical success rates of remedial operations
and variations in the depth of the historical and proposed operations.
All capital and operating expenditures were held constant over the life of the
properties.
<PAGE> 229
Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995
Page Five
FACTORS NOT INCLUDED
- --------------------
Values were not assigned to nonproducing acreage or to the salvage of surface
and subsurface equipment.
General office overhead, income taxes, and allowances for depletion,
depreciation, and amortization have not been deducted from future revenues.
REPORT QUALIFICATIONS
- ---------------------
THE ESTIMATED REVENUES AND PRESENT VALUE OF THESE REVENUES ARE NOT REPRESENTED
AS MARKET VALUE.
Estimates for individual completions should be considered in context with the
overall or total estimated revenues. Actual individual lease performances will
vary considerably from the projections particularly in comparison to the total
estimated production from all properties.
We did not inspect the properties or conduct independent well tests.
Ownership, product prices, and other factual data have been accepted as
represented by Benton. We have generally tested these data and believe the
information is correct.
Respectfully submitted,
Peter D. Huddleston, P.E.
PDH:JPK:dbw
<PAGE> 230
Huddleston & Co., Inc.
Petroleum and Geological Engineers
1111 Fannin-Suite 1700
Houston, Texas 77002
---------------------
(713) 658-0248
March 8, 1995
Mr. A.E. Benton
Benton Oil and Gas Company
1145 Eugenia Place 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
<FN>
Note: The nonproducing category includes behind pipe and shut-in categories.
</TABLE>
<PAGE> 231
Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995
Page Two
REPORTING REQUIREMENTS
- ----------------------
Securities and Exchange Commission (SEC) Regulation S-K, Item 102 and
Regulation S-X, Rule 4-10 and Financial Accounting Standards Board (FASB)
Statement No. 69 require oil and gas reserve information to be reported by
publicly held entities as supplemental financial data. These regulations and
standards provide for estimates of Proved reserves and associated revenues
discounted at 10% based on product prices being received on the effective date
of the report.
The Society of Petroleum Engineers (SPE) requires Proved reserves to be
economically recoverable with costs and prices in effect on the "as of" date of
the report. In addition, the SPE has issued Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserve Information which sets standards
for the qualification and independence of reserve estimators and auditors and
accepted methods for estimating and scheduling future reserves.
In our opinion, both the audit performed by Huddleston, and the estimates
prepared by Benton have been performed in accordance with all applicable SEC,
FASB, and SPE regulations and requirements. It should be noted that the
reserve estimates shown herein are consistent with estimates prepared by Benton
as of January 1, 1995.
REPORT PREPARATION
- ------------------
The estimated reserves and revenues provided for this review were initially
prepared by Benton and have been reviewed in detail by our firm for the
purposes of this audit. Where there were significant differences in the
estimated reserves and revenues, Huddleston has suggested revisions in the
Benton estimates and Benton has revised its projections accordingly. In our
opinion, estimates for the properties, individually and in aggregate, are not
materially different from those which would have been rendered by Huddleston
had we independently projected the reserve volumes.
In performing our audit we have utilized certain geological and petrophysical
studies which were prepared by Benton and representatives of the current and
previous operators. We have reviewed these studies and have found them to be
reasonable with respect to the subject reservoirs; however, we have not
attempted to independently prepare geological interpretations or estimates of
reservoir parameters. In some cases we have utilized information from our
files relating to previous studies of certain properties shown herein.
The projections which were reviewed for the purposes of this audit represent
100% of the total future revenues as projected by Benton.
The projections shown herein were based on performance data derived from public
sources available in January 1995; however, data of this type is subject to
delays as a result of regulatory reporting requirements and the timing of the
commercial sources providing such data.
The cash flow projections were prepared utilizing a commercially available
software package marketed by David P. Cook & Associates. We have generally
reviewed the output of the calculation procedures utilized by the program and
believe them to be mathematically correct for the purposes of this audit.
<PAGE> 232
Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995
Page Three
PRODUCT PRICES
- --------------
It is our understanding that SEC regulations require future revenues to be
projected on the basis of product prices in effect on the "as of" date of the
report without further escalations or reductions. However, certain variations
in product prices, attributable to contractual provisions, may be utilized in
the preparation of the cash flows where the prices are specified by the
contract.
The projections shown herein have been based on actual prices being received on
December 31, 1994. These prices were held constant over the life of the
properties.
Market prices for both oil and gas continue to be subject to a significant
degree of variation in both domestic and international markets. Future
variations in the projected prices may materially affect our projections of
economically recoverable reserves and associated revenues.
A comparison of the average product prices, weighted as a composite for all
properties, is as follows:
<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
- -------------
The projections shown herein reflect the divestiture of interests owned by the
partnership in the Shallow Oil Reservoirs in West Cote Blanche Bay Field which
was effective January 1, 1995. The partnership retained interests in the Gas
Cap Reservoirs in this property.
RESERVES ESTIMATES
- ------------------
Reserve estimates for the properties reviewed for the purpose of this audit
have been prepared with consideration of the available data and the nature of
the producing horizons. The projections have been based on performance data
for the existing completions, analogy to other completions in the subject
reservoirs, and volumetric calculations. Estimates prepared on the basis of
analogy and volumetric calculations will be subject to much greater variation
than those prepared for depletion drive reservoirs having established
production trends.
UMBRELLA POINT FIELD - This property operated by French Production,
Incorporated, is located in state waters offshore Chambers County, Texas, and
produces from multiple reservoirs. Projections for this property were based
primarily on the extrapolation of production data with consideration for water
cut and pressure information, where available. We have also utilized
information from our files from previous studies prepared by our firm relating
to this property. In general, the productive reservoirs for this property are
in the latter stages of depletion and future recoveries may be influenced by
both mechanical and reservoir factors.
<PAGE> 233
Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995
Page Four
WEST COTE BLANCHE BAY FIELD - Estimated reserves for the gas cap reservoirs
have been assigned on the basis of volumetric calculations for eight horizons
ranging in depth from 9,000 to 12,000 feet in three fault blocks. The
volumetric calculations have been based on log-derived parameters and
geological interpretations prepared on the basis of subsurface information,
pressure information, and geophysical interpretations based on 3-D seismic
data. Subsequent to our previous review, revised geological interpretations
have resulted in the transfer of reserves for the 12,600' reservoir to location
1-A (#868) from well #720 with no change in the estimated recoverable reserves.
Additional recoverable reserves have been assigned to the 38 and 38A reservoirs
based on geologic interpretations with consideration for historical performance
data.
The projected reserves for the #831 gas well, 13,900' reservoir, have been
revised relative to our July 1, 1994, evaluation on the basis of performance
data to reflect an ultimate recovery of 6,400 MMcf. The remaining reserves for
this reservoir have been transferred to location 1- A (#868).
GENERAL CONCLUSIONS - On an overall basis, we have not encountered materials
differences in our reserve estimates and those prepared by Benton. In cases
where we have encountered significant differences in estimated recoveries,
Benton has consented to the revision of its reserve estimates to be consistent
with projections by Huddleston. The projected reserves shown herein will be
subject to a significant level of variation due to the nature of the subject
reservoirs, the stage of depletion of the producing horizons, the reserve
estimation techniques, and the actual schedule of future remedial and
development operations.
Huddleston has relied on Benton to provide development schedules. The
scheduling of future operations will be influenced by a variety of factors
including economic and market conditions, political considerations,
availability of funds, alternative investment opportunities, leasehold
obligations, and internal decision making. Variations in the execution of
these development plans may have a material impact on the economic value of
both the discounted and undiscounted revenue streams.
OPERATING AND CAPITAL COSTS
- ---------------------------
Huddleston has reviewed operating costs utilized by Benton and believes they
are appropriate for the subject properties. Costs for all properties were
consistent with historical levels. Severance and ad valorem taxes were
deducted from gross revenues in accordance with statutory rates. all taxes
(excluding income taxes) were estimated by Benton and have been deducted from
future revenues.
All capital costs were based on information provided by Benton. Huddleston has
generally reviewed these costs and believes they are reasonable. The capital
costs shown for the remedial operations for West Cote Blanche Bay Field have
been adjusted to reflect the statistical success rates of remedial operations
and variations in the depth of the historical and proposed operations.
All capital and operating expenditures were held constant over the life of the
properties.
FACTORS NOT INCLUDED
- --------------------
Values were not assigned to nonproducing acreage or to the salvage of surface
and subsurface equipment.
General office overhead, income taxes, and allowances for depletion,
depreciation, and amortization have not been deducted from future revenues.
<PAGE> 234
Mr. A.E. Benton
Benton Oil and Gas Company
March 8, 1995
Page Five
REPORT QUALIFICATIONS
- ---------------------
THE ESTIMATED REVENUES AND PRESENT VALUE OF THESE REVENUES ARE NOT REPRESENTED
AS MARKET VALUE.
Estimates for individual completions should be considered in context with the
overall or total estimated revenues. Actual individual lease performances will
vary considerably from the projections particularly in comparison to the total
estimated production from all properties.
We did not inspect the properties or conduct independent well tests.
Ownership, product prices, and other factual data have been accepted as
represented by Benton. We have generally tested these data and believe the
information is correct.
Respectfully submitted,
Peter D. Huddleston, P.E.
PDH:JPK:dbw
<PAGE> 235
EXHIBIT C
THE PROPOSAL
Set forth below is a proposed amendment ("Amendment") to the Agreement
of Limited Partnership (the "Partnership Agreement") of Benton Oil and Gas
Combination Partnership 1989-1 Limited Partnership (the "Partnership"). This
Amendment shall be effective upon the acceptance pursuant to the Exchange Offer
of written consents from Investors holding not less than 75% of the Interests
in the Partnership. If the Amendment becomes effective, it will become a
separate article of the Partnership Agreement and shall be placed immediately
after the last article contained in the Partnership Agreement.
PROPOSED AMENDMENT
Notwithstanding any provisions of this Agreement to the contrary, it
is hereby agreed as follows:
1. Definitions. Except as defined in the Partnership Agreement or
this article, each capitalized term used herein shall, for the purposes of this
article, have the meaning ascribed to it in the Prospectus of Benton Oil and
Gas Company, a Delaware corporation ("Benton"), dated ________________, 1995.
2. Elimination of Restrictions. No provision of this Agreement shall
prohibit, limit or prevent (i) the transfer and conveyance of all the assets
and liabilities of the limited partnership formed by this Agreement (the
"Partnership") to Benton in exchange for Interests pursuant to and in
accordance with the terms of the Exchange Offer or otherwise, or (ii) the
distribution of Interests to partners of the Partnership ("Partners") upon
dissolution of the Partnership. In addition, no consent of the Partnership or
any Partner, opinion of counsel or other procedure shall be required in order
to enable any Partner, the Partnership or Benton to effect any such transfer,
Exchange Offer or distribution.
3. Exchange of Partnership Assets and Liabilities for Interests.
Effective as of the Effective Date, the Partnership shall transfer and convey
all Partnership's assets and liabilities to Benton in exchange for Interests
pursuant to and in accordance with the terms of the Exchange Offer.
4. Election to Dissolve. Immediately after consummation of the
Exchange Offer, the Partnership shall be dissolved. Upon its dissolution, the
business and affairs of the Partnership shall be terminated and wound up and,
as soon as practicable thereafter, any and all Interests held by the
Partnership shall be distributed in kind to the Partners (or their assignees)
with each Partner (or his assignee) to receive a whole number of Common Stock
and Warrants equal to the Exchange Value of his Interest divided by the
Exchange Price.
5. Authority of General Partner. Benton, in its capacity as managing
general partner of the Partnership, shall execute, acknowledge, verify,
deliver, file and record, for and in the name of the Partnership, any and all
documents and shall do and perform all acts required by applicable law or that
it deems necessary or desirable in order to give effect to this article and the
transactions contemplated herein, including by not limited to thedissolution,
termination, winding-up and distribution contemplated by paragraph 4 of this
article.
6. This Article Controlling. The provisions of this article shall
control over all other provisions of this Agreement.
Except as herein expressly amended, all other terms and provisions of
the Certificate and this Agreement shall remain in full force and effect.
<PAGE> 236
EXHIBIT C
THE PROPOSAL
Set forth below is a proposed amendment ("Amendment") to the Agreement
of Limited Partnership (the "Partnership Agreement") of Benton Oil and Gas
Combination Partnership 1990-1 Limited Partnership (the "Partnership"). This
Amendment shall be effective upon the acceptance pursuant to the Exchange Offer
of written consents from Investors holding not less than 75% of the Interests
in the Partnership. If the Amendment becomes effective, it will become a
separate article of the Partnership Agreement and shall be placed immediately
after the last article contained in the Partnership Agreement.
PROPOSED AMENDMENT
Notwithstanding any provisions of this Agreement to the contrary, it
is hereby agreed as follows:
1. Definitions. Except as defined in the Partnership Agreement or
this article, each capitalized term used herein shall, for the purposes of this
article, have the meaning ascribed to it in the Prospectus of Benton Oil and
Gas Company, a Delaware corporation ("Benton"), dated ________________, 1995.
2. Elimination of Restrictions. No provision of this Agreement shall
prohibit, limit or prevent (i) the transfer and conveyance of all the assets
and liabilities of the limited partnership formed by this Agreement (the
"Partnership") to Benton in exchange for Interests pursuant to and in
accordance with the terms of the Exchange Offer or otherwise, or (ii) the
distribution of Interests to partners of the Partnership ("Partners") upon
dissolution of the Partnership. In addition, no consent of the Partnership or
any Partner, opinion of counsel or other procedure shall be required in order
to enable any Partner, the Partnership or Benton to effect any such transfer,
Exchange Offer or distribution.
3. Exchange of Partnership Assets and Liabilities for Interests.
Effective as of the Effective Date, the Partnership shall transfer and convey
all Partnership's assets and liabilities to Benton in exchange for Interests
pursuant to and in accordance with the terms of the Exchange Offer.
4. Election to Dissolve. Immediately after consummation of the
Exchange Offer, the Partnership shall be dissolved. Upon its dissolution, the
business and affairs of the Partnership shall be terminated and wound up and,
as soon as practicable thereafter, any and all Interests held by the
Partnership shall be distributed in kind to the Partners (or their assignees)
with each Partner (or his assignee) to receive a whole number of Common Stock
and Warrants equal to the Exchange Value of his Interest divided by the
Exchange Price.
5. Authority of General Partner. Benton, in its capacity as managing
general partner of the Partnership, shall execute, acknowledge, verify,
deliver, file and record, for and in the name of the Partnership, any and all
documents and shall do and perform all acts required by applicable law or that
it deems necessary or desirable in order to give effect to this article and the
transactions contemplated herein, including by not limited to the dissolution,
termination, winding-up and distribution contemplated by paragraph 4 of this
article.
6. This Article Controlling. The provisions of this article shall
control over all other provisions of this Agreement.
Except as herein expressly amended, all other terms and provisions of
the Certificate and this Agreement shall remain in full force and effect.
<PAGE> 237
EXHIBIT C
THE PROPOSAL
Set forth below is a proposed amendment ("Amendment") to the Agreement
of Limited Partnership (the "Partnership Agreement") of Benton Oil and Gas
Combination Partnership 1991-1 Limited Partnership (the "Partnership"). This
Amendment shall be effective upon the acceptance pursuant to the Exchange Offer
of written consents from Investors holding not less than 75% of the Interests
in the Partnership. If the Amendment becomes effective, it will become a
separate article of the Partnership Agreement and shall be placed immediately
after the last article contained in the Partnership Agreement.
PROPOSED AMENDMENT
Notwithstanding any provisions of this Agreement to the contrary, it
is hereby agreed as follows:
1. Definitions. Except as defined in the Partnership Agreement or
this article, each capitalized term used herein shall, for the purposes of this
article, have the meaning ascribed to it in the Prospectus of Benton Oil and
Gas Company, a Delaware corporation ("Benton"), dated ________________, 1995.
2. Elimination of Restrictions. No provision of this Agreement shall
prohibit, limit or prevent (i) the transfer and conveyance of all the assets
and liabilities of the limited partnership formed by this Agreement (the
"Partnership") to Benton in exchange for Interests pursuant to and in
accordance with the terms of the Exchange Offer or otherwise, or (ii) the
distribution of Interests to partners of the Partnership ("Partners") upon
dissolution of the Partnership. In addition, no consent of the Partnership or
any Partner, opinion of counsel or other procedure shall be required in order
to enable any Partner, the Partnership or Benton to effect any such transfer,
Exchange Offer or distribution.
3. Exchange of Partnership Assets and Liabilities for Interests.
Effective as of the Effective Date, the Partnership shall transfer and convey
all Partnership's assets and liabilities to Benton in exchange for Interests
pursuant to and in accordance with the terms of the Exchange Offer.
4. Election to Dissolve. Immediately after consummation of the
Exchange Offer, the Partnership shall be dissolved. Upon its dissolution, the
business and affairs of the Partnership shall be terminated and wound up and,
as soon as practicable thereafter, any and all Interests held by the
Partnership shall be distributed in kind to the Partners (or their assignees)
with each Partner (or his assignee) to receive a whole number of Common Stock
and Warrants equal to the Exchange Value of his Interest divided by the
Exchange Price.
5. Authority of General Partner. Benton, in its capacity as managing
general partner of the Partnership, shall execute, acknowledge, verify,
deliver, file and record, for and in the name of the Partnership, any and all
documents and shall do and perform all acts required by applicable law or that
it deems necessary or desirable in order to give effect to this article and the
transactions contemplated herein, including by not limited to the dissolution,
termination, winding-up and distribution contemplated by paragraph 4 of this
article.
6. This Article Controlling. The provisions of this article shall
control over all other provisions of this Agreement.
Except as herein expressly amended, all other terms and provisions of
the Certificate and this Agreement shall remain in full force and effect.
<PAGE> 238
EXHIBIT D
BENTON OIL AND GAS COMPANY
LETTER OF TRANSMITTAL
FOR
INVESTORS IN
BENTON OIL AND GAS COMBINATION PARTNERSHIP 1989 - 1 L.P.
Capitalized terms used but not defined herein have the meanings given
to them in the Prospectus of Benton Oil and Gas Company, as supplemented or
amended (the "Prospectus"). General instructions are included in Part VI.
This Letter of Transmittal must be received by the Exchange Agent on
or before 5:00 p.m. Eastern Time, on ______________, 1995 unless the Exchange
Offer is extended. To accept the Exchange Offer or withhold consent to the
related Proposal, please complete this Letter in accordance with the
Instructions in Items IV and VI, and send or deliver the completed Letter of
Transmittal to the Exchange Agent. Neither accepting the Exchange Offer nor
withholding consent to the Proposal will prevent an Investor from challenging
the fairness of the Exchange Offer.
Adoption of the Proposal requires consent by Investors holding 75% of
the units in the Partnership. Assuming consummation of the Exchange Offer, all
of the partners of the Partnership, whether or not they tender their Interests,
will receive the same number of shares of Common Stock and Warrants they would
have received had they tendered their Interests, except that California
investors exercising their limited dissenters' rights may receive a higher or
lower number of shares or warrants. See Part V below and "The Exchange Offer
and Proposal" in the Prospectus.
Exchange Agent: Benton Oil and Gas Company
By Mail or By Hand:
-------------------
Benton Oil and Gas Company
1145 Eugenia Place, Suite 200
Carpenteria, California 93013
Attention: Investor Relations Department
Delivery of this Form is at the risk of the Investor. If sent by U.S.
Mail, it is recommended that an Investor use certified mail, return receipt
requested.
PART I
NAME AND ADDRESS OF INVESTOR
---------------------------------------------------------
---------------------------------------------------------
----------------------------------------------------------
<PAGE> 239
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>
<S> <C> <C> <C>
Partnership Exchange Common
Interests Value Shares Warrants
--------- ----- ------ --------
</TABLE>
PART III
REPRESENTATIONS, WARRANTIES, COVENANTS AND POWER OF ATTORNEY
An Investor checking the "Tender and Consent" box and signing Part IV
below ("Consenting Investor") hereby (i) accepts the Exchange Offer on the
terms and subject to the conditions set forth in the Prospectus, receipt of a
copy of which is hereby acknowledged, and tenders to Benton Oil and Gas Company
("Benton") all of his Interest in the Partnership, thereby consenting to the
Proposal, and (ii) subject to acceptance of the tender made hereby, sells,
transfers, contributes and assigns to Benton all right, title and interest in
the Interest tendered hereby. Tenders of Interests are revocable upon written
notice to Benton at any time prior to the Expiration Date.
An Investor checking the "Withhold Consent" box and signing Part IV
below or Part V for California residents ("Non-consenting Investor") hereby (i)
acknowledges receipt of the Prospectus and (ii) assuming adoption of the
Proposal, accept the Common Stock and Warrants offered in exchange for all
right, title and interest in the Interest represented by the Partnership
Interests set forth above.
The undersigned Investor represents and warrants to Benton that, as of
the Closing Date, (i) he has not disposed of or agreed to dispose of his
Interest other than pursuant to the Exchange Offer, (ii) upon exchange of his
Interest pursuant to the Exchange Offer, Benton will acquire good and
marketable title to the Interest, free and clear of all liens, encumbrances and
adverse claims, (iii) he has full legal right, power and authority to convey
his Interest pursuant to the Exchange Offer, (iv) he has received and reviewed
a copy of the Prospectus and (v) he is qualified to make decisions with respect
to investments presenting an investment decision similar to that involved in
the Exchange Offer. All representations, warranties and covenants contained
herein shall survive the Closing Date and all other transactionscontemplated by
this Letter and the Prospectus.
In connection with the solicitation of written consents of Investors
in the Partnership, each Consenting Investor below hereby (i) represents and
warrants to Benton that he has full legal right, power and authority to execute
a written consent with respect to the Proposal and (ii) consents to the
adoption of the Proposal to amend the Partnership Agreement, as described in
the Prospectus.
<PAGE> 240
The undersigned Investor hereby irrevocably appoints Benton or any
designee of Benton, with full power of substitution, as his true and lawful
attorney-in-fact, in his name, place and stead, to execute on behalf of the
Investor any additional documents necessary to consummate the Exchange and the
withdrawal and transfer of the assets underlying his Interest. This power of
attorney shall become effective upon acceptance by Benton of his Interest,
shall be deemed coupled with an interest, shall be irrevocable (except in the
event of a withdrawal of a Consenting Investor's tender of his Interest
following a modification or amendment of the Exchange Offer), is granted in
consideration of the acceptance of his Interest, shall survive the death,
incapacity, dissolution or termination of the existence of the Investor and
shall be binding upon the Investor's heirs, legal representatives or assigns.
The following information must be completed in order to entitle the
Soliciting Dealer to receive a fee in connection with the Exchange Offer.
----------------------------------------
Name of Soliciting Dealer
(Please Print)
----------------------------------------
Name of Account Executive
(Please Print)
----------------------------------------
City and State of Account Executive
<PAGE> 241
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, When signing as a general
unless printed incorrectly. partner, corporate officer,
attorney-in-fact, executor,
administrator, trustee or
guardian, please give full
title and send proper
evidence of authority with
this consent. For joint
owners, each joint owner must
sign.
- -----------------------------------------------------
Full Name of Investor
(Please Print)
- -----------------------------------------------------
Full Name of Co-owner, if any
(Please Print)
- -----------------------------------------------------
Signature of Investor
(Please Print)
- -----------------------------------------------------
Signature of Co-owner, if any
(Please Print)
Business Telephone: (_____) ____________________
Home Telephone: (_____) _____________________
Dated ______________________________________,1995
IF THE INVESTOR FAILS TO INDICATE WHETHER CONSENT TO THE PROPOSAL IS GIVEN OR
WITHHELD, CONSENT WILL BE DEEMED TO BE GIVEN.
<PAGE> 242
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 ----------------------------------------
this consent. For joint Full Name of Investor authority with
owners, each joint owner must sign. (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> 243
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.
<PAGE> 244
Tenders will be deemed not to have been made until any irregularities
have been cured or waived. Any Letter of Transmittal which is not properly
completed and executed, and as to which irregularities are not cured or waived,
will be returned by Benton to the Investor as soon as practicable. Benton is
under no duty to give notification of defects in tenders and will not incur any
liability for failure to give notification.
Benton will not accept tenders of less than all of an Investor's
Interest in the Partnership.
7. Consents to Proposal. A tender of an Interest constitutes a
consent to the Proposal. Only persons who are holders of record of Partnership
Interests on the date of the Prospectus may vote on the Proposal.
8. Dissenters' Rights for California Residents. Investors residing
in California have limited dissenters' rights in accordance with the
requirements for rollup transactions. By signing Part V and thereby
withholding consent to the Proposal, Investors in that State will be deemed to
exercise their dissenters' rights and will receive the number of Shares of
Common Stock equal to the Exchange Value of their Interests divided by the
average closing prices of the Units on NASDAQ-NMS during the twenty trading
days immediately after the Closing Date. Each California Investor withholding
consent to the Proposal will also be deemed to have tendered his Interest for
that number of Units and therefore will not be required to separately submit an
executed Transfer Application. If the average price of the Units during the
specified period after the Closing Date is lower than the Exchange Price,
dissenting California Investors will receive more for their Interests than they
would otherwise receive in the Exchange Offer. Any increase in the market
price of the Common Stock during that period relative to the Exchange Price,
however, would reduce the number of shares that dissenting California Investors
will receive in the Exchange Offer.
Although the rollup requirements for California residents entitle them
to an appraisal in rollup transactions involving their investments, Investors
residing in California who exercise these dissenters' rights will not be
entitled to a separate appraisal for their Interests because the Exchange Value
of the Common Stock determined by Benton exceeds the liquidation value assigned
to the Partnership's net assets in an independent appraisal already performed
in accordance with the Partnership Agreement.
<PAGE> 245
EXHIBIT D
BENTON OIL AND GAS COMPANY
LETTER OF TRANSMITTAL
FOR
INVESTORS IN
BENTON OIL AND GAS COMBINATION PARTNERSHIP 1990 - 1 L.P.
Capitalized terms used but not defined herein have the meanings given
to them in the Prospectus of Benton Oil and Gas Company, as supplemented or
amended (the "Prospectus"). General instructions are included in Part VI.
This Letter of Transmittal must be received by the Exchange Agent on
or before 5:00 p.m. Eastern Time, on ______________, 1995 unless the Exchange
Offer is extended. To accept the Exchange Offer or withhold consent to the
related Proposal, please complete this Letter in accordance with the
Instructions in Items IV and VI, and send or deliver the completed Letter of
Transmittal to the Exchange Agent. Neither accepting the Exchange Offer nor
withholding consent to the Proposal will prevent an Investor from challenging
the fairness of the Exchange Offer.
Adoption of the Proposal requires consent by Investors holding 75% of
the units in the Partnership. Assuming consummation of the Exchange Offer, all
of the partners of the Partnership, whether or not they tender their Interests,
will receive the same number of shares of Common Stock and Warrants they would
have received had they tendered their Interests, except that California
investors exercising their limited dissenters' rights may receive a higher or
lower number of shares or warrants. See Part V below and "The Exchange Offer
and Proposal" in the Prospectus.
Exchange Agent: Benton Oil and Gas Company
By Mail or By Hand:
------------------
Benton Oil and Gas Company
1145 Eugenia Place, Suite 200
Carpenteria, California 93013
Attention: Investor Relations Department
Delivery of this Form is at the risk of the Investor. If sent by U.S.
Mail, it is recommended that an Investor use certified mail, return receipt
requested.
PART I
NAME AND ADDRESS OF INVESTOR
_________________________________________________________
_________________________________________________________
_________________________________________________________
<PAGE> 246
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>
<S> <C> <C> <C>
Partnership Exchange Common
Interests Value Shares Warrants
------------ -------- ------- --------
</TABLE>
PART III
REPRESENTATIONS, WARRANTIES, COVENANTS AND POWER OF ATTORNEY
An Investor checking the "Tender and Consent" box and signing Part IV
below ("Consenting Investor") hereby (i) accepts the Exchange Offer on the
terms and subject to the conditions set forth in the Prospectus, receipt of a
copy of which is hereby acknowledged, and tenders to Benton Oil and Gas Company
("Benton") all of his Interest in the Partnership, thereby consenting to the
Proposal, and (ii) subject to acceptance of the tender made hereby, sells,
transfers, contributes and assigns to Benton all right, title and interest in
the Interest tendered hereby. Tenders of Interests are revocable upon written
notice to Benton at any time prior to the Expiration Date.
An Investor checking the "Withhold Consent" box and signing Part IV
below or Part V for California residents ("Non-consenting Investor") hereby (i)
acknowledges receipt of the Prospectus and (ii) assuming adoption of the
Proposal, accept the Common Stock and Warrants offered in exchange for all
right, title and interest in the Interest represented by the Partnership
Interests set forth above.
The undersigned Investor represents and warrants to Benton that, as of
the Closing Date, (i) he has not disposed of or agreed to dispose of his
Interest other than pursuant to the Exchange Offer, (ii) upon exchange of his
Interest pursuant to the Exchange Offer, Benton will acquire good and
marketable title to the Interest, free and clear of all liens, encumbrances and
adverse claims, (iii) he has full legal right, power and authority to convey
his Interest pursuant to the Exchange Offer, (iv) he has received and reviewed
a copy of the Prospectus and (v) he is qualified to make decisions with respect
to investments presenting an investment decision similar to that involved in
the Exchange Offer. All representations, warranties and covenants contained
herein shall survive the Closing Date and all other transactions contemplated
by this Letter and the Prospectus.
In connection with the solicitation of written consents of Investors
in the Partnership, each Consenting Investor below hereby (i) represents and
warrants to Benton that he has full legal right, power and authority to execute
a written consent with respect to the Proposal and (ii) consents to the
adoption of the Proposal to ament the Partnership Agreement, as described in
the Prospectus.
<PAGE> 247
The undersigned Investor hereby irrevocably appoints Benton or any
designee of Benton, with full power of substitution, as his true and lawful
attorney-in-fact, in his name, place and stead, to execute on behalf of the
Investor any additional documents necessary to consummate the Exchange and the
withdrawal and transfer of the assets underlying his Interest. This power of
attorney shall become effective upon acceptance by Benton of his Interest,
shall be deemed coupled with an interest, shall be irrevocable (except in the
event of a withdrawal of a Consenting Investor's tender of his Interest
following a modification or amendment of the Exchange Offer), is granted in
consideration of the acceptance of his Interest, shall survive the death,
incapacity, dissolution or termination of the existence of the Investor and
shall be binding upon the Investor's heirs, legal representatives or assigns.
The following information must be completed in order to entitle the
Soliciting Dealer to receive a fee in connection with the Exchange Offer.
________________________________________
Name of Soliciting Dealer
(Please Print)
________________________________________
Name of Account Executive
(Please Print)
________________________________________
City and State of Account Executive
<PAGE> 248
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> 249
PART V
NON-CONSENTING CALIFORNIA INVESTORS
COMPLETE ONLY IF YOU DO NOT WISH TO TENDER YOUR INTEREST PURSUANT TO
THE EXCHANGE OFFER AND WISH TO EXERCISE YOUR DISSENTERS' RIGHTS.
The Non-consenting Investor signing in this Part V represents that
California is the Investor's state of residence and withholds his consent to
the Proposal to approve and adopt the Amendment to the Program Agreement. By
withholding consent, a Non-consenting California Investor will exercise his
dissenters' rights and will be deemed to have made the representations,
warranties and covenants (other than the consent to the adoption of the
Proposal) set forth in Part III above, and he will receive, pursuant to those
dissenters' rights, the number of shares of Common Stock equal to the Exchange
Value of his Interest divided by the average closing prices of the Units on
NASDAQ-NMS during the twenty trading days immediately after the Closing Date.
SIGNATURE BOX
(ONLY FOR NON-CONSENTING CALIFORNIA RESIDENTS)
Please sign exactly as your name is printed in Part
I above, unless printed incorrectly. When signing
as general partner, corporate officer,
attorney-in-fact, executor,administrator,
trustee or guardian, please give full -------------------------------------
title and send proper evidence of Full Name of Investor authority
with this consent. For joint owners, (Please Print)
each joint owner must sign.
-------------------------------------
Full Name of Co-owner, if any
(Please Print)
-------------------------------------
Signature of Investor
-------------------------------------
Signature of Co-owner, if any
Business Telephone: ( )
---- ------------------
Home Telephone: ( )
---- ------------------
Dated
-----------------------------------, 1995
<PAGE> 250
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.
<PAGE> 251
Tenders will be deemed not to have been made until any irregularities
have been cured or waived. Any Letter of Transmittal which is not properly
completed and executed, and as to which irregularities are not cured or waived,
will be returned by Benton to the Investor as soon as practicable. Benton is
under no duty to give notification of defects in tenders and will not incur any
liability for failure to give notification.
Benton will not accept tenders of less than all of an Investor's
Interest in the Partnership.
7. Consents to Proposal. A tender of an Interest constitutes a
consent to the Proposal. Only persons who are holders of record of Partnership
Interests on the date of the Prospectus may vote on the Proposal.
8. Dissenters' Rights for California Residents. Investors residing
in California have limited dissenters' rights in accordance with the
requirements for rollup transactions. By signing Part V and thereby
withholding consent to the Proposal, Investors in that State will be deemed to
exercise their dissenters' rights and will receive the number of Shares of
Common Stock equal to the Exchange Value of their Interests divided by the
average closing prices of the Units on NASDAQ-NMS during the twenty trading
days immediately after the Closing Date. Each California Investor withholding
consent to the Proposal will also be deemed to have tendered his Interest for
that number of Units and therefore will not be required to separately submit an
executed Transfer Application. If the average price of the Units during the
specified period after the Closing Date is lower than the Exchange Price,
dissenting California Investors will receive more for their Interests than they
would otherwise receive in the Exchange Offer. Any increase in the market
price of the Common Stock during that period relative to the Exchange Price,
however, would reduce the number of shares that dissenting California Investors
will receive in the Exchange Offer.
Although the rollup requirements for California residents entitle them
to an appraisal in rollup transactions involving their investments, Investors
residing in California who exercise these dissenters' rights will not be
entitled to a separate appraisal for their Interests because the Exchange Value
of the Common Stock determined by Benton exceeds the liquidation value assigned
to the Partnership's net assets in an independent appraisal already performed
in accordance with the Partnership Agreement.
<PAGE> 252
EXHIBIT D
BENTON OIL AND GAS COMPANY
LETTER OF TRANSMITTAL
FOR
INVESTORS IN
BENTON OIL AND GAS COMBINATION PARTNERSHIP 1991 - 1 L.P.
Capitalized terms used but not defined herein have the meanings given
to them in the Prospectus of Benton Oil and Gas Company, as supplemented or
amended (the "Prospectus"). General instructions are included in Part VI.
This Letter of Transmittal must be received by the Exchange Agent on
or before 5:00 p.m. Eastern Time, on ______________, 1995 unless the Exchange
Offer is extended. To accept the Exchange Offer or withhold consent to the
related Proposal, please complete this Letter in accordance with the
Instructions in Items IV and VI, and send or deliver the completed Letter of
Transmittal to the Exchange Agent. Neither accepting the Exchange Offer nor
withholding consent to the Proposal will prevent an Investor from challenging
the fairness of the Exchange Offer.
Adoption of the Proposal requires consent by Investors holding 75% of
the units in the Partnership. Assuming consummation of the Exchange Offer, all
of the partners of the Partnership, whether or not they tender their Interests,
will receive the same number of shares of Common Stock and Warrants they would
have received had they tendered their Interests, except that California
investors exercising their limited dissenters' rights may receive a higher or
lower number of shares or warrants. See Part V below and "The Exchange Offer
and Proposal" in the Prospectus.
Exchange Agent: Benton Oil and Gas Company
By Mail or By Hand:
-------------------
Benton Oil and Gas Company
1145 Eugenia Place, Suite 200
Carpenteria, California 93013
Attention: Investor Relations Department
Delivery of this Form is at the risk of the Investor. If sent by U.S.
Mail, it is recommended that an Investor use certified mail, return receipt
requested.
PART I
NAME AND ADDRESS OF INVESTOR
-----------------------------
-----------------------------
-----------------------------
<PAGE> 253
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>
<S> <C> <C> <C>
Partnership Exchange Common
Interests Value Shares Warrants
--------- ----- ------ --------
</TABLE>
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.
<PAGE> 254
The undersigned Investor hereby irrevocably appoints Benton or any
designee of Benton, with full power of substitution, as his true and lawful
attorney-in-fact, in his name, place and stead, to execute on behalf of the
Investor any additional documents necessary to consummate the Exchange and the
withdrawal and transfer of the assets underlying his Interest. This power of
attorney shall become effective upon acceptance by Benton of his Interest,
shall be deemed coupled with an interest, shall be irrevocable (except in the
event of a withdrawal of a Consenting Investor's tender of his Interest
following a modification or amendment of the Exchange Offer), is granted in
consideration of the acceptance of his Interest, shall survive the death,
incapacity, dissolution or termination of the existence of the Investor and
shall be binding upon the Investor's heirs, legal representatives or assigns.
The following information must be completed in order to entitle the
Soliciting Dealer to receive a fee in connection with the Exchange Offer.
----------------------------------------
Name of Soliciting Dealer
(Please Print)
----------------------------------------
Name of Account Executive
(Please Print)
---------------------------------------
City and State of Account Executive
<PAGE> 255
PART IV
ALL INVESTORS
(EXCEPT NON-CONSENTING CALIFORNIA RESIDENTS. SEE PART V)
CALIFORNIA INVESTORS ELECTING TO EXERCISE DISSENTERS' RIGHTS SHOULD
INSTEAD COMPLETE PART V.
