<PAGE> 1
As filed with the Securities and Exchange Commission on October 7, 1998.
Registration Statement No. 333-50637
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------
AMENDMENT NO. 4
TO
FORM S-4
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
---------------
SWIFT ENERGY COMPANY
(Exact name of Registrant)
TEXAS 1311 74-2073055
(State of incorporation) (Primary Standard Industrial (I.R.S. Employer
Classification Code Number) Identification No.)
A. EARL SWIFT, CHIEF EXECUTIVE OFFICER
SWIFT ENERGY COMPANY
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060
(281) 874-2700
(Name, address and telephone number of Registrant's executive offices and agent
for service)
Copies to:
DONALD W. BRODSKY
KAREN BRYANT
JENKENS & GILCHRIST,
A PROFESSIONAL CORPORATION
1100 LOUISIANA STREET, SUITE 1800
HOUSTON, TEXAS 77002
(713) 951-3300
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 being offered in connection
with the formation of a holding company and there is compliance with General
Instruction G, check the following box. [ ]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following
box and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under
the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
CALCULATION OF REGISTRATION FEE
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<CAPTION>
============================================================================================================
PROPOSED PROPOSED
TITLE OF EACH AMOUNT MAXIMUM MAXIMUM AMOUNT OF
CLASS OF SECURITIES TO BE OFFERING AGGREGATE REGISTRATION
TO BE REGISTERED REGISTERED PRICE PER SHARE(1) OFFERING PRICE FEE
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Common Stock, $.01 par
value per share 2,500,000 $18.3125 $45,781,250.00 $13,505.47(2)
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</TABLE>
(1) Estimated solely for the purpose of calculating the registration fee.
(2) Paid previously.
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 WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT
SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE
SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a),
MAY DETERMINE.
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SWIFT ENERGY COMPANY
CROSS REFERENCE SHEET
FORM S-4
<TABLE>
<CAPTION>
LOCATION/CAPTION IN JOINT PROXY
FORM S-4 ITEM NUMBER AND CAPTION STATEMENT/PROSPECTUS
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A. INFORMATION ABOUT THE TRANSACTION
1. Forepart of the Registration Statement and Outside Front Cover
Page of Prospectus . . . . . . . . . . . . . . . . . . . . . . Outside Front Cover Page of Joint
Proxy Statement/Prospectus
2. Inside Front and Outside Back Cover Pages of Prospectus . . . . Inside Front and Outside Back Cover
Pages of Joint Proxy
Statement/Prospectus
3. Risk Factors and Ratio of Earnings to Fixed Charges and Other
Information . . . . . . . . . . . . . . . . . . . . . . . . . . Summary; Risk Factors
4. Terms of the Transaction . . . . . . . . . . . . . . . . . . . Summary; Special Factors; The
Proposals
5. Pro Forma Financial Information . . . . . . . . . . . . . . . . Unaudited Pro Forma Con-solidated
Financial Statements
6. Material Contracts with Company being Acquired . . . . . . . . . Not Applicable
7. Additional Information Required for Reoffering by Persons and
Parties Deemed to be Underwriters . . . . . . . . . . . . . . . Not Applicable
8. Interests of Named Experts and Counsel . . . . . . . . . . . . Not Applicable
9. Disclosure of Commission Position on Indemnification for
Securities Act Liabilities . . . . . . . . . . . . . . . . . . Not Applicable
B. INFORMATION ABOUT THE REGISTRANT
10. Information with Respect to S-2 Registrants . . . . . . . . . . Incorporation of Certain Information
by Reference
11. Incorporation of Certain Information by
Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . Incorporation of Certain Information
by Reference; Description of Capital
Stock
12. Information with Respect to S-2 or S-3 Registrants . . . . . . . Business and Properties
13. Incorporation of Certain Information by Reference. . . . . . . . Not Applicable
</TABLE>
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<TABLE>
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14. Information with Respect to Registrants Other Than S-3 or 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
Companies . . . . . . . . . . . . . . . . . . . . . . . . . . . Partnership Supplements
D. VOTING AND MANAGEMENT INFORMATION
18. Information if Proxies, Consents or Authorizations are to be
Solicited . . . . . . . . . . . . . . . . . . . . . . . . . . . The Proposals; Management; Principal
Shareholders; Certain Relationships
and Related Transactions
19. Information if Proxies, Consents or Authorizations are not to
be Solicited or in an Exchange Offer . . . . . . . . . . . . . Not Applicable
</TABLE>
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SWIFT ENERGY COMPANY
CROSS-REFERENCE SHEET
FORM S-3
<TABLE>
<CAPTION>
CAPTION OR LOCATION/CAPTION IN
FORM S-3 ITEM NUMBER AND CAPTION JOINT PROXY STATEMENT/PROSPECTUS
-------------------------------- --------------------------------
<S><C> <C>
1. Forepart of the Registration Statement and Outside Front Cover Page
of Prospectus . . . . . . . . . . . . . . . . . . . . . . . . . . . . Front Cover Page of the Registration
Statement; Inside Front and Outside Back
Cover Page
2. Inside Front and Outside Back Cover Pages of Prospectus . . . . . . . Inside Front and Outside Back Cover Pages
of Joint Proxy Statement/Prospectus;
Table of Contents
3. Summary Information, Risk Factors and Ratio of Earnings to Fixed
Charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Summary; Risk Factors
4. Use of Proceeds . . . . . . . . . . . . . . . . . . . . . . . . . . . Not Applicable
5. Determination of Offering Price . . . . . . . . . . . . . . . . . . . Outside Front Cover Page of Joint Proxy
Statement/Prospectus; Summary; Investor
Election to Participate in Offering of
2,500,000 Shares of Swift Common Stock to
Eligible Purchasers
6. Dilution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Risk Factors--Dilution upon Issuance of
Shares
7. Selling Security Holders . . . . . . . . . . . . . . . . . . . . . . Not Applicable
8. Plan of Distribution . . . . . . . . . . . . . . . . . . . . . . . . Summary; Investor Election to Participate
in Offering of 2,500,000 Shares of Swift
Common Stock to Eligible Purchasers
9. Description of Securities to be Registered . . . . . . . . . . . . . Outside Front Cover Page; Summary;
Description of Swift Energy Company
Capital Stock
10. Interests of Named Experts and Counsel. . . . . . . . . . . . . . . . Legal Matters; Experts
11. Material Changes . . . . . . . . . . . . . . . . . . . . . . . . . . Incorporation of Certain Information by
Reference and Attachment of Information
Hereto; Summary--The Company;
Management's Discussion and Analysis of
Financial Condition and Results of
Operations; Business
12. Incorporation of Certain Information by Reference . . . . . . . . . Incorporation of Certain Information by
Reference and Attachment of Information
Hereto; Available Information
13. Disclosure of Commission Position on Indemnification for
Securities Act Liabilities . . . . . . . . . . . . . . . . . . . . . Not Applicable
</TABLE>
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SWIFT ENERGY MANAGED PENSION ASSETS PARTNERSHIP 1988-A, LTD.
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060
(281) 874-2700
NOTICE OF SPECIAL MEETING OF LIMITED PARTNERS
TO BE HELD ________________, 1998
Notice is hereby given that a special meeting of limited partners (the
"Special Meeting") of Swift Energy Managed Pension Assets Partnership 1988-A,
Ltd. (the "Partnership") will be held at 16825 Northchase Drive, Suite 400,
Houston, Texas, on Tuesday, _________________, 1998 at 4:00 p.m. Central Time
for the following purposes:
1. To consider and vote upon the adoption of a proposal for the
ultimate sale of substantially all of the assets of the
Partnership to the Managing General Partner and the dissolution,
winding up and termination of the Partnership. The asset sale and
the termination comprise a single proposal (the "Proposal"), and a
vote in favor of the Proposal will constitute a vote in favor of
each of these matters.
2. To transact such other business as may be properly presented at
the Special Meeting or any adjournments or postponement thereof.
Only limited partners of record as of the close of business on __________,
1998 will be entitled to notice of and to vote at the Special Meeting, or any
postponement or adjournment thereof.
IF YOU DO NOT EXPECT TO BE PRESENT IN PERSON AT THE SPECIAL MEETING OR
PREFER TO VOTE BY PROXY IN ADVANCE, PLEASE SIGN AND DATE THE ENCLOSED PROXY AND
RETURN IT PROMPTLY IN THE ENCLOSED POSTAGE-PAID ENVELOPE WHICH HAS BEEN
PROVIDED FOR YOUR CONVENIENCE. THE PROMPT RETURN OF THE PROXY WILL ENSURE A
QUORUM AND SAVE THE PARTNERSHIP THE EXPENSE OF FURTHER SOLICITATION.
SWIFT ENERGY COMPANY,
Managing General Partner
JOHN R. ALDEN
Secretary
__________________, 1998
[VARIABLE PAGE]
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__________________, 1998
[SWIFT LOGO]
Dear Investor:
As your Managing General Partner, Swift Energy Company believes that the
time has come to dissolve and liquidate your Partnership. Enclosed is a Joint
Proxy Statement/Prospectus and related information pertaining to a proposal for
the sale of all of your Partnership's oil and gas assets to the Managing
General Partner and the dissolution and liquidation of the Partnership. The
price proposed to be paid by the Managing General Partner is based on the
higher of two fair market value estimates on a Partnership-by-Partnership basis
prepared by independent appraisers, plus a premium of 7.5% above such higher
fair market value estimate added by the Managing General Partner. In order for
the sale and liquidation to take place; investors in your Partnership holding
at least a majority of the outstanding Units must approve this proposal. IT IS
IMPORTANT THAT YOU REVIEW THE ENCLOSED MATERIALS BEFORE VOTING ON THE PROPOSAL,
WHICH YOU MAY VOTE "FOR" OR "AGAINST."
The Managing General Partner recommends that you vote "FOR" such
proposed sale and liquidation for a number of reasons. The Partnership has
been in existence for at least the planned five to ten years. Limited capital
is available for enhancement or development activities on the properties in
which the Partnership owns interests. To continue operation of the Partnership
means the direct and administrative expenses, as well as the cost of operating
the properties in which the Partnership owns an interest, will continue while
revenues decrease, which may decrease funds ultimately available to investors
in your Partnership. See "Special Factors--Reasons for Proposals--Decreasing
Cash Flow While Expenses Continue." Thus, approval of the current sale of the
Partnership's property interests at this time will accelerate the receipt by
investors of the remaining cash value of the Partnership's property interests
while avoiding the risk of continued and extreme volatility of oil and gas
prices, as well as inherent geological, engineering and operational risks. The
Managing General Partner believes that improvements over the last several years
in the level of natural gas prices, relative to such prices in the mid-1990's,
make this an appropriate time for the Investors to consider the sale of the
Partnership's property interests, which also increases the likelihood of
maximizing the value of such assets. See "Special Factors--Reasons for the
Proposals" and "The Proposals--Recommendation of the Managing General Partner."
Also included in this package are the most recent financial and other
information prepared regarding your Partnership. The enclosed Joint Proxy
Statement/Prospectus relates to the proposal as well as presents an opportunity
for you to purchase shares of Swift Energy Company common stock directly from
Swift, without any broker commissions, with funds you may receive from any cash
distribution from your Partnership if the proposal is approved. The shares are
offered to you should you wish to continue your investment in, among other
things, the Partnership's properties. Of course, any such investment on your
part is your choice. IF THE PROPOSAL IS APPROVED BY THE REQUISITE VOTE OF THE
INVESTORS IN THE PARTNERSHIPS, UNLESS YOU MAKE AN ELECTION TO RECEIVE SWIFT
ENERGY COMPANY SHARES, YOU WILL RECEIVE CASH UPON LIQUIDATION OF THE
PARTNERSHIP. If you need any further material or have questions regarding this
proposal or the offering, please feel free to contact the Managing General
Partner at (800) 777-2750.
WE URGE YOU TO COMPLETE YOUR PROXY AND RETURN IT IMMEDIATELY, AS YOUR VOTE
IS IMPORTANT IN REACHING A QUORUM AND IS NECESSARY TO HAVE AN EFFECTIVE VOTE ON
THIS PROPOSAL. Enclosed is a green Proxy, along with a postage-paid envelope
addressed to the Managing General Partner for your use in voting and returning
your Proxy. Thank you very much.
SWIFT ENERGY COMPANY,
Managing General Partner
A. Earl Swift
Chairman
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Information contained herein is subject to completion or amendment. These
securities may not be delivered without the delivery of a final prospectus.
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.
SWIFT ENERGY COMPANY
JOINT PROXY STATEMENT/PROSPECTUS
DATED ___________________, 1998
Swift Energy Company, a Texas corporation ("Swift," the "Company" or
"Managing General Partner"), hereby submits for approval its proposals to
purchase all of the oil and gas assets (the "Property Interests") owned by 63
Texas limited partnerships (individually, a "Partnership" and, collectively,
the "Partnerships") for which it serves as Managing General Partner, and
thereafter, dissolve the Partnerships (for each Partnership, the "Proposal"
and, collectively, the "Proposals"). The net purchase price for the Property
Interests is expected to be approximately $70.6 million, subject to certain
reductions based on cash flow distributions to the Partnerships prior to
closing. A portion of the purchase price for the Property Interests may be
funded by the concurrent offer hereby of up to 2,500,000 shares of common
stock, $.01 par value (the "Common Stock"), of the Company to certain Investors
(as defined) in the Partnerships who elect to receive Common Stock in lieu of
some or all of the cash that they will be entitled to receive upon their
Partnership's liquidation.
Both the vote upon the Proposals and any election made by an individual
Investor to elect to receive shares of Common Stock are subject to numerous
risk factors, including these highlighted below:
o Substantial conflicts of interest exist because if the Proposals are
approved, the Managing General Partner will purchase assets from the
Partnerships while it serves as Managing General Partner for the
Partnerships.
o Although the purchase price for Property Interests is based on
appraisals by independent appraisers, it may or may not be the highest
possible price.
o No independent representative on behalf of the Investors negotiated the
terms of the Proposal with the Managing General Partner.
o No fairness opinion was obtained regarding the fairness of the Proposals
or of the purchase price for any of the Partnerships.
o Investors may forgo profit from approving the sale of the Property
Interests that the Managing General Partner may gain by investing
capital to recover behind-pipe reserves or develop non-developed
reserves of those acquired assets, and possibly due to commodity price
improvement.
o An election by an Investor to receive shares of Common Stock in lieu of
a cash distribution subjects such Investor to various risks of owning
Common Stock.
o An investment in the Company fundamentally differs from investments in
the Partnerships.
SEE "RISK FACTORS" BEGINNING ON PAGE ___ FOR A MORE COMPLETE DISCUSSION OF
RISK FACTORS THAT SHOULD BE CONSIDERED BY INVESTORS IN DETERMINING WHETHER TO
VOTE TO APPROVE THE PROPOSALS AND WHETHER TO ELECT TO PURCHASE ANY COMMON STOCK
IF THE PROPOSAL IS APPROVED BY THEIR PARTNERSHIP.
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SPECIAL MEETINGS OF INVESTORS
OF THE PARTNERSHIPS
This Joint Proxy Statement/Prospectus is being furnished to limited
partners or interest holders in the Partnerships (individually, an "Investor"
and collectively, the "Investors") in connection with the solicitation of
proxies (individually, a "Proxy" and collectively, the "Proxies") by the
Managing General Partner for use at Special Meetings of the Investors (the
"Special Meetings," or singly for each Partnership, the "Special Meeting") of
each of the Partnerships. The Special Meetings are being called by the
Managing General Partner for Investors to consider and vote upon the Proposals
for the ultimate sale of substantially all of the Property Interests of each of
the Partnerships to the Company and the subsequent termination of such
Partnerships, and to transact such other business as may be properly presented
at the Special Meeting or any adjournments or postponements thereof. In the
event of such sale of the Property Interests, the Partnerships' assets will
consist solely of cash which each Investor of the Partnerships will be entitled
to receive as a distribution pursuant to the terms of the limited partnership
agreement of each Partnership.
The Company intends to profit through a return on the capital used to
purchase the Property Interests and by investing additional capital in their
further development. The purpose of the Proposals is to wind up the business
of the Partnerships because the hydrocarbon production of the producing
properties in which the Partnerships own interests has steadily declined, as
was contemplated when the Partnerships were formed. Furthermore, the
Partnerships do not have the capital to further develop their Property
Interests, nor was it contemplated at formation of the Partnerships that
additional capital contributions would be made by Investors. The Company in its
capacity as Managing General Partner believes that the Proposals are fair to
Investors and are structured in a manner that attempts to realize the highest
sales price for the Partnerships' Property Interests. However, there can be no
assurance that the proposed purchase prices represent the highest possible
prices which could be received for the Property Interests.
OFFERING OF
2,500,000 SHARES OF COMMON STOCK
OF SWIFT ENERGY COMPANY
This Joint Proxy Statement/Prospectus also relates to the concurrent
offering (the "Offering") of up to 2,500,000 shares of Common Stock of the
Company being made solely to those Investors in Partnerships which along with
their Companion Partnerships (as defined) approve the Proposals (individually,
an "Eligible Purchaser" and collectively, the "Eligible Purchasers"). The
Company hereby offers to each Eligible Purchaser the opportunity to purchase
shares of Common Stock direct from the Company without any broker commissions.
The decision to purchase any shares of Common Stock rests with each Eligible
Purchaser and is completely voluntary. The Common Stock may be purchased with
all or any portion of the Partnership cash distribution such Eligible Purchaser
will be entitled to receive, provided that a minimum round lot of 100 shares
must be purchased, although Eligible Purchasers may purchase shares in addition
to the number of shares purchasable with their liquidating distributions.
Eligible Purchasers may purchase shares of Common Stock with funds in addition
to their cash distributions in order to purchase the minimum round lot of 100
shares, subject to prorata limitations in the event of oversubscription.
Investors in multiple Partnerships may aggregate their cash distributions to
purchase the minimum round lot. The Common Stock is listed on the New York
Stock Exchange (the "NYSE") and the Pacific Exchange, Inc. (the "Pacific
Exchange") under the symbol "SFY." The price at which the Common Stock offered
hereby will be issued will be the average price of the Common Stock as reported
by the NYSE for the period between ____________ and _____________, 1998. The
closing price on the NYSE for the Common Stock on ________________, 1998, was
$______ per share.
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NEITHER THIS TRANSACTION NOR THESE SECURITIES HAVE BEEN APPROVED OR DISAPPROVED
BY THE SECURITIES AND EXCHANGE COMMISSION (THE "COMMISSION"). THE COMMISSION
HAS NOT PASSED UPON THE FAIRNESS OR MERITS OF THIS TRANSACTION NOR UPON THE
ACCURACY OR ADEQUACY OF THE INFORMATION CONTAINED IN THIS JOINT PROXY
STATEMENT/PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS UNLAWFUL.
The date of this Joint Proxy Statement/Prospectus is _________________, 1998.
<PAGE> 10
AVAILABLE INFORMATION
The Company has filed a Registration Statement on Form S-4 (the
"Registration Statement"), of which this Joint Proxy Statement/Prospectus is a
part, with the Commission under the Securities Act of 1933, as amended (the
"1933 Act"), with respect to the Special Meetings and to the securities offered
hereby. This Joint Proxy Statement/Prospectus does not contain all of the
information set forth in the Registration Statement or the exhibits thereto,
and reference is hereby made to the Registration Statement and related exhibits
for further information. Information herein is qualified in its entirety by
such reference.
The Company and 39 of the Partnerships are subject to the
informational requirements of the Securities Exchange Act of 1934, as amended
(the "1934 Act"), and accordingly file reports, proxy statements and other
information ("Reports") with the Commission. The Registration Statement, the
exhibits thereto and the Reports can be inspected and copied at the public
reference facilities maintained by the Commission at 450 5th Street, N.W., Room
1024, Washington, D.C. 20549, and at the following regional offices of the
Commission: 7 World Trade Center, 13th Floor, New York, New York 10048 and
Northwestern Atrium Center, 500 West Madison Street, Suite 1400, Chicago,
Illinois 60661, at prescribed rates. Reports concerning the Company can also
be inspected at the offices of the NYSE, 20 Broad Street, New York, New York
10005 and the Pacific Exchange, 115 Sansome Street, 8th Floor, San Francisco,
California 94104. In addition, such materials filed electronically by the
Company and the 39 Partnerships with the Commission are available at the
Commission's World Wide Web site at http://www.sec.gov.
INCORPORATION OF CERTAIN INFORMATION BY REFERENCE AND
ATTACHMENT OF INFORMATION HERETO
Included with this Joint Proxy Statement/Prospectus and incorporated
herein by reference are the following documents: (1) the specific
Partnership's Annual Report on Form 10-K for the fiscal year ended December 31,
1997, or for a Partnership not subject to the informational requirements of the
1934 Act, audited financial statements for the years ended December 31, 1997,
1996 and 1995, (2) the specific Partnership's Quarterly Report on Form 10-Q for
the quarter ended June 30, 1998, or for a Partnership not subject to the
informational requirements of the 1934 Act, unaudited financials for the
quarter ended June 30, 1998, and (3) a Partnership Supplement for the specific
Partnership and attached thereto a reserve report for that Partnership,
prepared as of December 31, 1997 and audited by H.J. Gruy and Associates, Inc.,
together with the fair market value estimates for that Partnership by J.R.
Butler & Company and H.J. Gruy & Associates, Inc., and by CIBC Oppenheimer
Corp.
This Joint Proxy Statement/Prospectus also incorporates documents by
reference which are not presented herein or delivered herewith. The following
documents filed by the Company with the Commission are hereby incorporated by
reference into this Joint Proxy Statement/Prospectus: (1) the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1997; (2) the
Company's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30,
1998; (3) the Company's Reports on Form 8-K, filed on June 5 and July 10, 1998;
and (4) the Company's Proxy Statement, dated April 9, 1998. Copies of such
documents are available upon request and without charge from Ms. Betty Tucker,
Investor Relations Department, Swift Energy Company, 16825 Northchase Drive,
Suite 400, Houston, Texas 77060, telephone number (281) 874-2750.
Additionally, documents filed by the Company pursuant to Section
13(a), 13(c), 14 or 15(d) of the 1934 Act subsequent to the date of this Joint
Proxy Statement/Prospectus and prior to the termination of the Offering of the
shares of Common Stock hereunder shall be deemed to be incorporated by
reference in this Joint Proxy Statement/Prospectus and to be a part hereof from
the date of filing of such documents.
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Any statement contained in a document incorporated or deemed to be
incorporated by reference herein shall be deemed to be modified or replaced for
purposes of this Joint Proxy Statement/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
replaces such statement. Any such statement so modified or replaced shall not
be deemed, except as so modified or replaced, to constitute a part of this
Joint Proxy Statement/Prospectus.
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TABLE OF CONTENTS
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SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Proposals to Sell Each Partnership's Oil and Gas Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Liquidation of Partnerships Approving their Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Election to Purchase Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Special Meeting of Investors of the Partnerships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Partnership Property Interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Summary Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Conflicts of Interest and Benefits to the Company. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Background of the Proposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Purpose and Effect of the Proposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Reasons for the Proposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Managing General Partner's Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Special Transaction Committee's Selection of Appraisers to Set Fair Market Value . . . . . . . . . . . . . . . 9
Methodology of Determining Fair Market Value of Partnerships' Oil and Gas Assets . . . . . . . . . . . . . . . 9
Determination of Price to be Paid to Purchase Partnership Property Interests . . . . . . . . . . . . . . . . 10
Summary Partnership Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Fairness of Proposed Sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Alternative Transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Federal Income Tax Consequences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Benefits to the Managing General Partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
No Appraisal or Dissenters' Rights Provided; Investor Lists; Books and Records . . . . . . . . . . . . . . . 19
Consequences of a Partnership not Approving its Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Supplements for Individual Partnerships and Current Reports Included . . . . . . . . . . . . . . . . . . . . 20
Investor Elections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Voting Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Offer to Eligible Purchasers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Comparison of Partnerships and the Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Swift Energy Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Business Strategy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Recent Developments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
SUMMARY HISTORICAL CONSOLIDATED FINANCIAL DATA OF
SWIFT ENERGY COMPANY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
SUMMARY PRO FORMA CONSOLIDATED FINANCIAL DATA OF
SWIFT ENERGY COMPANY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
SUMMARY RESERVES AND PRODUCTION DATA OF
SWIFT ENERGY COMPANY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
SUMMARY HISTORICAL COMBINED FINANCIAL DATA OF THE PARTNERSHIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
RISKS OF THE PROPOSALS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Conflicts of Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
No Fairness Opinion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Lack of Independent Representation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Timing of Sale and Price Volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
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Dependence on Vote of Companion Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Volatility of and Relationship Between Value of Property Interests and Stock Price . . . . . . . . . . . . . 37
Possible Decrease in Distributions to Investors Due to Interim Production . . . . . . . . . . . . . . . . . 37
RISKS OF ELECTING TO TAKE COMMON STOCK . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
Trading Price of Shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
Demand in Market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
Uncertainties at Time of Voting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Change in Nature of Investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Retained Earnings Impact Upon Market Value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Dilution upon Issuance of Shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Risks of Investment in the Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
Volatility of Oil and Gas Prices and Markets; Ceiling Test Writedowns . . . . . . . . . . . . . . . . . . . 39
Leverage and Debt Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Replacement and Expansion of Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
Development and Exploration Risks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
Risks Associated with Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
Future Capital Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
Uncertainty of Estimates of Reserves and Future Net Revenues . . . . . . . . . . . . . . . . . . . . . . . . 42
Operating Hazards and Uninsured Risks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
Effect of Price Risk Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
Foreign Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
Concentration of Credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dependence on Key Personnel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
Governmental and Environmental Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
Year 2000 Issue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
TAX RISKS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
Investors that are Tax Exempt Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
Investors Subject to Federal Income Tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
Payment for Stock with Liquidating Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
SPECIAL FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
Purpose and Effect of the Proposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
Partnership Property Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
Reasons for the Proposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
Independent Appraisal of the Fair Market Value of Property Interests of the Partnerships . . . . . . . . . . 51
Qualifications of Appraisers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
Fair Market Value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53
Valuation by Petroleum Engineering Consultants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
Valuation by CIBC Oppenheimer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
Collective Analysis of Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
Determination of Premium Over Fair Market Value by the Company . . . . . . . . . . . . . . . . . . . . . . . 60
Fairness of Proposed Sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
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FEDERAL INCOME TAX CONSEQUENCES OF ADOPTION OF THE PROPOSALS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
Tax Treatment of Tax Exempt Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64
Tax Treatment of Investors Subject to Federal Income Tax . . . . . . . . . . . . . . . . . . . . . . . . . . 65
Taxable Gain or Loss Upon Sale of Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65
Liquidation of the Partnerships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66
Capital Gains Tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66
Passive Loss Limitations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67
Consideration of Alternative Transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67
COMPARISON OF OWNERSHIP OF UNITS AND SHARES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70
No Unaffiliated Representative or Fairness Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79
Consequences of a Partnership not Approving its Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . 79
Prior Relationships between the Appraisers, the Partnerships and the
Managing General Partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79
Expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79
Source of Funds to Purchase Partnership Property Interests . . . . . . . . . . . . . . . . . . . . . . . . . 80
Managing General Partner Benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80
THE PROPOSALS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
Vote Required . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
Proxies; Revocation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
Solicitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
Simultaneous Proposals to Companion Partnerships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
Steps to Implement the Proposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84
Estimated Selling Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84
Recommendation of the Managing General Partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85
CONFLICTS OF INTEREST . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
Fiduciary Duties of Managing General Partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
Lack of Independent Representation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
Benefits of the Managing General Partner of Undeveloped Reserves . . . . . . . . . . . . . . . . . . . . . . 87
FIDUCIARY RESPONSIBILITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88
Managing General Partner of the Partnerships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88
INVESTOR ELECTION TO PARTICIPATE IN OFFERING OF 2,500,000 SHARES OF COMMON STOCK TO ELIGIBLE PURCHASERS . . . . . . . 89
Investor Election to Purchase Shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89
Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89
Shares Outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89
New York Stock Exchange Listing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89
Closing Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89
Due Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90
Oversubscription . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90
Revocation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90
Offers to Third Parties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90
Method of Purchase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90
MATERIAL FEDERAL INCOME TAX CONSIDERATIONS OF ELECTING TO
RECEIVE COMMON STOCK IN LIEU OF CASH UPON PARTNERSHIP LIQUIDATION . . . . . . . . . . . . . . . . . . . . . . . . . . 92
Payment for Stock with Liquidating Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
Stock Purchase With Cash Liquidating Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
Partners That Are Tax Exempt Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY OF THE COMPANY . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
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CAPITALIZATION OF SWIFT ENERGY COMPANY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95
NOTES TO UNAUDITED PRO FORMA
CONSOLIDATED FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108
SELECTED CONSOLIDATED HISTORICAL FINANCIAL DATA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110
SELECTED HISTORICAL COMBINED FINANCIAL
DATA OF THE PARTNERSHIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112
Results of Operations - Three months ended March 31, 1998 and 1997 . . . . . . . . . . . . . . . . . . . . . 113
Results of Operations - Years ended 1997, 1996 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . 117
Liquidity and Capital Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119
Year 2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121
BUSINESS AND PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122
Business Strategy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122
Recent Developments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124
Exploration and Development Drilling Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126
Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129
Marketing of Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129
Price Risk Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131
Acquisition Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131
Foreign Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131
Oil and Gas Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132
Oil and Gas Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135
Oil and Gas Acreage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135
Partnerships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136
Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136
Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139
Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139
MANAGEMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140
Directors, Executive Officers and Certain Other Officers . . . . . . . . . . . . . . . . . . . . . . . . . . 140
PRINCIPAL SHAREHOLDERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144
DESCRIPTION OF SWIFT ENERGY COMPANY CAPITAL STOCK . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145
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Preferred Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145
Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147
Antitakeover Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147
Transfer Agent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148
LEGAL MATTERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149
EXPERTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149
GLOSSARY OF TERMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150
OTHER BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153
CONSOLIDATED FINANCIAL STATEMENTS OF THE COMPANY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-1
COMBINED FINANCIAL STATEMENTS OF THE PARTNERSHIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-23
THE SONAT PROPERTIES ACQUISITION - HISTORICAL STATEMENTS OF
REVENUES AND DIRECT OPERATING EXPENSES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-34
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SUMMARY
The following summary is qualified in its entirety by, and should be
read in connection with, the more detailed information contained in the
Company's Consolidated Financial Statements, the Partnerships' Combined
Financial Statements, the Sonat Properties Acquisition Historical Statements of
Revenue and Direct Operating Expenses and the related notes thereto set forth
elsewhere or incorporated herein in this Joint Proxy Statement/Prospectus.
References herein to "Swift" or the "Company" include Swift Energy Company and
its subsidiaries unless the context requires otherwise. See "Glossary of
Terms" for definitions of certain oil and gas terms used in this Joint Proxy
Statement/Prospectus. Swift's principal executive offices are located at 16825
Northchase, Suite 400, Houston, Texas 77060, telephone number (281) 874-2700.
PROPOSALS TO SELL EACH PARTNERSHIP'S OIL AND GAS ASSETS
The Company is the Managing General Partner of 63 limited partnerships
formed between 1986 and 1994 to invest in producing oil and gas properties.
Swift is submitting this Joint Proxy Statement/Prospectus to Investors in each
of the 63 individual Partnerships to ask their approval of a Proposal to sell
all of that particular Partnership's oil and gas assets to the Managing General
Partner at a price set by taking the higher of two fair market value estimates
of those assets on a Partnership-by-Partnerships basis determined by three
independent appraisers, H.J. Gruy & Associates, J.R. Butler & Company and CIBC
Oppenheimer Corp. (collectively, the "Appraisers") and adding to that higher
number a 7.5% premium. The total purchase price for all of the oil and gas
assets of all 63 partnerships is approximately $81 million as of December 31,
1997.
See "Special Factors--Background" and "Special Factors--Background and Purpose
of the Proposal" in each Partnership's Specific Partnership Supplement.
LIQUIDATION OF PARTNERSHIPS APPROVING THEIR PROPOSAL
Each Partnership is voting separately on a Proposal. Accordingly, not
all of the 63 Partnerships may choose to sell their oil and gas assets and
dissolve. Investors in each of the 63 Partnerships may vote "FOR" or "AGAINST"
the Proposal being voted upon by their individual Partnership. If the Proposal
is approved by Investors in a Partnership and, if applicable, by its Companion
Partnership, after the sale of substantially all of their properties such
Partnerships, will wind up their businesses and terminate. The Partnerships
will receive cash for their oil and gas assets, which the Investors in the
Partnerships will be entitled to receive as distributions in accordance with
their respective percentage ownership interests in their Partnership. If the
Proposal is rejected by the Investors of a particular Partnership or if a
Companion Partnership does not approve the Proposal, the Partnership will
continue to operate.
See "Special Factors--Purpose and Effect of the Proposals" and "The
Proposals--Simultaneous Proposal to Companion Partnerships" herein.
ELECTION TO PURCHASE COMMON STOCK
Eligible Purchasers can elect, in their sole individual discretion, to
receive shares of Common Stock of the Company instead of some or all of the
cash which they are entitled to receive upon their Partnership's liquidation.
The shares will be sold directly by the Company without any broker commissions.
The minimum number of shares of Common Stock which must be purchased by an
Eligible Purchaser is a round lot of 100 shares. If an Eligible Purchaser has
interests in more than one Partnership, the cash distributions he will be
entitled to receive may be aggregated to meet the minimum round lot of 100
shares requirement. Eligible Purchasers may purchase shares of Common Stock
with funds in addition to the cash distributions which they are entitled to
receive in order to purchase (i) the minimum round lot of 100 shares, or (ii)
shares in addition to the number of shares purchasable with their cash
distributions, subject to prorata limitations in the event of
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oversubscription. The shares of Common Stock of the Company are listed on the
NYSE and the Pacific Exchange under the symbol "SFY" and application will be
made to list the Common Stock being offered to Eligible Purchasers on the NYSE
and the Pacific Exchange. The price at which the Common Stock is offered
hereby to Eligible Purchasers is based upon an average of prices as reported by
the NYSE during a period contemporaneous with completion of voting upon the
Proposals.
See "Investor Election to Participate in Offering of 2,500,000 Shares of Common
Stock to Eligible Purchasers--Investor Election to Purchase Shares" herein and
"Offering of Shares of Swift Energy Company Common Stock of Investors Approve
the Proposal--Offer of Swift Common Stock Investors if the Proposal is
Approved" in each Partnership's specific Partnership Supplement.
SPECIAL MEETING OF INVESTORS OF THE PARTNERSHIPS
This Joint Proxy Statement/Prospectus and the enclosed Proxy are
provided to Investors for use at their specific Partnership's Special Meeting
of Investors and any adjournment or postponement of such meeting. The Special
Meetings are to be held at 16825 Northchase Drive, Suite 400, Houston, Texas at
the time and on the date indicated on the Notice of Special Meeting for each
specific Partnership accompanying this Joint Proxy Statement/Prospectus. These
Special Meetings are called for the purpose of considering and voting upon the
Proposals and to transact such other business as may be properly presented at
the Special Meetings. The Joint Proxy Statement/Prospectus and the enclosed
Proxy are first being mailed to Investors on or about _______ ___, 1998.
See "The Proposals--General" herein and "Voting on the Proposal" in each
Partnership's specific Partnership Supplement.
PARTNERSHIP PROPERTY INTERESTS
The Partnerships' Property Interests consist either of working
interests or non-operating interests in producing oil and gas properties. Of
the 63 Partnerships, 37 Partnerships, sometimes referred to herein as
"Operating Partnerships," were formed to purchase working interests in such
properties. The other 26 Partnerships, sometimes referred to herein as
"Pension Partnerships," were designed for tax-exempt investors and were formed
to purchase non- operating interests in such properties. Pension Partnerships
own a net profits interest that covers multiple working interests owned by an
Operating Partnership, created under a net profits agreement. Such Pension and
Operating Partnerships are sometimes referred to herein as "Companion"
Partnerships. If both of the Companion Partnerships approve their Proposals,
the Pension Partnership will sell its interests in oil and gas assets to its
Companion Operating Partnership, which will immediately thereafter sell such
properties it receives as well as its other oil and gas assets to the Managing
General Partner.
Information regarding the most significant fields in which
Partnerships own Property Interests are set out in detail in each Partnership's
specific Partnership Supplement (as defined) under "The Partnership," including
specific information on those fields in which each Partnership has Property
Interests which constitute 10% or more of the Partnership's PV-10 Value at
December 31, 1997. A Partnership's "PV-10 Value" is the estimated future net
cash flows (using unescalated prices) from production of proved reserves
attributed to such Partnership's Property Interests, discounted to present
value at 10% per annum. See "Glossary of Terms."
See "Special Factors--Property Interests of the Partnership" herein and "The
Partnership" in each Partnership's specific Partnership Supplement.
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SUMMARY RISK FACTORS
o The purchase price to be paid by the Managing General Partner for the
Partnerships' Property Interests may not represent the highest
possible prices that might be received for the Partnerships' Property
Interests in all circumstances. Such prices might be higher (or
lower) if these Property Interests were sold on another basis, such as
at auction or in a negotiated sale. See "Risk Factors--Conflicts of
Interest in Purchase of Property Interests by Managing General
Partner."
o No independent representative was retained on behalf of the Investors
to negotiate the purchase price to be paid by the Managing General
Partner for the Partnerships' Property Interests. Such proposed
purchase prices have not been negotiated at arm's length and are
subject to significant conflicts of interest between the Company
acting both as the purchaser of the Property Interests and as the
Managing General Partner of the Partnerships.
o The fair market values (which does not include the 7.5% premium)
forming the basis of the purchase prices to be paid by the Managing
General Partner for the Partnerships' Property Interests are the
Appraisers' estimation of such values. Year-end 1997 prices, along
with other then-current market factors, were used as a starting point
for the Appraisers' analyses. The Petroleum Engineering Consultants
(as defined) then made the determination to escalate prices and costs
at a rate of 3.5% per year over 15 years. Higher increases in the
prices for oil and gas or lower increases in costs in the future, if
any, might result in Investors receiving higher distributions from
continued operations of the Partnerships than estimated. However, the
effect of any higher prices or lower costs is somewhat limited because
the Partnerships have already produced a substantial majority of their
oil and gas reserves. See "Risk Factors--Timing of Sale and Price
Volatility."
o Although two estimations of the fair market value of the Property
Interests for each Partnership forming the basis for the proposed
purchase price to be paid by the Managing General Partner were
determined by three independent Appraisers, no opinion was acquired as
to the fairness of the entire transaction, including but not limited
to the 7.5% premium over the higher of the two fair market estimations
by the Appraisers. The 7.5% premium was determined in the Managing
General Partner's sole judgment and was not based upon a determination
by an impartial third party. Another party intent upon purchasing the
Property Interests of the Partnerships could have evaluated their
value on a different basis and offered a different purchase price.
o If the Proposals are approved by Investors resulting in the
Partnerships' Property Interests being purchased by the Company, the
Company will likely further develop the Property Interests by spending
additional capital on recovery of behind-pipe reserves or developing
undeveloped reserves. In such event, Investors will not share in any
possible increase in value of such Property Interests as they would
had their Partnership so acted. However, the Company is hereby
concurrently offering to Eligible Purchasers up to 2,500,000 shares of
Common Stock of the Company which they may purchase with the funds
they would otherwise be entitled to receive upon their Partnership's
liquidation so that they might share indirectly in any such increase.
o For the 18 Partnerships formed in the fourth quarter of 1986, the
first three quarters of 1987, and between the fourth quarter of 1992
and the second quarter of 1994, a majority of their proved oil and gas
reserves are non-producing. Because non-producing reserves are
traditionally discounted due to future costs that must be incurred to
recover those reserves and the risk that any drilling will be
unsuccessful, there is a risk that the discount applied to the
non-producing reserves by the Petroleum Engineering Consultants could
be greater than the discount applied by third party purchaser.
Likewise, any drilling conducted on Property Interests acquired from
these
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Partnerships may have upside potential, the benefit of which will go
to the Managing General Partner if it acquires those properties.
o Investors that are not exempt from federal income tax on an investment
in their Partnership are required to recognize gain or loss on the
sale of Property Interests by that Partnership. See "Summary of
Federal income Tax Consequences" in their individual Partnership
Supplements as to whether a particular Partnership's Investors will
have a gain or a loss. To the extent that gain is recognized, such
taxpaying Investors will be required to pay federal income tax. Tax
must be paid even if Investors choose to acquire Common Stock with
some or all of their proceeds from the sales of Property Interests.
Investors should consult their individual tax advisors to determine
whether they are subject to any tax under state law. See "Federal
Income Tax Consequences of Adoption of the Proposals."
o In the event an Investor does not otherwise hold Common Stock but
purchases shares hereunder, such Investor will become a shareholder of
the Company. An investment in the Company fundamentally differs from
an investment in the Partnerships. The Company's business is
different and subject to different risks than the Partnerships and the
Company's results of operations, as well as the price of its Common
Stock, is affected by many factors different than those affecting the
Partnerships' results of operations and the price of the Units.
Additionally, the Company has never paid cash dividends to its
shareholders and does not anticipate doing so in the future, as
opposed to regular quarterly cash distributions having been made to
Investors in the Partnerships. See "Risk Factors--Risks of Electing
to Take Common Stock" and "Comparison of Ownership of Units and
Shares" for further discussion and additional differences and rights
resultant from being a Swift shareholder in contrast to an Investor.
o If a Partnership's Companion Partnership does not approve its
Proposal, it is likely that the Proposals to both Partnerships will be
withdrawn and the value of their Property Interests reassessed.
Although in such event, the Managing General Partner will attempt to
provide a different approach for sale of such Partnerships' Property
Interests, it is possible that such Partnerships' assets may not be
sold. All but ten Partnerships have Companion Partnerships. See "Risk
Factors--Dependence on Vote of Companion Partnership" and, for
additional information including, but not limited to, which
Partnerships do not have companions. See "The
Proposals--Simultaneous Proposal to Companion Partnership."
See "Risk Factors" herein and "Risk Factors" in each Partnership's specific
Partnership Supplement.
CONFLICTS OF INTEREST AND BENEFITS TO THE COMPANY
There are substantial conflicts of interest which exist by virtue of
the Managing General Partner acting in that capacity on behalf of all 63
Partnerships while at the same time also being the proposed purchaser of all of
the Property Interests. Furthermore, the Company proposes to offer Common
Stock to those Investors of Partnerships which, along with their Companion
Partnerships, approve their Proposals. These conflicts of interests are
discussed below. For further information, see "Conflicts of Interest" in this
Joint Proxy Statement/Prospectus and the section "Conflicts of Interest" in the
Supplements for each of the Partnerships.
o If Investors of all of the Partnerships approve the Proposals, the
Company anticipates, when comparing "100% Case" reserve and balance
sheet pro forma information to December 31, 1997 Company historical
data, that its total proved reserves on an equivalent basis will
increase by approximately 26% and its cash flow and total assets will
increase by approximately 25% and
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19%, respectively. Furthermore, the Company intends to invest capital
in DEVELOPING certain of the properties' non-producing reserves
acquired from the Partnerships which approve the sale of their
Property Interests to the Company, depending upon the Company's
assessment of each property's characteristics and upon changes from
time to time in the prices of oil and gas. The Company intends to
profit from a return on the capital used to purchase the Property
Interests and by investing additional capital in their further
development.
o The terms of the Proposals are established by the Company which is
also the Managing General Partner of the Partnerships.
o Neither the Managing General Partner nor a majority of its independent
directors retained an unaffiliated representative to act on behalf of
the Partnerships' Investors for the purposes of negotiating the terms
upon which any such sale to the Managing General Partner would be made
or for the preparation of a report concerning the fairness of such
transaction.
o Benefits accruing to the Company include the following:
o The Company will share in the benefits available to Investors
through liquidating its Partnership interests and receiving
the current value of those interests as a result of such
sales.
o Because of the purchase by the Company of the Partnerships'
Property Interests rather than a third party, the Company will
continue to serve as operator of many of the properties in
which the Partnerships own interests and will continue to
receive operating fees.
See "Conflicts of Interest" herein and "Conflicts of Interest" in each
Partnership's specific Partnership Supplement.
BACKGROUND OF THE PROPOSALS
The Partnerships were formed between 1986 and 1994, with approximately
60% of the Partnerships having been in existence for over 7 years. As
contemplated when the Partnerships were organized, the hydrocarbon production
of the producing properties in which the Partnerships own interests has
steadily declined over time. All of the Partnerships own interests in
properties with substantial natural gas reserves, and many of the Partnerships'
reserves are comprised almost totally of natural gas. The general improvement
in the prices for natural gas over the last several years, relative to such
prices in the mid-1990's, make this an appropriate time, especially in light of
the age of the Partnerships, to consider Proposals to sell their Property
Interests. For the reasons set out below, the Managing General Partner
believes that the Proposals under which it would purchase all of the oil and
gas properties owned by the Partnerships are fair to Investors and are
structured in a manner so as to attempt to realize the highest value for the
Partnerships' Property Interests, given that the purchase prices were derived
by choosing the higher of two estimates on a Partnership-by-Partnership basis
of the fair market value of each of the Partnerships' Property Interests by
three independent Appraisers and adding to that higher number a 7.5% premium.
The purchase of the Property Interests assets of any particular Partnership is
not conditioned upon the purchase of the Property Interests of any Partnership
other than a Partnership's Companion Partnership, if any.
See "Special Factors--Background" herein and "Special Factors--Background and
Purpose of the Proposal" in each Partnership's specific Partnership Supplement.
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PURPOSE AND EFFECT OF THE PROPOSALS
The Proposals are submitted at this time as part of the Managing
General Partner's obligations to manage the business of the Partnerships and
their investments and to address the timely conclusion of the Partnerships'
activities in light of the purposes for which the Partnerships were formed as
well as the anticipated length of their operation. The Managing General
Partner believes that the Proposals are fair to Investors and are structured in
a manner so as to attempt to realize the highest value for the Partnerships'
Property Interests. The Proposals are subject to a number of conflicts of
interest, which are discussed in greater detail below.
See "Special Factors--Purpose and Effect of the Proposals" herein and "Special
Factors--Background and Purpose of the Proposal" in each Partnership's specific
Partnership Supplement.
Approval of the Proposals will have the following effects:
1. The Managing General Partner will ultimately purchase all of the oil
and gas assets of each Partnership and its Companion Partnership, if
any, which approve their respective Proposals;
2. Such Partnerships, having sold all of their Property Interests, will
be required to liquidate and distribute their assets (principally the
cash proceeds from sale of their Property Interests) to their partners
(including the general partners) in accordance with their respective
ownership interests in the Partnerships; and
3. Investors will be given the opportunity to receive shares of Swift
Common Stock in amounts that they choose on an individual basis in
lieu of some or all of the cash they would be entitled to receive upon
their Partnerships' liquidation.
REASONS FOR THE PROPOSALS
THE REASONS FOR PROPOSING THE SALE OF THE PARTNERSHIP'S PROPERTY
INTERESTS AT THIS TIME ARE DESCRIBED IN DETAIL FOR EACH PARTNERSHIP IN THAT
PARTNERSHIP'S SUPPLEMENT INCLUDED WITH THIS JOINT PROXY STATEMENT/PROSPECTUS
UNDER "SPECIAL FACTORS--REASONS FOR THE PROPOSAL," AND VARY FROM PARTNERSHIP TO
PARTNERSHIP DEPENDING UPON, AMONG OTHER FACTORS, THE NATURE OF PROPERTY
INTERESTS WHICH IT OWNS. The Managing General Partner believes that it is in
the best interest of Investors for their Partnerships to sell their Property
Interests at this time and to dissolve the Partnerships and make a final
liquidating distribution to its Partners for the reasons discussed below.
Reasons Common to all Partnerships. The reasons common to all
Partnerships include: (i) the inherent decline in hydrocarbons produced over
time, which leads to decreasing levels of oil and gas revenues and cash flow
from the Partnerships' Property Interests, compounded by the absence of any
further capital expenditures on the properties in which the Partnerships own
Property Interests, which in turn leads to declining cash distributions to
Investors over time, and (ii) the continuation of fairly steady levels of
certain fixed oil field overhead and operating costs, without regard to the
level of production, and continued direct expenses (such as audits, reserve
reports and tax returns) and general and administrative costs incurred each
year. As production quantities and revenues continue to decline, the cost per
Mcfe for production and operating costs constitutes an increasingly larger
percentage of per Mcfe revenues. This increases the risk to the Partnerships
from future price volatility, because the margin between revenue per Mcfe and
production cost per Mcfe continues to narrow, and smaller differences in prices
can consume a larger portion of that margin. By selling their Property
Interests and liquidating the Partnerships, future overhead and direct expenses
and general and administrative costs will be avoided and the receipt of the
value of the Partnerships' reserves accelerated so that such funds are received
at one time. This in turn avoids the risk of subjecting future revenues and
cash distributions of Investors to the continued and
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extreme volatility of oil and gas prices, as well as inherent geological,
engineering and operational risks, which could affect future returns.
Reasons that Differ Among Partnerships. Other factors differ from
Partnership to Partnership:
o Although the amount differs among Partnerships, a majority of
the estimated remaining recoverable reserves of the
Partnerships (other than the 16 Partnerships formed during
1993 and 1994) have been produced. Especially for the 39
Partnerships with less than a third of their estimated
remaining recoverable reserves remaining for future production
(all but two of the Partnerships formed prior to the second
quarter of 1992), any future increases in oil and gas prices
are not likely to have a material positive impact on the
return on investment to Investors in those Partnerships.
Because of steadily declining levels of production, the
Managing General Partner believes that the asset base and
future net revenues of many Partnerships which were formed
between 1986 and 1992 no longer justify the continuation of
the Partnerships' operations, especially when these
Partnerships have been in existence for six to twelve years.
o For those 18 Partnerships formed in the fourth quarter of
1986, in the first three quarters of 1987, and in the period
from the fourth quarter of 1992 through the second quarter of
1994, a majority of the estimated remaining recoverable
reserves attributable to those Partnerships' Property
Interests are proved non-producing reserves. Non-producing
reserves generally fall into two categories: (1) undeveloped
reserves, which require substantial expenditures by the
working interest owners for the drilling of new wells to
recover such reserves; and (2) behind-pipe reserves, which are
unlikely to be producible for many years because behind-pipe
reserves require completion in a different producing zone,
which does not take place until production is depleted from
the currently producing zone.
o The 14 Partnerships (formed between the fourth
quarter of 1992 and the end of the second quarter of
1994) have over a third of their estimated remaining
recoverable reserves in the undeveloped category.
o The 24 Partnerships formed in the fourth quarter of
1986, in the first three quarters of 1987, and in the
first three quarters of 1988, between the fourth
quarter of 1992 and the first quarter of 1993 have an
additional amount of their estimated recoverable
remaining reserves (more than 20%) in the behind pipe
category.
Recovery in amounts great enough to significantly impact the results
of those Partnerships' operations and their ultimate cash distributions can
only occur after currently producing zones are depleted after many years, or
with the investment of new capital. As provided in the Partnership Agreements,
the Partnerships expended all of the Investors' net commitments for the
acquisition of Property Interests many years ago, and they no longer have
capital to invest in improvement of the properties through secondary or
tertiary recovery. Significant amounts of behind-pipe reserves, combined with
the capital expenditures necessary to recover proved undeveloped reserves, has
negatively affected the willingness of third party joint interest owners in
such properties to engage in further development activities. When properties
have large quantities of non-producing reserves, the purchase price an
unrelated third party is willing to pay for these Property Interests is likely
to be heavily discounted. Lastly, sufficient additional capital to drill wells
to produce undeveloped reserves is not available from the Partnerships. The
most important factor leading to the significant proportion of behind-pipe or
undeveloped reserves currently owned by the Partnerships has been the depletion
of most of the Partnerships' proved producing reserves, resulting in the growth
over time in the proportion of the Partnerships' total assets comprised of
non-producing reserves. Thus, non-producing reserves which were a
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small proportion of each Partnership's reserves when its oil and gas assets
were purchased have remained and grown to comprise a larger proportion of the
Partnerships' remaining assets.
A limited amount (less than 10%) of the capital of the Operating
Partnerships was reserved for workover, completion or development activity, the
Partnerships were not intended to engage in material drilling activities. The
Partnerships were formed to distribute cash from sale of Partnership's oil and
gas production to Investors on a current basis. The current level of cash flow
of the Partnerships is not sufficient to pay for meaningful drilling activities
or to support borrowing activities for that purpose. Even if cash flow were
allowed to be used for drilling by a Partnership's limited partnership
agreement, this would require suspension of cash distributions for an extended
period.
The Managing General Partner believes that this is an appropriate time
for the Partnerships to sell their Property Interests due to its perception of
the marketplace, including estimates as to future oil and gas prices, the cash
flow of the Partnerships and the character of their reserves. The Managing
General Partner believes that after significantly depleting producing oil and
gas properties, they become less attractive to prospective purchasers because
of less cash flow. Additionally, the Partnerships' limitations on capital
invested in drilling activities in recent years also makes the Property
Interests less attractive to prospective purchasers. Although the price of oil
has fallen significantly in 1998, gas prices have declined to a lesser degree.
Given the fact that the reserves of the Partnerships and their recent
production consist principally of gas, this is believed to be a good time to
sell Partnership properties to avoid the risk that gas prices might fall to
levels equivalent to those for oil. At the current time the marketplace's
perception is that gas prices are likely to increase. Based upon its
experience in the industry and past historical trends, the Managing General
Partner believes that it is often preferable to sell based upon perceptions of
future prices. Moreover, the sale at this time by any Partnership in
conjunction with the other 62 Partnerships to whom Proposals have been made
allows the costs of the transactions to be spread among a larger number of
entities, which costs are likely to be much higher if such asset sales were
made on an individual Partnership basis or by small groups of Partnerships over
an extended period of time.
MANAGING GENERAL PARTNER'S RECOMMENDATIONS
The Managing General Partner recommends that Investors of each of the
Partnerships vote in favor of their Partnership's Proposal for the reasons
discussed above. However, no recommendation is made by the Managing General
Partner as to whether Investors should elect to take shares of Common Stock in
lieu of cash for their interest in the distributions. The Managing General
Partner believes the terms of the Proposals are fair to Investors. See
"Fairness of Proposed Sale" below, "Special Factors--Background" and
"--Fairness of the Proposed Sale" in each Partnership's specific Partnership
Supplement for the Managing General Partner's assessment of the fairness of the
Proposals.