Consent to the Proposal being submitted by Benton to adopt the
Amendment to the Partnership Agreement:
[ ] Tender and Consent [ ] Withhold Consent
CASH ELECTION
Subject to the availability to elect a cash payment in lieu of Benton
Common Stock, I hereby elect to receive Cash rather than Benton Common Stock.
[ ]
SIGNATURE BOX
(NOT FOR NON-CONSENTING CALIFORNIA RESIDENTS. SEE PART V)
Please sign exactly as you name is printed When signing as a general
in Part I above, unless printed incorretly. 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> 256
PART V
NON-CONSENTING CALIFORNIA INVESTORS
COMPLETE ONLY IF YOU DO NOT WISH TO TENDER YOUR INTEREST PURSUANT TO
THE EXCHANGE OFFER AND WISH TO EXERCISE YOUR DISSENTERS' RIGHTS.
The Non-consenting Investor signing in this Part V represents that
California is the Investor's state of residence and withholds his consent to
the Proposal to approve and adopt the Amendment to the Program Agreement. By
withholding consent, a Non-consenting California Investor will exercise his
dissenters' rights and will be deemed to have made the representations,
warranties and covenants (other than the consent to the adoption of the
Proposal) set forth in Part III above, and he will receive, pursuant to those
dissenters' rights, the number of shares of Common Stock equal to the Exchange
Value of his Interest divided by the average closing prices of the Units on
NASDAQ-NMS during the twenty trading days immediately after the Closing Date.
SIGNATURE BOX
(ONLY FOR NON-CONSENTING CALIFORNIA RESIDENTS)
Please sign exactly as your name is
printed in Part I above, unless printed
incorrectly. When signing as general partner,
corporate officer, attorney-in-fact, executor, ----------------------------
administrator, trustee or guardian, please give Full Name of Investor
full title and send proper evidence of authority (Please Print)
with this consent. For joint owner must sign.
----------------------------
Full Name of Co-owner, if any
(Please Print)
-----------------------------
Signature of Investor
------------------------------
Signature of Co-owner, if any
Business Telephone: ( )
--- ------------
Home Telephone: ( )
--- ------------
Dated ,1995
----------------------------
<PAGE> 257
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.
<PAGE> 258
Tenders will be deemed not to have been made until any irregularities
have been cured or waived. Any Letter of Transmittal which is not properly
completed and executed, and as to which irregularities are not cured or waived,
will be returned by Benton to the Investor as soon as practicable. Benton is
under no duty to give notification of defects in tenders and will not incur any
liability for failure to give notification.
Benton will not accept tenders of less than all of an Investor's
Interest in the Partnership.
7. Consents to Proposal. A tender of an Interest constitutes a
consent to the Proposal. Only persons who are holders of record of Partnership
Interests on the date of the Prospectus may vote on the Proposal.
8. Dissenters' Rights for California Residents. Investors residing
in California have limited dissenters' rights in accordance with the
requirements for rollup transactions. By signing Part V and thereby
withholding consent to the Proposal, Investors in that State will be deemed to
exercise their dissenters' rights and will receive the number of Shares of
Common Stock equal to the Exchange Value of their Interests divided by the
average closing prices of the Units on NASDAQ-NMS during the twenty trading
days immediately after the Closing Date. Each California Investor withholding
consent to the Proposal will also be deemed to have tendered his Interest for
that number of Units and therefore will not be required to separately submit an
executed Transfer Application. If the average price of the Units during the
specified period after the Closing Date is lower than the Exchange Price,
dissenting California Investors will receive more for their Interests than they
would otherwise receive in the Exchange Offer. Any increase in the market
price of the Common Stock during that period relative to the Exchange Price,
however, would reduce the number of shares that dissenting California Investors
will receive in the Exchange Offer.
Although the rollup requirements for California residents entitle them
to an appraisal in rollup transactions involving their investments, Investors
residing in California who exercise these dissenters' rights will not be
entitled to a separate appraisal for their Interests because the Exchange Value
of the Common Stock determined by Benton exceeds the liquidation value assigned
to the Partnership's net assets in an independent appraisal already performed
in accordance with the Partnership Agreement.
<PAGE> 259
PART II
ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Under provisions of the Certificate of Incorporation and Bylaws of the
Company, each person who is or was a director or officer of the Company shall be
indemnified by the Company as a matter of right to the full extent permitted or
authorized by law. The effects of the Certificate of Incorporation, Bylaws and
General Corporation Law of Delaware may be summarized as follows:
(a) Under Delaware law, to the extent that such a person is
successful on the merits in defense of a suit or proceeding brought
against him by reason of the fact that he is a director or officer of
the Company, he shall be indemnified against expenses (including
attorneys' fees) reasonably incurred in connection with such action.
(b) If unsuccessful in defense of a third-party civil suit or
a criminal suit, or if such a suit is settled, such a person shall be
indemnified under such law against both (1) expenses (including
attorneys' fees) and (2) judgments, fines and amounts paid in
settlement if he acted in good faith and in a manner he reasonably
believed to be in, or not opposed to, the best interests of the
Company, and with respect to any criminal action, had no reasonable
cause to believe his conduct was unlawful.
(c) If unsuccessful in defense of a suit brought by or in the
right of the Company, or if such suit is settled, such a person shall
be indemnified under such law only against expenses (including
attorneys' fees) incurred in the defense or settlement of such suit if
he acted in good faith and in a manner he reasonably believed to be in,
or not opposed to, the best interests of the Company except that if
such a person is adjudged to be liable in a suit in the performance of
his duty to the Company, he cannot be made whole even for expenses
unless the court determines that he is fairly and reasonably entitled
to indemnity for such expenses.
(d) The Company may not indemnify a person in respect of a
proceeding described in (b) or (c) above unless it is determined that
indemnification is permissible because the person has met the
prescribed standard of conduct by any one of the following: (i) the
Board of Directors, by a majority vote of a quorum consisting of
directors not at the time parties to the proceeding, (ii) if a quorum
of directors not parties to the proceeding cannot be obtained, or, if
obtainable but the quorum so directs, by independent legal counsel
selected by the Board of Directors or the committee thereof; or (iii)
by the stockholders.
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a) Exhibits.
1.1 Form of Soliciting Agent Agreement.
2.1 Asset Purchase Agreement between Benton Oil & Gas
Combination Partnership 1989-1, L.P. and Goldking
Trinity Bay Corp. dated June ______, 1995 (to be
filed by amendment).
2.2 Asset Purchase Agreement between Benton Oil & Gas
Combination Partnership 1990-1, L.P. and Goldking
Trinity Bay Corp. dated June _____, 1995 (to be filed
by amendment).
II-1
<PAGE> 260
2.3 Asset Purchase Agreement between Benton Oil & Gas
Combination Partnership 1991-1, L.P. and Goldking
Trinity Bay Corp. dated June ______, 1995 (to be
filed by amendment).
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 September 1,
1989.
4.3 Benton Oil & Gas Combination Partnership 1990-1, L.P.
Limited Partnership Agreement dated November 29,
1990.
4.4 Benton Oil & Gas Combination Partnership 1991-1, L.P.
Limited Partnership Agreement dated July 30, 1991.
5.1 Form of Opinion of Emens, Kegler, Brown, Hill &
Ritter Co., LPA as to the legality of the securities
being registered.
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.
23.3 Consents of Huddleston & Co., Inc.
24.1 Power of Attorney (included on signature page).
24.2 Power of Attorney of the Company.
(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
II-2
<PAGE> 261
statement relating to the securities offered therein
and the offering of such securities at that time
shall be deemed to be the initial bona fide offering
thereof.
(3) To remove from registration by means of a
post-effective amendment any of the securities being
registered which remain unsold at the termination of
the offering.
(4) If the registrant is a foreign private
issuer, to file a post-effective amendment
to the registration statement to include any
financial statements required by Section 210.3-19 of
this chapter at the start of any delayed offering of
throughout a continuous offering. Financial
statements and information otherwise required by
Section 10(a)(3) of the Act need not be furnished,
provided that the registrant includes in the
prospectus, by means of a post-effective amendment,
financial statements required pursuant to this
paragraph (a)(4) and other information necessary to
ensure that all other information in the prospectus
is at least as current as the date of those
financial statements.
b. The undersigned registrant hereby undertakes to deliver or
cause to be delivered with the prospectus, to each person to
whom the prospectus is sent or given, the latest annual report
to security holders that is incorporated by reference in the
prospectus and furnished pursuant to and meeting the
requirements of Rule 14a-3 or Rule 14c-3 under the Securities
Exchange Act of 1934; and, where interim financial information
required to be presented by Article 3 of Regulation S-X are
not set forth in the prospectus, to deliver, or cause to be
delivered to each person to whom the prospectus is sent or
given, the latest quarterly report that is specifically
incorporated by reference in the prospectus to provide such
interim financial information.
c. (1) The undersigned registrant hereby undertakes as
follows: that prior to any public reoffering of the
securities registered hereunder through use of a
prospectus which is a part of this registration
statement, by any person or party who is deemed to be
an underwriter within the meaning of Rule 145(c), the
issuer undertakes that such reoffering prospectus
will contain the information called for by the
applicable registration form with respect to
reofferings by persons who may be deemed
underwriters, in addition to the information called
for by the other items of the applicable form.
(2) The registrant undertakes that every prospectus (i)
that is filed pursuant to paragraph (1) immediately
preceding, or (ii) that purports to meet the
requirements of section 10(a)(3) of the Act and is
used in connection with an offering of securities
subject to Rule 415, will be filed as a part of an
amendment to the registration statement and will not
be used until such amendment is effective and that,
for purposes 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.
d. 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
II-3
<PAGE> 262
contained in documents filed subsequent to the effective date
of the registration statement through the date of responding
to the request.
e. 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.
II-4
<PAGE> 263
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended,
the Registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of
Carpinteria, State of California, on the 24th day of July 1995.
BENTON OIL AND GAS COMPANY
By:/s/ A. E. Benton
------------------------
A. E. Benton, President
Each person whose signature appears below appoints A. E. Benton, David
H. Pratt, Jack A. Bjerke and Amy M. Shepherd and all four of them, any of whom
may act without the joinder of the others as his true and lawful
attorney-in-fact and agent, with full power of substitution and resubstitution,
for him, and in his stead, in all capacities to sign any and all amendments,
including post-effective amendments to this Registration Statement, and to file
the same with the Securities and Exchange Commission, granting to said
attorney-in-fact and agent full power and authority to do and perform each and
every act and thing requisite and necessary to be done, as fully to all intents
and purposes as he might or could do in person, hereby ratifying and confirming
all that said attorney-in-fact and agent or their substitute or substitutes may
lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, as amended,
this Registration Statement has been signed on July 24th, 1995 by the following
persons in the capacities indicated:
/s/ A. E. Benton President, Chief Executive Officer and Director
- -----------------------
A.E. Benton
/s/ David H. Pratt Vice President -- Finance, Principal Financial Officer
- -----------------------
David H. Pratt
/s/Chris C. Hickok Principal Accounting Officer
- -----------------------
Chris C. Hickok
/s/ Michael B. Wray Director
- -----------------------
Michael B. Wray
/s/ William H. Gumma Director
- -----------------------
William H. Gumma
/s/ Richard W. Fetzner Director
- -----------------------
Richard W. Fetzner
/s/ Bruce M. McIntyre Director
- -----------------------
Bruce M. McIntyre
II-5
<PAGE> 1
EXHIBIT 1.1
July 19, 1995
Soliciting Dealer
Dear Sirs:
The undersigned, Benton Oil and Gas Company, a Delaware corporation
("Benton"), is seeking your assistance in connection with the solicitation of
tenders and votes in connection with an exchange offer made by Benton to the
Benton Oil & Gas Combination Partnership 1989-1, L.P., the Benton Oil & Gas
Combination Partnership 1990-1, L.P. and the Benton Oil & Gas Combination
Partnership 1991-1, L.P. (collectively referred to as the "Partnerships").
Benton hereby confirms with you the agreement set forth below:
1. ENGAGEMENT OF SOLICITING DEALER. Soliciting Dealer is hereby
engaged to solicit tenders of units in the Partnerships and consents to the
Proposal as set forth in the Prospectus dated ________________________________,
1995.
2. SOLICITATION. Soliciting Dealer agrees to use its best efforts in
the solicitation set forth above with the primary purpose to encourage
participation by partners in the Partnerships, whether such partners vote in
favor of or against the Proposal and whether or not they tender their units in
the Exchange Offer.
3. SOLICITATION MATERIAL. No sales or other literature may be used by
Soliciting Dealer other than the Prospectus dated ______________ _________
unless such literature is approved in writing by Benton and is delivered to a
partner concurrently with a copy of the Prospectus.
4. PAYMENT OF FEES. Soliciting Dealer shall be entitled to receive a
fee from Benton equal to 2% of the aggregate exchange value of units held by
partners who return a completed Letter of Transmittal (whether the partner
votes for or against the Proposal, such entitlement being evidenced by the
appearance of the Soliciting Dealer's name on the Letter of Transmittal in the
space provided for that purpose.
5. PAYMENT. Payment will be made within 5 days of the Closing Date of
the Exchange Offer.
6. INDEMNIFICATION. Benton will indemnify and hold Soliciting Dealer
and each person, if any, who controls the Soliciting Dealer within the meaning
of either the Securities Act of 1933 or the Securities Exchange Act of 1934
(the "Acts") against any losses, claims, damages or liabilities, joint or
several, to which Soliciting Dealer or such controlling person may become
subject, under either of the Acts, at common law or otherwise insofar as such
losses, claims, damages or liabilities (or actions in respect thereof, arise
out of or are based upon and are caused by any untrue statement or alleged
untrue statement of any material fact contained in the Prospectus, or any
amendment or supplement thereto, or arise out of or are based upon and are
caused by the omission or alleged omission to state therein a material fact
required to be stated
<PAGE> 2
therein or necessary to make the statements therein not misleading, and will
reimburse Soliciting Dealer and each such controlling person for any legal or
other expenses reasonably incurred by them in connection with investigating or
defending any such loss, claim, damage, liability or action. Provided,
however, that Benton shall not be liable in any such case to the extent that
any such losses, claims, damages or liabilities are out of or are based upon
any untrue statement or alleged omission made in the Prospectus, or such
amendment or supplement, in reliance upon and in conformity with written
information provided to Benton by Soliciting Dealer for use in the preparation
thereof. This indemnity agreement will be in addition to any liability which
Benton may otherwise have.
Soliciting Dealer will indemnify and hold harmless Benton, and each
person, if any, who controls Benton within the meaning of either of the Acts,
against any losses, claims, damages or liabilities, joint or several, to which
Benton, or any such controlling person may become subject, under either of the
Acts, at common law or otherwise insofar as such losses, claims, damages or
liabilities (or actions in respect thereof) arise out of or are based upon and
are caused by any unauthorized conduct or action on Soliciting Dealer's part in
connection with its duties and obligations hereunder or arise out of or are
based upon and cause by any untrue statement or alleged untrue statement of any
material fact contained in the Prospectus, or any amendment or supplement
thereto, or the omission or alleged omission to state therein a material fact
required to be stated therein or necessary to make the statements therein not
to be stated therein or necessary to make the statements therein not
misleading, in each case to the extent, but only to the extent, that such
untrue statement or omission or alleged omission was made in the Prospectus, or
such amendment or such supplement, in reliance upon and in conformity with
written information furnished to Benton by Soliciting Dealer specifically for
use in the preparation thereof or statements or representations made by
Soliciting Dealer that are not consistent with the information disclosed in the
Prospectus; and will reimburse Benton, and each controlling person for any
legal or other expenses reasonably incurred by it in connection with
investigating or defending any such loss, claim, damage, liability or action.
This indemnity agreement will be in addition to any liability claims, losses or
damages resulting from offers or sales by any person or entity other than
Soliciting Dealer.
Promptly after receipt by an indemnified party under this Section of
notice of the commencement of any action, such indemnified party will, if a
claim in respect thereof is to be made against the indemnifying party under
this Section, notify the indemnifying party in writing of the commencement
thereof, by the omission to so notify the indemnifying party will not relieve
it from any liability which it may have to any indemnified party otherwise than
under this Section. In case any such action is brought against any indemnified
party, and it notifies the indemnifying party of the commencement thereof, the
indemnifying party will be entitled to participate in and, to the extent that
it may wish, jointly with any other indemnifying party, similarly notified, to
assume the defense thereof, with counsel satisfactory to such indemnified
party, of its election to so assume the defense thereof, the indemnifying party
will not be liable to such indemnified party under this Section for any legal
or to other expenses subsequently incurred by such indemnified party in
connection with the defense thereof to other than reasonable costs of
investigation.
<PAGE> 3
7. INDEMNITIES TO SURVIVE CLOSING. The respective indemnities,
agreements, representations and other statements of Benton and of Soliciting
Dealer set forth in or made in writing pursuant to this agreement will remain
in full force and effect, regardless of any investigation made by or on behalf
of Soliciting Dealer, Benton or any controlling person and will survive the
closing of the Exchange Offer and Benton, Soliciting Dealer or any controlling
person, as the case may be, shall be entitled to the benefit of the respective
indemnity agreements.
8. GOVERNING LAW. This agreement will be governed by and construed in
accordance with the laws of the state of California.
9. NOTICES. All communications hereunder will be in writing and if
sent to Soliciting Dealer will be mailed and delivered or faxed and confirmed
to it at ___________________________________________; or if sent to Benton will
be mailed, delivered or faxed and confirmed to: Benton Oil and Gas Company,
1145 Eugenia Place, Suite 200, Carpenteria, California 93013.
If the foregoing is in accordance with Soliciting Dealer's
understanding of our agreement, sign and return to us the enclosed duplicate
hereof, whereupon it will become a binding agreement between us in accordance
with it's terms.
Very truly yours,
Benton Oil and Gas Company
By:
---------------------------
The foregoing agreement is hereby confirmed and accepted by us as of
the date first above written.
Soliciting Dealer
------------------------------
By:
---------------------------
3
<PAGE> 1
EXHIBIT 4.2
BENTON OIL & GAS
COMBINATION PARTNERSHIP 1989-1
LIMITED PARTNERSHIP
<PAGE> 2
<TABLE>
<CAPTION>
TABLE OF CONTENTS
Page
----
<S> <C>
ARTICLE I. NAME AND PRINCIPAL OFFICE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
ARTICLE II. DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
ARTICLE III. PURPOSE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
ARTICLE IV. CAPITAL OF THE PARTNERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
A. Capital Contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
B. Determination of Capital Accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
C. Simulated Depletion Account . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
D. Interest on Capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
ARTICLE V. COSTS CHARGED TO PARTNERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
A. Partnership Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
B. Operating Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
C. Other Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
D. Loss on Sale of Partnership Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
ARTICLE VI. ALLOCATION OF REVENUES AND DISTRIBUTIONS OF CASH . . . . . . . . . . . . . . . . . . . . . . . 8
A. Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
B. Cash Distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
C. Allocations Among Participants and Co-Managing General Partners . . . . . . . . . . . . . . . 9
ARTICLE VII. ELECTIONS AND ALLOCATION OF DEDUCTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
ARTICLE VIII. APPLICATION OF PROCEEDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
ARTICLE IX. TERM AND CONVERSION OF GENERAL PARTNER UNITS . . . . . . . . . . . . . . . . . . . . . . . . . 12
ARTICLE X. RIGHTS AND OBLIGATIONS OF BENTON AND EPC . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
ARTICLE XI. COMPENSATION OF BENTON AND EPC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
ARTICLE XII. PROTECTION OF THE PARTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
ARTICLE XIII. RELATED PARTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
ARTICLE XIV. RESTRICTIONS ON TRANSFERABILITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
ARTICLE XV. RIGHTS, AUTHORITY AND LIABILITIES OF PARTICIPANTS . . . . . . . . . . . . . . . . . . . . . . . 22
A. Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
</TABLE>
i
<PAGE> 3
<TABLE>
<S> <C>
B. Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
C. Liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
D. Miscellaneous . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
ARTICLE XVI. WITHDRAWAL OF BENTON OR EPC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
A. Events Requiring Consent of All Partners to Avoid Withdrawal . . . . . . . . . . . . . . . . 24
B. Events Not Causing Withdrawal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
ARTICLE XVII. DISSOLUTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
ARTICLE XVIII. ASSESSMENTS AND BORROWINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
ARTICLE XIX. POWER OF ATTORNEY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
ARTICLE XX. TAX MATTERS PARTNER . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
ARTICLE XXI. MISCELLANEOUS PROVISIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
A. Notices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
B. Binding Nature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
C. Entire Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
D. Severability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
E. Counterparts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
F. Governing Law . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
G. Amendments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
H. Captions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
I. Execution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
J. Parties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .32
K. Evidence of Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
L. Certificate of Limited Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
</TABLE>
ii
<PAGE> 4
BENTON OIL & GAS
COMBINATION PARTNERSHIP 1989-1
LIMITED PARTNERSHIP
AGREEMENT OF LIMITED PARTNERSHIP
This is an Agreement of Limited Partnership (the "Agreement"), made and
entered into as of September 1, 1989, by and among Benton Oil & Gas Company, a
Delaware corporation ("Benton"), and Energy Partners Corporation, a California
corporation ("EPC"), as "Co-Managing General Partners," and all other persons
who are parties to this Agreement by execution of this Agreement or a
Subscription Agreement (herein so called), or as assignees or transferees of
such persons (collectively, the "Subscribers" or the "Participants").
W I T N E S S E T H :
In consideration of the premises and mutual covenants herein
contained, the parties do hereby form a partnership (the "Partnership") under
and pursuant to the California Revised Uniform Limited Partnership Act, upon
the terms and conditions hereinafter set forth.
ARTICLE I. NAME AND PRINCIPAL OFFICE
(A) The business of the Partnership shall be conducted under the
name "Benton Oil & Gas Combination Partnership 1989-1 Limited Partnership."
(B) The principal office of the Partnership and the address of EPC
shall be 5151 Shoreham Place, Suite 250, San Diego, California 92122-3991,
provided that Benton or EPC may change the address of the principal office of
the Partnership and of EPC by giving notice to all Partners. EPC may maintain
such other offices for the Partnership as it may deem necessary or advisable.
(C) The address of each Participant shall be that stated on that
Participant's Subscription Agreement or assignment document, subject to written
notice of change given by the Participant to Benton.
ARTICLE II. DEFINITIONS
AFFILIATE. An "Affiliate" of Benton or EPC means: (a) any person
directly or indirectly owning, controlling, or holding, with power to vote, 10%
or more of the outstanding voting securities of Benton or EPC; (b) any person,
10% or more of whose outstanding voting securities are directly or indirectly
owned, controlled, or held, with the power to vote, by Benton or EPC; (c) any
person directly or indirectly controlling, controlled by, or under common
control with Benton or EPC; (d) any officer or director of Benton or EPC or
their Affiliates; (e) any entity for which Benton or EPC or their officers and
directors acts in the capacity of an officer, director or general partner.
<PAGE> 5
ASSESSMENTS. Additional amounts of capital which may be required by
the Partnership to be paid by a Participant in addition to his Subscription.
BENTON. Benton Oil & Gas Company, a Co-Managing General Partner.
CASING POINT. "Casing Point" means the point in time in the drilling
of a well when total depth has been reached, appropriate tests have been made
and a decision must be made to run and set production casing or production
liner, as the case may be, and a decision to commence attempting to complete
the well is made or the well is plugged and abandoned.
COMPLETION COSTS. "Completion Costs" means, as to any well, all those
costs incurred after Casing Point. 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.
COST. When used in connection with selling undeveloped leases and
other interests to the Partnership or providing for the drilling of a
Partnership well by Benton, EPC and their Affiliates, "Cost" shall mean the sum
of (1) the amounts paid by Benton, EPC or their Affiliates to unaffiliated
third parties for the property, including bonuses; (2) title insurance or title
examination costs, brokers' commissions, filing fees, recording costs, transfer
taxes, if any, and like charges in connection with the acquisition of the
property; (3) delay rentals and ad valorem taxes paid with respect to the
property to the date of its transfer to the Partnership; (4) interest on funds
used to acquire or maintain the property; (5) equipment, drilling, seismic and
all other usual costs for the acquisition and development of a property or
having a well drilled; and (6) a portion of Benton's, EPC's or their
Affiliates' reasonable, necessary and actual direct expenses for geological,
geophysical, seismic, engineering, drafting, accounting, legal and other like
services, including a share of compensation of employees or officers, allocated
to the property in accordance with generally accepted and customary industry
practices, and screening costs paid to third parties for geological,
geophysical and seismic evaluations of Benton's, EPC's or their Affiliates'
lease inventory, to the extent such evaluations condemn the acreage prior to
selection for the Partnership. Delay rentals, ad valorem taxes, interest on
funds used to acquire or maintain properties and direct expenses will not be
included in "Cost" when such expenses were incurred by Benton, EPC or their
Affiliates in connection with the past drilling of wells which are not
producers of sufficient quantities of oil or gas to make commercially
reasonable their continued operation, or when such expenses, as enumerated in
subsections (3) and (4) hereof, were incurred more than 36 months prior to the
purchase of the property interest by the Partnership. When used with respect
to services, "Cost" means the reasonable, necessary and actual expenses
incurred by Benton, EPC or their Affiliates on behalf of the Partnership in
providing such services, determined in accordance with generally accepted and
customary industry practices. Except as otherwise indicated or as the context
requires, "cost" means the price paid by Benton, EPC or their Affiliates in a
fair or arm's length transaction.
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<PAGE> 6
DEVELOPMENT WELL. A well drilled as an additional well to the same
reservoir as other producing wells on a lease, or drilled on an offset lease
usually not more than one location away from a well producing from the same
reservoir.
DIRECT EXPENSES. Those third party expenses which are directly
attributable to the Partnership. These expenses include the costs of outside
accounting and auditing services, reserve and engineering reports, legal fees
and other third party expenses where such other third party costs would not be
incurred except for the requirements imposed by the terms of the Partnership
Agreement.
EPC. Energy Partners Corporation, a California corporation, a
Co-Managing General Partner.
ESCROW AGENT.A bank which will act as escrow agent to hold the
subscription amounts of all investors prior to the Offering Termination Date
for the Partnership.
EXPLORATORY WELL. A well drilled either in search of a new and as yet
undiscovered pool of oil or gas, or to extend greatly the limits of a field
under development.
GENERAL AND ADMINISTRATIVE EXPENSES. Those reasonable and necessary
expenses incurred by Benton, EPC and their Affiliates for administering the
Partnership including, without limitation, computer use costs, accounting and
legal fees, geological and engineering costs, office rent, telephone expenses,
secretarial salaries, the cost of printing and mailing reports to the
Participants and reimbursement of the out-of-pocket operating costs (including
employee costs and a fair allocation of general office overhead computed on a
cost basis) of Benton, EPC and their Affiliates which pertain to Partnership
business. All overhead costs shall be allocated in accordance with generally
accepted industry standards, subject to annual independent audit.
GENERAL PARTNER. A person or entity who executes the Subscription
Agreement and the Partnership Agreement as a General Partner and/or any person
who becomes a substitute General Partner in accordance with the terms of such
Partnership Agreement.
JOINT AND SEVERAL LIABILITY. Joint liability is liability in which
co-obligors must all be joined as co-defendants in any action, whereas joint
and several liability is where a claimant against the Partnership, at his
option, may sue any one or more of the obligors, in this case, the General
Partners.
LIMITED PARTNER. A person or entity who executes the Subscription
Agreement and the Partnership Agreement as a Limited Partner and/or any person
who becomes a substitute Limited Partner in accordance with the terms of such
Partnership Agreement.
LOWER RISK WELL. A well which is lower risk than an Exploratory Well
due to its location in an area having a history of proven hydrocarbon
production and to its (a) being controlled seismically, (b) being controlled
through subsurface geology, or (c) proximity to existing, producing wells.
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<PAGE> 7
MANAGING GENERAL PARTNER. Benton or EPC, each of whom is a Co-Managing
General Partner of the Partnership.
NET PROCEEDS. The Proceeds, less the sum of Sales Commissions,
Organizational Expenses, the first year General and Administrative Costs and
Partnership Working Capital.
OFFERING TERMINATION DATE. The date on which the offering of Units
described in the Memorandum terminates with regard to the Partnership;
specifically, July 31, 1989 (subject to an extension of up to 30 days).
ORGANIZATION AND OFFERING EXPENSES. All costs of organizing and
selling the Partnership, including, but not limited to, underwriting
commissions (including fees of underwriters' attorneys), expenses for printing,
mailing, and other expenses of qualification of the sale of securities under
federal and state law, including taxes and fees, accountants' and attorneys'
fees and other front-end fees.
PARTICIPANT. Each person or entity holding any number of Units in the
Partnership, whether such individual owns these Units as a General Partner or
as a Limited Partner. The term "Participant" also includes Benton and EPC to
the extent they purchase interests on the same basis as other Participants and
to the extent of their 1% capital contributions.
PARTNERSHIP. The partnership formed pursuant to the offering described
in this Memorandum; specifically, Benton Oil & Gas Combination Partnership
1989-1 Limited Partnership.
PARTNERSHIP AGREEMENT. The Limited Partnership Agreement to be entered
into by and among Benton, EPC and the Participants, in respect of the
Partnership.
PARTNERSHIP WELLS. The wells to be drilled by this Partnership, and
includes Development Wells, Lower Risk Wells and Exploratory Wells.
PARTNERSHIP WELL COSTS. The Costs of (a) acquiring leases, performing
geological, geophysical and seismic tests on leasehold property, drilling,
testing, completing or equipping wells, including geological and engineering
services, whether provided by Benton or third parties, (b) constructing and/or
purchasing facilities and equipment such as pumping units, storage facilities
and separators which are necessary for the operation of a well, (c)
constructing gathering lines from each well to a gas transmission pipeline in
the area, and (d) abandoning a well prior to commercial production.
Partnership Well Costs do not include the costs of operating such wells or
Direct Expenses or General and Administrative Expenses of operating the
Partnership.
PROCEEDS. The amount paid by all Subscribers for Units in the
Partnership, including amounts paid by Benton or EPC for Units, and amounts
paid by Benton and EPC as capital contributions to the Partnership.
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<PAGE> 8
PROSPECT. An area in which the Partnership owns or intends to own one
or more oil and gas interests, which is geographically defined on the basis of
geological data by Benton and which is reasonably anticipated by Benton to
contain at least one reservoir.
PROVEN PRODUCING PROPERTIES. Properties acquired by the Partnership
which are currently producing oil and/or gas.
RECOMPLETION WELLS; REWORK WELLS. Wells purchased by the Partnership,
in which the Partnership intends to recomplete so as to enhance their oil
and/or gas production either by completing to a shallower or deeper formation,
refracing, or any other method designed to enhance oil and/or gas revenues, in
the discretion of the Co-Managing General Partners.
SELLING COMMISSIONS. Selling Commissions of 9% of the Subscriptions of
the Participants.
SUBSCRIBER. The investor who executes a Subscription Agreement and
becomes a Participant, at such time as the Subscription is accepted by EPC.
SUBSCRIPTION AGREEMENT. The instrument executed by a Subscriber which
also constitutes execution of the Partnership Agreement upon acceptance of the
Subscription Agreement by EPC.
SUBSCRIPTIONS. Monies paid by Subscribers as initial capital
contributions to the Partnership.
UNITS. Units of assessable preformation partnership interest in the
Partnership, and such interests after formation of the Partnership, each
representing an original capital contribution of $5,000 to the Partnership.
ARTICLE III. PURPOSE
The sole purpose and ordinary business of the Partnership shall be to
explore for oil and gas, to acquire undeveloped and Proven Producing Properties
and other interests, to drill Exploratory, Developmental and Lower Risk Wells,
to acquire and recomplete existing wells, to dispose of properties, and to
conduct all other operations relating to the exploration, production and sale
of oil and gas as Benton deems to be in the best interest of the Partnership,
including the sale of all or substantially all of the Partnership's assets. It
is expected that Partnership operations will be undertaken primarily in the
state waters of Texas and offshore Louisiana, but the Partnership may
participate in other areas of the country, at the discretion of the Co-Managing
General Partners.
ARTICLE IV. CAPITAL OF THE PARTNERS
A. CAPITAL CONTRIBUTIONS
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<PAGE> 9
(1) Each Participant has made a capital contribution to
the Partnership in cash equal to the amount set forth in the
Subscription Agreement submitted to EPC by the Participants and
accepted by EPC. A Participant's interest in the Partnership,
including his interest in undistributed profits, will be subject to
the debts of the Partnership.
(2) Benton and EPC will make a capital contribution to the
Partnership as required to pay their share of costs as provided in
Article V hereof, and in return for such payments, Benton, EPC and
other General Partners shall be entitled to share in all items of
income, gain, loss, deduction or credit allocated to the respective
Partners as provided in Article VI.
(3) Benton and EPC will make a capital contribution as a 1%
General Partner if no other Participants subscribe for general
partnership units. Otherwise, Benton and EPC will make no capital
contribution for their interest.
(4) Each investor is subject to assessments in the amount
of up to 25% of the amount of their original capital contribution.
B. DETERMINATION OF CAPITAL ACCOUNTS
A single capital account shall be maintained for each Partner (or
transferee of a Partner, which transferee shall have the capital account of his
transferor, as of the effective date of the transfer). The capital account for
each Partner will be determined based on the Regulations regarding maintenance
of capital accounts promulgated under {704(b) of the Internal Revenue Code.
Generally, these Regulations provide that capital accounts of Partners shall be
increased by (1) the amount of money contributed by a partner to the
partnership, (2) the fair market value of property contributed by a partner to
the partnership, (3) allocation to a partner of partnership income and gain (or
items thereof), and (4) interest earned on Subscriptions after formation of the
Partnership. Capital accounts will be decreased by (1) the amount of money
distributed to a Partner by the Partnership, (2) the fair market value of
property distributed to a Partner by the Partnership, (3) allocations of
Partnership loss and deduction (or items thereof), and (4) organizational and
syndication costs which are not amortized.
In the event of a distribution in kind of any property, the capital
accounts of the Partners shall first be adjusted to reflect the manner in which
the unrealized income, gain, or loss inherent in the property (which has not
been previously reflected in capital accounts) would be allocated among the
Partners if there were a taxable disposition of the property at its fair market
value.
C. SIMULATED DEPLETION ACCOUNT
Solely for purposes of maintaining capital accounts, depletion with
respect to oil and gas properties shall be computed at the Partnership level.
The Partnership shall compute a simulated depletion allowance on each oil or
gas property using the percentage depletion method. The Partnership's
simulated depletion allowance shall reduce the Partners' capital accounts in
the
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<PAGE> 10
same proportion as such Partners (or their predecessors in interest) were
allocated adjusted basis with respect to such property. The aggregate capital
account adjustments for simulated depletion allowances with respect to an oil
or gas property shall not exceed the Partnership's adjusted tax basis in such
property. Upon the taxable disposition of an oil or gas property by the
Partnership, the Partnership's simulated gain or loss shall be determined by
subtracting its simulated adjusted basis in such property from the amount
realized from such disposition. (The Partnership's simulated adjusted basis in
an oil and gas property is determined in the same manner as adjusted tax basis
except that simulated depletion allowances are taken into account instead of
actual depletion allowances.) Any resultant simulated gain shall be allocated
to the Partners in the same manner as that portion of the amount realized from
such disposition which exceeds the Partnership's simulated adjusted basis in
such property is allocated to such Partners and shall increase such Partners'
capital accounts accordingly. Any resultant simulated loss shall be allocated
to the Partners in proportion to the Partners' allocable shares of the total
amount realized from the disposition of such property that represents recovery
of the Partnership's simulated adjusted basis in such property, and shall
reduce such Partners' capital accounts accordingly.
D. INTEREST ON CAPITAL
No interest shall be paid on the capital account of or capital
contributed by any Partner either before or after the time repayment should be
made.
ARTICLE V. COSTS CHARGED TO PARTNERS
The accounts of the Partners shall be charged as follows for items
expended by the Partnership, provided that costs paid out of assessments shall
only be charged to Partners who paid such assessments:
A. PARTNERSHIP COSTS
All Partnership Well Costs, including completion costs, costs of
Recompletion Wells, costs of acquiring Proven Producing Properties, geological,
geophysical and seismic costs and Organization and Offering Expenses shall be
allocated one hundred percent (100%) to the Participants.
B. OPERATING COSTS
The expenses of operating Partnership wells are to be shared in the
same ratio that revenues are shared in such wells, pursuant to paragraph A of
Article VI. In addition, operating costs shall include the costs of
recompleting Partnership Wells.
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C. OTHER COSTS
All costs which are not otherwise specifically
provided for in Article V(A) above, including, but not limited to General and
Administrative and Direct Expenses, shall be allocated one hundred percent
(100%) to the Participants.
Costs charged to Participants and the Co-Managing General Partners
will be allocated among the Participants as provided below in paragraph C of
Article VI.
D. LOSS ON SALE OF PARTNERSHIP ASSETS
If the Partnership sells any oil and gas property at a price which is
less than its undepleted cost, the Partnership shall allocate the loss on such
sale to the Partners in the ratio of their remaining undepleted bases in such
property at the time of sale.
If the Partnership sells any asset, other than an oil and gas property,
at a price which is less than its undepreciated cost, the Partnership shall
allocate the loss on such sale to the Partners who bore the cost of such asset.