This recommendation should be evaluated in light of the significant
conflicts of interest which exist by virtue of the Managing General Partner's
fiduciary obligations to the Investors in the Partnerships, and acting as the
purchaser of these Partnerships' oil and gas assets. Additionally, the general
partners (the Managing General Partner and the Special General Partner) own
either a 10% or 15% interest as general partners in each of the Partnerships,
and the Managing General Partner owns between a 0% and 23.4% interest (an
average interest of 4.1%) in the Partnerships as a limited partner. Although
the Managing General Partner has attempted to address these conflicts of
interest through the factors discussed under "Fairness of the Proposals" below,
the Managing General Partner's recommendation to Investors in voting upon the
Proposals should be evaluated in light of these significant existing conflicts
of interest.
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SPECIAL TRANSACTION COMMITTEE'S SELECTION OF APPRAISERS TO SET FAIR MARKET VALUE
The Proposals to ultimately sell substantially all of the
Partnerships' Property Interests to the Managing General Partner are discussed
in detail under "The Proposals" and "Special Factors" herein. The Proposals
present significant conflicts of interest between the Company acting in its
capacity as Managing General Partner of the Partnerships and its actions in its
corporate capacity as the proposed purchaser of the Partnerships' Property
Interests. See "Risk Factors--Conflicts of Interest" herein and "Conflicts of
Interest" in each Partnership's specific Partnership Supplement. The Special
Transactions Committee of the Board of Directors of the Company (the "Special
Transactions Committee"), which consists solely of four of the five outside
independent directors of the Company, approved the selection of the Appraisers.
The Special Transactions Committee determined that such conflicts of interest
were best addressed by asking three independent Appraisers, consisting of two
petroleum engineering firms and one investment banking firm, to estimate the
fair market values of the Partnerships' Property Interests, rather than
proposing that the Managing General Partner set such fair market values itself
and asking for an opinion on the fairness thereof from an independent third
party.
The Appraisers were selected based upon the Special Transactions
Committee's assessment of their professional reputations and qualifications,
capabilities, experience and responsiveness. The Special Transactions
Committee believes that using three Appraisers working collectively provides
the distinct professional expertise of each firm, and gives the Partnerships
the benefit of the independent analytic methods of the different disciplines of
petroleum engineering and investment banking, resulting in a determination of
fair market values which are both independent and comprehensive, and thereby
protects Investors by addressing the potential conflict of interest in the sale
of such Property Interests to the Managing General Partner.
The methodology used by the Appraisers in estimating the fair market
values is discussed below under "Special Factors--Independent Appraisal of the
Fair Market Values of Property Interests of the Partnerships" herein. The
Managing General Partner believes that using this methodology to estimate the
fair market values at which the Property Interests will be purchased from the
Partnerships is fair to Investors, as discussed in detail under "Special
Factors--Fairness of Proposed Sale" herein and "Special Factors--Fairness of
Proposed Sale" in each specific Partnership Supplement. Also discussed under
"Special Factors--Reasons for the Proposals" herein in each Partnership's
specific Partnership Supplement are the reasons for proposing the sale of such
Property Interests and liquidation of the Partnerships at this time. A
discussion of the alternatives to such sales and liquidations which were
considered is contained under "Special Factors--Consideration of Alternative
Transactions" herein. In addition to the foregoing, there are certain risks
involved in the Proposals. See "--Risks" below, "Risk Factors" herein and
"Risk Factors" in each Partnership's specific Partnership Supplement.
METHODOLOGY OF DETERMINING FAIR MARKET VALUE OF PARTNERSHIPS' OIL AND GAS ASSETS
The Managing General Partner did not instruct the Appraisers as to
pricing, cost or other economic parameters or methods, or the assessment of
reserves characteristics, nor did it limit the scope of their investigation for
purposes of preparing their appraisals. The Managing General Partner provided
the petroleum engineering firms with basic evaluation data for their use in
determining Partnerships' reserves and their value. The petroleum engineering
firms prepared their own reserves audit of the Property Interests. The
Managing General Partner did not direct the Appraisers as to the amount of
consideration to be paid to the Partnerships for their Property Interests nor
provide any information to the Appraisers on amounts to be paid to Investors.
The amount of consideration to be paid was determined by the Company's Board of
Directors based upon the Appraisers' estimates of the fair market value of
those interests. The Appraisers did not opine on the fairness of the
transaction to Investors, and the Managing General Partner has not acquired a
separate report or opinion regarding the fairness to Investors of the price at
which the
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Partnerships' Property Interests will be sold to the Managing General Partner
if the Proposals are approved by Investors.
The petroleum engineering firms individually audited the estimate of
present value of future net cash flows from the 44 property groups in which
Property Interests are owned by the Partnerships. The petroleum engineering
firms began their analysis based upon the year-end 1997 PV-10 Value of each
property audited by H.J. Gruy and together they re-evaluated reserve
quantities, projected operating costs and cash flows. The present value of
this reserves analysis was then derived by escalating year-end 1997 prices
($2.38 per MMBtu and $16.00 per barrel before adjustments for Btu content for
gas and gravity variances for oil as well as transportation charges and
geographic location) and costs by 3.5% per year for 15 years. This present
value was then adjusted for various individual field risks and risk adjustments
of proved non-producing reserves, proved undeveloped reserves and identified
probable and possible reserves. The result of this collective analysis by the
petroleum engineering firms was their estimation of the fair market value of
each of the property groups in which Property Interests are owned by the
Partnerships as of December 31, 1997.
CIBC Oppenheimer's evaluation of each Partnership's Property Interests
began with the PV-10 Value of each property group, as calculated by the Company
and audited by Gruy. CIBC Oppenheimer then divided the property groups into
two categories. Those property groups with reserves consisting primarily of
proved developed producing reserves were placed in the "Conventional Case"
category. Those property groups with significant proved developed
non-producing or undeveloped reserves were placed in the "Non-Conventional
Case" category. CIBC Oppenheimer then valued each property group by applying
the multiples discussed below under "Independent Appraisal of the Fair Market
Value of Property Interests of the Partnerships--Valuation by CIBC Oppenheimer"
to each property group's PV-10 Value, proved reserves on a BOE basis, and
projected 1998 EBIDTA. A separate set of multiples was used for property
groups in the Conventional Case category and the Non-Conventional Case
category, respectively. This provided CIBC Oppenheimer with three estimated
values for each property group. The average of these three values yielded CIBC
Oppenheimer's estimation of the fair market value of each property group. CIBC
Oppenheimer then allocated the appropriate portion of the property group's
estimated fair market value to the Partnership based upon the Partnership's
Property Interest in each property group. The result of this analysis by CIBC
Oppenheimer was its estimation of fair market value of each Partnership's
Property Interests as of December 31, 1997.
See "Specific Factors--Fair Market Value," "--Independent Appraisal of the Fair
Market Value of Property Interests of the Partnerships" herein.
DETERMINATION OF PRICE TO BE PAID TO PURCHASE PARTNERSHIP PROPERTY INTERESTS
Choice of Higher of Two Appraisals: The Special Transactions
Committee of the Swift Board of Directors determined that, in keeping with the
definition of Fair Market Value (see "Glossary of Terms"), the higher of these
two estimations on a Partnership-by-Partnership basis of fair market value
represents the Fair Market Value of each Partnership's Property Interests which
are set out for each Partnership in its specific Supplement. Accordingly, the
fair market value estimation of the Petroleum Consulting Engineers and the fair
market value determined by CIBC Oppenheimer were compared to each other and the
higher of the two for each Partnership was chosen as the Fair Market Value of
each Partnership's Property Interests.
Decision to Add 7.5% Premium. The Company determined that paying a
7.5% premium over the appraised fair market value of the Partnerships' Property
Interests was appropriate and fair based upon the factors and for the reasons
discussed herein. The amount of the premium principally was based upon
10
<PAGE> 27
management's experience in purchasing properties which contain both producing
reserves and drilling potential. Because the Managing General Partner has
served in that capacity on behalf of all of the Partnerships for a number of
years, it is intimately familiar with the Property Interests owned by each of
the Partnerships. The Managing General believes that if the Property Interests
were to be sold to a third party purchaser who was not equally familiar with
those interests, it is likely that the purchaser would discount the purchase
price to account for that lack of familiarity and perceived potential risks.
If these interests are purchased by the Company, then the additional cost and
personnel often inherent in making a property acquisition are not required.
Since 1979, the Company, on behalf of itself and others, has gained a wide
range of experience with the valuation of oil and gas properties and the prices
for their purchase and sale, having purchased $478 million of such properties
in 129 separate transactions. In the judgment of the Company, the purchase of
any Partnership's Property Interests, together with interests in many of the
same properties owned by other Partnerships at approximately the same time,
will result in efficiencies to the Company in aggregating such interests.
Swift's long-term knowledge of the risks involved in these properties means
that it is in a better position to evaluate these risks than third parties.
No attempt was made to distinguish between the Property Interests
owned by any particular Partnership, nor was any statistical or analytical
study prepared by the Company on a separate basis in the course of determining
the amount of this premium.
Other purchasers might have determined it inappropriate to pay a
premium, or if so, to pay a premium based upon other factors or in a different
amount. Because there has been no independent determination to pay this
premium or of its amount, and no fairness opinion has been requested regarding
this premium, conflicts of interest existing in its determination, although the
Managing General Partner believes, based upon its knowledge of the oil and gas
industry, its knowledge of the properties involved, its experience in
purchasing and selling oil and gas properties, and the benefits from purchasing
the Property Interests which are particular to the Company, that the amount
being offered to the Partnerships to purchase their Property Interests is fair.
Amounts to be Paid to Investors Upon Liquidation of their
Partnerships. The evaluation of the fair market values of the Property
Interests of the Partnerships were based upon values as of December 31, 1997,
including the fair market value estimates by the Petroleum Engineering
Consultants (using pricing assumptions and reserve quantities at that time)
which were in turn based upon the audit of each of the Partnerships' total
proved reserves at that date by H.J. Gruy. As is the case with all oil and gas
purchases, the purchase is proposed to be made as of the date which the
properties were evaluated (in this case January 1, 1998). Obviously, the
quantities of reserves being purchased are reduced by production which takes
place after the evaluation date (net of the lease operating cost incurred to
produce such reserves) but before the purchase takes place.
Therefore, the actual purchase price to be paid to each Partnership
for its oil and gas assets is the purchase price set out in the table contained
in the Summary and the individual Partnership Supplement for each Partnership,
reduced by the net revenues that have been received by that Partnership for
production during 1998. Money received by each Partnership from the sale of
such production during 1998 has been paid to such Partnership. The
Partnerships have continued to make quarterly cash distributions during 1998.
A portion of 1998 revenues, therefore, have already been distributed to their
partners during 1998 and the remainder of revenues from 1998 production will be
distributed as part of that Partnership's liquidating distribution.
Portion of Purchase Price Payable to the Managing General Partner.
The total purchase price for the oil and gas assets of all 63 Partnerships is
approximately $81 million. Of this amount, approximately $14 million
represents the portion of the purchase price which is payable to the Managing
General Partner by virtue
11
<PAGE> 28
of the Managing General Partner's interest in the Partnerships. Approximately
$11 million of this is attributable to its interests as a general partner and
$3 million attributable to the units which it has purchased under the right of
presentment set out in the various Partnership Agreements. Therefore, the
amount payable to purchase all of the oil and gas assets of all 63
Partnerships, net of the amount distributable to the Managing General Partner
itself upon liquidation of the Partnerships, is approximately $67 million as of
December 31, 1997 before any reduction for 1998 production.
See "Special Factors--Collective Analysis of Purchase Price" and "Special
Factors--Determination of Premium Over Fair market Value by the Company" and
"Special Factors--Proposed Purchase Price," and "Special Factors--Determination
of Premium Over Fair Market Value by the Company" in each Partnership's
specific Partnership Supplement.
SUMMARY PARTNERSHIP INFORMATION
The Partnerships include four series of Partnerships (two that own
working interests and two that own non- operating interests) formed between
1986 and 1994 under five publicly offered limited Partnership programs under
which partnerships were formed to acquire interests in producing properties.
Under the earliest of the programs, Swift Energy Income Partners ("SEIP"), 24
Partnerships were formed, all of which own working interests. These
Partnerships were formed between the fourth quarter of 1986 and the second
quarter of 1990. Commencing in 1988, 13 Partnerships were formed under the
Swift Energy Managed Pension Assets Partnership program ("SEMPAP"), all of
which Partnerships owned non-operating interests in properties in which the
working interest is held in Partnerships formed under the SEIP program.
Commencing in the fourth quarter of 1991, 26 Partnerships were formed under the
Swift Depositary Interests offering. One-half (13) of these Partnerships were
formed to purchase working interests as Swift Energy Operating Partners
("SEOP") partnerships. The remaining 13 Partnerships were formed as Swift
Energy Pension Partners ("SEPP") solely to acquire non-operating interests
(principally net profits interests) in the properties in which the SEOP
Partnerships own the working interests.
Presented on the following two pages is summary information regarding
each of the 63 Partnerships to which Proposals are being submitted under this
Joint Proxy Statement/Prospectus. A separate Proposal is being submitted to
the Investors in each of the Partnerships for their respective approval or
rejection. If the Investors in a particular Partnership vote to reject their
Proposal, then that Partnership will continue its operations. A vote to reject
the Proposal by a Partnership may adversely affect its Companion Partnership,
if it has a Companion Partnership. Information is being presented to allow
Investors to evaluate the total assets of each Partnership at year-end 1997 and
the PV-10 Value of each Partnership's total proved reserves at the same date,
and compares the value of each Partnership's assets (using the proposed
purchase price of each Partnership's Property Interests) to the total assets of
the Company and the PV-10 Value of the Company's total proved reserves at the
same date. The amounts shown for liquidating distributions include
distribution of a Partnership's cash on hand after collection of receivables
and payment of all liabilities, and thus these amounts differ from the purchase
price of a Partnership's Property Interests.
If all of the Partnerships approve the Proposals, the Property
Interests which would be purchased by the Company would consist of interests in
over 1,200 gross wells covering 93 fields in seven states. The
Company-operated properties comprise a majority of the PV-10 Value of all such
Property Interests which would be acquired. In the aggregate, if all of the
interests are acquired, it would increase the Company's total proved reserves
at December 31, 1997, by approximately 26%. These properties are principally
gas, with 73% of the December 31, 1997 reserve volumes and 69% of 1997
production attributable to these properties comprised of natural gas. Among
these properties, the principal properties to be acquired are located in the
states of Texas, Oklahoma and Louisiana. The only three fields which
12
<PAGE> 29
would comprise more than 10% of the aggregate of all Property Interests to be
acquired if all the Proposals are approved (based upon their PV-10 Value at
December 31, 1997) are the following:
The Weatherford Area in the Anardarko Basin in Caddo and Custer
Counties of Oklahoma includes the Weatherford and Eakly Fields. These two
fields include 108 wells, 40 operated by Swift, producing from the Red Fork
and Springer formations with over 93% of the total proved reserves as of
December 31, 1997 comprised of natural gas. Interests in these fields were
first acquired in 1989. The Partnerships' aggregate Property Interests in
these fields account for approximately 18.5% of the total Partnerships'
PV-10 Value and 5.58% of the Company's PV-10 Value at year-end 1997. The
Company holds no direct working interest in these properties.
The AWP Field is located in McMullen County in South Texas. The
properties to be acquired include interest in 96 wells, all operated by
Swift, producing from the tight-sand Olmos formation, with over 80% of the
total proved reserves at December 31, 1997 comprised of natural gas. These
properties were first acquired in 1988. The Partnerships' aggregate
Property Interests in these fields account for approximately 13.1% of the
total Partnerships' PV-10 Value and 3.96% of the Company's PV-10 Value at
year-end 1997. The Company owns between a 47% and 75% direct working
interest in the AWP wells in which the Partnerships own an interest, as
well as up to a 100% working interest in other wells in the AWP Field,
which is the Company's most significant property.
The Second Bayou Field is located in Cameron Parish, Louisiana. The
properties to be acquired include interest in 28 wells, all operated by
Fina Oil and Chemical Company. This field has a substantial amount of
behind-pipe and undeveloped reserves from multiple pay zones, which is
common for South Louisiana production. Over 90% of the total proved
reserves of this field at December 31, 1997 were comprised of natural gas.
These properties were first acquired in 1993. The Partnerships' aggregate
Property Interests in these fields account for approximately 11.3% of the
total Partnerships' PV-10 Value and 3.41% of the Company's PV-10 Value at
year- end 1997. The Company owns between a 3% and 7% direct working
interest in these properties.
13
<PAGE> 30
SUMMARY PARTNERSHIP INFORMATION(a)
<TABLE>
<CAPTION>
PERCENTAGE OF GAS(b)
---------------------------
YEARS SINCE COMPANION NO. OF NO. OF TOTAL ASSETS PV-10 VALUE 1997 12/31/97
PARTNERSHIP NAME INCEPTION PARTNERSHIP WELLS FIELDS 12/31/97 12/31/97 PRODUCTION RESERVE AMTS
---------------- ----------- ----------- ------ ------ ------------ ------------ ----------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
SWIFT ENERGY INCOME PARTNERS ("SEIP")
(24 Partnerships -- All operating partnerships)
SEIP 1986-D........ 11 -- 128 6 $ 2,519,671 $ 2,327,011 78% 81%
SEIP 1987-A........ 11 -- 157 10 2,924,868 2,817,686 74% 79%
SEIP 1987-B........ 11 -- 187 14 4,390,459 3,949,746 80% 83%
SEIP 1987-C........ 10 -- 158 10 2,968,685 2,731,738 85% 85%
SEIP 1987-D........ 10 -- 284 20 2,087,397 1,648,735 80% 80%
SEIP 1988-A........ 10 -- 274 18 1,632,237 1,448,565 84% 82%
SEIP 1988-B........ 10 SEMPAP 1988-A 280 21 1,035,904 895,773 87% 89%
SEIP 1988-C........ 9 SEMPAP 1988-B 632 29 852,696 983,661 85% 86%
SEIP 1988-D........ 9 SEMPAP 1988-C 535 22 994,832 1,269,413 77% 79%
SEIP 1989-A........ 9 SEMPAP 1989-A 801 37 2,395,343 2,557,309 46% 56%
SEIP 1989-B........ 9 SEMPAP 1989-B 643 34 3,871,732 4,009,417 50% 60%
SEIP 1989-C........ 8 SEMPAP 1989-C 367 20 1,067,405 993,485 51% 55%
SEIP 1989-D........ 8 SEMPAP 1989-D 263 21 1,060,246 1,392,883 59% 69%
SEIP 1990-A........ 8 SEMPAP 1990-A 224 18 2,325,842 2,657,236 91% 91%
SEIP 1990-B........ 8 SEMPAP 1990-B 224 18 1,320,209 1,690,766 90% 91%
SEIP 1988-1........ 10 SEMPAP 1988-1 200 14 272,690 201,163 93% 93%
SEIP 1988-2........ 9 SEMPAP 1988-2 471 17 422,150 428,295 75% 78%
SEIP 1988-3........ 9 SEMPAP 1988-2 500 21 637,001 624,152 70% 74%
SEIP 1989-1........ 9 -- 656 26 796,382 823,195 48% 60%
SEIP 1989-2........ 9 SEMPAP 1989-1 643 34 1,745,795 1,779,114 51% 61%
SEIP 1989-3........ 8 SEMPAP 1989-2 367 20 555,380 544,207 53% 58%
SEIP 1989-4........ 8 -- 263 21 407,441 520,349 60% 69%
SEIP 1990-1........ 8 -- 224 18 598,658 684,917 91% 91%
SEIP 1990-2........ 8 -- 224 18 394,877 494,088 90% 91%
SWIFT ENERGY MANAGED PENSION ASSETS PARTNERSHIPS ("SEMPAP")
(13 Partnerships -- All non-operating partnerships)
SEMPAP 1988-A...... 10 SEIP 1988-B 200 14 480,570 484,519 93% 92%
SEMPAP 1988-B...... 9 SEIP 1988-C 552 22 439,044 602,813 89% 88%
SEMPAP 1988-C...... 9 SEIP 1988-D 484 19 310,901 399,008 77% 79%
SEMPAP 1989-A...... 9 SEIP 1989-A 772 33 894,877 1,024,373 50% 60%
SEMPAP 1989-B...... 9 SEIP 1989-B 614 30 1,604,592 1,859,102 54% 63%
SEMPAP 1989-C...... 8 SEIP 1989-C 338 16 642,552 611,918 55% 59%
SEMPAP 1989-D...... 8 SEIP 1989-D 263 21 566,447 770,968 59% 69%
SEMPAP 1990-A...... 8 SEIP 1990-A 224 18 1,469,780 1,888,635 91% 91%
SEMPAP 1990-B...... 8 SEIP 1990-B 224 18 1,042,830 1,455,668 90% 91%
SEMPAP 1988-1...... 9 SEIP 1988-1 200 14 248,171 191,265 93% 92%
SEIP 88-1 &
SEMPAP 1988-2...... 9 88-3 363 10 551,123 517,404 67% 72%
SEMPAP 1989-1...... 9 SEIP 1989-2 614 30 1,369,124 1,544,890 55% 63%
SEMPAP 1989-2...... 8 SEIP 1989-3 338 16 339,803 390,195 56% 61%
SWIFT ENERGY OPERATING PARTNERS ("SEOP")
(13 Partnerships -- All operating partnerships)
SEOP 1991-C........ 6 SEPP 1991-C 427 21 1,836,041 2,117,830 63% 66%
SEOP 1992-A........ 6 SEPP 1992-A 315 18 1,563,796 1,430,194 75% 92%
SEOP 1992-B........ 6 SEPP 1992-B 315 18 3,205,916 3,357,192 85% 93%
SEOP 1992-C........ 5 SEPP 1992-C 472 31 4,624,022 4,484,201 78% 82%
SEOP 1992-D........ 5 SEPP 1992-D 226 20 1,888,378 1,782,087 69% 78%
SEOP 1993-A........ 5 SEPP 1993-A 245 25 2,634,456 2,619,770 67% 72%
SEOP 1993-B........ 5 SEPP 1993-B 245 25 3,999,299 3,162,357 60% 59%
SEOP 1993-C........ 4 SEPP 1993-C 245 25 2,801,251 2,368,261 63% 65%
SEOP 1993-D........ 4 SEPP 1993-D 133 18 2,448,298 2,447,617 71% 63%
SEOP 1994-A........ 4 SEPP 1994-A 174 20 2,826,830 2,666,567 59% 63%
SEOP 1994-B........ 4 SEPP 1994-B 174 20 3,604,339 3,566,231 64% 63%
SEOP 1994-C........ 3 SEPP 1994-C 227 23 3,498,954 3,352,411 47% 63%
SEOP 1994-D........ 3 SEPP 1994-D 128 7 3,617,365 3,083,256 60% 65%
SWIFT ENERGY PENSION PARTNERS ("SEPP")
(13 Partnerships -- All non-operating partnerships)
SEPP 1991-C........ 6 SEOP 1991-C 427 21 1,379,021 1,742,627 63% 66%
SEPP 1992-A........ 6 SEOP 1992-A 315 18 1,166,675 1,286,221 75% 92%
SEPP 1992-B........ 6 SEOP 1992-B 315 18 1,539,916 1,968,944 85% 93%
SEPP 1992-C........ 5 SEOP 1992-C 472 31 2,156,190 2,400,896 78% 82%
SEPP 1992-D........ 5 SEOP 1992-D 226 20 2,302,132 2,263,118 69% 78%
SEPP 1993-A........ 5 SEOP 1993-A 245 25 2,288,079 2,332,948 67% 72%
SEPP 1993-B........ 5 SEOP 1993-B 245 25 2,472,675 2,048,682 60% 59%
SEPP 1993-C........ 4 SEOP 1993-C 245 25 1,902,998 1,674,959 63% 65%
SEPP 1993-D........ 4 SEOP 1993-D 133 18 1,434,890 1,516,278 71% 63%
SEPP 1994-A........ 4 SEOP 1994-A 174 20 1,634,500 1,578,850 59% 63%
SEPP 1994-B........ 4 SEOP 1994-B 174 20 2,240,827 2,261,965 64% 63%
SEPP 1994-C........ 3 SEOP 1994-C 227 23 1,833,917 1,820,780 47% 63%
SEPP 1994-D........ 3 SEOP 1994-D 128 7 2,237,066 1,957,390 60% 65%
------------ ------------ --- ---
$110,375,545 $110,505,294 69% 73%
============ ============ === ===
<CAPTION>
PERCENTAGE OF
NON-PRODUCING
PARTNERSHIP NAME RESERVES 12/31/97
---------------- -----------------
<S> <C>
SWIFT ENERGY INCOME PARTNERS ("SEIP")
(24 Partnerships -- All operating partnerships)
SEIP 1986-D........ 66%
SEIP 1987-A........ 67%
SEIP 1987-B........ 56%
SEIP 1987-C........ 57%
SEIP 1987-D........ 26%
SEIP 1988-A........ 27%
SEIP 1988-B........ 30%
SEIP 1988-C........ 26%
SEIP 1988-D........ 25%
SEIP 1989-A........ 16%
SEIP 1989-B........ 17%
SEIP 1989-C........ 19%
SEIP 1989-D........ 23%
SEIP 1990-A........ 32%
SEIP 1990-B........ 30%
SEIP 1988-1........ 31%
SEIP 1988-2........ 23%
SEIP 1988-3........ 21%
SEIP 1989-1........ 17%
SEIP 1989-2........ 18%
SEIP 1989-3........ 20%
SEIP 1989-4........ 24%
SEIP 1990-1........ 32%
SEIP 1990-2........ 30%
SWIFT ENERGY MANAGED PENSION ASSETS PARTNERSHIPS ("SEMPAP")
(13 Partnerships -- All non-operating partnerships)
SEMPAP 1988-A...... 34%
SEMPAP 1988-B...... 29%
SEMPAP 1988-C...... 26%
SEMPAP 1989-A...... 18%
SEMPAP 1989-B...... 19%
SEMPAP 1989-C...... 21%
SEMPAP 1989-D...... 23%
SEMPAP 1990-A...... 32%
SEMPAP 1990-B...... 30%
SEMPAP 1988-1...... 34%
SEMPAP 1988-2...... 19%
SEMPAP 1989-1...... 19%
SEMPAP 1989-2...... 22%
SWIFT ENERGY OPERATING PARTNERS ("SEOP")
(13 Partnerships -- All operating partnerships)
SEOP 1991-C........ 13%
SEOP 1992-A........ 33%
SEOP 1992-B........ 33%
SEOP 1992-C........ 30%
SEOP 1992-D........ 71%
SEOP 1993-A........ 73%
SEOP 1993-B........ 59%
SEOP 1993-C........ 65%
SEOP 1993-D........ 69%
SEOP 1994-A........ 48%
SEOP 1994-B........ 55%
SEOP 1994-C........ 25%
SEOP 1994-D........ 19%
SWIFT ENERGY PENSION PARTNERS ("SEPP")
(13 Partnerships -- All non-operating partnerships)
SEPP 1991-C........ 13%
SEPP 1992-A........ 33%
SEPP 1992-B........ 33%
SEPP 1992-C........ 31%
SEPP 1992-D........ 70%
SEPP 1993-A........ 73%
SEPP 1993-B........ 59%
SEPP 1993-C........ 65%
SEPP 1993-D........ 69%
SEPP 1994-A........ 48%
SEPP 1994-B........ 55%
SEPP 1994-C........ 25%
SEPP 1994-D........ 19%
---
39%
===
</TABLE>
14
<PAGE> 31
SUMMARY PARTNERSHIP INFORMATION(a)
<TABLE>
<CAPTION>
ENGINEERING FIRMS
ESTIMATED CIBC OPPENHEIMER FAIR MARKET
1998 CASH LIQUIDATING FAIR MARKET VALUE VALUE FAIR MARKET
PARTNERSHIP NAME DISTRIBUTIONS(C) DISTRIBUTION(D) ESTIMATE ESTIMATE VALUE(E)
---------------- ---------------- --------------- ----------------- ----------------- -----------
<S> <C> <C> <C> <C> <C>
SWIFT ENERGY INCOME PARTNERS ("SEIP")
(24 Partnerships -- All operating partnerships)
SEIP 1986-D................ $ 175,640 $ 1,691,807 $ 1,369,233 $ 1,567,013 $ 1,567,013
SEIP 1987-A................ 192,634 1,946,673 1,633,293 1,891,557 1,891,557
SEIP 1987-B................ 441,905 2,556,938 2,300,789 2,487,048 2,487,048
SEIP 1987-C................ 319,632 1,777,553 1,509,772 1,648,082 1,648,082
SEIP 1987-D................ 260,873 1,495,861 1,133,246 1,139,378 1,139,378
SEIP 1988-A................ 206,080 1,138,374 973,233 991,898 991,898
SEIP 1988-B................ 122,404 793,754 647,934 654,752 654,752
SEIP 1988-C................ 112,497 741,628 715,596 715,415 715,596
SEIP 1988-D................ 163,404 954,556 912,565 964,529 964,529
SEIP 1989-A................ 501,952 1,841,991 1,926,262 1,924,455 1,926,262
SEIP 1989-B................ 763,665 3,146,801 3,028,036 3,083,309 3,083,309
SEIP 1989-C................ 263,508 907,224 700,816 707,621 707,621
SEIP 1989-D................ 156,465 1,069,395 1,011,026 1,077,886 1,077,886
SEIP 1990-A................ 460,409 2,195,043 1,770,035 1,930,359 1,930,359
SEIP 1990-B................ 254,614 1,300,744 1,124,167 1,232,438 1,232,438
SEIP 1988-1................ 31,576 226,630 146,639 145,331 146,639
SEIP 1988-2................ 53,654 404,717 321,722 344,363 344,363
SEIP 1988-3................ 83,821 583,491 473,711 503,103 503,103
SEIP 1989-1................ 149,746 575,265 604,515 610,895 610,895
SEIP 1989-2................ 361,423 1,404,468 1,338,435 1,366,070 1,366,070
SEIP 1989-3................ 131,539 480,065 377,256 388,917 388,917
SEIP 1989-4................ 58,565 379,113 367,510 391,776 391,776
SEIP 1990-1................ 118,469 566,839 456,496 497,826 497,826
SEIP 1990-2................ 75,268 387,593 326,379 357,814 357,814
SWIFT ENERGY MANAGED PENSION ASSETS PARTNERSHIPS ("SEMPAP")
(13 Partnerships -- All non-operating partnerships)
SEMPAP 1988-A.............. 77,204 367,219 347,204 342,030 347,204
SEMPAP 1988-B.............. 69,698 411,721 436,930 428,888 436,930
SEMPAP 1988-C.............. 49,876 307,834 290,891 297,515 297,515
SEMPAP 1989-A.............. 222,575 681,940 758,786 763,835 763,835
SEMPAP 1989-B.............. 393,333 1,296,417 1,382,913 1,419,895 1,419,895
SEMPAP 1989-C.............. 164,095 601,145 420,342 428,967 428,967
SEMPAP 1989-D.............. 90,686 627,530 558,871 596,024 596,024
SEMPAP 1990-A.............. 343,418 1,606,640 1,260,871 1,375,076 1,375,076
SEMPAP 1990-B.............. 236,907 1,179,094 965,293 1,058,264 1,058,264
SEMPAP 1988-1.............. 31,091 200,600 137,862 137,089 137,862
SEMPAP 1988-2.............. 66,004 507,499 387,188 413,823 413,823
SEMPAP 1989-1.............. 298,633 1,152,355 1,149,841 1,180,670 1,180,670
SEMPAP 1989-2.............. 91,831 326,820 265,714 276,138 276,138
SWIFT ENERGY OPERATING PARTNERS ("SEOP")
(13 Partnerships -- All operating partnerships)
SEOP 1991-C................ 251,749 1,525,351 1,508,176 1,617,489 1,617,489
SEOP 1992-A................ 288,051 779,579 908,932 961,599 961,599
SEOP 1992-B................ 577,428 1,937,761 2,118,171 2,257,441 2,257,441
SEOP 1992-C................ 777,343 3,000,613 3,025,691 3,097,269 3,097,269
SEOP 1992-D................ 196,192 1,027,779 993,575 1,025,173 1,025,173
SEOP 1993-A................ 248,940 1,434,683 1,470,188 1,456,092 1,470,188
SEOP 1993-B................ 478,409 2,305,815 2,049,580 1,905,857 2,049,580
SEOP 1993-C................ 310,853 1,512,412 1,447,987 1,389,251 1,447,987
SEOP 1993-D................ 259,888 1,375,138 1,467,493 1,421,415 1,467,493
SEOP 1994-A................ 224,279 1,587,809 1,725,946 1,541,759 1,725,946
SEOP 1994-B................ 305,102 2,096,747 2,287,464 2,040,891 2,287,464
SEOP 1994-C................ 272,867 2,159,720 2,246,106 2,103,263 2,246,106
SEOP 1994-D................ 347,569 2,410,994 2,158,881 2,080,309 2,158,881
SWIFT ENERGY PENSION PARTNERS ("SEPP")
(13 Partnerships -- All non-operating partnerships)
SEPP 1991-C................ 207,060 1,257,979 1,240,975 1,330,920 1,330,920
SEPP 1992-A................ 259,055 837,262 817,439 864,804 864,804
SEPP 1992-B................ 338,799 1,347,534 1,242,278 1,323,959 1,323,959
SEPP 1992-C................ 424,320 1,836,011 1,650,715 1,689,383 1,689,383
SEPP 1992-D................ 245,105 1,291,468 1,239,909 1,279,339 1,279,339
SEPP 1993-A................ 223,427 1,299,005 1,309,553 1,296,994 1,309,553
SEPP 1993-B................ 309,950 1,484,949 1,327,783 1,234,678 1,327,783
SEPP 1993-C................ 220,174 1,068,185 1,024,096 982,556 1,024,096
SEPP 1993-D................ 160,527 836,952 908,440 880,083 908,440
SEPP 1994-A................ 131,903 922,808 1,021,927 912,886 1,021,927
SEPP 1994-B................ 190,301 1,275,293 1,450,877 1,294,482 1,450,877
SEPP 1994-C................ 148,146 1,170,937 1,219,922 1,142,352 1,219,922
SEPP 1994-D................ 220,584 1,527,364 1,370,541 1,320,652 1,370,541
----------- ----------- ----------- ----------- -----------
$15,213,115 $77,143,485 $72,764,017 $73,790,943 $75,291,494
=========== =========== =========== =========== ===========
<CAPTION>
PURCHASE PRICE PURCHASE PRICE
PROPERTY AS % OF SWIFT AS % OF SWIFT
PURCHASE ASSETS PV-10 VALUE
PARTNERSHIP NAME PRICE(F) 12/31/97(G) 12/31/97(G)
---------------- ----------- -------------- --------------
<S> <C> <C> <C>
SWIFT ENERGY INCOME PARTNERS
(24 Partnerships -- All opera
SEIP 1986-D................ $ 1,684,539 0.50% 0.48%
SEIP 1987-A................ 2,033,424 0.60% 0.58%
SEIP 1987-B................ 2,673,577 0.79% 0.76%
SEIP 1987-C................ 1,771,688 0.52% 0.51%
SEIP 1987-D................ 1,224,831 0.36% 0.35%
SEIP 1988-A................ 1,066,290 0.31% 0.30%
SEIP 1988-B................ 703,858 0.21% 0.20%
SEIP 1988-C................ 769,266 0.23% 0.22%
SEIP 1988-D................ 1,036,869 0.31% 0.30%
SEIP 1989-A................ 2,070,732 0.61% 0.59%
SEIP 1989-B................ 3,314,557 0.98% 0.95%
SEIP 1989-C................ 760,693 0.22% 0.22%
SEIP 1989-D................ 1,158,727 0.34% 0.33%
SEIP 1990-A................ 2,075,136 0.61% 0.59%
SEIP 1990-B................ 1,324,871 0.39% 0.38%
SEIP 1988-1................ 157,637 0.05% 0.04%
SEIP 1988-2................ 370,190 0.11% 0.11%
SEIP 1988-3................ 540,836 0.16% 0.15%
SEIP 1989-1................ 656,712 0.19% 0.19%
SEIP 1989-2................ 1,468,525 0.43% 0.42%
SEIP 1989-3................ 418,086 0.12% 0.12%
SEIP 1989-4................ 421,159 0.12% 0.12%
SEIP 1990-1................ 535,163 0.16% 0.15%
SEIP 1990-2................ 384,650 0.11% 0.11%
SWIFT ENERGY MANAGED PENSION
(13 Partnerships -- All non-o
SEMPAP 1988-A.............. 373,244 0.11% 0.11%
SEMPAP 1988-B.............. 469,700 0.14% 0.13%
SEMPAP 1988-C.............. 319,829 0.09% 0.09%
SEMPAP 1989-A.............. 821,123 0.24% 0.23%
SEMPAP 1989-B.............. 1,526,387 0.45% 0.44%
SEMPAP 1989-C.............. 461,140 0.14% 0.13%
SEMPAP 1989-D.............. 640,726 0.19% 0.18%
SEMPAP 1990-A.............. 1,478,207 0.44% 0.42%
SEMPAP 1990-B.............. 1,137,634 0.34% 0.32%
SEMPAP 1988-1.............. 148,202 0.04% 0.04%
SEMPAP 1988-2.............. 444,860 0.13% 0.13%
SEMPAP 1989-1.............. 1,269,220 0.37% 0.36%
SEMPAP 1989-2.............. 296,848 0.09% 0.08%
SWIFT ENERGY OPERATING PARTNE
(13 Partnerships -- All opera
SEOP 1991-C................ 1,738,801 0.51% 0.50%
SEOP 1992-A................ 1,033,719 0.30% 0.30%
SEOP 1992-B................ 2,426,749 0.72% 0.69%
SEOP 1992-C................ 3,329,564 0.98% 0.95%
SEOP 1992-D................ 1,102,061 0.32% 0.31%
SEOP 1993-A................ 1,580,452 0.47% 0.45%
SEOP 1993-B................ 2,203,299 0.65% 0.63%
SEOP 1993-C................ 1,556,586 0.46% 0.44%
SEOP 1993-D................ 1,577,555 0.47% 0.45%
SEOP 1994-A................ 1,855,392 0.55% 0.53%
SEOP 1994-B................ 2,459,024 0.73% 0.70%
SEOP 1994-C................ 2,414,564 0.71% 0.69%
SEOP 1994-D................ 2,320,797 0.68% 0.66%
SWIFT ENERGY PENSION PARTNERS
(13 Partnerships -- All non-o
SEPP 1991-C................ 1,430,739 0.42% 0.41%
SEPP 1992-A................ 929,664 0.27% 0.27%
SEPP 1992-B................ 1,423,256 0.42% 0.41%
SEPP 1992-C................ 1,816,087 0.54% 0.52%
SEPP 1992-D................ 1,375,289 0.41% 0.39%
SEPP 1993-A................ 1,407,769 0.42% 0.40%
SEPP 1993-B................ 1,427,367 0.42% 0.41%
SEPP 1993-C................ 1,100,903 0.32% 0.31%
SEPP 1993-D................ 976,573 0.29% 0.28%
SEPP 1994-A................ 1,098,572 0.32% 0.31%
SEPP 1994-B................ 1,559,693 0.46% 0.45%
SEPP 1994-C................ 1,311,416 0.39% 0.37%
SEPP 1994-D................ 1,473,332 0.43% 0.42%
----------- ----- -----
$80,938,359 23.87% 23.10%
=========== ===== =====
</TABLE>
- ---------------
(a) Summary information relates to total Partnership.
(b) Based on volumes on a Mcfe basis
(c) Cash distributions paid to Partners from January 1, 1998 to September 30,
1998.
(d) Purchase price less estimated dissolution expenses plus net assets less
interim cash distributions.
(e) Represents the higher of the two fair market value estimates.
(f) Fair Market Value plus a 7.5% premium.
(g) As of 12/13/97 Swift's total asset value was $339 million and its PV-10
Value was $350 million.
15
<PAGE> 32
FAIRNESS OF PROPOSED SALE
The Managing General Partner believes that the entire transaction related
to the Proposals involving the proposed method of sales of the Partnerships'
Property Interests is fair to Investors for the following reasons, without
giving any particular weight to any reason:
1. The Managing General Partner believes that the most important element
of the Proposals is the determination of the Fair Market Values of the
Partnerships' Property Interests. The prices to be paid by the
Company to purchase the Partnerships' Property Interests were
determined in the Managing General Partners' sole judgment by adding a
7.5% premium to the higher of the Appraisers' two estimates on a
Partnership-by-Partnership basis of fair market value of the
Partnerships' Property Interests, done on a Partnership-by-Partnership
basis. Two of the three Appraisers are qualified independent
petroleum engineering firms and the other is an investment banking
firm. The factors and methods used by the Appraisers in determining
Fair Market Value are discussed in detail under "Special
Factors--Independent Appraisal of the Fair Market Value of
Partnerships' Property Interests" herein and "Special
Factors--Collective Analysis of Purchase Price; Premium Over Fair
Market Value" in each Partnership's specific Partnership Supplement.
2. No transaction will take place in a particular Partnership unless the
Proposal is approved by Investors holding at least a majority of the
interests in such Partnership (without any vote by the Managing
General Partner) and a similar Proposal is approved by such
Partnership's Companion Partnership.
3. The Special Transactions Committee made the determination as to the
retention of the Appraisers and approved the fair market value
estimates provided by the Appraisers and recommended the reports of
the Appraisers to the Board of Directors of the Company. The Special
Transactions Committee is comprised solely of independent directors of
the Company.
4. If any of the Proposals are approved by Investors, it is likely that
the Managing General Partner intends to expend the capital necessary
to develop various non-producing reserves on the Property Interests
purchased by the Managing General Partner. If all of the Property
Interests which are the subject of the Proposals are acquired by the
Company, such Property Interests in the aggregate will constitute less
than 20% of the Company's total assets. Because the Managing General
Partner would be the beneficiary of any such increase in value, the
Managing General Partner is hereby offering to Eligible Purchasers the
opportunity to purchase up to 2,500,000 shares of Common Stock of the
Company. There is no requirement that any purchase of Swift's Common
Stock be made. See-- "Offer to Eligible Purchasers" below.
5. In structuring the Proposals and related transactions, the Managing
General Partner considered that any sale of Partnership Property
Interests, whether to the Managing General Partner or to a third
party, would be a taxable transaction. Thus, if an Investor subject
to income tax on its Partnership investment chooses to use the
proceeds received on liquidation of that Investor's Partnership to
purchase Swift Common Stock, tax will still have to be paid on the
amount of any taxable income resulting from the liquidation of that
Investor's Partnership, whether or not the Investor has available cash
proceeds remaining from his liquidating distribution after some or all
of such proceeds are used to purchase Common Stock.
The individual Partnership Supplements contain an estimate of the
liquidating net cash distributions payable to Investors if their Partnership's
Proposal is approved, along with an estimate of the net cash distributions to
Investors from their Partnership continuing to operate for the remaining life
of that
16
<PAGE> 33
Partnership's reserves. In all but three Partnerships, the estimated amount
receivable from continuing operations is higher than the amount which Investors
will receive if the Proposals are approved. Despite this difference, which
ranges from 3% to 48%, depending upon the particular Partnership, the Managing
General Partner believes that the Proposals are fair. The estimates of
distributions from continuing operations are based upon continuation of current
oil and gas prices over a 17 to 20 year period. Continued volatility in the
markets for oil and gas therefore make this estimation subject to significant
variance based upon pricing changes. In addition, there are significant
operational risks over such a long period of time to which each of the
Partnerships would be subject. Current cash distributions paid in one lump
sum currently are not subject to these risks.
The fairness of the Proposals for the 18 Partnerships formed in the fourth
quarter of 1986, the first three quarters of 1987, and between the fourth
quarter of 1992 and the second quarter of 1994, the majority of whose proved
reserves are non-producing, should be assessed in light of the benefit to the
Managing General Partner of being able to use its capital resources to drill
wells to develop undeveloped reserves, in addition to the possible benefit of
holding such interests for a period of time sufficient to allow completion of
wells in different zones in order to produce behind- pipe reserves.
Notwithstanding the above, determinations made by the Special Transactions
Committee, the independent Appraisers' determination of the fair market value
of the properties, and the payment of a 7.5% premium does not necessarily
remove the substantial conflicts of interest which exist due to the Managing
General Partner acting on behalf of the Partnerships and also acting as the
purchaser of the Property Interests from the Partnerships. No fairness opinion
was requested or received regarding the ultimate purchase price to be paid by
the Managing General Partner to purchase the Partnerships' oil and gas assets.
Rather than setting the purchase price for Partnership Property Interests
itself, the Managing General Partner determined it would be preferable to
request three different independent Appraisers, using two different appraisal
methods to determine fair market values at which such Property Interests should
be purchased. The Managing General Partner then chose the higher of the two
values on a Partnership-by-Partnership basis. The Managing General Partner
believes that adding a 7.5% premium to the highest of the fair market value
determinations made by the three Appraisers only increases the amount to be
paid to Investors upon liquidation of their Partnerships and does not require a
separate fairness opinion. The Managing General Partner believes that when the
Appraisers rendered their opinion as to the "fair market value" of each
Partnership's Property Interests, inherent within that appraisal was the
appraiser's determination that these "fair market values" were "fair," or such
determination would not have been made. Consequently, no independent fairness
opinion upon the premium was requested. The determination of a different third
party purchaser as to the purchase price to be paid might be more or less than
that being proposed to be paid by the Managing General Partner.
By selling all of their respective oil and gas assets to the Managing
General Partner, proceeds from such liquidating sale will be distributed to the
Partners in the Partnerships and the Partnerships will be liquidated, dissolved
and terminated. These Proposals are subject to a number of conflicts of
interest, all of which are discussed in greater detail below. The purpose of
the Proposals is to provide for sale of the Partnerships' oil and gas assets
because it is time that the business of the Partnerships be concluded, and to
do so in a way intended to maximize the sale price of the Partnership's oil and
gas assets. The Managing General Partner is proposing to purchase these assets
from the Partnerships because it believes that its knowledge of the Properties
allows it to pay the highest price for such assets. The reasons for proposing
the sale of the Partnerships' Property Interests at this time are described
below under "Special Factors--Reasons for the Proposal--Reasons for Sale of
Assets at this Time." This decision was made after full consideration by the
Managing General Partner of its fiduciary obligations to Investors.
Furthermore, the decision to use three Appraisers, rather than one, and to have
the Appraisers actually set the fair market value for purchase of the
properties, rather than the Managing General Partner setting that value and
requesting a fairness opinion and the decision to add the 7.5% premium, was
based upon the Managing
17
<PAGE> 34
General Partner's consideration of the substantial conflicts of interest which
exist in the transactions covered hereby, which are detailed herein.
See "Special Factors--Fairness of Proposed Sale" herein and in each
Partnership's specific Partnership Supplement.
ALTERNATIVE TRANSACTIONS
The Managing General Partner has given consideration to a number of
different alternatives prior to submitting the Proposals to Investors for their
approval. These alternatives include continued operation of the properties for
a longer period, offering the Partnerships' Property Interests at auction or
selling them in negotiated transactions. For the reasons discussed at greater
length under "Reasons for the Proposals" above, the Managing General Partner
believes that sale of the Partnerships' Property Interests at this time is
preferable to continued operation of the Partnerships. Although in the past,
certain marginal Property Interests have been sold in negotiated transactions
or at auction, the Managing General Partner does not believe that such methods
of sale are likely to maximize the value of the Partnerships' Property
Interests, as discussed above. Although offering oil and gas properties for
sale at auction is often an efficient means of selling smaller interests in
properties in which the seller is not the operator of the property, auctions
are generally unsuited to the offer and sale of substantial property interests,
may exceed the normal size of properties offered at auction, and may well be
beyond the purchasing capacity of the parties which typically are bidders at
such auctions or might lower the price or the number of interested bidders.
To the extent that the Managing General Partner is operator of properties
in which a Partnership owns Property Interests, this can and often does
negatively affect the interest of third party auction buyers in purchasing such
properties, as well as the amount a third party auction buyer is likely willing
to pay. Furthermore, auction buyers are generally not interested in purchasing
properties with non-producing reserves, or will usually apply a large discount
to such reserves. Many of the Partnerships have Property Interests in
properties with a substantial amount of such reserves. Additionally, the
transaction cost for auctions are often substantial. Similarly, negotiated
sales of properties are negatively affected by the same factors regarding
operations of the properties and non-producing reserves, and often require
substantial periods of time for due diligence, negotiation, execution of
agreements and closings. Purchasers in negotiated transactions are often
interested in only selected properties, which often requires different
properties to be sold to different purchasers, necessitating a large number of
transactions.
An alternative to the Proposals would be to continue each of the
Partnerships according to its existing business plan. For the reasons set out
above, principally including the decline in the revenues of each of the
Partnerships while direct costs, general and administrative expenses and
certain fixed oil field overhead and operating costs remain at fixed levels or
decline at a less rapid rate (and in some cases, due to the number of years for
which certain of the Partnerships have been in existence), the Managing General
Partner recommends that Investors vote to approve the Proposals.
See "Special Factors--Consideration of Alternative Transactions" herein.
FEDERAL INCOME TAX CONSEQUENCES
The federal income tax consequences of the sale of substantially all of the
Partnerships' Property Interests and their liquidation may vary depending upon
the type of partnership involved and the tax character of the Investor, as well
as the Investor's individual circumstances. Generally, sales of the
Partnership properties, as described in the Proposals, are taxable transactions
to Investors of a Partnership that may generate taxable income or tax loss
depending on the particular Partnership. Investors, however,
18
<PAGE> 35
that are Tax Exempt Plans that are not subject to acquisition indebtedness on
their Partnership investment and that have only invested in Partnerships that
own non-operating properties generally are not subject to federal income tax on
their share of Partnership income or loss. The tax consequences resulting from
the sale of Partnership properties are not affected by an Investor's decision
to receive cash or Common Stock upon the applicable Partnership's liquidation.
The purchase of Common Stock is not a taxable transaction for federal income
purposes. For a more complete discussion of the federal income tax
consequences of a sale of properties and Partnership liquidation, see "Federal
Income Tax Consequences of the Proposals" herein. An opinion of Special Tax
Counsel is included as an Exhibit to the Registration Statement. All Investors
interested in electing to receive Common Stock in lieu of cash should read
"Material Federal Income Tax Considerations of Electing to Receive Common Stock
in lieu of Cash Upon Partnership Liquidation" herein. For information
concerning the federal income tax risks associated with the sale of
substantially all of the Partnerships' Property Interests and the acquisition
of Company Common Stock by Investors, see "Risk Factors--Tax Risks" herein.
BENEFITS TO THE MANAGING GENERAL PARTNER
The Managing General Partner will share the benefits available to Investors
through liquidating its Partnership interests (including both its general
partner's interests and any units its owns) and receiving the same value of
those interests as Investors. Additionally, the Company intends to profit from
purchasing the Partnerships' Property Interests through a return on capital
used to purchase those oil and gas assets and invest in their development. By
purchasing the Partnerships' Property Interests itself, Managing General
Partner will be able to maintain its position as operator of certain properties
in which Partnerships own interests. Consequently, the Managing General
Partner would continue to receive operating fees as operator of those
properties. Additionally, the purchase of all of the oil and gas assets of the
Partnerships would increase the Company's proved reserves, cash flow and total
assets. Lastly, if individual Investors in Partnerships which approve the
Proposals elect to purchase Company Common Stock, rather than receiving cash
upon liquidation of their Partnerships, the Company will benefit by using stock
to pay the purchase price, rather than using its available cash resources or
borrowing facilities.
See "Special Factors--Managing General Partner Benefits" herein.
NO APPRAISAL OR DISSENTERS' RIGHTS PROVIDED; INVESTOR LISTS; BOOKS AND RECORDS
In connection with the Proposals to sell all of the Partnerships' oil and
gas assets and liquidate the Partnerships, Investors are not entitled to any
dissenters' or appraisal rights such as would be available to shareholders in a
corporation engaging in a merger. Dissenting Investors are protected under
state law by virtue of the fiduciary duty of the Managing General Partner to
act with prudence in the business affairs of the Partnerships, although
investors would be required to initiate suit to assert claims based upon a
general partner's fiduciary duties under the Texas Revised Limited Partnership
Act and the terms of each Partnership's limited partnership agreement.
Generally speaking, Investors of each of the Partnerships are entitled to
request copies of Investor lists showing the names and addresses of all
Investors in that Partnership. The right to receive such Investor lists may be
conditioned upon the Investors' paying the cost of duplication and a showing
that the request is for a reasonable purpose. Reasonable requests would
include requests for Investor lists for the purpose of challenging or opposing
the Proposals. Requests for Investor lists may be addressed to the Company at
16825 Northchase Drive, Suite 400, Houston, Texas 77060; Attention: Investor
Relations Department.
The limited partnership agreements of the Partnerships provide that their
books and records (generally limited to the records which are just and
reasonable for Investors to examine and copy) are available for
19
<PAGE> 36
inspection by Investors or their duly authorized representatives at all
reasonable times at the Partnerships' principal offices in Houston, Texas,
although certain oil and gas operational materials may be kept confidential.
For most of the Partnerships, a written request must be received stating a
proper purpose for inspection of such books and records, with the inspection to
be conducted at the Investor's expense. An Investor may request in writing
without charge copies of a Partnership's limited partnership agreement,
certificate of limited partnership and tax return.
CONSEQUENCES OF A PARTNERSHIP NOT APPROVING ITS PROPOSAL
If the Investors in a Partnership do not approve its Proposal, such
nonparticipating Partnership will continue to operate as a separate legal
entity with its own assets and liabilities. There will be no change in its
investment objectives, policies or restrictions, and the nonparticipating
Partnerships will continue to be operated in accordance with the terms of their
Partnership Agreement. It is also likely that the Proposal to the Companion
Partnership of any such nonparticipating Partnership will be withdrawn even if
a Proposal is approved by Investors of such Companion Partnership.
See "Special Factors--Consequences of Partnership not Approving its Proposal"
herein.
SUPPLEMENTS FOR INDIVIDUAL PARTNERSHIPS AND CURRENT REPORTS INCLUDED
Also included with the delivery of this Joint Proxy Statement/Prospectus
are the following documents:
o A separate Partnership Supplement (the "Partnership Supplement")
containing information specific to each Investor's specific
Partnership, including:
o Information on the Partnership's oil and gas assets including
the number of wells, fields, the nature of the oil and gas
interest held, the Partnership's age, the top fields
constituting 10% or more of the Partnership's PV-10 Value at
December 31, 1997, and the portion of the Partnership's proved
reserve comprised of proved producing, behind-pipe and
non-developed reserves;
o Risk Factors specific to the Partnership;
o The exact amount of the proposed purchase price for the
Partnership's Property Interests, and estimates of the
liquidating distribution to be made to Investors and a
comparison of estimates of distributions from continuing
operations to this liquidating distribution amount, and a
discussion of the fairness of the transaction in light of
these differing amounts;
o Specific information on the number of units outstanding and
the vote necessary to approve each Partnership's Proposal; and
o Summary of the Partnership's business and financial condition,
including cash distributions received over the last three
years and information regarding transactions between the
Managing General Partner and the Partnership including all
fees paid to the Managing General Partner over the past three
years.
20
<PAGE> 37
Also attached to each Partnership Supplement is:
o a reserve report from H. J. Gruy & Associates, Inc.,
independent petroleum engineers, on that Partnership's oil and
gas reserves as of December 31, 1997;
o the fair market value estimate for that Partnership's Property
Interests by J. R. Butler and Company and H. J. Gruy &
Associates, Inc.; and
o the fair market value estimate for that Partnership's Property
Interests by CIBC Oppenheimer Corp.
o The specific Partnership's Annual Report on Form 10-K for the year
ended December 31, 1997 or financial statements and related financial
information for fiscal years 1997, 1996 and 1995 for those
Partnerships not subject to the informational requirements of the 1934
Act.
o The specific Partnership's Quarterly Report on Form 10-Q for the
quarter ended March 31, 1998 or financial statements and related
financial information for the quarter ended March 31, 1998 for those
Partnerships not subject to the informational requirements of the 1934
Act.
INVESTOR ELECTIONS
The Investors are being asked by the Company to make two elections:
o Approve or disapprove their Partnership's Proposal, and
o If approved, to receive their distributions in the form of cash,
Common Stock or a combination thereof.
Further, each Investor is hereby given the opportunity to purchase shares
of Common Stock with funds in addition to the cash distributions they are
entitled to receive in order to purchase (i) the minimum round lot of 100
shares, or (ii) shares in addition to the number of shares purchasable with
their cash distribution, subject to prorata limitations in the event of
oversubscription. See "Offer to Eligible Purchasers" below.
VOTING PROCEDURES
This Joint Proxy Statement/Prospectus contains detailed procedures to be
followed by Investors in voting as to the Partnerships' Proposals. Strict
compliance with these procedures must be followed in order for the elections of
the Investors marked on the Proxies to be effective. The following is a
summary of certain of these procedures:
(a) Investors may make their elections on the Proxies signed by all
subscribers commencing upon delivery of this Joint Proxy Statement/Prospectus
and continuing until the Due Date.
(b) Eligible Purchasers may revoke their election to purchase Shares
offered hereby at any time until the Due Date by delivering or faxing a letter
so stating or a later dated subscription agreement, both of which must be
signed by such revoking subscribers, to the Company at 16825 Northchase Drive,
Suite 400, Houston, Texas 77060, fax number (281) 874-2818; Attention:
Investor Relations Department.
(c) Investors failing to submit Proxies by the Due Date will be deemed to
have voted against their Partnership's Proposal and, if their Partnership
approves its Proposal, will receive their distribution in cash. See "The
Proposals--Vote Required" herein and "Voting on the Proposal--Vote Required" in
each Partnership's specific Partnership Supplement.
21
<PAGE> 38
OFFER TO ELIGIBLE PURCHASERS
Investor Election to Purchase Shares
In connection with the concurrent Proposals for sale of substantially all
of the assets of 63 Partnerships to the Company and the subsequent termination
of such Partnerships, the Company is offering (the "Offering") up to 2,500,000
shares of the Company's Common Stock (the "Shares"). This Offering is made
solely to Eligible Purchasers, those Investors of each Partnership in which the
Proposals are approved by it and its Companion Partnership. Upon approval of
the Proposals by Companion Partnerships and sale of such Partnerships'
properties, the Partnerships' assets will consist solely of cash which each
Eligible Purchaser of such Partnerships will be entitled to receive as a
distribution. The Company hereby offers to each Eligible Purchaser the
opportunity to purchase shares of Common Stock with all or any portion of the
cash distribution such Investor will be entitled to receive, provided that a
minimum round lot of 100 shares must be purchased. If an Eligible Purchaser
has interests in more than one Partnership, the cash distributions he will be
entitled to receive may be aggregated to meet the minimum round lot of 100
shares requirement. Eligible Purchasers may purchase shares of Common Stock
with funds in addition to their cash distributions in order to purchase (i) the
minimum round lot of 100 shares, or (ii) shares in addition to the number of
shares for which their cash distribution will be applied, subject to prorata
limitations in the event of oversubscription. No fractional shares will be
sold.
Purchase Price
The price at which the Common Stock offered hereby will be issued will be
the average price of the Common Stock as reported by the NYSE for the period
between ________ and __________, 1998.
A supplement to this Joint Proxy Statement/Prospectus (the "Prospectus
Supplement") will be sent to Eligible Purchasers advising as to which
Partnerships approved the Proposals and the purchase price of the Shares
offered hereby.
Shares Outstanding
At June 30, 1998, 16,534,357 shares of Common Stock were issued and
outstanding. If the 2,500,000 Shares had been issued as of such date, they
would have constituted approximately 13.1% of the Company's issued and
outstanding Common Stock.
New York Stock Exchange and Pacific Exchange Listings
The Common Stock is traded on the NYSE and the Pacific Exchange under the
symbol "SFY." Application will be made to list the Shares offered hereby on
the NYSE and the Pacific Exchange.
Closing Date
The Company will issue checks representing full or partial distributions
and/or stock certificates representing the shares of Common Stock subscribed
for hereunder approximately forty-five (45) days after the date of the
Prospectus Supplement (the "Closing Date"), unless earlier terminated or
extended by the Company.
22
<PAGE> 39
Due Date
All subscriptions, revocations of prior subscriptions or additional
required consideration must be received no later than thirty (30) days after
the date of the Prospectus Supplement (the "Due Date"), unless extended by the
Company.
Oversubscription
In the event this Offering is oversubscribed, all subscribing Eligible
Purchasers will first be sold a round lot of 100 shares and then, if
applicable, that number of shares of Common Stock the purchase price of which
is equal to such Eligible Purchaser's cash distribution, rounded down to the
next whole share. Any remaining shares will be sold on a prorata basis based
on the number of shares such subscribers wish to purchase.
Revocation
Eligible Purchasers may revoke their subscriptions to purchase of the
Shares offered hereby at any time until the Due Date by delivering or faxing a
letter so stating or a later dated proxy, either of which must be signed by
such revoking subscribers, to the Company at 16825 Northchase Drive, Suite 400,
Houston, Texas 77060, fax number (281) 874- 2818; Attention: Investor
Relations Department.
Offers to Third Parties
In the event this Offering is not fully subscribed by Eligible Purchasers,
the Company may offer any remaining Shares from time to time to third parties
including, but not limited to, underwriters and institutional investors.
Specific terms of the offer for the unsubscribed Shares of Common Stock in
respect of which this Prospectus is being delivered will be set forth in one or
more accompanying prospectus supplements. Such prospectus supplement(s) will
set forth, without limitation, the number of shares of Common Stock and the
terms of the offering and sale thereof.
See "Investor Election to Participate in Offering of 2,500,000 Shares of Common
Stock to Eligible Purchasers" herein and "Offering of Shares of Swift Energy
Company Common Stock If Investors Approve the Proposal" in each Partnership's
specific Partnership Supplement.
23
<PAGE> 40
COMPARISON OF PARTNERSHIPS AND THE COMPANY
The information below highlights a number of significant differences
between the Partnerships and the Company relating to, among other things, form
of organization, investment objectives, policies and restrictions, asset
diversification, capitalization, management structure, compensation and fees,
and investor rights. These differences are discussed in detail under
"Comparison of Ownership of Units or Shares." Such section of this Joint Proxy
Statement/Prospectus also includes a summary comparison of the legal rights
associated with the ownership of Units or Shares.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------
PARTNERSHIPS COMPANY
- --------------------------------------------------------------------------------------------------------------------
Form of Organization
<S> <C>
o Partnerships formed as Texas limited partnerships, o Company formed as a Texas corporation, which is a
which are finite life entities. At the end of the continuing life entity.
Partnerships' lives (or upon sale of substantially
all of their assets), Investors receive net proceeds
from sale of any remaining assets upon liquidation.
</TABLE>
The Partnerships and the Company are each vehicles recognized as
appropriate for the holding of Property Interests and afford benefits to
passive investors such as the Investors, such as limitation of liabilities.
<TABLE>
<CAPTION>
Length of Investment
<S> <C>
o Expected holding period of five to ten years after o Company to be operated as an infinite life
acquisition, subject to the Managing General entity, with no plans or expectations as to the
Partner's judgment as to the timing of sales liquidation of Company assets
</TABLE>
Investors in each of the Partnerships expect liquidation of their
investment when the assets of the Partnership are liquidated. In contrast,
Shareholders are expected to achieve liquidity of their investments by trading
the shares of Common Stock in the public markets. The Company does not expect
to dispose of its investments within any prescribed periods.
Properties and Diversification
The Company owns an oil and gas portfolio substantially larger and
more diversified than the portfolio of any of the Partnerships or all of the
Partnerships taken together. Whereas the Company is engaged in an active
drilling program, which involves a higher degree of risk, the Partnerships were
not established for any substantial drilling of oil and gas wells, and do not
have the capital to do so.
24
<PAGE> 41
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------
PARTNERSHIPS COMPANY
- --------------------------------------------------------------------------------------------------------------------
Cash Distributions v. No Cash Dividends
<S> <C>
o Partnerships have made quarterly cash o Shareholders in the Company cannot expect to
distributions to Investors from sale of oil and receive cash dividends, as the Company has never
gas production. paid any cash dividends and does not expect to do
so for the foreseeable future, although since
1995 it has paid two 10% common stock dividends.
Any profit or loss from investing in Company
Common Stock will come from the increase or
decrease in the price of that stock.
Additional Equity
o Not authorized to issue equity securities beyond o Board of Directors likely to issue additional
the Units initially offered to the public securities (Common Stock or Preferred Stock),
plus various debt securities, which will dilute
any interest Investors may have in the Company
</TABLE>
Unlike the Partnerships, the Company has substantial flexibility to
raise equity through the sale of Common Stock, Preferred Stock or sell debt
securities to finance its business and affairs.
<TABLE>
<S> <C>
Debt Policy
o Partnerships not intended to borrow substantial o Expected that the Company may incur more leverage
funds and borrowing was generally restricted or than the Partnerships
limited in the Partnerships' limited partnership
agreements.
</TABLE>
In conducting its business, the Company may incur indebtedness to the
extent believed appropriate, subject to indebtedness restrictions. It is
expected that the Company will be more leveraged than any of the Partnerships.
<TABLE>
<S> <C>
Management Control
o Substantially all management authority vested in o Board of Directors vested with control over the
the Managing General Partner Company's business and affairs subject to
restrictions in the Company's Articles of
o Investors have no right to participate in Incorporation and By-Laws
management, except for limited matters that might
be submitted to a vote of the Investors, such as o Shareholders elect members of the Board of
the Proposals Directors on a staggered basis annually
</TABLE>
To some extent, Shareholders will have greater control over management
of the Company than the Investors have over the Partnerships because members of
the Board of Directors are elected each year by the Shareholders at the
Company's annual meeting.
25
<PAGE> 42
SWIFT ENERGY COMPANY
The Company is engaged in the development, exploration, acquisition
and operation of oil and gas properties, with a primary focus on U.S. onshore
natural gas reserves. As of December 31, 1997, the Company had interests in
over 1,500 oil and gas wells located in 10 states, of which the Company
operated 650 wells representing 91% of its proved reserve base. At such date,
the Company had proved reserves of 361.5 Bcfe, of which approximately 87% were
natural gas, 60% were proved developed and 93% were located in Texas. The
Company's primary focus is development and exploration drilling in its two core
areas: the AWP Olmos Field located in South Texas and the Texas Austin Chalk
trend. The AWP Olmos Field is characterized by long-lived reserves, while the
Austin Chalk trend is characterized by short-lived reserves with high initial
production and rapid decline rates. These fields accounted for approximately
74% and 15%, respectively, of the Company's proved reserves as of December 31,
1997, and approximately 61% and 19%, respectively, of the Company's production
during 1997.
On August 26, 1998, the Company purchased certain producing oil and
gas properties (the "Sonat Properties") from Sonat Exploration Company
("Sonat"), a subsidiary of Sonat Inc. As a result of the acquisition of the
Sonat Properties (the "Sonat Properties Acquisition"), and assuming the
Proposals are approved by all the Partnerships (collectively, the
"Acquisitions"), the Acquisitions provide the Company with significant proved
reserves as well as additional development and exploratory opportunities in its
core areas. The Company expects to utilize its operating expertise in these
areas to successfully develop and exploit these properties. The Acquisitions
will increase the Company's interest in oil and gas wells to over 1,650 wells,
of which the Company will operate approximately 765 wells. The Company expects
reserves in the Austin Chalk trend to increase to approximately 26% of proved
reserves as a result of the Acquisitions. See "--Recent Developments."
The Company maintains a flexible capital spending program in order to
take advantage of the relative economic attractiveness of either drilling or
acquisition opportunities. Over the last several years, the Company's growth
in reserves and production has resulted primarily from its increased acreage
position and drilling activities in the AWP Olmos Field and in the Austin Chalk
trend. The Company has budgeted capital expenditures of $241.5 million for
1998, comprised of $145.8 million for the Acquisitions and $95.7 million for
development and exploration. Approximately 59% of the $95.7 million is
targeted for the continued development of the Company's two core areas. The
Company is also actively pursuing exploratory drilling opportunities in high
potential projects elsewhere in the Gulf Coast Basin and in New Zealand.
In 1997, the Company increased its proved reserves by 40% primarily
from additions through drilling, resulting in the replacement of 522% of 197
production. The Company's five-year average reserve replacement costs were
$0.76 per Mcfe. As a result of increased drilling activity, 1997 production
increased 31% over 1996 production. Due to economies of scale, geographic
concentration and increased production, general and administrative expenses and
production costs have fallen from $0.57 and $0.39 per Mcfe, respectively, in
1992 to $0.14 and $0.35 per Mcfe, respectively, in 1997. For the six months
ended June 30, 1998, such costs were $0.13 and $0.34 per Mcfe, respectively.
See "Business and Properties--General" herein.
BUSINESS STRATEGY
The Company pursues a balanced growth strategy that includes an active
drilling program, strategic acquisitions and advanced technologies. The
Company's operating philosophy is to increase its reserve base through both
drilling and acquisitions, shifting the balance between the two in response to
market conditions.
26
<PAGE> 43
Key elements of the Company's strategy include the following:
Active Drilling Program. With the expanded inventory of drilling
prospects that the Company will have following the assumed consummation of both
of the Acquisitions and when economic drilling conditions improve, the Company
intends to pursue an active program of development drilling in its core areas
together with selected step-out and exploratory drilling on its undeveloped
acreage. Exploratory drilling is based on a "controlled risk" approach,
focusing on regions where the exploration objective would allow the Company to
utilize its technological or geological expertise and that are in close
proximity to known production. In 1997, the Company drilled 128 net
development wells, 127 of which were in the Company's AWP Olmos Field and
Austin Chalk trend core areas, and seven net exploration wells, of which two
were in such core areas. During this period, the Company had net drilling
success rates of 97% for development wells and 38% for exploratory wells. The
Company expects to drill a total of 77 gross wells in 1998, 55 of which had
been drilled as of June 30, 1998 at a capital cost of approximately $45.7
million to the Company. The Company anticipates that drilling activity in the
AWP Olmos Field and the Austin Chalk trend will represent 59% of the total 1998
drilling budget. The Company looks to reduce its overall risk exposure with
respect to development and exploration activities by entering into joint
development agreements with industry partners to share capital exposure for any
individual well. As an example of this strategy, the Company has active joint
development projects with, among others, Union Pacific Resources Company
("UPRC") and Chevron USA production Company ("Chevron") in the Austin Chalk
trend, in which the Company serves as operator of a majority of the wells.
Strategic Acquisitions. The Company continuously reviews acquisition
opportunities, including opportunities to acquire properties with significant
proved producing reserves and substantial undeveloped acreage for future
drilling activities. The Company targets properties located in close proximity
to its current reserves, where such reserves can be increased through
development drilling and where operating efficiencies can be achieved. Using
these criteria, the Company employs a disciplined, market-driven approach to
acquisitions to augment its drilling program. The Company has conducted an
ongoing acquisition program since its inception.
Advanced Technologies. In order to minimize the risks associated with
development and exploration drilling and enhance operating efficiencies, the
Company has devoted considerable resources to developing advanced technological
expertise. These technologies include 2-D and 3-D seismic analysis, amplitude
versus offset (AVO) studies and detailed formation depletion studies. The
Company has also attained substantial expertise in horizontal well drilling
technology, having participated as of June 30, 1998 in 70 such wells in the
Austin Chalk trend, 62 of which have been successful. Additionally, the
Company uses innovative fracturing methods, coiled tubing technology and
computer telemetry to monitor well performance. As a result of these
technologies, the Company has enhanced its production yields while reducing its
costs per Mcfe. Application of thee technologies has enabled the Company to
achieve historical drilling success rates that exceed applicable U.S. industry
averages.
See "Business and Properties--Business Strategy" herein.
RECENT DEVELOPMENTS
In addition to the proposed acquisition of the Partnerships' Property
Interests (sometimes referred to herein as the "Partnership Properties
Acquisition"), the Company recently consummated the following transactions:
Sonat Properties Acquisition. On August 26, 1998, the Company
purchased from Sonat, effective April 1, 1998, the Sonat Properties for
approximately $87.6 million in cash. As of April 1, 1998, estimated
27
<PAGE> 44
proved reserves for the Sonat Properties were 91.1 Bcfe, of which approximately
56% was natural gas, with 1997 production of 22.0 Bcfe, of which approximately
51% was natural gas. The properties include 156 producing oil and natural gas
wells in the Brookeland Field in Southeast Texas and the Masters Creek Field in
Western Louisiana, 21 saltwater disposal wells, a 20% interest in two natural
gas plants, associated production facilities and working interests averaging
50% in approximately 200,000 undeveloped gross acres containing more than 50
drilling locations. The Company became operator of 113 of the 156 wells. The
two gas plants have combined capacity of 250 Mmcfe per day, and in 1997 had
operating cash flow of $2.8 million. UPRC is the operator of both plants.
Acquisition of the Sonat Properties extends one of the Company's core
areas through the addition of producing reserves that will significantly
increase the Company's production on a short-term basis.
See "Business and Properties--Recent Developments" herein.
New Credit Facility. On August 18, 1998, the Company closed on a
$250.0 million revolving line of credit (the "New Credit Facility"), of which
Bank One, Texas, National Association, the lead bank, has committed $37.5
million and has syndicated the balance with a group of nine other banks. The
New Credit Facility is subject to an initial borrowing base of $170.0 million.
However, an additional $30.0 million will be added to this borrowing base upon
consummation of the Partnership Properties Acquisition. As of September 1,
1998, $19.2 million of the $170.0 million borrowing base was available to the
Company. The New Credit Facility replaces all of the Company's prior bank
credit facilities. The borrowing base will be redetermined semi-annually on
the basis of reserve reports and other information available to the lenders.
In addition, the lenders may, at their discretion, make a redetermination of
the borrowing base at any time including in connection with a request by the
Company to redetermine the borrowing base, the incurrence of additional debt
and the sale or transfer of properties by the Company.
Borrowings under the New Credit Facility bear interest, at the option
of the Company, either at (i) the lead bank's prime rate, currently 8.5%, or
(ii) adjusted LIBOR plus the applicable margin, which increases as the level of
outstanding debt increases. The New Credit Facility extends until August 18,
2002. The terms of the New Credit Facility include restrictions such as
limitations on debt obligations, certain liens, dividends (not to exceed $2.0
million annually), a $15.0 million limit on repurchases by the Company of its
Common Stock, as well requirements as to maintenance of certain minimum
financial ratios (principally pertaining to working capital, debt and equity
ratios).
28
<PAGE> 45
SUMMARY HISTORICAL CONSOLIDATED FINANCIAL DATA
OF SWIFT ENERGY COMPANY
The summary historical consolidated financial data of the Company for each
of the five years in the period ended December 31, 1997, has been derived from
the audited consolidated financial statements of the Company. The summary
historical consolidated financial data of the Company as of and for each of the
six months ended June 30, 1998 and 1997 were derived from the unaudited
condensed consolidated financial statements of the Company. In the opinion of
the Company's management, the summary historical consolidated financial data of
the Company as of and for each of the six months ended June 30, 1998 and 1997
include all adjusting entries (consisting only of normal recurring adjustments)
necessary to present fairly the information set forth therein. The results of
operations for the six months ended June 30, 1998 should not be regarded as
indicative of the results that may be expected for the full year.
The information presented below should be read in conjunction with the
Consolidated Financial Statements and related notes thereto "Management's
Discussion and Analysis of Financial Condition and Results of Operations," and
other financial information included elsewhere in the Joint Proxy
Statement/Prospectus.
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEAR ENDED DECEMBER 31,
----------------------- ----------------------------------------------------
1998(A) 1997(A) 1997(A) 1996(A) 1995(A) 1994 1993
--------- ----------- -------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and gas sales....................... $ 31,483 $ 32,441 $ 69,015 $ 52,771 $ 22,528 $ 19,802 $ 15,536
Fees and Earned Interests(b)............ 205 264 746 937 590 702 4,072
Interest income......................... 63 1,750 2,395 433 212 48 201
Other, net.............................. 1,065 1,195 2,556 2,157 1,762 1,073 604
-------- -------- -------- -------- -------- -------- --------
Total Revenues.................... 32,816 35,650 74,712 56,298 25,092 21,625 20,413
-------- -------- -------- -------- -------- -------- --------
Costs and Expenses:
General and administrative, net of
reimbursement......................... 1,880 1,808 3,524 4,150 3,336 3,323 3,206
Depreciation, depletion, and
amortization.......................... 13,985 11,108 24,247 16,526 8,839 7,905 7,301
Oil and gas production.................. 4,875 4,172 8,779 6,142 4,907 3,764 2,680
Interest expense, net................... 2,970 2,393 5,033 694 1,115 1,795 598
-------- -------- -------- -------- -------- -------- --------
Total Costs and Expenses.......... 23,710 19,481 41,583 27,512 18,197 16,787 13,785
-------- -------- -------- -------- -------- -------- --------
Income before Income Taxes................ 9,106 16,169 33,129 28,786 6,895 4,838 6,628
Provision for Income Taxes................ 2,980 5,286 10,819 9,760 1,982 1,112 1,732
-------- -------- -------- -------- -------- -------- --------
Income Before Cumulative Effect of Change
in Accounting Principle................. $ 6,126 $ 10,883 $ 22,310 $ 19,026 $ 4,913 $ 3,726 $ 4,896
======== ======== ======== ======== ======== ======== ========
Per share amounts (c)--
Basic................................... $ 0.37 $ 0.66 $ 1.35 $ 1.27 $ 0.49 $ 0.51 $ 0.68
======== ======== ======== ======== ======== ======== ========
Diluted................................. $ 0.37 $ 0.61 $ 1.26 $ 1.25 $ 0.49 $ 0.51 $ 0.64
======== ======== ======== ======== ======== ======== ========
Weighted Average Shares Outstanding(c).... 16,513 16,552 16,493 15,001 10,035 7,309 7,247
======== ======== ======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
Net cash provided by operating
activities.............................. $ 25,491 $ 30,285 $ 55,256 $ 37,103 $ 14,376 $ 10,395 $ 7,238
Capital expenditures...................... 66,968 64,043 131,967 91,487 40,033 34,531 24,229
Ratio of earnings to fixed charges(d)..... 2.6x 5.4x 5.2x 12.8x 3.1x 2.6x 7.0x
BALANCE SHEET DATA:
Working capital........................... $ 10,345 $ 25,543 $ 1,464 $ 68,704 $ 3,247 $(13,137) $ 9,742
Total assets.............................. 404,259 315,219 339,115 310,375 175,253 135,673 160,893
Long-term debt:
6.25% Convertible Subordinated Notes.... 115,000 115,000 115,000 115,000 -- -- --
6.5% Convertible Subordinated
Debentures............................ -- -- -- -- 28,750 28,750 28,750
Existing Credit Facility................ 64,000 -- 7,915 -- -- -- --
Stockholders' equity...................... 165,937 147,115 159,401 142,762 93,346 42,127 54,466
</TABLE>
- ---------------
(a) For a discussion of the significant items affecting comparability of 1997,
1996, 1995, and for the six months ended June 30, 1998 and 1997, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" included elsewhere in this Joint Proxy Statement/Prospectus.
(b) As of January 1, 1994, the Company changed its revenue recognition policy
for earned interests. Accordingly, for 1997, 1996, 1995, 1994, and for the
six months ended June 30, 1998 and 1997, "Fees and Earned Interests" do not
include earned interests.
(c) Amounts have been retroactively restated in all periods presented to: (a)
an equivalent change in capital structure as a result of two 10% stock
dividends, one in September 1994, the other in October 1997 (see Note 2 to
the Consolidated Financial Statements); and (b) the adoption of Statement
of Financial Accounting Standards No. 128, "Earnings per Share" (see Note 2
to the Consolidated Financial Statements).
(d) For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expense, capitalized interest, amortization of
debt issuance costs and that portion of non-capitalized rental expense
deemed to be the equivalent of interest. Earnings represents income before
income taxes from continuing operations before fixed charges. The Company's
Management uses the ratio of earnings to fixed charges to determine the
extent to which the Company's earnings are adequate to cover fixed charges
(as defined).
29
<PAGE> 46
SUMMARY PRO FORMA CONSOLIDATED FINANCIAL DATA
OF SWIFT ENERGY COMPANY
The summary historical consolidated financial data of the Company for the
year ended December 31, 1997 has been derived from the audited consolidated
financial statements of the Company. The summary historical consolidated
financial data of the Company as of and for the six month period ended June 30,
1998 were derived from the unaudited condensed consolidated financial statements
of the Company.
The unaudited summary pro forma financial data is based on the Company's
historical financial statements, adjusted to give effect to the following
scenarios (i) the purchase of substantially all of the oil and gas assets (the
"Partnership Properties Acquisition") of all 63 Partnerships ("100% Case") for
(a) all cash or (b) cash and 2.5 million shares of Common Stock at an assumed
price of $18 per share and the Sonat Properties Acquisition consummated for all
cash and (ii) the effect of the approval of the Proposals by those 48
Partnerships with the lowest levels of net cash provided by operating
activities, selected in ascending order until the group of such Partnerships
collectively represent approximately 50% of the combined net cash provided by
operating activities for the six months ended June 30, 1998 of all 63
Partnerships ("50% Case") for (a) all cash or (b) 2.1 million shares of Common
Stock at an assumed price of $18 per share and the Sonat Properties Acquisition
consummated for all cash. The above scenarios assume that the Company uses
available cash and borrowings under the new $250 million credit facility due
2002 (the "New Credit Facility") to satisfy the required cash outlay to fund the
Partnership Properties Acquisition and the Sonat Properties Acquisition
(together "the Acquisitions"). The unaudited summary pro forma statements of
income data assumes the Partnership Properties Acquisition and the Sonat
Properties Acquisition occurred January 1, 1997. The unaudited summary balance
sheet data assumes the Partnership Properties Acquisition and the Sonat
Properties Acquisition occurred as of June 30, 1998. The unaudited summary pro
forma data is not necessarily indicative of the results that actually would have
occurred if the Partnership Properties Acquisition and the Sonat Properties
Acquisition had been in effect on the dates indicated or which may be obtained
in the future.
The information presented below should be read in conjunction with the
Consolidated Financial Statements and related notes thereto, the Unaudited Pro
Forma Consolidated Financial Statements, "Management's Discussion and Analysis
of Financial Condition and Results of Operations," and other financial
information included elsewhere in the Joint Proxy Statement/Prospectus.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
--------------------------------------------------------------
100% CASE PARTNERSHIP 50% CASE PARTNERSHIP
PROPERTIES ACQUISITION & PROPERTIES ACQUISITION
SONAT PROPERTIES & SONAT PROPERTIES
ACQUISITION PRO FORMA ACQUISITION PRO FORMA
------------------------ ----------------------
HISTORICAL ALL CASH EQUITY/CASH ALL CASH ALL EQUITY
---------- --------- ------------ -------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and gas sales..................................... $ 69,015 $169,367 $169,367 $155,964 $155,964
Fees from limited partnerships........................ 746 542 542 620 620
Interest income....................................... 2,395 2,395 2,395 2,395 2,395
Other, net............................................ 2,556 2,778 2,778 2,703 2,703
-------- -------- -------- -------- --------
Total Revenues.................................. 74,712 175,082 175,082 161,682 161,682
-------- -------- -------- -------- --------
Costs and Expenses:
General and administrative, net of reimbursement...... 3,524 7,683 7,683 6,324 6,324
Depreciation, depletion, and amortization............. 24,247 56,660 56,660 53,018 53,018
Oil and gas production................................ 8,779 31,654 31,654 27,422 27,422
Interest expense, net................................. 5,033 15,613 12,126 13,807 10,848
-------- -------- -------- -------- --------
Total Costs and Expenses........................ 41,583 111,610 108,123 100,571 97,612
-------- -------- -------- -------- --------
Income before Income Taxes.............................. 33,129 63,472 66,959 61,111 64,070
Provision for Income Taxes.............................. 10,819 21,136 22,321 20,332 21,340
-------- -------- -------- -------- --------
Income Before Cumulative Effect of Change in Accounting
Principle............................................. $ 22,310 $ 42,336 $ 44,638 $40,779 42,730
======== ======== ======== ======== ========
Per share amounts --
Basic................................................. $ 1.35 $ 2.57 $ 2.35 $ 2.47 $ 2.30
======== ======== ======== ======== ========
Diluted............................................... $ 1.26 $ 2.23 $ 2.09 $ 2.15 $ 2.04
======== ======== ======== ======== ========
Weighted Average Shares Outstanding..................... 16,493 16,493 18,993 16,493 18,615
======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
Net cash provided by operating activities............... $ 55,256 $107,695 $109,997 $102,496 $104,447
Capital expenditures.................................... 131,967 278,350 233,350 254,838 215,999
Ratio of earnings to fixed charges(a)................... 5.2x 4.4x 5.5x 4.6x 5.7x
</TABLE>
(Pro forma data and
notes thereto continued on following page)
30
<PAGE> 47
SUMMARY PRO FORMA CONSOLIDATED FINANCIAL DATA
OF SWIFT ENERGY COMPANY -- (CONTINUED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, 1998
----------------------------------------------------------------------------------
100% CASE PARTNERSHIP PROPERTIES 50% CASE PARTNERSHIP PROPERTIES
ACQUISITION & SONAT PROPERTIES ACQUISITION & SONAT PROPERTIES
ACQUISITION PRO FORMA ACQUISITION PRO FORMA
-------------------------------- --------------------------------
HISTORICAL ALL CASH EQUITY/CASH ALL CASH ALL EQUITY
---------- ------------- ---------------- ------------- ---------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales................. $ 31,483 $ 73,987 $ 73,987 $ 70,040 $ 70,040
Fees from limited partnerships.... 205 155 155 182 182
Interest income................... 63 63 63 63 63
Other, net........................ 1,065 1,141 1,141 1,115 1,115
-------- -------- -------- -------- --------
32,816 75,346 75,346 71,400 71,400
-------- -------- -------- -------- --------
Costs and Expenses:
General and administrative, net of
reimbursement................... 1,880 3,764 3,764 3,180 3,180
Depreciation, depletion, and
amortization.................... 13,985 29,928 29,928 28,639 28,639
Oil and gas production............ 4,875 14,909 14,909 13,288 13,288
Interest expense, net............. 2,970 8,260 6,516 7,357 5,877
-------- -------- -------- -------- --------
23,710 56,861 55,117 52,464 50,984
-------- -------- -------- -------- --------
Income before Income Taxes.......... 9,106 18,485 20,229 18,936 20,416
Provision for Income Taxes.......... 2,980 6,169 6,762 6,322 6,825
-------- -------- -------- -------- --------
Net Income.......................... $ 6,126 $ 12,316 $ 13,467 $ 12,614 $ 13,591
======== ======== ======== ======== ========
Per share amounts
Basic: ........................... $ 0.37 $ 0.75 $ 0.71 $ 0.76 $ 0.73
======== ======== ======== ======== ========
Diluted: ......................... $ 0.37 $ 0.71 $ 0.68 $ 0.72 $ 0.70
======== ======== ======== ======== ========
Weighted Average Shares
Outstanding....................... 16,513 16,513 19,013 16,513 18,635
======== ======== ======== ======== ========
Net cash provided by operating
activities...................... $ 25,491 $ 47,624 $ 48,775 $ 46,633 $ 47,610
Capital Expenditures................ 66,968 66,968 66,968 66,968 66,968
Ratio of Earnings to fixed
charges........................... 2.6x 2.7x 3.3x 2.9x 3.5x
Balance Sheet
Working Capital..................... 10,345 839 839 839 839
Total Assets........................ 404,259 537,299 537,299 515,138 515,138
Long-term debt
6.25% convertible subordinated
notes........................... 115,000 115,000 115,000 115,000 115,000
Existing Credit Facility.......... 64,000 64,000 64,000 64,000 64,000
New Credit Facility............... -- 136,526 91,526 113,226 75,026
Stockholder's equity................ 165,937 165,937 210,937 165,937 204,137
</TABLE>
- ---------------
(a) For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expense, capitalized interest, amortization of
debt issuance costs and that portion of non-capitalized rental expense
deemed to be the equivalent of interest. Earnings represents income before
income taxes from continuing operations before fixed charges. The Company's
management uses the ratio of earnings to fixed charges to determine the
extent to which the Company's earnings are adequate to cover fixed charges
(as defined).
31
<PAGE> 48
SUMMARY RESERVES AND PRODUCTION DATA
OF SWIFT ENERGY COMPANY
The following tables set forth certain summary information with respect to
estimates of oil and gas reserves and production data. The Company's historical
oil and gas reserves, the future net revenues therefrom and their PV-10 Value
have been prepared by the Company, and audited by H.J. Gruy and Associates,
Inc., independent petroleum engineers ("Gruy"). The reserve information is based
upon numerous assumptions and is subject to change due to numerous factors. See
"Business and Properties -- Oil and Gas Reserves" and "Risk
Factors -- Uncertainty of Estimates of Reserves and Future Net Revenues."
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------------------------------
100% CASE PARTNERSHIP 50% CASE PARTNERSHIP
PROPERTIES ACQUISITION PROPERTIES ACQUISITION
& SONAT PROPERTIES & SONAT PROPERTIES HISTORICAL
ACQUISITION ACQUISITION --------------------------------------------------
1997 PRO FORMA(A) 1997 PRO FORMA(A) 1997 1996 1995 1994 1993
---------------------- ---------------------- -------- -------- -------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
ESTIMATED PROVED OIL AND
GAS RESERVES:
Net natural gas reserves
(MMcf):
Proved developed......... 276,706 257,216 191,108 135,425 81,532 46,406 50,937
Proved undeveloped....... 159,053 154,279 123,198 90,333 62,036 29,858 13,526
-------- -------- -------- -------- -------- ------- -------
Total.............. 435,759 411,495 314,306 225,758 143,568 76,264 64,463
======== ======== ======== ======== ======== ======= =======
Net oil reserves (MBbl):
Proved developed......... 11,639 10,565 4,289 3,622 3,313 3,209 3,110
Proved undeveloped....... 8,172 7,778 3,570 1,862 2,109 1,344 1,161
-------- -------- -------- -------- -------- ------- -------
Total.............. 19,811 18,343 7,859 5,484 5,422 4,553 4,271
======== ======== ======== ======== ======== ======= =======
ESTIMATED PRESENT VALUE OF
PROVED RESERVES:
Estimated present value of
future net cash flows
from proved reserves
discounted at 10% per
annum (dollars in
thousands):
Proved developed......... $417,438 $392,457 $244,365 $310,409 $ 85,537 $47,172 $66,310
Proved undeveloped....... 161,025 153,733 105,980 160,776 61,501 22,223 17,451
-------- -------- -------- -------- -------- ------- -------
Total PV-10 Value
(before income
taxes)(b)........ $578,463 $546,190 $350,345 $471,185 $147,038 $69,395 $83,761
======== ======== ======== ======== ======== ======= =======
Standardized measure of
discounted estimated
future net cash flows
after income taxes....... $471,737 $446,427 $292,838 $367,232 $128,904 $66,472 $74,968
======== ======== ======== ======== ======== ======= =======
Prices used in calculating
end of year proved
reserves:
Oil (Per Bbl)............ $ 15.97 $ 15.98 $ 15.76 $ 23.75 $ 18.07 $ 15.09 $ 12.87
======== ======== ======== ======== ======== ======= =======
Gas (Per Mcf)............ $ 2.77 $ 2.77 $ 2.78 $ 4.47 $ 2.41 $ 1.85 $ 2.50
======== ======== ======== ======== ======== ======= =======
OTHER RESERVES DATA:
Reserve replacement
cost(c).................. N/A N/A $ 0.73 $ 0.67 $ 0.61 $ 0.79 $ 0.70
Exploration and development
reserves added (MMcfe)... N/A N/A 120,150 118,235 72,425 24,804 13,502
Acquisition reserves added
(MMcfe).................. N/A N/A 33,824 3,259 5,692 12,879 26,469
</TABLE>
- ---------------
(a) Adjusted to give effect to the Acquisitions as if they had occurred January
1, 1997.
(b) Changes in quantity estimates and the PV-10 Value and standardized measure
are affected by the change in crude oil and gas prices at the end of each
year. While the Company's total proved reserves quantities (on an MMcfe
basis) at year end 1997 increased by 40% over reserves quantities a year
earlier, the PV-10 Value and standardized measure of those reserves
decreased 26% and 20%, respectively, from the PV-10 Value and standardized
measure at year end 1996. This decrease was almost totally due to the
higher year end 1996 prices. If year end 1997 PV-10 Value and standardized
measure used year end 1996 prices, there would have been an increase in the
PV-10 Value and standardized measure from year end 1996 to year end 1997
comparable to the 40% increase in the total proved reserves quantities
during that same period.
(c) Calculated for a three-year period ending with the year presented by
dividing total acquisition, exploration and development costs (excluding
future development costs) incurred during such period by net reserves added
during the period (excluding revisions).
(Production data continued on following page)
32
<PAGE> 49
The following table sets forth summary operating data with respect to the
production and sales of oil and natural gas for the periods indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------------------------------
100% CASE PARTNERSHIP 50% CASE PARTNERSHIP
PROPERTIES ACQUISITION PROPERTIES ACQUISITION
& SONAT PROPERTIES & SONAT PROPERTIES
ACQUISITION ACQUISITION
1997 PRO FORMA(A) 1997 PRO FORMA(A) 1997 1996 1995 1994 1993
---------------------- ---------------------- ------- ------- ------- ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
PRODUCTION:
Net Sales Volume:
Oil (MBbls)................. 3,193 2,962 672 623 545 467 324
Gas (MMcf)(b)............... 42,113 38,804 21,359 15,697 7,914 6,799 5,422
Gas equivalents (MMcfe)..... 61,271 56,574 25,394 19,437 11,187 9,601 7,369
WEIGHTED AVERAGE SALES PRICES:
Oil (Per Bbl)................. $ 17.88 $ 17.90 $ 17.59 $ 19.82 $ 15.66 $14.35 $15.10
Gas (Per Mcf)................. $ 2.67 $ 2.76 $ 2.68 $ 2.57 $ 1.77 $ 1.93 $ 1.96
SELECTED DATA PER MCFE:
Production Costs.............. $ 0.52 $ 0.48 $ 0.35 $ 0.31 $ 0.44 $ 0.39 $ 0.36
Depreciation, depletion, and
amortization................ $ 0.92 $ 0.94 $ 0.95 $ 0.85 $ 0.79 $ 0.82 $ 0.99
General and administrative,
net of reimbursement........ $ 0.13 $ 0.11 $ 0.14 $ 0.21 $ 0.30 $ 0.35 $ 0.44
WELLS DRILLED:
Gross......................... N/A N/A 182 153 76 44 34
Net........................... N/A N/A 135 116 42 16 9
</TABLE>
- ---------------
(a) Adjusted to give effect to the Acquisitions as if they had occurred January
1, 1997.
(b) Natural gas production for 1997, 1996, 1995, 1994, and 1993 includes 1,015,
1,156, 1,211, 1,358, and 1,581 MMcf, respectively, delivered under the
volumetric production payment agreement pursuant to which the Company is
obligated to deliver certain monthly quantities of natural gas. Future
volumes associated with the volumetric production payment are not included
in the Company's estimate of net reserves.
33
<PAGE> 50
SUMMARY HISTORICAL COMBINED FINANCIAL DATA OF THE PARTNERSHIPS
The summary combined financial data as of December 31, 1997 and for the
year then ended were derived from the audited combined financial statements of
the Partnerships included herein. The summary combined financial data as of
December 31, 1996, 1995, 1994 and 1993, and for each of the four years in the
period ended December 31, 1996 are unaudited and were derived from the
accounting records of the Managing General Partner. The summary combined
financial data as of and for the six months ended June 30, 1998 and 1997 were
derived from the unaudited combined financial statements of the Partnerships. In
the opinion of the Managing General Partner of the Partnerships, the summary
combined financial data of the Partnerships as of December 31, 1996, 1995, 1994
and 1993, and for each of the four years in the period ended December 31, 1996,
and as of and for the six months ended June 30, 1998 and 1997 include all
adjusting entries (consisting only of normal recurring adjustments) necessary to
present fairly the information set forth therein. The results of operations for
the six months ended June 30, 1998 should not be regarded as indicative of the
results that may be expected for the full year.
The information presented below should be read in conjunction with the
Combined Financial Statements of the Partnerships and related notes thereto and
other financial information included elsewhere in the Joint Proxy
Statement/Prospectus.
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEAR ENDED DECEMBER 31,
------------------ ----------------------------------------------------
1998 1997 1997 1996 1995 1994 1993
-------- ------- -------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER INVESTMENT AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Oil and gas revenues................. $ 11,463 $21,743 $ 42,228 $ 52,512 $ 43,430 $ 54,902 $ 58,061
Net income (loss).................... $ (7,075) $ 1,563 $ 6,966 $ 11,938 $ (8,346) $(14,094) $ 13,573
Investors' net income (loss)
per $100 investment(a)............. $ (2.13) $ 0.23 $ 1.64 $ 2.91 $ (2.62) $ (8.39) $ 2.93
BALANCE SHEET DATA:
Cash and cash equivalents............ $ 6,805 $ 7,429 $ 7,169 $ 3,622 $ 11,904 $ 16,269
Total assets......................... $ 92,241 $108,597 $127,839 $144,418 $174,105 $195,942
Total liabilities.................... $ 6,568 $ 4,680 $ 5,403 $ 14,755 $ 17,606 $ 28,179
Investors' equity.................... $ 84,280 $101,783 $119,714 $127,264 $154,111 $165,006
General Partners' equity............. $ 1,393 $ 2,134 $ 2,722 $ 2,399 $ 2,388 $ 2,757
Investors' book value per $100
investment(a)...................... $ 25.43 $ 30.71 $ 36.12 $ 38.40 $ 48.26 $ 58.11
OTHER DATA:
Net cash provided by operating
activities......................... $ 11,324 $ 23,742 $ 20,694 $ 24,305 $ 32,788 $ 33,679
Net increase (decrease) in cash and
cash equivalents................... $ (624) $ 260 $ 3,547 $ (8,282) $ (4,365) $ 16,269
Total assets at the value assigned
for the Transaction(b)............. $ 75,291
Investors' value assigned for the
Transaction Per $100
investment(a)...................... $ 19.53
Cash distributions................... $ 11,169 $14,345 $ 25,485 $ 19,165 $ 18,490 $ 29,243 $ 29,471
Investors' cash distributions per
$100 investment(a)................. $ 2.96 $ 3.66 $ 6.69 $ 4.75 $ 4.91 $ 7.85 $ 8.87
Ratio of earnings to fixed
charges(c)......................... NM 188.1x 325.6x 59.3x NM NM 42.2x
</TABLE>
- ---------------
(a) The Investors' per $100 investment calculations are based upon the number of
$100 investments into the total combined Partnerships' Investor original
capital contributions. The Investors' original capital contributions for the
combined Partnerships totaled $331,427,600 for 1995 through June 30, 1998,
$319,308,800 for 1994 and $283,970,600 for 1993. The per $100 investment is
presented in order to achieve a comparable measure for all Partnerships, as
interests in the Partnerships were sold on a basis of either $1.00 units,
$100 units or $1,000 units.
(b) Represents the total combined Partnerships fair market value of the
Partnerships' Property Interests. The fair market value was derived from the
higher of the Appraisers' fair market valuation estimates for each
Partnership and was used in determining the purchase price for the
Partnership Property Acquisitions. See "Summary -- Summary Partnership
Information" for the fair market value of each Partnership.
(c) For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expense capitalized interest, amortization of debt
issuance costs and that portion of non-capitalized rental expense deemed to
be the equivalent of interest. Earnings represents income before income
taxes from continuing operations before fixed charges.
34
<PAGE> 51
RISK FACTORS
In addition to the other information contained in this Joint Proxy
Statement/Prospectus, the following factors should be considered carefully in
evaluating an investment in the Shares offered hereby. The statements
contained herein that are not historical facts are "forward-looking statements"
as that term is defined in Section 21E of the 1934 Act, and therefore involve a
number of risks and uncertainties. Such forward-looking statements may be or
may concern, among other things, the Company's future financial position,
business strategy, budgets, projected costs, plans, capital expenditures,
drilling activity, development activities, cost savings, production efforts and
volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory
matters and competition. Such forward-looking statements generally are
accompanied by words such as "plan," "budget," "estimate," "expect," "predict,"
"anticipate," "projected," "should," "believe," or other words that convey the
uncertainty of future events or outcomes. Such forward-looking information is
based upon management's current plans, expectations, estimates and assumptions
and is subject to a number of risks and uncertainties that could significantly
affect current plans, anticipated actions, the timing of such actions and the
Company's financial condition and results of operations. As a consequence,
actual results may differ materially from expectations, estimates or
assumptions expressed in or implied by any forward-looking statements made by
or on behalf of the Company, including those regarding the Company's financial
results, levels of oil and gas production or revenues, capital expenditures,
and capital resource activities. Among the factors that could cause actual
results to differ materially are: fluctuations of the prices received or demand
for the Company's oil and natural gas; the uncertainty of drilling results and
reserve estimates; operating hazards; requirements for capital; general
economic conditions; competition and government regulations; as well as the
risks and uncertainties set forth in "Risk Factors" below, including, without
limitation, the portions referenced above and the uncertainties set forth from
time to time in the Company's other public reports, filings and public
statements (collectively, "Cautionary Statements"). Also, because of the
volatility in oil and gas prices and other factors, interim results are not
necessarily indicative of those for a full year. All subsequent, written and
oral forward-looking statements attributable to the Company or persons acting
on its behalf, are expressly qualified in their entirety by the Cautionary
Statements.
Prior to making an investment decision, Investors should consider all
of the information in this Joint Proxy Statement/Prospectus and in their
specific Partnership Supplement and should give careful consideration to the
risks involved, including those summarized below:
RISKS OF THE PROPOSALS
CONFLICTS OF INTEREST
If the Proposals are approved, the Partnerships' Property Interests
ultimately would be sold to the Managing General Partner at a purchase price
that has been set by the Special Transactions Committee of the Board of
Directors of the Company based on the valuation estimates of the Appraisers
plus a 7.5% premium. This purchase price may not represent the highest
possible prices that might be received for the Partnerships' Property Interests
in all circumstances. It is possible that a higher or lower price might be
received if the properties were sold on an individual basis. A different price
(either higher or lower) might also be received if certain properties were sold
at auction or in a negotiated sale. The Company has not attempted to sell or
locate partners for the Partnerships' Property Interests by any of these means.
35
<PAGE> 52
NO FAIRNESS OPINION
Although the fair market value of the Property Interests forming the
basis for the proposed purchase price to be paid by the Managing General
Partner was determined by three independent Appraisers, no opinion was acquired
as to the fairness of the 7.5% premium over the highest of the Appraisers' fair
market value for each Partnership's Property Interests. The 7.5% premium was
determined in the Managing General Partner's sole judgment and was not based
upon a determination by an impartial third party. It is possible that another
party intent upon purchasing the Property Interests in the Partnerships would
have offered a different Purchase Price.
LACK OF INDEPENDENT REPRESENTATION
No independent representative was retained to act on behalf of the
Investors in structuring and negotiating the terms and conditions (including
the consideration to be received) of the Proposals. The proposed purchase
prices have not been negotiated at arm's length and are subject to significant
conflicts of interests between the Company acting both as the purchaser of the
Partnerships' Property Interests and as the Managing General Partner of the
Partnerships. If an independent representative had been retained for the
Investors, the terms of the Proposals might have been different and possibly
more favorable to the Investors.
TIMING OF SALE AND PRICE VOLATILITY
The fair market values (which does not include the 7.5% premium)
forming the basis of the purchase price to be paid by the Managing General
Partner for the Partnerships' Property Interests are based upon the Appraisers
estimations of such values. Year-end 1997 prices, along with other
then-current market factors, were used as a starting point for the Appraisers'
analyses. The petroleum engineer consultants then made the determination to
escalate prices and costs at a rate of 3.5% per year over 15 years. Greater
increases in the prices or lesser increases in costs in the future might result
and Investors would receive higher distributions from continued operations of
the Partnerships than estimated. However, the effect of any higher prices or
lower costs is somewhat limited because the Partnerships have already produced
a substantial majority of their oil and gas reserves.
DEPENDENCE ON VOTE OF COMPANION PARTNERSHIP
If a Partnership's companion Partnership does not approve its Proposal
to sell all of its oil and gas assets and liquidate, it is likely that the
Proposals to both such Partnerships will be withdrawn and the value of their
Property Interests reassessed. This could occur, even though a Proposal is
approved by Investors of the other Partnership, due to the decrease in value of
the Property Interests involved when the working and non-operating interests
are separated. All but ten of the 63 Partnerships have companion Partnerships.
See "The Proposal--Simultaneous Proposal to Companion Partnership" for
additional information including, but not limited to, which Partnerships do not
have companions. Although in such event the Managing General Partner will
attempt to provide a different approach for sale of such Partnerships' Property
Interests, it is possible that such Partnerships' assets may not be sold.
36
<PAGE> 53
VOLATILITY OF AND RELATIONSHIP BETWEEN VALUE OF PROPERTY INTERESTS AND STOCK
PRICE
The Managing General Partner intends to invest capital in drilling
activities in the fields that comprise the Property Interests it proposes to
purchase from the Partnerships. Such investment may and future drilling
activity by third parties in or near such fields could increase the value of
such Property Interests. Investors will not share in any possible increase in
value of such Property Interests. In addition, certain of this drilling
activity is likely to consist of higher risk development or exploratory
drilling. However, the Company is hereby offering up to 2,500,000 shares of
Common Stock directly to Investors of Partnerships that along with their
Companion Partnerships, if any, approve the Proposals. Investors who elect to
receive such stock may share indirectly in any increase in the value of the
Property Interests purchased by the Company through increase in the price of
the Common Stock, however, such Investors are also subject to the risk that the
price of the Common Stock could decline even if the value of such Property
Interests purchased by the Company increase.
For the 18 Partnerships formed in the fourth quarter of 1986, the
first three quarters of 1987, and between the fourth quarter of 1992 and the
second quarter of 1994, a majority of their proved oil and gas reserves are
non- producing. Because non-producing reserves are traditionally discounted
due to future costs which must be incurred to recover those reserves and the
risk that any drilling will be unsuccessful, there is a risk that the discount
applied to the non-producing reserves by the Petroleum Engineering Consultants
could be greater than the discount applied by third party purchaser. Likewise,
it is likely that any drilling conducted on Property Interests acquired from
these Partnerships has upside potential. The benefit of which will go to the
Managing General Partner if it acquires those properties.
POSSIBLE DECREASE IN DISTRIBUTIONS TO INVESTORS DUE TO INTERIM PRODUCTION
The amounts available for distribution to Investors if the Proposals
are approved are estimated under "The Proposal--Estimates of Liquidating
Distribution Amount." The amounts estimated thereon have been reduced by
estimated cash distributions to Investors between January 1, 1998 and [June
30,] 1998. Thus in analyzing the Proposal, amounts distributed upon
liquidation could be smaller than, or vary from, those shown.
RISKS OF ELECTING TO TAKE COMMON STOCK
TRADING PRICE OF SHARES
There is substantial uncertainty as to the prices at which the Shares
will trade following consummation of the Proposals. It is not known whether
the prices at which the Shares will trade will be greater or less than the (i)
price at which the Shares will be sold hereunder or (ii) the cash distribution
the Investor could receive in lieu of subscribing for any Shares. As with
other equity securities, the value of the Shares will depend upon various
market conditions, which change from time to time. The conditions that may
affect the value of the Shares include, but are not limited to, the following:
the price of oil and gas; institutional interest in the Company; the Company's
financial performance; and general stock market conditions.
DEMAND IN MARKET
There can be no assurance that demand will rise for the Shares after
the consummation of the Proposals. Whether such demand rises will depend on,
among other things, the Company's performance, market yield expectations,
institutional interest in the Company and perceptions regarding the Company's
growth potential.
37
<PAGE> 54
UNCERTAINTIES AT TIME OF VOTING
Prior to completion of the solicitation to which this Joint Proxy
Statement/Prospectus relates, it is not known which of the Partnerships will
approve the Proposals. Investors, therefore, do not know the extent to which
the Company will draw upon its line of credit to purchase the Property Interest
or the extent of dilution to shareholder ownership as a result of this
Offering.
CHANGE IN NATURE OF INVESTMENT
By electing to receive shares of Common Stock instead of continuing to
hold Units, the nature of an Investor's investment fundamentally changes.
These changes are due in part to differences in the governing documents under
which the Company and Partnerships are organized and the fact that the Company
is subject to federal and state statutes, regulations and laws applicable to
corporations and, subject to the provisions of the Code applicable to
corporations. The Partnerships are instead subject to the state statutes,
regulations and laws applicable to partnerships and subject to the provisions
of the Code applicable to entities taxed as partnerships. Certain of these
differences are summarized under "Comparison of Ownership of Units and Shares"
and should be carefully considered by the Investors in assessing how to vote on
the Proposals. Several of these factors may increase the risks of the
Investors if they elect to receive Shares of Common Stock in lieu of cash
distributions or continuing to hold Units in the Partnerships.