ARTICLE VI. ALLOCATION OF REVENUES AND DISTRIBUTIONS OF CASH
A. REVENUES
All Partnership Revenues from Proven Producing Properties shall be
allocated one hundred percent (100%) to the Participants. All Partnership
Revenues from Recompleted Wells shall be allocated seventy-five percent (75%)
to the Participants and twenty-five percent (25%) to the Co-Managing General
Partners. All Partnership revenues from Partnership Wells shall be allocated
sixty-five percent (65%) to the Participants and thirty-five percent (35%) to
the Co-Managing General Partners. For Partnership purposes, "Revenues" shall
mean funds received by the Partnership from all sources, except capital
contributions, borrowings, assessments and interest on subscriptions, whether
occurring during the term of the Partnership or occurring as part of any plan
of dissolution and liquidation of the Partnership. Provided, however, that the
portion of the revenues generated by the taxable disposition of a Partnership
oil and gas property that represents recovery of its simulated adjusted tax
basis therein will be allocated to the Partners in the same proportion such
Partners (or their predecessors in interest) were allocated the basis of such
property pursuant to paragraph C of Article IV. Provided further, that the
portion of the revenues generated by the taxable disposition of a Partnership
asset, other than an oil and gas property, equal to the Partnership's adjusted
tax basis in such property shall be allocated to the Partners in the same
proportion that the Partners bore the cost of such asset.
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B. CASH DISTRIBUTIONS
(1) The Partnership expects to distribute quarterly, or on a more
current basis if so determined by the Co-Managing General Partners, amounts to
the Participants equal to approximately the difference between revenues
allocated to the respective Partners as provided in this Article, and costs
charged to the Partners as provided in Article V. This provision shall not,
however, serve as a limitation on Benton's right to retain, pledge or use so
much of the revenues or other assets of the Partnership, including amounts
required to eliminate any capital deficit of the Partners, to conduct
additional operations of the Partnership, to establish reserves for anticipated
expenditures, or to repay any amounts borrowed by the Partnership to finance
the conduct of such operations.
(2) Upon the sale of any Partnership property at a gain, a
Partner's share of any gain may be applied to reduction of any deficits in
capital accounts of Partners caused by distribution in excess of their share of
Partnership profits and losses.
C. ALLOCATIONS AMONG PARTICIPANTS AND CO-MANAGING GENERAL PARTNERS
All allocations of income, gain, loss and deduction to the
Participants as a class shall be allocated among the Participants based on the
ratio of their respective paid capital contributions, including assessments.
Expenses and other costs paid from assessments shall be allocated only to those
Partners who paid the assessment. All allocations of income, gain, loss,
deduction and all capital contributions and assessments to the Co-Managing
General Partners will be divided 80% to Benton and 20% to EPC.
ARTICLE VII. ELECTIONS AND ALLOCATION OF DEDUCTIONS
For purposes of federal income taxes, and appropriate state or
local income taxes, the following allocations shall be made:
A. To the extent permitted by law, all income, gain, losses and
deductions shall be allocated to the party who has been charged with the
expenditures or credited with the revenues giving rise to such deductions or
income; and to the extent permitted by law, such party shall be entitled to
such deductions and income in computing taxable income or tax liabilities to
the exclusion of any other party.
B. The basis of Partnership properties for purposes of Code
Section 613A(c)(7)(D) shall be allocated in the same ratio as Partnership Costs
are allocated.
C. Notwithstanding the foregoing, however, production required to
be allocated for the purpose of computing the depletion deduction (including
percentage depletion in excess of the depletable basis of the property) shall
be allocated in the ratio in which the related revenues are shared.
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D. All tax credits and tax credit recapture shall be allocated in
the ratio in which revenues are shared at the time the expenditure giving rise
to such tax credit arises.
E. The Partnership shall make an election to deduct intangible
drilling and development costs on its federal income tax return in accordance
with the option granted by the Internal Revenue Code of 1986. No election
shall be made by the Partnership to be excluded from the application of the
provisions of Subchapter K of the Internal Revenue Code of 1986.
F. In the event of the transfer of an interest in the Partnership,
or in the event of the distribution of property to any party hereto, the
Partnership may (but is not required to) file an election in accordance with
the applicable Treasury Regulations to cause the basis of the Partnership's
assets to be adjusted for federal income tax purposes as provided by {{734 and
743 of the Internal Revenue Code of 1986.
G. Notwithstanding any other provision of this Article VII, if the
capital accounts of all Participants are not equal and if any allocation of
loss or deduction to a Partner would reduce such Participant's capital account
balance below zero or would increase the negative balance in such Participant's
capital account at a time when another Participant has a positive capital
account balance, as determined at the close of the period in respect of which
the loss or deduction, as the case may be, is to be allocated, such excess
shall instead be allocated pro rata to Participants having positive capital
account balances until such capital account balances are reduced to zero;
provided, however, that in no event shall there be a reallocation of any item
of income, gain, loss or deduction allocated among the Partners pursuant to
this Agreement for prior years.
Notwithstanding any other provision of this Article VII, if any
allocation of loss or deduction would cause the capital account balances of any
Participant to be negative (or would increase the negative balance of a
Participant's capital account) at a time when no other Participant has a
positive capital account balance, such loss or deduction shall instead be
allocated to the Co-Managing General Partners.
For purposes of determining a Participant's capital account balance
under this Paragraph G, distributions made prior to or contemporaneous with any
allocation to a Participant shall be reflected in such Participant's capital
account prior to making such allocation to such Participant. For purposes of
this paragraph G, a Partner's capital account shall be reduced for:
(1) Adjustments that, as of the end of each Partnership
year, reasonably are expected to be made to such Partner's capital
account under paragraph (b)(2)(iv)(k) of Treas. Reg. {1.704-1 for
depletion allowances with respect to oil and gas properties of the
Partnership, and
(2) Allocations of loss and deduction which, as of the end
of such year, are reasonably expected to be allocated to such Partner
pursuant to Code Section 704(e)(2), Code Section 706(d) and Treas.
Reg. {1.751-1(b)(2)(ii), and
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(3) Distributions that, as of the end of such year,
reasonably are expected to be made to such Partner to the extent they
exceed offsetting increases to such Partner's capital account that
reasonably are expected to occur during (or prior to) the Partnership
taxable years in which such distributions reasonably are expected to
be made.
For purposes of determining the amount of expected distributions and
expected capital account increases described in (3) above: (i) the rule set
forth in Treas. Reg. {1.704-1(b)(2)(iii)(c) concerning the presumed value of
Partnership property shall apply, and (ii) gross income or items of income or
gain allocated to a Partner pursuant to paragraph H hereof shall be taken into
account. For purposes of this paragraph G and paragraph H, a Partner's
capital account shall be increased to the extent that such Partner is obligated
to fund deficits in such Partner's capital account upon liquidation of the
Partnership (or is treated as obligated to so restore such deficits pursuant to
Treas. Reg. {1.704-1(b)(2)(ii)(c)).
H. In the event any Partners unexpectedly receive any adjustments,
allocations, or distributions described in Treas. Reg.{1.704-1(b)(2)(ii)(d)(4),
1.704(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6) so as to cause a deficit, or
increase a deficit, in the Partner's capital account, items of Partnership
income and gains shall be specially allocated to such Partners in an amount and
manner sufficient to eliminate the deficit balances in their capital accounts
created by such adjustments, allocations, or distributions as quickly as
possible. Any special allocations of income, gain, loss or deduction pursuant
to paragraph G and this paragraph H shall be taken into account in computing
subsequent allocations of income, gain, loss and deduction pursuant to this
Article VII, so that the net amount of any items so allocated and the income,
gain, loss and deduction and all other items allocated to each Partner pursuant
to this Article VII shall, to the extent possible, be equal to the net amount
that would have been allocated to each such Partner pursuant to the provisions
of this Article VII if the reallocations provided in paragraphs G and H had not
occurred.
ARTICLE VIII. APPLICATION OF PROCEEDS
All Net Proceeds will be used solely for the conduct of Partnership
operations.
In view of the fact that any Partnership activities will not commence
until sales are closed and Partnership operations commence, Benton and EPC
reserve the right to change the estimated allocation of Proceeds, as described
below, in the best interest of the Partnership. However, it is anticipated
that the Net Proceeds will be applied by the Partnership, on the basis of
approximately the following percentages:
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<TABLE>
ACTIVITY--ASSUMING THE MINIMUM PERCENTAGE OF NET
AMOUNT OFFERED IS RAISED: PROCEEDS
<S> <C>
Acquisition of Producing Properties . . . . . . . . . . . . . . . . . . . 100.0%
ACTIVITY--ASSUMING THE MAXIMUM
AMOUNT OFFERED IS RAISED:
Acquisition of Producing Properties . . . . . . . . . . . . . . . . . . . 48.0%
Recompletion of Wells . . . . . . . . . . . . . . . . . . . . . . . . . 23.5%
Geological, Geophysical and Seismic Costs . . . . . . . . . . . . . . . . 12.0%
Drilling and Completion of Partnership Wells . . . . . . . . . . . . . . 16.5%
</TABLE>
Notwithstanding the foregoing, Benton and EPC reserve the right to
vary substantially the percentage of Net Proceeds allocated towards the various
activities described above, depending upon the total amount of Proceeds raised
by Benton, EPC and others from offerings which will raise funds to participate
on the same Prospects as that anticipated to be acquired, developed or reworked
by this Partnership.
ARTICLE IX. TERM AND CONVERSION OF GENERAL PARTNER UNITS
A. The term of the Partnership will commence on the date of
execution of this Agreement, and will continue until December 31, 2039, and will
terminate at such earlier time as all of the interests and properties acquired
for the Partnership have been fully depleted, disposed of, sold or abandoned,
unless sooner terminated as set forth in Article XV or XVII of this Agreement.
The calendar year is the Partnership's fiscal year, subject to change
by Benton and EPC.
B. As soon as practicable after the completion of the
Partnership's drilling activity, and subject to the receipt of the opinion of
counsel described below, the General Partner Units shall be converted to
Limited Partner Units. Such conversion shall occur automatically upon
compliance with this section. All other rights and obligations under this
Agreement shall not be affected by such conversion. Prior to any such
conversion, Benton and EPC shall obtain an opinion of tax counsel to the
Partnership to the effect that such conversion would not result in any material
adverse federal tax consequences to the Partnership or the General Partners. In
order to accomplish such conversion, Benton and EPC will (i) amend this Limited
Partnership Agreement with such changes therein or amendments thereto as are
deemed appropriate by Benton and EPC and that do not adversely affect the
General Partners, (ii) file an amended Certificate of Limited Partnership with
the Secretary of State for the State of California and (iii) take such other
actions as are necessary or appropriate to accomplish conversion of the General
Partner interests. Notwithstanding the foregoing, Benton and EPC shall not be
obligated to cause
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conversion of the Partnership or may delay such conversion if Benton
and EPC or their tax counsel determine that conversion at that time would not
be in the best interests of the General Partners.
ARTICLE X. RIGHTS AND OBLIGATIONS OF BENTON AND EPC
A. Benton and EPC shall be the Co-Managing General Partners of the
Partnership and as such shall conduct, direct and exercise full control over
all activities of the Partnership. Generally, Benton shall be primarily
responsible for all of the Partnership's oil and gas activities and EPC shall
be primarily responsible for all the Partnership's administrative activities.
In order to carry out the purposes of the Partnership as set forth in Article
III of this Agreement all Participants agree that Benton and EPC have the
rights and obligations set forth below.
(1) Benton may purchase or sell any oil and gas interest
and may execute on behalf of the Partnership any and all documents or
instruments of any kind which Benton may deem appropriate in carrying
out the interests of the Partnership, including, but without
limitation, deeds, assignments, leases, subleases, operating
agreements, farmout agreements, unitization agreements, pooling
agreements, sales contracts, gas sales contracts, transportation
contracts, division orders, transfer orders, or other marketing
agreements, documents or instruments of any kind or character or
amendments thereto, which relate to the affairs of the Partnership;
(2) EPC shall maintain complete and accurate books of
account for the Partnership; said books shall be kept at the principal
office of the Partnership and shall be open to inspection after
reasonable notice and request by any Partner or his authorized
representative, at his own expense, at any time during the ordinary
business hours;
(3) Within one hundred twenty (120) days after the end of
the fiscal year, EPC shall provide each Participant on an annual
basis, commencing at the end of the second full year of Partnership
operations, an independent petroleum engineer's appraisal of the
status of the properties;
(4) EPC shall provide each Participant with an annual
report (copies of which, together with a report on oil and gas
reserves and a tax information report, shall be furnished to
appropriate state securities administrators, as required) within
ninety (90) days after the close of the Partnership's fiscal year,
containing the following information:
(a) Financial statements, including the balance
sheet and statements of operations, Partners' equity and
changes in financial position, prepared in accordance with
generally accepted accounting principles and accompanied by an
auditor's report containing the opinion of an independent
certified public accountant;
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(b) A description of each Prospect in which the
Partnership owns an interest, including the cost, location,
number of acres under lease and interest owned by the
Partnership, except that succeeding reports will contain only
material changes from the preceding report;
(c) A summary itemization by type and/or
classification of the total fees, reimbursements and
compensation paid by the Partnership, or indirectly on behalf
of the Partnership, to Benton, EPC, or their Affiliates during
the period; and
(d) A schedule reflecting the total Partnership
costs, and where applicable, the costs pertaining to each
Prospect, the costs paid by Benton and the costs paid by the
Participants, the total Partnership revenues, the revenues
received or credited to Benton, and the revenues received or
credited to the Participants during the period;
(5) EPC shall furnish a report to each Participant by March 15 of
each year, containing such information as EPC deems necessary for the proper
presentation of federal income tax returns;
(6) EPC shall maintain, at the principal office of the
Partnership, copies of the Partnership's federal, state and local income tax
returns and reports for the three (3) most recent years;
(7) Benton will purchase, at the expense of the Partnership,
liability and other insurance to protect the Partnership's properties and
business;
(8) Benton and EPC may enter into any agreement for the borrowing
of money from a commercial bank or other lending institution for payment of
expenses of drilling and completion activities on wells started with Proceeds
and for payment of General and Administrative Expenses, including the purchase
and lease of oil and gas properties or equipment, and are authorized to assign
any portion of, or all of, the Partnership's properties and revenues therefrom
for the purpose of securing any such borrowed money; provided, however, that
such borrowing shall not exceed, in principal amount, twenty-five percent (25%)
of the Proceeds plus all paid assessments and providedthat in no event will the
lender have the election to convert its position as creditor into an equity
interest in the Partnership or in Benton, EPC or in any of their Affiliates;
(9) Benton and EPC may, in the sole exercise of their discretion,
make unsecured loans and advances to the Partnership at Benton's and EPC's
interest cost and may otherwise borrow money and assign to the lender
Partnership properties and production therefrom as security; and, provided
further, that the interest on loans and advances made by Benton and EPC or
their Affiliates shall not exceed the amounts which
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<PAGE> 18
would be charged by unrelated banks (without regard to financial
abilities or guarantees) on comparable loans for the same purpose, and no fees,
points or other financing charges will be charged to the Partnership by Benton,
EPC or their Affiliates;
(10) In the states where the Partnership conducts activities, EPC
may file any necessary instruments required to qualify the Partnership to do
business in the particular state as a Limited Partnership, or to cause the
limited partnership status of the entity to be recognized;
(11) Benton may cause title to Partnership property to be held in
the name of Benton or an Affiliate, or the Partnership or a nominee chosen by
Benton; provided, that if property is held in the name of Benton, an Affiliate
or a nominee, an unrecorded assignment to the Partnership shall be made and
maintained in the Partnership's files and, provided further, that if it is
prohibited from making an assignment of record, the Partnership will enter into
an agreement with the record owner indicating that the properties are being
held for the benefit of the Partnership and are not subject to the debts,
obligations or liabilities of Benton or its Affiliates;
(12) Benton and EPC may admit Participants or substituted
Participants without the consent of other Participants; provided, that any
transferee of a Unit will receive a right to share in the profits and capital
of the Partnership but will not be a substituted Participant without the prior
written consent of Benton and EPC and, provided further, that Benton and EPC
will withhold their written consent in the event that it has reasonably
determined in its sole discretion that such substitution could have an adverse
effect on the business activities or the legal or tax status of the
Partnership, under either state or federal law;
(13) Benton and EPC may admit one or more additional managing
general partners which may become a successor entity to Benton and EPC and take
action which would have the effect of providing an additional and/or a
successor managing general partner, if the holders of a majority of the Units
outstanding approve; provided, however, that such approval of the holders of
Units shall not be necessary if the additional managing general partner
proposed by Benton or EPC is (1) an Affiliate of Benton or EPC; (2) an entity
with which Benton or EPC has merged; or (3) a person or entity that has
purchased all or substantially all the assets of Benton or EPC;
(14) EPC may call for a vote of the Participants to be taken on the
items set forth in Article XV;
(15) EPC may cause the investment of Partnership funds in
short-term liquid securities until the expenditure of such funds is necessary
in connection with Partnership activities;
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(16) EPC and Benton may amend the Agreement, including amending the
Agreement to alter the Partnership's form so that it becomes a different type
of business entity, for business and tax reasons, subject to the provisions of
Article XV;
(17) EPC and Benton may do any and all things necessary or
appropriate in order to accomplish the purpose of the Partnership, subject to
the provisions of this Agreement;
(18) EPC and Benton may conduct other oil and gas drilling and
acquisition programs or income programs which may commence prior to, during or
subsequent to the Partnership;
(19) Benton may purchase assets from the Partnership in connection
with a dissolution of the Partnership, at a price which is the greater of the
then fair market value (which term shall mean the value of the assets as
determined by an independent oil an gas engineer) or the highest bona fide
offer for such assets by a third party, if any, regardless of any difference
between such fair market value and the original cost to the Partnership of such
assets (subject to the approval of a majority in interest of the Participants
if the asset represents five percent (5%) or more of the value of the assets of
the Partnership);
(20) EPC may make any and all elections for purposes of federal,
state or local income taxes that it deems appropriate; and
(21) Benton and EPC may submit a partnership claim or liability to
arbitration or reference, assign the Partnership property and trust for
creditors or on the assignee's promise to pay the debts of the partnership,
confess a judgment or dispose of the goodwill of the Partnership for adequate
consideration.
B. Benton and EPC shall have no authority on behalf of the Partnership or
themselves to:
(1) Do any act in contravention of this Agreement;
(2) Use Partnership property or commingle any Partnership bank
accounts or monies with funds of Benton, EPC or their Affiliates, or to make
advances to Benton, EPC or its Affiliates, except where necessary to secure tax
benefits of prepaid drilling and completion costs, and in no event will such
advances include non-refundable payments for capital completion costs prior to
the time that a decision is made that the well warrants such equipment;
(3) Take any action with respect to Partnership assets or property
which does not primarily benefit the Partnership, including, among other
things, the utilization of Partnership funds as compensating balances for their
own benefit, and the commitment of future production if not in the best
interests of the Partnership;
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(4) Make any loans of Partnership funds to Benton, EPC or their
Affiliates;
(5) Make or institute any marketing arrangements or other
relationships affecting the property of the Partnership where the benefits are
not fairly and equitably apportioned according to the respective interests of
all parties; or
(6) Knowingly enter into any arrangements involving working
interests in any oil and gas property which commit the working interest to be
held in an entity which limits the liability of the Participants as to the
working interest so as to cause the working interest to be considered a passive
activity so that losses from the working interest may only offset passive
activity income as set forth in Section 469 of the Code.
C. The following prohibitions and restrictions shall be applicable to
Benton:
(1) If Benton sells, transfers or conveys all or any portion of a
lease to the Partnership, Benton must, at the same time, sell, transfer, or
convey to the Partnership an equal proportionate interest in all its other
leases in the same Prospects. If Benton or any Affiliate of Benton
subsequently proposes to acquire a lease on a Prospect in which that
Partnership owns an interest, or on a Prospect abandoned by the Partnership
within one (1) year preceding such proposed acquisition, Benton or its
Affiliate shall offer to the Partnership an equivalent interest in such lease
as the Partnership had in the Prospect before the proposed acquisition, or
before the abandonment; and, if cash or financing is not available to enable
the Partnership to acquire such interest, neither Benton nor any of its
Affiliates shall acquire the lease. For the purposes of this paragraph, the
term "Affiliate" shall not include another partnership whether the interest of
the Benton is identical to, or less than, Benton's interest in the Partnership.
The restrictions described in this paragraph cease with regard to the
Partnership five (5) years after the Partnership's formation. The geological
limits of the Prospect shall be enlarged or contracted on the basis of
subsequently acquired geological data to define the productive limits of a
reservoir, and must include all of the acreage determined by the subsequent
data to be encompassed by such reservoir; provided, however, that the
Partnership shall not be required to expend additional funds unless they are
available from the initial capitalization of the Partnership or if Benton
believes it is prudent to borrow for the purpose of acquiring such additional
acreage. If the geological limits of a Prospect, as so enlarged, encompass any
interest held by Benton or an Affiliate, that interest will be sold to the
Partnership in accordance with the provisions of this Article;
(2) A sale, transfer, or conveyance to the Partnership of less
than all of the ownership of Benton or its Affiliates in any portion of a lease
(the "Subject Portion") is prohibited unless the interest retained by Benton or
its Affiliates is a working interest, the respective obligations of Benton or
its Affiliates and the Partnership to pay costs with respect to the Subject
Portion are proportionate to their respective working interests after the
transfer, and Benton's or its Affiliates' interest in the revenues does not
exceed any amount proportionate to its retained working interest. Benton or
its Affiliates may not
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retain any overrides or other burdens on the Subject Portion, and may
not enter into any Farmout arrangements with respect to its retained interest,
except to nonaffiliated third parties or other partnerships sponsored by
Benton. For the purposes of this paragraph, the term "Affiliate" shall not
include another partnership where the interest of Benton is identical to, or
less than, Benton's interest in the Partnership.
(3) Purchases and sales of leases among oil and gas partnerships
sponsored by Benton are prohibited except for transactions between the
Partnership and another partnership for which Benton or any of its Affiliates
acts as sponsor, whereby a lease is transferred in exchange for the
transferee's obligation to conduct oil and gas drilling activities on such
lease, or the property is operated pursuant to a joint venture among such
partnerships, which are permitted only if the respective obligations and
revenue sharing of all parties to the transaction are substantially the same
and the compensation arrangement of Benton and any Affiliate is the same in the
Partnership and each such partnership or, if different, the aggregate
compensation of Benton and its Affiliates therefrom does not exceed the lowest
compensation Benton and its Affiliates would have received through any one of
the relevant partnerships, taking into consideration varying participation by
Benton or its Affiliates.
(4) Partnership funds may not be used to prove up adjacent
properties in any Prospect belonging to Benton or its Affiliates.
(5) Benton and its Affiliates (other than other public or private
partnerships and programs) are not permitted to purchase any producing leases
from the Partnership, but this prohibition will not prohibit the purchase by
Benton or an Affiliate of such producing leases in connection with a
dissolution or sale of substantially all of the assets. If any non-producing
lease is to be purchased from the Partnership by Benton or its Affiliates, such
purchase must be at the higher of its fair market value or the cost of such
lease to the Partnership.
(6) Benton and its Affiliates (excluding partnerships in which
Benton's interest is equal to or less than its interest in the Partnership) may
not acquire, retain, or drill for their own account any oil and gas interest on
any Prospect in which the Partnership has an interest, except as permitted by
the terms of clause (2), above. This restriction also continues for one (1)
year after abandonment as to any Prospect by the Partnership. If a Prospect is
enlarged by reason of subsequently obtained geological data to include an
interest held by Benton or its Affiliates, a portion of the interest shall be
sold to the Partnership concerned in accordance with the terms of clause A.,
above.
(7) Benton may never profit by drilling in contravention of its
fiduciary obligation to the Partners. All services provided to the Partnership
by Benton or its Affiliates will be embodied in a written contract which
precisely describes the services to be rendered and all compensation to be
paid.
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ARTICLE XI. COMPENSATION OF BENTON AND EPC
Benton maintains a staff of geologists, engineers and land personnel
who are responsible for screening and acquisition of leases and for conducting
drilling and producing operations. The costs incurred in maintaining these
departments, including salaries of personnel, are allocable in part to the
Partnership's activities and are included in Partnership Costs. Such costs
shall be paid or reimbursed by the Partnership out of Proceeds or revenues.
Benton and EPC will be reimbursed for an allocable portion of actual
General and Administrative Expenses, which will be paid as incurred and which
includes actual and necessary costs of their offices, including office
overhead, salaries, telephone, secretarial, travel, costs of accounting
services and other costs and expenses not directly related to a specific
Partnership activity. Such expense reimbursement is estimated not to exceed
three percent (3%) of the Subscriptions during the first twelve (12) months of
operations. These reimbursements will be subject to audit on an annual basis.
As set forth in Article VI, Benton and EPC will share in Partnership
revenues in an amount in excess of their contribution to Partnership costs. The
Participants consent to the receipt by Benton, EPC and their Affiliates of the
benefits and profits set forth in this Article.
ARTICLE XII. PROTECTION OF THE PARTIES
In any threatened, pending or completed action, suit or proceeding to
which the Co-Managing General Partners were or are a party or is threatened to
be made a party by reason of the fact that they were or are a Co-Managing
General Partner of the Partnership (other than an action by or in the right of
the Partnership) involving any alleged cause of action for damages arising from
the performance of oil and gas activities, including exploration, development,
completion, operation, or other activities relative to management and
disposition of oil and gas properties or production from such properties, the
Partnership will indemnify the Co-Managing General Partners against expenses,
including attorneys' fees, judgments and amounts paid in settlement 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 Participants. The termination of any
action, suit or proceeding by judgment, order or settlement shall not, of
itself, create a presumption that Benton or EPC did not act in good faith and
in a manner which they reasonably believed to be in or not opposed to the best
interests of the Partnership.
In any threatened, pending or completed action or suit by the
Partnership in the right of the Partnership, to which a Co-Managing General
Partner was or is a party or is threatened to be made a party, involving an
alleged cause of action by a Participant(s) for damages arising from the
activities of a Co-Managing General Partner in the performance of management of
the internal affairs of the Partnership as prescribed by this Agreement, the
Partnership will indemnify
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the Co-Managing General Partner against expenses, including attorneys'
fees, actually and reasonably incurred by it in connection with the defense or
settlement of such action or suit if it acted in good faith and in a manner it
reasonably believed to be in or not opposed to the best interests of the
Partnership, as specified in this paragraph, except that no indemnification
shall be made in respect of any claim, issue or matter as to which a
Co-Managing General Partner shall have been adjudged to be liable for
negligence, misconduct, or breach of fiduciary obligation in the performance of
its duty to the Partnership unless and only to the extent that the court in
which such action or suit was brought shall determine upon application, that,
despite the adjudication of liability, but in view of all circumstances of the
case, a Co-Managing General Partner is fairly and reasonably entitled to
indemnity for such expenses which the court shall deem proper.
To the extent that a Co-Managing General Partner has been successful on
the merits or otherwise in defense of any action, suit or proceeding referred
to above, or in defense of any claim, issue or matter therein, the Partnership
shall indemnify a Co-Managing General Partner against the expenses, including
attorneys' fees, actually and reasonably incurred by it in connection
therewith. Any such indemnification of a Co-Managing General Partner shall be
prohibited unless the Co-Managing General Partner has determined in good faith
that the course of conduct which caused the loss or liability was in the best
interest of the Partnership; that such liability or loss was not the result of
negligence or misconduct by a Co-Managing General Partner; and that
indemnification of a Co-Managing General Partner or its Affiliates will not be
allowed for any liability imposed by judgment, and costs associated therewith,
including attorneys' fees, arising from or out of violation of state or federal
securities laws associated with the offer and sale of Partnership Units.
Indemnification will be allowed for settlements and related expenses of a
lawsuit alleging securities law violations, and for expenses incurred in
successfully defending such lawsuits, provided that a court either: (a)
approves the settlement and finds indemnification of the settlement and related
costs should be made or (b) approves indemnification of litigation costs if a
successful defense is made.
Any indemnification, unless ordered by a court, shall be made by the
Partnership only as authorized in the specific case and only upon a
determination by independent legal counsel in a written opinion that
indemnification of a Co-Managing General Partner is proper in the circumstances
because a Co-Managing General Partner has met the applicable standard of
conduct set forth above.
The indemnification of a Co-Managing General Partner shall be limited
to and recoverable only out of the assets of the Partnership and not against
any Limited Partner or General Partner and indemnification of the Co-Managing
General Partners as to a third party is only with respect to such loss,
liability or damage not otherwise compensated for by insurance carried for the
benefit of the Partnership.
The Partnership may not incur the cost of that portion of insurance
which insures a Co-Managing General Partners from any liability as to which the
Co-Managing General Partner is prohibited from being indemnified under this
Article.
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The Participants hereby agree that each shall be solely and
individually responsible only for their pro rata share of the liabilities and
obligations of the Partnership, and any Participant who incurs liability in
excess of his pro rata share shall be entitled to contribution from the other
Participants. Pursuant thereto, each Co-Managing General Partner further
agrees to indemnify each Participant from paying any liabilities or obligations
of the Partnership in excess of such Participant's capital contribution.
Furthermore, although the Participants may be personally liable for the
liabilities and obligations of the Partnership, all such liabilities and
obligations shall be paid or discharged first with Partnership assets
(including insurance proceeds) before the Participants shall be obligated to
pay or discharge any liability or obligation with their personal assets.
ARTICLE XIII. RELATED PARTIES
Benton and EPC and their Affiliates or related persons or entities may
be engaged or employed by the Partnership to render or perform services for the
Partnership and/or may sell property of any kind or description to it, or may
otherwise engage in transactions with the Partnership. All such engagements,
employments and other transactions shall not be invalidated by reason of any
such relationships so long as such person is engaged, independently of the
Partnership and as an ongoing business in rendering such services or selling
such equipment and supplies to a substantial extent to other persons and such
prices and terms are not higher than those normally charged in the same
geographic area by unaffiliated persons or companies dealing at arm's length.
If the person is not engaged in business as provided above, then the price of
such services shall be the cost of such services, equipment or supplies to such
person or the competitive rate in the geographical area, whichever is less.
Benton or EPC may be presently conducting or may conduct in the future other
oil and gas income, drilling and acquisition programs which may commence during
or subsequent to this Partnership. All contracts entered into between the
Partnership, Benton, EPC and their Affiliates or related persons or entities
shall be terminated without penalty on not less than thirty (30) days' written
notice by the Partnership or on sixty (60) days' written notice by Benton, EPC
or their Affiliates.
The leases transferred to the Partnership by Benton or its Affiliates
shall be sold at Cost unless Benton believes that the appraised value is
substantially lower than Cost. In such a case the value of the lease will be
determined by an independent appraiser and sold at the lower of Cost or
appraised value.
ARTICLE XIV. RESTRICTIONS ON TRANSFERABILITY
No Participant shall have the power to sell, assign or transfer his
interest in the Partnership or to cause a transferee to become a substitute
Participant except upon the written consent of Benton and EPC. Each
Participant specifically agrees to the admission of any substitute Participant
as a Partner when consented to by Benton and EPC. Benton and EPC shall review
any proposed transfer and shall withhold their consent in the event they
reasonably determine, in their sole discretion, that such substitution could
have an adverse effect on the
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business activities or the legal or tax status of the Partnership or
the remaining partners under either state or federal law.
Benton and EPC may sell, assign, transfer, pledge or encumber all or
any portion of their rights to receive revenues as a Managing General Partner
under this Partnership Agreement; provided, however, that the assignment of
such revenue interest shall not affect Benton's and EPC's other rights and
obligations pursuant to this Agreement.
In addition to the restrictions upon substitution of an additional
Participant, a Participant may not sell his rights to profits and capital in
the Partnership without furnishing Benton and EPC with a copy of the offer to
buy such interest and giving Benton and EPC the prior right for a period of ten
(10) days after receipt of written notice, to purchase such interest on the
terms contained in such offer. In the event Benton and EPC do not exercise
their prior right to purchase such interest in profits and capital within a ten
(10) day period or notify the Participant that such right will not be
exercised, the Participant shall have the right to sell his interest in profits
and capital for a period of forty-five (45) days. Thereafter, the Participant
shall not sell any part of his interest in profits and capital without again
offering the same to Benton and EPC. A transferee of a Participant's right to
profits and capital who is not admitted as a Participant is not entitled to any
of the rights of a Participant. A transferee Participant has no greater right
to terminate the Partnership than his transferor.
In no event shall any assignee or transferee hold less than one Unit
except by gift or operation of law.
ARTICLE XV. RIGHTS, AUTHORITY AND
LIABILITIES OF PARTICIPANTS
A. RIGHTS
By a majority vote of the outstanding Units, the Participants shall
have the right to:
(1) Remove Benton, EPC and/or any successor Managing
General Partner; terminate all contracts between the Partnership and
Benton, EPC and their Affiliates; allow Benton, EPC or their
Affiliates to remove all of their property interests in the
Partnership; and select a substitute managing general partner or
additional general partner to continue the business of the
Partnership;
(2) Amend the Agreement, subject to the written consent of
Benton and EPC concerning matter affecting their interests in profits,
losses, credits and property;
(3) Terminate the Partnership;
(4) Approve the sale or exchange of all or substantially
all of the assets; and/or
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(5) Approve the admission of an additional general partner
proposed to be admitted as a Managing General Partner by Benton and EPC,
subject to the right of Benton and EPC to admit certain parties as
general partners without the consent of the Participants, as provided
in paragraph 13 of Article X.
Either the Participants, upon the written request of ten percent (10%)
of the outstanding Units, or Benton or EPC can cause a vote to be taken with
respect to the matters referred to above. Notice of a meeting of the
Participants will be mailed to the Participants within ten (10) days of the
receipt of such written notice unless compliance with federal or state laws or
regulations requires additional time. A meeting will be held within sixty (60)
days of the mailing of the notice. The presence, in person or by proxy, of the
holders of a majority of the Units outstanding shall constitute a quorum and
Participants may vote in person or by proxy at any such meeting. If a quorum
shall not be present or represented at any meeting, a majority of the holders
of Units entitled to vote at the meeting, who are present in person or
represented by proxy, may adjourn the meeting from time to time, without notice
other than announcement at the meeting, until a quorum shall be present or
represented. At any reconvening of an adjourned meeting at which a quorum
shall be present or represented, any business may be transacted which could
have been transacted at the original meeting if a quorum had been present or
represented. No matters that would constitute taking part in control of the
Partnership by the Participants shall be considered at any meeting. In order
to facilitate the above rights, each Participant shall have a right to receive
by mail the complete list of names, addresses and interests of all other
Participants, upon written request to EPC.
Any action that may be taken at a meeting of the Participants may be
taken without a meeting if a consent in writing setting forth the action so
taken is signed by Participants owning not less than the minimum Units that
would be necessary to authorize or take such action at a meeting at which all
the Participants were present and voted. Prompt notice of the taking of action
without a meeting shall be given to the Participants who have not consented in
writing.
Benton and EPC shall have the right to amend the Agreement; provided,
that the Agreement shall not be amended by Benton and EPC in any material
respect which would adversely affect the rights of the Participants except by
the affirmative vote of not less than a majority of the outstanding amount of
Partnership interests.
In the event that the Participants vote to remove Benton or EPC and
substitute a new Managing General Partner pursuant to Paragraph A of this
Article, the Partnership or the new Managing General Partner shall purchase the
entire interest of Benton or EPC, including their interest in capital and
revenues on an assumed dissolution basis, at a price determined by mutual
agreement or by independent appraisal by a petroleum engineer selected by
mutual agreement. Such purchase shall provide for payment in full, or
assignment to Benton or EPC of a direct interest in each Partnership asset
and/or liability equal to their then interest in revenue and capital as
determined above. Such payment or assignment shall occur at the time of
amendment of the Agreement and substitution of the new Managing General
Partner.
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B. AUTHORITY
No Participant has the power to manage or conduct Partnership business,
to act in the ordinary course of business for the Partnership or to sign for or
to bind the Partnership or any of its Partners and no such actions will be
considered to have been authorized by the other Partners.
C. LIABILITY
No Limited Partner shall be personally liable for any of the debts of
the Partnership or any of the losses thereof; provided, however, that the
amount committed by him to the capital of the Partnership, any return thereof,
and his interest in the Partnership's undistributed profits shall be subject to
liability. Additionally, a Limited Partner may be liable for wrongfully
distributed profits and interest on distributions in return of capital.
A Partner receives a return of his contribution to the extent that a
distribution to him reduces his share of the fair value of the net assets of
the Partnership below the value, as set forth in the Certificate of Limited
Partnership, of his contribution that has not been distributed to him. If a
Limited Partner receives the return of any part of his contribution without
violation of this Agreement or the California Revised Uniform Limited
Partnership Act, he shall be liable to the Partnership for one (1) year after
the return for the amount of the returned contributions but only to the extent
necessary to discharge the Partnership's liabilities to creditors who extended
credit to the Partnership during the period the contribution was held by the
Partnership. If a Limited Partner receives the return of any part of his
contribution in violation of this Agreement or the California Revised Uniform
Limited Partnership Act, he shall be liable to the Partnership for six (6)
years after the return for the amount of the contribution wrongfully returned.
D. MISCELLANEOUS
No Participant has any right of repayment of his contributions to the
Partnership except as provided in Articles VI and XVII. Participants will
share in losses as provided in Articles V and VII and will share in profits as
provided in Article VI. Further, the Participants have no right to vote on any
Partnership matters except as set forth in this Agreement. Participants agree
that they will not request a decree of dissolution from a court until a
majority vote of the outstanding Units of Participants has approved such
decree.