Length of Investments. Investors in each of the Partnerships expect
liquidation of their investment when the assets of the Partnership are
liquidated, which liquidations were to occur within 5 to 10 years of the
Partnership's organization. In contrast, shareholders are dependent upon the
secondary securities markets to achieve liquidity of their investments by
trading the Shares. Such secondary market may not fully reflect the
liquidation value of the Company's assets.
Potential Leverage. It is expected that the Company may incur
indebtedness substantially beyond that incurred for any of the Partnerships.
None of the Partnerships has incurred significant indebtedness, nor is it
expected that any such indebtedness would be incurred by the Partnerships in
the future. Investment in the Shares would, accordingly, expose the Investors
to the risks associated with substantial leverage.
RETAINED EARNINGS IMPACT UPON MARKET VALUE
The market value of the Company's Common Stock is generally believed
to be based primarily upon a multiple of net cash receipts, whether from
operations or sales or refinancings, and a factor for the market's expectation
of the likelihood of a continuation of that cash flow and secondarily upon the
appraised value of the underlying assets. For such reasons, the Shares may
trade at prices below the value of the underlying assets divided by the number
of outstanding shares of Common Stock. To the extent the Company retains
operating cash flow for investment purposes, working capital reserves or other
purposes, such retention of funds, while increasing the value of the Company's
underlying assets, may not correspondingly increase the market value of the
Shares. Furthermore, the Company has never paid any cash dividends and does
not expect to do so in the foreseeable future.
38
<PAGE> 55
DILUTION UPON ISSUANCE OF SHARES
The issuance of the Shares will have the effect of diluting existing
shareholders of the Company. The Company has the right to issue, at the
discretion of the Board of Directors, additional equity securities, including
additional shares of Common Stock. Such equity securities can be issued upon
such terms and at such prices as the Board of Directors may establish. Should
additional equity securities be sold, such sales would dilute the interests of
all Shareholders. In addition, the Company may in the future issue preferred
stock that might have priority over the Common Stock as to distributions and
liquidation proceeds. See "Investment Policies and
Restrictions--Capitalizations--Common and Preferred Stock."
RISKS OF INVESTMENT IN THE COMPANY
VOLATILITY OF OIL AND GAS PRICES AND MARKETS; CEILING TEST WRITEDOWNS
The Company's revenue and profitability are substantially dependent
upon prevailing prices of oil and natural gas. In the months preceding the
date of this Joint Proxy Statement/Prospectus, oil prices dropped to 12-year
lows and gas prices remained volatile. There can be no assurance that oil and
gas prices will improve. Continued declines, or prolonged pricing at current
levels, could have a material adverse effect on the Company's results of
operations and financial condition, could impact the Company's ability to find
drilling partners or to otherwise fund development and exploration programs,
and may reduce the amount of the Company's reserves that can be produced
economically.
Prices for oil and natural gas are also subject to considerable
volatility. Price volatility makes it difficult to estimate the value of
producing properties for acquisition and often causes disruption in the market
for oil and natural gas producing properties, as buyers and sellers have
difficulty agreeing on such value. Furthermore, price volatility makes it
difficult to budget for and project the return on acquisitions and development
and exploration projects. Prices for oil and natural gas are likely to
continue to be subject to wide fluctuation in response to relatively minor
changes in the supply of and demand for oil and natural gas, market uncertainty
and a variety of additional factors beyond the control of the Company. These
factors include the level of consumer product demand, weather conditions,
domestic and foreign governmental regulations, the price and availability of
alternative fuels, world political conditions, the foreign supply of oil and
natural gas, the price of oil and gas imports and overall economic conditions.
From time to time, oil and gas prices have been depressed by excess domestic
and imported supplies, as is the current situation. In addition, as a result
of changes in recent years in the natural gas market regulatory structure and
volatility in the market price of natural gas, most producers and purchasers
are unwilling to enter into long-term purchase and sale contracts.
Accordingly, most of the Company's gas production is sold on the "spot market,"
where producers and purchasers negotiate sales on a short-term (usually a
30-day) basis. Accordingly, the stability of the Company's future revenues is
vulnerable to short-term fluctuations in the price of natural gas. See
- --Effect of Price Risk Management.
Under Commission regulations applicable to entities that account for
their investments in oil and gas properties using the full-cost accounting
rules, on a quarterly basis the Company confirms that the after-tax PV-10 Value
of its proved reserves (plus certain amounts for unproved properties) exceeds
the capitalized costs of oil and gas properties and deferred taxes carried on
its balance sheet. This "ceiling test" must be performed using oil and gas
prices at the end of the applicable period, rather than historical amounts or
averages calculated over longer periods. In addition, the quantity of reserves
to which the test is applied may be reduced to the extent depressed pricing
makes it uneconomic to produce. As of June 30, 1998, gas prices
39
<PAGE> 56
were $2.59 per Mcf and oil prices were $12.32 per Bbl. Applying such prices to
the Company's June 30, 1998 estimated reserves results in a ceiling test
cushion of approximately $23.4 million. Declines in oil and gas prices below
the June 30, 1998 levels could require a writedown of the value of the
Company's oil and gas properties. Additionally, the Company calculates its
ceiling test on a country by country basis, and a negative outlook in a
particular country could result in a writedown even if prospects in other
countries remain positive. Although any such writedown would not affect cash
flow from operating activities, it would constitute a charge to earnings and
would decrease stockholders' equity. See "Management's Discussion and Analysis
of Financial Conditions and Results of Operations--General--Proved Oil and Gas
Reserves."
LEVERAGE AND DEBT SERVICE
After giving effect to the Sonat Properties Acquisition and the
Proposals (assuming the 100% Case All Cash Partnership Properties Acquisition),
the Company will have indebtedness that is substantial in relation to its
stockholders' equity. As of June 30, 1998, on a pro forma basis after giving
effect to these transactions, the Company would have had approximately [$275]
million of outstanding total consolidated indebtedness and stockholders' equity
of approximately [$163] million. The Company's level of indebtedness will have
several important effects on its future operations, including (i) a significant
portion of the Company's cash flow from operations will be dedicated to the
payment of interest on its indebtedness and will not be available for other
purposes, (ii) covenants contained in the Company's debt obligations will
require the Company to meet certain financial tests, and other restrictions
will limit its ability to borrow additional funds or to dispose of assets and
may affect the Company's flexibility in planning for, and reacting to, changes
in its business, including possible acquisition activities, (iii) the Company's
ability to obtain financing in the future for working capital, capital
expenditures, acquisitions, general corporate purposes or other purposes may be
impaired and (iv) the Company's leveraged position may make the Company more
vulnerable to economic downturns and may limit its ability to withstand
competitive pressures. The Company's ability to meet its debt service
obligations and to reduce its total indebtedness will depend upon the Company's
future performance, which will be subject to general economic conditions and to
financial, business and other factors affecting the operations of the Company,
many of which are beyond its control. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and
Capital Resources."
REPLACEMENT AND EXPANSION OF RESERVES
The Company's continued success is largely dependent on its ability to
replace and expand its oil and gas reserves through the development of and
exploration for oil and gas reserves and the acquisition of producing
properties, both of which involve substantial risks. Without successful
drilling or acquisition ventures, the Company will be unable to replace the
reserves being depleted by production, and its assets, revenues, cash flows and
reserves would decline. There can be no assurance that the Company's
development and exploration and acquisition activities will result in the
replacement of, or additions to, the Company's reserves, or that it will have
continuing success at drilling productive wells at economically viable costs.
DEVELOPMENT AND EXPLORATION RISKS
Development and exploration of oil and gas reserves involve a high
degree of risk that no commercial production will be obtained or that the
production will be insufficient to recover drilling and completion costs. The
cost of drilling, completing and operating wells is often uncertain and during
the past several years such costs paid by the Company to providers in the
service sector of the industry have increased, due primarily to higher demand
for drilling rigs and other equipment and services (as reflected in the
Company's increasing reserve replacement costs). The Company's drilling
operations may be curtailed, delayed or canceled as a
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result of numerous factors, including title problems, weather conditions,
compliance with governmental requirements and shortages or delays in the
delivery of equipment. Furthermore, completion of a well does not assure a
profit on the investment or a recovery of drilling, completion and operating
costs. See "Business and Properties--Development and Exploration Drilling
Activities."
The Company currently emphasizes development and exploration of
natural gas reserves. The marketability of the Company's production depends
upon the availability and capacity of gas gathering systems, pipelines and
processing facilities. The unavailability or lack of capacity thereof could
result in the shut-in of producing wells or the delay or discontinuation of
development plans for properties. In addition, the effects of the foregoing
could be exacerbated by the fact that the Company's operations are
geographically concentrated in its two core areas, making the Company more
vulnerable to an adverse change in conditions in its operating area than more
geographically diversified competitors might be.
RISKS ASSOCIATED WITH ACQUISITIONS
The Company's growth since its inception has been attributable in
significant part to acquisitions of producing properties. The Company expects
to continue to evaluate and, where appropriate, pursue acquisition
opportunities on terms management considers favorable to the Company. There
can be no assurance that suitable acquisition candidates will be identified in
the future, or that the Company will be able to finance such acquisitions on
favorable terms. In addition, the Company competes against other companies for
acquisitions, and there can be no assurance that the Company will be successful
in the acquisition of any material property interests. Furthermore, there can
be no assurances that any future acquisitions made by the Company will be
integrated successfully into the Company's operations or will achieve desired
profitability objectives.
The successful acquisition of producing properties requires an
assessment of recoverable reserves, exploration potential, future oil and
natural gas prices, operating costs, potential environmental and other
liabilities and other factors beyond the Company's control. In connection with
such an assessment, the Company performs a review of the subject properties
that it believes to be generally consistent with industry practices.
Nonetheless, the resulting assessments are necessarily inexact and their
accuracy inherently uncertain, and such a review may not reveal all existing or
potential problems, nor will it necessarily permit the Company to become
sufficiently familiar with the properties to fully assess their merits and
deficiencies. It is generally not feasible for the Company to review in detail
every property it purchases and all records with respect to such properties.
Moreover, even a detailed review of properties and records may not necessarily
reveal existing or potential problems, nor will it permit a buyer to become
familiar enough with the properties to assess fully their deficiencies and
capabilities. Evaluation of future recoverable reserves of oil, gas and
natural gas liquids, which is an integral part of the property selection
process, is a process that depends upon evaluation of existing geological,
engineering and production data, some or all of which may prove to be
unreliable or not indicative of future performance. See "--Uncertainty of
Estimates of Reserves and Future Net Revenues." To the extent the seller does
not operate the properties, obtaining access to properties and records may be
more difficult. Even when problems are identified, the seller may not be
willing or financially able to give contractual protection against such
problems and the Company may decide to assume environmental and other
liabilities in connection with acquired properties. See "Business and
Properties--Oil and Gas Acreage."
As is customary in the industry, the Company generally acquires oil
and gas acreage without any warranty of title except as to claims made by,
through or under the transferor. Although the Company has title to developed
acreage examined prior to acquisition in those cases in which the economic
significance of the acreage justifies the cost, title opinions may not be
obtained if, in the Company's judgment, it would be
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uneconomical or impractical to do so, and there can be no assurance that losses
will not result from title defects or from defects in the assignment of
leasehold rights.
Additionally, significant acquisitions can change the nature of the
operations and business of the Company depending upon the character of the
acquired properties, which may be substantially different in operating and
geologic characteristics or geographic location from existing properties.
While the Company's current operations are located primarily in Texas, there is
no assurance that the Company will not pursue acquisitions or properties
located in other geographic areas.
FUTURE CAPITAL REQUIREMENTS
The Company makes and will continue to make substantial capital
expenditures to further explore and develop its properties and to acquire
additional oil and gas properties. These expenditures are currently
anticipated to be approximately $171.5 million for the second half of 1998.
Cash flow from operations will be used to fund these expenditures. The Company
may also seek additional capital from traditional reserve base borrowings,
equity and debt offerings, joint ventures and other sources. The Company's
ability to access additional capital will depend on its continued success in
exploring for and developing its reserves and the status of the capital markets
at the time such capital is sought. In addition, the Company's ability to
obtain financing from existing or future partners in its drilling joint
ventures will depend on the continued cooperation of such partners, whose
interests may not be the same as those of the Company. Accordingly, there can
be no assurance that capital will be available to the Company from any source
or that, if available, it will be on terms acceptable to the Company. In such
an event, the development and exploration of the Company's properties could be
delayed and, accordingly, the implementation of the Company's business strategy
would be adversely affected.
UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET REVENUES
Estimates of the Company's proved developed oil and gas reserves and
future net revenues therefrom appearing elsewhere herein are based on reserve
reports audited by independent petroleum engineers. The estimation of reserves
requires substantial judgment on the part of the petroleum engineers, resulting
in imprecise determinations, particularly with respect to new discoveries.
Estimates of proved undeveloped reserves, which comprise a significant portion
of the Company's total reserves, are by their nature less certain. The
accuracy of any reserve estimate depends on the quality of available data as
well as engineering and geological interpretation and judgment. Actual future
production, oil and gas prices, revenues, taxes, capital expenditures,
operating expenses, geologic success and quantities of recoverable oil and gas
reserves may vary substantially from those assumed in the estimates, may result
in revisions to such estimates and could materially affect the estimated
quantities and related PV-10 Value of reserves set forth in this Joint Proxy
Statement/Prospectus. Although cost and reserve estimates attributable to the
Company's oil and gas reserves have been prepared in accordance with industry
standards, no assurance can be given that the estimated costs are accurate,
that development will occur as scheduled or that the results will be as
estimated.
The present value of future net revenues referred to in this Joint
Proxy Statement/Prospectus should not be construed as the current market value
of the estimated oil and gas reserves attributable to the Company's properties.
In accordance with applicable requirements of the Commission, the estimated
discounted future net cash flows from proved reserves are generally based on
prices and costs as of the date of the estimate, whereas actual future prices
and costs may be materially higher or lower, except where changes in prices
were fixed under existing contracts. There can be no assurance, however, that
such prices will be realized or that the estimated production volumes will be
produced during the periods indicated. Future performance that
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deviates significantly from the reserve reports could have a material adverse
effect on the Company. See "Business and Properties--Properties" and "--Oil
and Gas Reserves."
OPERATING HAZARDS AND UNINSURED RISKS
Hazards such as unusual or unexpected geologic formations, pressures,
downhole fires, mechanical failures, blowouts, cratering, explosions,
uncontrollable flow of oil, gas or well fluids, pollution and other
environmental risks such as oil spills, gas leaks, ruptures or discharges of
toxic gases are inherent in oil and gas exploration and production. These
hazards could result in substantial losses to the Company due to injury and
loss of life, severe damage to and destruction of property and equipment,
pollution and other environmental damage and suspension of operations. Because
the Company's drilling operations are conducted by independent contractors, the
Company does not have the benefit of workmen's compensation insurance for
liabilities arising out of the injuries to employees of such contractors. The
Company carries insurance which it believes is in accordance with customary
industry practices, but, as is common in the oil and gas industry, the Company
does not fully insure against all risks associated with its business either
because such insurance is not available or because the cost thereof is
prohibitive.
EFFECT OF PRICE RISK MANAGEMENT
The Company may, from time to time, enter into hedging transactions
with respect to a portion of its expected future production. While such
transactions would be entered into with the objective of reducing risks
associated with price volatility, such transactions may limit potential gains
by the Company if oil and gas prices were to rise substantially over the price
established by a hedge. In addition, such transactions may expose the Company
to the risk of financial loss in certain circumstances, including instances in
which (i) production is less than expected, (ii) there is a widening of price
differential between delivery points for the Company's production and the
delivery point assumed in the hedge arrangement, (iii) the counter parties to
the Company's futures contracts fail to perform on a contract or (iv) a sudden,
unexpected event materially impacts oil or gas prices. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources." To the extent that price floors
are purchased for a portion of the Company's production but are not needed, or
to the extent that future sales are made at prices below ultimate future market
prices, funds so spent will have been lost or income realized from sale of
production may be reduced. See "Business and Properties--Price Risk
Management."
FOREIGN ACTIVITIES
In the last five years, the Company has undertaken development and
exploration activities in New Zealand and Russia, and is also pursuing
opportunities in Venezuela. The Company's investment in these projects was
approximately $15.1 million at December 31, 1997. Russia has experienced and
continues to experience social, political and economic instability, and all of
the Company's operations overseas are subject to various additional risks,
including risks associated with foreign currency fluctuations, currency
controls, changes in laws (including laws regulating the import and export of
hydrocarbons) and political instability. There can be no assurance that future
developments in these regions, over which the Company has no control, will not
impair the Company's operations in these regions or result in a loss of part or
all of the Company's investment. See "--Leverage and Debt Service" and
"Business and Properties--Foreign Activities."
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COMPETITION
The Company operates in a highly competitive environment, competing
with major integrated and independent energy companies for customers, for the
acquisition of desirable oil and natural gas properties, as well as for the
equipment and labor required to develop and operate such properties. Many of
these competitors have financial and other resources substantially greater than
those of the Company. See "Business and Properties--Competition."
CONCENTRATION OF CREDIT
The Company extends credit, primarily in the form of monthly oil and
gas sales and joint interest owners receivables, to various companies in the
oil and gas industry, which results in a concentration of credit risk. The
concentration of credit risk may be affected by changes in economic or other
conditions and may accordingly impact the Company's overall credit risk.
During the year ended December 31, 1997, three oil or gas purchasers each
accounted for 10% or more of the Company's revenues, with those purchasers
together accounting for approximately 42% of revenues. An economic downturn or
similar occurrence that affects such purchasers concurrently could prevent the
Company from collecting significant amounts of revenue owed to it by such
purchasers, and could thereby result in a material adverse effect on the
Company's financial condition and results of operations.
DEPENDENCE ON KEY PERSONNEL
The Company depends, and will continue to depend in the foreseeable
future, on the services of its officers and key employees with extensive
experience and expertise in evaluating and analyzing producing oil and gas
properties and drilling prospects, maximizing production from oil and gas
properties and marketing oil and gas production. The ability of the Company to
retain its officers and key employees is important to the continued success and
growth of the Company. There can be no assurance that the Company will be
successful in retaining such employees, and the loss of key personnel could
have a material adverse effect on the Company. See "Management."
GOVERNMENTAL AND ENVIRONMENTAL REGULATION
The Company's operations are subject to regulation under a wide range
of foreign, federal, state and local laws, rules, orders and regulations
relating to the development, production, marketing, transportation and storage
of crude oil and natural gas, protection of the environment and employee health
and safety. In particular, such laws, rules and regulations govern air and
water emissions, the use, management and disposal of hazardous and
non-hazardous substances and wastes, and investigation and cleanup obligations
relating to contaminated properties. Certain such laws and regulations require
well and facility sites to be closed and reclaimed in accordance with
requirements that may vary from one jurisdiction to another. The Company
frequently buys and sells interests in properties that have been operated in
the past, and as a result of such transactions may have retained or assumed
cleanup or reclamation obligations relating to its own former operations or
those of third parties. The Company is required to obtain and maintain
compliance with permits and other approvals for its drilling, reworking and
recompletion operations, for transporting hydrocarbons and other materials and
wastes, and for other aspects of its operations. The various government
authorities that issue such permits may modify, renew or revoke them under
certain circumstances. Failure to comply with requirements under its permits
or other applicable laws and regulations could subject the Company to
substantial civil or criminal penalties and to the temporary or permanent
curtailment or cessation of all or a portion of its operations. Under certain
laws and regulations, the Company may also be subject to strict, joint
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and several liability in connection with releases, or threatened releases, of
hazardous substances. In addition, the Company may be subject to personal
injury or property damage claims relating to violations of environmental laws
and regulations, the cleanup of contaminated properties or reclamation of
former fields or exposure to hazardous substances. The Company's costs of
maintaining compliance with its permit requirements and with other
environmental laws and regulations can be substantial, and there can be no
assurance that such requirements will not have a material adverse effect on the
Company's business results of operations and financial condition.
Certain laws and regulations also require the Company to demonstrate
financial responsibility for drilling and operations, and impose various
reporting requirements. In addition, most states in which the Company owns and
operates properties have regulations governing conservation matters, including
provisions for the unitization or pooling of oil and natural gas properties,
the establishment of maximum rates of production from oil and natural gas wells
and the regulation of the spacing, plugging and abandonment of wells. Many
states also restrict production to the market demand for oil and natural gas
and several states have indicated interest in revising applicable regulations
in light of the persistent oversupply and low prices for oil and natural gas
production. These regulations may limit the rate at which oil and natural gas
could otherwise be produced from the Company's properties. Some states have
also enacted statutes prescribing ceiling prices for natural gas sold within
the state. The Company cannot predict how existing laws and regulations may be
interpreted by enforcement agencies or court rulings, whether additional laws
and regulations will be adopted, or the effect such changes may have on the
Company's business, results of operations or financial condition. See
"Business and Properties--Regulations--Environmental Regulations."
YEAR 2000 ISSUE
The Year 2000 issue results from computer programs written with date
fields that cannot distinguish between the year 1900 and 2000. The Company is
currently studying the steps necessary to make the Company's operations Year
2000 compliant. These steps include upgrading, testing and certifying its
computer systems and field operation services and obtaining Year 2000
compliance certification from all of the Company's important business
suppliers. The Company does not believe that costs incurred to address the
Year 2000 issue with respect to its financial and administrative systems will
have a material effect on the Company. The Company is uncertain, however, as
to the impact that the Year 2000 issue will have on its field operation systems
or as to how the Company will be indirectly affected by the impact that the
Year 2000 issue will have on the companies with which it conducts business.
For example, the pipeline operators to whom the Company sells gas, as well as
other customers and suppliers, could be prone to Year 2000 problems that could
not be assessed or detected by the Company. In these cases, the effect of the
Year 2000 issue may be material. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Year 2000."
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TAX RISKS
The following is a discussion of the material federal income tax
consequences that are generally applicable under existing United States federal
income tax law to Investors that vote to liquidate the Partnership in which
such Investors are partners for federal income tax purposes and also for those
that elect to subscribe to shares of Company stock in lieu of receiving all or
some of their Partnership liquidating distribution. The discussion is based
upon the Code, Treasury Regulations, judicial authority, published positions of
the Internal Revenue Service (the "Service") and other applicable authorities
(including to the extent applicable, certain private letter rulings, all as in
effect on the date hereof and all of which are subject to change, possibly
retroactively. This discussion does not address all aspects of federal income
taxation that may be material or relevant to particular investors in light of
their own personal circumstances. This discussion does not address any aspect
of state, local or foreign tax law or certain aspects of tax law solely
applicable to qualified plans and individual retirement accounts, all as
defined under the Code, and is not applicable to nonresident aliens, foreign
corporations, debtors under the jurisdiction of a court in a case under federal
bankruptcy laws or in a receivership, foreclosure or similar proceedings, or an
investment company, financial institution or insurance company. No ruling has
been sought from the Service in connection with tax aspects related to the
proposed transactions. Accordingly, no assurance can be given that the Service
will not take a position contrary to any of the tax aspects described below.
For a more complete discussion of the federal income tax consequences to
Investors in Partnerships that sell their properties and for those that elect
to subscribe to shares of Company stock see "Federal Income Tax Consequences of
the Proposals" and "Material Federal Income Tax Considerations of Electing to
Receive Common Stock in lieu of Cash Upon Partnership Liquidation."
Additionally, a summary discussion of the tax consequences upon the sale of
Partnership properties is contained in each supplement to this Proxy. See
"Summary of Federal Income Tax Consequences."
INVESTORS THAT ARE TAX EXEMPT PLANS
Investors that are Tax Exempt Plans that have directly or indirectly
acquired their Partnership interests through debt financing, as defined in the
Internal Revenue Code of 1986, as amended, or that have invested in
Partnerships that own interests in operating properties may be subject to
taxation on the Partnership's sale of property and the liquidation of the
Partnership. See "Federal Income Tax Consequences of Adoption of the
Proposal--Tax Treatment of Tax Exempt Plans--Debt-Financed Property." Tax
Exempt Plans, other than those described above, are not expected to be subject
to federal income tax on the sale of properties.
INVESTORS SUBJECT TO FEDERAL INCOME TAX
Investors that are subject to federal income tax are expected to
recognize and realize taxable gain or loss, or a combination of both gain and
loss on the sale of Partnership property and the subsequent liquidation of the
Partnerships. The character of the gain or loss depends on certain factors
specific to the Partnerships and to the Investors. For a broader discussion of
the tax consequences, Investors should read "Federal Income Tax Consequences of
Adoption of the Proposal."
PAYMENT FOR STOCK WITH LIQUIDATING DISTRIBUTION
Investors that subscribe for Company stock pursuant to this offering
will not actually receive some or all of the cash liquidating distribution of
their partnership interests to which they otherwise would be entitled. The
amount of any cash liquidating distribution they actually receive depends upon
the purchase price to be paid for the shares they elect to and are entitled to
receive pursuant to the terms of this offering. For federal
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income tax purposes, Investors subscribing for shares of Company stock will be
treated as though they had purchased those shares for cash, even though they
never had actual possession of the cash used to acquire the shares.
Additionally, the fact that such Investors elect to acquire shares rather than
receive cash in liquidation of their partnership interests will not affect the
federal income tax consequences attending the liquidation of their partnership
interests. Because the purchase of shares of Company stock will reduce the
cash received by the Investor on partnership liquidation, to the extent that
Investors owe federal income tax as a result of the liquidation, they may not
receive sufficient cash to pay some or all of any tax they may owe on the
liquidation. Such Investors owing tax as a result of the liquidation will have
to pay such tax from sources other than distributions from their partnership.
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SPECIAL FACTORS
BACKGROUND
The Partnerships were formed between 1986 and 1994, with approximately
60% of the Partnerships having been in existence for over seven years. As
contemplated when the Partnerships were organized, the hydrocarbon production
of the producing properties in which the Partnerships own interests have
steadily declined over time. All of the Partnerships own interests in
properties with substantial natural gas reserves, and many of the Partnerships'
reserves are comprised almost totally of natural gas. The general improvement
in the prices for natural gas over the last several years, relative to such
prices in the mid-1990's, make this an appropriate time, especially in light of
the age of the Partnerships, to consider Proposals to sell their Property
Interests. For the reasons set out below, the Managing General Partner
believes that the Proposals under which it would purchase all of the oil and
gas assets owned by the Partnerships are fair to Investors and are structured
in a manner that attempts to realize the highest value for each Partnership's
Property Interests, given that the purchase prices are based upon the higher of
two estimates on a Partnership-by-Partnership basis of the fair market value of
the Partnerships' Property Interests by three independent Appraisers to which
has been added a 7.5% premium. The purchase of the oil and gas assets of any
particular Partnership is not conditioned upon the purchase of the oil and gas
assets of any Partnership other than a Partnership's companion Partnership.
PURPOSE AND EFFECT OF THE PROPOSALS
By selling all of their respective oil and gas assets to the Managing
General Partner, proceeds from such liquidating sale will be distributed to the
partners in the Partnerships and the Partnerships will be liquidated, dissolved
and terminated. These Proposals are subject to a number of conflicts of
interest, all of which are discussed in greater detail below. The purpose of
the Proposals is to provide for the sale of the Partnerships' oil and gas
assets because it is time that the business of the Partnerships be concluded,
and to do so in a way intended to maximize the sale price of the Partnership's
oil and gas assets. The Managing General Partner is proposing to purchase
these oil and gas assets from the Partnerships because it believes that its
knowledge of the Properties allows it to pay the highest price for such assets.
The reasons for proposing the sale of the Partnerships' Property Interests at
this time are described below under "Reasons for the Proposal--Reasons for Sale
of Assets at this Time."
Approval of the Proposals will have the following effects:
1. The Managing General Partner will purchase all of the oil and gas
assets of each Partnership, and if applicable, its Companion
Partnership which approve their respective Proposals;
2. Such Partnerships, having sold all of their respective oil and gas
assets, will be required to liquidate and distribute their assets
(principally the cash proceeds from sale of their Property Interests)
to their partners (including the general partners) in accordance with
their respective ownership interests in the Partnerships;
3. Investors will be given the option of receiving shares of Common Stock
in amounts that they choose on an individual basis in lieu of some or
all of the cash they would be entitled to receive upon their
Partnerships' liquidation, as discussed in detail below under
"Investor Election to Participate in Offering of 2,500,000 shares of
Common Stock to Eligible Purchasers";
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4. The Managing General Partner intends to spend capital needed to
develop non-producing reserves on certain of the Partnerships'
Property Interests which it acquires, although the properties in which
such investment will be made have not yet been determined; and
5. Investors in the Partnerships will be taxed on the sale of their
Partnerships' oil and gas assets, which will result in a gain or a
loss depending upon the particular Partnership in which an Investor
has an ownership interest, and dependent upon the individual tax
status of that Investor.
PARTNERSHIP PROPERTY INTERESTS
Tabulations presenting information specific to a Partnership are set
out in each Partnership's specific Partnership Supplement on those fields in
which such Partnership has Property Interests which constitute 10% or more of
the Partnership's PV-10 Value at December 31, 1997. A Partnership's "PV-10
Value" is the estimated future net cash flows (using unescalated prices) from
production of proved reserves attributed to such Partnership's Property
Interests, discounted to present value at 10% per annum (See "Glossary of
Terms"). The information set forth in the Partnership Supplement includes the
location of each field, the number of wells and operators, together with
information on the percentage of the Partnership's total PV-10 Value on
December 31, 1997, attributable to each of these fields. Information is also
provided regarding such percentage of the Partnership's 1997 production (on a
volumetric basis) from each of these fields.
REASONS FOR THE PROPOSALS
THE REASONS FOR PROPOSING THE SALE OF THE PARTNERSHIP'S PROPERTY
INTERESTS AT THIS TIME ARE DESCRIBED IN DETAIL FOR EACH PARTNERSHIP IN THAT
PARTNERSHIP'S SUPPLEMENT INCLUDED WITH THIS JOINT PROXY STATEMENT/PROSPECTUS
UNDER "SPECIAL FACTORS--REASONS FOR THE PROPOSAL," AND VARY FROM PARTNERSHIP TO
PARTNERSHIP DEPENDING UPON, AMONG OTHER FACTORS, A PARTNERSHIP'S AGE AND THE
NATURE OF PROPERTY INTERESTS WHICH IT OWNS. The Managing General Partner
believes that it is in the best interest of the Investors for their
Partnerships to sell their Property Interests at this time and to dissolve the
Partnerships and make a final liquidating distribution to its Partners for the
reasons discussed below. Certain reasons are common to all Partnerships.
Other reasons vary from Partnership to Partnership and are highlighted below.
Current Liquidating Distribution Lowers Volatility Risk
The Partnerships have been in existence for between four and twelve
years. The Managing General Partner believes that the ability to receive the
estimated liquidating distribution in one lump sum currently, rather than
smaller amounts over a longer period, is one of the benefits of the Proposals,
without the risk of such distributions being negatively affected by oil and gas
price changes. Receiving the value of the Partnerships' assets at one time
avoids the risk of subjecting future revenues and cash distributions of
Investors to the continued and extreme volatility of oil and gas prices, as
well as inherent geological, engineering and operational risks, which could
affect future returns. It is also the Managing General Partner's belief that
improvements over the last several years in the level of natural gas prices,
relative to such prices in the mid-1990's, make this an appropriate time to
consider the sale of the Partnerships' Property Interests and increases the
likelihood of maximizing the value of the Partnerships' assets, although the
future prices and market volatility cannot be predicted with any accuracy.
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Decreasing Cash Flow While Expenses Continue
Although the amount differs among Partnerships, other than as to the
16 Partnerships formed in 1993 and 1994 a majority of the estimated ultimate
recoverable reserves in which the Partnerships have an interest have been
produced. As a result of the depletion of the Partnerships' oil and gas
reserves, the Managing General Partner believes the asset base and future net
revenues of the Partnerships formed between 1986 and 1992 no longer justify the
continuation of operations. The Partnership's underlying interests in oil and
gas reserves are expected to continue to decline as remaining reserves are
produced. Declines in well production are based principally upon the maturity
of the wells, not on market factors. These declines will occur while operating
costs and general and administrative expenses continue, which are relatively
fixed amounts. Each producing well requires a certain amount of overhead
costs, as operating and other costs are incurred regardless of the level of
production. Likewise, direct costs and/or general and administrative expenses
such as compliance with the securities laws, producing reports to partners and
filing partnership tax returns do not decline as revenues decline. By
accelerating the liquidation of the Partnership, those future administrative
costs will be avoided by the Partnerships.
Effect of Oil and Gas Prices on Value
The Managing General Partner believes that the key factor affecting
the Partnerships' long-term performance has been the decrease in oil and
particularly gas prices that occurred subsequent to the purchase of Partnership
Property Interests. Additionally, prices are expected to continue to vary
widely over the remaining life of the Partnerships, and such changes in prices
will affect future estimates of revenues from continued operations of the
Partnerships, especially for the 39 Partnerships with less than a third of
their estimated remaining recoverable reserves remaining for future production
(all but two of the Partnerships formed prior to the second quarter of 1992).
Many Partnerships have only a small amount of their ultimate recoverable
reserves remaining for future production. Because of small amounts of
remaining reserves, even if oil and gas prices were to increase in the future,
such increases would be unlikely to have a material positive impact on the
total return on investment to Investors in view of the expenses of the
Partnerships as described above.
Non-Producing Reserves
For those 18 Partnerships formed in the fourth quarter of 1986, in the
first three quarters of 1987, and in the period from the fourth quarter of 1992
through the second quarter of 1994, a majority of the estimated remaining
recoverable reserves attributable to those Partnerships' Property Interests are
proved non-producing reserves. Non- producing reserves generally fall into two
categories: (1) undeveloped reserves, which require substantial expenditures
by the working interest owners for the drilling of new wells to recover such
reserves; and (2) behind-pipe reserves, which are unlikely to be producible for
many years because behind-pipe reserves require completion in a different
producing zone, which does not take place until production is depleted from the
currently producing zone. Recovery in amounts great enough to significantly
impact the results of those Partnerships' operations and their ultimate cash
distributions can only occur after currently producing zones are depleted in
many years, or with the investment of new capital. As provided in the
Partnership Agreements, the Partnerships expended all of the Investors' net
commitments for the acquisition of Property Interests many years ago, and they
no longer have capital to invest in improvement of the properties through
secondary or tertiary recovery.
The most important factor leading to the significant proportion of
behind-pipe or undeveloped reserves currently owned by the Partnerships has
been the depletion of most of the Partnerships' proved producing
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reserves, resulting in the growth over time in the proportion of the
Partnerships' total assets comprised of non- producing reserves. Thus,
non-producing reserves which were a small proportion of each Partnership's
reserves when its oil and gas assets were purchased have remained and grown to
comprise a larger proportion of the Partnerships' remaining assets.
A limited amount (less than 10%) of the capital of the Operating
Partnerships was reserved for workover, completion or development activity, the
Partnerships were not intended to engage in material drilling activities. The
Partnerships were formed to distribute cash from sale of Partnership's oil and
gas production to Investors on a current basis. The current level of cash flow
of the Partnerships is not sufficient to pay for meaningful drilling activities
or to support borrowing activities for that purpose. Even if cash flow were
allowed to be used for drilling by a Partnership's limited partnership
agreement, this would require suspension of cash distributions for an extended
period.
Reasons for Sale of Assets at this Time
The Managing General Partner believes that this is an appropriate time
for the Partnerships to sell their Property Interests due to its perception of
the marketplace, including estimates as to future oil and gas prices, the cash
flow of the Partnerships and the character of their reserves. The Managing
General Partner believes that after significantly depleting producing oil and
gas properties, they become less attractive to prospective purchasers because
of less cash flow. Additionally, the Partnerships' limitations on capital
invested in drilling activities in recent years also makes the Property
Interests less attractive to prospective purchasers. Although the price of oil
has fallen significantly in 1998, gas prices have declined but to a lesser
degree. Given the fact that the reserves of the Partnership Properties and
their recent production consist principally of gas, this is believed to be a
good time to sell the Partnership Properties to avoid the risk that gas prices
might fall to levels equivalent to those for oil. At the current time the
marketplace's perception is that gas prices are likely to increase. Based
upon its experience in the industry and past historical trends, the Managing
General Partner believes that it is often preferable to sell based upon
perceptions of future prices. Moreover, the sale at this time by any
Partnership in conjunction with the other 62 Partnerships to whom Proposals
have been made allows the costs of the transactions to be spread among a larger
number of entities, which costs are likely to be much higher if such asset
sales were made on an individual Partnership basis or by small groups of
Partnerships over an extended period of time.
Investors' Tax Reporting
Investors will continue to have a partnership income tax reporting
obligation with respect to his Units as long as the Partnerships continue to
exist. There is no trading market for the Units, so Investors generally are
unable to dispose of their Units. See "Business of the Partnership--No Trading
Market." Following the approval of the Proposal and the sale of the
Partnerships' Property Interests and dissolution of the Partnerships, Investors
will realize gain or loss, or a combination of both, under federal income tax
laws. Thereafter, Investors will have no further tax reporting obligations
with respect to the Partnerships. The dissolution of the Partnerships will
also allow certain Investors to take a capital loss deduction for syndication
costs incurred in connection with formation of their Partnerships. See
"Federal Income Tax Consequences of Adoption of the Proposal."
INDEPENDENT APPRAISAL OF THE FAIR MARKET VALUE OF PROPERTY INTERESTS OF THE
PARTNERSHIPS
The Special Transactions Committee selected H.J. Gruy and Associates,
Inc. ("H.J. Gruy" or "Gruy"), J.R. Butler and Company ("J.R. Butler" or
"Butler") and CIBC Oppenheimer Corp. ("CIBC Oppenheimer")
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to estimate the fair market value of the Property Interests of each of the
Partnerships. Collectively, H.J. Gruy, J.R. Butler and CIBC Oppenheimer are
referred to herein as the "Appraisers," and H.J. Gruy and J.R. Butler together
are sometimes referred to herein as the "Petroleum Engineering Consultants."
The Special Transactions Committee determined that having three
independent appraisers collectively determine the fair market value for a cash
purchase of the Partnerships' Property Interests would protect Investors by
attempting to address the conflicts of interest in the sale of such Property
Interests to the Managing General Partner. The Appraisers were selected based
upon the Special Transactions Committee's assessment of their professional
reputations and qualifications, capabilities, experience and responsiveness.
The Special Transactions Committee believes that using the three Appraisers
working collectively provides the distinct professional expertise of each firm,
and gives the Partnerships the benefit of the independent analytic methods of
the different disciplines of petroleum engineering and investment banking,
resulting in a determination of fair market value which is both independent and
comprehensive.
One of the three Appraisers, H.J. Gruy, is the independent petroleum
engineering firm most familiar with the properties in which the Partnerships
have interests and has prepared the annual reserves audit and independent
reserve report upon the Partnerships' reserves since inception of each of the
Partnerships. J.R. Butler and H.J. Gruy together are actively involved as a
principal part of their businesses in the evaluation of producing oil and gas
properties, and both are widely recognized in their field. The Petroleum
Engineering Consultants are independent consulting firms as provided in the
Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information promulgated by the Society of Petroleum Engineers ("SPE"). As an
internationally known investment banking firm with broad experience in the oil
and gas industry, CIBC Oppenheimer has used additional methods of analysis and
considered other factors and perspectives in evaluating the Partnerships'
Property Interests.
The Managing General Partner did not instruct the Appraisers as to
pricing, cost or other economic parameters or methods or the assessment of
reserves characteristics, nor did it limit the scope of their investigation for
purposes of preparing their appraisals. The Managing General Partner provided
the Petroleum Engineering Consultants with basic evaluation data for their use
in determining each Partnership's reserves and their value. The Petroleum
Engineering Consultants prepared their own reserves audit of the Property
Interests. The Managing General Partner did not set the amount of
consideration to be paid to the Partnerships for their Property Interests nor
provide any information to the Appraisers on amounts to be paid to the
Investors. The amount of consideration to be paid was determined by the
Special Transactions Committee based upon the Appraisers' assessment of the
fair market value of those interests. The Appraisers did not opine on the
fairness of the transaction to the Investors, and the Managing General Partner
has not acquired separate reports or opinions regarding the fairness to the
Investors of the prices at which the Partnerships' Property Interests will be
sold to the Managing General Partner if the Proposals are approved by the
Investors.
QUALIFICATIONS OF APPRAISERS
Gruy is an established independent petroleum engineering firm in
Houston, Texas. Gruy's predecessor firms were founded by its current Chairman,
H.J. Gruy in 1950. Gruy is engaged solely in the business of petroleum
evaluation and engineering studies for public and private oil and gas companies
with oil and gas properties in North and South America, Africa, Russia and the
Far East. Gruy has extensive experience evaluating properties in all of the
areas in which the Partnerships own Property Interests. Gruy has completed
over 17,000 assignments for oil and gas companies, commercial banks, investment
banks, and governments. Over the past four years, Gruy has added more than 280
new clients.
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J.R. Butler is an established worldwide oil and gas consulting firm
organized in 1948 by Mr. J.R. Butler, Sr. and has been headquartered in
Houston, Texas since its founding. J.R. Butler has extensive experience in
reserves estimation, property evaluation, formation evaluation, petrophysical
support for geophysical and exploration geology, drilling operations,
production surveillance, unitization and design and supervision of workovers.
Over the last 20 years Butler has performed projects for more than 350 clients,
which include law firms, financial institutions, oil and gas operators,
research/academic institutions, service companies, individual investors and
government bodies, and has been involved with more than 140 major consulting
projects involving evaluation of U.S. oil and gas properties. Approximately
50% of Butler's work in 1997 was devoted to property evaluations. Butler
administered and analyzed the annual "Evaluation Parameters Survey" for the
Society of Petroleum Evaluation Engineers ("SPEE") during the first 15 years of
its publication from 1982 to 1996.
CIBC Oppenheimer, a CIBC World Markets Company, is an internationally
recognized investment banking firm with 31 offices worldwide and over 8,000
employees. CIBC Oppenheimer was selected by the Special Transactions Committee
to serve with the Petroleum Engineering Consultants as an appraiser based upon
CIBC Oppenheimer's substantial experience in oil and gas property purchase and
sale transactions, familiarity with the Managing General Partner, and
familiarity with oil and gas company operations and the oil and gas industry in
general. CIBC Oppenheimer regularly engages in the valuation of oil and gas
businesses and their securities in connection with mergers and acquisitions,
negotiated underwritings, private placements and other corporate purposes.
FAIR MARKET VALUE
For each Partnership, the Petroleum Engineering Consultants estimated
the aggregate fair market value of each Partnership's Property Interests as of
December 31, 1997. CIBC Oppenheimer also estimated a fair market value of the
same Property Interests at the same date. For each Partnership, the Special
Transactions Committee chose the higher of these two determinations as the Fair
Market Value for the purchase of these interests and the Board of Directors of
the Company determined to pay a 7.5% premium above the fair market value to
purchase the Partnerships' Property Interests. The valuation estimates of the
Appraisers are attached to specific Partnership's Supplement. The PV-10 Value
for each Partnership prepared on an annual basis by H.J. Gruy of the same
Property Interests as of the same date is also set out in the specific
Partnership's Supplement. The valuations of the Appraisers do not in any
manner address the underlying business decision to sell these Property
Interests. Moreover, the valuation estimates of the Appraisers are necessarily
based upon the market, economic and other conditions as they existed on the
dates specified or could be evaluated as of the date of preparation of the
valuations.
The Petroleum Engineering Consultants arrived at a fair market
valuation estimate, which is discussed in detail under "--Valuation by
Petroleum Engineering Consultants" below and is based upon appraisal of the
projected discounted cash flow from the various Property Interests. On the
other hand, the investment banking firm of CIBC Oppenheimer made a valuation
estimate for each Partnership based upon the application of multiple
quantitative and qualitative factors. The quantitative factors include, among
other things, a review of relevant valuation criteria from comparable
acquisitions of both oil and gas properties and companies which are
predominantly active in the oil and gas industry, and a review of valuation
criteria for relevant publicly traded oil and gas companies.
Although CIBC Oppenheimer was not directly involved in the work
performed by the Petroleum Consultants, it did review both the methodology
employed and the resulting analysis from the application of the approach used
by the Petroleum Engineering Consultants. In turn, although the Petroleum
Engineering
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Consultants were not directly involved in the evaluation work performed by CIBC
Oppenheimer, they provided input to, and consulted with, CIBC Oppenheimer as to
the characteristics of certain groups of Property Interests. As a result of
their individual and collective work, the Petroleum Engineering Consultants
estimated a fair market valuation for groups of properties that are related
geographically, geologically or by time of acquisition by the Partnerships (a
"Partnership Group") in which the Partnerships have Property Interests, and
CIBC Oppenheimer estimated a fair market valuation for each such property
group. These valuation amounts were then divided among the Partnerships which
own Property Interests in each property group in proportion to their respective
ownership interests therein. This generated valuation estimates for each
Partnership. After presentation of the two valuation estimates for each
Partnership to the Special Transactions Committee, the committee determined
that the Fair Market Value for each Partnership was the higher of the two
values estimated by the Petroleum Engineering Consultants and CIBC Oppenheimer.
This necessarily matches the definition of "Fair Market Value," which is the
maximum price that a willing buyer will pay and at which a willing seller will
sell at a given point in time at which the buyer is under no compulsion to buy
and the seller is not compelled to sell, both having reasonable knowledge of
all the material circumstances.
VALUATION BY PETROLEUM ENGINEERING CONSULTANTS
The value estimate from the Petroleum Engineering Consultants uses the
"income approach." The income approach for proved producing properties reduces
the discounted future net cash flows before federal income tax to a fair market
value by multiplying such cash flow by a suitable fraction that accounts for
the risk associated with the purchase of that cash flow stream. For proved
developed non-producing and proved undeveloped reserves, the risk adjustments
are generally more severe for a variety of reasons, including the necessity of
making a capital investment when it is assumed that the capital is invested
with certainty and the resulting operating cash income stream is burdened with
the uncertainty.
The Petroleum Engineering Consultants audited the estimates of proved,
probable and possible reserves and future net revenues therefrom prepared by
the Managing General Partner utilizing standard petroleum engineering methods.
For properties with sufficient production history, reserves estimates and rate
projections were based primarily on extrapolation of established performance
trends and reconciled, whenever possible, with volumetric and/or material
balance calculations. For the undeveloped locations, reserves were determined
by a combination of volumetric calculations (geologic mapping) and analogy.
Volumetrically determined reserves or those determined by analogy are generally
subject to greater qualifications than reserve estimates supported by
established production decline curves and/or material balance calculations.
The Petroleum Engineering Consultants audited the determination and
classification of proved reserves in accordance with Securities and Exchange
Commission guidelines (with the exception of having employed escalated prices
and costs). The definitions used by the Petroleum Engineering Consultants for
the unproved reserves conform to those promulgated by the Society of Petroleum
Engineers, Inc. (SPE) and the World Petroleum Congresses (WPC).
Basic evaluation data used by the Petroleum Engineering Consultants,
including ownership and other data, logs, maps, production data, tests,
technical information, estimates of drilling, completion and workover costs and
operating costs, were obtained principally from the Managing General Partner.
Benchmark gas and oil prices were $2.38 per MMBtu and $16.00 per barrel for
West Texas Intermediate, respectively, which were based upon year-end 1997
prices (before adjustments for Btu content for gas and gravity variances for
oil as well as transportation charges and geographic location) and then
escalated at a rate of 3.5% per annum for a period of 15 years. Operating
costs and projected investments were also escalated at the rate of 3.5% per
year for 15 years. The Petroleum Engineering Consultants recommended this
escalation scenario based on rates being used by banks, oil and gas industry
sources, the U.S. government and other oil and gas companies which
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acquire producing properties. The estimates of future net cash flow consisted
of those revenues expected to be realized from the sale of the estimated
reserves after deduction of royalties, ad valorem and production taxes, direct
operating costs, excess costs and required capital expenditures, when
applicable. Future net cash flow was determined before the deduction of
federal income tax. The Petroleum Engineering Consultants prepared their value
estimates by applying qualitative risk adjustments considered by them to be
appropriate for the various reserves categories against the spread of
discounted future net cash flow values obtained from an escalated pricing
scenario.
The reserves and the resulting "value estimates" made by the Petroleum
Engineering Consultants are not exact quantities. Future conditions may affect
the recovery of estimated reserves and revenue, and all categories of reserves
may be subject to revision and/or reclassification as more performance and well
data become available. Furthermore, any oil or gas reserves estimate or
forecast of production and income is a function of engineering and geological
interpretation and judgment and such estimates should be used with the
understanding that additional information obtained subsequent to a study may
justify revisions which could increase or decrease the original estimates of
reserves and value.
In summary, the evaluation procedures used by the Petroleum
Engineering Consultants included:
o Reviewing technical and economic data presented by the
Managing General Partner relative to proved, probable and
possible reserves as of December 31, 1997.
o Examining the cash flow forecasts for individual wells and/or
production units for their quantified probable and possible
reserves.
o Reviewing the lease operating costs for individual wells
and/or production units for reasonableness.
o Preparing reserves and future performance estimates for the
audit evaluation utilizing standard petroleum engineering
methods. For wells and/or production units with sufficient
production history, reserves estimates and rate projections
were based primarily on extrapolation of established
performance trends. For the non-producing zones and
undeveloped locations, reserves were determined by a
combination of volumetric calculations and analogy.
o Estimating of drilling, completion and workover costs, which
was based on information supplied by the Managing General
Partner. Surface and well equipment salvage values and well
plugging and field abandonment costs were not considered in
the cash flow projections.
VALUATION BY CIBC OPPENHEIMER
In performing its analysis of the value of each Partnership's Property
Interests, CIBC Oppenheimer first reviewed the PV-10 Value at December 31, 1997
for each property group in which such Partnership has a Property Interest (a
"Property"). In addition, CIBC Oppenheimer reviewed the valuation estimates
prepared by the Petroleum Engineering Consultants for each Property.
Individual Partnerships own interests in a number of different Properties.
Therefore, CIBC Oppenheimer first focused upon valuing the individual
Properties and then subsequently valuing the Property Interests of each
Partnership in various Properties by allocating to each Partnership its
relevant share of the value attributable to different Properties in which it
has an interest.
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Working with the Petroleum Engineering Consultants, CIBC Oppenheimer
reviewed the Properties for characteristics which would allow them to be
divided into separate classifications. Of the total of 44 Properties, the
reserves of 34 Properties were determined to be comprised primarily of Proved
Developed Producing reserves ("PDP") which have comparable reserve
characteristics ("Conventional Case"). The remaining 10 Properties were
determined to have distinguishing or unique reserves characteristics in that
their reserves are comprised predominately of reserves in the Proved Developed
but Not Producing ("PDNP") and Proved but Undeveloped "(PUD") categories
(collectively, the "Non- Conventional Case").
The individual Properties in the Conventional Case group and the
Non-Conventional Case group were valued according to the following three
criteria (collectively and individually, the "Valuation Multiples"): value as a
percentage of PV-10 Value; value as a multiple of barrels of oil equivalent on
a revenue interest basis ("BOE") (See "Glossary of Terms"); and value as a
multiple of projected earnings before interest, taxes and depreciation,
depletion and amortization ("EBITDA") for 1998.
The Valuation Multiples were, in turn, developed from the application
of multiple quantitative and qualitative factors. The quantitative factors
include a review of relevant valuation criteria from comparable acquisitions of
both oil and gas properties and companies which are predominantly active in the
oil and gas industry, and a review of valuation criteria for relevant publicly
traded oil and gas companies (the "Analysis Factors").
The Valuation Multiples determined for the Properties in the
Conventional Case group and the Non-Conventional Case group were unique,
reflecting the different reserves characteristics of the two groups. Based
upon conversations with the Petroleum Engineering Consultants, CIBC Oppenheimer
applied a 20% adjustment factor to the Valuation Multiples used in the
Conventional Case in order to determine Valuation Multiples applied to the
Non-Conventional Case. The adjustment factor was applied to the
Non-Conventional Case because PDNP and PUD reserves are less valuable than PDP
reserves, and PDNP and PUD reserves have additional costs and risks involved in
bringing known reserves into production. Also associated with these types of
reserves are uncertainties as to the estimated quantities of oil and gas
included in such reserves and in the timing of first production and initial
production rates once such reserves are placed into production.
CIBC Oppenheimer applied its set of Valuation Multiples to a
mathematical model, with each valuation multiple given equal weight (e.g.,
33.3% each) to compute a weighted average value for each individual Property.
Each Partnership was allotted its respective proportionate share of individual
Properties ("Property Share") based upon the Partnership's Property Interest
in such Property in order to convert the value determined for the Properties
into values for an individual Partnership's Property Interests in each
Property. The CIBC Oppenheimer valuation estimate for each individual
Partnership is the cumulative total of that Partnership's respective Property
Shares.
Analysis Factors
Analysis of Relevant Publicly Traded Companies. Using publicly
available information, CIBC Oppenheimer compared selected projected operating
and financial data and ratios of the Managing General Partner to the
corresponding data and ratios of certain publicly traded oil and gas companies
considered by CIBC Oppenheimer to be reasonably comparable to the Managing
General Partner due to their focus primarily on exploring and developing oil
and gas reserves in the Mid-Continent and onshore Gulf Coast regions of the
U.S. and their similar business strategies, operations and market capabilities
(the "Selected Companies"). The Selected Companies consist of Abraxas
Petroleum, Bellwether Exploration, Comstock Resources, Cross Timbers Oil,
Gothic Energy, National Energy Group, Titan Exploration and Wiser Oil Company.
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Analysis of Comparable Property Acquisitions. CIBC Oppenheimer
reviewed publicly available information relating to certain acquisitions of
U.S. oil and gas companies that closed between March 10, 1994 and October 23,
1997, and had total transactions values between $20 million and $150 million.
These transactions consisted of 10 transactions in many of the same operating
regions in which the Partnerships own Property Interests and included the
following: Comstock Resources and Black Stone Oil; National Energy and
Alexander Energy; Alliance Resources and LaTex Resources; Melrose Petroleum
Group and Pentex Energy; PANACO and Goldking Companies; Alexander Energy and
American Natural Resources; Gothic Energy and Buttonwood Energy; Key Production
and Brock Exploration; ONEOK and PSEC; and ONEOK and Washita Production. These
selected transactions are not intended to represent the complete list of oil
and gas transactions which have occurred or been announced during this period;
rather, such transactions represent recent transactions involving publicly
traded oil and gas companies engaged in oil and gas exploration and production
activities that were deemed by CIBC Oppenheimer to operate in comparable
producing basins or have comparable financial and operating characteristics to
the Managing General Partner.
No company or transaction described above was directly comparable to
the Partnerships, their reserves, the Managing General Partner or the proposed
transaction. Accordingly, analysis of the results of the foregoing was not
simply mathematical or necessarily precise; rather, it involved complex
considerations and judgments concerning differences in financial and operating
characteristics of companies and other factors that could affect public trading
values.
Analysis of Comparable Reserve Acquisitions. CIBC Oppenheimer
reviewed selected acquisitions of oil and gas reserves from January 24, 1995 to
December 18, 1997, with aggregate purchase prices up to $150 million. The
selected acquisitions were in comparable geographic regions as the
Partnerships' Property Interests and these were reviewed for the consideration
paid in such transactions in terms of the aggregate purchase price paid as a
multiple of the reported total proved reserves on a BOE basis. This analysis
relies primarily on information obtained from John S. Herold, Inc. and may not
represent the complete list of oil and gas transactions with the given search
parameters that have occurred or been announced.
Valuation Multiples
Value as a Percentage of PV-10. CIBC Oppenheimer's analysis included,
among other things, the consideration of a company's market capitalization of
common stock as of April 7, 1998 plus total debt and preferred stock, less cash
and cash equivalents ("Aggregate Value") as a multiple of the Company's PV-10
Value as of the most recently reported date. Given the difficulty of
identifying truly comparable companies to the Managing General Partner which
are at the same stage of reserve exploration and development and have similar
financial and technical resources, none of the Selected Companies are identical
to the Managing General Partner. In addition, the Properties which comprise
the Non- Conventional Case are comprised predominately of PDNP and PUD reserves
which tend to be inherently difficult to analyze, given the significant impact
which future development capital could have relative to existing operations.
CIBC Oppenheimer applied its reference value of 78% to the Property's PV-10
Value. This reference value reflects a slight discount to the adjusted average
value at which comparable properties are acquired. This discount reflects (i)
the fact that the Managing General Partner itself trades at a discount to the
adjusted average value of its peers on a PV-10 Value basis, and (ii) that
certain oil and gas properties in the Properties are generally near the end of
their economic lives and require additional capital investment to attain
sustained and/or enhanced production. In the Non-Conventional Case, CIBC
Oppenheimer applied an adjustment factor of 20% to its reference value to
reflect higher proportions of PDNP and PUD reserves, an approach that is
consistent with conversations held between CIBC Oppenheimer and the Petroleum
Engineering Consultants.
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Value as a Multiple of BOE. CIBC Oppenheimer reviewed the
consideration paid in such transactions in terms of the price paid for the
common stock plus total debt, preferred stock and transaction costs less cash
and cash equivalents of such transactions as a multiple of the reported total
proved reserves on a BOE basis. Using comparable company acquisitions data,
the analysis of purchase price as a multiple of proved reserves on a BOE basis
indicated an adjusted average value of $4.90 per BOE for acquisitions of
comparable onshore Gulf Coast and Mid-Continent oil and gas companies while
comparable onshore Gulf Coast and Mid-Continent oil and gas properties were
acquired for $4.83 per BOE. Relative to other acquisition values, CIBC
Oppenheimer applied a $4.70 per BOE reference value, which represents a slight
discount to the aforementioned acquisition values, to reflect the fact that
certain individual properties in the Properties are near the end of their
economic lives. The degree of this discount was reduced, however, by the fact
that the Properties exhibit an above average gas reserve component. In the
Non-Conventional Case, CIBC Oppenheimer applied an adjustment factor of 20% to
its reference value to reflect higher proportions of PDNP and PUD reserves, an
approach that is consistent with conversations held between CIBC Oppenheimer
and the Petroleum Engineering Consultants.
Value as a Multiple of EBITDA. CIBC Oppenheimer's analysis included,
among other things, Aggregate Value as a multiple of projected EBITDA.
Projected EBITDA for the Managing General Partner and the Selected Companies
were based on estimates compiled by Institutional Brokers Estimate Service and
published estimates of selected investment banking firms, including CIBC
Oppenheimer.
CIBC Oppenheimer's reference value of 3.5x is slightly lower than the
trading value of the Managing General Partner relative to its projected 1998
EBITDA. This value is used to reflect the fact that certain oil and gas assets
in the Properties require significant additional capital investment to extend
their productive lives. In the Non- Conventional Case, CIBC Oppenheimer
applied an adjustment factor of 20% to its reference value to reflect higher
proportions of PDNP and PUD reserves, an approach that is consistent with
conversations held between CIBC Oppenheimer and the Petroleum Engineering
Consultants.
No company or transaction used in the analysis described above was
directly comparable to the Properties, the Managing General Partner or the
proposed transaction. Accordingly, analysis of the results of the foregoing
was not simply mathematical nor necessarily precise; rather, it involved
complex consideration and judgments concerning differences in financial and
operating characteristics of companies and other factors that could affect
public trading values.
Valuation Letters of CIBC Oppenheimer
The Special Transactions Committee retained CIBC Oppenheimer to
prepare for each of the Partnerships an independent fair market valuation of
the Property Interests held by the Partnerships. On April 20, 1998, CIBC
Oppenheimer delivered to the Special Transactions Committee letters for each of
the Partnerships (the "Valuation Letters") stating that, as of a certain date
and based upon and subject to the factors and assumptions set forth therein,
CIBC Oppenheimer's estimate of the value of the Partnership's Property
Interests. The appraisal report of CIBC Oppenheimer will be available to
Investors or representatives designated in writing for inspection and copying
during the solicitation period for the Proposals at the office of the Managing
General Partners, 16825 Northchase, Suite 400, Houston, Texas 77060 from 9:00
a.m. to 5:00 p.m. Monday to Friday during such period.
The full text of each of the Valuation Letters, which sets forth the
assumptions made, matters considered, and qualifications and limitations on the
review undertaken by CIBC Oppenheimer, is attached to the specific
Partnership's Supplement and is incorporated herein by reference. The summary
of the
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Valuation Letters set forth in this Joint Proxy Statement/Prospectus is
qualified in its entirety by reference to the full text of such letters.
Investors of the Partnerships are urged to read such letters in their entirety.
The Valuation Letters were provided to the Special Transactions Committee for
its information and is directed only to the estimates, from a financial point
of view, of the value of the Partnerships' Property Interests and does not
address the merits of the underlying decision by the Managing General Partner
or the Partnerships to engage in the sale of the Property Interests to the
Managing General Partner and does not constitute a recommendation to the
Partnerships' Investors as to how such Investors should vote on the approval of
the Proposals or any matter related thereto.
The summary set forth above does not purport to be a complete
description of the analyses performed by CIBC Oppenheimer. The fair market
value estimates involve various determinations as to the most appropriate and
relevant methods of financial analysis and the application of these methods to
the particular circumstances and, therefore, such estimates are not readily
susceptible to summary description. These estimations of fair market value
required CIBC Oppenheimer to exercise its professional judgment based on its
experience and expertise in considering a wide variety of analyses taken as a
whole. Each of the analyses conducted by CIBC Oppenheimer was carried out in
order to provide a different perspective on the transaction and add to the
total mix of information available. CIBC Oppenheimer did not form a conclusion
as to whether any individual analysis, considered in isolation, supported or
failed to support any one valuation methodology. Rather, in reaching its
conclusion, CIBC Oppenheimer considered the results of the analyses in light of
each other and ultimately reached its value estimate based on the results of
all analyses taken as a whole. Except as described herein, CIBC Oppenheimer
did not place particular reliance or weight on any individual analysis, but
instead concluded that its analysis, taken as a whole and that selecting
portions of its analyses and the factors considered by it, without considering
all analyses and factors, may create an incomplete view of the evaluation
process underlying its value estimate. In performing its analyses, CIBC
Oppenheimer made numerous assumptions with respect to industry performances,
business and economic conditions and other matters. The analyses performed by
CIBC Oppenheimer are not necessarily indicative of actual values or future
results, which may be significantly more or less favorable than suggested by
such analysis.
COLLECTIVE ANALYSIS OF PURCHASE PRICE
Thus, as described above, the Petroleum Engineering Consultants
individually audited the estimate of present value of future net cash flows
from the 44 property groups in which Property Interests are owned by the
Partnerships to whom similar proposals are being made to sell substantially all
of their assets and liquidate their Partnerships. The Petroleum Engineering
Consultants began their analysis based upon the year-end 1997 PV-10 Value of
each property audited by H.J. Gruy and together they re-evaluated reserve
quantities, projected operating costs and cash flows. The present value of
this reserves analysis was then derived by escalating year-end 1997 prices
($2.38 per MMBtu and $16.00 per barrel before adjustments for Btu content for
gas and gravity variances for oil as well as transportation charges and
geographic location) and costs by 3.5% per year for 15 years. This present
value was then adjusted for various individual field risks and risk adjustments
of proved non-producing reserves and proved undeveloped reserves. The result
of this collective analysis by the Petroleum Consulting Engineers was their
estimation of the fair market values of Property Interests owned by the
Partnerships as of December 31, 1997, which estimates are set out for each
Partnership in its specific Partnership Supplement.
CIBC Oppenheimer's evaluation of the Partnerships' Property Interests
began with the PV-10 Value of each property group, as calculated by Swift and
audited by H.J. Gruy, which Gruy reserve report is attached to each Partnership
Supplement as Attachment D. CIBC Oppenheimer then divided the property groups
("Property") into two categories. Those property groups with reserves
consisting primarily of proved
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developed producing reserves were placed in the "Conventional Case" category.
Those property groups with significant proved developed non-producing or
undeveloped reserves were placed in the "Non-Conventional Case" category. CIBC
Oppenheimer then valued each property group by applying the multiples discussed
under "Valuation Multiples" above in this section to each property group's
PV-10 Value, proved reserves on a BOE basis, and projected 1998 EBITDA. A
separate set of multiples was used for property groups in the Conventional Case
category and the Non-Conventional Case category, respectively. This provided
CIBC Oppenheimer with three estimated values for each property group. The
average of these three values yielded CIBC Oppenheimer's estimation of the fair
market value of each property group. CIBC Oppenheimer then allocated the
appropriate portion of the each property group's estimated fair market value to
the Partnership based upon the Partnership's Property Interest in each property
group. The result of this analysis by CIBC Oppenheimer was an estimation that
the fair market value of the Partnership's Property Interests which are set out
for each Partnership in its specific Supplement.
The Special Transactions Committee has determined that, in keeping
with the definition of Fair Market Value, the higher of these two estimations
of fair market value, represents the Fair Market Value of the Partnerships'
Property Interests, which are set out for each Partnership in its specific
Supplement. Accordingly, the fair market value estimation of the Petroleum
Consulting Engineers and the fair market value determined by CIBC Oppenheimer
were compared to each other and the higher of the two for each Partnership was
chosen as the Fair Market Value of the Property Interests owned by that
Partnership. The variations between the fair market value estimates prepared
by the Petroleum Consulting Engineers and CIBC Oppenheimer had a weighted
average deviation which ranged from 0.025% to 16%, with an average of 1%.
DETERMINATION OF PREMIUM OVER FAIR MARKET VALUE BY THE COMPANY
Choice of Higher of Two Appraisals
The Special Transactions Committee presented their recommendation to
the Board of Directors of the Company as to the Fair Market Value of the
Property Interests of the Partnerships. The proposed sale of the Partnerships'
Property Interests to the Managing General Partner and the procedures
established for the appraisal of fair market value for such interests was
approved by vote of all of the members of the Board of Directors (other than
one absent director) of the Company based upon the recommendation of the
Special Transactions Committee. The Board of Directors also determined to
consider whether it was appropriate to pay a premium over the Fair Market Value
in purchasing the Property Interests from each of the Partnerships.
Decision to Add 7.5% Premium
The Company determined that paying a 7.5% premium over the appraised
fair market value of the Partnerships' Property Interests was appropriate and
fair based upon the factors and for the reasons discussed below. The amount of
the premium principally was based upon management's experience in purchasing
properties which contain both producing reserves and drilling potential.
Because the Managing General Partner has served in that capacity on behalf of
all of the Partnerships for a number of years, it is intimately familiar with
the Property Interests owned by each of the Partnerships. The Managing General
Partner believes that if the Property Interests were to be sold to a third
party purchaser who was not equally familiar with those interests, it is likely
that the purchaser would discount the purchase price to account for that lack
of familiarity and perceived potential risks. If these interests are purchased
by the Company, then the additional cost and personnel often inherent in making
a property acquisition are not required, because the files and deed records
already exist in the Company's lease and computer systems, and conveyance and
title issues do not exist.
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Since 1979, the Company, on behalf of itself and others, has gained a wide
range of experience with the valuation of oil and gas properties and the prices
for their purchase and sale, having purchased $478 million of such properties
in 129 separate transactions.
In the judgment of the Company, the purchase of any Partnership's
Property Interests, together with interests in many of the same properties
owned by other Partnerships at approximately the same time, will result in
efficiencies to the Company in aggregating such interests. Swift's long-term
knowledge of the risks involved in these properties means that it is in a
better position to evaluate these risks than third parties.
Based upon the Company's experience in purchasing properties, the lack
of additional costs often incurred in purchasing oil and gas properties in
which the purchaser has owned no interest, and the Company's intimate
familiarity with these Property Interests and consequent ability to evaluate
acquisition risks, it was deemed appropriate to pay a premium representing the
benefit to the Company arising from these factors.
The amount of the premium principally was based upon management's
experience in purchasing properties which contain both producing reserves and
drilling potential. No attempt was made to distinguish between the Property
Interests owned by any particular Partnership, nor was any statistical or
analytical study prepared by the Company on a separate basis in the course of
determining the amount of this premium.
Other purchasers might have determined it inappropriate to pay a
premium, or if so, to pay a premium based upon other factors or in a different
amount. Because there has been no independent determination to pay this
premium or of its amount, and no fairness opinion has been requested regarding
this premium, conflicts of interest exist in its determination, although the
Managing General Partner believes, based upon its knowledge of the oil and gas
industry, its knowledge of the properties involved, its experience in
purchasing and selling oil and gas properties, and the benefits from purchasing
the Property Interests which are particular to the Company, that the amount
being offered to the Partnerships to purchase their Property Interests is fair.
Amounts to be Paid to Investors Upon Liquidation of their
Partnerships.
The evaluation of the fair market values of the Property Interests of
the Partnerships were based upon values as of December 31, 1997, including the
fair market value estimates by the Petroleum Engineering Consultants (using
pricing assumptions and reserve quantities at that time) which were in turn
based upon the audit of each of the Partnerships' total proved reserves at that
date by H.J. Gruy. As is the case with all oil and gas purchases, the purchase
is proposed to be made as of the date which the properties were evaluated (in
this case December 31, 1997). Obviously, the quantities of reserves being
purchased are reduced by production which takes place after the evaluation date
(net of the lease operating cost incurred to produce such reserves) but before
the purchase takes place.
Therefore, the actual purchase price to be paid to each Partnership
for its oil and gas assets is the purchase price set out in the table contained
in the Summary and the individual Partnership Supplement for each Partnership,
reduced by the net revenues that have been received by that Partnership for
production during 1998. Money received by each Partnership from the sale of
such production during 1998 has been paid to such Partnership. The
Partnerships have continued to make quarterly cash distributions during 1998.
A portion of 1998 revenues, therefore, have already been distributed to their
partners during 1998 and the remainder of revenues from 1998 production will be
distributed as part of that Partnership's liquidating distribution.
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Portion of Purchase Price Payable to the Managing General Partner
The total purchase price for the oil and gas assets of all 63
Partnerships is approximately $81 million. Of this amount, approximately $14
million represents the portion of the purchase price which is payable to the
Managing General Partner by virtue of the Managing General Partner's interest
in the Partnerships. Approximately $11 million of this is attributable to its
interests as a general partner and $3 million attributable to the units which
it has purchased under the right of presentment set out in the various
Partnership Agreements. Therefore, the amount payable to purchase all of the
oil and gas assets of all 63 Partnerships net of the amount distributable to
the Managing General Partner itself upon liquidation of the Partnerships is
approximately $67 million as of December 31, 1997 before any reduction for 1998
production.
FAIRNESS OF PROPOSED SALE
The Managing General Partner believes that the entire transaction
related to the Proposals involving the proposed method of sales of the
Partnerships' Property Interests is fair to Investors for the following
reasons, without giving any particular weight to any reason:
1. The Managing General Partner believes that the most important
element of the Proposals is the determination of the Fair
Market Values of the Partnerships' Property Interests. The
prices to be paid by the Company to purchase the Partnerships'
Property Interests was determined in the Managing General
Partners' sole judgment by adding a 7.5% premium to the higher
of the Appraisers' two estimates of the fair market value on a
Partnership-by-Partnership basis of the Partnerships' Property
Interests. Two of the three Appraisers are qualified
independent petroleum engineering firms and the other is an
investment banking firm. The factors and methods used by the
Appraisers in determining Fair Market Value are discussed in
detail under "Independent Appraisal of the Fair Market Value
of Partnerships' Property Interests."
2. No transaction will take place in a particular Partnership
unless the Proposal is approved by Investors holding at least
a majority of the interests in such Partnership (without any
vote by the Managing General Partner) and a similar Proposal
is approved by such Partnership's companion Partnership.
3. The Special Transactions Committee made the determination as
to the retention of the Appraisers and approved the fair
market value estimates provided by the Appraisers and
recommended the reports of the Appraisers to the Board of
Directors of the Company. The Special Transactions Committee
is comprised solely of independent directors of the Company.
4. If any of the Proposals are approved by Investors, it is
likely that the Managing General Partner will expend the
capital necessary to develop various non-producing reserves on
the Property Interests purchased by the Managing General
Partner. If all of the Property Interests which are
the subject of the Proposals are acquired by the Company, such
Property Interests in the aggregate will constitute less than
20% of the Company's total assets. Because the Managing
General Partner would be the beneficiary of any such increase
in value, the Managing General Partner is hereby offering to
Eligible Purchasers the opportunity to purchase up to
2,500,000 shares of Common Stock of the Company. There is no
requirement that any purchase of Swift's Common Stock be made.
See "Offer to Eligible Purchasers" below.
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5. In structuring the Proposals and related transactions, the
Managing General Partner considered that any sale of
Partnership Property Interests, whether to the Managing
General Partner or to a third party, would be a taxable
transaction. Thus, if an Investor subject to federal income
tax chooses to use the proceeds received on liquidation of
that Investor's Partnership to purchase Swift Common Stock,
tax will still have to be paid on the amount of any taxable
income resulting from the liquidation of that Investor's
Partnership, whether or not the Investor has available cash
proceeds remaining from his liquidating distribution after
some or all of such proceeds are used to purchase Common
Stock.
The individual Partnership Supplements contain an estimate of the
liquidating net cash distributions payable to Investors if their Partnership's
Proposal is approved, along with an estimate of the net cash distributions to
Investors from their Partnership continuing to operate for the remaining life
of that Partnership's reserves. In all but three Partnerships the estimated
amount receivable from continuing operations is higher than the amount which
Investors will receive if the Proposals are approved. Despite this difference,
which ranges from 3% to 48%, depending upon the particular Partnership, the
Managing General Partner believes that the Proposals are fair. The estimates
of distributions from continuing operations are based upon continuation of
current oil and gas prices over a 17 to 20 year period. Continued volatility
in the markets for oil and gas therefore make this estimation subject to
significant variance based upon pricing changes. In addition, there are
significant operational risks over such a long period of time to which each of
the Partnerships would be subject. Current cash distributions paid in one
lump sum currently are not subject to these risks.
The fairness of the Proposals for the 18 Partnerships formed in the
fourth quarter of 1986, the first three quarters of 1987, and between the
fourth quarter of 1992 and the second quarter of 1994, the majority of whose
proved reserves are non-producing, should be assessed in light of the benefit
to the Managing General Partner of being able to use its capital resources to
drill wells to develop undeveloped reserves, in addition to the possible
benefit of holding such interests for a period of time sufficient to allow
completion of wells in different zones in order to produce behind-pipe
reserves.
Notwithstanding the above, determinations made by the Special
Transactions Committee, the independent Appraisers' determination of the fair
market value of the properties, and the payment of a 7.5% premium does not
necessarily remove the substantial conflicts of interest which exist due to the
Managing General Partner acting on behalf of the Partnerships and also acting
as the purchaser of the Property Interests from the Partnerships. No fairness
opinion was requested or received regarding the ultimate purchase price to be
paid by the Managing General Partner to purchase the Partnerships' oil and gas
or assets. Rather than setting the purchase price for Partnership Property
Interests itself, the Managing General Partner determined it would be
preferable to request three different independent Appraisers, using two
different appraisal methods to determine fair market values at which such
Property Interests should be purchased. The Managing General Partner then
chose the higher of the two values for each Partnership. The Managing General
Partner believes that adding a 7.5% premium to the highest of the fair market
value determinations made by the three Appraisers only increases the amount to
be paid to Investors upon liquidation of their Partnerships and does not
require a separate fairness opinion. The Managing General Partner believes
that when the Appraisers rendered their opinion as to the "fair market value"
of each Partnership's Property Interests, inherent within that appraisal was
the appraiser's determination that these "fair market values" were "fair," or
such determination would not have been made. Consequently, no independent
fairness opinion upon the premium was requested. The determination of a
different third party purchaser as to the purchase price to be paid might be
more or less than that being proposed to be paid by the Managing General
Partner.
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The determination to submit proposals to Investors in which the
Managing General Partner would purchase the Property Interests of the
Partnerships was deemed by the Managing General Partner to be the most
preferable means of addressing the appropriate time for liquidation of the
Partnerships and the method of doing so. This decision was made after full
consideration by the Managing General Partner of its fiduciary obligations to
Investors. Furthermore, the decision to use three Appraisers, rather than one,
and to have the Appraisers actually set the fair market value for purchase of
the properties, rather than the Managing General Partner setting that value and
requesting a fairness opinion and the decision to add the 7.5% premium, was
based upon the Managing General Partner's consideration of the substantial
conflicts of interest which exist in the transactions covered hereby, which are
detailed herein.
FEDERAL INCOME TAX CONSEQUENCES OF ADOPTION OF THE PROPOSALS
GENERAL
In the opinion of Hoops & Levy, L.L.P., Special Tax Counsel, the
following summarizes material federal income tax consequences to the Investors
arising from the Partnerships' proposed sale of their oil and gas operating and
non- operating properties and liquidation pursuant to the Proposals. This
Section of the Registration Statement is subject to and conditioned upon all
matters set forth in the written opinion of Special Tax Counsel dated ________,
and included as an exhibit to the Registration Statement. As set forth herein,
statements of legal conclusions regarding tax consequences are based upon
relevant provisions of the Internal Revenue Code of 1986, as amended (the
"Code"), and accompanying Treasury Regulations, as in effect on the date
hereof, upon reported judicial decisions and published positions of the
Internal Revenue Service (the "Service"), and upon further assumptions that the
Partnerships constitute partnerships for federal tax purposes and that the
Partnerships will be liquidated as described herein. Statements of legal
conclusions regarding tax consequences also are based upon private letter
rulings dated October 5, 1987 and August 22, 1991, with respect to Swift Energy
Managed Pension Assets Partnerships and February 6, 1991, with respect to Swift
Energy Pension Partnerships. The laws, regulations, administrative rulings and
judicial decisions which form the basis for conclusions with respect to the tax
consequences described herein are complex and are subject to prospective or
retroactive change at any time and any change may adversely affect Investors.
Although the Special Tax Counsel understands that Investors will rely to a
degree on its opinion, Investors should recognize that an opinion of Special
Tax Counsel represents merely such counsel's best legal judgment and has no
binding effect on any federal or state governmental entity or courts or
official status of any kind. For a discussion of the tax consequences that may
result from an Investor's election to receive common stock in lieu of cash upon
a partnership's liquidation reference should be made to "Material Federal
Income Tax Consequences of Electing to Receive Common stock in Lieu of Cash
upon Partnership Liquidation."
Under written request of an Investor or his or her representative, the
Company will promptly transmit a copy of the tax opinion, without charge to the
Investor. Requests should be directed to Mr. Steven Yakle, Assistant
Controller, Swift Energy Company, 16825 Northchase Drive, Suite 400, Houston,
Texas 77060.
This summary does not describe all the tax aspects which may affect
Investors because the tax consequences may vary depending upon the individual
circumstances of an Investor. It is generally directed to Investors that are
individuals, qualified plans and trusts under Code Section 401(a) or individual
retirement accounts ("IRAs") under Code Section 408 (collectively "Tax Exempt
Plans") and that are the original purchasers of the Units and hold interests in
the Partnerships as "capital assets" (generally, property held for investment).
Each Investor is strongly encouraged to consult its own tax advisor as to the
rules which are specifically applicable to such Investor. Except as otherwise
specifically set forth herein, this summary does not address foreign, state or
local tax consequences, and is inapplicable to nonresident aliens, foreign
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corporations, debtors under the jurisdiction of a court in a case under federal
bankruptcy laws or in a receivership, foreclosure or similar proceeding, or an
investment company, financial institution or insurance company.
TAX TREATMENT OF TAX EXEMPT PLANS
This section applies to Tax Exempt Plans that are Investors in either
of the two series of partnerships which invested in only non-operating
interests, the 13 Swift Energy Managed Pension Assets Partnerships ("SEMPAP")
partnerships formed between 1988 and 1990, or the 13 Swift Energy Pension
Partners ("SEPP") partnerships formed between 1991 and 1994.
Sale of Property Interests and Liquidation of Partnerships
The Managing General Partner is proposing to sell the Partnerships'
Property Interests as well as any other royalties and overriding royalties the
Partnerships may own. After the sale of the properties, the Partnerships'
assets will consist solely of cash, which will be distributed to the Investors
in complete liquidation of the Partnerships.
Tax Exempt Plans are subject to tax on their unrelated business
taxable income ("UBTI"). UBTI is income derived by an organization from the
conduct of a trade or business that is substantially unrelated to its
performance of the function that constitutes the basis of its tax exemption
(aside from the need of such organization for funds). Royalty interests,
dividends, interest and gain from the disposition of capital assets are
generally excluded from classification as UBTI. Notwithstanding these
exclusions, royalties, interest, dividends, and gains will create UBTI if they
are received from debt-financed property, as discussed below.
The Service has previously ruled that the Partnerships' Property
Interests, as structured under the net profits agreements, are royalties, as
are any overriding royalties the Partnerships may own. To the extent that the
Property Interests are not debt-financed property, neither the sale of the
Property Interests by the Partnerships nor the liquidation of the Partnerships
are expected to cause Investors that are Tax Exempt Plans to recognize taxable
gain or loss for federal income tax purposes, even though there may be gain or
loss upon the sale of the Property Interests for federal income tax purposes.
The foregoing assumes Investors have not borrowed funds to acquire their
partnership interests.
Debt-Financed Property
Debt-financed property is property held to produce income that is
subject to acquisition indebtedness. The income is taxable in the same
proportion which the debt bears to the total cost of acquiring the property.
Generally, acquisition indebtedness is the unpaid amount of (i) indebtedness
incurred by a Tax Exempt Plan to acquire an interest in a partnership, (ii)
indebtedness incurred in acquiring or improving property, or (iii) indebtedness
incurred either before or after the acquisition or improvement of property or
the acquisition of a partnership interest if such indebtedness would not have
been incurred but for such acquisition or improvement, and if incurred
subsequent to such acquisition or improvement, the incurrence of such
indebtedness was reasonably foreseeable at the time of such acquisition or
improvement. Generally, property acquired subject to a mortgage or similar
lien is considered debt-financed property even if the organization acquiring
the property does not assume or agree to pay the debt. Notwithstanding the
foregoing, acquisition indebtedness excludes certain indebtedness incurred by
Tax Exempt Plans other than IRAs to acquire or improve real property. Although
this exception may apply, its usefulness may be limited due to its technical
requirements and the fact that the debt excluded from classification as
acquisition indebtedness appears to be debt incurred by a partnership and not
debt incurred by a partner directly or indirectly in acquiring a partnership
interest.
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If an Investor that is a Tax Exempt Plan borrowed to acquire its
partnership interest or had borrowed funds either before or after it acquired
its partnership interest, its pro rata share of Partnership gain on the sale of
the Property Interests may be UBTI, see "Tax Treatment of Investors Subject to
Federal Income Tax" below. The Managing General Partner has represented that
(i) the Partnerships did not borrow money to acquire their Property Interests,
and (ii) that the Property Interests of the Partnerships are not subject to any
debt, mortgages or similar liens that will cause the Partnerships' Property
Interests to be debt-financed property under Code Section 514. If a Tax Exempt
Plan has not caused its partnership interest to be debt-financed property, and
based upon the representations of the Managing General, the Property Interests
are not expected to be considered debt-financed property.
TAX TREATMENT OF INVESTORS SUBJECT TO FEDERAL INCOME TAX
All references to Investors in this section refer solely to Investors
that either are not Tax Exempt Plans or are Tax Exempt Plans (a) whose
Partnership Interests are debt-financed or (b) that have invested in the Swift
Energy Income Partnerships ("SEIP") formed between 1986 and 1990, or in the
Swift Energy Operating Partnerships formed between 1991 and 1994.
Tax Treatment of Tax-Exempt Plans Subject to Federal Income Tax Due
to Debt-financing
To the extent that a Tax Exempt Plan's partnership interest is only
partially debt-financed, the percentage of gain or loss from the sale of the
Property Interests and liquidation of the Partnerships that will be subject to
taxation as UBTI is the percentage of the Tax Exempt Plan's share of
Partnership income, gain, loss and deduction adjusted by the following
calculation. Section 514(a)(1) includes, with respect to each debt-financed
property, as gross income from an unrelated trade or business an amount which
is the same percentage of the total gross income derived during the taxable
year from or on account of the property as (i) the average acquisition
indebtedness for the taxable year with respect to the property is of (ii) the
average amount of the adjusted basis of the property during the period it is
held by the organization during the taxable year (the "debt/basis percentage").
A similar calculation is used to determine the allowable deductions.
For each debt-financed property, the amount of the deductions directly
attributable to the property are multiplied by the debt/basis percentage, which
yields the allowable deductions. If the average acquisition indebtedness is
equal to the average adjusted basis, the debt/basis percentage is zero and all
the income and deductions are included within UBTI. The debt/basis percentage
is calculated on an annual basis.
Tax Exempt Plans with debt-financed partnership interests should
consult their tax advisors to determine the portion of gain or loss that may be
recognized for federal income tax purposes. The following discussion of the
tax consequences of the sale of the Partnerships Property Interests and the
liquidation of the Partnerships assumes that all of an Investor's income, gain,
loss and deduction from his Partnership is subject to federal taxation.
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Taxable Gain or Loss Upon Sale of Properties
An Investor will realize and recognize gain or loss, or a combination
of both, upon his Partnership's sale of its properties prior to liquidation.
The amount of gain realized with respect to each property, or related asset,
will be an amount equal to the excess of the amount realized by such
Partnership and allocated to such Investor (i.e., cash or consideration
received) over the Investor's adjusted tax basis for such property.
Conversely, the amount of loss realized with respect to each property or
related asset will be an amount equal to the excess of the Investor's tax basis
over the amount realized by such Partnership for such property and allocated to
such Investor. Investors in Swift Energy Income Partnerships ("SEIP") or Swift
Energy Operating Partnerships ("SEOP") are not expected to realize any gain or
loss on property acquired from a SEMPAP or SEPP partnership and immediately
sold by the acquiring Partnership to the Managing General Partner. It is
projected that SEIP and SEOP Partnerships will realize taxable gain upon the
sale of the Partnership properties (other than those acquired from SEMPAP or
SEPP partnerships) and that SEMPAP and SEPP Partnerships will realize taxable
loss upon the sale of Partnerships properties. Such gain or loss will be
allocated among the Investors in accordance with the Partnership Agreements.
The Partnership Agreements include allocation provisions that require
allocations pursuant to a liquidation be made among partners in a fashion that
equalizes capital accounts of the partners so that the amount in each partner's
capital account will reflect such partner's sharing ratio of income and loss.
The extent to which capital accounts can be equalized, however, is limited by
the amount of gain and loss available to be allocated.
Realized gains and losses generally must be recognized and reported in
the year the sale occurs. Accordingly, each Investor will realize and
recognize his allocable share of gains and losses in his tax year within which
the Partnership properties are sold.
Factors Solely Applicable to All Investors in SEIP and SEOP
Partnerships (Partnerships holding working interests)
Because the oil and gas properties, and related assets owned by the
SEIP and SEOP Partnerships are properties used in a trade or business, the
character of gains and losses realized by the Partners generally will be
governed by Section 1231 of the Code. Deductions for intangible drilling and
development costs, depletion and depreciation expenses with respect to these
properties, however, may be subject to recapture as ordinary income, in an
amount which does not exceed gain recognized. With respect to properties
placed in service after 1986, Code Section 1254 recaptures all intangible
drilling and development costs and depletion (to the extent of basis) as
ordinary income. The SEIP and SEOP Partnerships did not incur material amounts
of intangible drilling and development costs, and accordingly the recapture of
same is not expected to be material.
Each Investor's recognized allocable share of the net Partnership 1231
gains or losses must be netted with that Investor's individual section 1231
gains and losses recognized during the year in order to determine the character
of such net gains or net losses under section 1231. Net gains will be treated
as capital gains except to the extent recharacterized as ordinary income due to
recapture and net losses will be treated as ordinary losses.
Liquidation of the Partnerships
After sale of their properties, the Partnerships' assets will consist
solely of cash which they will distribute to their partners in complete
liquidation. The Partnerships will not realize gain or loss upon such
distribution of cash to their partners in liquidation. If the amount of cash
distributed to an Investor in liquidation is less than such Investor's adjusted
tax basis in his Partnership interest, the Investor will realize
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and recognize a capital loss to the extent of the excess. If the amount of
cash distributed is greater than such Investor's adjusted tax basis in his
Partnership interest, the Investor will recognize a capital gain to the extent
of the excess. Investors in SEIP and SEMPAP Partnerships paid a portion of
syndication and formation costs upon entering his or its Partnership, neither
of which costs were deductible expenses, therefore it is anticipated that
liquidating distributions to Investors in SEIP and SEMPAP Partnerships will be
less than such Investors' bases in their Partnership interests and thus will
generate capital losses.
Capital Gains Tax
Net long-term capital gains of individuals, trusts and estates
generally will be taxed at a maximum rate of 20%, while ordinary income,
including income from the recapture of depletion, will be taxed at a maximum
rate depending on that Investor's taxable income of 36% or 39.6%. With respect
to net capital losses, other than Section 1231 net losses, the amount of net
long-term capital loss that can be utilized to offset ordinary income will be
limited to the sum of net capital gains from other sources recognized by the
Investor during the tax year, plus $3,000 ($1,500, in the case of a married
individual filing a separate return). The excess amount of such net long-term
capital loss may be carried forward and utilized in subsequent years subject to
the same limitations. Corporations are taxed on net long- term capital gains
at their ordinary Section 11 rates and are allowed to carry net capital losses
back three years and forward five years.
Passive Loss Limitations
Investors that are individuals, trusts, estates, or personal service
corporations are subject to the passive activity loss limitations rules that
were enacted as part of the Tax Reform Act of 1986.
An Investor's allocable share of Partnership income, gain, loss, and
deduction is treated as derived from a passive activity, except to the extent
of Partnership portfolio income, which includes interest, dividends, royalty
income and gains from the sale of property held for investment purposes. A
SEMPAP or SEPP Investor's allocable share of any gain realized on sale of his
Partnership's net profits interest is expected to be characterized as portfolio
income and may not offset, or be offset by, passive activity gains or losses.
An SEIP or SEOP Investor's allocable share of any gain realized on
sale of Partnership properties (other than gain from the sale of portfolio
investments) will be characterized as passive activity income that may be
offset by passive activity losses from other passive activity investments.
Moreover, because the sale of properties and liquidation of such Partnerships
will terminate the Investors' interest in the passive activity, an Investor's
allocable share of any loss (i) previously realized as an Investor in such
Partnership and suspended because of its passive characterization, (ii)
realized on the liquidating sale of Partnership properties, or (iii) realized
by the Investor upon liquidation of his Partnership interest, will not be
characterized as losses from a passive activity.
THE FOREGOING DISCUSSION IS INTENDED TO BE A SUMMARY OF MATERIAL
INCOME TAX CONSIDERATIONS OF THE SALE OF PROPERTIES AND LIQUIDATION OF THE
PARTNERSHIPS. EACH INVESTOR SHOULD CONSULT HIS, HER OR ITS OWN TAX ADVISOR
CONCERNING SUCH INVESTOR'S PARTICULAR TAX CIRCUMSTANCES AND THE FEDERAL, STATE,
LOCAL, FOREIGN AND OTHER TAX CONSEQUENCES TO HIM OR IT OF THE SALE OF
PROPERTIES AND THE LIQUIDATION OF HIS OR ITS PARTNERSHIP.
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CONSIDERATION OF ALTERNATIVE TRANSACTIONS
The Managing General Partner has given consideration to a number of
different alternatives prior to submitting the Proposals to Investors for their
approval. These alternatives included continued operation of the properties
for a longer period, offering the Partnerships' remaining property interests at
auction or selling them in negotiated transactions. For the reasons discussed
at greater length under "The Proposal--Reasons for the Proposal" below, the
Managing General Partner believes that a sale at this time is preferable to
continued operations of the Partnerships. Although in the past certain
marginal Property Interests have been sold in negotiated transactions or at
auction, the Managing General Partner does not believe that such methods of
sale are likely to maximize the value of the Partnerships' Property Interests,
as discussed below.
Continuing Operations
As discussed above under "Fairness of Proposed Sale," the
estimates of the liquidating net cash distributions payable to
Investors if the Partnerships' Proposals are approved is less than the
estimate of net cash distributions to Investors if their Partnerships
continue to operate for the remaining lives of their reserves. For
reasons discussed at greater length under "Special Factors--Reasons
for the Proposal" above, the Managing General Partner believes that a
sale at this time is preferable to continuing operations of the
Partnerships. There are a number of assumptions contained in the
estimates of distributions from continued operations that may or may
not prove to be true over the remaining life of the Partnerships'
reserves. Such distributions would be subject to the risks of oil and
gas operations, in addition to the risk of continued price volatility
for oil and gas.
Auction
Although offering oil and gas properties for sale at auction is often
an efficient means of selling smaller interests in properties in which the
seller is not the operator of the property, auctions are generally unsuited to
the offer and sale of substantial property interests, may exceed the normal
size of properties offered at auction, and may well be beyond the purchasing
capacity of the parties which typically are bidders at such auctions or might
lower the price or the number of interested bidders.
o Many of the Partnerships organized by the Managing General Partner own
significant interests in the same fields. Consequently, if a substantial
majority of these Partnerships approve sale of their properties, the size
of the interests in many properties would exceed the normal size of
properties offered at auction, and may well be beyond the purchasing
capacity of the parties which typically are bidders at such auctions.
Larger consolidated property interests normally bring higher prices, and
thus there are significant reasons to sell the interests in the same
properties owned by all of the Partnerships affiliated with the Managing
General Partner at one time. On the other hand, doing so at auction
would cause such properties to dominate each auction and would likely
lower the price or the number of interested bidders. In order to avoid
this consequence, the interests in properties to be sold could be divided
into smaller pieces and offered at auction on multiple occasions over
several years, but this might be counterproductive in terms of prices
received at auction, thus minimizing many of the benefits of taking
properties to auction for sale.
o A portion of the value of the properties in which the Partnerships own
interests would remain operated by the Managing General Partner because
it controls other interests in fields in which they are located. This
often negatively affects the amount a third party is willing to pay and
the overall interest of third parties in buying such properties. On the
other hand, because of its control of such properties, the Managing
General Partner is the party in the position to pay the highest price for
such interests and the one most likely to do so.
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<PAGE> 86
o A significant portion of the proved reserves attributed to many of the
Partnerships' Property Interests are non-producing reserves. Typically
auction buyers base the prices they pay at auction upon a multiple of
cash flow. This methodology of auction pricing significantly discounts
the value of non-producing reserves.
o Because of the necessity of preparing and disseminating auction
information on properties to be offered and soliciting attendance by
prospective bidders, and then screening and qualifying such purchasers,
the transaction costs for offering properties at auction are substantial,
and often higher than other means of sale.
Because of the various factors discussed above, the Special Transactions
Committee has determined that it would not be in the best interests of the
Partnerships to offer substantially all of their properties and assets to third
parties.
Negotiated Sale
Many of the same factors discussed above affect whether the
Partnerships would benefit from attempting to sell their Property Interests in
negotiated transactions, such as:
o The fact that buyers would be purchasing many Property Interests they
would neither control nor operate applies equally in negotiated sales,
and might discourage interest and prices offered for such interests.
o Likewise, the discount for non-producing reserves could exceed the
discounts applied by the Appraisers in the case of negotiated sales of
properties with substantial amounts of such reserves. This factor is
minimized to the greatest extent through the Managing General Partner's
purchase of such Property Interests, because the Managing General Partner
is familiar with all of these properties through its management of the
Partnerships' interests therein over several years.
o Lastly, sale of properties on a direct basis often involves substantial
periods of time for due diligence, negotiation and execution of
agreements and closings, often with different purchases for different
properties, in addition to the necessity of taking large amounts of time
to create and supervise data rooms or disseminate data to possible
purchasers, plus the time needed to deal directly with multiple
prospective purchasers. Furthermore, certain issues, such as
environmental and title matters, may come to light in the late stages of
a negotiated sale, which may delay or preclude the consummation of the
sale.
Although the Company did sell the properties of other partnerships
whose assets were liquidated between 1996 and 1998 both by means of auction and
negotiated transactions, neither form of transaction has been attempted for the
Property Interests owned by the Partnerships because of the smaller size of the
properties placed in auction in the former liquidations and the other reasons
noted above. No offers have been received to purchase the properties owned by
the Partnerships from any third party, nor has the Managing General Partner
undertaken an effort to sell the Property Interests on behalf of any of the
Partnerships through the alternatives discussed above.
Assessment of Investors
The limited partnership agreements under which the Partnerships were
formed do not provide for any form of voluntary or mandatory assessment for
further capital contributions by the Investors in the Partnerships. Given the
purpose of the Partnerships when they were formed, and the explicit Partnership
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<PAGE> 87
provisions and disclosures that no assessments would be made, the Managing
General Partner did not consider it to be appropriate to consider this as an
alternative for funding development of non-producing reserves of the
Partnerships or otherwise invest further capital in the Partnerships'
activities. Engaging in extensive drilling operations is contrary to the
purposes of the Partnerships and represents a higher degree of risk than
contemplated when the Partnerships were formed. In certain Partnerships,
borrowing was forbidden or restricted by the terms of their limited partnership
agreements. Although there was limited borrowing in the early years by certain
Partnerships, at this time lower levels of cash flow are not sufficient to
support the additional cost of borrowing and repayment.
Third Party Tender Offer
In June 1998, Madison Partnership Liquidity Investors 60, L.L.C. made
an offer to purchase up to 4.0% of the outstanding units of Swift Energy Income
Partners 1987-B, Ltd. from its limited partners for $5.66 per unit in cash.
[FILL IN LATER IF INFORMATION AVAILABLE:] Upon the conclusion of the offer in
late July 1998, holders of __% of its outstanding units had tendered their
Units to Madison for purchase. It is not known whether other tender offers
will be made to purchase Units from Investors in other Partnerships, or the
price at which such offers will be made, although based upon various securities
regulatory restrictions, it is anticipated that any such offers would cover no
more than 4.9% of outstanding Units of any one Partnership.
COMPARISON OF OWNERSHIP OF UNITS AND SHARES
The information below highlights a number of the significant
differences between the Partnerships and the Company relating to, among other
things, form of organization, investment objectives, policies and restrictions,
asset diversification, capitalization, management structure, compensation and
fees, and investor rights, and compares certain of the respective legal rights
associated with the ownership of the Units and Shares. These comparisons are
intended to assist Eligible Purchasers in understanding how their investments
will be changed if they elect to receive all or any portion of the distribution
they are entitled to receive in shares of Common Stock offered hereunder. This
comparison is summary in nature and does not constitute a complete discussion
of these matters, and Eligible Purchasers should carefully review the balance
of this Joint Proxy Statement/Prospectus for additional discussions.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
PARTNERSHIP COMPANY
- -------------------------------------------------------------------------------------------------------------
FORM OF ORGANIZATION
<S> <C>
Partnerships formed as Texas limited partnerships, Company formed as a Texas corporation, which is a
which are finite life entities. At the end of the continuing life entity.
Partnerships' lives (or upon sale of substantially
all of its assets, Investors receive net proceeds
from such sale upon liquidation
</TABLE>
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<PAGE> 88
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
PARTNERSHIP COMPANY
- -------------------------------------------------------------------------------------------------------------
LENGTH OF INVESTMENT
<S> <C>
Investments in the Partnerships were presented to Unlike the Partnerships, the Company intends to
Investors as finite life investments, with the continue its operations for an indefinite time
Investors to receive cash distributions principally period and has no specific plans for disposition of
from the sale of oil and gas produced from the the assets it owns currently, or to be acquired upon
Partnerships' properties and to receive cash consummation of the Proposals or that may be
distributions upon sale of production from, or subsequently acquired.
liquidation of, the Partnerships' Property
Interests. Under each of the Partnership
Agreements, the Partnerships' stated terms of
existence was approximately 25 years, but the
Managing General Partner stated its intention of
selling the Partnerships' properties after a
Partnership's fifth to ninth year, market conditions
permitting. See "Background and Reasons for
Proposals-- Background of the Partnerships."
</TABLE>
Investors in each of the Partnerships expect liquidation of their
investment when the assets of the Partnerships are liquidated. In contrast,
Shareholders are expected to achieve liquidity for their investments by
trading the Shares on the secondary market.
<TABLE>
<CAPTION>
PROPERTIES AND DIVERSIFICATION
<S> <C>
The investment portfolio of each of the Partnerships The Company is engaged in the exploration,
is limited to the interests in producing oil and gas development, acquisition and operation of oil and
properties acquired with the initial equity raised gas properties, with its primary focus being
through the sale of the Units to the Investors. The exploration and development drilling in its core
Partnerships are not authorized to issue additional areas. The Company plans to issue debt and/or
equity securities to expand their investment equity securities in the future, and to apply all,
portfolio. See "Background and Reasons for or substantially all, of the net proceeds from the
Proposals--Background of the Partnerships." sale of the Shares offered hereunder towards the
purchase of the Property Interests. To the extent
the Company sells or refinances its assets, the net
proceeds therefrom will, generally speaking, be
retained by the Company for new investments rather
than being distributed to Shareholders in the form
of dividends. In contrast to the Partnerships, the
Company will constitute a vehicle for taking
advantage of future investment opportunities that
may be available in oil and gas properties. See
"Background and Reasons for Proposals--Expected
Benefits from Proposals--Expected Benefits to
Investors Partners."
</TABLE>
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<PAGE> 89
- --------------------------------------------------------------------------------
PARTNERSHIP COMPANY
- --------------------------------------------------------------------------------
The Company owns an oil and gas portfolio substantially larger and
more diversified than the portfolio of any of the Partnerships or all of the
Partnerships taken together. Whereas the Company is engaged in an active
drilling program, which involves a higher degree of risk, the Partnerships
were not established for any substantial drilling of the oil and gas wells,
and do not have the capital to do so.
<TABLE>
<CAPTION>
CASH DISTRIBUTIONS V. NO CASH DIVIDENDS
<S> <C>
Partnerships have made quarterly cash distributions Shareholders in the Company cannot expect to receive
to Investors from sale of oil and gas production. cash dividends as the Company has never paid any
cash dividends and does not expect to do so for the
foreseeable future, although it has since 1995 paid
two 10% stock dividends. Any profit or loss from
investing in Company Common Stock will come from the
increase or decrease in the price of that stock.
PERMITTED INVESTMENTS
Each of the Partnerships are only authorized to The Company may invest in such investments as
acquire, manage and ultimately sell interests in specifically approved by the Board of Directors.
properties that are producing oil and gas in
commercial quantities or which contain shut-in-wells
capable of such production with the initial equity
raised through the sale of Units. All such funds
was required to be used or committed to be used
within two years of the formation of the
Partnerships.
</TABLE>
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<PAGE> 90
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
PARTNERSHIP COMPANY
- -------------------------------------------------------------------------------------------------------------
ADDITIONAL EQUITY
<S> <C>
None of the Partnerships are authorized to issue The Board of Directors may, it its discretion, issue
equity securities other than the Units. additional equity securities consisting of Common
Stock or Preferred Stock, provided that the total
number of shares issued do not exceed the authorized
number of shares of Common Stock or of Preferred
Stock set forth in the Company's Articles of
Incorporation. The Company expects to raise
additional equity from time to time to increase its
available capital. The Board of Directors is likely
to issue additional securities (Common Stock or
Preferred Stock), plus various debt securities,
which will dilute any interest Investors may have in
the Company.
</TABLE>
Unlike the Partnerships, the Company has substantial flexibility to raise
equity, through the sale of Common Stock or Preferred Stock, to finance its
business and affairs.
<TABLE>
<CAPTION>
BORROWING POLICIES
<S> <C>
The Partnership Agreement of each of the The Company is permitted to borrow, on a
Partnerships places various restrictions on the secured or unsecured basis, funds to finance its
authority of the Partnership to borrow funds. business, subject to restrictions contained in its
Furthermore, as a matter of overall policy, each of revolving credit agreement.
the Partnerships limited the amount it borrowed, if
any, to finance the Partnership's activities.
</TABLE>
In conducting its business, the Company may incur Indebtedness to the
extent believed appropriate. The incurrence of Indebtedness will increase the
risk of loss of an Investment. As a general rule, each of the Partnerships has
not incurred significant indebtedness in acquiring its assets or conducting its
business.
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<PAGE> 91
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
PARTNERSHIP COMPANY
- -------------------------------------------------------------------------------------------------------------
MANAGEMENT CONTROL AND RESPONSIBILITY
<S> <C>
Under each of the Partnership Agreements, the The Board of Directors controls the Company's
Managing General Partner is, subject to certain business and affairs subject only to the
narrow limitations, vested with all management restrictions in the Articles of Incorporation and
authority to conduct the business of the the By-Laws. Shareholders have the right to elect
Partnership, including authority and responsibility members of the Board of Directors on a staggered
for overseeing all executive, supervisory and basis at each annual meeting of the Shareholders.
administrative services rendered to the Partnership. The Directors are accountable to the Company as
The Special General Partner assists and consults fiduciaries and are required to exercise good faith
with the Managing General Partner regarding certain and integrity in conducting the Company's affairs.
financial and administrative aspects of the
Partnerships' business. The General Partners have
the right to continue to serve in such capacities
unless either or both are removed by Investors
holding at least a majority of the Units. Investors
have no right to participate in the management and
control of the Partnerships and have no voice in its
affairs except for certain limited matters that may
be submitted to a vote of the Investors under the
terms of the Partnership Agreements. See "--Voting
Rights" below. The General Partners are accountable
as fiduciaries to the Partnerships and are required
to exercise good faith and integrity in their
dealings in conducting the Partnerships' affairs.
</TABLE>
Shareholders have greater control over management of the Company than the
Investors have over the Partnerships because members of the Board of Directors
are elected on a staggered basis annually by the Shareholders at the Company's
annual meeting. However, in both cases, Investors and Shareholders must rely
upon management for the prudent administration of their investments.
75
<PAGE> 92
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
PARTNERSHIP COMPANY
- -------------------------------------------------------------------------------------------------------------
MANAGEMENT LIABILITY AND INDEMNIFICATION
<S> <C>
As a matter of state law, the General Partners have The Articles of Incorporation provide that directors
liability for the payment of Partnership obligations shall be indemnified to the full extent permitted
and debts, unless limitations upon such liability under Texas law. The By-Laws and Texas law provide
are expressly stated in the obligations. Under broad indemnification rights to directors and
state law, the General Partners are liable to the officers who act in good faith, and in a manner
Investors for a breach of a Partnership Agreement or reasonably believed to be in or not opposed to the
a violation of a duty to a Partnership that causes best interests of the Company. Pursuant to the By-
harm to such Partnership. In addition, the Laws and Texas law, the Company has the power to (a)
Partnership Agreements indemnify the General indemnify against judgments, penalties (including
Partners and their affiliates against expenses, excise and similar taxes), fines, settlements and
including attorneys' fees, judgments and amounts reasonable expenses actually incurred by the party
paid in settlement, actually and reasonably incurred seeking indemnification, and (b) advance reasonable
by them in conducting the Partnerships' business, expenses incurred by a director who was, is, or is
if, in good faith, they determined their course of threatened to be made a named defendant in a
conduct was in or not opposed to the best interests proceeding, in advance of final disposition of the
of the Partnership and if the conduct of such entity proceeding after the Company receives a written
did not constitute negligence, misconduct or a affirmation by the director of his good faith belief
breach of fiduciary obligations to the Investors that he has met the standard of conduct necessary
except in the event of fraud, misconduct, bad faith for indemnification and a written undertaking by
or negligence. such director to repay the amount if it is
ultimately determined that the standard was not met.
In addition, to the extent a director has been
successful on the merits or otherwise in defense of
any action, suit or proceeding to which he was
subject by reason of fact that he is or was a
director, he shall be entitled to mandatory
indemnification against reasonable expenses
incurred by him in connection therewith.
</TABLE>
The General Partners of the Partnerships have limited liability to the
Partnerships for acts or omissions undertaken by them when performed in good
faith, in a manner reasonably believed to be within the scope of their
authority and in the best interests of the Partnerships. The General Partners
also have, under specified circumstances, a right to be advanced expenses or
reimbursed for any loss, claim, liability, damage and expenses (including
attorneys' fees) actually and reasonably incurred by them by virtue of serving
as General Partners. Although the standards are expressed somewhat
differently, there are similar limitations upon the liability of the directors
and officers of the Company when acting on behalf of the Company and upon the
rights of such persons to seek indemnification from the Company.
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<PAGE> 93
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
PARTNERSHIP COMPANY
- -------------------------------------------------------------------------------------------------------------
VOTING RIGHTS
<S> <C>
Investors by a majority vote may, with or without Shareholders are entitled to elect the Company's
the concurrence of the Managing General Partner: Board of Directors at each annual meeting of the
Company.
(a) Certain amendments to the Partnership
Agreements; Under Texas law, the following actions may not be
(b) Dissolve the Partnerships; taken without the approval of Shareholders:
(c) Remove either or both of the General
Partners, with or without cause; (a) Amend the Certificate of Incorporation;
(d) Elect a new general partner provided (b) Merge with another corporation;
certain conditions are satisfied; and (c) Sell, lease or exchange all or
(e) Approve or disapprove the sale, exchange substantially all of the Company's assets;
or other disposition of all or (d) Dissolve the Company or revoke a pending
substantially all of the Partnerships' dissolution; and
assets. (e) Elect directors.