ARTICLE XVI. WITHDRAWAL OF BENTON OR EPC
A. EVENTS REQUIRING CONSENT OF ALL PARTNERS TO AVOID WITHDRAWAL
Except as approved by the specific written consent of all Partners at
the time, Benton, EPC or any other General Partner shall cease to be a General
Partner of the Partnership upon the happening of any of the following events of
withdrawal: (1) Benton, EPC or a General Partner withdrawing from the
Partnership by giving one hundred twenty (120) days written notice to the other
Partners, provided that the Partnership has completed its Proven Producing
Property
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acquisition, Recompletion Well activities and drilling of Partnership
Wells, and provided that the withdrawing Partner pays all expenses incurred as
a result of its withdrawal; (2) Benton, EPC or a General Partner is removed as
a General Partner in accordance with the terms of the Agreement; (3) in the
case of a General Partner who is a natural person, the death or adjudication of
incompetency of a General Partner; (4) in the case of a General Partner who is
acting as a General Partner by virtue of being a trustee of a trust, the
termination of the trust, but not merely the substitution of a new trustee; (5)
in the case of a General Partner which is a separate partnership, the
dissolution and commencement of winding up of the partnership; (6) in the case
of Benton, EPC or a General Partner that is a corporation, the dissolution of
the corporation or the revocation of its charter; (7) in the case of an estate,
the distribution by the fiduciary of the estate's entire interest in the
Partnership; or (8) in the case of a General Partner that is any other legal
entity, the cessation of the legal existence of the legal entity.
Upon withdrawal, a General Partner other than Benton or EPC shall
retain all rights to its proportionate share of revenues and capital, but shall
cease to have any vote or engage in any other activities as a General Partner.
The withdrawing General Partner will have the right to transfer his interest
subject to provisions of Article XIV hereof.
B. EVENTS NOT CAUSING WITHDRAWAL
Neither Benton, EPC nor any other General Partner shall cease to be a
general partner of the Partnership upon the happening of any of the following
events: (1) Benton, EPC or a General Partner makes an assignment for the
benefit of creditors; (2) Benton, EPC or a General Partner files a voluntary
petition in bankruptcy; (3) Benton, EPC or a General Partner is adjudicated
bankrupt or insolvent; (4) Benton, EPC or a General Partner files a petition or
answer seeking for itself any reorganization, arrangement, composition,
readjustment, liquidation, dissolution or similar relief under any statute, law
or regulation; (5) Benton, EPC or a General Partner files an answer or other
pleading admitting or failing to contest the material allegations of a petition
filed against it in any proceeding of a type described in (4), above; (6)
Benton, EPC or a General Partner seeks, consents to or acquiesces in the
appointment of a trustee, receiver or liquidator of Benton, EPC or a General
Partner or of all or any substantial part of Benton's, EPC's or a General
Partner's properties; or (7) one hundred twenty (120) days have elapsed after
the commencement of any proceeding against Benton, EPC or a General Partner
seeking reorganization, arrangement, composition, readjustment, liquidation,
dissolution or similar relief under any statute, law or regulation and the
proceeding has not been dismissed; or within ninety (90) days after the
appointment, without Benton's, EPC's or a General Partner's consent or
acquiescence, of a trustee, receiver or liquidator of Benton, EPC or a General
Partner or of all or any substantial part of its properties, the appointment is
not vacated or stayed, or within ninety (90) days after the expiration of such
a stay, the appointment is not vacated.
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ARTICLE XVII. DISSOLUTION
A. The parties specifically agree that the retirement,
resignation, expulsion, death, incompetency, bankruptcy, insolvency,
dissolution, withdrawal, conveyance of the interest of a Participant, or
admission of a new partner, or express decision of a Participant shall not
dissolve the Partnership. In such event, the heir, legal representative,
successor or assign of such Participant, as the case may be, shall become an
assignee of such Participant's interest. Such assignee shall not have the
rights of a substituted Participant, unless, with the approval of EPC, such
heir, legal representative, successor or assign shall execute an addendum to
this Agreement, agreeing to be bound by all of the terms and conditions hereof,
and to assume all of the obligations of the deceased or incapacitated
Participant hereunder. When a Participant dies or retires and the business is
continued, the Participant or his estate has no right to require the
Partnership or the remaining Participants to make an evaluated purchase of his
Partnership interest.
B. If, notwithstanding the intent of the Partners as set forth in
A., above, any event listed in A. results in the dissolution of the
Partnership, such dissolution shall be considered in contravention of the
Agreement, and the Partnership shall be continued or reconstituted. In the
event that the Partnership is dissolved, despite the intention of the Partners,
through any acts pursuant to A., above, the Partners agree that EPC may take
any action which it deems necessary or appropriate to continue the Partnership
or to reform the Partnership on terms as identical as possible to this
Agreement. In the event that EPC causes a continuation or reformation of the
Partnership, the liability of all Partners will be deemed to continue
uninterrupted.
C. The following actions shall cause a dissolution of the
Partnership, provided that Benton or EPC cannot take any voluntary action to
cause dissolution between the time it receives notice from the Participants of
their intent to remove a Co-Managing General Partner and the completion of the
voting and the actions, if any, authorized by the voting:
(1) The transfer or assignment of the entire interest of
Benton or EPC unless a remaining Managing General Partner agrees to
continue the Partnership;
(2) The written vote or consent by Participants
representing a majority of the outstanding Units and as further
provided by Article XV;
(3) The conduct of the Partnership becoming unlawful;
(4) The disposition of all or substantially all of the
assets of the Partnership;
(5) The expiration of the term of the Partnership as
provided in Article IX;
(6) An event of withdrawal or expulsion of Benton and EPC,
unless at the time there is at least one other Partner who carries on
the business of the Partnership; provided, that the Partnership is not
dissolved and is not required to be wound up by
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reason of any event of withdrawal if, within ninety (90) days after the
withdrawal, all remaining parties agree in writing to continue the
business of the Partnership and to the appointment of one or more
managing general partners if necessary or desired; or
(7) The entry of a decree of judicial dissolution.
Any dissolution caused by an event other than those
events listed above as causes of dissolution will be considered a dissolution
in contravention of this Agreement.
D. Upon dissolution and winding up of the Partnership, all of the
assets of the Partnership may be liquidated, and all Partnership assets shall
be applied in the following order:
(a) To creditors, including Partners who are
creditors, to the extent permitted by law, in satisfaction of
liabilities of the Partnership other than liabilities for
distributions to Partners; then
(b) To Partners and former Partners in satisfaction
of their rights to interim distributions or distributions upon
withdrawal; then
(c) To Partners, to the extent of positive capital
accounts, first for the return of their capital account
balances and, secondly, respecting their Partnership
interests, in the proportions in which they then share in cash
distributions.
With respect to the distributions made in liquidation, Partners who are
not otherwise creditors shall not have the status of and be entitled to the
remedies available to a creditor of the Partnership. In the event of a
distribution of assets in kind, all assets to be distributed to the
Participants shall be distributed to an independent trustee for all of the
Participants who shall hold title for the benefit of such Participants, collect
and distribute to such Participants all of the net income from such properties
and/or sell such properties as such independent trustee deems to be in the best
interests of the Participants and at the expense of such Participants. The
independent trustee shall operate the liquidating trust arrangement for so long
as is necessary to sell or exchange Partnership Assets for cash on terms which
the trustee deems to be in the best interest of the Participants.
In the event the liabilities of the Partnership exceed its assets upon
liquidation, the Partners must contribute funds to the Partnership in the ratio
of their negative capital accounts until negative capital accounts are
eliminated. In the event any Partner fails to make the required contribution,
Benton agrees to pay the amounts required and no Participant shall have any
liability for the amounts not contributed by other Participants.
Upon termination of the Partnership, a statement shall be prepared by
the certified public accountant employed by the Partnership setting forth the
assets and liabilities of the Partnership and the distribution of cash or
property of the Partnership as prescribed above, and a copy of such statement
shall be furnished to each Partner within ninety (90) days after completion of
winding up of Partnership business.
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For purposes of the liquidation of Partnership assets, the discharge of
its liabilities, and the distribution of the remaining funds and/or assets
among the Partners as above described, in the event that all Partnership
property is not sold, or in the sole discretion of Benton cannot be sold so
that distributions in kind to the Partners are appropriate or necessary, Benton
and EPC shall cause all Partnership assets to be appraised by a competent,
qualified appraiser. Any excess of fair market value, as evidenced by such
appraisal, over book value of any Partnership assets and any excess of book
value over such fair market value of any Partnership assets shall be deemed
gains or losses of the Partnership, as the case may be, and subject to the
provisions of Articles V and VI, above, Benton and EPC shall have the authority
on behalf of the Partnership to sell, convey, exchange, buy back, or otherwise
transfer the assets of the Partnership upon such terms and conditions as it
determines appropriate subject to the terms of this Agreement. A reasonable
time shall be allowed for the orderly liquidation of the assets of the
Partnership to minimize normal losses of the liquidation period. Any return of
all or any portion of the contributions by a Partner to the capital of the
Partnership shall be made solely from or out of Partnership assets and Benton
and EPC shall not be personally liable for any such return.
ARTICLE XVIII. ASSESSMENTS AND BORROWINGS
The Partners are subject to the payment of one or more assessments as
additional capital contributions to the Partnership. No assessment shall be
made, however, unless and until all original Proceeds have been expended or
committed. The failure of one or more Participants to pay any assessment does
not result in personal liability, but will result in the dilution of such
Participants' interest in all Partnership revenues and costs. A Participant's
interest in the Participants' share of Partnership revenues is based on the
ratio that the sum of his Subscription and paid assessments bears to the total
sum of all Participants' Subscriptions and assessments paid by all Participants
(including Benton and EPC to the extent they pay non-consenting Participants'
shares of assessments). The failure of a Participant to pay his share of an
assessment will reduce this ratio accordingly, as of the closing of the
pre-assessment or assessment period. Costs paid out of assessments will be
allocated only to those Partners who paid such assessment. If one or more
Participants fail to pay such assessment, Benton and EPC may contribute the
nonconsenting Participants' shares of such assessment, at their election, which
will proportionately increase the interest of Benton and EPC in all Partnership
revenues and costs, on the same basis as if Benton and EPC were a Participant.
If the Participants fail to pay an amount equal to at least fifty percent (50%)
of the total assessment requested, Benton and EPC have the option of either
returning to the Participants all assessments contributed, or contributing the
non-consenting Participants' shares of such assessment. If the amount
contributed by the Participants equals or exceeds fifty percent (50%) of the
assessment requested, Benton and EPC may contribute all or a portion of the
non-consenting Participants' shares of such assessment and also may reduce the
Partnership's participation in the Prospect for which the assessment was made
by entering into a farmout agreement with respect to such Prospect. The
cumulative amount of assessments shall not exceed twenty-five percent (25%) of
the Proceeds of the Partnership.
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After the Partnership has expended or committed its Proceeds for
property acquisitions and drilling operations, Benton and EPC may finance
necessary additional operations by Partnership assessments, use of Partnership
revenues, or borrowings. Assessments may be levied by Benton and EPC only for
the purpose of conducting subsequent operations on Prospects upon which
evaluation had begun during the Partnership's initial operation or on leases
sufficiently related to such Prospects as to merit, in the Co-Managing General
Partners' judgment, additional operations to fully develop those Prospects or
to acquire additional undeveloped leases located on the geological feature or
features of Prospects owned by the Partnership in order to fully develop and
protect its Prospects.
Benton and EPC will give written notice to each Participant of the
nature and purpose of any assessment, the Participant's proportionate share of
the estimated costs, and the effect of the Participant's not participating in
the assessment. A Participant may elect to participate in an assessment by
notifying Benton and EPC of his intention to participate and sending the
requested payment by mail within twenty (20) days after Benton and EPC mail the
written assessment notice, unless such period is extended by Benton and EPC.
Any Participant shall be deemed to have refused to participate in any
assessment by notifying Benton and EPC of his election not to participate or by
failure to pay his share of the assessment when due. In the event that the
proportionate interests of the Partners change by reason of assessments, solely
for the purpose of allocating costs and revenues, there shall be an interim
closing of the Partnership financial books immediately upon closing of the
assessment period, with all allocations made as of the date of the interim
closing according to the interests of the Partners immediately prior to payment
of the assessments. The pre-assessment or assessment period closes on the last
day established by Benton and EPC for the payment of an assessment by the
Participants.
Benton intends to develop the Partnership's Prospects fully through the
initial Proceeds and assessments. However, no assurance can be made that such
funds will be sufficient. If such funds are not sufficient, the Partnership
may borrow the necessary funds, may farm out the undeveloped portion of certain
Prospects, or may sell or abandon certain undeveloped leases.
ARTICLE XIX. POWER OF ATTORNEY
The Participants constitute and appoint Benton and EPC and their
successors and assigns, with full power of substitution, as their true and
lawful representative and attorney-in-fact in their name, place and stead to
make, execute, and sign a partnership agreement which admits the Participants
as such to the Partnership, any amendments thereof required by law and all such
other instruments, documents and certificates or amendments thereto which may
from time to time be required by the laws of the United States of America, the
State of California or any other state in which the Partnership shall determine
to do business, or any political subdivision or agency thereof, to effectuate,
implement and continue the valid subsisting existence of the Partnership. Such
representative and attorney-in-fact shall not, however, have any right, power
or authority to amend or modify this Agreement when acting in such capacities
except when the amendment is made pursuant to Article XV.
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ARTICLE XX. TAX MATTERS PARTNER
EPC is designated as the "Tax Matters Partner" as referred to in
{6231(a)(7)(A) of the Internal Revenue Code of 1986, as amended. As Tax
Matters Partner, EPC shall:
A. Receive notice of the beginning of administrative proceedings
by the Internal Revenue Service at the Partnership level;
B. Receive notice of the final Partnership administrative adjustment
resulting from any Internal Revenue Service administrative proceedings;
C. Keep all Partners informed of all administrative and judicial
proceedings as to proposed adjustments at the Partnership level;
D. Have authority to enter into a settlement agreement with the
Internal Revenue Service with respect to determination of Partnership tax items
which shall bind all other Partners who have not received notice of the
proceedings from the Internal Revenue Service and who have not filed a
statement with the Secretary of Treasury providing that the Tax Matters Partner
shall not have authority to bind the Partner, which settlement may be on such
terms as the Tax Matters Partner shall determine in its sole discretion to be
in the best interests of the Partners as a class;
E. Have authority to commence judicial action for readjustment of
Partnership items included in a notice of final Partnership administrative
adjustment, with the appropriate court and the Partnership items to be
contested selected at the sole discretion of the Tax Matters Partner, or to
elect not to commence such action at its sole discretion;
F. Have authority in its sole discretion to intervene on behalf of
the Partnership in any judicial action commenced by any other Partner as to
Partnership tax matters;
G. Have authority in its sole discretion to file a request with
the Internal Revenue Service for an administrative adjustment, as a substituted
Partnership return, or otherwise, and to request judicial review on behalf of
the Partnership as to any part of a request for administrative adjustment not
allowed by the Internal Revenue Service;
H. Have authority in its sole discretion to enter into an
agreement with respect to all Partners to extend the period for assessing any
tax which is attributable to any Partnership item (and no other person shall be
authorized to enter into such an agreement);
I. Upon receipt of a notice of the beginning of administrative
proceedings from the Internal Revenue Service, to furnish to the Internal
Revenue Service the name, address, profit interest and taxpayer identification
number of each Partner in the Partnership during the applicable Partnership tax
year, and such revised or additional information as may be required by law; and
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J. Conform to any tax administrative requirements as may be placed
on the Tax Matters Partner by Treasury Regulations as to income tax adopted
after the formation of the Partnership.
ARTICLE XXI. MISCELLANEOUS PROVISIONS
A. NOTICES
Except as elsewhere provided herein, any notice to Benton which shall
be given in connection with the business of this Partnership shall be duly
given if written and addressed and delivered by mail or wire to Benton Oil &
Gas Company, 2151 Alessandro Drive, Suite 120, Ventura, California 93001, to
Energy Partners Corporation, 5151 Shoreham Place, Suite 250, San Diego,
California 92122-3991. The effective date of notice given shall be the date it
is received by Benton or EPC.
Notices to a Participant shall be considered given if addressed and
sent by mail or wire to the Participant at the address shown on the
Subscription Agreement or assignment document.
B. BINDING NATURE
This Agreement shall be binding upon the parties hereto, their
successors, heirs, devisees, assigns, legal representatives, executors, and
administrators.
C. ENTIRE AGREEMENT
This Agreement and the Subscription Agreement contain the entire
understanding between the parties and supersede any prior understanding or
agreements between them respecting the subject matter. There are no
representations, arrangements, understandings or agreements, oral or written,
relating to the subject matter of this Agreement and the Subscription
Agreement, except those fully expressed herein or therein.
D. SEVERABILITY
If any provision of this Agreement shall be held to be invalid, such
holding shall not in any way whatsoever affect the validity of the remainder of
this Agreement.
E. COUNTERPARTS
Several copies of this Agreement may be executed. All executed copies
constitute one Agreement, binding on all parties, even though all parties have
not executed the original or the same copy.
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F. GOVERNING LAW
This Agreement has been executed and will be partially performed in the
State of California. All questions concerning this Agreement and performance
hereunder shall be judged and resolved in accordance with the laws of
California.
G. AMENDMENTS
Amendments may be made to this Agreement as provided under Articles X
and XV herein. Amendments shall be reduced to writing and, if required,
consented to by the Partners pursuant to Article XV.
H. CAPTIONS
The captions of the several articles and paragraphs of this Agreement
are not part of the context thereof, are only guides or labels to assist in
locating or reading the several provisions thereof and shall be ignored in
construing it.
I. EXECUTION
Execution of the Subscription Agreement or acceptance of the assignment
of Units was or will be deemed an execution of this Agreement on the date that
the person becomes a Participant, which will occur when EPC accepts the
Subscription Agreement or the assignment. Execution of the Subscription
Agreement or acceptance of the assignment of Units constitutes authorization
under Article XIX for Benton to file any certificate containing the names of
Subscribers or assignees as Participants, general partners and limited
partners.
J. PARTIES
The parties form this Partnership pursuant to the California Revised
Uniform Limited Partnership Act, as modified by the terms and conditions of
this Agreement. If any provision in this Agreement shall be held to be
invalid, such holding shall not in any way whatsoever affect the validity of
the remainder of this Agreement or affect the intent of the parties to continue
the Partnership pursuant to and make the Partnership subject to a statute
corresponding to the California Revised Uniform Limited Partnership Act.
K. EVIDENCE OF SALES
Materials used in connection with the sale of Units in this Partnership
will be retained by EPC for at least four (4) years after the beginning of
Partnership operations.
L. CERTIFICATE OF LIMITED PARTNERSHIP
A Certificate of Limited Partnership, as required by the California
Revised Uniform Limited Partnership Act, will be filed in the office of the
Secretary of State and in such other
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places as may be required by law. The Certificate of Limited
Partnership shall provide that information required under the law and such
additional information as may be needed to effectuate the terms of this
Agreement. Such other filings may be made as required to permit the
Partnership to transact business in other jurisdictions.
IN WITNESS WHEREOF, Benton, EPC, and the Participants have executed
this Partnership Agreement, effective on the date first above written.
BENTON OIL & GAS COMPANY, as PARTICIPANTS
Co-Managing General Partner By: Energy Partners Corporation as Attorney-
in-Fact, pursuant to Article XIX and
the Subscription Agreement for the
Participants listed on Exhibit A
By:
-----------------------------
A. E. Benton, President By:
----------------
Michael J. Greer
ENERGY PARTNERS CORPORATION, President
as Co-Managing General Partner
By:
------------------
Michael J. Greer
President
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EXHIBIT 4.3
BENTON OIL & GAS COMBINATION
PARTNERSHIP 1990-1, L.P.
AGREEMENT OF LIMITED PARTNERSHIP
This is an Agreement of Limited Partnership (the "Agreement"),
made and entered into as of November 29, 1990, by and among Benton Oil
& Gas Company, a Delaware corporation ("Benton"), and Energy Partners, a
California corporation, as "Co-Managing General Partners," and all other
persons who are parties to this Agreement by execution of this Agreement
or a Subscription Agreement (herein so called), or as assignees or
transferees of such persons (collectively, the "Subscribers" or the
"Participants").
WITNESSETH:
In consideration of the premises and mutual covenants herein contained,
the parties do hereby form a partnership (the "Partnership") under and
pursuant to the California Revised Limited Partnership Act, upon the terms
and conditions hereinafter set forth.
ARTICLE I. NAME AND PRINCIPAL OFFICE
A. The business of the Partnership shall be conducted under
the name "Benton Oil & Gas Combination Partnership 1990-1, L.P."
B. The principal office of the Partnership and the address of
Energy Partners shall be 5151 Shoreham Place, Suite 250, San Diego,
California 92122-3991, provided that Benton or Energy Partners may change
the address of the principal office of the Partnership and of Energy Partners
by giving notice to all Partners. Energy Partners may maintain such other
offices for the Partnership as it may deem necessary or advisable.
C. The address of each Participant shall be that stated on
that Participant's Subscription Agreement or assignment document, subject
to written notice of change given by the Participant to Energy Partners.
ARTICLE II. DEFINITIONS
ADJUSTED CAPITAL ACCOUNT DEFICIT. With respect to any Partner, the
deficit balance, if any, in such Partner's capital account as of the end of
the relevant fiscal year, after giving effect to the following adjustments:
(A) Add to such capital account the following items:
(i) The amount which such Partner is
obligated, pursuant to Paragraph D of Article XVIII of this
Agreement or otherwise, to contribute to the Partnership upon
liquidation of such Partner's Interest; and
(ii) The amount which such Partner is deemed to
be obligated to restore to the Partnership pursuant to the
penultimate sentences of Treasury Regulation
Sections 1.704-1T(b)(4)(iv)(f) and 1 .704-1T(b)(4)(iv)(h)(5);
and
<PAGE> 2
(B) Subtract from such capital account such
Partner's share of the items described in Treasury Regulation
Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5) and
1.704-1(b)(2)(ii)(d)(6).
AFFILIATE. An "Affiliate" of Benton or Energy Partners means: (a)
any person directly or indirectly owning, controlling, or holding, with power
to vote, ten percent (10%) or more of the outstanding voting securities of
Benton or Energy Partners; (b) any person, ten percent (10%) or more of
whose outstanding voting securities are directly or indirectly owned,
controlled, or held, with the power to vote, by Benton or Energy Partners; (c)
any person directly or indirectly controlling, controlled by, or under
common control with Benton or Energy Partners; (d) any officer or director
of Benton or Energy Partners or their Affiliates; and (e) any entity for which
Benton or Energy Partners or their officers and directors acts in the
capacity of an officer, director or general partner.
ASSESSMENTS. Additional amounts of capital which may be required by
the Partnership to be paid by a Participant in addition to his Subscription.
BENTON. Benton Oil & Gas Company, a Delaware corporation, a
Co-Managing General Partner.
CASING POINT. "Casing Point" means the point in time in the drilling
of a well when total depth has been reached, appropriate tests have been made
and a decision must be made to run and set production casing or production
liner, as the case may be, and a decision to commence attempting to complete
the well is made or the well is plugged and abandoned.
CODE. The Internal Revenue Code of 1986, as amended.
COMPLETION COSTS. "Completion Costs" means, as to any well, all
those costs incurred after Casing Point. 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.
COST. When used in connection with selling Proven Producing
Properties, undeveloped leases and other interests to the Partnership or
providing for the drilling or completion of a Partnership Well by Benton,
Energy Partners or their Affiliates, "Cost" shall mean the sum of (1) the
amounts paid by Benton, Energy Partners or their Affiliates to unaffiliated
third parties for the property, including bonuses; (2) title insurance or
title examination costs, brokers' commissions, filing fees, recording costs,
transfer taxes, if any, and like charges in connection with the acquisition
of the property; (3) delay rentals and ad valorem taxes paid with respect to
the property to the date of its transfer to the Partnership; (4) interest on
funds used to acquire or maintain the property; (5) equipment, drilling,
seismic and all other usual costs for the acquisition and development of a
property or having a well drilled; and (6) a portion of Benton's, Energy
Partners' or their Affiliates' reasonable, necessary and actual direct
expenses for geological, geophysical, seismic, engineering, drafting,
accounting, legal and other like services, including a share of compensation
of employees or others, allocated to the property in accordance with
generally accepted and customary industry practices, and screening costs
paid to third parties for geological, geophysical and seismic evaluations
of Benton's, Energy Partners' or their Affiliates' lease inventory, to
the extent such evaluations condemn the acreage prior to selection for
the Partnership. Delay rentals, ad valorem taxes, interest on funds used to
acquire or maintain properties and direct expenses will not be included in
"Cost" when such expenses were incurred by Benton, Energy Partners or their
Affiliates in connection with the past drilling of wells which are not
producers of sufficient quantities of oil or gas to make commercially
reasonable their continued operation, or when such expenses, as enumerated in
subsections (3) and (4) hereof, were incurred more than thirty-six (36)
months prior to the purchase of the property interest by the
Partnership. When used with respect to services, "Cost" means the
reasonable, necessary and actual expenses incurred by Benton or its
Affiliates on behalf of the Partnership in providing such services,
determined in accordance with generally
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<PAGE> 3
accepted and customary industry practices. Except as otherwise indicated or
as the context requires, "cost" means the price paid by Benton, Energy Partners
or their Affiliates in a fair or arm's length transaction.
DEVELOPMENT WELL. A well drilled as an additional well to the
same reservoir as other producing wells on a lease, or drilled on an offset
lease usually not more than one location away from a well producing from the
same reservoir.
DIRECT EXPENSE. Those third party expenses which are directly
attributable to the Partnership. These expenses include the costs of
outside accounting and auditing services, reserve and engineering reports,
legal fees and other third party expenses where such other third party costs
would not be incurred except for the requirements imposed by the terms of the
Partnership Agreement.
ENERGY PARTNERS. Energy Partners, a California corporation, a
Co-Managing General Partner.
EXPLORATORY WELL. A well drilled either in search of a new and as
yet undiscovered pool of oil or gas, or to extend greatly the limits of a
field under development.
GENERAL AND ADMINISTRATIVE EXPENSES. Those reasonable and
necessary expenses incurred by Benton, Energy Partners and their Affiliates
for administering the Partnership including, without limitation, computer
use costs, accounting and legal fees, geological and engineering costs,
office rent, telephone expenses, secretarial salaries, the cost of
printing and mailing reports to the Participants and reimbursement of
the out-of-pocket operating costs (including employee costs and a fair
allocation of general office overhead computed on a cost basis) of Benton,
Energy Partners and their Affiliates which pertain to Partnership business.
All overhead costs shall be allocated in accordance with generally accepted
industry standards, subject to annual independent audit, except for the
first twelve (12) months of operations when the reimbursement shall be in the
form of a fee.
GENERAL PARTNER. A person or entity who executes the Subscription
Agreement and the Partnership Agreement as a General Partner and/or any
person who becomes a substituted General Partner in accordance with the terms
of such Partnership Agreement.
JOINT AND SEVERAL LIABILITY. Joint liability is liability in which
co-obligors must all be joined as co-defendants in any action, whereas joint
and several liability is where a claimant against the Partnership, at his
option, may sue any one or more of the obligors, in this case, the General
Partners.
LIMITED PARTNER. A person or entity who executes the Subscription
Agreement and the Partnership Agreement as a Limited Partner and/or any
person who becomes a substituted Limited Partner in accordance with the terms
of such Partnership Agreement.
LOWER RISK WELL. A well which is lower risk than an Exploratory Well
due to its location in an area having a history of proven hydrocarbon
production and to its (a) being controlled seismically, (b) being
controlled through subsurface geology, or (c) proximity to existing, producing
wells.
MANAGING GENERAL PARTNERS. Benton or Energy Partners, each of which
is a Co-Managing General Partner of the Partnership.
MEMORANDUM. The Private Placement Memorandum, dated March 1, 1990,
relating to the placement of preorganizational units of interest in the
Partnership.
NET PROCEEDS. The Proceeds, less the sum of Organization and
Marketing Expenses, the first year General and Administrative Expenses and
Partnership working capital.
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<PAGE> 4
OFFERING TERMINATION DATE. May 31, 1990 (subject to an extension of
up to 60 days).
ORGANIZATION AND MARKETING EXPENSES; SELLING COMMISSIONS. The
marketing expenses include Selling Commissions of one percent (1%) to three
percent (3%) of the Subscriptions of the Participants which will be made to
wholesalers and selected broker/dealers who assist in coordination of and
education of broker/dealers participating in the placement of Units. Selling
Commissions to broker/dealers will not exceed nine percent (9%) of
Subscriptions. In addition, broker/dealers may receive a reimbursement of
their due diligence expenses in an amount not to exceed one-half of one
percent (0.5%) of the Subscriptions of the Participants, which amount may be
paid directly to broker/dealers or to Energy Partners to reimburse it for due
diligence expenditures. Organization expenses include all costs of
organizing the Partnership, including, but not limited to, expenses for
printing, mailing, and other expenses of qualification of sale of securities
under federal and state law, including attorney fees, accounting fees,
printing and reimbursement of time and expenses incurred by the
Co-Managing General Partners in connection with organizing the Partnership.
The total amount of Organization and Marketing Expenses (exclusive of
Selling Commissions) will not exceed six and one-half percent (6.5%) of the
Subscriptions of the Participants. Any costs in excess of this amount will be
borne by the Co-Managing General Partners.
PARTICIPANT. Each person or entity holding any number of Units in
the Partnership, whether such individual owns these Units as a General
Partner or as a Limited Partner. The term Participant also includes
Benton and Energy Partners to the extent they purchase interests on the
same basis as other Participants and to the extent of their one percent (1%)
capital contributions.
PARTNER MINIMUM GAIN. An amount, with respect to each "partner
nonrecourse debt" (within the meaning of Treasury Regulation
Section 1.704-1T(b)(4)(iv)(k)(4)), equal to the "partnership minimum gain"
(within the meaning of Treasury Regulation Section 1.704-1T(b)(4)(iv)(a)(2)
and Section 1.704-1T(b)(4)(iv)(c)) that would result if such partner
nonrecourse debt were treated as a "nonrecourse liability" (within the
meaning of Treasury Regulation Section 1.704-1T(b)(4)(iv)(k)(3)), determined
in accordance with Treasury Regulation Section 1.704-1T(b)(4)(iv)(h).
PARTNER NONRECOURSE DEDUCTIONS. As defined in Treasury Regulation
Section 1.704-1T(b)(4)(iv)(h)(3). The amount of Partner Nonrecourse Deductions
with respect to a "partner nonrecourse debt" (within the meaning of Treasury
Regulation Section 1.704-1T(b)(4)(iv)(k)(4)) for a Partnership fiscal year
equals the excess, if any, of the net increase, if any, in the amount of Partner
Minimum Gain attributable to such partner nonrecourse debt during such fiscal
year over the aggregate amount of any distributions during such fiscal year
to the Partner who bears the economic risk of loss for such partner
nonrecourse debt to the extent such distributions are from the proceeds of
such partner nonrecourse debt and are allocable to an increase in Partner
Minimum Gain attributable to such partner nonrecourse debt, determined
in accordance with Treasury Regulation Section 1.704-1T(b)(4)(iv)(h)(3).
PARTNERS. Benton, Energy Partners, the Participants and the Special
Limited Partners (if any), all of whom are general partners or limited
partners under the California Revised Limited Partnership Act.
PARTNERSHIP. Benton Oil & Gas Combination Partnership 1990-1, L.P.
PARTNERSHIP AGREEMENT. This Agreement of Limited Partnership.
PARTNERSHIP WELL COSTS. The Costs of (a) acquiring leases,
performing geological, geophysical and seismic tests on leasehold property,
drilling, testing, completing or equipping wells, including geological and
engineering services, whether provided by Benton or third parties, (b)
constructing and/or purchasing facilities and equipment such as pumping units,
storage facilities and separators which are necessary for the operation of a
well, (c) constructing gathering lines from each well to a gas transmission
pipeline in the area, and (d) abandoning a well prior to commercial
production.
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Partnership Well Costs do not include the costs of operating such wells or
Direct Expenses or General and Administrative of operating the Partnership.
PARTNERSHIP WELLS. The wells to be drilled by the Partnership,
including Development Wells, Lower Risk Wells and Exploratory Wells.
PROCEEDS. The amount paid by all Subscribers for Units in the
Partnership, including amounts paid by Benton or Energy Partners for Units,
and amounts paid by Benton and Energy Partners as capital contributions to
the Partnership.
PROPERTIES. Properties acquired by the Partnership, including
Proven Producing Properties, Recompletion Wells, Rework Wells and Partnership
Wells.
PROSPECT. An area in which the Partnership owns or intends to own
one or more oil and gas interests, which is geographically defined on the
basis of geological data by Benton and which is reasonably anticipated by
Benton to contain at least one reservoir.
PROVEN PRODUCING PROPERTIES. Properties acquired by the
Partnership which are currently producing oil and/or gas.
RECOMPLETION WELLS; REWORK WELLS. Wells purchased by the Partnership,
which the Partnership intends to recomplete so as to enhance their oil and/or
gas production either by completing to a shallower or deeper formation,
refracing, or any other method designed to enhance oil and/or gas revenues,
in the discretion of the Co-Managing General Partners.
SPECIAL LIMITED PARTNERS. The Special Limited Partners shall be
those broker/dealers, if any, admitted to the Partnership. The Special
Limited Partners shall make no contribution to the Partnership's capital and
shall not be liable for Assessments.
SUBSCRIBER. The investor who executes a Subscription Agreement and
becomes a Participant at such time as the Subscription is accepted by Energy
Partners.
SUBSCRIPTION AGREEMENT. The instrument executed by a Subscriber
which also constitutes execution of the Partnership Agreement upon acceptance
of the Subscription Agreement by Energy Partners.
SUBSCRIPTIONS. Monies paid by Subscribers as initial capital
contributions to the Partnership.
UNITS. Units of assessable preformation partnership interest in the
Partnership, and such interests after formation of the Partnership, each
representing an original capital contribution of Five Thousand Dollars
($5,000) to the Partnership.
ARTICLE III. PURPOSE
The sole purpose and ordinary business of the Partnership shall be
to explore for oil and gas, to acquire undeveloped leases and Proven
Producing Properties and other interests, to drill Exploratory Wells, Lower
Risk Wells and Development Wells, to acquire and recomplete existing wells,
to dispose of properties, and to conduct all other operations relating to the
exploration, production and sale of oil and gas as Benton deems to be in the
best interest of the Partnership, including the sale of all or substantially
all of the Partnership's assets. It is expected that Partnership operations
will be undertaken primarily in California, Texas, Louisiana, Oklahoma,
Colorado and the Gulf of Mexico but the Partnership may participate in
other areas of the country.
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ARTICLE IV. CAPITAL OF THE PARTNERS
A. CAPITAL CONTRIBUTIONS
(1) Each Participant has made a capital contribution to
the Partnership in cash equal to the amount set forth in the
Subscription Agreement submitted to Energy Partners by the
Participants and accepted by Energy Partners. A Participant's
interest in the Partnership, including his interest in undistributed
profits, will be subject to the debts of the Partnership.
(2) Benton and Energy Partners will make a capital
contribution to the Partnership as required to pay their share of
costs as provided in Article V hereof, and in return for such
payments, Benton, Energy Partners and other General Partners shall be
entitled to share in all items of income, gain, loss, deduction or
credit allocated to the respective Partners as provided in
Article VI.
(3) Benton and Energy Partners will make a capital
contribution as a one percent (1%) General Partner.
(4) Each Participant is subject to Assessments in the
amount of up to twenty-five percent (25%) of the amount of his
original capital contribution.
(5) The Special Limited Partners shall not be liable
for Assessments or to make any other capital contributions to the
Partnership.
B. DETERMINATION OF CAPITAL ACCOUNTS
A single capital account shall be maintained for each Partner (or
transferee of a Partner, which transferee shall succeed to the allocable
portion of the capital account of his transferor, as of the effective
date of the transfer). The capital account for each Partner will be
determined based on the Treasury Regulations regarding maintenance of
capital accounts promulgated under Code Section 704(b), including
Treasury Regulation 1.704-1(b)(2)(iv)(g). Generally, these Treasury
Regulations provide that capital accounts of Partners shall be increased by
(1) the amount of money contributed by a Partner to the Partnership, (2) the
fair market value of property contributed by a Partner to the
Partnership and (3) allocations to a Partner of Partnership taxable income
and gain (or items thereof). Capital accounts will be decreased by (1) the
amount of money distributed to a Partner by the Partnership, (2) the fair
market value of property distributed to a Partner by the Partnership, (3)
allocations of Partnership tax loss and deduction (or items thereof), and
(4) organizational and syndication costs which are not amortized.
In the event of a distribution in kind of any property, the capital
accounts of the Partners shall first be adjusted to reflect the manner in
which the unrealized income, gain, or loss inherent in the property (which
has not been previously reflected in capital accounts) would be allocated
among the Partners if there were a taxable disposition of the property at its
fair market value.
C. SIMULATED DEPLETION ACCOUNT
Solely for purposes of maintaining capital accounts, depletion with
respect to oil and gas properties shall be computed at the Partnership level.