Investors may not exercise these rights in a way to
extend the term of the Partnerships, change the
Partnerships to general partnerships, change the
limited liability of the Investors or affect the
status of the Partnerships for federal income tax
purposes.
</TABLE>
Shareholders have broader voting rights (i.e. the right to elect the
members of the Board of Directors on a staggered basis at each annual meeting)
than those currently afforded to Investors.
<TABLE>
<CAPTION>
LIMITED LIABILITY OF INVESTORS
<S> <C>
Under each of the Partnership Agreements and Under Texas law, Shareholders will not be liable for
applicable state law, the liability of Investors for Company debts or obligations. The Shares, upon
the Partnerships' debts and obligations is generally issuance, will be fully paid and nonassessable.
limited to the amount of their investment in their
Partnership, together with an interest in
undistributed income, if any. The Units are fully
paid and nonassessable.
</TABLE>
The limitation on personal liability of Shareholders of the Company is
substantially the same as that of Investors in the Partnerships.
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<PAGE> 94
The following compares certain of the investment attributes and legal
rights associated with the ownership of Units and Shares.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
UNITS SHARES
- -------------------------------------------------------------------------------------------------------------
NATURE OF INVESTMENT
<S> <C>
The Units of each Partnership constitute equity The Shares constitute equity interests in the
interests entitling each Investor to his pro rata Company. Each Shareholder will be entitled to his
share of cash distributions made to the Investors of pro rata share of the dividends made with respect to
a Partnership. Each of the Partnership Agreements the Common Stock. The dividends payable to the
specifies how the cash available for distribution. Shareholders are not fixed in amount and are only
paid when declared by the Company's Board of
Directors. Since the Company's inception, no cash
dividends have been declared on its Common Stock,
and the Company does not expect to declare cash
dividends in the foreseeable future. The Company
did, however, declare a 10% Common Stock dividend in
October 1997.
</TABLE>
Both the Units and Shares represent equity interests entitling the
holders thereof to participate in the growth of the Partnerships and the
Company, respectively. Distributions and dividends payable with respect to the
Units and Shares depend upon the performance of the Partnerships and the
Company, respectively.
<TABLE>
<CAPTION>
POTENTIAL DILUTION OF PAYMENT RIGHTS
<S> <C>
Since the Partnerships are not authorized to issue The Board of Directors may, in its discretion, issue
additional equity securities, there can be no additional Shares of Common Stock or issue Preferred
dilution of the distributive share of the Investors Stock with such powers, preferences and rights as
to cash available for distribution. the Board of Directors may at the time designate.
The issuance of additional Shares of either Common
Stock or Preferred Stock, beyond the Shares to be
issued pursuant to this Offering, may result in the
dilution of the interests of the Shareholders. See
"Investment Policies and
Restrictions--Capitalization."
</TABLE>
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<PAGE> 95
The Shareholders will be subject to potential dilution if the Company
issues additional equity securities at prices below the then current value
represented by such securities. Furthermore, the Company may issue Preferred
Stock with priorities or preferences with respect to individuals and
liquidation proceeds.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
UNITS SHARES
- -------------------------------------------------------------------------------------------------------------
LIQUIDITY
<S> <C>
The transfer of the Units is subject to a number of The Shares will be freely transferable. The Common
restrictions imposed by the Partnership Agreements, Stock will be listed on the NYSE and the Pacific
which are designed primarily to preserve the tax Exchange. A public market for the Shares exists,
status of the Partnerships as "partnerships" under but the breadth and strength of this secondary
the Code. No transferee of a Unit or SDI has the market will depend, among other things upon the
right to become a substitute Investor (entitling number of Shares outstanding, the Company's
such person to vote on matters submitted to a vote financial results and prospects, and the relative
of the Investors) unless, among other things, such attractiveness of the Company's yields compared to
substitution is approved by the Managing General those of other equity securities.
Partner, who may grant or withhold such consent in
its absolute discretion. Furthermore, transfers
would not be permitted if the transfers would result
in the termination of the Partnership under Section
708 of the Code or, in some cases, if the transfer
would effect the partnership status of the
Partnership for federal income tax purposes. In
view of the foregoing, the secondary market for the
Units has been either non-existent or limited, thin
and sporadic.
</TABLE>
The Shares will be listed on the NYSE and the Pacific Exchange. While
there has been a limited secondary market for the Units, trading on that market
has been sporadic and limited.
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<PAGE> 96
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
UNITS SHARES
- -------------------------------------------------------------------------------------------------------------
TAXATION OF TAXABLE INVESTORS IN SEIP AND SEOP PARTNERSHIPS
<S> <C>
Income or loss earned by each of the Partnerships is Any dividends received by Shareholders from the
not taxed at the partnership level. Investors are Company generally will constitute portfolio income,
required to report their allocable share of which cannot offset "passive" loss from other
Partnership income and loss on their respective tax investments. Losses and credits generated within
returns. Income and loss from the Partnerships the Company do not pass through to the Shareholders.
generally constitute "passive" income and loss, After the end of the Company's calendar year,
which can generally offset "passive" income and loss Shareholders will receive the less complicated Form
from other investments. Due to depletion and other 1099-DIV used by corporations to report any dividend
non-cash items, cash distributions are not generally income. See "Federal Income Tax Considerations--
equivalent to the income and loss allocated to Taxation of Taxable Shareholders."
Investors. During operations, such cash
distributions are partially sheltered. After the
end of each fiscal year, Investors receive annual
Schedule K-1 forms showing their allocable shares of
Partnership income and loss for inclusion on their
federal income tax returns. Investors may also be
required to file state income tax returns and/or pay
state income taxes in states other than Texas where
their Partnership owns properties.
</TABLE>
Each of the Partnerships is a pass-through entity, whose income and
loss is not taxed at the entity level but instead allocated directly to the
General Partners and Investors. Investors are taxed on income or loss allocate
to them, whether or not cash distributions are made to the Investors. To the
extent the Company has net income, such income will be taxed at the Company's
level at the standard corporate tax rates. Any dividends paid to Shareholders
will constitute portfolio income and not passive income.
<TABLE>
<CAPTION>
TAXATION OF TAX-EXEMPT INVESTORS IN SEMPAP AND SEPP PARTNERSHIPS
<S> <C>
Partnership income, gain or loss earned by each of Any dividends received from the Company by Tax-
the Partnerships is generally treated as nontaxable Exempt Shareholders should not constitute UBTI if
unless the Investor has caused its interest in a such Shareholders did not finance the acquisition of
Partnership to be debt financed in which case the their Shares. The amount of dividends paid to Tax-
income would be UBTI. Therefore, it is uncertain Exempt Shareholders is expected to be less than the
whether the gain or loss received by the distributions made to such entities from their
Partnerships in connection with the sale of their respective Partnerships. See "Federal Income Tax
net profits interests constitutes taxable gain or Considerations-- Taxation of Tax-Exempt
loss for UBTI purposes. Accordingly, there is risk Shareholders."
that the Partnership's gain or loss could be taxable
for certain Tax-Exempt Partners.
</TABLE>
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<PAGE> 97
A tax-exempt entity is treated as owning and carrying on any
business activity conducted by a partnership in which such entity owns an
interest. Accordingly, to the extent a Tax-Exempt Partner owns an interest in
a Partnership, the income received by such Partnership must not constitute
UBTI in order for the Tax-Exempt Partner to avoid taxation. The income
received from the Partnership appears not to be UBTI for these purposes;
however, the actions of each Tax-Exempt Partner may affect whether the
income is taxable to such Partner. Any income attributable to the Shares is
not UBTI unless such shares are debt financed.
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<PAGE> 98
NO UNAFFILIATED REPRESENTATIVE OR FAIRNESS REPORT
Neither the Managing General Partner nor a majority of its independent
directors retained an unaffiliated representative to act on behalf of the
Partnerships' Investors for the purposes of negotiating the terms upon which
any such sale to the Managing General Partner would be made or for the
preparation of a report concerning the fairness of such transaction.
CONSEQUENCES OF A PARTNERSHIP NOT APPROVING ITS PROPOSAL
If the Investors in a Partnership do not approve its Proposal, such
nonparticipating Partnership will continue to operate as a separate legal
entity with its own assets and liabilities. There will be no change in its
investment objectives, policies or restrictions, and the nonparticipating
Partnerships will continue to be operated in accordance with the terms of their
Partnership Agreement. It is also likely that the Proposal to the companion
Partnership of any such nonparticipating Partnership will be withdrawn even if
a Proposal is approved by Investors of such companion Partnership.
PRIOR RELATIONSHIPS BETWEEN THE APPRAISERS, THE PARTNERSHIPS AND THE MANAGING
GENERAL PARTNER
H.J. Gruy has audited the reserve evaluations for the Partnerships,
other partnerships managed by the Managing General Partner, and the Managing
General Partner itself since their respective inceptions. The amount paid to
H.J. Gruy over the two most recent fiscal years by each specific Partnership
is set out in its specific Supplement. Approximately $72,300 over the past two
years has been paid by the Managing General Partner and its affiliates to H.J.
Gruy. In 1997, J.R. Butler provided an appraisal of the fair market value of
certain Property Interests in a particular field owned by seven limited
partnerships (not including the Partnerships) formed by the Managing General
Partner, which was the price for which those property interests were purchased
in 1998 from those seven partnerships by the Managing General Partner. J.R.
Butler was paid approximately $38,500 over the last two years for such
appraisal services and other work performed for the Managing General Partner,
none of which was performed for any of the Partnerships. Additionally, J.R.
Butler performed four technical studies for the Company during the period
November 1990 to October 1994. Otherwise, there has been no preexisting
relationship between the Managing General Partner and J.R. Butler. CIBC
Oppenheimer acted as managing underwriter of a public offering of $48.875
million of common stock for the Managing General Partner in 1995, in which the
gross underwriting discount was 5.64% and participated as an underwriter of the
Managing General Partner's 1996 public offering of $115 million of Convertible
Subordinated Notes, in which the gross underwriting discount was 3.5%. CIBC
Oppenheimer also may be involved in future investment banking activities on
behalf of the Managing General Partner. None of the Appraisers nor any of their
personnel have any direct or indirect interest in the Managing General Partner
or the Partnerships, and the Appraisers' compensation is not contingent upon
the results of their fair market value opinions resulting from their review of
the Partnerships' properties.
In preparing their valuation estimates, the Appraisers assumed the
accuracy and completeness of the financial and other information provided by
the Managing General Partner or which was publicly available and did not
attempt to independently verify such information. The Appraisers did not make
field inspections or judgments relative to environmental or other legal
liabilities.
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<PAGE> 99
EXPENSES
The total expenses associated with the Proposals is estimated to be 3%
of the Fair Market Value of the Property Interests of all of the Partnerships,
or $2,250,000, comprised principally of appraisal fees of $575,000, mailing
costs of $325,000, legal and accounting fees of $750,000, printing costs of
$350,000 and other expenses (travel, telephone and other solicitation expenses,
filing fees, etc.) of $250,000. The appraisal fees are to be paid by the
Partnerships and allocated in percentages proportionate to the Fair Market
Value of each Partnership's oil and gas assets determined by the Appraisers.
Printing, mailing and solicitation costs will be allocated among the
Partnerships according to the number of Investors in each Partnership. The
remaining costs will be allocated according to percentages proportionate to the
Fair Market Value. Consequently, it is estimated that the maximum amount of
these expenses allocated to any Partnership will be $127,500, and the minimum
amount will be $7,800, which generally is proportionate to the original
capitalization of each Partnership.
The general and administrative costs of the Managing General Partner
anticipated to be incurred in connection with the Proposals and related
transactions will be covered by the normal ongoing general and administrative
cost reimbursement to it set out in each Partnership's Partnership Agreement.
The Managing General Partner has received this reimbursement on an annual basis
since inception of the Partnerships.
SOURCE OF FUNDS TO PURCHASE PARTNERSHIP PROPERTY INTERESTS
The Company will use internally generated cash resources and
borrowings available under the New Credit Facility to purchase the
Partnerships' Property Interests, the net purchase price of which is expected
to be approximately $70.6 million, subject to certain reductions based on cash
flow distributions to the Partnerships prior to closing. The principal terms
and restrictions of the New Credit Facility are described in detail in this
Joint Proxy Statement/Prospectus under "Summary--Recent Developments--New
Credit Facility." It is anticipated that these borrowings will be repaid
through, and other capital needs will be met by, internally generated cash
flows, and other forms of debt and/or equity financing.
MANAGING GENERAL PARTNER BENEFITS
The Managing General Partner will share the benefits available to
Investors through liquidating its Partnership interests (including both its
general partner's interest and any units it owns) and receiving the same value
for those interests as Investors.
The Managing General Partner will purchase the Partnerships' Property
Interests if the Proposals are approved by the companion Partnerships. See
"The Proposals--Estimates of Liquidating Distribution Amount." Additionally,
by purchasing the Partnerships' Property Interests itself, the Managing General
Partner will be able to maintain its position as operator of many of the
properties in which the Partnerships own interests and for which it will
continue to receive operating fees. The sale of any one Partnership's Property
Interests to the Managing General Partner will have no effect or an
inconsequential effect on the Managing General Partner's net book value and net
earnings. However, the Managing General Partner is making similar Proposals to
Investors in 63 Partnerships organized for the same purposes between the years
1986 and 1994. If the Investors in all of these Partnerships approve the
Proposals to sell all of their properties to the Managing General Partner, the
Managing General Partner anticipates, when comparing the year-end 1997 "100%
Case" reserve and balance sheet proforma information to December 31, 1997
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Company historical data, that the oil and gas interests acquired would increase
the Company's total proved reserves on a gas equivalent basis by approximately
26%, and would increase the Company's cash flow and total assets by
approximately 25% and 19%, respectively. Furthermore, the Company intends to
invest capital in developing certain of the properties' non-producing reserves
acquired from the Partnerships which approve the sale of their Property
Interests to the Company, depending upon the Company's assessment of each
property, characteristics and changes from time to time in the price of oil and
gas. The Company intends to profit from this activity through a return on the
capital used and purchase such assets and invest in their development. The
Managing General Partner is making its recommendations as set forth below, on
the basis of its fiduciary duty to the Investors, rather than on the basis of
the direct economic impact on it in its corporate capacity.
If individual Investors in Partnerships which approve the Proposals to
sell their oil and gas assets elect to purchase Company Common Stock, rather
than receiving cash upon liquidation of their Partnership, the Company will
benefit through not having to use its available cash resources or borrowing
facilities to pay for the purchase of Partnership Property Interests, through
instead being able to issue stock to pay for a proportion of the Property
Interests purchased.
No sale of a Partnership's Property Interests can take place without
approval by that Partnership's Investors, including any future sale to the
Managing General Partner if the Partnership does not approve its Proposal. If
a Partnership rejects its Proposal, the Managing General Partner does not
contemplate presenting a similar proposal to that Partnership in the near
future, nor is there any assurance that any other proposal for liquidation of
that Partnership would be presented, or if so whether it would be similar to
the Proposals.
The advantages to the Company from acquiring the Partnerships'
Property Interests at this time, as opposed to a future date, are: (1) the
Company currently has access to capital resources which could be used to
further develop the Property Interests being acquired; (2) the price of oil and
gas could increase subsequent to the date of acquisition; (3) the Company is in
the business of purchasing oil and gas properties and increasing its reserves,
and the acquisition of the Property Interests at this time allows it to do so
currently; (4) and the drilling costs could increase at a future date.
INVESTORS ARE URGED TO COMPLETE, SIGN AND DATE THE ENCLOSED PROXY AND
TO RETURN IT TO THE MANAGING GENERAL PARTNER NO LATER
THAN ___________________, 1998.
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THE PROPOSALS
GENERAL
The Managing General Partner has proposed that the Partnerships'
Property Interests be sold, the Partnerships be dissolved and that the Managing
General Partner, acting as liquidator, wind up the Partnerships' affairs and
make final distributions to Investors.
Pursuant to the terms of the Partnership Agreements, the
Partnerships, if not terminated earlier, will continue in being for a finite
period specified in their Partnership Agreements (usually 25 years), at which
point they will terminate automatically.
This Joint Proxy Statement/Prospectus is being provided by the Company
in its capacity as the Managing General Partner of the particular Partnership
designated on the Notice of Special Meeting contained in the package with this
Joint Proxy Statement/Prospectus. It is being provided to holders of either
the units of limited partnership interests representing an initial investment
of $100 or $1,000, depending on the particular Partnership, per unit in those
Partnerships formed prior to April 1, 1991 and to holders of depositary
interests (singly, the "SDIs," and collectively with the units, the "Units"
unless the context requires otherwise) representing an initial investment of
$1.00 per SDI in those Partnerships formed after April 1, 1991. This Joint
Proxy Statement/Prospectus and the enclosed Form of Proxy are being provided
for use at the Special Meetings of Investors of each of the Partnerships and at
any adjournment of any of such meetings (the "Meeting") to be held at 16825
Northchase Drive, Houston, Texas at 4:00 p.m. Central Time on ______, 1998.
The Meetings are being called for the purpose of considering and voting upon
the proposal to sell all of the oil and gas assets of the Partnerships to Swift
Energy Company, and to dissolve, wind up and terminate the Partnerships (the
"Proposals"), and to transact such other business as may be properly presented
at the Special Meeting or any adjournments or postponements thereof, all in
accordance with the terms and provisions of each Partnership's Limited
Partnership Agreement (the "Partnership Agreement"), and the Texas Revised
Limited Partnership Act (the "Texas Act"). This Joint Proxy
Statement/Prospectus and enclosed Form of Proxy are first being mailed to
Investors on or about August ___, 1998.
VOTE REQUIRED
Under the Partnership Agreements, the Proposals must be approved by
the affirmative vote of Investors holding either (1) a majority or (2) at least
51% of the Units or SDIs, respectively, then held by Investors in each
particular Partnership as of the Record Date (as defined). Therefore, an
abstention by an Investor will have the same effect as a vote against the
Proposal. The solicitations are being made for votes in favor of the Proposals
(which will result in liquidation and dissolution of the Partnerships). The
number of Units outstanding (excluding the Managing General Partner's Units)
and the number of record holders are set out in each Partnership's specific
Supplement. Each Investor appearing on the records of the Partnership as of
______, 1998 (the "Record Date") is entitled to notice of their respective
Meeting and is entitled to one vote for each Unit or SDI held by such
Investor, as the case may be. VJM Corporation, a California corporation, is
the Special General Partner of the Partnerships, and owns between a 0.5% and
1.5% interest in each of the Partnerships as a General Partner, but owns no
Units or SDIs. The Managing General Partner owns a general partner's interest
in each of the Partnerships, which varies between 9.0% and 14.25%, depending
upon the particular Partnership and whether it has reached payout.
Additionally, the Managing General Partner owns a certain percentage of the
outstanding Units
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or SDIs in many Partnerships, which ownership results from the Managing General
Partner's purchase over the life of the Partnerships of Units or SDIs from
Investors under the Right of Presentment, which is contained in each of the
Partnership Agreements. Under the Partnership Agreement of each of the
Partnerships, the Managing General Partner may not vote any Units or SDIs owned
by it for matters such as the Proposals. The Managing General Partner's
non-vote, in contrast to abstention by Investors, will not affect the outcome,
because for purposes of adopting the Proposals its Units are excluded from the
total number of voting Units.
See "The Proposal--General" herein. See "The Proposal--Reasons for
the Proposal" and "Business of The Partnership--Transactions Between the
Managing General Partner and the Partnership."
PROXIES; REVOCATION
A sample of the form of proxy is attached to this Joint Proxy
Statement/Prospectus. The actual proxy to be used to register your vote on
your Proposal before you is the separate green sheet of paper included with
this Joint Proxy Statement/Prospectus. PLEASE USE THE GREEN PROXY TO CAST YOUR
VOTE ON THE PROPOSAL.
If a proxy is properly signed and is not revoked by an Investor, the
Units it represents will be voted in accordance with the instructions of the
Investor. If no specific instructions are given, the Units will be voted FOR
the Proposal. An Investor may revoke his proxy at any time before it is voted
at the Meeting. Any Investor who attends the Meeting and wishes to vote in
person may revoke his proxy at that time. Otherwise, an Investor must advise
the Managing General Partner of revocation of his proxy in writing, which
revocation must be received by the Managing General Partner at 16825 Northchase
Drive, Suite 400, Houston Texas 77060 prior to the time the vote is taken.
SOLICITATION
The solicitations are being made by the Partnerships. The
Partnerships will bear the costs of the preparation of this Joint Proxy
Statement/Prospectus and of the solicitation of proxies and such costs for each
Partnership will be allocated to the Investors and to the General Partners
according to their respective percentage interests set out, usually either 90%
and 10% respectively, or 85% and 15%, respectively, pursuant to the Partnership
Agreement. If, for example, the Managing General Partner holds approximately
5% of the Units held by all Investors, 5% of the costs borne by the Investors
will be borne by the Managing General Partner, in addition to its portion borne
as a General Partner. Solicitations will be made primarily by mail. In
addition to solicitations by mail, a number of regular or temporary employees
of the Managing General Partner may, to ensure the presence of a quorum,
solicit proxies in person or by telephone. The Managing General Partner also
may retain a proxy solicitor to assist in contacting brokers or Investors to
encourage the return of proxies, although it does not anticipate doing so.
SIMULTANEOUS PROPOSALS TO COMPANION PARTNERSHIPS
Simultaneous Proposals are being made to Investors of so-called
companion Partnerships. For example, simultaneously with the Proposal to
Investors to ultimately sell all of a specific Partnership's Property
Interests, a similar Proposal is being made to the Investors of the companion
Partnership which
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owns either the working interest or the non-operating interest in the same
properties. If both Partnerships do not approve the Proposal, it is likely to
affect the ability of both Partnerships to consummate the sale of their
Property Interests. Although the Investors in one Partnership may desire to
sell their Property Interests, the separation of the working interest and the
non-operating interests in the same properties may affect the salability of
those interests on a permanent basis. The value of a working interest burdened
by a large non-operating interest is likely to be lowered significantly.
Conversely, the value of a non-operating interest is likely to be negatively
affected by the lack of control over operations. If the two Partnerships
owning the operating and non-operating interests in the same properties do not
both approve the Proposals to sell their Property Interests and liquidate the
Partnerships, it is likely that the Proposals to both Partnerships will be
withdrawn and the value of both Partnerships' Property Interests will be
reassessed. If a Pension Partnership's companion Operating Partnership does
not approve its Proposal to liquidate and sell its Property Interests, and the
Managing General Partner is the operator of that Partnership's properties, then
it is possible but not certain that the Pension Partnership's Property Interest
might be sold under the terms set out in the Proposal. If one of the two
companion Partnerships does not approve its Proposal, then the Managing General
Partner will advise the Investors of such Partnerships accordingly.
If the Investors of companion Partnerships do not vote in favor of the
Proposals, then it is likely that the Partnerships will continue operations and
will produce their reserves until depletion with steadily decreasing rates of
cash flow and consequently steadily decreasing amounts of cash distributions to
the Investors.
The following ten Partnerships, all formed as Swift Energy Income
Partners Partnerships, do not have Companion Partnerships: 1986-D, Ltd.;
1987-A, Ltd.; 1987-B, Ltd.; 1987-C, Ltd.; 1987-D, Ltd.; 1988-A, Ltd.; 1989-3,
Ltd.; 1989-4, Ltd.; 1990-1, Ltd.; and 1990-2, Ltd.
STEPS TO IMPLEMENT THE PROPOSALS
Following the approval of the Proposals by companion Partnerships, the
Managing General Partner intends to take the following steps to implement the
proposals:
i. Pay the purchase prices of the Property Interests, transfer
the Pension Partnerships' Property Interests to their
companion Operating Partnerships, and execute assignments and
other instruments to accomplish such sale (including documents
to be executed together by the companion Partnerships);
ii. Pay or provide for payment of the Partnerships' liabilities
and obligations to creditors, if any, using the Partnerships'
cash on hand and sales proceeds;
iii. Conduct final accountings in accordance with the Partnership
Agreements and make final liquidating distributions;
iv. Cause final Partnerships' tax returns to be prepared and filed
with the Internal Revenue Service and appropriate state taxing
authorities;
v. Distribute to the Investors final Form K-1 tax information; and
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vi. File Certificates of Cancellation on behalf of the
Partnerships with the Secretary of State of the State of
Texas.
ESTIMATED SELLING COSTS
The expenses associated with the sale of the Partnerships' Property
Interests are expected to be approximately 3% of the Fair Market Value of the
Partnerships' Property Interests, primarily comprised of third party costs
incurred, including the costs of the Appraisers, legal counsel and auditors,
printing and mailing costs and related out-of-pocket expenses. The general and
administrative costs of the Managing General Partner anticipated to be incurred
in connection with the Proposals and related transactions will be met through
the normal ongoing fee set out in the Partnerships' Limited Partnership
Agreements. See "Voting on the Proposals--Solicitation."
RECOMMENDATION OF THE MANAGING GENERAL PARTNER
The Managing General Partner believes that it is in the best interests
of the Investors to liquidate and dissolve the Partnerships. Liquidation will
allow the Investors to receive the remaining value of Partnerships' reserves
currently, rather than receiving distributions over the remaining life of the
Partnerships, and to redeploy such assets. This removes the risk of future
decreases and continued volatility in oil and gas prices during the lengthy
period necessary to produce the Partnerships' interests in remaining reserves.
The Managing General Partner believes that general improvements over the last
several years in the level of natural gas prices relative to prices in the
mid-1990's make this an appropriate time to consider the sale of the
Partnerships' Property Interests. If operations continue over many years,
revenues will continue to decline while direct, operating, general and
administrative expenses continue, reducing cash distributions. Continued
operations also mean continuation of the additional costs incurred by the
Investors, including the costs associated with inclusion of information from
the Schedule K-1 relating to the Partnerships in their personal income tax
returns, while reserves continue to decline. Termination of the Partnerships
will allow preparation of final tax returns and certain additional deductions
may be generated in connection with these terminations.
THE MANAGING GENERAL PARTNER RECOMMENDS THAT THE
INVESTORS VOTE FOR THE PROPOSALS.
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CONFLICTS OF INTEREST
There are substantial conflicts of interest which exist by virtue of
the Managing General Partner acting in that capacity on behalf of all 63
Partnerships while at the same time acting as the proposed purchaser of all of
the oil and gas assets of the Partnerships. Furthermore, the Company proposes
to offer shares of its Common Stock to those Investors which own interests in
Partnerships that sell their oil and gas properties to the Company and
liquidate. These conflicts of interest are discussed below. See also "Special
Factors--Managing General Partner Benefits."
FIDUCIARY DUTIES OF MANAGING GENERAL PARTNER
The Managing General Partner has fiduciary duties to each of the
Partnerships that go beyond the specific duties and obligations imposed upon
them under the partnership agreements. The Managing General Partner in
handling the affairs of the Partnerships is expected to exercise good faith, to
use care and prudence and to act with an undivided duty of loyalty to the
Investor. Under these fiduciary duties, the Managing General Partner is
obligated to ensure that each Partnership is treated fairly and equitably in
transactions with third parties, especially where consummation of such
transactions may result in the interests of the Managing General Partner, being
opposed to, or not totally consistent with, the interests of the Investors.
Accordingly, the Managing General Partner is required to assess whether the
Company's offer to each Partnership is fair and equitable, taking into account
the unique characteristics of each Partnership which affect the value of such
Partnership's assets, and comparing these factors against similar factors
affecting the value of the oil and gas assets held by the other Partnerships.
As discussed in "The Proposals--Reasons for the Proposals" in detail, after
consideration of the terms and conditions of the Proposals, the Managing
General Partner is recommending that Investors vote for the Proposals.
LACK OF INDEPENDENT REPRESENTATION
The Managing General Partner has not retained an independent
representative or representatives to act on behalf of the Investors of each of
the Partnerships in structuring and negotiating the terms and conditions
(including the consideration to be received) upon implementation of the
Proposals. No group of Investors was empowered to negotiate the terms and
conditions of the Proposals or to determine what procedures should be in place
to safeguard the rights and interests of the Investors. In addition, no
investment banker, attorney, financial consultant or expert was engaged to
represent the interests of the Investors. On the contrary, the Managing
General Partner and the executive management of the Company have been the
parties responsible for structuring all the terms and conditions of the
Proposals. Legal counsel engaged to assist with the preparation of the
documentation for the Proposals, including the Joint Proxy
Statement/Prospectus, was engaged by the Company and did not serve, or purport
to serve, as legal counsel for the Investors. If an independent representative
or representatives had been retained for the Partnerships, the terms of the
Proposals might have been different and possibly more favorable to the
Investors.
The Managing General Partner does not believe it was necessary to
engage as independent representative to represent the interests of Investors in
order to structure a program fair to the Investors. In addition, the Managing
General Partner believes the interests of the Investors were protected in a
number of other ways described under "Fairness of the Proposals," including
retention of independent Appraisers. The Managing General Partner believes
that many of the benefits which might be obtained through retention of such a
representative are present by virtue of the use of three Appraisers, rather
than
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one Appraiser, and by asking the Appraisers to determine the "fair market
value" of each Partnership's Property Interests. If an independent
representative had been hired, there is a high likelihood that the
representative would have retained a single appraiser to value the oil and gas
assets to be sold. By virtue of the Special Transactions Committee choosing
the higher of the two values on a Partnership-by-Partnership basis, determined
by two different types of Appraisers, it is believed that many of the elements
of an auction and negotiation were present in the method of setting the value
for purchase of Partnership assets.
BENEFITS TO THE MANAGING GENERAL PARTNER OF UNDEVELOPED RESERVES
The conflicts of interest are heightened as to those 18 Partnerships
formed in the fourth quarter of 1986, the first three quarters of 1987, and
between the fourth quarter of 1992 and the second quarter of 1994, that have a
majority of their reserves in the non-producing category. If these Property
Interests are acquired by the Managing General Partner and it spends capital to
develop undeveloped reserves, the Managing General Partner will benefit from
this activity, possibly to a greater extent than the value given to such
undeveloped reserves.
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FIDUCIARY RESPONSIBILITY
MANAGING GENERAL PARTNER OF THE PARTNERSHIPS
Under Texas partnership law, the Managing General Partner is
accountable to the Partnerships as a fiduciary and is required to exercise good
faith and integrity in all its dealings in each Partnership's affairs. The
partnership agreements generally provide that neither the Managing General
Partner nor any of its affiliates performing services on behalf of the
Partnerships will be liable to the Partnerships or any of the Investors for any
conduct by any such person performed in good faith pursuant to authority
granted to such person by the partnership agreements, or in accordance with its
provisions, and any manner reasonably believed by such person to be within the
scope of authority granted to such person and in the best interests of the
Partnerships, provided that such conduct did not constitute negligence,
misconduct or a breach of fiduciary obligations to the Investors or the
Partnerships. As a result, Investors might have a more limited right of action
in certain circumstances than they would have in the absence of such provisions
in the partnership agreements.
Under the partnerships agreements of the Partnerships, the Managing
General Partner is essentially granted the full and exclusive power and
authority to control and manage the Partnerships and the Investors are granted
various rights and powers in accordance with Texas partnership law with respect
to, among others, removal of general partners, dissolution, amendment, meetings
and voting rights. Further, under Texas partnership law, a limited partner may
bring a derivative action on behalf of the partnership if all of the general
partners with authority to do so have refused to bring the action or if an
effort to cause those general partners to bring such an action is likely to
fail.
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INVESTOR ELECTION TO PARTICIPATE IN
OFFERING OF 2,500,000 SHARES OF
COMMON STOCK TO ELIGIBLE PURCHASERS
INVESTOR ELECTION TO PURCHASE SHARES
In connection with the concurrent Proposals for sale of substantially
all of the assets of 63 Partnerships to the Company and the subsequent
termination of such Partnerships, the Company is offering (the "Offering) up to
2,500,000 shares of the Company's Common Stock to Investors of Partnerships
which approve such Proposals. This offering is made solely to those Investors
of Partnerships in which the Proposals are approved by it and its companion
Partnership ("Eligible Purchasers"). Upon approval of the Proposals and sale
of the Partnerships' properties, the Partnerships' assets will consist solely
of cash which each Investor of such Partnerships will be entitled to receive as
a distribution. The Company hereby offers to each Eligible Purchaser the
opportunity to purchase shares of Common Stock with all or any portion of the
cash distribution such Investor will be entitled to receive, provided that a
minimum round lot of 100 shares must be purchased. If an Eligible Purchaser
has interests in more than one Partnership, the cash distributions he will be
entitled to receive may be aggregated to meet the minimum round lot of 100
shares requirement. Eligible Purchasers may purchase shares of Common Stock
with funds in addition to their cash distributions in order to purchase (i) the
minimum round lot of 100 shares, or (ii) additional shares in excess of the
number for which their cash distribution will be applied, subject to prorata
limitations in the event of oversubscription. No fractional shares will be
sold.
PURCHASE PRICE
The price at which the Common Stock offered hereby will be issued will
be the average price of the Common Stock as reported by the NYSE for the period
between ________ and __________, 1998.
A Prospectus Supplement to this Joint Proxy Statement/Prospectus will
be sent to Eligible Purchasers advising as to which Partnerships approved the
Proposals and the purchase price of the Shares offered hereby.
SHARES OUTSTANDING
At _______ ___, 1998, [16,515,038] shares of Common Stock were issued
and outstanding. As of such date, the 2,500,000 Shares constitute
approximately [15.1]% of the Company's issued and outstanding Common Stock.
NEW YORK STOCK EXCHANGE LISTING
The Common Stock is traded on the NYSE and the Pacific Exchange under
the symbol "SFY." Application will be made to list the Shares of Common Stock
offered hereby on the NYSE and the Pacific Exchange.
CLOSING DATE
The Company will issue checks representing full or partial
distributions and/or stock certificates representing shares of Common Stock
subscribed for hereunder on the Closing Date (approximately forty-five (45)
days after the date of the Prospectus Supplement), unless earlier terminated or
extended by the Company.
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DUE DATE
All subscriptions, revocations of prior subscriptions or additional
required consideration must be received by the Due Date (no later than thirty
(30) days after the date of the Prospectus Supplement), unless extended by the
Company.
OVERSUBSCRIPTION
In the event this Offering is oversubscribed, all subscribing Eligible
Purchasers will first be sold a round lot of 100 shares and then, if
applicable, that number of shares of Common Stock the purchase price of which
is equal to such Eligible Purchaser's cash distribution, rounded down to the
next whole share. Any remaining shares will be sold on a prorata basis based
on the number of shares such subscribers wish to purchase.
REVOCATION
Eligible Purchasers may revoke their subscriptions to purchase Shares
offered hereby at any time until the Due Date by delivering or faxing a letter
so stating or a later dated proxy, either of which must be signed by all
subscribers, to the Company at 16825 Northchase Drive, Suite 400, Houston,
Texas 77060, fax number (281) 874-2818; Attention: Investor Relations
Department.
OFFERS TO THIRD PARTIES
In the event this Offering is not fully subscribed by Eligible
Purchasers, the Company may offer any remaining Shares from time to time to
third parties including, but not limited to, underwriters and institutional
investors. Specific terms of the offer for the unsubscribed Shares of Common
Stock in respect of which this Prospectus is being delivered will be set forth
in one or more accompanying prospectus supplements. Such prospectus
supplement(s) will set forth, without limitation, the number of shares of
Common Stock and the terms of the offering and sale thereof.
METHOD OF PURCHASE
In addition to this Joint Proxy Statement/Prospectus, Investors are
being provided with (i) the relevant Partnership Supplement relating to the
Proposal before their Partnership, (ii) a proxy upon which to vote regarding
the Proposal, and (iii) a Subscription Agreement by which Investors can
purchase shares of the Common Stock offered hereby contingent upon their
becoming Eligible Purchasers. In order to purchase shares of Common Stock
offered hereby, a Subscription Agreement must be returned. If a Subscription
Agreement is not returned, an Investor will receive the cash distribution.
Provided their cash distribution is more than the amount required to purchase
the minimum number of shares, Investors may indicate on the Subscription
Agreement that they elect to (i) apply all of their cash distribution to
purchase shares of Common Stock rounded down to the nearest whole share
(fractional shares will be paid in cash), (ii) apply all of their cash
distribution toward the purchase of a designated number of shares of Common
Stock for an amount in excess of their cash distribution for which additional
consideration will be paid to the Company, (iii) apply all of their cash
distribution plus an additional designated dollar amount toward the purchase of
shares of Common Stock, or (iv) purchase shares of Common Stock with a
designated dollar amount or percentage of their cash distribution and receive
the remainder of their distribution in cash. An Eligible Purchaser whose cash
distribution is less than the amount required to purchase the minimum 100
shares may elect to apply all of his cash distribution towards the minimum
purchase of 100 shares, or a designated number in excess
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thereof, in either case additional consideration will be paid to the Company.
A second Subscription Agreement will be sent to Eligible Purchasers accompanied
by the Prospectus Supplement advising as to which Partnerships approved the
Proposals. Eligible Purchasers may subscribe, or revoke their previous
subscription, to purchase shares of the Common Stock offered hereby from the
date of this Prospectus until the Due Date, unless earlier terminated or
extended by the Company.
In the event Eligible Purchasers chose to apply all of their cash
distribution to purchase shares of Common Stock and such distribution is more
than the purchase price required to purchase a round lot of 100 shares, such
Eligible Purchasers will receive that number of shares of Common Stock rounded
down to the nearest whole share as can be purchased for such amount. If such
Eligible Purchaser elects to purchase shares of Common Stock in addition to the
number of shares purchasable with his or her cash distribution, the Eligible
Purchaser will receive a request from the Company for the additional required
purchase price. If the additional purchase price is not received by the Due
Date, the Company will deem the Eligible Purchaser's subscription for
additional shares revoked. Upon receipt of the remaining purchase price in the
form of a personal check, a certificate or certificates representing such
shares of Common Stock will be issued on the Closing Date and registered in the
name of or for the account of the Eligible Purchaser.
In the event an Eligible Purchaser subscribes for the minimum purchase
of 100 shares of Common Stock and his or her cash distribution is less than the
required purchase price for such shares, a request by the Company for the
additional purchase price required will be sent to such Eligible Purchaser. If
the additional purchase price is not received by the Due Date, the Eligible
Purchaser's subscription will be deemed revoked and the cash distribution will
be sent to such Eligible Purchaser.
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MATERIAL FEDERAL INCOME TAX CONSIDERATIONS OF ELECTING TO
RECEIVE COMMON STOCK IN LIEU OF CASH
UPON PARTNERSHIP LIQUIDATION
The following is a discussion of the material federal income tax
consequences that are generally applicable under existing United States federal
income tax law to Investors that elect to subscribe to shares of Common Stock
in lieu of receiving all or some of their Partnership liquidating distribution.
The discussion is based upon the Code, Treasury Regulations, judicial
authority, published positions of the Service and other applicable authorities,
all as in effect on the date hereof and all of which is subject to change,
possibly retroactively. This discussion does not address all aspects of
federal income taxation that may be material or relevant to particular
investors in light of their own personal circumstances. This discussion does
not address any aspect of state, local or foreign tax law or any aspect of tax
law solely applicable to qualified plans and individual retirement accounts,
all as defined under the Code, and is not applicable to nonresident aliens,
foreign corporations, debtors under the jurisdiction of a court in a case under
federal bankruptcy laws or in a receivership, foreclosure or similar
proceedings, or an investment company, financial institution or insurance
company. No ruling has been sought from the Service in connection with tax
aspects related to the proposed transactions. Accordingly, no assurance can be
given that the Service will not take a position contrary to any of the tax
aspects described below.
PAYMENT FOR STOCK WITH LIQUIDATING DISTRIBUTION
As currently proposed, Investors that subscribe for Common Stock
pursuant to this Offering will not actually receive some or all of the cash
liquidating distribution of their Partnership interest to which they otherwise
would be entitled. The amount of any cash liquidating distribution they
actually receive depends upon the purchase price to be paid for the shares they
elect to and are entitled to receive pursuant to the terms of this Offering.
For federal income tax purposes, Investors subscribing for shares of Common
Stock will be treated as though they had purchased those shares for cash, even
though they never had actual possession of the cash used to acquire the shares.
Additionally, the fact that such Investors elect to acquire shares rather than
receive cash in liquidation of their Partnership interests will not affect the
federal income tax consequences attending the liquidation of their Partnership
interests. Investors should refer to Federal Income Tax Consequences of
Adoption of the Proposals in this Prospectus for a discussion of the federal
income tax consequences related to the liquidation of their Partnership
interests. Because the purchase of shares of Common Stock will reduce the cash
received by the Investor on the Partnership liquidation, to the extent that
Investors owe federal income tax as a result of the liquidation, they may not
receive sufficient cash to pay some or all of any tax they may owe on the
liquidation. Such Investors owing tax as a result of the liquidation will have
to pay such tax from sources other than distributions from their Partnership.
STOCK PURCHASE WITH CASH LIQUIDATING DISTRIBUTION
Subject to unusual individual circumstances of an Investor, Investors
that elect to purchase shares of Common Stock will hold such shares as capital
assets and will have a holding period that begins on the day they acquire such
shares.
PARTNERS THAT ARE TAX EXEMPT PLANS
Investors in SEMPAP or SEPP Partnerships that are Tax Exempt Plans
that elect to subscribe for Common Stock and that are not subject to the debt
financing rules, are not expected to realize any current tax consequences upon
liquidation of their Partnership or the acquisition of Common Stock. See
"Federal Income Tax Consequences of Adoption of the Proposals--Tax Treatment of
Tax Exempt Plans."
95
<PAGE> 112
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY OF THE COMPANY
The Common Stock trades on the New York Stock Exchange and the Pacific
Exchange, Inc. under the symbol "SFY." At June 30, 1998, the Company had
approximately 554 stockholders of record. The following table sets forth the
range of high and low quarterly sales prices for the Common Stock of the
Company as reported by the New York Stock Exchange for the periods indicated.
<TABLE>
<CAPTION>
High Low
---------- ----------
<S> <C> <C>
1998
Third Quarter (Through July 24) . . . . . . $ 16.75 $ 11.13
Second Quarter . . . . . . . . . . . . . . 20.75 15.00
First Quarter . . . . . . . . . . . . . . . 21.00 15.88
1997
Fourth Quarter . . . . . . . . . . . . . . 29.50 19.25
Third Quarter . . . . . . . . . . . . . . . 27.22 18.86
Second Quarter . . . . . . . . . . . . . . 26.02 16.93
First Quarter . . . . . . . . . . . . . . . 34.20 19.32
1996
Fourth Quarter . . . . . . . . . . . . . . 28.86 20.91
Third Quarter . . . . . . . . . . . . . . . 22.61 15.91
Second Quarter . . . . . . . . . . . . . . 16.48 11.82
First Quarter . . . . . . . . . . . . . . . 12.84 9.89
</TABLE>
The above prices for 1996 and 1997 have been revised to reflect a 10%
Common Stock dividend declared and paid in October 1997. On July 24, 1998, the
last reported sale price for the Common Stock on the New York Stock Exchange
was $11.94 per share.
Since the Company's inception, no cash dividends have been declared on
its Common Stock, and the Company does not expect to declare cash dividends in
the foreseeable future. The Company currently intends to continue a policy of
using retained earnings for expansion of its business. Under its current
credit arrangements, the Company may not declare cash dividends on its Common
Stock that exceed $2.0 million in any fiscal year.
96
<PAGE> 113
CAPITALIZATION OF SWIFT ENERGY COMPANY
The following table sets forth as of June 30, 1998 the actual
capitalization of the Company and the capitalization of the Company as adjusted
to give effect to the Partnership Properties Acquisition and the Sonat
Properties Acquisition and the borrowings under the New Credit Facility assuming
(i) the Partnership Properties Acquisition (100% Case) is consummated for (a)
all cash ("All Cash") or (b) cash and 2.5 million shares of Common Stock
("Equity/Cash") at an assumed price of $18 per share, or the Partnership
Properties Acquisition (50% Case) is consummated for (a) all cash or (b) 2.1
million shares of Common Stock ("All Equity") at an assumed price of $18 per
share and (ii) the Sonat Properties Acquisition is consummated for all cash.
This table should be read in conjunction with "Unaudited Pro Forma Consolidated
Financial Statements," "Management's Discussion and Analysis of Financial
Condition and Results of Operations," and the Consolidated Financial Statements
included elsewhere in this Joint Proxy Statement/Prospectus.
<TABLE>
<CAPTION>
AS OF JUNE 30, 1998
---------------------------------------------------------------
AS ADJUSTED FOR THE AS ADJUSTED FOR THE
PARTNERSHIP PROPERTIES PARTNERSHIP PROPERTIES
ACQUISITION & ACQUISITION &
SONAT PROPERTIES SONAT PROPERTIES
ACQUISITION ACQUISITION
100% CASE 50% CASE
COMPANY ----------------------- ----------------------
HISTORICAL ALL CASH EQUITY/CASH ALL CASH ALL EQUITY
---------- -------- ----------- -------- ----------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C> <C>
Current Assets:
Cash and cash equivalents.......................... $ 11,506 $ 2,000 $ 2,000 $ 2,000 $ 2,000
======== ======== ======== ======== ========
Long-Term Debt:
Existing Credit Facility........................... $ 64,000 $64,000 $ 64,000 $64,000 $ 64,000
New Credit Facility................................ -- 136,526 91,526 113,226 75,026
6.25% Convertible Subordinated Notes............... 115,000 115,000 115,000 115,000 115,000
-------- -------- -------- -------- --------
Total Long-Term Debt......................... 179,000 315,526 270,526 292,226 254,026
-------- -------- -------- -------- --------
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding..................... -- -- -- -- --
Common stock, $.01 par value, 35,000,000 shares
authorized, 16,969,631 shares issued and
16,534,357 shares outstanding, respectively(a)... 170 170 195 170 191
Additional paid-in capital......................... 148,696 148,696 193,671 148,696 186,875
Treasury stock held, at cost, 435,274 shares....... (9,347) (9,347) (9,347) (9,347) (9,347)
Unearned ESOP compensation......................... (67) (67) (67) (67) (67)
Retained earnings.................................. 26,485 26,485 26,485 26,485 26,485
-------- -------- -------- -------- --------
165,937 165,937 210,937 165,937 204,137
-------- -------- -------- -------- --------
Total Capitalization......................... $344,937 $481,463 $481,463 $458,163 $458,163
======== ======== ======== ======== ========
</TABLE>
- ---------------
(a) Excludes 1,792,582 shares issuable upon exercise of employee and director
stock options outstanding as of June 30, 1998.
97
<PAGE> 114
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
The following unaudited pro forma consolidated statements of income for the
year ended December 31, 1997 and for the six months ended June 30, 1998, and the
unaudited pro forma consolidated balance sheets as of June 30, 1998
(collectively, the "Pro Forma Financial Statements") are based on the historical
consolidated financial statements of the Company, the historical combined
financial statements of all the Partnerships (See Note 1 to the Combined
Financial Statements of the Partnerships for a listing of the 63 Partnerships
whose oil and gas assets are proposed to be acquired) under the 100% Case and
the 50% Case scenarios, and the historical statements of revenues and direct
operating expenses of the oil and gas properties acquired from Sonat, adjusted
to give effect to the Partnership Properties Acquisition and the Sonat
Properties Acquisition and borrowings under the New Credit Facility under the
scenarios described below.
The Company has no reason to believe that any Partnership or group of
Partnerships is more or less likely than any other to withhold approval of the
Proposals to sell their assets and liquidate their respective Partnerships.
Accordingly the Partnership Properties Acquisition adjustments in the 100% Case
Pro Forma Financial Statements assume that all 63 Partnerships will approve
their respective Proposals. However, for purposes of presenting a pro forma case
should there be only partial approval of the Proposals, the 50% Case shows the
effect of approval of the Proposals only by those 48 Partnerships with the
lowest levels of net cash provided by operating activities, selected in
ascending order until the group of such Partnerships collectively represents
approximately 50% of the combined net cash provided by operating activities for
the six months ended June 30, 1998 of all 63 Partnerships.
The unaudited pro forma consolidated statements of income for the year
ended December 31, 1997 and for the six months ended June 30, 1998 give effect
to the Acquisitions and the borrowings under the New Credit Facility as if they
had occurred as of January 1, 1997. The unaudited pro forma consolidated balance
sheets give effect to the Acquisitions and the borrowings under the New Credit
Facility as if they had occurred as of June 30, 1998. The Pro Forma Financial
Statements assume (i) the Partnership Properties Acquisition (100% Case) is
consummated for (a) all Cash ("All Cash") or (b) cash and 2.5 million shares of
Common Stock ("Equity/Cash") at an assumed price of $18 per share, or the
Partnership Properties Acquisition (50% Case) is consummated for (a) all cash or
(b) 2.1 million shares of Common Stock ("All Equity") at an assumed price of $18
per share and (ii) the Sonat Properties Acquisition is consummated for all cash.
The Pro Forma Financial Statements present the following Acquisitions and
financing scenarios:
a) 100% Case All Cash Partnership Properties Acquisition, the Sonat
Properties Acquisition and borrowings under the New Credit Facility;
b) 100% Case Equity/Cash Partnership Properties Acquisition, the Sonat
Properties Acquisition and borrowings under the New Credit Facility;
c) 50% Case All Cash Partnership Properties Acquisition, the Sonat
Properties Acquisition and borrowings under the New Credit Facility; and
d) 50% Case All Equity Partnership Properties Acquisition, the Sonat
Properties Acquisition and borrowings under the New Credit Facility.
The pro forma adjustments are described in the accompanying Notes to
Unaudited Pro Forma Consolidated Financial Statements and are based upon
available information and certain assumptions that Management believes are
reasonable.
The Pro Forma Financial Statements do not purport to represent what the
Company's results of operations or financial condition would actually have been
had the Acquisitions in fact occurred on such dates or to project the Company's
results of operations or financial condition for any future date or period. The
Pro Forma Financial Statements should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations", the
Consolidated Financial Statements of the Company and related notes thereto, the
Combined Financial Statements of the Partnerships and related notes thereto, and
the Historical Statements of Revenues and Direct Operating Expenses of the Sonat
Properties Acquisition and related notes thereto all included elsewhere in this
Joint Proxy Statement/Prospectus.
98
<PAGE> 115
UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
(100% CASE -- ALL CASH)
ASSETS
<TABLE>
<CAPTION>
AS OF JUNE 30, 1998
------------------------------------------------------------------------
PRO FORMA
PARTNERSHIP SONAT 100% ALL CASH
PARTNERSHIP PROPERTIES PROPERTIES PARTNERSHIP
PROPERTIES ACQUISITION ACQUISITION PROPERTIES ACQ.
COMPANY ACQUISITION PRO FORMA PRO FORMA & SONAT
HISTORICAL HISTORICAL ADJUSTMENTS ADJUSTMENTS PROPERTIES ACQ.
---------- ----------- ----------- ----------- ---------------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C> <C>
Current Assets:
Cash and cash equivalents............................ $ 11,506 $ 6,805 $ (6,805)(c) $ (500)(j) $ 2,000
(9,006)(n)
Accounts receivable --
Oil and gas sales.................................. 10,385 6,249 (1,094)(a) -- 10,385
(5,155)(k)
Associated limited partnerships and joint
ventures......................................... 7,932 -- (4,337)(h) -- 3,595
Joint interest owners and other.................... 7,711 223 (223)(k) -- 7,711
Other current assets................................. 1,748 179 (179)(k) -- 1,748
-------- --------- --------- ------- --------
Total Current Assets........................... 39,282 13,456 (26,799) (500) 25,439
-------- --------- --------- ------- --------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized.................. 387,960 329,152 (57,361)(a) 76,532(g) 526,843
62,351(g)
(271,791)(k)
Unproved properties not being amortized............ 49,936 -- -- 7,500(g) 57,436
-------- --------- --------- ------- --------
437,896 329,152 (266,801) 84,032 584,279
Furniture, fixtures, and other equipment............. 6,488 -- -- -- 6,488
-------- --------- --------- ------- --------
444,384 329,152 (266,801) 84,032 590,767
Less -- Accumulated depreciation, depletion, and
amortization....................................... (84,615) (250,367) 36,125(a) -- (84,615)
214,242(k)
-------- --------- --------- ------- --------
359,769 78,785 (16,434) 84,032 506,152
-------- --------- --------- ------- --------
Other Assets:
Receivables from associated limited partnerships, net
of current portion................................. 425 -- -- -- 425
Limited partnership formation and marketing costs.... 775 -- -- -- 775
Deferred charges..................................... 4,008 -- -- 500(j) 4,508
-------- --------- --------- ------- --------
5,208 -- -- 500 5,708
-------- --------- --------- ------- --------
Total Assets................................... $404,259 $ 92,241 $ (43,233) $84,032 $537,299
======== ========= ========= ======= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities............. $ 22,190 $ 1,474 $ (884)(a) $ -- $ 17,853
(590)(k)
(4,337)(h)
Payable to associated limited partnerships........... 284 4,039 (4,039)(h) -- 284
Undistributed oil and gas revenues................... 6,463 -- -- -- 6,463
-------- --------- --------- ------- --------
Total Current Liabilities...................... 28,937 5,513 (9,850) -- 24,600
-------- --------- --------- ------- --------
Existing Credit Facility............................... 64,000 -- -- -- 64,000
New Credit Facility.................................... -- -- 52,494(g) 84,032(g) 136,526
6.25% Convertible Subordinated Notes................... 115,000 -- -- -- 115,000
Deferred Revenues...................................... 2,302 1,055 (204)(a) -- 3,153
Deferred Income Taxes.................................. 28,083 -- -- -- 28,083
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding....................... -- -- -- -- --
Common stock, $.01 par value, 35,000,000 shares
authorized, 16,969,631 shares issued, and
16,534,357 shares outstanding, respectively........ 170 -- -- -- 170
Additional paid-in capital........................... 148,696 -- -- -- 148,696
Treasury stock held, at cost, 435,274 shares......... (9,347) -- -- -- (9,347)
Unearned ESOP compensation........................... (67) -- -- -- (67)
Retained earnings.................................... 26,485 -- -- -- 26,485
Partners' capital.................................... -- 85,673 (85,673)(k) -- --
-------- --------- --------- ------- --------
165,937 85,673 (85,673) -- 165,937
-------- --------- --------- ------- --------
Total Liabilities and Stockholders' Equity..... $404,259 $ 92,241 $ (43,233) $84,032 $537,299
======== ========= ========= ======= ========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
99
<PAGE> 116
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(100% CASE -- ALL CASH)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
----------------------------------------------------------------------------------------
PRO FORMA
PARTNERSHIP SONAT 100% ALL CASH
PARTNERSHIP SONAT PROPERTIES PROPERTIES PARTNERSHIP
PROPERTIES PROPERTIES ACQUISITION ACQUISITION PROPERTIES ACQ.