The Partnership shall compute a simulated depletion allowance on each oil or
gas property using the percentage depletion method. The Partnership's
simulated depletion allowance shall reduce the Partners' capital accounts in
the same proportion as such
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Partners (or their predecessors in interest) were allocated adjusted basis
with respect to such property. The aggregate capital account adjustments for
simulated depletion allowances with respect to an oil or gas property
shall not exceed the Partnership's adjusted tax basis in such property. Upon
the taxable disposition of an oil or gas property by the Partnership, the
Partnership's simulated gain or loss shall be determined by subtracting its
simulated adjusted basis in such property from the amount realized from such
disposition. (The Partnership's simulated adjusted basis in an oil and gas
property is determined in the same manner as adjusted tax basis except
that simulated depletion allowances are taken into account instead of
actual depletion allowances.) Any resultant simulated gain shall be allocated
to the Partners in the same manner as that portion of the amount realized
from such disposition which exceeds the Partnership's simulated adjusted
basis in such property is allocated to such Partners and shall increase
such Partners' capital accounts accordingly. Any resultant simulated loss
shall be allocated to the Partners in proportion to the Partners' allocable
shares of the total amount realized from the disposition of such property
that represents recovery of the Partnership's simulated adjusted basis in
such property, and shall reduce such Partners' capital accounts
accordingly.
D. INTEREST ON CAPITAL
No interest shall be paid on the capital account of, or on any
capital contributed by, any Partner either before or after the time repayment
should be made.
ARTICLE V. COSTS CHARGED TO PARTNERS
For purposes of determining liability for Assessments, sharing in
distributions and otherwise as provided herein, items expended by the
Partnership shall be charged as follows, provided that costs paid out of
Assessments shall only be charged to Partners who paid such Assessments:
A. PARTNERSHIP COSTS
All Partnership Well Costs, including completion costs, costs of
Recompletion Wells, costs of acquiring Proven Producing Properties, and
geological, geophysical and seismic costs, and all Organization and Marketing
Expenses shall be allocated one hundred percent (100%) to the Participants.
B. OPERATING COSTS
The expenses of operating Partnership Wells are to be charged in
the same ratio that revenues are shared in such wells, pursuant to paragraph
A of Article VI. In addition, operating costs shall include the costs of
recompleting Partnership Wells.
C. OTHER COSTS
All costs which are not otherwise specifically provided for in
Article V(A) above, including, but not limited to General and Administrative
Expenses and Direct Expenses, shall be charged one hundred percent (100%)
to the Participants.
Costs charged to Participants and the Co-Managing General
Partners will be allocated among the Participants as provided in paragraph C
of Article VI.
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D. LOSS ON SALE OF PARTNERSHIP ASSETS
If the Partnership sells any oil and gas property at a price which is
less than its undepleted cost, the Partnership shall charge the loss on such
sale to the Partners in the ratio of their remaining undepleted bases in such
property at the time of sale.
If the Partnership sells any asset, other than an oil and gas
property, at a price which is less than its undepreciated cost, the
Partnership shall charge the loss on such sale to the Partners who bore the
cost of such asset.
ARTICLE VI. ALLOCATION OF REVENUES AND
DISTRIBUTIONS OF CASH
A. ALLOCATION OF REVENUES
All Partnership revenues shall be allocated seventy-four and
one-fourth percent (74.25%) to the Participants, twenty-four and
three-fourths percent (24.75%) to the Co-Managing General Partners and
one percent (1%) to the Special Limited Partners. For Partnership purposes,
revenues shall mean funds received by the Partnership from all sources,
except capital contributions, borrowings, Assessments and interest on
subscriptions, whether occurring during the term of the Partnership or
occurring as part of any plan of dissolution and liquidation of the
Partnership; provided, however, that the portion of the revenues generated by
the taxable disposition of a Partnership oil and gas property that
represents recovery of its simulated adjusted tax basis therein will be
allocated to the Partners in the same proportion such Partners (or their
predecessors in interest) were allocated the basis of such property
pursuant to paragraph C of Article IV; provided, further, that the portion
of the revenues generated by the taxable disposition of a Partnership asset,
other than an oil and gas property, equal to the Partnership's adjusted tax
basis in such property shall be allocated to the Partners in the same
proportion that the Partners bore the cost of such asset.
B. CASH DISTRIBUTIONS
The Partnership expects to distribute quarterly, or on a more
current basis if so determined by the Co-Managing General Partners, amounts to
the Partners equal to approximately the difference between revenues allocated
to the respective Partners as provided in this Article VI, and costs
charged to the Partners as provided in Article V. This provision shall
not, however, serve as a limitation on the right of the Co-Managing
General Partners to retain, pledge or use so much of the revenues or
other assets of the Partnership, including amounts required to eliminate
any capital deficit of the Partners, to conduct additional operations of
the Partnership, to establish reserves for anticipated expenditures, or to
repay any amounts borrowed by the Partnership to finance the conduct of such
operations.
C. ALLOCATIONS AMONG PARTICIPANTS, SPECIAL LIMITED PARTNERS
AND CO-MANAGING GENERAL PARTNERS
All allocations of income, gain, loss and deduction to the
Participants as a class shall be allocated among the Participants based on
the ratio of their respective paid capital contributions, including
Assessments. Expenses and other costs paid from Assessments shall be charged
only to those Partners who paid the Assessment. All allocation of income,
gain, loss, deduction to the Special Limited Partners, if any, shall be
allocated among the Special Limited Partners in such proportions as shall be
established at the time of their admission to the Partnership or as they
shall later agree. All allocations of income, gain, loss, deduction and all
capital contributions and Assessments to the Co-Managing General Partners
will be divided eighty percent (80%) to Benton and twenty percent (20%) to
Energy Partners.
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ARTICLE VII. ELECTIONS AND TAX ALLOCATIONS
For purposes of federal income taxes, and appropriate state or
local income taxes, the following allocations shall be made:
A. To the extent permitted by law, and except as otherwise
provided by this Article VII, all income, gain, losses and deductions
shall be allocated to the party who has been charged with the
expenditures or credited with the revenues giving rise to such deductions or
income.
B. The basis of Partnership properties for purposes of Code
Section 613A(c)(7)(D) shall be allocated in the same ratio as Partnership
Costs are allocated.
C. Notwithstanding the foregoing, however, production required
to be allocated for the purpose of computing the depletion deduction
(including percentage depletion in excess of the depletable basis of the
property) shall be allocated in the ratio in which the related revenues are
shared.
D. All tax credits and tax credit recapture shall be allocated
in the ratio in which revenues are shared at the time the expenditure giving
rise to such tax credit arises.
E. The Partnership shall make an election to deduct intangible
drilling and development costs on its federal income tax return in
accordance with the option granted by the Code. No election shall be made
by the Partnership to be excluded from the application of the provisions of
Subchapter K of the Code.
F. In the event of the transfer of an interest in the
Partnership, or in the event of the distribution of property to any party
hereto, the Partnership may (but is not required to) file an election in
accordance with the applicable Treasury Regulations to cause the basis of
the Partnership's assets to be adjusted for federal income tax purposes as
provided by Code Sections 734 and 743.
G. Notwithstanding the foregoing provisions of this Article VII,
if the capital accounts of all Participants are not equal and if any
allocation of loss or deduction to a Partner would reduce such
Participant's capital account balance below zero or would increase the
negative balance in such Participant's capital account at a time when another
Participant has a positive capital account balance, as determined at the
close of the period in respect of which the loss or deduction, as the case
may be, is to be allocated, such excess shall instead be allocated pro
rata to Participants having positive capital account balances until such
capital account balances are reduced to zero; provided, however, that in no
event shall there be a reallocation of any item of income, gain, loss or
deduction allocated among the Partners pursuant to this Agreement for prior
years.
Notwithstanding the foregoing provisions of this Article VII:
(1) The losses and deductions allocated to any
Partner pursuant to the foregoing provisions of this Article VII shall
not exceed the maximum amount of losses and deductions that can be so
allocated without causing such Partner to have an Adjusted Capital
Account Deficit at the end of any fiscal year. All losses and
deductions in excess of the limitation set forth in this clause (1)
shall be allocated to other Partners.
(2) If there is a net decrease in partnership minimum
gain (within the meaning of Treasury Regulation
Sections 1.704-1T(b)(4)(iv)(a)(2) and 1.704-1T(b)(4)(iv)(c)) during any
Partnership fiscal year, each Partner shall be specially
allocated items of Partnership income and gain for such year (and,
if necessary, subsequent years) in an amount equal to the greater
of:
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(i) the portion of such Partner's share of
the net decrease in "partnership minimum gain," determined in
accordance with Treasury Regulation Section
1.704-1T(b)(4)(iv)(f), that is allocable to the disposition of
Partnership property subject to "nonrecourse liabilities"
(within the meaning of Treasury Regulation Section
1.704-1T(b)(4)(iv)(k)(3)), determined in accordance with
Treasury Regulation Section 1.704-1(b)(4)(iv)(e), and
(ii) if such Partner would otherwise have an
Adjusted Capital Account Deficit at the end of such fiscal
year, an amount sufficient to eliminate such Adjusted
Capital Account Deficit.
The items of income and gain to be so specially allocated pursuant
to this clause (2) shall be determined in accordance with Treasury
Regulation Section 1.7041T(b)(4)(iv)(e). This clause (2) is intended
to comply with the minimum gain chargeback requirement of Treasury
Regulation Section 1.704-1T(b)(4)(iv)(e) and shall be interpreted
consistently therewith.
(3) Notwithstanding any provision of this Paragraph G
to the contrary (except clause (2)), if there is a net decrease in
Partner Minimum Gain attributable to a "partner nonrecourse debt"
(within the meaning of Treasury Regulation
Section 1.704-1T(b)(4)(iv)(k)(4)) during any Partnership fiscal year,
each Partner who has a share of the Partner Minimum Gain attributable
to such partner nonrecourse debt, determined in accordance with
Treasury Regulation Section 1.704-1T(b)(4)(iv)(h)(5), shall be
specially allocated items of Partnership income and gain for such
fiscal year (and, if necessary, subsequent years) in an amount equal
to the greater of:
(i) the portion of such Partner's share of the
net decrease in Partner Minimum Gain attributable to
such partner nonrecourse debt, determined in accordance
with Treasury Regulation Section 1.704-1T(b)(4)(iv)(h)(5),
that is allocable to the disposition of Partnership property
subject to such partner nonrecourse debt, determined in
accordance with Treasury Regulation Section
1.7041T(b)(4)(iv)(h)(4) and
(ii) if such Partner would otherwise have an
Adjusted Capital Account Deficit at the end of such fiscal
year, an amount sufficient to eliminate such Adjusted
Capital Account Deficit.
The items of income and gain to be so specially allocated pursuant
to this clause (3) shall be determined in accordance with Treasury
Regulation Section 1.7041T(b)(4)(iv)(h)(4). This clause (3) is
intended to comply with the minimum gain chargeback
requirement of Treasury Regulation Section 1.704-1T(b)(4)(iv)(h)(4)
and shall be interpreted consistently therewith.
(4) Subject to the priority rules of Treasury Regulation
Section 1.704-1T(b)(4), if any Partner unexpectedly receives any
adjustment, allocation or distribution described in Treasury
Regulation Sections 1.704-1(b)(2)(ii)(d)(5) or
1.704-1T(b)(2)(ii)(d)(6), items of Partnership income and gain shall
be specially
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allocated to such Partner in an amount and manner sufficient to
eliminate, to the extent required by Treasury Regulation
Sections 1.704-1 (b) and 1.704-1T, the Adjusted Capital Account
Deficit of such Partner as quickly as possible. It is intended that
this clause (4) qualify and be construed as a "qualified income
offset" within the meaning of Treasury Regulation
Section 1.704-1 (b)(2)(ii)(d).
(5) Subject to the priority rules of Treasury Regulation
Section 1.704-1T(b)(4), if any Partner has a deficit capital account
at the end of any Partnership fiscal year which is in excess of the
sum of (i) the amount such Partner is obligated, pursuant to
Paragraph D of Article XVIII of this Agreement or otherwise, to
contribute to the Partnership upon liquidation of such Partner's
Interest, and (ii) the amount such Partner is deemed to be
obligated to restore to the Partnership pursuant to Treasury
Regulation Sections 1.704-1T(b)(4)(iv)(f) and
1.704-1T(b)(4)(iv)(h)(5), such Partner shall be specially
allocated items of Partnership income and gain in the amount of such
excess as quickly as possible.
(6) If special allocations are required under clauses
(2), (3), (4) and/or (5) in any fiscal year, such allocations shall
be made in the priorities required by Treasury Regulation
Sections 1.704-1(b) and 1.704-1T.
(7) "Nonrecourse deductions" (within the meaning
of Treasury Regulation Section 1.704-1T(b)(4)(iv)(b)) for any fiscal
year or other period shall be specially allocated to the Partners
in proportion to their Units in the Partnership. "Partner
nonrecourse deductions" (within the meaning of Treasury Regulation
Section 1.704-1T(b)(4)(iv)(h)(3)) for any fiscal year or other
period shall be specially allocated to the Partner who bears the
economic risk of loss with respect to the partner nonrecourse debt
(within the meaning of Treasury Regulation Section
1.704-1T(b)(4)(iv) (k) (4)) to which such partner nonrecourse
deductions are attributable in accordance with Treasury Regulation
Section 1.704-1T(b)(4)(iv)(h).
(8) The Partners acknowledge that all
distributions of cash (including distributions upon liquidation of
the Partnership) are intended to be made in accordance with the
priorities set forth in Articles V and VI and that the Partners'
capital accounts are intended to reflect the manner in which such
distributions are intended to be made. The allocations set forth in
clauses (1) (last sentence), (2), (3), (4), (5) and (7) (first
sentence) (the "Regulatory Allocations") are intended to comply with
certain requirements of Treasury Regulation Section 1.704-1 (b) and
1.704-1T(b)(4), but may result in distortions of the Partner's
capital accounts in relation to the distributions that each Partner
is intended to receive from the Partnership. Notwithstanding any
other provisions of this Article VII (other than the Regulatory
Allocations), the Regulatory Allocations shall be taken into
account in allocating other Profits, Losses and items of income,
gain, loss and deduction to the Partners so that, to the maximum
extent possible, at any point in time the Partners' capital
accounts shall reflect the manner in which distributions would be
made to the Partners, if the Partnership were liquidated and the
proceeds of such liquidation were distributed to the Partners in
accordance with Articles VI and XVIII.
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ARTICLE VIII. APPLICATION OF PROCEEDS
Net Proceeds will be used solely for the conduct of Partnership
operations.
In view of the fact that Partnership activities will not
commence until sales are closed and Partnership operations commence,
Benton and Energy Partners reserve the right to change the estimated
allocation of Proceeds, as described below, in the best interest of
the Partnership. However, it is anticipated that the Net Proceeds will be
applied by the Partnership on the basis of approximately the following
percentages:
ACTIVITY-ASSUMING THE MINIMUM AMOUNT OFFERED IS RAISED PERCENTAGE
------------------------------------------------------ ----------
Acquisition of Proven Producing Properties 100%
Drilling and Completion of Partnership Wells -0-
ACTIVITY-ASSUMING THE MAXIMUM AMOUNT OFFERED IS RAISED PERCENTAGE
------------------------------------------------------ ----------
Acquisition of Proven Producing Properties 24.5%
Drilling and Completion of Partnership Wells 75.5%
ARTICLE IX. FORMATION OF PARTNERSHIP
In the sole discretion of the Co-Managing General Partners, the
Partnership may be formed as soon as the minimum Subscriptions ($250,000)
have been raised. Additional Participants may be admitted to the Partnership
until the Offering Termination Date, as extended. From the time the minimum
Subscriptions have been received and the Partnership formed until the
Offering Termination Date or final closing date, the Partnership will close
at the end of each month and admit new Participants and acquire either a
greater working interest in the Proven Producing Properties previously
acquired or will acquire interest in additional Proven Producing Properties.
At the sole discretion of the Co-Managing General Partners, the
Partnership may continue to have monthly closing dates until such time as
the Offering Termination Date occurs or the Partnership sales are closed.
Once the final termination date has occurred or the Partnership sales have
closed, then all Participants will share in all Partnership costs and
revenues on a proportionate basis thereafter. The Partnership will not
engage in any recompletions, nor will the Partnership drill any wells, until
the final termination date.
ARTICLE X. TERM AND CONVERSION OF GENERAL PARTNER UNITS
A. The term of the Partnership will commence on the date of
execution of this Agreement, and will continue until December 31, 2039, and
will terminate at such earlier time as all of the interests and properties
acquired for the Partnership have been fully depleted, disposed of, sold
or abandoned, unless sooner terminated as set forth in Article XVI or XVIII of
this Agreement.
The calendar year is the Partnership's fiscal year, subject to change by
Benton and Energy Partners as permitted by the Code.
B. As soon as practicable after the completion of the
Partnership's drilling activity, and subject to the receipt of the
opinion of counsel described below, the General Partner Units shall be
converted to Limited Partner Units. Such conversion shall occur
automatically upon compliance with this paragraph B. All other rights and
obligations under this Agreement shall not be affected by such
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conversion. Prior to any such conversion, Benton and Energy Partners shall
obtain an opinion of tax counsel to the Partnership to the effect that such
conversion would not result in any materially adverse federal tax
consequences to the Partnership or the General Partners. In order to
accomplish such conversion, Benton and Energy Partners will (i) amend this
Agreement with such changes therein or amendments thereto as are deemed
appropriate by Benton and Energy Partners and that do not adversely affect the
General Partners, (ii) file an amended Certificate of Limited Partnership
with the Secretary of State for the State of California and (iii) take such
other actions as are necessary or appropriate to accomplish conversion of
the General Partner interests. Notwithstanding the foregoing, Benton and
Energy Partners shall not be obligated to cause conversion of the
Partnership or may delay such conversion if Benton and Energy Partners or
their tax counsel determine that conversion at that time would not be in the
best interests of the General Partners.
ARTICLE XI. RIGHTS AND OBLIGATIONS OF BENTON
AND ENERGY PARTNERS
A. Benton and Energy Partners shall be the Co-Managing General
Partners of the Partnership and as such shall conduct, direct and exercise
full control over all activities of the Partnership. Generally, Benton shall
be primarily responsible for all of the Partnership's oil and gas activities
and Energy Partners shall be primarily responsible for all the Partnership's
administrative activities. In order to carry out the purposes of the
Partnership as set forth in Article III of this Agreement, the Participants
and the Special Limited Partners, if any, agree that Benton and Energy
Partners have the rights and obligations set forth below.
(1) Benton may purchase or sell any oil and gas
interest and may execute on behalf of the Partnership any and all
documents or instruments of any kind which Benton may deem
appropriate in carrying out the interests of the Partnership,
including, but without limitation, deeds, assignments, leases,
subleases, operating agreements, farmout agreements, unitization
agreements, pooling agreements, sales contracts, gas sales
contracts, transportation contracts, division orders, transfer orders,
or other marketing agreements, documents or instruments of any
kind or character or amendments thereto, which relate to the affairs
of the Partnership;
(2) Energy Partners shall maintain complete and
accurate books of account for the Partnership; said books shall be
kept at the principal office of the Partnership and shall be open to
inspection after reasonable notice and request by any Partner or
his authorized representative, at his own expense, at any time during
ordinary business hours;
(3) Within one hundred twenty (120) days after the
end of the fiscal year, Energy Partners shall provide each
Participant and Special Limited Partner on an annual basis,
commencing at the end of the second full year of Partnership
operations, an independent petroleum engineer's appraisal of the
status of the properties;
(4) Energy Partners shall provide each Participant and
Special Limited Partner with an annual report (copies of which,
together with a report on oil and gas reserves and a tax information
report, shall be furnished to appropriate state securities
administrators, as required) within ninety (90) days after the close
of the Partnership's fiscal year, containing the following
information:
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(a) Financial statements, including the
balance sheet and statements of operations, Partners'
equity and changes in financial position, prepared in
accordance with generally accepted accounting principles and
accompanied by an auditor's report containing the opinion of
an independent certified public accountant;
(b) A description of each Prospect in which the
Partnership owns an interest, including the cost,
location, number of acres under lease and interest owned
by the Partnership, except that succeeding reports will
contain only material changes from the preceding report;
(c) A summary itemization by type and/or
classification of the total fees, reimbursements and
compensation paid by the Partnership, or indirectly on
behalf of the Partnership, to Benton, Energy Partners or
their Affiliates during the period; and
(d) A schedule reflecting the total Partnership
costs, and where applicable, the costs pertaining to each
Prospect, the costs paid by Benton and the costs paid by
the Participants and the Special Limited Partners, the total
Partnership revenues, the revenues received or credited to
Benton, and the revenues received or credited to the
Participants and the Special Limited Partners during the
period;
(5) Energy Partners shall furnish a report to each
Participant and Special Limited Partner by March 15 of each year,
containing such information as Energy Partners deems necessary for
the proper presentation of federal income tax returns;
(6) Energy Partners shall maintain, at the principal
office of the Partnership, copies of the Partnership's federal,
state and local income tax returns and reports for the six (6) most
recent years;
(7) Benton will purchase, at the expense of the
Partnership, liability and other insurance to protect the
Partnership's properties and business;
(8) Benton and Energy Partners may enter into any
agreement for the borrowing of money from a commercial bank or
other lending institution for payment of expenses of drilling
and completion activities on wells started with Proceeds, the
acquisition of Proven Producing Properties and for payment of
General and Administrative Expenses, including the purchase and lease
of oil and gas properties or equipment, and are authorized to
assign any portion of, or all of, the Partnership's properties
and revenues therefrom for the purpose of securing any such borrowed
money; provided, however, that such borrowing shall not exceed, in
principal amount, twenty-five percent (25%) of the Proceeds plus
all paid Assessments; provided, further, that in no event will the
lender have the election to convert its position as creditor into an
equity interest in the Partnership or in Benton, Energy Partners or
in any of their Affiliates;
(9) Benton and Energy Partners may, in the sole
exercise of their discretion, make unsecured loans and advances to
the Partnership at Benton's and Energy Partners' interest cost and
may otherwise borrow money and assign to the lender Partnership
properties and production therefrom as security; provided, however,
that the interest on loans and advances made by Benton and Energy
Partners or their Affiliates shall not exceed the amounts which
would be charged by unrelated banks (without regard to financial
abilities or guarantees) on comparable
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loans for the same purpose, and no fees, points or other financing
charges will be charged to the Partnership by Benton, Energy Partners
or their Affiliates;
(10) In the states where the Partnership conducts
activities, Energy Partners may file any necessary instruments
required to qualify the Partnership to do business in the particular
state as a limited partnership, or to cause the limited partnership
status of the entity to be recognized;
(11) Benton may cause title to Partnership property to
be held in the name of Benton; provided, however, that if property
is held in the name of Benton, an unrecorded assignment to the
Partnership shall be made and maintained in the Partnership's files;
provided, further, that any such assignment shall provide that the
properties are being held for the benefit of the Partnership and
are not subject to the debts, obligations or liabilities of Benton or
its Affiliates;
(12) Benton and Energy Partners may admit
Participants, Special Limited Partners or substituted Participants
without the consent of other Participants or Special Limited
Partners; provided, however, that any transferee of a Unit or a
Special Limited Partner's interest will receive a right to share in
the profits and capital of the Partnership but will not be a
substituted Partner without the prior written consent of Benton
and Energy Partners, which consent may be given or withheld in
their sole and absolute discretion; provided, further, that Benton
and Energy Partners will withhold their written consent in the event
that they have reasonably determined in their sole discretion that
such substitution could have an adverse effect on the business
activities or the legal or tax status of the Partnership, under
either state or federal law;
(13) Benton and Energy Partners may admit one or
more additional managing general partners which may become a
successor entity to Benton and Energy Partners and take action
which would have the effect of providing an additional and/or a
successor managing general partner, if the holders of a majority of
the Units outstanding approve; provided, however, that such approval
of the holders of Units shall not be necessary if the additional
managing general partner proposed by Benton or Energy Partners is
(1) an Affiliate of Benton or Energy Partners; (2) an entity with
which Benton or Energy Partners has merged; or (3) a person or entity
that has purchased all or substantially all the assets of Benton or
Energy Partners;
(14) Benton and Energy Partners may call for a vote of
the Participants to be taken on the items set forth in Article XVI;
(15) Energy Partners may cause the investment of
Partnership funds in short-term liquid securities until the
expenditure of such funds is necessary in connection with
Partnership activities;
(16) Energy Partners and Benton may amend the Agreement,
including amending the Agreement to alter the Partnership's form so
that it becomes a different type of business entity, for business and
tax reasons, subject to the provisions of Article XVI;
(17) Energy Partners and Benton may do any and all
things necessary or appropriate in order to accomplish the purpose
of the Partnership, subject to the provisions of this Agreement;
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(18) Energy Partners and Benton may conduct other oil
and gas drilling and acquisition programs or income programs which may
commence prior to, during or subsequent to the Partnership;
(19) Benton may purchase assets from the Partnership in
connection with a dissolution of the Partnership, at a price which is
the greater of the then fair market value (which term shall mean the
value of the assets as determined by an independent oil an gas
engineer) or the highest bona fide offer for such assets by a third
party, if any, regardless of any difference between such fair market
value and the original cost to the Partnership of such assets
(subject to the approval of a majority in interest of the
Participants if the asset represents five percent (5%) or more of
the initial value of the assets of the Partnership);
(20) Energy Partners may make any and all elections for
purposes of federal, state or local income taxes that it deems
appropriate; and
(21) Benton and Energy Partners may submit a
partnership claim or liability to arbitration or reference,
assign the Partnership property and trust for creditors or on
the assignee's promise to pay the debts of the partnership, confess a
judgment or dispose of the goodwill of the Partnership for adequate
consideration.
B. Benton and Energy Partners shall have no authority on
behalf of the Partnership or themselves to:
(1) Do any act in contravention of this Agreement;
(2) Use Partnership property or commingle any
Partnership bank accounts or monies with funds of Benton, Energy
Partners or their Affiliates, or to make advances to Benton, Energy
Partners or their Affiliates, except where necessary to secure tax
benefits of prepaid drilling and completion costs, and in no event
will such advances include non-refundable payments for capital
completion costs prior to the time that a decision is made that the
well warrants such equipment;
(3) Take any action with respect to Partnership
assets or property which does not primarily benefit the
Partnership, including, among other things, the utilization of
Partnership funds as compensating balances for its own benefit, and
the commitment of future production if not in the best interests of
the Partnership;
(4) Make any loans of Partnership funds to Benton, Energy
Partners or their Affiliates;
(5) Make or institute any marketing arrangements or
other relationships affecting the property of the Partnership where
the benefits are not fairly and equitably apportioned according to
the respective interests of all parties; or
(6) Knowingly enter into any arrangements involving
working interests in any oil and gas property which commit the
working interest to be held in an entity which limits the liability
of the General Partners as to the working interest so as to cause the
working interest to
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be considered a passive activity so that losses from the working
interest may only offset passive activity income as set forth in Code
Section 469.
C. The following prohibitions and restrictions shall be
applicable to Benton:
(1) If Benton sells, transfers or conveys all or
any portion of a lease to the Partnership, Benton must, at the
same time, sell, transfer, or convey to the Partnership an equal
proportionate interest in all its other leases in the same Prospects.
(2) A sale, transfer, or conveyance to the Partnership
of less than all of the ownership of Benton or its Affiliates in any
portion of a lease (the "Subject Portion") is prohibited unless the
interest retained by Benton or its Affiliates is a working interest,
the respective obligations of Benton or its Affiliates and the
Partnership to pay costs with respect to the Subject Portion are
proportionate to their respective working interests after the
transfer, and Benton's or its Affiliates' interest in the revenues
does not exceed any amount proportionate to its retained working
interest. Benton or its Affiliates may not retain any overrides
or other burdens on the Subject Portion, and may not enter into
any farmout arrangements with respect to its retained interest,
except to nonaffiliated third parties or other partnerships
sponsored by Benton. For the purposes of this paragraph, the term
Affiliate shall not include another partnership where the
interest of Benton is identical to, or less than, Benton's interest in
the Partnership.
(3) Benton may never profit by drilling in contravention
of its fiduciary obligation to the Partners. All services provided
to the Partnership by Benton or its Affiliates will be embodied in a
written contract which precisely describes the services to be
rendered and all compensation to be paid.
ARTICLE XII. COMPENSATION OF BENTON AND ENERGY PARTNERS
Benton maintains a staff of geologists, engineers and land
personnel who are responsible for screening and acquisition of leases and
for conducting drilling and producing operations. The costs incurred in
maintaining these departments, including salaries of personnel, are allocable
in part to the Partnership's activities and are included in Partnership Costs.
Such costs shall be paid or reimbursed by the Partnership out of Proceeds or
revenues.
Benton and Energy Partners will also be reimbursed for General and
Administrative Expenses incurred on behalf of the Partnership as a fee for
the first twelve (12) months of Partnership operations and thereafter as a
reimbursement of expenses incurred. The amount of the fee which will be
allocated to the Participants for the first twelve (12) months of
Partnership operations will be three percent (3%) of the Participants'
Subscriptions.
MHM Energy Investments, Inc. shall receive a wholesaling fee equal to
three percent (3%) of the total Units sold by the broker/dealers for which
MHM Energy Investments, Inc. acts as a wholesaling broker/dealer.
As set forth in Article VI, Benton and Energy Partners will share in
Partnership revenues in an amount in excess of their contribution to
Partnership costs. The Participants and the Special Limited Partners
consent to the receipt by Benton, Energy Partners and their Affiliates of the
benefits and profits set forth in this Article.
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ARTICLE XIII. PROTECTION OF THE PARTIES
In any threatened, pending or completed action, suit or proceeding to
which the either of the Co-Managing General Partners was or is a party or is
threatened to be made a party by reason of the fact that it was or is a
Co-Managing General Partner of the Partnership (other than an action by or
in the right of the Partnership) involving any alleged cause of action for
damages arising from the performance of oil and gas activities,
including exploration, development, completion, operation, or other
activities relative to management and disposition of oil and gas properties
or production from such properties, the Partnership will indemnify the
Co-Managing General Partners against expenses, including attorneys' fees,
judgments and amounts paid in settlement 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 Participants and the Special Limited Partners.
The termination of any action, suit or proceeding by judgment, order or
settlement shall not, of itself, create a presumption that Benton or Energy
Partners did not act in good faith and in a manner which they reasonably
believed to be in or not opposed to the best interests of the Partnership.
In any threatened, pending or completed action or suit by the
Partnership in the right of the Partnership, to which a Co-Managing
General Partner was or is a party or is threatened to be made a party,
involving an alleged cause of action by a Participant or a Special Limited
Partner for damages arising from the activities of a Co-Managing General
Partner in the performance of management of the internal affairs of the
Partnership as prescribed by this Agreement, the Partnership will
indemnify the Co-Managing General Partner against expenses, including
attorneys' fees, actually and reasonably incurred by it in connection with
the defense or settlement of such action or suit if it acted in good faith
and in a manner it reasonably believed to be in or not opposed to the best
interests of the Partnership, as specified in this paragraph, except that no
indemnification shall be made in respect of any claim, issue or matter
as to which a Co-Managing General Partner shall have been adjudged to be
liable for negligence, misconduct or breach of fiduciary obligation in the
performance of its duty to the Partnership unless and only to the extent that
the court in which such action or suit was brought shall determine
upon application, that, despite the adjudication of liability, but in view
of all circumstances of the case, a Co-Managing General Partner is fairly
and reasonably entitled to indemnity for such expenses which the court shall
deem proper.
To the extent that a Co-Managing General Partner has been successful
on the merits or otherwise in defense of any action, suit or proceeding
referred to above, or in defense of any claim, issue or matter therein, the
Partnership shall indemnify a Co-Managing General Partner against the
expenses, including attorneys' fees, actually and reasonably incurred by it
in connection therewith. Any such indemnification of a Co-Managing General
Partner shall be prohibited unless the Co-Managing General Partner has
determined in good faith that the course of conduct which caused the loss
or liability was in the best interest of the Partnership; that such
liability or loss was not the result of negligence or misconduct by a
Co-Managing General Partner; and that indemnification of a Co-Managing
General Partner or its Affiliates will not be allowed for any liability
imposed by judgment, and costs associated therewith, including attorneys'
fees, arising from or out of violation of state or federal securities laws
associated with the offer and sale of Partnership Units. Indemnification will
be allowed for settlements and related expenses of a lawsuit alleging
securities law violations, and for expenses incurred in successfully
defending such lawsuits, provided that a court either: (a) approves the
settlement and finds indemnification of the settlement and related costs
should be made or (b) approves indemnification of litigation costs if a
successful defense is made.
Any indemnification, unless ordered by a court, shall be made by the
Partnership only as authorized in the specific case and only upon a
determination by independent legal counsel in a written
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opinion that indemnification of a Co-Managing General Partner is proper
in the circumstances because a Co-Managing General Partner has met the
applicable standard of conduct set forth above.
The indemnification of a Co-Managing General Partner shall be limited
to and recoverable only out of the assets of the Partnership and not against
any Limited Partner or General Partner and indemnification of the Co-Managing
General Partners as to a third party is only with respect to such loss,
liability or damage not otherwise compensated for by insurance carried for the
benefit of the Partnership.
The Partnership may not incur the cost of that portion of
insurance which insures a Co-Managing General Partners from any liability
as to which the Co-Managing General Partner is prohibited from being
indemnified under this Article.
The General Partners hereby agree that each shall be solely and
individually responsible only for their pro rata share of the liabilities
and obligations of the Partnership, and any Participant who incurs
liability in excess of his pro rata share shall be entitled to contribution
from the other General Partners. Pursuant thereto, each Co-Managing General
Partner further agrees to indemnify each Participant from paying any
liabilities or obligations of the Partnership in excess of such
Participant's capital contribution. Furthermore, although the General
Partners may be personally liable for the liabilities and obligations of
the Partnership, all such liabilities and obligations shall be paid or
discharged first with Partnership assets (including insurance proceeds) before
the General Partners shall be obligated to pay or discharge any liability or
obligation with their personal assets.
ARTICLE XIV. RELATED PARTIES
Benton and Energy Partners and their Affiliates or related persons
or entities may be engaged or employed by the Partnership to render or
perform services for the Partnership and/or may sell property of any kind or
description to it, or may otherwise engage in transactions with the
Partnership. All such engagements, employments and other transactions shall
not be invalidated by reason of any such relationships so long as such person
is engaged, independently of the Partnership and as an ongoing business in
rendering such services or selling such equipment and supplies to a
substantial extent to other persons and such prices and terms are not higher
than those normally charged in the same geographic area by unaffiliated
persons or companies dealing at arm's length. If the person is not engaged in
business as provided above, then the price of such services shall be the cost
of such services, equipment or supplies to such person or the competitive rate
in the geographical area, whichever is less. Benton and Energy Partners may
be presently conducting or may conduct in the future other oil and gas
income, drilling and acquisition programs which may commence during or
subsequent to this Partnership. All contracts entered into between the
Partnership, Benton, Energy Partners and their Affiliates or related persons
or entities shall be terminated without penalty on not less than thirty (30)
days' written notice by the Partnership or on sixty (60) days' written
notice by Benton, Energy Partners or their Affiliates.
The leases transferred to the Partnership by Benton or its Affiliates
shall be sold at Cost unless Benton believes that the appraised value is
substantially lower than Cost. In such a case the value of the lease will be
determined by an independent appraiser and sold at the lower of Cost or
appraised value.
ARTICLE XV. RESTRICTIONS ON TRANSFERABILITY
No Participant or Special Limited Partner shall have the power to sell,
assign or transfer his interest in the Partnership or to cause a transferee
to become a substituted Partner except upon the written consent of Benton
and Energy Partners. Each Participant and Special Limited Partner
specifically agrees to the admission of any substituted Partner as a Partner
when consented to by Benton and Energy Partners. Benton and Energy Partners
shall review any proposed transfer and shall withhold their consent in
the event they determine, in their sole and absolute discretion, that such
substitution could have an
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adverse effect on the business activities or the legal or tax status of
the Partnership or the remaining partners under either state or federal law.
Each of Benton and Energy Partners may sell, assign, transfer,
pledge or encumber all or any portion of its rights to receive revenues as
a Co-Managing General Partner under this Partnership Agreement; provided,
however, that the assignment of such revenue interest shall not affect
Benton's and Energy Partners' other rights and obligations pursuant to this
Agreement.
In addition to the restrictions upon substitution of an additional
Participant or Special Limited Partner, neither a Participant nor a Special
Limited Partner may sell his rights to profits and capital in the Partnership
without furnishing Benton and Energy Partners with a copy of the offer to
buy such interest and giving Benton and Energy Partners the prior right for a
period of ten (10) days after receipt of written notice, to purchase such
interest on the terms contained in such offer. In the event Benton and
Energy Partners do not exercise their prior right to purchase such interest in
profits and capital within a ten (10) day period or notify the Participant
or Special Limited Partner that such right will not be exercised, the
Participant or Special Limited Partner shall have the right to sell his
interest in profits and capital for a period of forty-five (45) days.
Thereafter, the Participant or Special Limited Partner shall not sell any
part of his interest in profits and capital without again offering the same
to Benton and Energy Partners. A transferee of a Partner's right to profits
and capital who is not admitted as a Partner is not entitled to any of the
rights of a Partner. A transferee Participant or Special Limited Partner has
no greater right to terminate the Partnership than his transferor.
In no event shall any assignee or transferee hold less than one Unit
except by gift or operation of law.