COMPANY ACQUISITION ACQUISITION PRO FORMA PRO FORMA & SONAT
HISTORICAL HISTORICAL HISTORICAL ADJUSTMENTS ADJUSTMENTS PROPERTIES ACQ.
---------- ----------- ----------- ----------- ----------- ---------------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales.................... $ 69,015 $42,228 $64,872 $(6,748)(a) $ -- $ 169,367
Fees from limited partnerships....... 746 -- -- (204)(b) -- 542
Interest income...................... 2,395 330 -- (330)(c) -- 2,395
Other, net........................... 2,556 266 -- (44)(a) -- 2,778
--------- ------- ------- ------- -------- ---------
74,712 42,824 64,872 (7,326) -- 175,082
--------- ------- ------- ------- -------- ---------
Costs and Expenses:
General and administrative, net of
reimbursement...................... 3,524 5,206 -- (843)(a) -- 7,683
(204)(b)
Depreciation, depletion, and
amortization....................... 24,247 16,857 -- (2,150)(a) 22,897(d) 56,660
(5,191)(d)
Oil and gas production............... 8,779 13,774 11,322 (2,221)(a) -- 31,654
Interest expense, net................ 5,033 21 -- 4,047(e) 6,512(e) 15,613
--------- ------- ------- ------- -------- ---------
41,583 35,858 11,322 (6,562) 29,409 111,610
--------- ------- ------- ------- -------- ---------
Income before Income Taxes............. 33,129 6,966 53,550 (764) (29,409) 63,472
Provision for Income Taxes............. 10,819 -- -- 2,109(f) 8,208(f) 21,136
--------- ------- ------- ------- -------- ---------
Net Income............................. $ 22,310 $ 6,966 $53,550 $(2,873) $(37,617) $ 42,336
========= ======= ======= ======= ======== =========
Per share amounts --
Basic:............................... $ 1.35 $ 2.57
========= =========
Diluted:............................. $ 1.26 $ 2.23
========= =========
Weighted Average Shares Outstanding.... 16,493 16,493
========= =========
Ratio of earnings to fixed
charges(l)........................... 5.2x 4.4x
========= =========
SUPPLEMENTAL CASH FLOW INFORMATION(M):
Net cash provided by operating
activities......................... $ 55,256 $ 107,695
Net cash used in investing
activities......................... (132,788) (279,171)
Net cash provided by financing
activities......................... 1,784 138,310
--------- ---------
Net increase (decrease) in cash and
cash equivalents................... $ (75,748) $ (33,166)
========= =========
</TABLE>
See accompanying notes to Unaudited Pro Forma Financial Statements
100
<PAGE> 117
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(100% CASE -- ALL CASH)
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, 1998
--------------------------------------------------------------------------------------
PRO FORMA
PARTNERSHIP SONAT 100% ALL CASH
PARTNERSHIP SONAT PROPERTIES PROPERTIES PARTNERSHIP
PROPERTIES PROPERTIES ACQUISITION ACQUISITION PROPERTIES ACQ.
COMPANY ACQUISITION ACQUISITION PRO FORMA PRO FORMA & SONAT
HISTORICAL HISTORICAL HISTORICAL ADJUSTMENTS ADJUSTMENTS PROPERTIES ACQ.
---------- ----------- ----------- ----------- ----------- ---------------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales...................... $ 31,483 $11,463 $32,925 $(1,884)(a) $ -- $ 73,987
Fees from limited partnerships......... 205 -- -- (50)(b) -- 155
Interest income........................ 63 201 -- (201)(c) -- 63
Other, net............................. 1,065 91 -- (15)(a) -- 1,141
-------- ------- ------- ------- -------- --------
32,816 11,755 32,925 (2,150) -- 75,346
-------- ------- ------- ------- -------- --------
Costs and Expenses:
General and administrative, net of
reimbursement........................ 1,880 2,329 -- (395)(a) -- 3,764
(50)(b)
Depreciation, depletion, and
amortization......................... 13,985 11,323 -- (828)(a) 12,581(d) 29,928
(7,133)(d)
Oil and gas production................. 4,875 5,144 5,744 (854)(a) -- 14,909
Interest expense, net.................. 2,970 34 -- 2,000(e) 3,256(e) 8,260
-------- ------- ------- ------- -------- --------
23,710 18,830 5,744 (7,260) 15,837 56,861
-------- ------- ------- ------- -------- --------
Income before Income Taxes............... 9,106 (7,075) 27,181 5,110 (15,837) 18,485
Provision for Income Taxes............... 2,980 -- -- (668)(f) 3,857(f) 6,169
-------- ------- ------- ------- -------- --------
Net Income............................... $ 6,126 $(7,075) $27,181 $ 5,778 $(19,694) $ 12,316
======== ======= ======= ======= ======== ========
Per share amounts --
Basic:................................. $ 0.37 $ 0.75
======== ========
Diluted:............................... $ 0.37 $ 0.71
======== ========
Weighted Average Shares Outstanding...... 16,513 16,513
======== ========
Ratio of earnings to fixed charges(l).... 2.6x 2.7x
======== ========
SUPPLEMENTAL CASH FLOW INFORMATION(M):
Net cash provided by operating
activities........................... $ 25,491 $ 47,624
Net cash used in investing
activities........................... (72,469) (72,469)
Net cash provided by financing
activities........................... 56,437 56,437
-------- --------
Net increase (decrease) in cash and
cash equivalents..................... $ 9,459 $ 31,592
======== ========
</TABLE>
See accompanying notes to Unaudited Pro Forma Financial Statements
101
<PAGE> 118
UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
(100% CASE -- EQUITY/CASH)
ASSETS
<TABLE>
<CAPTION>
AS OF JUNE 30, 1998
-----------------------------------------------------------------------
PRO FORMA
PARTNERSHIP SONAT 100% EQUITY/CASH
PARTNERSHIP PROPERTIES PROPERTIES PARTNERSHIP
PROPERTIES ACQUISITION ACQUISITION PROPERTIES ACQ.
COMPANY ACQUISITION PRO FORMA PRO FORMA & SONAT
HISTORICAL HISTORICAL ADJUSTMENTS ADJUSTMENTS PROPERTIES ACQ.
---------- ----------- ----------- ----------- ----------------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C> <C>
Current Assets:
Cash and cash equivalents.............................. $ 11,506 $ 6,805 $ (6,805)(c) $ (500)(j) $ 2,000
(9,006)(n)
Accounts receivable --
Oil and gas sales.................................... 10,385 6,249 (1,094)(a) -- 10,385
(5,155)(k)
Associated limited partnerships and joint ventures... 7,932 -- (4,337)(h) -- 3,595
Joint interest owners and other...................... 7,711 223 (223)(k) -- 7,711
Other current assets................................... 1,748 179 (179)(k) -- 1,748
-------- --------- --------- ------- --------
Total Current Assets............................. 39,282 13,456 (26,799) (500) 25,439
-------- --------- --------- ------- --------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized.................... 387,960 329,152 (57,361)(a) 76,532(g) 526,843
62,351(g)
(271,791)(k)
Unproved properties not being amortized.............. 49,936 -- -- 7,500(g) 57,436
-------- --------- --------- ------- --------
437,896 329,152 (266,801) 84,032 584,279
Furniture, fixtures, and other equipment............... 6,488 -- -- -- 6,488
-------- --------- --------- ------- --------
444,384 329,152 (266,801) 84,032 590,767
Less -- Accumulated depreciation, depletion, and
amortization......................................... (84,615) (250,367) 36,125(a) -- (84,615)
214,242(k)
-------- --------- --------- ------- --------
359,769 78,785 (16,434) 84,032 506,152
-------- --------- --------- ------- --------
Other Assets:
Receivables from associated limited partnerships, net
of current portion................................... 425 -- -- -- 425
Limited partnership formation and marketing costs...... 775 -- -- -- 775
Deferred charges....................................... 4,008 -- -- 500(j) 4,508
-------- --------- --------- ------- --------
5,208 -- -- 500 5,708
-------- --------- --------- ------- --------
Total Assets..................................... $404,259 $ 92,241 $ (43,233) $84,032 $537,299
======== ========= ========= ======= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities............... $ 22,190 $ 1,474 $ (884)(a) $ -- $ 17,853
(590)(k)
(4,337)(h)
Payable to associated limited partnerships............. 284 4,039 (4,039)(h) -- 284
Undistributed oil and gas revenues..................... 6,463 -- -- -- 6,463
-------- --------- --------- ------- --------
Total Current Liabilities........................ 28,937 5,513 (9,850) -- 24,600
-------- --------- --------- ------- --------
Existing Credit Facility................................ 64,000 -- -- -- 64,000
New Credit Facility..................................... -- -- 7,494(g) 84,032(g) 91,526
6.25% Convertible Subordinated Notes.................... 115,000 -- -- -- 115,000
Deferred Revenues....................................... 2,302 1,055 (204)(a) -- 3,153
Deferred Income Taxes................................... 28,083 -- -- -- 28,083
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding......................... -- -- -- -- --
Common stock, $.01 par value, 35,000,000 shares
authorized, 16,969,631 shares issued, and 16,534,357
shares outstanding, 19,469,631 issued and 19,034,357
outstanding as adjusted for the 100%
Case -- Equity/Cash, respectively.................... 170 -- 25(i) -- 195
Additional paid-in capital............................. 148,696 -- 44,975(i) -- 193,671
Treasury stock held, at cost, 435,274 shares........... (9,347) -- -- -- (9,347)
Unearned ESOP compensation............................. (67) -- -- -- (67)
Retained earnings...................................... 26,485 -- -- -- 26,485
Partners' capital...................................... -- 85,673 (85,673)(k) -- --
-------- --------- --------- ------- --------
165,937 85,673 (40,673) -- 210,937
-------- --------- --------- ------- --------
Total Liabilities and Stockholders' Equity....... $404,259 $ 92,241 $ (43,233) $84,032 $537,299
======== ========= ========= ======= ========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
102
<PAGE> 119
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(100% CASE -- EQUITY/CASH)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
-----------------------------------------------------------------------------------------
PRO FORMA
PARTNERSHIP SONAT 100% EQUITY/CASH
PARTNERSHIP SONAT PROPERTIES PROPERTIES PARTNERSHIP
PROPERTIES PROPERTIES ACQUISITION ACQUISITION PROPERTIES ACQ.
COMPANY ACQUISITION ACQUISITION PRO FORMA PRO FORMA & SONAT
HISTORICAL HISTORICAL HISTORICAL ADJUSTMENTS ADJUSTMENTS PROPERTIES ACQ.
---------- ----------- ----------- ----------- ----------- ----------------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales................... $ 69,015 $42,228 $64,872 $(6,748)(a) $ -- $ 169,367
Fees from limited partnerships...... 746 -- -- (204)(b) -- 542
Interest income..................... 2,395 330 -- (330)(c) -- 2,395
Other, net.......................... 2,556 266 -- (44)(a) -- 2,778
--------- ------- ------- ------- -------- ---------
74,712 42,824 64,872 (7,326) -- 175,082
--------- ------- ------- ------- -------- ---------
Costs and Expenses:
General and administrative, net of
reimbursement..................... 3,524 5,206 -- (843)(a) -- 7,683
(204)(b)
Depreciation, depletion, and
amortization...................... 24,247 16,857 -- (2,150)(a) 22,897(d) 56,660
(5,191)(d)
Oil and gas production.............. 8,779 13,774 11,322 (2,221)(a) -- 31,654
Interest expense, net............... 5,033 21 -- 560(e) 6,512(e) 12,126
--------- ------- ------- ------- -------- ---------
41,583 35,858 11,322 (10,049) 29,409 108,123
--------- ------- ------- ------- -------- ---------
Income before Income Taxes............ 33,129 6,966 53,550 2,723 (29,409) 66,959
Provision for Income Taxes............ 10,819 -- -- 3,294(f) 8,208(f) 22,321
--------- ------- ------- ------- -------- ---------
Net Income............................ $ 22,310 $ 6,966 $53,550 $ (571) $(37,617) $ 44,638
========= ======= ======= ======= ======== =========
Per share amounts --
Basic:.............................. $ 1.35 $ 2.35
========= =========
Diluted:............................ $ 1.26 $ 2.09
========= =========
Weighted Average Shares Outstanding... 16,493 18,993
========= =========
Ratio of earnings to fixed
charges(l).......................... 5.2x 5.5x
========= =========
SUPPLEMENTAL CASH FLOW INFORMATION(M):
Net cash provided by operating
activities........................ $ 55,256 $ 109,997
Net cash used in investing
activities........................ (132,788) (234,171)
Net cash provided by financing
activities........................ 1,784 93,310
--------- ---------
Net increase (decrease) in cash and
cash equivalents.................. $ (75,748) $ (30,864)
========= =========
</TABLE>
See accompanying notes to Unaudited Pro Forma Financial Statements
103
<PAGE> 120
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(100% CASE -- EQUITY/CASH)
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, 1998
--------------------------------------------------------------------------------------
PRO FORMA
PARTNERSHIP SONAT 100% EQUITY/CASH
PARTNERSHIP SONAT PROPERTIES PROPERTIES PARTNERSHIP
PROPERTIES PROPERTIES ACQUISITION ACQUISITION PROPERTIES ACQ.
COMPANY ACQUISITION ACQUISITION PRO FORMA PRO FORMA & SONAT
HISTORICAL HISTORICAL HISTORICAL ADJUSTMENTS ADJUSTMENTS PROPERTIES ACQ.
---------- ----------- ----------- ----------- ----------- ----------------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales..................... $ 31,483 $11,463 $32,925 $(1,884)(a) $ -- $73,987
Fees from limited partnerships........ 205 -- -- (50)(b) -- 155
Interest income....................... 63 201 -- (201)(c) -- 63
Other, net............................ 1,065 91 -- (15)(a) -- 1,141
-------- ------- ------- ------- -------- -------
32,816 11,755 32,925 (2,150) -- 75,346
-------- ------- ------- ------- -------- -------
Costs and Expenses:
General and administrative, net of
reimbursement....................... 1,880 2,329 -- (395)(a) -- 3,764
(50)(b)
Depreciation, depletion, and
amortization........................ 13,985 11,323 -- (828)(a) 12,581(d) 29,928
(7,133)(d)
Oil and gas production................ 4,875 5,144 5,744 (854)(a) -- 14,909
Interest expense, net................. 2,970 34 -- 256(e) 3,256(e) 6,516
-------- ------- ------- ------- -------- -------
23,710 18,830 5,744 (9,004) 15,837 55,117
-------- ------- ------- ------- -------- -------
Income before Income Taxes.............. 9,106 (7,075) 27,181 6,854 (15,837) 20,229
Provision for Income Taxes.............. 2,980 -- -- (75)(f) 3,857(f) 6,762
-------- ------- ------- ------- -------- -------
Net Income.............................. $ 6,126 $(7,075) $27,181 $ 6,929 $(19,694) $13,467
======== ======= ======= ======= ======== =======
Per share amounts --
Basic:................................ $ 0.37 $ 0.71
======== =======
Diluted:.............................. $ 0.37 $ 0.68
======== =======
Weighted Average Shares Outstanding..... 16,513 19,013
======== =======
Ratio of earnings to fixed charges(l)... 2.6x 3.3x
======== =======
SUPPLEMENTAL CASH FLOW INFORMATION(M):
Net cash provided by operating
activities.......................... $ 25,491 $48,775
Net cash used in investing
activities.......................... (72,469) (72,469)
Net cash provided by financing
activities.......................... 56,437 56,437
-------- -------
Net increase (decrease) in cash and
cash equivalents.................... $ 9,459 $32,743
======== =======
</TABLE>
See accompanying notes to Unaudited Pro Forma Financial Statements
104
<PAGE> 121
UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
(50% CASE -- ALL CASH)
ASSETS
<TABLE>
<CAPTION>
AS OF JUNE 30, 1998
----------------------------------------------------------------------
PRO FORMA
PARTNERSHIP SONAT 50% ALL CASH
PARTNERSHIP PROPERTIES PROPERTIES PARTNERSHIP
PROPERTIES ACQUISITION ACQUISITION PROPERTIES ACQ.
COMPANY ACQUISITION PRO FORMA PRO FORMA & SONAT
HISTORICAL HISTORICAL ADJUSTMENTS ADJUSTMENTS PROPERTIES ACQ.
---------- ----------- ----------- ----------- ---------------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C> <C>
Current Assets:
Cash and cash equivalents........................ $ 11,506 $ 4,003 $ (4,003)(c) $ (500)(j) $ 2,000
(9,006)(n)
Accounts receivable --
Oil and gas sales.............................. 10,385 3,762 (657)(a) -- 10,385
(3,105)(k)
Associated limited partnerships and joint
ventures..................................... 7,932 -- (2,986)(h) -- 4,946
Joint interest owners and other................ 7,711 57 (57)(k) -- 7,711
Other current assets............................. 1,748 82 (82)(k) -- 1,748
-------- --------- --------- ------- --------
Total Current Assets....................... 39,282 7,904 (19,896) (500) 26,790
-------- --------- --------- ------- --------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized.............. 387,960 237,711 (42,317)(a) 76,532(g) 503,331
38,839(g)
(195,394)(k)
Unproved properties not being amortized........ 49,936 -- -- 7,500(g) 57,436
-------- --------- --------- ------- --------
437,896 237,711 (198,872) 84,032 560,767
Furniture, fixtures, and other equipment......... 6,488 -- -- -- 6,488
-------- --------- --------- ------- --------
444,384 237,711 (198,872) 84,032 567,255
Less -- Accumulated depreciation, depletion, and
amortization................................... (84,615) (184,219) 27,311(a) -- (84,615)
156,908(k)
-------- --------- --------- ------- --------
359,769 53,492 (14,653) 84,032 482,640
-------- --------- --------- ------- --------
Other Assets:
Receivables from associated limited partnerships,
net of current portion......................... 425 -- -- -- 425
Limited partnership formation and marketing
costs.......................................... 775 -- -- -- 775
Deferred charges................................. 4,008 -- -- 500(j) 4,508
-------- --------- --------- ------- --------
5,208 -- -- 500 5,708
-------- --------- --------- ------- --------
Total Assets............................... $404,259 $ 61,396 $ (34,549) $84,032 $515,138
======== ========= ========= ======= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities......... $ 22,190 $ 825 $ (569)(a) $ -- $ 19,204
(256)(k)
(2,986)(h)
Payable to associated limited partnerships....... 284 2,689 (2,689)(h) -- 284
Undistributed oil and gas revenues............... 6,463 -- -- -- 6,463
-------- --------- --------- ------- --------
Total Current Liabilities.................. 28,937 3,514 (6,500) -- 25,951
-------- --------- --------- ------- --------
Existing Credit Facility........................... 64,000 -- -- -- 64,000
New Credit Facility................................ -- -- 29,194(g) 84,032(g) 113,226
6.25% Convertible Subordinated Notes............... 115,000 -- -- -- 115,000
Deferred Revenues.................................. 2,302 809 (170)(a) -- 2,941
Deferred Income Taxes.............................. 28,083 -- -- -- 28,083
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding................... -- -- -- -- --
Common stock, $.01 par value, 35,000,000 shares
authorized, 16,969,631 shares issued, and
16,534,357 shares outstanding, respectively.... 170 -- -- -- 170
Additional paid-in capital......................... 148,696 -- -- -- 148,696
Treasury stock held, at cost, 435,274 shares....... (9,347) -- -- -- (9,347)
Unearned ESOP compensation......................... (67) -- -- -- (67)
Retained earnings.................................. 26,485 -- -- -- 26,485
Partners' capital.................................. -- 57,073 (57,073)(k) -- --
-------- --------- --------- ------- --------
165,937 57,073 (57,073) -- 165,937
-------- --------- --------- ------- --------
Total Liabilities and Stockholders'
Equity................................... $404,259 $ 61,396 $ (34,549) $84,032 $515,138
======== ========= ========= ======= ========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
105
<PAGE> 122
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(50% CASE -- ALL CASH)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
---------------------------------------------------------------------------------------
PRO FORMA
PARTNERSHIP SONAT 50% ALL CASH
PARTNERSHIP SONAT PROPERTIES PROPERTIES PARTNERSHIP
PROPERTIES PROPERTIES ACQUISITION ACQUISITION PROPERTIES ACQ.
COMPANY ACQUISITION ACQUISITION PRO FORMA PRO FORMA & SONAT
HISTORICAL HISTORICAL HISTORICAL ADJUSTMENTS ADJUSTMENTS PROPERTIES ACQ.
---------- ----------- ----------- ----------- ----------- ---------------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales..................... $ 69,015 $26,410 $64,872 $(4,333)(a) $ -- $ 155,964
Fees from limited partnerships........ 746 -- -- (126)(b) -- 620
Interest income....................... 2,395 188 -- (188)(c) -- 2,395
Other, net............................ 2,556 177 -- (30)(a) -- 2,703
--------- ------- ------- ------- -------- ---------
74,712 26,775 64,872 (4,677) -- 161,682
--------- ------- ------- ------- -------- ---------
Costs and Expenses:
General and administrative, net of
reimbursement....................... 3,524 3,509 -- (583)(a) -- 6,324
(126)(b)
Depreciation, depletion, and
amortization........................ 24,247 11,294 -- (1,312)(a) 22,978(d) 53,018
(4,189)(d)
Oil and gas production................ 8,779 8,777 11,322 (1,456)(a) -- 27,422
Interest expense, net................. 5,033 17 -- 2,245(e) 6,512(e) 13,807
--------- ------- ------- ------- -------- ---------
41,583 23,597 11,322 (5,421) 29,490 100,571
--------- ------- ------- ------- -------- ---------
Income before Income Taxes.............. 33,129 3,178 53,550 744 (29,490) 61,111
Provision for Income Taxes.............. 10,819 -- -- 1,333(f) 8,180(f) 20,332
--------- ------- ------- ------- -------- ---------
Net Income.............................. $ 22,310 $ 3,178 $53,550 $ (589) $(37,670) $ 40,779
========= ======= ======= ======= ======== =========
Per share amounts --
Basic:................................ $ 1.35 $ 2.47
========= =========
Diluted:.............................. $ 1.26 $ 2.15
========= =========
Weighted Average Shares Outstanding..... 16,493 16,493
========= =========
Ratio of earnings to fixed charges(l)... 5.2x 4.6x
========= =========
SUPPLEMENTAL CASH FLOW INFORMATION(m):
Net cash provided by operating
activities.......................... $ 55,256 $ 102,496
Net cash used in investing
activities.......................... (132,788) (255,659)
Net cash provided by financing
activities.......................... 1,784 115,010
--------- ---------
Net increase (decrease) in cash and
cash equivalents.................... $ (75,748) $ (38,153)
========= =========
</TABLE>
See accompanying notes to Unaudited Pro Forma Financial Statements
106
<PAGE> 123
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(50% CASE -- ALL CASH)
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, 1998
--------------------------------------------------------------------------------------
PRO FORMA
PARTNERSHIP SONAT 50% ALL CASH
PARTNERSHIP SONAT PROPERTIES PROPERTIES PARTNERSHIP
PROPERTIES PROPERTIES ACQUISITION ACQUISITION PROPERTIES ACQ.
COMPANY ACQUISITION ACQUISITION PRO FORMA PRO FORMA & SONAT
HISTORICAL HISTORICAL HISTORICAL ADJUSTMENTS ADJUSTMENTS PROPERTIES ACQ.
---------- ----------- ----------- ----------- ----------- ---------------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales...................... $ 31,483 $ 6,726 $32,925 $(1,094)(a) $ -- $ 70,040
Fees from limited partnerships......... 205 -- -- (23)(b) -- 182
Interest income........................ 63 121 -- (121)(c) -- 63
Other, net............................. 1,065 59 -- (9)(a) -- 1,115
-------- ------- ------- ------- -------- --------
32,816 6,906 32,925 (1,247) -- 71,400
-------- ------- ------- ------- -------- --------
Costs and Expenses:
General and administrative, net of
reimbursement........................ 1,880 1,597 -- (274)(a) -- 3,180
(23)(b)
Depreciation, depletion, and
amortization......................... 13,985 7,557 -- (501)(a) 12,664(d) 28,639
(5,066)(d)
Oil and gas production................. 4,875 3,201 5,744 (532)(a) -- 13,288
Interest expense, net.................. 2,970 23 -- 1,108(e) 3,256(e) 7,357
-------- ------- ------- ------- -------- --------
23,710 12,378 5,744 (5,288) 15,920 52,464
-------- ------- ------- ------- -------- --------
Income before Income Taxes............... 9,106 (5,472) 27,181 4,041 (15,920) 18,936
Provision for Income Taxes............... 2,980 -- -- (487)(f) 3,829(f) 6,322
-------- ------- ------- ------- -------- --------
Net Income............................... $ 6,126 $(5,472) $27,181 $ 4,528 $(19,749) $ 12,614
======== ======= ======= ======= ======== ========
Per share amounts --
Basic:................................. $ 0.37 $ 0.76
======== ========
Diluted:............................... $ 0.37 $ 0.72
======== ========
Weighted Average Shares Outstanding...... 16,513 16,513
======== ========
Ratio of earnings to fixed charges(l).... 2.6x 2.9x
======== ========
SUPPLEMENTAL CASH FLOW INFORMATION(m):
Net cash provided by operating
activities........................... $ 25,491 $ 46,633
Net cash used in investing
activities........................... (72,469) (72,469)
Net cash provided by financing
activities........................... 56,437 56,437
-------- --------
Net increase (decrease) in cash and
cash equivalents..................... $ 9,459 $ 30,601
======== ========
</TABLE>
See accompanying notes to Unaudited Pro Forma Financial Statements
107
<PAGE> 124
UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
(50% CASE -- ALL EQUITY)
ASSETS
<TABLE>
<CAPTION>
AS OF JUNE 30, 1998
----------------------------------------------------------------------
PRO FORMA
PARTNERSHIP SONAT 50% ALL EQUITY
PARTNERSHIP PROPERTIES PROPERTIES PARTNERSHIP
PROPERTIES ACQUISITION ACQUISITION PROPERTIES ACQ.
COMPANY ACQUISITION PRO FORMA PRO FORMA & SONAT
HISTORICAL HISTORICAL ADJUSTMENTS ADJUSTMENTS PROPERTIES ACQ.
---------- ----------- ----------- ----------- ---------------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C> <C>
Current Assets:
Cash and cash equivalents.............................. $ 11,506 $ 4,003 $ (4,003)(c) $ (500)(j) $ 2,000
(9,006)(n)
Accounts receivable --
Oil and gas sales.................................... 10,385 3,762 (657)(a) -- 10,385
(3,105)(k)
Associated limited partnerships and joining
ventures........................................... 7,932 -- (2,986)(h) -- 4,946
Joint interest owners and other...................... 7,711 57 (57)(k) -- 7,711
Other current assets................................... 1,748 82 (82)(k) -- 1,748
-------- --------- --------- ------- --------
Total Current Assets............................. 39,282 7,904 (10,890) (9,506) 26,790
-------- --------- --------- ------- --------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized...................... 387,960 237,711 (42,317)(a) 76,532(g) 503,331
38,839(g)
(195,394)(k)
Unproved properties not being amortized................ 49,936 -- -- 7,500(g) 57,436
-------- --------- --------- ------- --------
437,896 237,711 (198,872) 84,032 560,767
Furniture, fixtures, and other equipment................. 6,488 -- -- -- 6,488
-------- --------- --------- ------- --------
444,384 237,711 (198,872) 84,032 567,255
Less -- Accumulated depreciation, depletion, and
amortization........................................... (84,615) (184,219) 27,311(a) -- (84,615)
156,908(k)
-------- --------- --------- ------- --------
359,769 53,492 (14,653) 84,032 482,640
-------- --------- --------- ------- --------
Other Assets:
Receivables from associated limited partnerships, net
of current portion................................... 425 -- -- -- 425
Limited partnership formation and marketing costs...... 775 -- -- -- 775
Deferred charges....................................... 4,008 -- -- 500(j) 4,508
-------- --------- --------- ------- --------
5,208 -- -- 500 5,708
-------- --------- --------- ------- --------
Total Assets..................................... $404,259 $ 61,396 $ (25,543) $75,026 $515,138
======== ========= ========= ======= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities............... $ 22,190 $ 825 $ (569)(a) $ -- $ 19,204
(256)(k)
(2,986)(h)
Payable to associated limited partnerships............. 284 2,689 (2,689)(h) -- 284
Undistributed oil and gas revenues..................... 6,463 -- -- -- 6,463
-------- --------- --------- ------- --------
Total Current Liabilities........................ 28,937 3,514 (6,500) -- 25,951
-------- --------- --------- ------- --------
Existing Credit Facility................................. 64,000 -- -- -- 64,000
New Credit Facility...................................... -- -- -- 75,026(g) 75,026
6.25% Convertible Subordinated Notes..................... 115,000 -- -- -- 115,000
Deferred Revenues........................................ 2,302 809 (170)(a) -- 2,941
Deferred Income Taxes.................................... 28,083 -- -- -- 28,083
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding......................... -- -- -- -- --
Common stock, $.01 par value, 35,000,000 shares
authorized, 16,969,631 shares issued and 16,534,357
shares outstanding, 19,091,853 issued and 18,656,579
outstanding as adjusted for the 50% Case -- All
Equity, respectively................................. 170 -- 21(i) -- 191
Additional paid-in capital............................... 148,696 -- 38,179(i) -- 186,875
Treasury stock held, at cost, 435,274 shares............. (9,347) -- -- -- (9,347)
Unearned ESOP compensation............................... (67) -- -- -- (67)
Retained earnings........................................ 26,485 -- -- -- 26,485
Partners' capital........................................ -- 57,073 (57,073)(k) -- --
-------- --------- --------- ------- --------
165,937 57,073 (18,873) -- 204,137
-------- --------- --------- ------- --------
Total Liabilities and Stockholders' Equity....... $404,259 $ 61,396 $ (25,543) $75,026 $515,138
======== ========= ========= ======= ========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
108
<PAGE> 125
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(50% CASE -- ALL EQUITY)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
----------------------------------------------------------------------------------------
PRO FORMA
PARTNERSHIP SONAT 50% ALL EQUITY
PARTNERSHIP SONAT PROPERTIES PROPERTIES PARTNERSHIP
PROPERTIES PROPERTIES ACQUISITION ACQUISITION PROPERTIES ACQ.
COMPANY ACQUISITION ACQUISITION PRO FORMA PRO FORMA & SONAT
HISTORICAL HISTORICAL HISTORICAL ADJUSTMENTS ADJUSTMENTS PROPERTIES ACQ.
---------- ----------- ----------- ----------- ----------- ---------------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales.................... $ 69,015 $26,410 $64,872 $(4,333)(a) $ -- $ 155,964
Fees from limited partnerships....... 746 -- -- (126)(b) -- 620
Interest income...................... 2,395 188 -- (188)(c) -- 2,395
Other, net........................... 2,556 177 -- (30)(a) -- 2,703
--------- ------- ------- ------- -------- ---------
74,712 26,775 64,872 (4,677) -- 161,682
--------- ------- ------- ------- -------- ---------
Costs and Expenses:
General and administrative, net of
reimbursement...................... 3,524 3,509 -- (583)(a) -- 6,324
(126)(b)
Depreciation, depletion, and
amortization....................... 24,247 11,294 -- (1,312)(a) 22,978(d) 53,018
(4,189)(d)
Oil and gas production............... 8,779 8,777 11,322 (1,456)(a) -- 27,422
Interest expense, net................ 5,033 17 -- (17)(a) 5,815(e) 10,848
--------- ------- ------- ------- -------- ---------
41,583 23,597 11,322 (7,683) 28,793 97,612
--------- ------- ------- ------- -------- ---------
Income before Income Taxes............. 33,129 3,178 53,550 3,006 (28,793) 64,070
Provision for Income Taxes............. 10,819 -- -- 2,103(f) 8,418(f) 21,340
--------- ------- ------- ------- -------- ---------
Net Income............................. $ 22,310 $ 3,178 $53,550 $ 903 $(37,211) $ 42,730
========= ======= ======= ======= ======== =========
Per share amounts --
Basic:............................... $ 1.35 $ 2.30
========= =========
Diluted:............................. $ 1.26 $ 2.04
========= =========
Weighted Average Shares Outstanding.... 16,493 18,615
========= =========
Ratio of earnings to fixed
charges(l)........................... 5.2x 5.7x
========= =========
SUPPLEMENTAL CASH FLOW INFORMATION(m):
Net cash provided by operating
activities......................... $ 55,256 $ 104,447
Net cash used in investing
activities......................... (132,788) (216,820)
Net cash provided by financing
activities......................... 1,784 76,810
--------- ---------
Net increase (decrease) in cash and
cash equivalents................... $ (75,748) $ (35,563)
========= =========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
109
<PAGE> 126
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(50% CASE -- ALL EQUITY)
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, 1998
--------------------------------------------------------------------------------------
PRO FORMA
PARTNERSHIP SONAT 50% ALL EQUITY
PARTNERSHIP SONAT PROPERTIES PROPERTIES PARTNERSHIP
PROPERTIES PROPERTIES ACQUISITION ACQUISITION PROPERTIES ACQ.
COMPANY ACQUISITION ACQUISITION PRO FORMA PRO FORMA & SONAT
HISTORICAL HISTORICAL HISTORICAL ADJUSTMENTS ADJUSTMENTS PROPERTIES ACQ.
---------- ----------- ----------- ----------- ----------- ---------------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales...................... $ 31,483 $ 6,726 $32,925 $(1,094)(a) $ -- $ 70,040
Fees from limited partnerships......... 205 -- -- (23)(b) -- 182
Interest income........................ 63 121 -- (121)(c) -- 63
Other, net............................. 1,065 59 -- (9)(a) -- 1,115
-------- ------- ------- ------- -------- --------
32,816 6,906 32,925 (1,247) -- 71,400
-------- ------- ------- ------- -------- --------
Costs and Expenses:
General and administrative, net of
reimbursement........................ 1,880 1,597 -- (274)(a) -- 3,180
(23)(b)
Depreciation, depletion, and
amortization......................... 13,985 7,557 -- (501)(a) 12,664(d) 28,639
(5,066)(d)
Oil and gas production................. 4,875 3,201 5,744 (532)(a) -- 13,288
Interest expense, net.................. 2,970 23 -- (23)(e) 2,907(e) 5,877
-------- ------- ------- ------- -------- --------
23,710 12,378 5,744 (6,419) 15,571 50,984
-------- ------- ------- ------- -------- --------
Income before Income Taxes............... 9,106 (5,472) 27,181 5,172 (15,571) 20,416
Provision for Income Taxes............... 2,980 -- -- (102)(f) 3,947(f) 6,825
-------- ------- ------- ------- -------- --------
Net Income............................... $ 6,126 $(5,472) $27,181 $ 5,274 $(19,518) $ 13,591
======== ======= ======= ======= ======== ========
Per share amounts --
Basic:................................. $ 0.37 $ 0.73
======== ========
Diluted:............................... $ 0.37 $ 0.70
======== ========
Weighted Average Shares Outstanding...... 16,513 18,635
======== ========
Ratio of earnings to fixed charges(l).... 2.6x 3.5x
======== ========
SUPPLEMENTAL CASH FLOW INFORMATION(m):
Net cash provided by operating
activities........................... $ 25,491 $ 47,610
Net cash used in investing
activities........................... (72,469) (72,469)
Net cash provided by financing
activities........................... 56,437 56,437
-------- --------
Net increase (decrease) in cash and
cash equivalents..................... $ 9,459 $ 31,578
======== ========
</TABLE>
See accompanying notes to Unaudited Pro Forma Financial Statements
110
<PAGE> 127
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
(a) The Company owns general partnership interests and certain limited
partnership interests in the Partnerships, which were derived respectively
from its Managing General Partner interests and the purchase of Limited
Partners' interests acquired through the right of presentment arrangement
provided in the Partnership agreements. This pro forma adjustment
represents the elimination of the Company's ownership interests in the
Partnerships prior to the Partnership Properties Acquisition.
(b) Represents a management fee provided in the Partnership Agreements, which
had the Partnership Properties Acquisition occurred on January 1, 1997
would not have been a source of revenue to the Company nor a general and
administrative expense to the Partnerships.
(c) As a result of the Partnership Properties Acquisition, all cash in the
Partnerships will be distributed to the Limited Partners.
(d) Represents adjustment to depreciation, depletion, and amortization based on
the Company's, the Partnership Properties' Acquisition, and the Sonat
Properties' Acquisition combined historical production, reserves, and the
Company's new cost basis for the Acquisitions.
(e) Represents an increase in interest expense for the period to reflect
borrowings under the New Credit Facility (at an assumed annual interest
rate of 7.75%), as follows (in thousands):
<TABLE>
<CAPTION>
100%
100% ALL CASH EQUITY/CASH 50% ALL CASH 50% ALL EQUITY
PARTNERSHIP PARTNERSHIP PARTNERSHIP PARTNERSHIP
PROPERTIES PROPERTIES PROPERTIES PROPERTIES
ACQUISITION AND ACQUISITION AND ACQUISITION AND ACQUISITION AND
SONAT PROPERTIES SONAT PROPERTIES SONAT PROPERTIES SONAT PROPERTIES
ACQUISITION ACQUISITION ACQUISITION ACQUISITION
---------------- ---------------- ---------------- ----------------
<S> <C> <C> <C> <C>
Borrowings under New Credit
Facility......................... $136,526 $91,526 $113,226 $75,026
</TABLE>
The effects of fluctuations of 0.125% and 0.25% in interest rates in
respect to the New Credit Facility on pro forma interest would have been as
follows (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS ENDED
DECEMBER 31, 1997 JUNE 30, 1998
------------------ ------------------
0.125% 0.25% 0.125% 0.25%
------ ------ ------ ------
<S> <C> <C> <C> <C>
100% All Cash Partnership Properties Acq. and Sonat
Properties Acq. .................................. $171 $341 $86 $171
100% Equity/Cash Partnership Properties Acq. and
Sonat Properties Acq. ............................ $114 $229 $57 $114
50% All Cash Partnership Properties Acq. and Sonat
Properties Acq. .................................. $142 $283 $71 $142
50% All Equity Partnership Properties Acq. and Sonat
Properties Acq. .................................. $ 94 $188 $47 $ 94
</TABLE>
(f) Represents adjustment to income tax expense (benefit) as a result of the
Acquisitions assuming a statutory tax rate of 34.0%.
(g) Represents the recording of the estimated purchase price to oil and gas
property costs and borrowings under the New Credit Facility, as follows (in
thousands):
<TABLE>
<CAPTION>
PARTNERSHIP SONAT
PROPERTIES ACQUISITION PROPERTIES ACQUISITION
----------------------- ----------------------
100% CASE 50% CASE
---------- ---------
<S> <C> <C> <C>
Estimated net purchase price........................ $61,350 $38,050 $83,532
Estimated acquisition costs......................... 150 150 500
------- ------- -------
Estimated purchase price............................ $61,500 $38,200 $84,032
======= ======= =======
</TABLE>
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<PAGE> 128
The above purchase price is allocated based on the fair value of the assets
acquired, as follows (in thousands):
<TABLE>
<CAPTION>
PARTNERSHIP SONAT
PROPERTIES ACQUISITION PROPERTIES ACQUISITION
----------------------- ----------------------
100% CASE 50% CASE
---------- ---------
<S> <C> <C> <C>
Proved oil and gas property costs................... $62,351 $38,839 $76,532
Unproved oil and gas property costs................. -- -- 7,500
Deferred revenues................................... (851) (639) --
------- ------- -------
Total Purchase Price...................... $61,500 $38,200 $84,032
======= ======= =======
</TABLE>
(h) Represents the elimination of intercompany accounts receivables due from
the Partnerships and payables due to the Partnerships.
(i) Under the 100% Case - Equity/Cash and the 50% Case - All Equity, this
reflects the issuance of 2.5 million and 2.1 million shares, respectively
of Common Stock ($0.01 par value) at an assumed price of $18 per share.
(j) The pro forma adjustments to deferred charges and cash represents the costs
incurred to establish the New Credit Facility.
(k) Represents the elimination of the Partnerships' historical asset and
liability balances (excluding the Company's ownership interests) and
Partners' Capital.
(l) For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expense, capitalized interest, amortization of
debt issuance costs and that portion of non-capitalized rental expense
deemed to be the equivalent to interest. Earnings represents income before
income taxes from continuing operations before fixed charges. The Company's
Management uses the ratio of earnings to fixed charges to determine the
extent to which the Company's earnings are adequate to cover fixed charges
(as defined).
(m) The "Supplemental Cash Flow Information" for each scenario presented was
calculated as follows:
(i) Pro forma operating cash flows was calculated by adding to the
Company's historical operating cash flows the pro forma incremental
increase in net income and depreciation, depletion, and
amortization resulting from the Acquisitions.
(ii) Pro forma investing cash flows was calculated by adding to the
Company's historical investing cash flows the cash outlay, if any,
required to consummate the Acquisitions.
(iii) Pro forma financing cash flows was calculated by adding to the
Company's historical financing cash flows the necessary funds
required to be borrowed under the Company's New Credit Facility to
consummate the Acquisitions.
(n) Represents the use of available cash to partially fund the cash outlay
required for the Acquisitions.
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<PAGE> 129
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA OF SWIFT ENERGY COMPANY
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEAR ENDED DECEMBER 31,
------------------- ------------------------------------------------------
1998(A) 1997(A) 1997(A) 1996(A) 1995(A) 1994 1993
-------- -------- -------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and gas sales............. $ 31,483 $ 32,441 $ 69,015 $ 52,771 $ 22,528 $ 19,802 $ 15,536
Fees and Earned
Interests(b)................ 205 264 746 937 590 702 4,072
Interest income............... 63 1,750 2,395 433 212 48 201
Other, net.................... 1,065 1,195 2,556 2,157 1,762 1,073 604
-------- -------- -------- -------- -------- -------- --------
Total Revenues......... 32,816 35,650 74,712 56,298 25,092 21,625 20,413
-------- -------- -------- -------- -------- -------- --------
Costs and Expenses:
General and administrative,
net of reimbursement........ 1,880 1,808 3,524 4,150 3,336 3,323 3,206
Depreciation, depletion, and
amortization................ 13,985 11,108 24,247 16,526 8,839 7,905 7,301
Oil and gas production........ 4,875 4,172 8,779 6,142 4,907 3,764 2,680
Interest expense, net......... 2,970 2,393 5,033 694 1,115 1,795 598
-------- -------- -------- -------- -------- -------- --------
Total Costs and
Expenses............. 23,710 19,481 41,583 27,512 18,197 16,787 13,785
-------- -------- -------- -------- -------- -------- --------
Income before Income Taxes...... 9,106 16,169 33,129 28,786 6,895 4,838 6,628
Provision for Income Taxes...... 2,980 5,286 10,819 9,760 1,982 1,112 1,732
-------- -------- -------- -------- -------- -------- --------
Income Before Cumulative Effect
of Change in Accounting
Principle..................... 6,126 10,883 22,310 19,026 4,913 3,726 4,896
Cumulative Effect of Change in
Accounting Principle(b)....... -- -- -- -- -- (16,773) --
-------- -------- -------- -------- -------- -------- --------
Net Income (Loss)............... $ 6,126 $ 10,883 $ 22,310 $ 19,026 $ 4,913 $(13,047) $ 4,896
======== ======== ======== ======== ======== ======== ========
Per share amounts (c)--
Basic......................... $ 0.37 $ 0.66 $ 1.35 $ 1.27 $ 0.49 $ (1.79)(d) $ 0.68(d)
======== ======== ======== ======== ======== ======== ========
Diluted....................... $ 0.37 $ 0.61 $ 1.26 $ 1.25 $ 0.49 $ (1.79)(d) $ 0.64(d)
======== ======== ======== ======== ======== ======== ========
Weighted Average Shares
Outstanding(c)................ 16,513 16,552 16,493 15,001 10,035 7,309 7,247
======== ======== ======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
Net cash provided by operating
activities.................... $ 25,491 $ 30,285 $ 55,256 $ 37,103 $ 14,376 $ 10,395 $ 7,238
Capital expenditures............ 66,968 64,043 131,967 91,487 40,033 34,531 24,229
BALANCE SHEET DATA:
Working capital................. $ 10,345 $ 25,543 $ 1,464 $ 68,704 $ 3,247 $(13,137) $ 9,742
Total assets.................... 404,259 315,219 339,115 310,375 175,253 135,673 160,893
Long-term debt:
6.25% Convertible Subordinated
Notes....................... 115,000 115,000 115,000 115,000 -- -- --
6.5% Convertible Subordinated
Debentures.................. -- -- -- -- 28,750 28,750 28,750
Existing Credit Facility...... 64,000 -- 7,915 -- -- -- --
Stockholders' equity............ 165,937 147,115 159,401 142,762 93,346 42,127 54,466
</TABLE>
- ---------------
(a) For a discussion of the significant items affecting comparability of 1997,
1996, 1995 and for the six months ended June 30, 1998 and 1997, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" included elsewhere in this Joint Proxy Statement/Prospectus.
(b) As of January 1, 1994, the Company changed its revenue recognition policy
for earned interests. Accordingly, for 1997, 1996, 1995, and 1994, and for
the six months ended June 30, 1998 and 1997 "Fees and Earned Interests"
does not include earned interests. In 1994, the Company recognized a charge
of $16.7 million related to the change in its revenue recognition policy as
a cumulative effect of change in accounting principle.
(c) Amounts have been retroactively restated in all periods presented to: (a)
an equivalent change in capital structure as a result of two 10% stock
dividends, one in September 1994, the other in October 1997 (see Note 2 to
the Consolidated Financial Statements); and (b) the adoption of Statement
of Financial Accounting Standards No. 128, "Earnings per Share" (see Note 2
to the Consolidated Financial Statements).
(d) On a pro forma basis, assuming the 1994 change in accounting principle is
applied retroactively, basic and diluted earnings per share would have been
$0.51 for 1994 and $0.60 and $0.57, respectively, for 1993.
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<PAGE> 130
SELECTED HISTORICAL COMBINED FINANCIAL DATA OF THE PARTNERSHIPS
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEAR ENDED DECEMBER 31,
------------------ ----------------------------------------------------
1998 1997 1997 1996 1995 1994 1993
-------- ------- -------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER INVESTMENT AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Oil and gas revenues........... $ 11,463 $21,743 $ 42,228 $ 52,512 $ 43,430 $ 54,902 $ 58,061
Net income (loss).............. $ (7,075) $ 1,563 $ 6,966 $ 11,938 $ (8,346) $(14,094) $ 13,573
Investors' net income (loss)
per $100 investment(a)....... $ (2.13) $ 0.23 $ 1.64 $ 2.91 $ (2.62) $ (8.39) $ 2.93
BALANCE SHEET DATA:
Cash and cash equivalents...... $ 6,805 $ 7,429 $ 7,169 $ 3,622 $ 11,904 $ 16,269
Total assets................... $ 92,241 $108,597 $127,839 $144,418 $174,105 $195,942
Total liabilities.............. $ 6,568 $ 4,680 $ 5,403 $ 14,755 $ 17,606 $ 28,179
Investors' equity.............. $ 84,280 $101,783 $119,714 $127,264 $154,111 $165,006
General Partners' equity....... $ 1,393 $ 2,134 $ 2,722 $ 2,399 $ 2,388 $ 2,757
Investors' book value per $100
investment(a)................ $ 25.43 $ 30.71 $ 36.12 $ 38.40 $ 48.26 $ 58.11
OTHER DATA:
Net cash provided by operating
activities................... $ 11,324 $ 23,742 $ 20,694 $ 24,305 $ 32,788 $ 33,679
Net increase (decrease) in cash
and cash equivalents......... $ (624) $ 260 $ 3,547 $ (8,282) $ (4,365) $ 16,269
Cash distributions............. $ 11,169 $14,345 $ 25,485 $ 19,165 $ 18,490 $ 29,243 $ 29,471
Investors' cash distributions
per $100 investment(a)....... $ 2.96 $ 3.66 $ 6.69 $ 4.75 $ 4.91 $ 7.85 $ 8.87
</TABLE>
(a) The Investors' per $100 investment calculations are based upon the number of
$100 investments into the total combined Partnerships' Investor original
capital contributions. The Investors' original capital contributions for the
combined Partnerships totaled $331,427,600 for 1995 through June 30, 1998,
$319,308,800 for 1994 and $283,970,600 for 1993. The per $100 investment is
presented in order to achieve a comparable measure for all partnerships, as
interests in the Partnerships were sold on a basis of either $1.00 units,
$100 units or $1,000 units.
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<PAGE> 131
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the
Company's Consolidated Financial Statements and the related notes thereto set
forth elsewhere in this Joint Proxy Statement/Prospectus.
GENERAL
The Company's principal corporate objectives are the accumulation of
crude oil and natural gas reserves for production and sale and the enhancement
of the net present value of those reserves. The Company was formed in 1979
and, from 1985 to 1991, grew primarily through the acquisition of producing
properties funded through limited partnership financing. Commencing in 1991,
the Company began to emphasize the addition of reserves through increased
development and exploration drilling activity. This emphasis on development and
exploration drilling has led to additions of increasing quantities of reserves
in each of the years 1995 through 1997, and in the first six months of 1998.
The Company's revenues are primarily comprised of oil and gas sales
attributable to properties in which the Company owns a direct or indirect
interest.
Proved Oil and Gas Reserves
In 1997, the Company's proved natural gas reserves increased 88.5 Bcf
(39%) and its proved oil reserves increased 2,374,609 barrels (43%) or a total
of 102.8 Bcfe (40%). From 1995 to 1996, the Company's proved natural gas
reserves increased 82.2 Bcf (57%) and its proved oil reserves increased 62,328
barrels (1%). The Company's additions to proved reserves from its development
and exploration program were 120.2 Bcfe in 1997, 118.2 Bcfe in 1996 and 72.4
Bcfe in 1995. A substantial portion of these reserves are proved undeveloped
reserves comprising 144.6 Bcfe (40%) of total proved reserves at year-end 1997,
101.5 Bcfe (39%) of total proved reserves at year-end 1996 and 74.7 Bcfe (42%)
of total proved reserves at year-end 1995. This reflects the emphasis on
development and exploration activities.
Proved developed reserves additions in 1997 resulted from drilling
activity (which also increased undeveloped reserves) and the purchases of
minerals in place, offset somewhat by revisions of previous estimates. The
change in the Standardized Measure of Discounted Future Net Cash Flows (see
Supplemental Information to the Company's Consolidated Financial Statements and
in the Estimated Present Value of Proved Reserves (see "Business and Properties
- --Oil and Gas Reserves") from year-end 1996 to year-end 1997 is also due to the
addition of reserves through the Company's drilling activity (primarily in the
AWP Olmos Field and the Austin Chalk trend) and the purchases of minerals in
place (primarily in the AWP Olmos Field), offset by revisions of previous
estimates and by the 38% decrease in year-end 1997 natural gas prices ($2.78
per Mcf at year-end 1997 versus $4.47 per Mcf at year-end 1996), and to the 34%
decrease in year-end 1997 oil prices ($15.76 per Bbl at year-end 1997, compared
to $23.75 per Bbl the prior year). While the Company's total proved reserves
quantities at year-end 1997 increased by 40% over reserves quantities the prior
year, the PV-10 Value of those reserves decreased 26% from the PV-10 Value at
year-end 1996. This decrease was due almost entirely to pricing declines at
year-end 1997 as compared to year-end 1996, which more than offset the 40% Bcfe
increase in reserve quantities.
Under Commission guidelines, the Company's estimates of cash flows
from proved reserves are made using oil and gas sales prices and operating
costs in effect as of the dates of such estimates and are
115
<PAGE> 132
held constant throughout the life of the properties, except where such
guidelines permit alternative treatment, including, in the case of gas
contracts, the use of fixed and determinable contractual price escalations.
The $2.78 per Mcf and the $15.76 per Bbl used to calculate the PV-10 Value at
year-end 1997 were the Company's sales prices in effect as of the year-end
1997. Such prices, however, may not be indicative of future sales prices
ultimately received. As of June 30, 1998, gas prices had declined slightly to
$2.59 per Mcf and oil prices had declined to $12.32 per barrel. This price
decline was the primary cause for the decrease in the Company's ceiling test
cushion from $60.1 million at year- end 1997 to an estimated $23.4 million at
June 30, 1998. See "Risk Factors--Risks of Investment in the
Company--Volatility of Oil and Gas Prices and Market; Ceiling Test Writedowns."
LIQUIDITY AND CAPITAL RESOURCES
During the first six months of 1998, the Company relied upon its
internally generated cash flows, along with $56.1 million of bank borrowings to
fund its capital expenditures. Cash and working capital for the remainder of
1998 are expected to be provided through internally generated cash flows, bank
borrowings and debt or equity financings. During 1997, the Company relied upon
net proceeds from its $115.0 million Convertible Notes and its internally
generated cash flows, along with $7.9 million of bank borrowings.
Net Cash Provided by Operating Activities
For the six month period ended June 30, 1998, net cash provided by
operating activities decreased 16% to $25.5 million, as compared to $30.3
million during the first six months of 1997. The 1998 decrease of $4.8 million
was primarily due to a decrease in cash flows from oil and gas sales, which
decreased by $0.8 million (3%), exclusive of the non-cash amortization of
deferred revenues associated with the Company's volumetric production payment,
along with the $1.7 million decrease in interest income and the $0.6 million
increase in interest expense, a result of having expended all the net proceeds
of the $115.0 million Convertible Notes offering, as well as the $0.7 million
increase in production costs which relates to the increase in production
volumes. The decrease in oil and gas sales was due to substantially lower
product prices, somewhat offset by increased production volumes, as discussed
below.
In 1997, 1996 and 1995, the Company's operating activities provided
net cash of $55.3 million, $37.1 million and $14.4 million, respectively.
These increases were primarily due to increased production volumes, as
discussed below. The 1997 increase of $18.2 million was primarily due to an
increase in cash flows from oil and gas sales, which increased $16.5 million
(32%), exclusive of the non-cash amortization of deferred revenues associated
with the Company's volumetric production payment. The 1996 increase of $22.7
million in net cash from operations was primarily due to the cash flows from
oil and gas sales, which increased $30.4 million (146%), exclusive of the
non-cash amortization of deferred revenues associated with the Company's
volumetric production payment, partially offset by a $1.6 million increase in
oil and gas production costs, a $1.1 million increase in general and
administrative costs, plus changes to assets and liabilities and deferred
income taxes. These 1997 and 1996 increases in oil and gas sales were
primarily the result of the Company's increased drilling activity, as well as
its being affected by product price fluctuations.