ARTICLE XVI. RIGHTS, AUTHORITY AND LIABILITIES
OF PARTICIPANTS AND SPECIAL LIMITED PARTNERS
A. RIGHTS
By a majority vote of the outstanding Units, the Participants (but
not the Special Limited Partners) shall have the right to:
(1) Remove Benton, Energy Partners and/or any successor
Co-Managing General Partner; terminate all contracts between the
Partnership and Benton, Energy Partners and their Affiliates; allow
Benton, Energy Partners or their Affiliates to remove all of their
property interests in the Partnership; and select a substitute
managing general partner or additional general partner to continue
the business of the Partnership;
(2) Amend the Agreement, subject to the written
consent of Benton and Energy Partners concerning matter affecting
their interests in profits, losses, credits and property;
(3) Terminate the Partnership;
(4) Approve the sale or exchange of all or substantially
all of the assets; and/or
(5) Approve the admission of an additional general
partner proposed to be admitted as a Co-Managing General Partner by
Benton and Energy Partners, subject to the right of Benton and Energy
Partners to admit certain parties as general partners without the
consent of the Participants, as provided in paragraph 13 of Article
XI.
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Either the Participants, upon the written request of ten percent
(10%) of the outstanding Units, or Benton or Energy Partners can cause a
vote to be taken with respect to the matters referred to above. Notice of a
meeting of the Participants will be mailed to the Participants within ten
(10) days of the receipt of such written notice unless compliance with federal
or state laws or regulations requires additional time. A meeting will be
held within sixty (60) days of the mailing of the notice. The presence,
in person or by proxy, of the holders of a majority of the Units outstanding
shall constitute a quorum and Participants may vote in person or by proxy at
any such meeting. If a quorum shall not be present or represented at any
meeting, a majority of the holders of Units entitled to vote at the
meeting, who are present in person or represented by proxy, may adjourn the
meeting from time to time, without notice other than announcement at the
meeting, until a quorum shall be present or represented. At any reconvening
of an adjourned meeting at which a quorum shall be present or
represented, any business may be transacted which could have been
transacted at the original meeting if a quorum had been present or
represented. No matters that would constitute taking part in control of the
Partnership by the Participants shall be considered at any meeting. In order
to facilitate the above rights, each Participant shall have a right to receive
by mail the complete list of names, addresses and interests of all other
Participants, upon written request to Energy Partners.
Any action that may be taken at a meeting of the Participants may
be taken without a meeting if a consent in writing setting forth the action
so taken is signed by Participants owning not less than the minimum Units
that would be necessary to authorize or take such action at a meeting at
which all the Participants were present and voted. Prompt notice of the
taking of action without a meeting shall be given to the Participants who have
not consented in writing.
Benton and Energy Partners shall have the right to amend the
Agreement; provided, however, that the Agreement shall not be amended by
Benton and Energy Partners in any material respect which would adversely
affect the rights of the Participants except by the affirmative vote of
not less than a majority of the outstanding amount of Units.
In the event that the Participants vote to remove Benton or Energy
Partners and substitute a new Co-Managing General Partner pursuant to
paragraph A of this Article XVI, the Partnership or the new
Co-Managing General Partner shall purchase the entire interest of Benton or
Energy Partners, including their interest in capital and revenues on an
assumed dissolution basis, at a price determined by mutual agreement or by
independent appraisal by a petroleum engineer selected by mutual agreement.
Such purchase shall provide for payment in full, or assignment to Benton or
Energy Partners of a direct interest in each Partnership asset and/or
liability equal to their then interest in revenue and capital as determined
above. Such payment or assignment shall occur at the time of amendment of
the Agreement and substitution of the new Co-Managing General Partner.
B. AUTHORITY
No Participant or Special Limited Partner other than a Co-Managing
General Partner has the power to manage or conduct Partnership business, to
act in the ordinary course of business for the Partnership or to sign for or
to bind the Partnership or any of its Partners and no such actions will be
considered to have been authorized by the other Partners.
C. LIABILITY
No Limited Partner shall be personally liable for any of the debts
of the Partnership or any of the losses thereof; provided, however, that the
amount committed by him to the capital of the Partnership, any return
thereof, and his interest in the Partnership's undistributed profits shall
be subject to liability. Additionally, a Limited Partner may be liable
for wrongfully distributed profits and interest on distributions in
return of capital.
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If a Limited Partner receives the return of any part of his
contribution without violation of this Agreement or the California Revised
Limited Partnership Act, he shall be liable to the Partnership as
provided by such Act for the return of the amount of the returned
contributions but only to the extent necessary to discharge the
Partnership's liabilities to creditors who extended credit to the
Partnership during the period the contribution was held by the Partnership.
D. MISCELLANEOUS
No Participant or Special Limited Partner has any right of
repayment of his contributions to the Partnership except as expressly
provided in this Agreement. Participants have no right to vote on any
Partnership matters except as set forth in this Agreement. Special Limited
Partners have no voting rights except as provided by law. The Participants
and Special Limited Partners agree that they will not request a decree of
dissolution from a court until a majority vote of the outstanding Units
of Participants has approved such decree.
ARTICLE XVII. WITHDRAWAL OF BENTON OR ENERGY PARTNERS
A. EVENTS REQUIRING CONSENT OF ALL PARTNERS TO AVOID
WITHDRAWAL
Except as waived in writing by all Partners at the time, Benton,
Energy Partners or any other General Partner shall cease to be a General
Partner of the Partnership upon the happening of any of the following events
of withdrawal: (1) Benton, Energy Partners or a General Partner withdrawing
from the Partnership by giving one hundred twenty (120) days written notice
to the other Partners, provided that the Partnership has completed its
primary drilling and completion activities and provided that the withdrawing
Partner pays all expenses incurred as a result of its withdrawal; (2) Benton,
Energy Partners or a General Partner is removed as a General Partner in
accordance with the terms of the Agreement; (3) in the case of a General
Partner who is a natural person, the death or adjudication or incompetency
of a General Partner; (4) in the case of a General Partner who is acting as
a General Partner by virtue of being a trustee of a trust, the termination of
the trust, but not merely the substitution of a new trustee; (5) in the case
of a General Partner which is a separate partnership, the dissolution and
commencement of winding up of the partnership; (6) in the case of Benton,
Energy Partners or a General Partner that is a corporation, the dissolution of
the corporation or the revocation of its charter; (7) in the case of an
estate, the distribution by the fiduciary of the estate's entire interest in
the Partnership; or (8) in the case of a General Partner that is any other
legal entity, the cessation of the legal existence of the legal entity.
Upon withdrawal, a General Partner other than Benton or Energy
Partners shall retain all rights to its proportionate share of revenues and
capital, but shall cease to have any vote or engage in any other activities
as a General Partner. The withdrawing General Partner will have the right to
transfer his interest subject to provisions of Article XV hereof.
B. EVENTS NOT CAUSING WITHDRAWAL
Neither Benton, Energy Partners nor any other General Partner shall
cease to be a general partner of the Partnership upon the happening of any
of the following events: (1) Benton, Energy Partners or a General Partner
makes an assignment for the benefit of creditors; (2) Benton, Energy
Partners or a General Partner files a voluntary petition in bankruptcy; (3)
Benton, Energy Partners or a General Partner is adjudicated bankrupt or
insolvent; (4) Benton, Energy Partners or a General Partner files a
petition or answer seeking for itself any reorganization, arrangement,
composition, readjustment, liquidation, dissolution or similar relief under
any statute, law or regulation; (5) Benton, Energy Partners or a General
Partner files an answer or other pleading admitting or failing to contest the
material allegations of a
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petition filed against it in any proceeding of a type described in clause
(4), above; or (6) Benton, Energy Partners or a General Partner seeks,
consents to or acquiesces in the appointment of a trustee, receiver or
liquidator of Benton, Energy Partners or a General Partner or of all or any
substantial part of Benton's, Energy Partners' or a General Partner's
properties.
ARTICLE XVIII. DISSOLUTION
A. The parties specifically agree that the retirement,
resignation, expulsion, death, incompetency, bankruptcy, insolvency,
dissolution, withdrawal, conveyance of the interest of a Participant or
Special Limited Partner, or admission of a new partner, or express
decision of a Participant shall not dissolve the Partnership. In such
event, the heir, legal representative, successor or assign of such
Participant or Special Limited Partner, as the case may be, shall become an
assignee of such Participant's or Special Limited Partner's interest. Such
assignee shall not have the rights of a substituted Partner, unless (i) such
heir, legal representative, successor or assign shall execute an addendum
to this Agreement, agreeing to be bound by all of the terms and conditions
hereof and to assume all of the obligations of the deceased or incapacitated
Participant or Special Limited Partner hereunder and (ii) both Benton and
Energy Partners shall have consented to such substitution, which consent may
be given or withheld in their sole and absolute discretion. When a
Participant or Special Limited Partner dies or retires and the business is
continued, the Participant, Special Limited Partner or his estate has no
right to require the Partnership or the remaining Participants or Special
Limited Partners to make an evaluated purchase of his Partnership
interest.
B. If, notwithstanding the intent of the Partners as set forth
in paragraph A. above, any event listed in paragraph A. results in the
dissolution of the Partnership, such dissolution shall be considered in
contravention of the Agreement, and the Partnership shall be continued or
reconstituted. In the event that the Partnership is dissolved, despite the
intention of the Partners, through any acts pursuant to paragraph A. above,
the Partners agree that Energy Partners may take any action which it deems
necessary or appropriate to continue the Partnership or to reform the
Partnership on terms as identical as possible to this Agreement. In the
event that Energy Partners causes a continuation or reformation of the
Partnership, the liability of all Partners will be deemed to continue
uninterrupted.
C. The following actions shall cause a dissolution of the
Partnership, provided that Benton or Energy Partners cannot take any
voluntary action to cause dissolution between the time it receives notice
from the Participants of their intent to remove a Co-Managing General
Partner and the completion of the voting and the actions, if any, authorized
by the voting:
(1) The transfer or assignment of the entire
interest of Benton or Energy Partners unless a remaining Co-Managing
General Partner agrees to continue the Partnership;
(2) The written vote or consent by Participants
representing a majority of the outstanding Units and as further
provided by Article XVI;
(3) The conduct of the Partnership becoming unlawful;
(4) The disposition of all or substantially all of the
assets of the Partnership;
(5) The expiration of the term of the Partnership as
provided in Article X;
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(6) An event of withdrawal or expulsion of Benton and
Energy Partners, unless at the time there is at least one other
General Partner who carries on the business of the Partnership;
provided, however, that the Partnership is not dissolved and is not
required to be wound up by reason of any event of withdrawal if,
within ninety (90) days after the withdrawal, all remaining Partners
agree in writing to continue the business of the Partnership and to
the appointment of one or more managing general partners if
necessary or desired; or
(7) The entry of a decree of judicial dissolution.
Any dissolution caused by an event other than those events listed
above as causes of dissolution will be considered a dissolution in
contravention of this Agreement.
D. Upon dissolution and winding up of the Partnership, all of
the assets of the Partnership may be liquidated, and all Partnership assets
shall be applied in the following order:
(1) To creditors, including Partners who are
creditors, to the extent permitted by law, in satisfaction of
liabilities of the Partnership other than liabilities for
distributions to Partners; then
(2) To Partners in proportion to their positive capital
account balances.
With respect to the distributions made in liquidation, Partners who
are not otherwise creditors shall not have the status of and be entitled to
the remedies available to a creditor of the Partnership. In the event of a
distribution of assets in kind, all assets to be distributed to the
Participants and the Special Limited Partners shall be distributed to an
independent trustee who shall hold title for the benefit of such Participants
and Special Limited Partners, collect and distribute to such Participants
and Special Limited Partners all of the net income from such properties
and/or sell such properties as such independent trustee deems to be in the
best interests of, and at the expense of, the Participants and Special Limited
Partners. The independent trustee shall operate the liquidating trust
arrangement for so long as is necessary to sell or exchange Partnership
Assets for cash on terms which the trustee deems to be in the best interest
of the Participants and Special Limited Partners.
In the event the liabilities of the Partnership exceed its assets
upon liquidation or otherwise if any General Partner then has a negative
balance in its capital account, the General Partners must contribute funds
to the Partnership, within the period required by Treasury Regulation
Section 1.704-1, in the ratio of their negative capital accounts until negative
capital accounts are eliminated. In the event any General Partner fails to
make the required contribution, Benton agrees to pay the amounts required,
and no Participant or Special Limited Partner shall have any liability for the
amounts not contributed by other Participants.
Upon termination of the Partnership, a statement shall be prepared by
the certified public accountant employed by the Partnership setting forth the
assets and liabilities of the Partnership and the distribution of cash or
property of the Partnership as prescribed above, and a copy of such statement
shall be furnished to each Partner within ninety (90) days after completion of
winding up of Partnership business.
For purposes of the liquidation of Partnership assets, the
discharge of its liabilities, and the distribution of the remaining funds
and/or assets among the Partners as above described, in the event that all
Partnership property is not sold, or in the sole discretion of Benton
cannot be sold so that distributions in kind to the Partners are
appropriate or necessary, Benton and Energy Partners shall cause all
Partnership assets to be appraised by a competent, qualified appraiser. Any
excess of fair market value, as evidenced by such appraisal, over book value
of any Partnership assets and any excess of book value
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over such fair market value of any Partnership assets shall be deemed gains
or losses of the Partnership, as the case may be, and subject to the
provisions of Articles V and VI, above, Benton and Energy Partners shall have
the authority on behalf of the Partnership to sell, convey, exchange, buy
back, or otherwise transfer the assets of the Partnership upon such terms
and conditions as it determines appropriate subject to the terms of this
Agreement. A reasonable time shall be allowed for the orderly liquidation of
the assets of the Partnership to minimize normal losses of the liquidation
period. Any return of all or any portion of the contributions by a Partner
to the capital of the Partnership shall be made solely from or out of
Partnership assets and Benton and Energy Partners shall not be personally
liable for any such return.
ARTICLE XIX. ASSESSMENTS AND BORROWINGS
The Participant are subject to the payment of one or more
Assessments as additional capital contributions to the Partnership. No
Assessment shall be made, however, unless and until all original
Proceeds have been expended or committed The failure of one or more
Participants to pay any Assessment does not result in personal liability,
but will result in the dilution of such Participants' interest in all
Partnership revenues and costs. A Participant's interest in the Participants'
share of Partnership revenues is based on the ratio that the sum of his
Subscription and paid Assessments bears to the total sum of all
Participants' Subscriptions and Assessments paid by all Participants
(including Benton and Energy Partners to the extent they pay non-consenting
Participants' shares of Assessments). The failure of a Participant to pay his
share of an Assessment will reduce this ratio accordingly, as of the
closing of the pre-Assessment or Assessment period. If one or more
Participants fail to pay such Assessment, Benton and Energy Partners may
contribute the nonconsenting Participants' shares of such Assessment,
at their election, which will proportionately increase the interest of
Benton and Energy Partners in all Partnership revenues and costs, on the same
basis as if Benton and Energy Partners were a Participant. If the Participants
fail to pay an amount equal to at least fifty percent (50%) of the total
Assessment requested, Benton or Energy Partners have the option of either
returning to the Participants all Assessments contributed, or
contributing the non-consenting Participants' shares of such Assessment. If
the amount contributed by the Participants equals or exceeds fifty percent
(50%) of the Assessment requested, Benton or Energy Partners may contribute
all or a portion of the non-consenting Participants' shares of such
Assessment and also may reduce the Partnership's participation in the
Prospect for which the Assessment was made by entering into a farmout
agreement with respect to such Prospect.
The cumulative amount of Assessments shall not exceed twenty-five
percent (25%) of the Proceeds of the Partnership.
After the Partnership has expended or committed its Proceeds for
property acquisitions and drilling operations, Benton and Energy Partners
may finance necessary additional operations by Partnership Assessments,
use of Partnership revenues, or borrowings. Assessments may be levied by
Benton and Energy Partners only for the purpose of conducting subsequent
operations on Prospects upon which evaluation had begun during the
Partnership's initial operation or on leases sufficiently related to such
Prospects as to merit, in Benton's and Energy Partners' judgment, additional
operations to fully develop those Prospects or to acquire additional
undeveloped leases located on the geological feature or features of Prospects
owned by the Partnership in order to fully develop and protect its Prospects.
Benton and Energy Partners will give written notice to each
Participant of the nature and purpose of any Assessment, the Participant's
proportionate share of the estimated costs, and the effect of the
Participant's not participating in the Assessment. A Participant may elect to
participate in an Assessment by notifying Benton and Energy Partners of his
intention to participate and sending the requested payment by mail within
twenty (20) days after Benton and Energy Partners mail the written Assessment
notice, unless such period is extended by Benton and Energy Partners. Any
Participant shall be deemed to have refused to participate in any
Assessment by notifying Benton and Energy Partners of his election not to
participate or by failure to pay his share of the Assessment when due. In the
event that the
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proportionate interests of the Partners change by reason of Assessments,
solely for the purpose of allocating costs and revenues, there shall be an
interim closing of the Partnership financial books immediately upon closing
of the Assessment period, with all allocations made as of the date of the
interim closing according to the interests of the Partners immediately prior
to payment of the Assessments. The pre-Assessment or Assessment period
closes on the last day established by Benton and Energy Partners for the
payment of an Assessment by the Participants.
Benton intends to develop the Partnership's Prospects fully
through the initial Proceeds and Assessments. However, no assurance can be
made that such funds will be sufficient. If such funds are not sufficient,
the Partnership may borrow the necessary funds, may farm out the undeveloped
portion of certain Prospects, or may sell or abandon certain undeveloped
leases.
ARTICLE XX. POWER OF ATTORNEY
The Participants and the Special Limited Partners constitute and
appoint Energy Partners and its successors and assigns, with full power
of substitution, as their true and lawful representative and
attorney-in-fact in their name, place and stead to make, execute, and sign
any duly adopted amendments to this Agreement and all such other
instruments, documents and certificates or amendments thereto which may from
time to time be required by the laws of the United States of America, the
State of California or any other state in which the Partnership shall
determine to do business, or any political subdivision or agency thereof, to
effectuate, implement and continue the valid subsisting existence of the
Partnership. Such representative and attorney-in-fact shall not, however,
have any right, power or authority to amend or modify this Agreement when
acting in such capacities except when the amendment is made pursuant to Article
XVI.
ARTICLE XXI. TAX MATTERS PARTNER
Energy Partners is designated as the "Tax Matters Partner" as
referred to in Code Section 6231 (a)(7)(A). As Tax Matters Partner, Energy
Partners shall:
A. Receive notice of the beginning of administrative proceedings
by the Internal Revenue Service at the Partnership level;
B. Receive notice of the final Partnership administrative
adjustment resulting from any Internal Revenue Service administrative
proceedings;
C. Keep all Partners informed of all administrative and
judicial proceedings as to proposed adjustments at the Partnership level;
D. Have authority to enter into a settlement agreement with the
Internal Revenue Service with respect to determination of Partnership tax items
which shall bind all other Partners who have not received notice of the
proceedings from the Internal Revenue Service and who have not filed a
statement with the Secretary of Treasury providing that the Tax Matters
Partner shall not have authority to bind the Partner, which settlement
may be on such terms as the Tax Matters Partner shall determine in its sole
discretion to be in the best interests of the Partners as a class;
E. Have authority to commence judicial action for readjustment of
Partnership items included in a notice of final Partnership administrative
adjustment, with the appropriate court and the Partnership items to be
contested selected at the sole discretion of the Tax Matters Partner, or to
elect not to commence such action at its sole discretion;
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<PAGE> 27
F. Have authority in its sole discretion to intervene on
behalf of the Partnership in any judicial action commenced by any other
Partner as to Partnership tax matters;
G. Have authority in its sole discretion to file a request with
the Internal Revenue Service for an administrative adjustment, as a
substituted Partnership return, or otherwise, and to request judicial review
on behalf of the Partnership as to any part of a request for administrative
adjustment not allowed by the Internal Revenue Service;
H. Have authority in its sole discretion to enter into an
agreement with respect to all Partners to extend the period for assessing
any tax which is attributable to any Partnership item (and no other person
shall be authorized to enter into such an agreement);
I. Upon receipt of a notice of the beginning of administrative
proceedings from the Internal Revenue Service, to furnish to the Internal
Revenue Service the name, address, profit interest and taxpayer
identification number of each Partner in the Partnership during the applicable
Partnership tax year, and such revised or additional information as may be
required by law; and
J. Conform to any tax administrative requirements as may be
placed on the Tax Matters Partner by Treasury Regulations as to income tax
adopted after the formation of the Partnership.
ARTICLE XXII. MISCELLANEOUS PROVISIONS
A. NOTICES
Except as elsewhere provided herein, any notice to Benton which shall
be given in connection with the business of this Partnership shall be duly
given if written and addressed and delivered by mail or wire to Benton Oil &
Gas Company, 2151 Alessandro Drive, Suite 120, Ventura, California 93001,
and any notice to Energy Partners which shall be given in connection with the
business of this Partnership shall be duly given if written and addressed
and delivered by mail or wire to Energy Partners, 5151 Shoreham Place, Suite
250, San Diego, California 92122-3991. The effective date of notice given
shall be the date it is received by Benton or Energy Partners, as the case
may be.
Notices to a Participant Partner shall be considered given if
addressed and sent by mail or wire to the Participant at the address shown
on the Subscription Agreement or assignment document or such other address
as the Participant shall have previously furnished the Co-Managing General
Partners pursuant to this paragraph A. Notices to a Special Limited Partner
shall be considered given if addressed and sent by mail or wire to the
Special Limited Partner at such address as the Special Limited Partner
shall have previously furnished the Co-Managing General Partners pursuant to
this paragraph A.
B. BINDING NATURE
This Agreement shall be binding upon the parties hereto, their
successors, heirs, devisees, assigns, legal representatives, executors and
administrators.
C. ENTIRE AGREEMENT
This Agreement and the Subscription Agreement contain the entire
understanding between and among the parties and supersede any prior
understanding or agreements between or among them
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respecting the subject matter. There are no representations, arrangements,
understandings or agreements, oral or written, relating to the subject matter
of this Agreement and the Subscription Agreement, except those fully
expressed herein or therein.
D. SEVERABILITY
If any provision of this Agreement shall be held to be invalid,
such holding shall not in any way whatsoever affect the validity of the
remainder of this Agreement.
E. COUNTERPART
Several copies of this Agreement may be executed. All executed
copies constitute one Agreement, binding on all parties, even though all
parties have not executed the original or the same copy.
F. GOVERNING LAW
This Agreement has been executed and will be partially performed
in the State of California. All questions concerning this Agreement and
performance hereunder shall be judged and resolved in accordance with the laws
of California.
G. AMENDMENTS
Amendments may be made to this Agreement as provided under Articles
XI and XVI herein. Amendments shall be reduced to writing and, if required,
consented to by the Partners pursuant to Article XVI.
H. CAPTIONS
The captions of the several articles and paragraphs of this
Agreement are not part of the context thereof, are only guides or labels to
assist in locating or reading the several provisions thereof and shall be
ignored in construing it.
I. EXECUTION
Execution of the Subscription Agreement or acceptance of the
assignment of Units was or will be deemed an execution of this Agreement
on the date that the person becomes a Participant, which will occur when
Energy Partners accepts the Subscription Agreement or the assignment.
Execution of the Subscription Agreement or acceptance of the assignment of
Units constitutes authorization under Article XX for either of the Co-Managing
General Partners to file any certificate containing the names of Subscribers
or assignees as Participants, general partners and limited partners.
J. PARTIES
The parties form this Partnership pursuant to the California
Revised Limited Partnership Act, as modified by the terms and conditions of
this Agreement. If any provision in this Agreement shall be held to be
invalid, such holding shall not in any way whatsoever affect the
validity of the remainder of this Agreement or affect the intent of the
parties to continue the Partnership pursuant to and make the
Partnership subject to a statute corresponding to the California Revised
Limited Partnership Act.
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K. EVIDENCE OF SALES
Materials used in connection with the sale of Units in this
Partnership will be retained by Energy Partners for at least four (4) years
after the beginning of Partnership operations.
I. CERTIFICATE OF LIMITED PARTNERSHIP
Certificate of Limited Partnership, as required by the California
Revised Limited Partnership Act, will be filed in the office of the
California Secretary of State and in such other places as may be required by
law. The Certificate of Limited Partnership shall provide that information
required under the law and such additional information as may be needed to
effectuate the terms of this Agreement. Such other filings may be made as
required to permit the Partnership to transact business in other jurisdictions.
IN WITNESS WHEREOF, Benton, Energy Partners, the Participants and
the Special Limited Partners, if any, have executed this Partnership
Agreement, effective on the date first above written.
BENTON OIL & GAS COMPANY, PARTICIPANTS
as Co-Managing General Partner By: Energy Partners
as Attorney-in-Fact,
pursuant to Article XX and
By:_______________________________ the Subscription Agreement
A. E. Benton, President for the Participants listed on
Exhibit A
ENERGY PARTNERS, By:__________________________________
as Co-Managing General Partner Michael J. Greer
President
BY:_______________________________
Michael J. Greer
President
SPECIAL LIMITED PARTNERS:
By:_______________________________
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<PAGE> 1
EXHIBIT 4.4
BENTON OIL & GAS COMBINATION
PARTNERSHIP 1991-1, LP.
AGREEMENT OF LIMITED PARTNERSHIP
This is an Agreement of Limited Partnership (the "Agreement"), made
and entered into as of July 30, 1991, by and among Benton Oil and Gas
Company, a Delaware corporation ("Benton"), and Energy Partners, a
California corporation, as "Co-Managing General Partners", the Special
Limited Partners, and all other persons who are parties to this Agreement
by execution of this Agreement or a Subscription Agreement (herein so
called), or as assignees or transferees of such persons (collectively,
the "Subscribers" or the "Participants").
W I T N E S S E T H:
In consideration of the premises and mutual covenants herein
contained, the parties do hereby form a partnership (the "Partnership") under
and pursuant to the California Revised Limited Partnership Act, upon the
terms and conditions hereinafter set forth.
ARTICLE I.
NAME AND PRINCIPAL OFFICE
A. The business of the Partnership shall be conducted under
the name "Benton Oil & Gas Combination Partnership 1991-1, L.P."
B. The principal office of the Partnership and the address of
Energy Partners shall be 1001 Dove Street, Suite 180, Newport Beach,
California 92660-2816, provided that Benton or Energy Partners may change
the address of the principal office of the Partnership and of Energy Partners
by giving notice to all Partners. Energy Partners may maintain such other
offices for the Partnership as it may deem necessary or advisable.
C. The address of each Participant shall be that stated on
that Participant's Subscription Agreement or assignment document, subject
to written notice of change given by the Participant to Energy Partners.
ARTICLE II. DEFINITIONS
Adjusted Capital Account Deficit. With respect to any Partner, the
deficit balance, if any, in such Partner's capital account as of the end of
the relevant fiscal year, after giving effect to the following adjustments:
(A) Add to such capital account the following items:
(i) The amount which such Partner is obligated,
pursuant to Paragraph D of Article XVIII of this Agreement or
otherwise, to contribute to the Partnership upon liquidation
of such Partner's Interest; and
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(ii) The amount which such Partner is deemed to
be obligated to restore to the Partnership pursuant to the
penultimate sentences of Treasury Regulation Sections
1.704-1T(b)(4)(iv)(f) and 1.704-1T(b)(4)(iv)(h)(5); and
(B) Subtract from such capital account such Partner's
share of the items described in Treasury Regulation
Sections 1.7041(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5) and
1.704-1(b)(2)(ii)(d)(6).
Affiliate. An "Affiliate" of Benton or Energy Partners means: (a)
any person directly or indirectly owning, controlling, or holding, with power
to vote, ten percent (10%) or more of the outstanding voting securities of
Benton or Energy Partners; (b) any person, ten percent (10%) or more of
whose outstanding voting securities are directly or indirectly owned,
controlled, or held, with the power to vote, by Benton or Energy Partners;
(c) any person directly or indirectly controlling, controlled by, or under
common control with Benton or Energy Partners; (d) any officer or director of
Benton or Energy Partners or their Affiliates; and (e) any entity for which
Benton or Energy Partners or their officers and directors acts in the
capacity of an officer, director or general partner.
Assessments. Additional amounts of capital which may be required by
the Partnership to be paid by a Participant in addition to his Subscription.
Benton. Benton Oil and Gas Company, a Delaware corporation, a
Co-Managing General Partner.
Casing Point. "Casing Point" means the point in time in the
drilling of a well when total depth has been reached, appropriate tests have
been made and a decision must be made to run and set production casing or
production liner, as the case may be, and a decision to commence attempting
to complete the well is made or the well is plugged and abandoned.
Code. The Internal Revenue Code of 1986, as amended.
Completion Costs. "Completion Costs" means, as to any well all
those costs incurred after Casing Point. 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.
Cost. When used in connection with selling Proven Producing
Properties, undeveloped leases and other interests to the Partnership or
providing for the drilling or completion of a Partnership Well by Benton,
Energy Partners or their Affiliates, "Cost" shall mean the sum of (1 ) the
amounts paid by Benton, Energy Partners or their Affiliates to unaffiliated
third parties for the property, including bonuses; (2) title insurance or
title examination costs, brokers commissions, filing fees, recording costs,
transfer taxes, if any, and like charges in connection with the acquisition
of the property; (3) delay rentals and ad valorem taxes paid with respect
to the property to the date of its transfer to the Partnership; (4) interest
on funds used to acquire or maintain the property; (5) equipment, drilling,
seismic and all other usual costs for the acquisition and development of a
property or having a well drilled; and (6) a portion of Benton's, Energy
Partners' or their Affiliates' reasonable, necessary and actual expenses
for geological, geophysical, seismic, engineering, drafting, accounting,
legal and other like services, including a share of compensation of
employees or others, allocated to the property in accordance with
generally accepted and customary industry practices, and screening costs
paid to third parties for
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<PAGE> 3
geological, geophysical and seismic evaluations of Benton's, Energy
Partners' or their Affiliates' lease inventory, to the extent such
evaluations condemn the acreage prior to selection for the Partnership. Delay
rentals, ad valorem taxes, interest on funds used to acquire or maintain
properties and direct expenses will not be included in cost when such
expenses were incurred by Benton, Energy Partners or their Affiliates in
connection with the past drilling of wells which are not producers of
sufficient quantities of oil or gas to make commercially reasonable their
continued operation, or when such expenses, as enumerated in subsections (3)
and (4) hereof, were incurred more than thirty-six (36) months prior to
the purchase of the property interest by the Partnership. When used with
respect to services, "Cost" means the reasonable, necessary and actual
expenses incurred by Benton or its Affiliates on behalf of the Partnership in
providing such services, determined in accordance with generally accepted
and customary industry practices. Except as otherwise indicated or as
the context requires, cost means the price paid by Benton, Energy
Partners or their Affiliates in a fair or arm's length transaction.
Development Well. A well drilled as an additional well to the
same reservoir as other producing wells on a lease, or drilled on an offset
lease usually not more than one location away from a well producing from the
same reservoir.
Direct Expenses. Those third party expenses which are directly
attributable to the Partnership. These expenses include the costs of outside
accounting and auditing services, reserve and engineering reports, legal
fees and other third party expenses where such other third party costs would
not be incurred except for the requirements imposed by the terms of the
Partnership Agreement.
Energy Partners. Energy Partners, a California corporation, a
Co-Managing General Partner.
Exploratory Well. A well drilled either in search of a new and as
yet undiscovered pool of oil or gas, or to extend greatly the limits of a
field under development.
General and Administrative Expenses. Those reasonable and
necessary expenses incurred by Benton, Energy Partners and their
Affiliates for administering the Partnership including, without
limitation, computer use costs, accounting and legal fees, geological and
engineering costs, office rent, telephone expenses, secretarial salaries,
the cost of printing and mailing reports to the Participants and
reimbursement of the out-of-pocket operating costs (including employee costs
and a fair allocation of general office overhead computed on a cost basis) of
Benton, Energy Partners and their Affiliates which pertain to Partnership
business. All overhead costs shall be allocated in accordance with generally
accepted industry standards, subject to annual independent audit, except for
the first twelve (12) months of operations when the reimbursement shall be in
the form of a fee.
General Partner. A person or entity who executes the Subscription
Agreement and the Partnership Agreement as a General Partner and/or any person
who becomes a substituted General Partner in accordance with the terms of such
Partnership Agreement.
Joint and Several Liability. Joint liability is liability in which
co-obligors must all be joined as codefendants in any action, whereas joint
and several liability is where a claimant against the Partnership, at his
option, may sue any one or more of the obligors, in this case, the General
Partners.
Limited Partner. A person or entity who executes the
Subscription Agreement and the Partnership Agreement as a Limited Partner
and/or any person who becomes a substituted Limited Partner in accordance
with the terms of such Partnership Agreement.
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<PAGE> 4
Lower Risk Well. A well which is lower risk than an Exploratory
Well due to its location in an area having a history of proven hydrocarbon
production and to its (a) being controlled seismically, (b) being
controlled through subsurface geology, or (c) proximity to existing, producing
wells.
Managing General Partners. Benton or Energy Partners, each of which is
a Co-Managing General Partner of the Partnership.
Memorandum. The Private Placement Memorandum, dated February 1,
1991, relating to the placement of preorganizational units of interest in the
Partnership.
Net Proceeds. The Proceeds, less the sum of Organization
and Marketing Expenses, Selling Commissions, the first year General and
Administrative Expenses and Partnership working capital.
Offering Termination Date. April 30, 1991 (subject to an extension of
up to 90 days).
Organization and Marketing Expenses; Selling Commissions.
Organization expenses include all costs of organizing the Partnership,
including, but not limited to, expenses for printing, mailing, and other
expenses of qualification of sale of securities under federal and state law,
including attorney fees, accounting fees, printing and reimbursement of time
and expenses incurred by the Co-Managing General Partners in connection with
organizing the Partnership. Marketing expenses include additional Selling
Commissions of one percent (1%) to three percent (3%) of the Subscriptions
of the Participants which will be paid to wholesalers and selected
broker/dealers who assist in coordination of and education of broker/dealers
participating in the placement of Units. Selling Commissions, including
wholesaling fees, to broker/dealers will not exceed ten percent (10%) of
Subscriptions. In addition, broker/dealers may receive a reimbursement of
their due diligence expenses in an amount not to exceed one-half of one
percent (0.5%) of the Subscriptions of the Participants, which amount may
be paid directly to broker/dealers or to Energy Partners to reimburse it for
due diligence expenditures. The total amount of Organization and Marketing
Expenses (exclusive of Selling Commissions) will not exceed six and one-half
percent (6.5%) of the Subscriptions of the Participants. Any costs In excess
of this amount will be borne by the Co-Managing General Partners.
Participant. Each person or entity holding any number of Units in
the Partnership, whether such individual owns these Units as a General
Partner or as a Limited Partner. The term Participant also includes
Benton and Energy Partners to the extent they purchase interests on the
same basis as other Participants and to the extent of their one percent (1%)
capital contributions.
Partner Minimum Gain. An amount, with respect to each "partner
nonrecourse debt" (within the meaning of Treasury Regulation
Section 1.7041-T(b)(4)(iv)(k)(4)), equal to the "partnership minimum gain"
(within the meaning of Treasury Regulation Sections 1.7041T(b)(4)(iv)(a)(2)
and 1.704-1T(b)(4)(1v)(c)) that would result if such partner nonrecourse debt
were treated as a "nonrecourse liability" (within the meaning of Treasury
Regulation Section 1.704-1T(b)(4)(iv)(k)(3)), determined in accordance with
Treasury Regulation Section 1.7041T(b)(4)(iv)(h).
Partner Nonrecourse Deductions. As defined in Treasury Regulation
Section 1.704-1T(b)-(4)(iv)(h)(3). The amount of Partner Nonrecourse Deductions
with respect to a "partner nonrecourse debt" (within the meaning of Treasury
Regulation Section 1.704-1T(b)(4)(iv)(k)(4)) for a Partnership fiscal year
equals the excess, if any, of the net increase, if any, in the amount of Partner
Minimum Gain attributable to such partner nonrecourse debt during such fiscal
year over the aggregate amount of any distributions during such fiscal year to
the Partner who bears the economic risk of loss for such partner nonrecourse
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<PAGE> 5
debt to the extent such distributions are from the proceeds of such
partner nonrecourse debt and are allocable to an increase in Partner Minimum
Gain attributable to such partner nonrecourse debt, determined in accordance
with Treasury Regulation Sections 1.704-1T(b)(4)(iv)(h)(3).
Partners. Benton, Energy Partners, the Participants and the Special
Limited Partners (if any), all of whom are general partners or limited
partners under the California Revised Limited Partnership Act.
Partnership. Benton Oil & Gas Combination Partnership 1991-1, L.P.
Partnership Agreement. This Agreement of Limited Partnership.
Partnership Well Costs. The Costs of (a) acquiring leases,
performing geological, geophysical and seismic tests on leasehold property,
drilling, testing, completing or equipping wells, including geological and
engineering services, whether provided by Benton or third parties, (b)
constructing and/or purchasing facilities and equipment such as pumping
units, storage facilities and separators which are necessary for the operation
of a well, (c) constructing gathering lines from each well to a gas
transmission pipeline in the area, and (d) abandoning a well prior to
commercial production. Partnership Well Costs do not include the costs of
operating such wells or Direct Expenses or General and Administrative
Expenses of operating the Partnership.
Partnership Wells. The wells to be drilled by the Partnership,
including Development Wells, Lower Risk Wells and Exploratory Wells.
Proceeds. The amount paid by all Subscribers for Units in the
Partnership, including amounts paid by Benton or Energy Partners for Units,
and amounts paid by Benton and Energy Partners as capital contributions to
the Partnership.
Properties. Properties acquired by the Partnership, including
Proven Producing Properties, Recompletion Wells, Rework Wells and
Partnership Wells.
Prospect. An area in which the Partnership owns or intends to own one
or more oil and gas interests, which is geographically defined on the basis
of geological data by Benton and which is reasonably anticipated by Benton to
contain at least one reservoir.
Proven Producing Properties. Properties acquired by the
Partnership which are currently producing oil and/or gas.
Recompletion Wells; Rework Wells. Wells purchased by the
Partnership, which the Partnership intends to recomplete so as to enhance
their oil and/or gas production either by completing to a shallower or deeper
formation, refracing, or any other method designed to enhance oil and/or gas
revenues, in the discretion of the Co-Managing General Partners.
Special Limited Partners. The Special Limited Partners shall be
those broker/dealers, if any, admitted to the Partnership. The Special
Limited Partners shall make no contribution to the Partnership s capital and
shall not be liable for Assessments.
Subscriber. The investor who executes a Subscription Agreement and
becomes a Participant at such time as the Subscription is accepted by Energy
Partners.
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Subscription Agreement. The instrument executed by a Subscriber
which also constitutes execution of the Partnership Agreement upon acceptance
of the Subscription Agreement by Energy Partners.
Subscriptions. Monies paid by Subscribers as initial capital
contributions to the Partnership.
Units. Units of assessable preformation partnership interest in the
Partnership, and such interests after formation of the Partnership, each
representing an original capital contribution of Five Thousand Dollars
($5,000) to the Partnership.
ARTICLE III. PURPOSE
The sole purpose and ordinary business of the Partnership shall be
to explore for oil and gas, to acquire undeveloped leases and Proven
Producing Properties and other interests, to drill Exploratory Wells,
Lower Risk Wells and Development Wells, to acquire and recomplete existing
wells, to dispose of properties, and to conduct all other operations relating
to the exploration, production and sale of oil and gas as Benton deems to be
in the best interest of the Partnership, including the sale of all or
substantially all of the Partnership s assets. It is expected that
Partnership operations will be undertaken primarily in California, Texas,
Louisiana and the Gulf of Mexico but the Partnership may participate in other
areas of the country.
ARTICLE IV. CAPITAL OF THE PARTNERS
A. CAPITAL CONTRIBUTIONS
1. Each Participant has made a capital contribution to the
Partnership in cash equal to the amount set forth in the
Subscription Agreement submitted to Energy Partners by the
Participants and accepted by Energy Partners. A Participant's
interest in the Partnership, including his interest in undistributed
profits, will be subject to the debts of the Partnership.
2. Benton and Energy Partners will make a capital contribution
to the Partnership as required to pay their share of costs as provided
in Article V hereof, and in return for such payments, Benton, Energy
Partners and other General Partners shall be entitled to share in all
items of income, gain, loss, deduction or credit allocated to the
respective Partners as provided in Article VI.
3. Benton and Energy Partners will make a capital
contribution of one percent (1%) of the total contributions as a
General Partner.
4. Each Participant is subject to Assessments in the amount
of up to twenty-five percent (25%) of the amount of his original
capital contribution.
5. The Special Limited Partners shall not be liable for
Assessments or to make any other capital contributions to the
Partnership.
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B. DETERMINATION OF CAPITAL ACCOUNTS
A single capital account shall be maintained for each Partner
(or transferee of a Partner, which transferee shall succeed to the
allocable portion of the capital account of his transferor, as of the
effective date of the transfer). The capital account for each Partner
will be- determined based on the Treasury Regulations regarding maintenance
of capital accounts promulgated under Code Section 704(b), including
Treasury Regulation Section 1.704-1(b)(2)(iv)(g). Generally, these Treasury
Regulations provide that capital accounts of Partners shall be increased by
(1) the amount of money contributed by a Partner to the Partnership, (2) the
fair market value of, property contributed by a Partner to the
Partnership and (3) allocations to a Partner of Partnership taxable income
and gain (or items thereof). Capital accounts will be decreased by (1) the
amount of money distributed to a Partner by the Partnership, (2) the fair
market value of property distributed to a Partner by the Partnership,
(3) allocations of Partnership tax loss and deduction (or items thereof),
and (4) organizational and syndication costs which are not amortized.
In the event of a distribution in kind of any property, the capital
accounts of the Partners shall first be adjusted to reflect the manner in
which the unrealized income, gain, or loss inherent in the property
(which has not been previously reflected in capital accounts) would be
allocated among the Partners if there were a taxable disposition of the
property at its fair market value.
C. SIMULATED DEPLETION ACCOUNT
Solely for purposes of maintaining capital accounts, depletion with
respect to oil and gas properties shall be computed at the Partnership
level. The Partnership shall compute a simulated depletion allowance on each
oil or gas property using the percentage depletion method. The
Partnership's simulated depletion allowance shall reduce the Partners'
capital accounts in the same proportion as such Partners (or their
predecessors in interest) were allocated adjusted basis with respect to such
property. The aggregate capital account adjustments for simulated depletion
allowances with respect to an oil or gas property shall not exceed the
Partnership's adjusted tax basis in such property. Upon the taxable
disposition of an oil or gas property by the Partnership, the Partnership's
simulated gain or loss shall be determined by subtracting its simulated
adjusted basis in such property from the amount realized from such
disposition. (The Partnership's simulated adjusted basis in an oil and gas
property is determined in the same manner as adjusted tax basis except that
simulated depletion allowances are taken into account instead of actual
depletion allowances.) Any resultant simulated gain shall be allocated to the
Partners in the same manner as that portion of the amount realized from such
disposition which exceeds the Partnership's simulated adjusted basis in
such property is allocated to such Partners and shall increase such Partners'
capital accounts accordingly. Any resultant simulated loss shall be
allocated to the Partners in proportion to the Partners' allocable shares of
the total amount realized from the disposition of such property that
represents recovery of the Partnership's simulated adjusted basis in such
property, and shall reduce such Partners' capital accounts accordingly.
D. INTEREST ON CAPITAL
No interest shall be paid on the capital account of, or on any
capital contributed by, any Partner either before or after the time repayment
should be made.
ARTICLE V. COSTS CHARGED TO PARTNERS
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<PAGE> 8
For purposes of determining liability for Assessments, sharing in
distributions and otherwise as provided herein, amounts expended by the
Partnership shall be charged as follows, provided that costs paid out of
Assessments shall only be charged to Partners who paid such Assessments:
A. PARTNERSHIP COSTS
All Partnership Well Costs, including completion costs, costs of
Recompletion Wells, costs of acquiring and developing Proven Producing
Properties, and geological, geophysical and seismic costs, and all
Organization and Marketing Expenses shall be allocated one hundred percent
(100%) to the Participants.
B. OPERATING COSTS
The expenses of operating Partnership Wells are to be charged in
the same ratio that revenues are shared in such wells, pursuant to paragraph
A of Article Vl. In addition, operating costs shall include the costs of
recompleting Partnership Wells.
C. OTHER COSTS
All General and Administrative Expenses shall be charged
seventy-five percent (75%) to the Participants and twenty-five percent
(25%) to the Co-Managing General Partners, except that the reimbursement of
General and Administrative Expenses payable to the Co-Managing General
Partners for the first twelve (12) months of the Partnership's operations
and equaling three percent (3%) of the Participants' Subscriptions shall be
charged entirely to the Participants. All costs which are not otherwise
specifically provided for in this Article V(A) above, including, but not
limited to Selling Commissions, shall be charged one hundred percent (100%)
to the Participants.
Costs charged to Participants and the Co-Managing General
Partners will be allocated among the Participants as provided in paragraph C
of Article VI.
D. LOSS ON SALE OF PARTNERSHIP ASSETS
If the Partnership sells any oil and gas property at a price which is
less than its undepleted cost, the Partnership shall charge the loss on such
sale to the Partners in the ratio of their remaining undepleted bases in such
property at the time of sale.
If the Partnership sells any asset, other than an oil and gas
property, at a price which is less than its undepreciated cost, the Partnership
shall charge the loss on such sale to the Partners who bore the cost of such
asset.
ARTICLE VI. ALLOCATION OF REVENUES AND DISTRIBUTIONS OF CASH
A. ALLOCATION OF REVENUES
All Partnership revenues shall be allocated seventy-four and
one-fourth percent (74.25%) to the Participants, twenty-four and
three-fourths percent (24.75%) to the Co-Managing General Partners and one
percent (1%) to the Special Limited Partners. For Partnership purposes,
revenues shall mean funds received by the Partnership from all sources, except
capital contributions, borrowings,
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<PAGE> 9
Assessments and interest on subscriptions, whether occurring during the term
of the Partnership or occurring as part of any plan of dissolution and
liquidation of the Partnership; provided, however, that the portion of the
revenues generated by the taxable disposition of a Partnership oil and gas
property that represents recovery of its simulated adjusted tax basis therein
will be allocated to the Partners in the same proportion such Partners (or
their predecessors in interest) were allocated the basis of such property
pursuant to paragraph C of Article IV; provided, further, that the portion
of the revenues generated by the taxable disposition of a Partnership
asset, other than an oil and gas property, equal to the Partnership's
adjusted tax basis in such property shall be allocated to the Partners in the
same proportion that the Partners bore the cost of such asset.
B. CASH DISTRIBUTIONS
The Partnership expects to distribute quarterly, or on a more current
basis if so determined by the Co-Managing General Partners, amounts to the
Partners equal to approximately the difference between revenues allocated to
the respective Partners as provided in this Article Vl, and costs charged to
the Partners as provided in Article V. This provision shall not, however,
serve as a limitation on the right of the Co-Managing General Partners
to retain, pledge or use so much of the revenues or other assets of
the Partnership, including amounts required to eliminate any capital
deficit of the Partners, to conduct additional operations of the
Partnership, to establish reserves for anticipated expenditures, or to repay
any amounts borrowed by the Partnership to finance the conduct of such
operations.
C. ALLOCATIONS AMONG PARTICIPANTS, SPECIAL LIMITED PARTNERS AND
CO-MANAGING GENERAL PARTNERS
All allocations of income, gain, loss and deduction to the
Participants as a class shall be allocated among the Participants based on
the ratio of their respective paid capital contributions, including
Assessments. Expenses and other costs paid from Assessments shall be charged
only to those Partners who paid the Assessment. All allocation of income,
gain, loss, deduction to the Special Limited Partners, if any, shall be
allocated among the Special Limited Partners in such proportions as shall be
established at the time of their admission to the Partnership or as they
shall later agree. All allocations of income, gain, loss, deduction and all
capital contributions and Assessments to the Co-Managing General Partners
will be divided eighty percent (80%) to Benton and twenty percent (20%) to
Energy Partners.
ARTICLE VII. ELECTIONS AND TAX ALLOCATIONS
For purposes of federal income taxes, and appropriate state or
local income taxes, the following allocations shall be made:
A. To the extent permitted by law, and except as otherwise
provided by this Article VII, all income, gain, losses and deductions
shall be allocated to the party who has been charged with the
expenditures or credited with the revenues giving rise to such deductions or
income.
B. The basis of Partnership properties for purposes of Code
Section 613A(c)(7)(D) shall be allocated in the same ratio as Partnership
Costs are allocated.
C. Notwithstanding the foregoing, however, production required
to be allocated for the purpose of computing the depletion deduction
(including percentage depletion in excess of the depletable basis of the
property) shall be allocated in the ratio in which the related revenues are
shared.
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<PAGE> 10
D. All tax credits and tax credit recapture shall be allocated
in the ratio in which revenues are shared at the time the expenditure giving
rise to such tax credit arises.
E. The Partnership shall make an election to deduct intangible
drilling and development costs on its federal Income tax return in
accordance with the option granted by the Code. No election shall be made
by the Partnership to be excluded from the application of the provisions of
Subchapter K of the Code.
F. In the event of the transfer of an interest in the
Partnership, or in the event of the distribution of property to any party
hereto, the Partnership may (but is not required to) file an election in
accordance with the applicable Treasury Regulations to cause the basis of
the Partnership's assets to be adjusted for federal income tax purposes as
provided by Code Sections 734 and 743.
G. Notwithstanding the foregoing provisions of this Article
VII, any allocation of loss or deduction to a Partner would reduce such
Participant's capital account balance below zero or would increase the
negative balance in such Participant's capital account at a time when another
Participant has a positive capital account balance, as determined at the close
of the period in respect of which the loss or deduction, as the case may be,
is to be allocated, such excess shall instead be allocated pro rata to
Participants having positive capital account balances until such capital
account balances are reduced to zero; provided, however, that in no event
shall there be a reallocation of any item of income, gain, loss or
deduction allocated among the Partners pursuant to this Agreement for prior
years.
Notwithstanding the foregoing provisions of this Article VII:
(1) The losses and deductions allocated to any
Partner pursuant to the foregoing provisions of this Article VII
shall not exceed the maximum amount of losses and deductions that can
be so allocated without causing such Partner to have an Adjusted
Capital Account Deficit at the end of any fiscal year. All losses
and deductions in excess of the limitation set forth in this clause
(1) shall be allocated to other Partners.
(2) If there is a net decrease in partnership
minimum gain (within the meaning of Treasury Regulation Sections
1.7041T(b)(4)(iv)(a)(2) and 1.704-1T(b)(4)(iv)(c)) during any
Partnership fiscal year, each Partner shall be specifically
allocated items of Partnership income and gain for such year (and,
if necessary, subsequent years) in an amount equal to the greater of:
(i) the portion of such Partner s share of the net decrease
in partnership minimum gain, determined in accordance with
Treasury Regulation Section 1.704-1T(b)(4)(iv)(f), that is
allocable to the disposition of Partnership property
subject to nonrecourse liabilities (within the meaning
of Treasury Regulation Section 1.704-1T(b)(4)(iv)(k)(3)),
determined in accordance with Treasury Regulation Section
1.704-1T(b)(4)(iv)(e), and
(ii) if such Partner would otherwise have an Adjusted
Capital Account Deficit at the end of such fiscal year, an
amount sufficient to eliminate such Adjusted Capital Account
Deficit.
The items of income and gain to be so specially allocated
pursuant to this clause (2) shall be determined in accordance with
Treasury Regulation Section 1.704-1T(b)(4)(iv)(e). This clause (2) is
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<PAGE> 11
intended to comply with the minimum gain chargeback
requirement of Treasury Regulation Section 1.7041T(b)(4)(iv)(e) and
shall be interpreted consistently therewith.
(3) Notwithstanding any provision of this Paragraph G
to the contrary (except clause (2)), if there is a net decrease in
Partner Minimum Gain attributable to a partner nonrecourse debt
(within the meaning of Treasury Regulation Section
1.704-1T(b)(4)(iv)(k)(4)) during any Partnership fiscal year, each
Partner who has a share of the Partner Minimum Gain
attributable to such partner nonrecourse debt, determined in
accordance with Treasury Regulation Section 1.704-1T(b)(4)(iv)(h)(5),
shall be specially allocated items of Partnership income and gain for
such fiscal year (and, if necessary, subsequent years) in an amount
equal to the greater of:
(i) the portion of such Partner s share of the net
decrease in Partner Minimum Gain attributable to such
partner nonrecourse debt, determined in accordance with
Treasury Regulation Section 1.704-1T(b)(4)(iv)(h)(5), that is
allocable to the disposition of Partnership property subject
to such partner nonrecourse debt, determined in accordance
with Treasury Regulation Section 1.704-1T(b)(4)(iv)(h)(4), and
(ii) if such Partner would otherwise have an Adjusted
Capital Account Deficit at the end of such fiscal year, an
amount sufficient to eliminate such Adjusted Capital Account
Deficit.
The items of income and gain to be so specially allocated
pursuant to this clause (3) shall be determined in accordance with
Treasury Regulation Section 1.704-1T(b)(4)(iv)(h)(4). This clause (3)
is intended to comply with the minimum gain chargeback requirement
of Treasury Regulation Section 1.704-1T(b)(4)(iv)(h)(4) and shall be
interpreted consistently therewith.
(4) Subject to the priority rules of Treasury
Regulation Section 1.704-1T(b)(4), if any Partner unexpectedly receives
any adjustment, allocation or distribution described in Treasury
Regulation Section 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5) or
1.704-1T(b)(2)(ii)(d)(6), items of Partnership income and gain shall
be specially allocated to such Partner in an amount and manner
sufficient to eliminate, to the extent required by Treasury
Regulation Sections 1.704-1 (b) and 1.704-1T, the Adjusted Capital
Account Deficit of such Partner as quickly as possible. It is intended
that this clause (4) qualify and be construed as a qualified
income offset within the meaning of Treasury Regulation Section
1.7041(b)(2)(ii)(d).
(5) If special allocations are required under clauses
(2), (3), and/or (4) in any fiscal year, such allocations shall be
made in the priorities required by Treasury Regulation Sections
1.704-1(b) and 1.704-1T.
(6) "Nonrecourse deductions" (within the meaning of
Treasury Regulation Section 1.704-1T(b)(4)(iv)(b)) for any fiscal year
or other period shall be specially allocated to the Partners in
proportion to their Units in the Partnership. Partner nonrecourse
deductions (within the meaning of Treasury Regulation Section
1.704-1T(b)(4)(iv)(h)(3)) for any fiscal year or other period
shall be specially allocated to the Partner who bears the economic
risk of loss with respect to the partner nonrecourse debt (within
the meaning of Treasury Regulation Section 1.704-1T(b)(4)(iv)(k)(4))
to which such partner nonrecourse deductions are attributable in
accordance with Treasury Regulation Section 1.704-1T(b)(4)(iv)(h).
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<PAGE> 12
(7) The Partners acknowledge that all distributions of
cash (including distributions upon liquidation of the Partnership)
are intended to be made in accordance with the priorities set forth
in Articles V and VI and that the Partners capital accounts are
intended to reflect the manner in which such distributions are
intended to be made. The allocations set forth in clauses (1) (last
sentence), (2), (3), (4), and (6) (first sentence) (the
Regulatory Allocations ) are intended to comply with certain
requirements of Treasury Regulation Sections 1.704-1(b) and
1.704-1T(b)(4), but may result in distortions of the Partner's
capital accounts in relation to the distributions that each Partner
is intended to receive from the Partnership. Notwithstanding any
other provisions of this Article VII (other than the Regulatory
Allocations), the Regulatory Allocations shall be taken into account
in allocating other Profits, Losses and items of income, gain,
loss and deduction to the Partners so that, to the maximum extent
possible, at any point in time the Partners' capital accounts shall
reflect the manner in which distributions would be made to the
Partners, if the Partnership were liquidated and the proceeds of
such liquidation were distributed to the Partners in accordance with
Articles VI and XVIII.
ARTICLE VIII. APPLICATION OF PROCEEDS
Net Proceeds will be used solely for the conduct of Partnership
operations.
In view of the fact that Partnership activities will not
commence until sales are closed and Partnership operations commence,
Benton and Energy Partners reserve the right to change the estimated
allocation of Proceeds, as described below, in the best interest of the
Partnership. However, it is anticipated that the Net Proceeds will be
applied by the Partnership on the basis of approximately the following
percentages:
<TABLE>
ACTIVITY - ASSUMING THE MINIMUM AMOUNT OFFERED IS RAISED PERCENTAGE
- -------------------------------------------------------- ----------
<S> <C>
Acquisition of Proven Producing Properties 100%
Drilling and Completion of Partnership Wells -0-
ACTIVITY - ASSUMING THE MAXIMUM AMOUNT OFFERED IS RAISED PERCENTAGE
- ------------------------------------------------------------- ----------
Acquisition of Proven Producing Properties 60%
Drilling and Completion of Partnership Wells 40%
</TABLE>
ARTICLE IX. FORMATION OF PARTNERSHIP
In the sole discretion of the Co-Managing General Partners, the
Partnership may be formed as soon as the minimum Subscriptions ($250,000)
have been raised. Additional Participants may be admitted to the
Partnership until the Offering Termination Date, as extended. From the time
the minimum Subscriptions have been received and the Partnership formed until
the Offering Termination
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<PAGE> 13
Date or final closing date, the Partnership will close at the end of each
month and admit new Participants and will acquire either a greater working
interest in the Proven Producing Properties previously acquired or will
acquire interest in additional Proven Producing Properties.
At the sole discretion of the Co-Managing General Partners, the
Partnership may continue to have monthly closing dates until such time as
the Offering Termination Date occurs or the Partnership sales are closed.
Once the final termination date has occurred or the Partnership sales
have closed, then all Participants will share in all Partnership costs and
revenues on a proportionate basis thereafter. The Partnership will not
engage in any recompletions, nor will the Partnership drill any wells, until
the final termination date.
ARTICLE X. TERM AND CONVERSION OF GENERAL PARTNER UNITS
A. The term of the Partnership will commence on the date of
execution of this Agreement, and will continue until December 31, 2040, and
will terminate at such earlier time as all of the interests and properties
acquired for the Partnership have been fully depleted, disposed of, sold
or abandoned, unless sooner terminated as set forth in Article XVI or XVIII of
this Agreement.
The calendar year is the Partnership s fiscal year, subject to
change by Benton and Energy Partners as permitted by the Code.
B. Following the completion of the Partnership s drilling
activities (but in no event prior to January 1, 1993), at the option of
Benton and Energy Partners, and subject to the receipt of the opinion of
counsel described below, the General Partner Units may be converted to
Limited Partner Units. Such conversion shall occur upon compliance with
this paragraph B. All other rights and obligations under this Agreement
shall not be affected by such conversion. Prior to any such conversion,
Benton and Energy Partners shall obtain an opinion of tax counsel to the
Partnership to the effect that such conversion would not result in any
materially adverse federal tax consequences to the Partnership or the General
Partners. In order to accomplish such conversion, Benton and Energy
Partners will (i) amend this Agreement with such changes therein or
amendments thereto as are deemed appropriate by Benton and Energy
Partners and that do not adversely affect the General Partners, (ii) file
an amended Certificate of Limited Partnership with the Secretary of State
for the State of California and (iii) take such other actions as are
necessary or appropriate to accomplish conversion of the General Partner
interests. Notwithstanding the foregoing, Benton and Energy Partners shall
not be obligated to cause conversion of the Partnership or may delay
such conversion if Benton and Energy Partners or their tax counsel determine
that conversion at that time would not be in the best interests of the
General Partners.
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ARTICLE XI. RIGHTS AND OBLIGATIONS OF BENTON AND ENERGY PARTNERS
A. Benton and Energy Partners shall be the Co-Managing
General Partners of the Partnership and as such shall conduct, direct and
exercise full control over all activities of the Partnership. Generally,
Benton shall be primarily responsible for all of the Partnership's oil and gas
activities and Energy Partners shall be primarily responsible for all the
Partnership's administrative activities. In order to carry out the purposes
of the Partnership as set forth in Article III of this Agreement, the
Participants and the Special Limited Partners, if any, agree that Benton and
Energy Partners have the rights and obligations set forth below.
1. Benton may purchase or sell any oil and gas interest
and may execute on behalf of the Partnership any and all documents or
instruments of any kind which Benton may deem appropriate in carrying
out the interests of the Partnership, including, but without
limitation, deeds, assignments, leases, subleases, operating
agreements, farmout agreements, unitization agreements, pooling
agreements, sales contracts gas sales contracts, transportation
contracts, division orders, transfer orders, or other marketing
agreements, documents or instruments of any kind or character or
amendments thereto, which relate to the affairs of the Partnership;
2. Energy Partners shall maintain complete and accurate
books of account for the Partnership; said books shall be kept at the
principal office of the Partnership and shall be open to inspection
after reasonable notice and request by any Partner or his authorized
representative, at his own expense, at any time during ordinary
business hours;
3. Within one hundred fifty (150) days after the end of
the fiscal year, Energy Partners shall provide each Participant and
Special Limited Partner on an annual basis commencing at the end of
the second full year of Partnership operations an independent
petroleum engineer s appraisal of the status of the properties;
4. Energy Partners shall provide each Participant and
Special Limited Partner with an annual report (copies of which,
together with a report on oil and gas reserves and a tax information
report, shall be furnished to appropriate state securities
administrators, as required) within one hundred fifty (150) days (or
such shorter period as may be required by law) after the close of the
Partnership's fiscal year, containing the following information:
a) Financial statements, including the
balance sheet and statements of operations, Partners'
equity and changes in financial position, prepared in
accordance with generally accepted accounting principles and
accompanied by an auditor's report containing the opinion of
an independent certified public accountant;
b) A description of each Prospect in which the
Partnership owns an interest, including the cost,
location, number of acres under lease and interest owned
by the Partnership, except that succeeding reports win
contain only material changes from the preceding report;
c) A summary itemization by type and/or
classification of the total fees, reimbursements and
compensation paid by the Partnership, or indirectly on
behalf of the Partnership, to Benton, Energy Partners or
their Affiliates during the period; and
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<PAGE> 15
d) A schedule reflecting the total Partnership
costs, and where applicable, the costs pertaining to each
Prospect, the costs paid by Benton and the costs paid by the
Participants and the Special Limited Partners, the total
Partnership revenues, the revenues received or credited to
Benton, and the revenues received or credited to the
Participants and the Special Limited Partners during the
period;
5. Energy Partners shall furnish a report to each
Participant and Special Limited Partner by March 15 of each year,
containing such information as Energy Partners deems necessary for the
proper presentation of federal income tax returns;
6. Energy Partners shall maintain, at the principal
office of the Partnership, copies of the Partnerships federal, state
and local income tax returns and reports for the six (6) most recent
years;
7. Benton will purchase, at the expense of the
Partnership, liability and other insurance to protect the Partnerships
properties and business;
8. Benton and Energy Partners may enter into any
agreement for the borrowing of money from a commercial bank or other
lending institution for payment of expenses of drilling and completion
activities on wells started with Proceeds, the acquisition of Proven
Producing Properties and for payment of General and Administrative
Expenses, including the purchase and lease of oil and gas properties
or equipment, and are authorized to assign any portion of, or all of,
the Partnerships properties and revenues therefrom for the purpose of
securing any such borrowed money; provided, however, that such
borrowing shall not exceed, in principal amount, twenty-five percent
(25%) of the Proceeds plus all paid Assessments; provided, further,
that in no event will the lender have the election to convert its
position as creditor Into an equally interest in the Partnership or in
Benton, Energy Partners or In any of their Affiliates;
9. Benton and Energy Partners may, in the sole exercise
of their discretion, make unsecured loans and advances to the
Partnership at Benton s and Energy Partners interest cost and may
otherwise borrow money and assign to the lender Partnership properties
and production therefrom as security; provided, however, that the
interest on loans and advances made by Benton and Energy Partners or
their Affiliates shall not exceed the amounts which would be charged
by unrelated banks (without regard to financial abilities or
guarantees) on comparable loans for the same purpose, and no fees,
points or other financing charges will be charged to the Partnership
by Benton, Energy Partners or their Affiliates;
10. In the states where the Partnership conducts
activities, Energy Partners may file any necessary instruments
required to qualify the Partnership to do business in the particular
state as a limited partnership, or to cause the limited partnership
status of the entity to be recognized;
11. Benton may cause title to Partnership property to be
held in the name of Benton; provided, however, that if property is
held in the name of Benton, an unrecorded assignment to the
Partnership shall be made and maintained in the Partnership's files;
provided, further, that any such assignment shall provide that the
properties are being held for the benefit of the Partnership and are
not subject to the debts, obligations or liabilities of Benton or its
Affiliates;
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<PAGE> 16
12. Benton and Energy Partners may admit Participants,
Special Limited Partners or substituted Participants without the
consent of other Participants or Special Limited Partners; provided,
however, that any transferee of a Unit or a Special Limited Partners
interest will receive a right to share in the profits and capital of
the Partnership but will not be a substituted Partner without the
prior written consent of Benton and Energy Partners, which consent may
be given or withheld in their sole and absolute discretion; provided,
further, that Benton and Energy Partners will withhold their written
consent in the event that they have reasonably determined in their
sole discretion that such substitution could have an adverse effect on
the business activities or the legal or tax status of the Partnership,
under either state or federal law;
13. Benton and Energy Partners may admit one or more
additional managing general partners which may become a successor
entity to Benton and Energy Partners and take action which would have
the effect of providing an additional and/or a successor managing
general partner, if the holders of a majority of the Units outstanding
approve; provided, however, that such approval of the holders of Units
shall not be necessary if the additional managing general partner
proposed by Benton or Energy Partners is (1) an Affiliate of Benton or
Energy Partners; (2) an entity with which Benton or Energy Partners
has merged; or (3) a person or entity that has purchased all or
substantially all the assets of Benton or Energy Partners;
14. Benton and Energy Partners may call for a vote of the
Participants to be taken on the items set forth in Article XVI;
15. Energy Partners may cause the investment of
Partnership funds in short-term liquid securities until the
expenditure of such funds is necessary in connection with Partnership
activities;
16. Energy Partners and Benton may amend the Agreement,
including amending the Agreement to alter the Partnership's form so
that it becomes a different type of business entity, for business and
tax reasons, subject to the provisions of Article XVI;
17. Energy Partners and Benton may do any and all things
necessary or appropriate in order to accomplish the purpose of the
Partnership, subject to the provisions of this Agreement;
18. Energy Partners and Benton may conduct other oil and
gas drilling and acquisition programs or income programs which may
commence prior to, during or subsequent to the Partnership;
19. Benton may purchase assets from the Partnership in
connection with a dissolution of the Partnership, at a price which is
the greater of the then fair market value (which term shall mean the
value of the assets as determined by an independent oil an gas
engineer) or the highest bona fide offer for such assets by a third
party, if any, regardless of any difference between such fair market
value and the original cost to the Partnership of such assets (subject
to the approval of a majority in interest of the Participants if the
asset represents five percent (5%) or more of the initial value of the
assets of the Partnership);
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<PAGE> 17
20. Energy Partners may make any and all elections for
purposes of federal, state or local income taxes that it deems
appropriate; and
21. Benton and Energy Partners may submit a partnership
claim or liability to arbitration or reference, assign the Partnership
property and trust for creditors or on the assignee s promise to pay
the debts of the partnership, confess a judgment or dispose of the
goodwill of the Partnership for adequate consideration.
B. Benton and Energy Partners shall have no authority on behalf
of the Partnership or themselves to:
1. Do any act in contravention of this Agreement;
2. Use Partnership property or commingle any Partnership
bank accounts or monies with funds of Benton, Energy Partners or their
Affiliates, or to make advances to Benton, Energy Partners or their
Affiliates, except where necessary to secure tax benefits of prepaid
drilling and completion costs, and in no event will such advances
include non-refundable payments for capital completion costs prior to
the time that a decision is made that the well warrants such
equipment;
3. Take any action with respect to partnership assets or
property which does not primarily benefit the Partnership, including,
among other things, the utilization of Partnership funds as
compensating balances for its own benefit, and the commitment of
future production n not in the best interests of the Partnership;
4. Make any loans of Partnership funds to Benton, Energy
Partners or their Affiliates;
5. Make or institute any marketing arrangements or other
relationships affecting the property of the Partnership where the
benefits are not fairly and equitably apportioned according to the
respective interests of all parties; or
6. Knowingly enter into any arrangements involving
working interests in any oil and gas property which commit the working
interest to be held in an entity which limits the liability of the
General Partners as to the working interest so as to cause the working
interest to be considered a passive activity so that losses from the
working interest may only offset passive activity income as set forth
in Code Section 469.
C. The following prohibitions and restrictions shall be
applicable to Benton:
1. If Benton sells, transfers or conveys all or any
portion of a lease to the Partnership, Benton must, at the same time,
sell, transfer, or convey to the Partnership an equal proportionate
interest in all its other leases in the same Prospects.
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<PAGE> 18
2. A sale, transfer, or conveyance to the Partnership of
less than all of the ownership of Benton or its Affiliates in any
portion of a lease (the Subject Portion ) is prohibited unless the
interest retained by Benton or its Affiliates is a working interest,
the respective obligations of Benton or its Affiliates and the
Partnership to pay costs with respect to the Subject Portion are
proportionate to their respective working interests after the
transfer, and Bentons or its Affiliates interest in the revenues does
not exceed any amount proportionate to its retained working interest.
Benton or its Affiliates may not retain any overrides or other burdens
on the Subject Portion, and may not enter into any farmout
arrangements with respect to its retained interest, except to
nonaffiliated third parties or other partnerships sponsored by Benton.
For the purposes of this paragraph, the term Affiliate shall not
include another partnership where the interest of Benton is identical
to, or less than, Benton s interest in the Partnership.
3. Benton may never profit by drilling in contravention
of its fiduciary obligation to the Partners. All services provided to
the Partnership by Benton or its Affiliates will be embodied in a
written contract which precisely describes the services to be rendered
and all compensation to be paid.
ARTICLE XII. COMPENSATION OF BENTON AND ENERGY PARTNERS
Benton maintains a staff of geologists, engineers and land
personnel who are responsible for screening and acquisition of leases and
for conducting drilling and producing operations. The costs incurred in
maintaining these departments, including salaries of personnel, are allocable
in past to the Partnership's activities and are included in Partnership
Costs. Such costs shall be paid or reimbursed by the Partnership out of
Proceeds or revenues.
Benton and Energy Partners will also be reimbursed for General and
Administrative Expenses incurred on behalf of the Partnership as a fee for
the first twelve (12) months of Partnership operations and thereafter as a
reimbursement of expenses incurred. The amount of the fee which will be
allocated entirely to the Participants for the first twelve (12) months of
Partnership operations will be three percent (3%) of the Participants'
Subscriptions.
Signal Securities, Inc. will receive a wholesaling fee of up to three
percent (3%) of the total Units sold by the broker/dealers for which Signal
acts as a wholesaling broker/dealer.
As set forth in Article Vl, Benton and Energy Partners will share
in Partnership revenues in an amount in excess of their contribution to
Partnership costs. The Participants and the Special Limited Partners
consent to the receipt by Benton, Energy Partners and their Affiliates of
the benefits and profits set forth in this Article.
ARTICLE XIII. PROTECTION OF THE PARTIES
In any threatened, pending or completed action, suit or proceeding
to which the either of the Co-Managing General Partners was or is a party or
is threatened to be made a party by reason of the fact that
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it was or is a Co-Managing General Partner of the Partnership (other than an
action by or in the right of the Partnership) involving any alleged cause of
action for damages arising from the performance of oil and gas activities,
including exploration, development, completion, operation, or other
activities relative to management and disposition of oil and gas properties
or production from such properties, the Partnership will indemnify the
Co-Managing General Partners against expenses, including attorneys fees,
judgments and amounts paid in settlement 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 Participants and the Special Limited Partners.
The termination of any action, suit or proceeding by judgment, order or
settlement shall not, of itself, create a presumption that Benton or Energy
Partners did not act in good faith and in a manner which they reasonably
believed to be in or not opposed to the best interests of the Partnership.
In any threatened, pending or completed action or suit by the
Partnership in the right of the Partnership, to which a Co-Managing
General Partner was or is a party or is threatened to be made a party,
involving an alleged cause of action by a Participant or a Special Limited
Partner for damages arising from the activities of a Co-Managing General
Partner in the performance of management of the internal affairs of the
Partnership as prescribed by this Agreement, the Partnership will indemnify
the Co-Managing General Partner against expenses, including attorneys fees,
actually and reasonably incurred by it in connection with the defense or
settlement of such action or suit if it acted in good faith and in a manner
it reasonably believed to be in or not opposed to the best interests of the
Partnership, as specified in this paragraph, except that no indemnification
shall be made in respect of any claim, issue or matter as to which a Co-
Managing General Partner shall have been adjudged to be liable for
negligence, misconduct or breach of fiduciary obligation in the performance
of its duty to the Partnership unless and only to the extent that the court in
which such action or suit was brought shall determine upon application,
that, despite the adjudication of liability, but in view of all
circumstances of the case, a Co-Managing General Partner is fairly and
reasonably entitled to indemnity for such expenses which the court shall deem
proper.
To the extent that a Co-Managing General Partner has been
successful on the merits or otherwise in defense of any action, suit or
proceeding referred to above, or in defense of any claim, issue or matter
therein, the Partnership shall indemnify a Co-Managing General Partner
against the expenses, including attorneys fees, actually and reasonably
incurred by it in connection therewith. Any such indemnification of a
Co-Managing General Partner shall be prohibited unless the Co-Managing
General Partner has determined in good faith that the course of conduct
which caused the loss or liability was in the best interest of the
Partnership; that such liability or loss was not the result of negligence
or misconduct by a Co-Managing General Partner; and that indemnification of
a Co-Managing General Partner or its Affiliates will not be allowed for
any liability imposed by judgment, and costs associated therewith, including
attorneys' fees, arising from or out of violation of state or federal
securities laws associated with the offer and sale of Partnership Units.
Indemnification will be allowed for settlements and related expenses of a
lawsuit alleging securities law violations, and for expenses incurred in
successfully defending such lawsuits, provided that a court either: (a)
approves the settlement and finds indemnification of the settlement and
related costs should be made or (b) approves indemnification of litigation
costs if a successful defense is made.
Any indemnification, unless ordered by a court, shall be made by the
Partnership only as authorized in the specific case and only upon a
determination by independent legal counsel in a written
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opinion that indemnification of a Co-Managing General Partner is proper in
the circumstances because a Co-Managing General Partner has met the
applicable standard of conduct set forth above.
The indemnification of a Co-Managing General Partner shall be limited
to and recoverable only out of the assets of the Partnership and not against
any Limited Partner or General Partner and indemnification of the Co-Managing
General Partners as to a third party is only with respect to such loss,
liability or damage not otherwise compensated for by insurance carried for the
benefit of the Partnership.
The Partnership may not incur the cost of that portion of
insurance which insures a Co-Managing General Partners from any liability
as to which the Co-Managing General Partner is prohibited from being
indemnified under this Article.
The General Partners hereby agree that each shall be solely and
individually responsible only for their pro rata share of the liabilities
and obligations of the Partnership, and any Participant who incurs liability
in excess of his pro rata share shall be entitled to contribution from the
other General Partners. Pursuant thereto, each Co-Managing General Partner
further agrees to indemnify each Participant from paying any liabilities or
obligations of the Partnership in excess of such Participant s capital
contribution. Furthermore, although the General Partners may be personally
liable for the liabilities and obligations to the Partnership, all such
liabilities and obligations shall be paid or discharged first with
Partnership assets (including insurance proceeds) before the General Partners
shall be obligated to pay or discharge any liability or obligation with their
personal assets.
ARTICLE XIV. RELATED PARTIES
Benton and Energy Partners and their Affiliates or related persons
or entities may be engaged or employed by the Partnership to render or
perform services for the Partnership and/or may sell property of any kind or
description to it, or may otherwise engage in transactions with the
Partnership. All such engagements, employments and other transactions shall
not be invalidated by reason of any such relationships so long as such person
is engaged, independently of the Partnership and as an ongoing business in
rendering such services or selling such equipment and supplies to a
substantial extent to other persons and such prices and terms are not higher
than those normally charged in the same geographic area by unaffiliated
persons or companies dealing at arm's length. If the person is not engaged in
business as provided above, then the price of such services shall be the cost
of such services, equipment or supplies to such person or the competitive
rate in the geographical area, whichever is less. Benton and Energy Partners
may be presently conducting or may conduct in the future other oil and gas
income, drilling and acquisition programs which may commence during or
subsequent to this Partnership. All contracts entered into between the
Partnership, Benton, Energy Partners and their Affiliates or related persons
or entities shall be terminated without penalty on not less than thirty (30)
days written notice by the Partnership or on sixty (60) days written
notice by Benton, Energy Partners or their Affiliates.
The leases transferred to the Partnership by Benton or its
Affiliates shall be sold at Cost unless Benton believes that the appraised
value is substantially lower than Cost. In such a case the value of the
lease will be determined by an independent appraiser and sold at the lower of
Cost or appraised value.
ARTICLE XV. RESTRICTIONS ON TRANSFERABILITY
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No Participant or Special Limited Partner shall have the power
to sell, assign or transfer his interest in the Partnership or to cause a
transferee to become a substituted Partner except upon the written consent of
Benton and Energy Partners. Each Participant and Special Limited Partner
specifically agrees to the admission of any substituted Partner as a Partner
when consented to by Benton and Energy Partners. Benton and Energy Partners
shall review any proposed transfer and shall withhold their consent In the
event they determine, in their sole and absolute discretion, that such
substitution could have an adverse effect on the business activities or the
legal or tax status of the Partnership or the remaining partners under
either state or federal law.
Each of Benton and Energy Partners may sell, assign, transfer, pledge
or encumber all or any portion of its rights to receive revenues as a
Co-Managing General Partner under this Partnership Agreement; provided,
however, that the assignment of such revenue interest shall not affect
Benton's and Energy Partners' other rights and obligations pursuant to this
Agreement.
In addition to the restrictions upon substitution of an additional
Participant or Special Limited Partner, neither a Participant nor a Special
Limited Partner may sell his rights to profits and capital In the Partnership
without furnishing Benton and Energy Partners with a copy of the offer to buy
such interest and giving Benton and Energy Partners the prior right for a
period of ten (10) days after receipt of written notice, to purchase such
interest on the terms contained in such offer. In the event Benton and
Energy Partners do not exercise their prior right to purchase such interest in
profits and capital within a ten (10) day period or notify the Participant or
Special Limited Partner that such right will not be exercised, the
Participant or Special Limited Partner shall have the right to sell his
interest in profits and capital for a period of forty-five (45) days.
Thereafter, the Participant or Special Limited Partner shall not sell any
part of his interest in profits and capital without again offering the same to
Benton and Energy Partners. A transferee of a Partner s right to profits
and capital who is not admitted as a Partner is not entitled to any of the
rights of a Partner. A transferee Participant or Special Limited Partner has
no greater right to terminate the Partnership than his transferor.
In no event shall any assignee or transferee hold less than one Unit
except by gift or operation of law.
ARTICLE XVI. RIGHTS, AUTHORITY AND LIABILITIES
OF PARTICIPANTS AND SPECIAL LIMITED PARTNERS
A. RIGHTS
By a majority vote of the outstanding Units, the Participants (but
not the Special Limited Partners) shall have the right to:
1. Remove Benton, Energy Partners and/or any successor
Co-Managing General Partner; terminate all contracts between the
Partnership and Benton, Energy Partners and their Affiliates; allow
Benton, Energy Partners or their Affiliates to remove all of their
property interests in the Partnership; and select a substitute
managing general partner or additional general partner to continue the
business of the Partnership;
2. Amend the Agreement, subject to the written consent
of Benton and Energy Partners concerning matter affecting their
interests in profits, losses, credits and property;
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3. Terminate the Partnership;
4. Approve the sale or exchange of all or substantially
all of the assets; and/or
5. Approve the admission of an additional general
partner proposed to be admitted as a Co-Managing General Partner by
Benton and Energy Partner, subject to the right of Benton and Energy
Partners to admit certain parties as general partners without the
consent of the Participants, as provided in paragraph 13 of Article
XI.
Either the Participants, upon the written request of ten percent
(10%) of the outstanding Units, or Benton or Energy Partners can cause a
vote to be taken with respect to the matters referred to above. Notice of a
meeting of the Participants will be mailed to the Participants within ten
(10) days of the receipt of such written notice unless compliance with
federal or state laws or regulations requires additional time. A meeting will
be held within sixty (60) days of the mailing of the notice. The presence,
in person or by proxy, of the holders of a majority of the Units outstanding
shall constitute a quorum and Participants may vote in person or by proxy at
any such meeting. If a quorum shall not be present or represented at any
meeting, a majority of the holders of Units entitled to vote at the meeting,
who are present in person or represented by proxy, may adjourn the meeting
from time to time, without notice other than announcement at the meeting,
until a quorum shall be present or represented. At any reconvening of an
adjourned meeting at which a quorum shall be present or represented, any
business may be transacted which could have been transacted at the
original meeting if a quorum had been present or represented. No matters
that would constitute taking part in control of the Partnership by the
Participants shall be considered at any meeting. In order to facilitate the
above rights, each Participant shall have a right to receive by mail the
complete list of names, addresses and interests of all other Participants, upon
written request to Energy Partners.
Any action that may be taken at a meeting of the Participants may
be taken without a meeting if a consent in writing setting forth the action
so taken is signed by Participants owning not less than the minimum Units
that would be necessary to authorize or take such action at a meeting at
which all the Participants were present and voted. Prompt notice of the
taking of action without a meeting shall be given to the Participants who have
not consented in writing.
Benton and Energy Partners shall have the right to amend the
Agreement; provided, however, that the Agreement shall not be amended by
Benton and Energy Partners in any material respect which would adversely
affect the rights of the Participants except by the affirmative vote of not
less than a majority of the outstanding amount of Units.
In the event that the Participants vote to remove Benton or Energy
Partners and substitute a new Co-Managing General Partner pursuant to
paragraph A of this Article XVI, the Partnership or the new Co-Managing
General Partner shall purchase the entire interest of
Benton or Energy Partners, including their interest in capital and
revenues on an assumed dissolution basis, at a price determined by mutual
agreement or by independent appraisal by a petroleum engineer selected by
mutual agreement. Such purchase shall provide for payment in full, or
assignment to Benton or Energy Partners of a direct interest in each
Partnership asset and/or liability equal to their then interest in revenue
and capital as determined above. Such payment or assignment shall occur at
the time of amendment of the Agreement and substitution of the new Co-Managing
General Partner.
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B. AUTHORITY
No Participant or Special Limited Partner other than a Co-Managing
General Partner has the power to manage or conduct Partnership business, to
act in the ordinary course of business for the Partnership or to sign for or
to bind the Partnership or any of its Partners and no such actions will be
considered to have been authorized by the other Partners.
C. LIABILITY
No Limited Partner shall be personally liable for any of the debts
of the Partnership or any of the losses thereof; provided, however, that the
amount committed by him to the capital of the Partnership, any return
thereof, and his interest in the Partnership's undistributed profits shall
be subject to liability. Additionally, a Limited Partner may be liable
for wrongfully distributed profits and interest on distributions in
return of capital.
If a Limited Partner receives the return of any part of his
contribution without violation of this Agreement or the California Revised
Limited Partnership Act, he shall be liable to the Partnership as
provided by such Act for the return of the amount of the returned
contributions but only to the extent necessary to discharge the
Partnership's liabilities to creditors who extended credit to the
Partnership during the period the contribution was held by the Partnership.
D. MISCELLANEOUS
No Participant or Special Limited Partner has any right of
repayment of his contributions to the Partnership except as expressly
provided in this Agreement. Participants have no right to vote on any
Partnership matters except as set forth in this Agreement. Special Limited
Partners have no voting rights except as provided by law. The Participants
and Special Limited Partners agree that they will not request a decree of
dissolution from a court until a majority vote of the outstanding Units
of Participants has approved such decree.
ARTICLE XVII. WITHDRAWAL OF BENTON OR ENERGY PARTNERS
A. EVENTS REQUIRING CONSENT OF ALL PARTNERS TO AVOID WITHDRAWAL
Except as waived in writing by all Partners at the time, Benton,
Energy Partners or any other General Partner shall cease to be a General
Partner of the Partnership upon the happening of any of the following events
of withdrawal: (1) Benton, Energy Partners or a General Partner withdrawing
from the Partnership by giving one hundred twenty (120) days written notice
to the other Partners, provided that the Partnership has completed its primary
drilling and completion activities and provided that the withdrawing Partner
pays all expenses incurred as a result of its withdrawal; (2) Benton, Energy
Partners or a General Partner is removed as a General Partner in accordance
with the terms of the Agreement; (3) in the case of a General Partner who is
a natural person, the death or adjudication or incompetency of a General
Partner; (4) in the case of a General Partner who is acting as a General
Partner by virtue of being a trustee of a trust, the termination of the trust,
but not merely the substitution of a new trustee; (5) in the case of a
General Partner which is a separate partnership, the dissolution and
commencement of winding up of the partnership; (6) in the case of Benton,
Energy Partners or a General Partner that is a corporation, the dissolution
of the corporation or the revocation of its charter; (7) in the case of an
estate,
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the distribution by the fiduciary of the estate s entire interest in the
Partnership; or (8) In the case of a General Partner that is any other legal
entity, the cessation of the legal existence of the legal entity.
Upon withdrawal, a General Partner other than Benton or Energy
Partners shall retain all rights to its proportionate share of revenues and
capital, but shall cease to have any vote or engage in any other activities
as a General Partner. The withdrawing General Partner will have the right to
transfer his interest subject to provisions of Article XV hereof.
B. EVENTS NOT CAUSING WITHDRAWAL
Neither Benton, Energy Partners nor any other General Partner shall
cease to be a general partner of the Partnership upon the happening of any of
the following events: (1) Benton, Energy Partners or a General Partner makes
an assignment for the benefit of creditors; (2) Benton, Energy Partners or
a General Partner files a voluntary petition in bankruptcy; (3) Benton,
Energy Partners or a General Partner is adjudicated bankrupt or insolvent;
(4) Benton, Energy Partners or a General Partner files a petition or answer
seeking for itself any reorganization, arrangement, composition,
readjustment, liquidation, dissolution or similar relief under any statute,
law or regulation; (5) Benton, Energy Partners or a General Partner files an
answer or other pleading admitting or failing to contest the material
allegations of a petition filed against it in any proceeding of a type
described in clause (4), above; or (6) Benton, Energy Partners or a General
Partner seeks, consents to or acquiesces in the appointment of a trustee,
receiver or liquidator of Benton, Energy Partners or a General Partner or
of all or any substantial part of Benton's, Energy Partners' or a General
Partner's properties.
ARTICLE XVIII. DISSOLUTION
A. The parties specifically agree that the retirement,
resignation, expulsion, death, incompetency, bankruptcy, insolvency,
dissolution, withdrawal, conveyance of the interest of a Participant or
Special Limited Partner, or admission of a new partner, or express
decision of a Participant shall not dissolve the Partnership. In such
event, the heir, legal representative, successor or assign of such
Participant or Special Limited Partner, as the case may be, shall become an
assignee of such Participant's or Special Limited Partner's interest. Such
assignee shall not have the rights of a substituted Partner, unless (i) such
heir, legal representative, successor or assign shall execute an
addendum to this Agreement, agreeing to be bound by all of the terms and
conditions hereof and to assume all of the obligations of the deceased or
incapacitated Participant or Special Limited Partner hereunder and (ii) both
Benton and Energy Partners shall have consented to such substitution, which
consent may be given or withheld in their sole and absolute discretion. When
a Participant or Special Limited Partner dies or retires and the business
is continued, the Participant, Special Limited Partner or his estate has no
right to require the Partnership or the remaining Participants or Special
Limited Partners to make an evaluated purchase of his Partnership interest.
B. If, notwithstanding the intent of the Partners as set forth
in paragraph A. above, any event listed in paragraph A results in the
dissolution of the Partnership, such dissolution shall be considered in
contravention of the Agreement, and the Partnership shall be continued or
reconstituted. In the event that the Partnership is dissolved, despite the
intention of the Partners, through any acts pursuant to paragraph A. above,
the Partners agree that Energy Partners may take any action which it deems
necessary or appropriate to continue the partnership or to reform the
Partnership on terms as Identical as possible to this Agreement. In the
event that Energy Partners causes a continuation or reformation of the
Partnership, the liability of all Partners will be deemed to continue
uninterrupted.
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C. The following actions shall cause a dissolution of the
Partnership, provided that Benton or Energy Partners cannot take any
voluntary action to cause dissolution between the time it receives notice
from the Participants of their intent to remove a Co-Managing General
Partner and the completion of the voting and the actions, if any, authorized
by the voting:
1. The transfer or assignment of the entire interest of
Benton or Energy Partners unless a remaining Co-Managing General
Partner agrees to continue the Partnership;
2. The written vote or consent by Participants
representing a majority of the outstanding Units and as further
provided by Article XVI;
3. The conduct of the Partnership becoming unlawful;
4. The disposition of all or substantially all of the
assets of the Partnership;
5. The expiration of the term of the Partnership as
provided in Article X;
6. An event of withdrawal or expulsion of Benton and
Energy Partners, unless at the time there is at least one other
General Partner who carries on the business of the Partnership;
provided, however, that the Partnership is not dissolved and is not
required to be wound up by reason of any event of withdrawal if,
within ninety (90) days after the withdrawal, all remaining Partners
agree in writing to continue the business of the Partnership and to
the appointment of one or more managing general partners if necessary
or desired; or
7. The entry of a decree of judicial dissolution.
Any dissolution caused by an event other than those events listed
above as causes of dissolution will be considered a dissolution in
contravention of this Agreement.
D. Upon dissolution and winding up of the Partnership, all of
the assets of the Partnership may be liquidated, and all Partnership assets
shall be applied in the following order:
1. To creditors, including Partners who are creditors,
to the extent permitted by law, in satisfaction of liabilities of
the Partnership other than liabilities for distributions to
Partners; then
2. To Partners in proportion to their positive capital
account balances.
With respect to the distributions made in liquidation, Partners who
are not otherwise creditors shall not have the status of and be entitled to
the remedies available to a creditor of the Partnership. In the event of a
distribution of assets in kind, all assets to be distributed to the
Participants and the Special Limited Partners shall be distributed to an
independent trustee who shall hold title for the benefit of such participants
and Special Limited Partners, collect and distribute to such Participants
and Special Limited Partners all of the net income from such properties
and/or sell such properties as such independent trustee deems to be in the
best interests of, and at the expense of, the Participants and Special
Limited Partners. The independent trustee shall operate the liquidating trust
arrangement for so long as is
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necessary to sell or exchange Partnership Assets for cash on terms which the
trustee deems to be in the best interest of the Participants and Special
Limited Partners.
In the event the liabilities of the Partnership exceed its assets
upon liquidation or otherwise if any General Partner then has a negative
balance in its capital account, the General Partners must contribute funds to
the Partnership, within the period required by Treasury Regulation Section
1.704-1, in the ratio of their negative capital accounts until negative
capital accounts are eliminated. In the event any General Partner fails to
make the required contribution, Benton and Energy Partners agree to pay the
amounts required, and no Participant or Special Limited Partner shall have
any liability for the amounts not contributed by other Participants.
Upon termination of the Partnership, a statement shall be prepared by
the certified public accountant employed by the Partnership setting forth the
assets and liabilities of the Partnership and the distribution of cash or
property of the Partnership as prescribed above, and a copy of such statement
shall be furnished to each Partner within ninety (90) days after completion of
winding up of Partnership business.
For purposes of the liquidation of Partnership assets, the
discharge of its liabilities, and the distribution of the remaining funds
and/or assets among the Partners as above described, in the event that all
Partnership property is not sold, or in the sole discretion of Benton
cannot be sold so that distributions in kind to the Partners are
appropriate or necessary, Benton and Energy Partners shall cause all
Partnership assets to be appraised by a competent, qualified appraiser. Any
excess of fair market value, as evidenced by such appraisal, over book value
of any Partnership assets and any excess of book value over such fair market
value of any Partnership assets shall be deemed gains or losses of the
Partnership, as the case may be, and subject to the provisions of Articles V
and VI, above, Benton and Energy Partners shall have the authority on behalf
of the Partnership to sell, convey, exchange, buy back, or otherwise
transfer the assets of the Partnership upon such terms and conditions as it
determines appropriate subject to the terms of this Agreement. A reasonable
time shall be allowed for the orderly liquidation of the assets of the
Partnership to minimize normal losses of the liquidation period. Any return
of all or any portion of the contributions by a Partner to the capital of the
Partnership shall be made solely from or out of Partnership assets and Benton
and Energy Partners shall not be personally liable for any such return.
ARTICLE XIX. ASSESSMENTS AND BORROWINGS
The Participant are subject to the payment of one or more
Assessments as additional capital contributions to the Partnership. No
Assessment shall be made, however, to unless and until all original
Proceeds have been expended or committed. The failure of one or more
Participants to pay any Assessment does not result in personal liability,
but will result in the dilution of such Participants interest In all
Partnership revenues and costs. A Participant's interest in the Participants'
share of Partnership revenues is based on the ratio that the sum of his
Subscription and paid Assessments bears to the total sum of all Participants'
Subscriptions and Assessments paid by all Participants (including Benton and
Energy Partners to the extent they pay non-consenting Participants' shares of
Assessments). The failure of a Participant to pay his share of an Assessment
will reduce this ratio accordingly, as of the closing of the pre-Assessment
or Assessment period. to one or more Participants fail to pay such
Assessment, Benton and Energy Partners may contribute the nonconsenting
Participants' shares of such Assessment, at their election, which will
proportionately increase the interest of Benton and Energy partners in all
Partnership revenues and costs, on the same basis as Benton and Energy Partners
were a
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Participant. If the Participants fail to pay an amount equal to at least
fifty percent (50%) of the total Assessment requested, Benton or Energy
Partners have the option of either returning to the Participants all
Assessments contributed, or contributing the non-consenting Participants'
shares of such Assessment. If the amount contributed by the Participants
equals or exceeds fifty percent (50%) of the Assessment requested, Benton
or Energy Partners may contribute all or a portion of the non-consenting
Participants' shares of such Assessment and also may reduce the Partnership's
participation in the Prospect for which the Assessment was made by entering
into a farmout agreement with respect to such Prospect.
The cumulative amount of Assessments shall not exceed twenty-five
percent (25%) of the Proceeds of the Partnership.
After the Partnership has expended or committed its Proceeds for
property acquisitions and drilling operations, Benton and Energy Partners
may finance necessary additional operations by Partnership Assessments,
use of Partnership revenues, or borrowings. Assessments may be levied by
Benton and Energy Partners only for the purpose of conducting subsequent
operations on Prospects upon which evaluation had begun during the
Partnership's initial operation or on leases sufficiently related to such
Prospects as to merit, in Benton's and Energy Partners' judgment, additional
operations to fully develop those Prospects or to acquire additional
undeveloped leases located on the geological feature or features of Prospects
owned by the Partnership in order to fully develop and protect its Prospects.
Benton and Energy Partners will give written notice to each
Participant of the nature and purpose of any Assessment, the Participant's
proportionate share of the estimated costs, and the effect of the
Participant's not participating in the Assessment. A Participant may elect to
participate in an Assessment by notifying Benton and Energy Partners of his
intention to participate and sending the requested payment by mail within
twenty (20) days after Benton and Energy Partners mail the written Assessment
notice, unless such period is extended by Benton and Energy Partners.
Any participant shall be deemed to have refused to participate in any
Assessment by notifying Benton and Energy Partners of his election not to
participate or by failure to pay his share of the Assessment when due. In
the event that the proportionate interests of the Partners change by reason
of Assessments, solely for the purpose of allocating costs and revenues,
there shall be an interim closing of the Partnership financial books
immediately upon closing of the Assessment period, with all allocations made
as of the date of the interim closing according to the interests of the
partners immediately prior to payment of the Assessments. The pre-Assessment
or Assessment period closes on the last day established by Benton and Energy
Partners for the payment of an Assessment by the Participants.
Benton intends to develop the Partnership's Prospects fully
through the initial Proceeds and Assessments. However, no assurance can be
made that such funds will be sufficient. If such funds are not sufficient,
the Partnership may borrow the necessary funds, may farm out the undeveloped
portion of certain Prospects, or may sell or abandon certain undeveloped
leases.
ARTICLE XX. POWER OF ATTORNEY
The Participants and the Special Limited Partners constitute and
appoint Energy Partners and its successors and assigns, with full power
of substitution, as their true and lawful representative and
attorney-in-fact in their name, place and stead to make, execute, and sign any
duly adopted amendments
27
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to this Agreement and all such other instruments, documents and certificates
or amendments thereto which may from time to time be required by the laws of
the United States of America, the State of California or any other state in
which the Partnership shall determine to do business, or any political
subdivision or agency thereof, to effectuate, implement and continue the
valid subsisting existence of the Partnership. Such representative and
attorney-in-fact shall not, however, have any right, power or authority to
amend or modify this Agreement when acting in such capacities except when the
amendment is made pursuant to Article XVI.
ARTICLE XXI. TAX MATTERS PARTNER
Energy Partners is designated as the Tax Matters Partner as
referred to in Code Section 6231 (a)(7)(A). As Tax Matters Partner, Energy
Partners shall:
A. Receive notice of the beginning of administrative
proceedings by the Internal Revenue Service at the Partnership level;
B. Receive notice of the final Partnership administrative
adjustment resulting from any Internal Revenue Service administrative
proceedings;
C. Keep all Partners informed of all administrative and
Judicial proceedings as to proposed adjustments at the Partnership level;
D. Have authority to enter into a settlement agreement with the
Internal Revenue Service with respect to determination of Partnership tax
items which shall bind all other Partners who have not received notice of
the proceedings from the Internal Revenue Service and who have not filed a
statement with the Secretary of Treasury providing that the Tax Matters
Partner shall not have authority to bind the Partner, which settlement may
be on such terms as the Tax Matters Partner shall determine in Ks sole
discretion to be in the best interests of the Partners as a class;
E. Have authority to commence judicial action for readjustment
of Partnership items included in a notice of final Partnership administrative
adjustment, with the appropriate court and the Partnership items to be
contested selected at the sole discretion of the Tax Matters Partner, or to
elect not to commence such action at its sole discretion;
F. Have authority in its sole discretion to intervene on
behalf of the Partnership in any judicial action commenced by any other
Partner as to Partnership tax matters;
G. Have authority in its sole discretion to file a request
with the Internal Revenue Service for an administrative adjustment, as a
substituted Partnership return, or otherwise, and to request judicial review
on behalf of the Partnership as to any part of a request for administrative
adjustment not allowed by the Internal Revenue Service;
H. Have authority in its sole discretion to enter into an
agreement with respect to all Partners to extend the period for assessing
any tax which is attributable to any Partnership item (and no other person
shall be authorized to enter into such an agreement);
I. Upon receipt of a notice of the beginning of administrative
proceedings from the Internal Revenue Service, to furnish to the Internal
Revenue Service the name, address, profit interest and
28
<PAGE> 29
taxpayer identification number of each Partner in the Partnership during the
applicable Partnership tax year, and such revised or additional information as
may be required by law; and
J. Conform to any tax administrative requirements as may be
placed on the Tax Matters Partner by Treasury Regulations as to income tax
adopted after the formation of the Partnership.
ARTICLE XXII. MISCELLANEOUS PROVISIONS
A. NOTICES
Except as elsewhere provided herein, any notice to Benton which shall
be given in connection with the business of this Partnership shall be duly
given if written and addressed and delivered by mail or wire to Benton Oil
and Gas Company, 2151 Alessandro Drive, Suite 120, Ventura, California
93001, and any notice to Energy Partners which shall be given in connection
with the business of this Partnership shall be duly given if written and
addressed and delivered by mail or wire to Energy Partners, 1001 Dove
Street, Suite 180, Newport Beach, California 92660-2816. The effective date
of notice given shall be the date it is received by Benton or Energy Partners,
as the case may be.
Notices to a Participant Partner shall be considered given if
addressed and sent by mail or wire to the Participant at the address shown
on the subscription Agreement or assignment document or such other address
as the participant shall have previously furnished the Co-Managing General
Partners pursuant to this paragraph A. Notices to a Special Limited Partner
shall be considered given if addressed and sent by mail or wire to the
Special Limited Partner at such address as the Special Limited Partner
shall have previously furnished the Co-Managing General Partners pursuant to
this paragraph A.
B. BINDING NATURE
This Agreement shall be binding upon the parties hereto, their
successors, heirs, devisees, assigns, legal representatives, executors and
administrators.
C. ENTIRE AGREEMENT
This Agreement and the Subscription Agreement contain the entire
understanding between and among the parties and supersede any prior
understanding or agreements between or among them respecting the subject
matter. There are no representations, arrangements, understandings or
agreements, oral or written, relating to the subject matter of this Agreement
and the Subscription Agreement, except those fully expressed herein or
therein.
D. SEVERABILTY
If any provision of this Agreement shall be held to be invalid,
such holding shall not in any way whatsoever affect the validity of the
remainder of this Agreement.
E. COUNTERPARTS
Several copies of this Agreement may be executed. All executed
copies constitute one Agreement, binding on all parties, even though all
parties have not executed the original or the same copy.
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<PAGE> 30
F. GOVERNING LAW
This Agreement has been executed and will be partially
performed in the State of California. All questions concerning this
Agreement and performance hereunder shall be judged and resolved in
accordance with the laws of California.
G. AMENDMENTS
Amendments may be made to this Agreement as provided under
Articles XI and XVI herein. Amendments shall be reduced to writing and, if
required, consented to by the Partners pursuant to Article XVI.
H. CAPTIONS
The captions of the several articles and paragraphs of this
Agreement are not part of the context thereof, are only guides or labels to
assist in locating or reading the several provisions thereof and shall be
ignored In construing it.
I. EXECUTION
Execution of the Subscription Agreement or acceptance of the
assignment of Units was or will be deemed an execution of this Agreement
on the date that the person becomes a Participant, which will occur when
Energy Partners accepts the Subscription Agreement or the assignment.
Execution of the Subscription Agreement or acceptance of the assignment of
Units constitutes authorization under Article XX for either of the
Co-Managing General Partners to file any certificate containing the names of
Subscribers or assignees as Participants, general partners and limited
partners.
J. PARTIES
The parties form this Partnership pursuant to the California
Revised Limited Partnership Act, as modified by the terms and conditions of
this Agreement. If any provision in this Agreement shall be held to be
invalid, such holding shall not in any way whatsoever affect the
validity of the remainder of this Agreement or affect the intent of the
parties to continue the Partnership pursuant to and make the
Partnership subject to a statute corresponding to the California Revised
Limited Partnership Act.
K. EVIDENCE OF SALES
Materials used in connection with the sale of Units in this
Partnership will be retained by Energy Partners for at least four (4) years
after the beginning of Partnership operations.
L. CERTIFICATE OF LIMITED PARTNERSHIP
A Certificate of Limited Partnership, as required by the California
Revised Limited Partnership Act, will be filed in the office of the
California Secretary of State and in such other places as may be required by
law. The Certificate of Limited Partnership shall provide that information
required under the law and such additional information as may be needed to
effectuate the terms of this Agreement. Such other filings may be made as
required to permit the Partnership to transact business in other jurisdictions.
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<PAGE> 31
IN WITNESS WHEREOF, Benton, Energy Partners, the Participants and
the Special Limited Partners, if any, have executed this Partnership
Agreement, effective on the date first above written.
BENTON OIL AND GAS COMPANY, PARTICIPANTS
as Co-Managing General Partner By: Energy Partners as Attorney-in-Fact,
pursuant to Article XX and the
By: _______________________________ Subscription Agreement for the
A.E. Benton, President Participants listed on Exhibit A
ENERGY PARTNERS, By: _________________________________
As Co-Managing General Partner Michael J. Greer
President
By: _______________________________
Michael J. Greer
President
SPECIAL LIMITED PARTNERS
By: _______________________________
31
<PAGE> 1
EXHIBIT 5.1
[EMENS, KEGLER, BROWN, HILL & RITTER LETTERHEAD]
__________, 1995
FORM OF OPINION
---------------
Benton Oil and Gas Company
1145 Eugenia Place
Suite 200
Carpinteria, California 93013
Gentlemen:
We have acted as counsel for Benton Oil and Gas Company (the "Company") in
connection with the registration under the Securities Act of 1933, as amended,
of up to _______ shares of common stock, $0.01 par value per share (the
"Shares"), and ________ Warrants to purchase shares of common stock (the
"Warrants"), to be offered to holders of partnership interests in the Benton
Oil & Gas Combination Partnership 1989-1 L.P., the Benton Oil & Gas Combination
Partnership 1990-1 L.P., and the Benton Oil & Gas Combination Partnership
1991-1 L.P. (the "Partnerships") in exchange for such partnership interests.
In this connection, we have examined the Certificate of Incorporation, the
Bylaws and the respective amendments thereto, the directors' and stockholders'
minutes, and the Registration Statement filed with the Securities and Exchange
Commission, and exhibits thereto, and such other documents that we have deemed
necessary to the opinion hereinafter expressed.
We are of the opinion that the Shares are validly authorized and upon their
issuance in exchange for partnership interests in the Benton Oil & Gas
Combination Partnership 1989-1 L.P., the Benton Oil & Gas Combination
Partnership 1990-1 L.P., and the Benton Oil & Gas Combination Partnership
1991-1 L.P. as contemplated by the Registration Statement, will be legally
issued, fully paid, and non-assessable.
We are of the opinion that the Warrants are validly authorized and upon their
issuance in exchange for partnership interests in the Partnerships will be
legally issued.
<PAGE> 2
[EMENS, KEGLER, BROWN, HILL & RITTER LETTERHEAD]
We are of the opinion that the Shares issued upon exercise of the Warrants as
contemplated by the Warrant Agreement will be validly authorized, legally
issued, fully paid, and non-assessable.
We hereby consent to the reference to Emens, Kegler, Brown, Hill & Ritter
Co., L.P.A. appearing under the heading "Legal Matters" in the Registration
Statement and any amendments thereto and the Prospectus of the Company relating
to the proposed exchange of the Shares and Warrants.
Very truly yours,
EMENS, KEGLER, BROWN, HILL & RITTER CO., L.P.A.
By:____________________________________________
<PAGE> 1
EXHIBIT 23.1
INDEPENDENT AUDITORS' CONSENT
We consent to the use in this Registration Statement of Benton Oil and Gas
Company on Form S-4 of our reports dated March 31, 1995 relating to the
financial statements of Benton Oil and Gas Company, Benton Oil & Gas
Combination Partnership 1989 - 1, L.P., Benton Oil & Gas Combination
Partnership 1990 - 1, L.P. and Benton Oil & Gas Combination Partnership 1991 -
1, L.P., appearing in the Prospectus, which is a part of such Registration
Statement, and to the reference to us under the heading "Experts" in such
Prospectus.
Deloitte & Touche LLP
Los Angeles, California
July 24, 1995
<PAGE> 1
EXHIBIT 23.2
CONSENT OF
EMENS, KEGLER, BROWN, HILL & RITTER CO., L.P.A.
We hereby consent to the reference to Emens, Kegler, Brown, Hill & Ritter
Co., L.P.A., appearing under the headings "Certain Federal Tax Consequences"
and "Legal Matters", in the Registration Statement and in any and all
amendments thereto and the Prospectus of the Company relating to the exchange
of Common Stock and Warrants of Benton Oil and Gas Company for the partnership
interests of 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. pursuant to the terms set forth in the Registration
Statement.
Very truly yours,
EMENS, KEGLER, BROWN, HILL & RITTER CO., L.P.A.
By: /s/ Jack A. Bjerke
--------------------------------------------
Jack A. Bjerke, Vice President
Dated: July 24, 1995
<PAGE> 1
EXHIBIT 23.3
[HUDDLESTON & CO. LETTERHEAD]
CONSENT OF INDEPENDENT PETROLEUM ENGINEER
-----------------------------------------
Gentlemen:
Huddleston & Co., Inc., hereby consents to the use of its name, use of its
audit reports, and reference to it regarding its audit of the Benton Oil and Gas
Company reserve reports, prepared by Benton Oil and Gas Company, dated March 8,
1995, included in Form S-4 Registration Statement, or included therein by
reference to the Form 10-K for the year ended December 31, 1994, of Benton Oil
and Gas Company registering shares of its common stock for exchange to holders
of partnership interests in Benton Oil & Gas Combination Partnership 1989-1,
L.P., Benton Oil & Gas Combination Partnership 1990-1, L.P., and Benton Oil and
Gas Combination Partnership 1991-1, L.P.
HUDDLESTON & CO., INC.
By: /s/ PETER D. HUDDLESTON
----------------------------
Peter D. Huddleston, P.E.
President
Date: July 19, 1995
<PAGE> 2
[HUDDLESTON & CO. LETTERHEAD]
CONSENT OF INDEPENDENT PETROLEUM ENGINEER
-----------------------------------------
Gentlemen:
Huddleston & Co., Inc., hereby consents to the use of its name, use of its
audit report, and reference to it regarding its audit of the Benton Oil and Gas
Combination Partnership 1989-1, L.P., reserve reports, prepared by Benton Oil
and Gas Company, managing general partner, dated March 8, 1995, in the Form S-4
Registration Statement of Benton Oil and Gas Company registering shares of its
common stock in exchange for partnership interests.
HUDDLESTON & CO., INC.
By: /s/ PETER D. HUDDLESTON
-----------------------------
Peter D. Huddleston, P.E.
President
Date: July 19, 1995
<PAGE> 3
[HUDDLESTON & CO. LETTERHEAD]
CONSENT OF INDEPENDENT PETROLEUM ENGINEER
-----------------------------------------
Gentlemen:
Huddleston & Co., Inc., hereby consents to the use of its name, use of its
audit report, and reference to it regarding its audit of the Benton Oil & Gas
Combination Partnership 1990-1, L.P., reserve reports, prepared by Benton Oil
and Gas Company, managing general partner, dated March 8, 1995, in the Form S-4
Registration Statement of Benton Oil and Gas Company registering shares of its
common stock in exchange for partnership interests.
HUDDLESTON & CO., INC.
By: /s/ PETER D. HUDDLESTON
----------------------------
Peter D. Huddleston, P.E.
President
Date: July 19, 1995
<PAGE> 4
[HUDDLESTON & CO. LETTERHEAD]
CONSENT OF INDEPENDENT PETROLEUM ENGINEER
-----------------------------------------
Gentlemen:
Huddleston & Co., Inc., hereby consents to the use of its name, use of its
audit report, and reference to it regarding its audit of the Benton Oil & Gas
Combination Partnership 1991-1, L.P., reserve reports, prepared by Benton Oil
and Gas Company, managing general partner, dated March 8, 1995, in the Form S-4
Registration Statement of Benton Oil and Gas Company registering shares of its
common stock in exchange for partnership interests.
HUDDLESTON & CO., INC.
By: /s/ PETER D. HUDDLESTON
-----------------------------
Peter D. Huddleston, P.E.
President
Date: July 19, 1995
<PAGE> 1
EXHIBIT 24.2
SECRETARY'S CERTIFICATE
The undersigned Toni L. Jackson hereby certifies that the following
resolution was duly adopted by the Board of Directors of Benton Oil and Gas
Company on January 25, 1995 and remains in full force and effect as of the date
hereof.
RESOLVED FURTHER, that A. E. Benton is authorized to sign the Registration
Statement and execute a power of attorney on behalf of the Company and as
the Company's Principal Executive Officer, and that Chris H. Hickok is
authorized to sign the Registration Statement and execute a power of
attorney as its Principal Financial Officer and Principal Accounting
Officer, which powers of attorney appoint Gregory S. Grabar, David H.
Pratt, Jack A. Bjerke and Amy M. Shepherd, and each of them, as
attorney-in-fact and agents to execute all necessary documents required to
be filed with the Securities and Exchange Commission or the states in
connection with the registration of the Common Stock and Warrants;
/s/ Toni L. Jackson
--------------------------
Toni L. Jackson, Secretary