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<PAGE> 133
Sale of Convertible Notes
In November 1996, the Company issued $115.0 million of the Convertible
Notes in a public offering. Proceeds of the offering were used to repay all of
the Company's bank borrowings ($33.1 million on November 25, 1996) and,
together with internally generated cash flows, to fund capital expenditures and
working capital needs through 1997. The principal terms of these Convertible
Notes are more fully described in Note 4 to the Company's Consolidated
Financial Statements included elsewhere in this Joint Proxy
Statement/Prospectus.
Credit Facilities
At June 30, 1998, the Company had outstanding borrowings of $64.0
million under its Credit Facilities. Such Credit Facilities consisted of a
$100.0 million revolving line of credit with an $80.0 million borrowing base
and a $7.0 million revolving line of credit with a $5.1 million borrowing base.
On August 18, 1998, the Company closed on the New Credit Facility,
consisting of a $250.0 million revolving line of credit, of which Bank One,
Texas, National Association, the lead bank, has committed $37.5 million and has
syndicated the balance with a group of nine other banks. The New Credit
Facility is subject to an initial borrowing base of $170.0 million. However,
an additional $30.0 million will be added to this borrowing base upon
consummation of the Partnership Properties Acquisition. As of September 1,
1998, $19.2 million of the $170.0 million borrowing base was available to the
Company. The New Credit Facility replaces all of the Company's prior bank
credit facilities. The borrowing base will be redetermined semi-annually on
the basis of reserve reports and other information available to the lenders.
In addition, the lenders may, at their discretion, make a redetermination of
the borrowing base at any time including in connection with a request by the
Company to redetermine the borrowing base, the incurrence of additional debt
and the sale or transfer of properties by the Company.
Borrowings under the New Credit Facility bear interest, at the option
of the Company, either at (i) the lead bank's prime rate, currently 8.5%, or
(ii) adjusted LIBOR plus the applicable margin, which increases as the level of
outstanding debt increases. The terms of the New Credit Facility include
restrictions such as limitations on debt obligations, certain liens, dividends
(not to exceed $2.0 million annually), a $15.0 million limit on repurchases by
the Company of its Common Stock, as well requirements as to maintenance of
certain minimum financial ratios (principally pertaining to working capital,
debt and equity ratios).
Debt Maturities
The New Credit Facility extends until August 18, 2002. The Company's
$115.0 million Convertible Notes mature November 15, 2006.
Working Capital
The Company's working capital increased in the first six months of
1998, from $1.5 million at December 31, 1997, to $10.3 million at June 30,
1998. This increase is primarily the result of approximately $8.8 million in
cash previously escrowed on the Sonat Properties (originally drawn on the
revolving line of credit) being refunded to the Company and increasing cash and
cash equivalents at period end.
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<PAGE> 134
Due to the nature of the Company's business highlighted above, the
individual components of its working capital fluctuate considerably from period
to period. The Company incurs significant working capital requirements in
connection with its role as operator of approximately 650 wells, its drilling
programs and the management of affiliated partnerships. In this capacity, the
Company is responsible for certain day-to-day cash management, including the
collection and disbursement of oil and gas revenues and related expenses.
Common Stock Repurchase Program
In March 1997, the Company's Board of Directors approved a Common
Stock repurchase program for up to $20.0 million of the Company's Common Stock
and subsequently extended the program through June 30, 1998. Purchases of
shares were made in the open market. Under this program, through June 30,
1998, the Company used $9.35 million of working capital to acquire 435,274
shares at an average cost of $21.47 per share. Although this program was
completed at June 30, 1998, the Board of Directors approved a new repurchase
program on July 23, 1998 for up to $10.0 million of the Company's common stock.
Common Stock Dividend
In October 1997, the Company declared a 10% stock dividend to
shareholders of record. The transaction was valued based on the closing price
($28.8125) of the Company's Common Stock on the New York Stock Exchange on
October 1, 1997. As a result of the issuance of 1,494,606 shares of the
Company's Common Stock as a dividend, retained earnings were reduced by
approximately $43.1 million, with the Common Stock and additional paid-in
capital account increased by the same amount.
Capital Expenditures
Capital expenditures for property, plant, and equipment during the
first six months of 1998 were $70.0 million. These capital expenditures
included: (a) $45.7 million of drilling costs, both development (25 wells) and
exploratory (5 wells) (primarily in the AWP Olmos Field and Austin Chalk
trend), (b) $14.3 million of prospect costs (principally prospect leasehold,
seismic and geological costs of unproved prospects for the Company's account),
(c) $1.3 million invested in foreign business opportunities in New Zealand
(approximately $0.6 million), in Venezuela (approximately $0.3 million) and
Russia (approximately $0.4 million), (d) $1.5 million spent on field facilities
and production equipment and (e) $4.0 million on producing property
acquisitions, with the remainder spent primarily for computer equipment and
furniture and fixtures.
The consummation of the Acquisitions, estimated at a capital cost of
$145.8 million, could impact the anticipated timing and nature of the remaining
1998 capital expenditures. The Company has budgeted capital expenditures of
$241.5 million for 1998, comprised of $145.8 million for acquisitions and $95.7
million for development and exploration. The Company currently plans to
participate in the drilling of 67 gross wells this year, compared to 182 wells
in 1997. Approximately 59% of the $95.7 million is targeted for the continued
development of the Company's two core areas. In the remaining six months of
1998, the Company expects capital expenditures to be approximately $171.5
million, including investments in all areas in which investments were made
during the first six months of the year as described above, with a particular
focus on the acquisition of producing properties. The Company currently plans
to participate in the drilling of 77 gross wells this year, compared to 182
wells in 1997. Through June 30, 1998, the
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<PAGE> 135
Company has participated in drilling 55 wells (44 development and 11
exploratory wells with 38 development and 5 exploratory successes) at a capital
cost of approximately $45.7 million to the Company. The steady growth in the
Company's unproved property account which is not being amortized is indicative
of the Company's continued focus on drilling, as the Company acquires prospect
acreage, and continued foreign activities.
The Company believes that 1998's anticipated internally generated cash
flows (expected to increase as the Company's production base increases as a
result of its drilling program and the Acquisitions), together with bank
borrowings will be sufficient to finance the costs associated with its
currently budgeted 1998 capital expenditures.
The Company's capital expenditures were approximately $132.0 million,
$91.5 million and $40.0 million for 1997, 1996 and 1995, respectively. The
1997 capital expenditures included (a) $90.3 million (68% of 1997 capital
expenditures) on development drilling (primarily in the AWP Olmos Field and
Austin Chalk trend), (b) $10.7 million (8%) on exploratory drilling, (c) $18.4
million (14%) on domestic prospect costs (principally prospect leasehold,
seismic and geological costs of unproven prospects for the Company's account),
(d) the purchase of $8.4 million (6%) of producing property interests, $7.1
million from third parties (primarily in the AWP Olmos Field), along with the
purchase of $1.3 million of limited partner interests in previously formed
partnerships through the right of presentment arrangement provided in those
partnerships, (e) $3.2 million (3%) invested in foreign business opportunities
in Russia ($0.7 million), Venezuela ($0.8 million) and New Zealand ($1.7
million), as described in Note 8 to the Company's Consolidated Financial
Statements and (f) $0.9 million (1%) spent on fixed assets. In 1997, the
Company participated in drilling 182 wells (167 development and 15 exploratory
wells with 159 development and 15 exploratory successes). The steady growth in
the Company's unproved property account ($41.8 million), which is not being
amortized, is indicative of the shift to a focus on drilling activity as the
Company acquires prospect acreage, including $3.2 million of capital
expenditures in 1997 made in relation to the Company's foreign business
opportunities, as described above.
Sonat Properties Acquisition
On July 2, 1998, the Company entered into an agreement to purchase
from Sonat, effective April 1, 1998, certain producing oil and gas properties
located in the Texas and Louisiana Austin Chalk trend for approximately $87.6
million in cash. As of April 1, 1998, estimated proved reserves for the Sonat
Properties were 91.1 Bcfe, of which approximately 56% was natural gas, with
1997 production of 22.0 Bcfe, of which approximately 51% was natural gas. The
properties include 156 producing oil and natural gas wells in the Brookeland
Field in Southeast Texas and the Masters Creed Field in Western Louisiana, 21
saltwater disposal wells, a 20% interest in two natural gas plants, associated
production facilities and working interests in approximately 200,000
undeveloped net acres containing more than 50 drilling locations. The company
will become operator of 113 of the 156 wells. The two gas plants have combined
capacity of 250.0 Mmcfe per day, and in 1997 had operating cash flow of $2.8
million. UPRC is the operator of both plants. Certain other owners of oil and
gas interests in the Sonat Properties have the preferential right to acquire
certain additional interests which, if acquired, would reduce the interest
acquired by the Company. The acquisition is expected to close in August 1998.
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<PAGE> 136
Partnership Programs
Since late 1993, the Company has offered interests in private
partnerships formed to drill for oil and gas. During the second quarter of
1998, the Company formed a drilling partnership with subscriptions of
approximately $3.5 million. During 1997, the Company formed three drilling
partnerships with subscriptions of approximately $16.8 million and in 1996
formed three partnerships with subscriptions of approximately $22.0 million.
The Company anticipates that it will continue to offer such drilling
partnerships for the foreseeable future.
At June 30, 1998, limited partnership formation and marketing costs
(which under the current drilling partnership offerings are borne by the
Company as part of the Company's general partner contribution) amounted to $0.8
million, an increase of $0.5 million when compared with the balance at December
31, 1997.
During 1996, the limited partners in 18 partnerships, which had been
in operation over nine years and had produced a substantial majority of their
reserves, voted to sell their remaining properties and liquidate the limited
partnerships. Of these partnerships, 10 were the earliest public income
partnerships (formed in 1984 to 1986) and were liquidated in 1996, and in early
1997 eight private drilling partnerships (formed in 1979 to 1985) were
liquidated. Similarly, during 1997, the limited partners in an additional 11
partnerships (formed in 1990 and 1991) voted to sell their properties and
liquidate the limited partnerships, which liquidation occurred in June 1998.
Other Financing Activities
During the third quarter of 1995, the Company sold 5.75 million shares
of Common Stock in a public offering at $8.50 per share, with net proceeds of
$45.7 million principally used to repay outstanding indebtedness and finance
the Company's development and exploration activities. In addition, as
described in Note 4 to the Company's Consolidated Financial Statements included
herein, following the Company's July 1996 announcement of their redemption, the
Debentures were converted by their holders into 2.34 million shares of the
Company's Common Stock. As a result of this conversion, the Company's
stockholders' equity increased approximately $27.0 million.
RESULTS OF OPERATIONS -- SIX MONTHS ENDED JUNE 30, 1998 AND 1997
Revenues
The Company's revenues decreased 8% during the first six months of
1998 as compared to the same period in 1997, due primarily to the decrease in
oil and gas sales, a result of lower commodity prices, and the decrease in
interest income, resulting from expenditure of the net proceeds from the
Convertible Notes by year-end 1997.
Oil and Gas Sales. Oil and gas sales decreased 3% to $31.5 million in
the first six months of 1998, compared to $32.4 million for the comparable
period in 1997. The 20% increase in natural gas production and the 18%
increase in oil production were primarily the result of production from recent
drilling activity, most notably from one of the Company's two primary
development areas, the Austin Chalk trend. The company's other primary
development area, the AWP Olmost Field, experiences a slight increase (3%) in
equivalent production when compared to 1997. The Company's net sales volume
(including the volumetric production payment volumes) of in the first six
months of 1998 increased by 19% or 2.3 Bcfe
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over volumes in the comparable 1997 period. The increases in volume were more
than offset by a 36% decrease in oil prices and a 15% decrease in gas prices
received between the two periods, as highlighted in the table below.
The elements of the Company's $1.0 million decrease in oil and gas
sales during the first six months of 1998 included: (1) volume increases that
added $5.1 million of sales from a 2.0 Bcf increase in gas sales volumes and
$1.1 million of increased sales from the 58,800 barrel increase in oil sales
volumes and (2) price variances that had a $7.2 million unfavorable impact on
sales due to the decrease in average oil prices received ($4.6 million), and a
decrease in average oil prices received ($2.6 million). Oil and gas sales for
the first six months of 1998 from the AWP Olmos Field were $17.2 million ($20.3
million in 1997) from 7.8 Bcfe of net sales volumes (7.6 Bcfe in 1997) for an
increase of 0.2 Bcfe, while the Austin Chalk trend generated oil and gas sales
of $8.9 million ($5.5 million in 1997) from 3.9 Bcfe of net sales volume (2.1
Bcfe in 1997) for an increase of 1.8 Bcfe.
Revenues from oil and gas sales comprised 96% and 91%, respectively,
of total revenues for the first six months of 1998 and 1997. The majority (85%
and 81%, respectively) of these revenues were derived from the sale of the
Company's gas production. The Company expects oil and gas production to
continue to increase due to both of the addition of oil and gas reserves
through the Company's active drilling program and from the Acquisitions.
The following table provides additional information regarding the
Company's oil and gas sales.
<TABLE>
<CAPTION>
Net Sales Volume Average Sales Price
---------------- -------------------
Oil (Bbl) Gas (Mcf) Oil (Bbl) Gas (Mcf)
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
3 Months ended 03-31-98 . . 195,114 5,858,509 $ 12.61 $ 2.28
3 Months ended 06-30-98 . . 190,225 6,159,255 11.20 2.20
------- ----------
6 Months ended 06-30-98 . . 385,339 12,017,764 11.91 2.24
======= ==========
3 Months ended 03-31-97 . . 166,240 4,903,206 $ 20.13 $ 3.06
3 Months ended 06-30-97 . . 160,341 5,154,947 17.08 2.20
------- ----------
6 Months ended 06-30-97 . . 326,581 10,046,153 18.64 2.62
======= ==========
</TABLE>
Costs and Expenses
General and administrative expenses for the first six months of 1998
increased by approximately $72,000, or 4%, when compared to the same period in
1997. This increase in costs reflects the increase in the Company's
activities. However, the Company's general and administrative expenses per
Mcfe produced decreased by 13% from $0.15 per Mcfe produced for the first six
months of 1997 to $0.13 per Mcfe produced for the comparable period in 1998.
Supervision fees netted from general and administrative expenses for the first
six months of 1998 and 1997 were $1.4 million and $1.3 million, respectively.
Depreciation, depletion, and amortization ("DD&A") increased 26%
(approximately $2.9 million) for the first six months of 1998, primarily due to
the Company's reserves additions and associated costs
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<PAGE> 138
and to the related sale of increased quantities of oil and gas produced
therefrom. The Company's DD&A rate per Mcfe of production has increased from
$0.93 per Mcfe produced in the 1997 period to $0.98 per Mcfe produced in the
1998 period, reflecting increases in the per unit cost of reserve additions.
Production costs per Mcfe decreased from $0.35 per Mcfe produced in
the 1997 period to $0.34 per Mcfe produced in the 1998 period. Primarily due
to the 19% increase in production volumes, oil and gas production costs
increased 17% (approximately $0.7 million) in the first six months of 1998 when
compared to the first six months of 1997. Supervision fees netted from
production costs for the first six months of 1998 and 1997 were $1.4 million
and $1.3 million, respectively.
Interest expense in the first six months of 1998 on the Convertible
Notes, including amortization of debt issuance costs, totaled approximately
$3.8 million (approximately $3.8 million in the 1997 period), while interest
expense on the Existing Credit Facilities, including commitment fees, totaled
$1.1 million ($24,000 in the 1997 period for commitment fees alone) for total
interest payments of $4.8 million (of which $1.9 million was capitalized). In
the first six months of 1997, these payments totaled $3.8 million (of which
$1.4 million was capitalized). The Company capitalizes that portion of
interest related to its exploration, partnership and foreign business
development activities. The increase in interest expense in 1998 is
attributable to the increase in interest incurred on the credit amounts
outstanding on its Existing Credit Facilities.
Net Income
Net income of $6.1 million and earnings per share of $0.37 for the
first six months of 1998 were both 44% lower than net income of $10.9 million
and earnings per share of $0.66 in the same period for 1997. This decrease in
net income primarily reflected the effect of a decrease in oil and gas revenues
as a result of a 36% and 15% decrease in oil and gas prices.
RESULTS OF OPERATIONS -- YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
Revenues
The Company's revenues in 1997 increased by 32% over revenues in 1996
and by 110% in 1996 over 1995 revenues, principally due to increases in oil and
gas production volumes and gas prices.
Oil and Gas Sales. The Company's net sales volumes in 1997 (including
the volumetric production payment associated with each year's production)
increased by 31% (6.0 Bcfe) over net sales volumes in 1996, while 1996 net
sales volumes increased by 74% (8.3 Bcfe) over net sales volumes in 1995. Oil
and gas sales in 1997 increased by 31% ($16.2 million) over those revenues for
1996, while in 1996 those revenues increased by 134% ($30.2 million) over oil
and gas sales in 1995. Average prices for oil increased from $15.66 per Bbl in
1995 to $19.82 per Bbl in 1996 and then decreased to $17.59 per Bbl in 1997,
while average gas prices increased from $1.77 per Mcf in 1995 to $2.57 per Mcf
in 1996 and to $2.68 per Mcf in 1997. The Company's $16.2 million increase in
oil and gas sales during 1997 was comprised of volume increases that added
$14.5 million of sales from the 5.7 Bcf increase in gas sales volumes and $1.0
million of sales from the 49,000 barrel increase in oil sales volumes, while
price variances contributed $2.2 million in increased sales from the increase
in average gas prices received, offset somewhat by a $1.5 million decrease in
sales from the decrease in average oil prices received. The Company's $30.2
million increase in oil and gas sales during 1996 was comprised of volume
increases that
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<PAGE> 139
added $13.8 million of sales from the 7.8 Bcf increase in gas sales volumes and
$1.2 million of sales from the 78,000 barrel increase in oil sales volumes,
while price variances contributed $12.7 million in increased sales from the
increase in average gas prices received and $2.5 million in increased sales
from the increase in average oil prices received.
The increases in oil and gas sales for 1997 and 1996 were primarily
the result of production from the Company's active drilling program, most
notably from the Company's two core areas, the AWP Olmos Field and the Austin
Chalk trend. The Company's 1997 oil and gas sales from the AWP Olmos Field
were $42.2 million ($29.9 million in 1996) from 15.5 Bcfe of net sales volumes
(11.2 Bcfe in 1996) for an increase of 4.3 Bcfe, while the Austin Chalk trend
generated 1997 oil and gas sales of $12.9 million ($9.4 million in 1996) from
4.9 Bcfe of net sales volumes (3.4 Bcfe in 1996) for an increase of 1.5 Bcfe.
Revenues from oil and gas sales comprised 86%, 87% and 78%,
respectively, of total revenues for 1997, 1996 and 1995. The majority (83%,
77% and 62%, respectively) of these oil and gas revenues in these periods were
derived from the sale of the Company's gas production. The Company expects oil
and gas sales to continue to increase as a direct consequence of the addition
of oil and gas reserves through the Company's active drilling program and from
the Acquisitions.
Costs and Expenses
General and administrative expenses in 1997 decreased $0.3 million
(4%) from the level of such expenses in 1996, while 1996 general and
administrative expenses increased $1.1 million (21%) over 1995 levels. The
slight decrease in these costs in 1997 over 1996 reflected the Company's
ability to continue increasing its drilling activity without increasing such
costs in 1997. The increase in costs in 1996 over 1995 reflected the increase
in the Company's activities. The Company's general and administrative expenses
per Mcfe produced have decreased in each of the past three years from $0.30 per
Mcfe produced in 1995 to $0.21 per Mcfe produced in 1996 to $0.14 per Mcfe
produced in 1997. Supervision fees netted from general and administrative
expenses for 1997, 1996 and 1995 were $2.6 million, $2.4 million and $1.9
million, respectively.
DD&A has steadily increased, primarily due to the Company's reserves
additions and associated costs and to the related sale of increased quantities
of oil and gas produced therefrom. The Company's DD&A rate per Mcfe of
production was $0.95 in 1997, $0.95 in 1996, and $0.79 in 1995, reflecting
variations in the per unit cost of reserves additions.
Production costs in 1997 increased $3.0 million (36%) over such
expenses in 1996, while those expenses in 1996 increased $1.6 million (23%)
over 1995. The increases in each of the periods primarily relate to the
increase in the Company's oil and gas sales volumes. The Company's production
costs per Mcfe produced were $0.35 in 1997, $0.31 in 1996 and $0.44 in 1995.
As discussed above, the Company's increase in production is primarily through
its drilling activities in the AWP Olmos Field and Austin Chalk trend, where
the Company already has an established operating base. The increase in
production costs has been partially offset by an exemption in these same fields
from the 7.5% Texas severance tax applicable to gas production from certain
natural gas wells certified to be in tight formations or to be deep wells by
the Texas Railroad Commission. This exemption in 1996 was a major contributor
in reducing the Company's production costs per Mcfe produced from the 1995 rate
of $0.44 to the 1996 rate of $0.31. Additionally, commencing September 1,
1996, certain wells certified as "high cost gas" wells are entitled to a
reduction of severance tax based upon a formula amount but not the full
exemption of 7.5% received
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on certified wells drilled prior to September 1, 1996. This tax exemption had
a favorable impact on the Company's production costs during 1996 and 1997,
although under the new rules, the proportionate amount of the exemption was
decreased in the 1997 period, thus contributing to the $0.04 increase in
production costs per Mcfe produced in 1997 when compared to 1996. Supervision
fees netted from production costs for 1997, 1996 and 1995 were $2.6 million,
$2.4 million and $1.9 million, respectively.
Interest expense in 1997 on the Convertible Notes, including
amortization of debt issuance costs, totaled $7.5 million, compared to $0.7
million on the Convertible Notes and $1.0 million on the 6.5% Convertible
Subordinated Debentures due 2003 (the "Debentures") in 1996 and $2.0 million on
only the Debentures in 1995, while interest expense on the Credit Facilities,
including commitment fees, totaled $0.1 million ($1.1 million in 1996 and $1.7
million in 1995), for a 1997 total of $7.6 million (of which $2.6 million was
capitalized). The 1996 total was $2.8 million (of which $2.1 million was
capitalized), while the 1995 total was $3.7 million (of which $2.6 million was
capitalized). The Company capitalizes a portion of interest related to certain
exploration, partnership and foreign business development activities. The
increase in interest expense in 1997 is attributable to the larger outstanding
principal amount on the Convertible Notes ($115.0 million) compared to the
Debentures ($28.8 million), offset to some degree by larger outstanding
balances under the Credit Facilities in 1996 and by the $2.4 million in
interest income earned in 1997 on the portion of the net proceeds of the
Convertible Notes invested pending use. The lower amount of interest expense
in 1996, compared to 1995 was attributable to a smaller average balance under
the Company's credit lines necessary to finance the Company's capital
expenditures, as well as to the Company's paying only six months of interest on
the Debentures due to their conversion into Common Stock in the third quarter
of 1996.
Net Income
Net income of $22.3 million and earnings per share of $1.35 for 1997
were 17% and 6% higher, respectively, than net income of $19.0 million and
earnings per share of $1.27 in 1996. This increase in net income primarily
reflected the effect of a 31% increase in oil and gas sales revenues as a
result of a 36% increase in natural gas production, an 8% increase in crude oil
production and a 4% increase in gas prices received, offset somewhat by an 11%
decrease in oil prices received. The lower percentage increase in earnings per
share reflects a 10% increase in weighted average shares outstanding in 1997 as
a result of the conversion of the Debentures into 2.34 million shares of Common
Stock in the third quarter of 1996. The Company's consolidated effective tax
rate was 32.7%, 33.9% and 28.7% in 1997, 1996 and 1995, respectively.
Net income of $19.0 million and earnings per share of $1.27 for 1996
were 287% and 159% higher, respectively, than net income of $4.9 million and
earnings per share of $0.49 in 1995. This increase in net income primarily
reflected the effect of a 134% increase in oil and gas sales revenues as a
result of a 98% increase in natural gas production, a 14% increase in crude oil
production and product price improvements. The lower percentage increase in
earnings per share reflects a 49% increase in weighted average shares
outstanding for 1996 as a result of the sale of 5.75 million shares of Common
Stock in the third quarter of 1995 and the conversion of the Debentures into
2.34 million shares of Common Stock in the third quarter of 1996.
YEAR 2000
A comprehensive assessment of the Year 2000 issue has been conducted
and a compliance plan is currently underway. The Company is in the process of
receiving verification of Year 2000 compliance from all hardware and software
vendors. The Company does not expect that the cost to modify its information
technology infrastructure will be material to its financial condition or
results of operation. The Company also does not anticipate any material
disruption in its operations as a result of any Year 2000 compliance issues.
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BUSINESS AND PROPERTIES
GENERAL
The Company is engaged in the development, exploration, acquisition
and operation of oil and gas properties, with a primary focus on U.S. onshore
natural gas reserves. As of December 31, 1997, the Company had interests in
over 1,500 oil and gas wells located in 10 states, of which the Company
operated 650 wells representing 91% of its proved reserve base. At such date,
the Company had proved reserves of 361.5 Bcfe, of which approximately 87% were
natural gas, 60% were proved developed and 93% were located in Texas. The
Company's primary focus is development and exploration drilling in its two core
areas: the AWP Olmos Field located in South Texas and the Texas Austin Chalk
trend. The AWP Olmos Field is characterized by long-lived reserves, while the
Austin Chalk trend is characterized by short-lived reserves with high initial
production and rapid decline rates. These fields accounted for approximately
74% and 15%, respectively, of the Company's proved reserves as of December 31,
1997, and approximately 61% and 19%, respectively, of the Company's production
during 1997.
On August 26, 1998, the Company purchased the Sonat Properties from
Sonat. As a result of the Sonat Property Acquisition and assuming the
Proposals are approved by all the Partnerships, the Acquisitions provide the
Company with significant proved reserves as well as additional development and
exploratory opportunities in its core areas. The Company expects to utilize
its operating expertise in these areas to successfully develop and exploit
these properties. As a result of these Acquisitions, the Company will increase
its interest in oil and gas wells to over 1,650 wells, of which the Company
will operate approximately 765 wells. The Company expects reserves in the
Austin Chalk trend to increase to approximately 26% of proved reserves as a
result of the Acquisitions.
The Company maintains a flexible capital spending program in order to
take advantage of the relative economic attractiveness of either drilling or
acquisition opportunities. Over the last several years, the Company's growth
in reserves and production has resulted primarily from its increased acreage
position and drilling activities in the AWP Olmos Field and the Austin Chalk
trend. Capital expenditures for development and exploration drilling,
primarily in the Company's core areas, were $25.8 million, $71.8 million and
$101.0 million in 1995, 1996 and 1997, respectively, while capital expenditures
for acquisitions were $3.5 million, $1.5 million and $8.4 million. The Company
has budgeted capital expenditures of $241.5 million for 1998, comprised of
$145.8 million for the Acquisitions and $95.7 million for development and
exploration. Approximately 59% of the $95.7 million is targeted for the
continued development of the Company's two core areas. The Company is also
actively pursuing exploratory drilling opportunities in high potential projects
elsewhere in the Gulf Coast region and in New Zealand.
In 1997, the Company increased its proved reserves by 40% primarily
from additions through drilling, resulting in the replacement of 522% of 1997
production. The Company's five-year average reserve replacement costs were
$0.76 per Mcfe. As a result of increased drilling activity, 1997 production
increased 31% over 1996 production. Due to economies of scale, geographic
concentration and increased production, general and administrative expenses and
production costs have fallen from $0.57 and $0.39 per Mcfe, respectively, in
1992 to $0.14 and $0.35 per Mcfe, respectively, in 1997. For the six months
ended June 30, 1998, such costs were $0.13 and $0.34 per Mcfe, respectively.
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BUSINESS STRATEGY
The Company pursues a balanced growth strategy that includes an active
drilling program, strategic acquisitions and advanced technologies. The
Company's operating philosophy is to increase its reserve base through both
drilling and acquisitions, shifting the balance between the two in response to
market conditions.
Key elements of the Company's strategy include the following:
Active Drilling Program. With the expanded inventory of drilling
prospects that the Company will have following the consummation of the
Acquisitions and when economic drilling conditions improve, the Company intends
to pursue an active program of development drilling in its core areas together
with selected step-out and exploratory drilling on its undeveloped acreage.
Exploratory drilling is based on a "controlled risk" approach, focusing on
regions where the exploration objective would allow the Company to utilize its
technological or geological expertise and that are in close proximity to known
production. In 1997, the Company drilled 128 net development wells, 127 of
which were in the Company's AWP Olmos Field and Austin Chalk trend core areas,
and seven net exploration wells, of which two were in such core areas. During
this period, the Company had net drilling success rates of 97% for development
wells and 38% for exploratory wells. The Company expects to drill a total of
77 gross wells in 1998, 55 of which had been drilled as of June 30, 1998 at a
capital cost of approximately $45.7 million to the Company. The Company
anticipates that drilling activity in the AWP Olmos Field and the Austin Chalk
trend will represent 59% of the total 1998 drilling budget. The Company looks
to reduce its overall risk exposure with respect to development and exploration
activities by entering into joint development agreements with industry partners
to share capital exposure for any individual well. As an example of this
strategy, the Company has active joint development projects with, among others,
UPRC and Chevron in the Austin Chalk trend, in which the Company serves as
operator of a majority of the wells. See "Business and Properties--
Properties" and "Foreign Activities."
Strategic Acquisitions. The Company continuously reviews acquisition
opportunities, including opportunities to acquire properties with significant
proved producing reserves and substantial undeveloped acreage for future
drilling activities. The Company targets properties located in close proximity
to its current reserves, where such reserves can be increased through
development drilling and where operating efficiencies can be achieved. Using
these criteria, the Company employs a disciplined, market-driven approach to
acquisitions to augment its drilling program. The Company has conducted an
ongoing acquisition program since its inception.
Advanced Technologies. In order to minimize the risks associated with
development and exploration drilling and enhance operating efficiencies, the
Company has devoted considerable resources to developing advanced technological
expertise. These technologies include 2-D and 3-D seismic analysis, amplitude
versus offset studies (AVO) and detailed formation depletion studies. The
Company has also attained substantial expertise in horizontal well drilling
technology, having participated as of June 30, 1998 in 70 such wells in the
Austin Chalk trend, 62 of which have been successful. Additionally, the
Company uses innovative fracturing methods, coiled tubing technology and
computer telemetry to monitor well performance. As a result of these
technologies, the Company has enhanced its production yields while reducing its
costs per Mcfe. Application of these technologies has enabled the Company to
achieve historical drilling success rates that exceed applicable U.S. industry
averages.
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RECENT DEVELOPMENTS
In accordance with its business strategy described above, the Company
plans to enter into the following transactions:
Sonat Properties Acquisition. On August 26, 1998 the Company purchased
from Sonat, effective April 1, 1998, certain producing oil and gas properties
located in the Texas and Louisiana Austin Chalk trend for approximately $87.6
million in cash, with a majority of the purchase price being allocated to
proved reserves. As of April 1, 1998, estimated proved reserves for the Sonat
Properties were 91.1 Bcfe, of which approximately 56% was natural gas, with
1997 production of 22.0 Bcfe, of which approximately 51% was natural gas. The
properties include 156 producing oil and natural gas wells in the Brookeland
Field in Southeast Texas and the Masters Creek Field in Western Louisiana, 21
saltwater disposal wells, a 20% interest in two natural gas plants, associated
production facilities and working interests in approximately 200,000
undeveloped net acres containing more than 50 drilling locations. The Company
became operator of 113 of the 156 wells. Net production averaged 8,997 barrels
per day and 34.5 Mmcf per day (88.5 Mmcfe per day) during February 1998.
Production is expected to rise to 12,000 barrels per day and 49.0 Mmcf per day
(121.0 Mmcfe per day) during the third quarter of 1998 when equipment repairs
involving seven Sonat-operated wells are completed at the Masters Creek gas
processing facility. The two gas plants have combined capacity of 250 Mmcfe
per day, and in 1997 had operating cash flow of $2.8 million. UORC is the
operator of both plants.
The Sonat Properties Acquisition extends one of the Company's core
areas by adding producing reserves that the Company believes will significantly
increase its production on a short-term basis. Furthermore, as a result of the
Company's extensive experience in other parts of the Austin Chalk trend, the
Company believes that it can successfully exploit incremental drilling
opportunities in the future.
Partnership Properties Acquisition. The Company hereby offers to
purchase all of the Partnership Properties owned by each of the 63
Partnerships, subject to approval by the investors in each such Partnership.
As of December 31, 1997, estimated proved reserves of the Partnership
Properties were 93.5 Bcfe, with 1997 production of 12.4 Bcfe. As of January 1,
1998, the net purchase price for the Partnership Properties (after deducting
the portion of the total purchase price allocated to the Company through its
ownership interests in the Partnerships) is expected to be approximately $70.6
million, subject to certain reductions based on cash flow distributions to the
Partnerships prior to closing. A portion of the purchase price for the
Partnership Properties may be funded by the issuance of up to 2.5 million
shares of Common Stock to Investors in the Partnerships who elect to receive
Common Stock in lieu of some or all of the cash that they will be entitled to
receive upon their Partnership's liquidation.
The Company believes that the Partnership Properties Acquisition
represents an opportunity to acquire properties having development and
exploration potential, without incurring additional overhead. As a result of
the Company's geological and operating experience with most of the Partnership
Properties, with its technological and drilling expertise, the Company expects
to enhance the recovery of the reserves on these properties.
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<PAGE> 144
PROPERTIES
The Company's proved reserves are geographically concentrated, with
approximately 89% of the Company's proved reserves at December 31, 1997,
attributable to its two largest properties, the AWP Olmos Field and the Austin
Chalk trend.
AWP Olmos Field
The Company's most significant property is located in the AWP Olmos
Field in South Texas. The Company has extensive expertise in the AWP Olmos
Field and a long history of experience with low-permeability tight-sand
formations typical of this field. Since acquiring its first AWP Olmos Field
acreage in 1988, the Company has made detailed studies of drainage patterns in
the formation and has introduced innovations in fracture design and
implementation methods and coiled tubing technology, all of which reduce
overall costs and improve recoveries.
The AWP Olmos Field represented approximately 74% of the Company's
proved reserves at December 31, 1997, and approximately 61% of the Company's
1997 production. As a result of the Acquisitions, the Company expects the AWP
Olmost Field to decrease to approximately 52% of the Company's proved reserves.
At December 31, 1997, the Company owned interests in and was the operator of
approximately 400 wells producing natural gas from the Olmos Sand Formation at
a depth of approximately 10,000 feet. The Company has engaged in extensive
fracturing operations to increase the permeability of the formation and flow of
gas from the wells. In addition, the Company has used coiled tubing velocity
strings in several wells to improve production rates and is able to monitor
fracturing operations from its Houston headquarters through direct computer
access to the field.
During 1997, the Company purchased, for approximately $3.8 million,
Olmos producing properties strategically located in the heart of its existing
leasehold in the AWP Olmos Field. The purchase included 35 producing wells, 35
new development drilling locations, and a related 20-mile pipeline. Net proved
reserves attributable to the purchase are approximately 25.0 Bcfe, with current
production of approximately 2.0 Mmcfe per day. Since the purchase, the
Company's efforts to improve production have resulted in an increase to 2.5
Mmcfe per day.
In 1997, the Company drilled 142 gross (137 successful) development
wells (120.4 net) in this field and one unsuccessful exploratory well northwest
of the field. The Company or entities managed by the Company own 100% of the
working interest in this field. During 1997, the Company maintained its
leasehold position in this area. The Company anticipates further acquisition
of acreage in this area in the future, if warranted. The Company plans to
drill approximately 57 additional development wells and four exploratory wells
to the Olmos formation in 1998.
Austin Chalk Trend
At December 31, 1997, the Company owned drilling and production rights
in 175,022 gross acres and 112,918 net acres in the Austin Chalk trend
containing substantial proved undeveloped reserves. The Austin Chalk trend
represented approximately 15% of the Company's proved reserves at December 31,
1997. As a result of the Acquisitions, the Company expects the Austin Chalk
trend to approximately 26% of the Company's proved reserves. Production from
this field constituted 19% of oil and gas production in 1997. The wells in
this trend are all horizontal, primarily natural gas, that deliver high initial
flow rates
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and strong initial cash flows which decline rapidly. The Company believes
these reserves complement its long-lived reserves in the AWP Olmos Field.
Since 1992, the Company has participated in 55 horizontal wells in the trend
with a 91% success rate, including 16 successful development wells out of 17
gross (6.3 net) drilled and two successful exploratory wells out of five
drilled in 1997. The Company believes its success is attributable to its
ability to identify hydrocarbon-bearing fractures, relying on its expertise in
seismic data analysis, and its ability to drill and operate horizontal wells.
The Company anticipates drilling 30 development wells and three exploratory
wells in the Austin Chalk during 1998. The acquisition of seismic data in the
Cougar Run and Nimitz areas in Fayette County has helped in upgrading locations
to drill numerous horizontal wells targeting the Austin Chalk formation
determined from previous seismic data acquisitions and subsequent successful
drilling in the Rocky Creek and North Fayetteville prospects.
Substantial portions of its property interests in the Austin Chalk
trend have been acquired through joint development arrangements with industry
partners who are active participants in exploration of the Austin Chalk trend.
The Company entered into its first such venture in 1993, in an arrangement that
covered approximately 8,800 acres, in which the Company currently has an
average working interest of 25%. In September 1995, the Company entered into
another joint development agreement providing for an area of mutual interest
covering 19,500 gross acres and pursuant to which the Company and its industry
partner in the venture alternate serving as operator of any wells drilled on
the acreage. During 1996, the Company purchased its partner's interest in
9,500 of these gross acres, and the joint development arrangement now covers a
10,000 gross acre block in which the Company expects to have an average working
interest of 30% to 35% based on certain assumptions relating to elections with
respect to the drilling of various wells. The Company has a 100% working
interest in the 9,500 acres.
In 1996, the Company reached joint development arrangement covering
approximately 8,000 acres in Washington County, Texas, in which the Company
owns a 25% working interest with an industry partner. This joint development
area has been further expanded to encompass approximately 17,000 gross acres.
Simultaneously, the Company entered into two additional joint development
agreements covering an approximate 6,300 gross acre area, in which the Company
owns a 50% working interest, and an approximate 8,100 gross acre area, in which
the Company owns a 75% working interest and serves as operator.
Also in 1997, the Company acquired a 50% working interest in 20,000
net acres adjoining the North Fayetteville Prospect area, for which it will
serve as operator. The initial test well was spudded in December 1997.
The Company signed a joint development agreement with Chevron
encompassing 144,000 gross (64,000 net) acres in central Texas where the
Company and Chevron will participate together in the drilling of a number of
wells targeted for the Edwards Limestone, Sligo, Austin Chalk and other
formations in Fayette, Colorado and Austin counties. The Company and Chevron
will each own an undivided 50% working interest within the area of mutual
interest (AMI), with the Company serving as the operator. The initial test
well within the AMI will be the Swift-Coufal #1-H well, which is targeted as a
horizontal Austin Chalk completion.
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<PAGE> 146
EXPLORATION AND DEVELOPMENT DRILLING ACTIVITIES
In 1991, the Company began to develop an inventory of development and
exploration drilling prospects. Drilling locations were selected through
intensive geological and geophysical studies of the Company's undeveloped
acreage and other prospects. During 1995, the Company added 72 Bcfe of proved
reserves through drilling, and in 1996, reserves added by drilling increased to
118 Bcfe. In 1997, reserves added by drilling increased to 120 Bcfe, with the
Company's success rate at 47% for exploratory wells (seven out of 15 drilled)
and 95% for development wells (159 out of 167 drilled). These successful
drilling results have led to acquisition by the Company of additional acreage
during 1997 in the area of its two core properties, the AWP Olmos Field in
South Texas and the Austin Chalk trend in Austin, Colorado, Fayette, Walker and
Washington counties in central and eastern Texas.
The Company pursues a "controlled risk" approach to exploratory
drilling, focusing on specific U.S. regions where its technical staff has
considerable experience, that are in close proximity to known production and
where the potential for significant reserves exists. The Company seeks to
minimize its exploration risk by investing in multiple prospects, farming out
interests to industry partners and drilling funds, utilizing advanced
technologies and drilling in different types of geological formations. The
Company utilizes basin studies to analyze targeted formations based on their
potential size, risk profile and economic parameters.
The Company's development strategy is designed to maximize the value
and productivity of its existing properties through development drilling and
recovery methods, enhancing production results through improved field
production techniques, lowering production costs and applying the Company's
technical expertise and resources to exploit producing properties efficiently.
The Company employs various recovery techniques, including water flooding,
fracturing reservoir rock through the injection of high-pressure fluid,
inserting coiled tubing velocity strings to speed gas flow and acid treatments.
The Company believes that the application of fracturing technology and coiled
tubing has resulted in significant increases in production and decreases in
drilling and operating costs, particularly in the Company's largest single
property, the AWP Olmos Field.
The Company's development and exploration activities are conducted by
its in-house exploration staff, assisted by professionals from other
departments, including reservoir engineers, geologists, geophysicists,
petrophysicists, landmen and drilling and operations engineers. The Company
believes that one of the keys to its success has been its team approach, which
integrates multiple disciplines to maximize efficient utilization of
information leading to drillable projects.
The Company has increasingly utilized advanced seismic technology to
enhance the quality of its drilling efforts, including two-dimensional (2-D)
and three-dimensional (3-D) seismic analysis and amplitude versus offset (AVO)
studies. During 1997, the Company completed its first international seismic
acquisition program in two key areas of its holding in New Zealand. In New
Zealand's Rimu prospect, the Company acquired a 30 kilometer cross-swath, as
well as 2-D seismic data in the Tawa prospect, complementing existing 2-D and
3-D data. It also acquired 21 miles of 2-D data in the Wheeler Ranch Olmos
trend in South Texas and 51 miles of data in the Fayette County Austin Chalk
trend. Two more prospects in the Ark-La-Tex region were shot in the form of
2-D swaths of approximately 16 miles each.
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<PAGE> 147
In addition to exploration and development activities in the AWP Olmos
Field and the Austin Chalk trend, the Company is currently focusing its
exploration activities in three main geographical areas: the Gulf Coast Basin,
the Wyoming Powder River Basin and the North Louisiana Salt Basin.
Gulf Coast Basin
The Company defines this area as including all the Texas counties and
Louisiana parishes along the Gulf Coast and extending into Mississippi and
Alabama, which includes all target formations present except the Austin Chalk
trend and the Olmos sand. In 1997, one successful development well (out of
three) and four successful exploratory wells (out of six) were drilled in the
Gulf Coast Basin, following two successful development wells and one successful
exploratory wells drilled in 1996. In 1998, 11 development and exploratory
wells and three exploratory wells are scheduled for drilling in the Gulf Coast
Basin. The locations were selected utilizing traditional geologic studies
combined with analyses of available seismic data.
During 1997, the Company acquired 1,920 gross acres in Jim Hogg County
in which the Company owns a minimum 75% working interest. [Additionally, the
Company has an oil and gas lease option on an additional 8,500 gross acres in
the area until August 1, 1998.] A well drilled by the Company to the Queen
City formation, the Chaparral #1, in 1997 was highly successful. Of the [11]
development wells expected to be drilled in the Gulf Coast Basin in 1998, [six]
will be drilled on this acreage. Three of those [six] have already been
successfully drilled in the first half of 1998, [with the fourth well currently
being drilled.] Further work in the area through licensing additional 2-D data
and acquiring 3-D data jointly with a third party will help complete the
analysis and the interpretation of the acreage for future development in 1998.
In the Sherburne prospect in south central Louisiana, the Company has
been working with 2-D seismic data to identify the location of a Sparta
formation, which was successfully tested in the second quarter of 1998, and has
designed a 2-D seismic cross-swath acquired in March 1998, to identify deeper
high-yield structures in the Wilcox trend. A Sparta development well is
planned for the fourth quarter of 1998.
Wyoming Powder River Basin
The Company intends to drill [one] development and [two] exploratory
wells and in 1998. In 1997, the Company successfully drilled one out of two
exploratory wells in the Minnelusa trend in Campbell County, Wyoming. In 1996,
the Company successfully drilled one out of three development wells and one out
of three exploratory wells in the trend. The Minnelusa trend has been the
subject of extensive study by the Company's multi-disciplinary teams in order
to identify the location of stratigraphic hydrocarbon traps. Recently, the
Company has shifted its emphasis to pursue the Cretaceous trend in southern
Campbell County and northern Converse County in Wyoming, as well as north into
the Williston Basin in Daniels County, Montana. The Company has licensed
various existing 2-D seismic data to help map the structural and stratigraphic
traps that have been identified for drilling in 1998.
North Louisiana Salt Basin
The North Louisiana Salt Basin covers the neighboring corners of
Arkansas, Louisiana, and Texas (Ark-La-Tex region). In 1997, the Company
drilled two wells, one development and one exploratory, one
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<PAGE> 148
of which (the development well) was successful. In 1996, the Company drilled
five successful wells, four of which were exploratory. The Company plans to
drill [two] exploratory wells in the region in 1998. In this area, the
Smackover formation is a prolific hydrocarbon producer from multiple levels and
from a variety of structures, including fault traps, salt anticlines, basement
structures and stratigraphic traps. In northern Louisiana and southern
Arkansas in the Smackover trend, in 1997 the Company acquired and completed
processing two sets of 2-D seismic swaths that have been interpreted to yield
numerous exploratory locations. Additional seismic acquisitions are planned in
Bossier Parish, Louisiana, to delineate a prospect pending the drilling of a
test well to determine the presence of hydrocarbon sands in the area.
132
<PAGE> 149
The following table sets forth the results of the Company's drilling
activities during the three fiscal years ended December 31, 1997:
<TABLE>
<CAPTION>
Gross Wells Net Wells
------------------------------------ -----------------------------------
Year Type of Well Total Producing Dry Total Producing Dry
------ ---------------- ------ -------------- ----- ------- ----------- -----
<S> <C> <C> <C> <C> <C> <C> <C>
1997 Development 167 159 8 127.5 123.8 3.9
Exploratory 15 7 8 7.2 2.7 4.5
1996 Development 142 134 8 110.5 106.7 3.8
Exploratory 11 7 4 5.9 3.7 2.2
1995 Development 68 65 3 38.7 38.0 0.7
Exploratory 8 4 4 3.5 1.5 2.0
</TABLE>
OPERATIONS
The Company generally seeks to be named as operator for wells in which
it or its affiliated limited partnerships and joint ventures have acquired a
significant interest, although this typically occurs only when it or its
affiliates own the major portion of the working interest in a particular well
or field. The Company acts as operator of approximately 650 wells at December
31, 1997, which comprise approximately 91% of the Company's total proved
reserves.
As operator, the Company is able to exercise substantial influence
over development and enhancement of a well and to supervise operation and
maintenance activities on a day-to-day basis. The Company does not conduct the
actual drilling of wells on properties for which it acts as operator. Drilling
operations are conducted by independent contractors engaged and supervised by
the Company. The Company employs petroleum engineers, geologists and other
operations and production specialists who strive to improve production rates,
increase reserves and lower the cost of operating its oil and gas properties.
Oil and gas properties are customarily operated under the terms of a
joint operating agreement, which provides for reimbursement of the operator's
direct expenses and monthly per-well supervision fees. Per-well supervision
fees vary widely depending on the geographic location and producing formation
of the well, whether the well produces oil or gas, and other factors. Such
fees received by the Company in 1997 ranged from $200 to $1,481 per well per
month.
MARKETING OF PRODUCTION
The Company typically sells its gas production at or near the
wellhead, although in some cases gas must be gathered by the Company or other
operators and delivered to a central point. Gas production is generally sold
in the spot market at prevailing prices. The Company generally sells its oil
production at prevailing market prices. The Company does not refine any oil it
produces. During the year ended December 31, 1997, three oil or gas purchasers
each accounted for 10% or more of the Company's revenues, with those purchasers
together accounting for 42%. Three oil or gas purchasers accounted for 10% or
more of the Company's revenues during the year ended December 31, 1996, with
those purchasers
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<PAGE> 150
accounting for approximately 51%. Because of the availability of other
purchasers, the Company does not believe that the loss of any single oil or gas
purchaser or contract would materially affect its sales.
The Company has entered into gas processing and gas transportation
agreements with respect to its natural gas production in the AWP Olmos Field
with Valero Transmission, L.P. and its affiliates ("Valero") for up to 75.0
Mmcf per day. These contracts have initial six-year terms, with automatic
one-year extensions unless earlier terminated. The Company believes that these
arrangements adequately provide for its gas transportation and processing needs
in the AWP Olmos Field for the foreseeable future. Additionally, at the
discretion of the Company and Valero, the gas processed and transported under
these agreements may be sold to Valero at monthly indexed prices based upon the
current natural gas price. Effective July 31, 1997, Valero was merged with
Pacific Gas & Electric Corporation ("PG&E"). This merger did not affect the
contractual obligations between the Company and Valero.
Much of the Company's Austin Chalk production from Fayette and
Washington counties, Texas, is currently dedicated under long-term gas purchase
and gas processing contracts with Aquila Southwest Pipeline Corporation
("Aquila"). The Company believes that these contracts adequately provide for
the gas purchase and processing needs of its Austin Chalk production, subject
to practical limitations inherent in gas field operations. The prices received
are redetermined monthly to reflect the current natural gas price.
The following table summarizes sales volumes, sales prices and
production cost information for the Company's net oil and gas production for
the three-year period ended December 31, 1997. "Net" production is production
that is owned by the Company either directly or indirectly through partnerships
or joint venture interests and produced to its interest after deducting
royalty, limited partner and other similar interests.
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------------------
1997 1996 1995
------------------- --------------------- ------------------
<S> <C> <C> <C>
Net Sales Volume:
Oil (Bbls) 672,385 623,386 545,435
Gas (Mcf)(1) 21,359,434 15,696,798 7,913,963
Gas Equivalents (Mcfe) 25,393,744 19,437,114 11,186,573
Average Sales Price:
Oil (Per Bbl) $ 17.59 $ 19.82 $ 15.66
Gas (Per Mcf) $ 2.68 $ 2.57 $ 1.77
Average Production Cost (per Mcfe) $ 0.45 $ 0.43 $ 0.61
</TABLE>
_______________
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<PAGE> 151
(1) Natural gas production for 1997, 1996 and 1995 includes 1,015,226,
1,156,361 and 1,211,255 Mcf, respectively, delivered under the volumetric
production payment agreement pursuant to which the Company is obligated to
deliver certain monthly quantities of natural gas (see Note 1 to the Company's
Consolidated Financial Statements). Under the volumetric production payment
entered into in 1992, as of December 31, 1997, the Company has a remaining
commitment to deliver approximately 2.0 Bcf of gas meeting certain heating
equivalent and quality standards through the later of October 2000 or such time
as the Company has delivered the requisite amount of gas under the agreement
when such agreement expires. Since entering into this agreement, these
properties have produced in excess of the required monthly delivery
requirements.
PRICE RISK MANAGEMENT
The Company's revenues are primarily the result of sales of its oil
and natural gas production. Market prices of oil and natural gas may fluctuate
and adversely affect operating results. To reduce some of this risk, the
Company does engage periodically in certain limited hedging activities, but
only to the extent of buying protection price floors for portions of its and
the limited partnerships' oil and gas production. Costs and benefits
associated with these price floors are recorded accordingly as a reduction or
increase, respectively, in oil and gas sales revenue and were not significant
for any year presented. The cost to purchase a put options is amortized over
the option period.
For the first [seven] months of 1998, the Company had entered into
hedging contracts covering 11,000,000 MMBtu and 120,000 barrels of the
Company's and its affiliated Partnerships' production, representing 48% and 13%
of oil and gas production, respectively, at a total cost of approximately $0.4
million with benefits of approximately $0.1 million being received, resulting
in a net cash outlay of approximately $0.3 million.
ACQUISITION ACTIVITIES
Since 1979, the Company has acquired approximately $478.0 million of
producing oil and natural gas properties on behalf of itself and its
co-investors in 129 separate transactions. In recent years, the Company's
acquisition activities have declined, as it has fulfilled its obligation to buy
producing properties for the remaining partnerships that invested in such
properties. As of December 31, 1997, all such partnerships investing in
producing properties had spent their available capital resources on producing
properties. Therefore, the Company anticipates all future acquisition activity
will be for its own behalf. Cumulatively, the Company has acquired for its own
account approximately $121.5 million of producing properties, with original
proved reserves estimated at 182.2 Bcfe. The Company's acquisition
expenditures in the past three years were approximately $8.4 million, $1.5
million and $3.5 million for properties acquired in 1997, 1996 and 1995,
respectively. The Company's acquisition costs have averaged $0.31 per Mcfe
over this three-year period.
The Company uses a disciplined, market-driven approach to
acquisitions, generally seeking to acquire properties located in close
proximity to its current reserves with the potential to add reserves and
production through additional development and exploration efforts.
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<PAGE> 152
FOREIGN ACTIVITIES
New Zealand
During 1996, the Company was issued two Petroleum Exploration Permits
by the New Zealand Minister of Energy. The first permit covered approximately
65,000 acres in the Onshore Taranaki Basin of New Zealand's North Island, and
the second covered approximately 69,300 adjacent acres. The Company formed a
wholly owned subsidiary, Swift Energy New Zealand Limited, for the purpose of
conducting its New Zealand activities and assigned its interest in the permits
to that subsidiary during the third quarter of 1997. In March 1998, the
Company surrendered approximately 46,400 acres covered in the first permit and
the remaining acreage has been included as an extension of the area covered in
the second permit. Under the terms of the expanded permit, the Company is
obligated to drill one exploratory well prior to August 12, 1999. All other
obligations under the permit have been fulfilled including the reinterpretation
of existing seismic data and the acquisition and processing of new seismic
data. On April 1, 1998, the Company reached an agreement in principle with
Bligh Oil & Minerals N.L. ("Bligh"), an Australian company, to obtain from
Bligh a 25% working interest in two additional New Zealand Petroleum
Exploration Permits, which cover approximately 51,900 acres, in exchange for a
5% working interest in the Company's permit. At December 31, 1997, the
Company's investment in New Zealand was approximately $2.5 million, which is
included in the unproved properties portion of oil and gas properties.
Russia
On September 3, 1993, the Company signed a Participation Agreement
with Senega, a Russian Federation joint stock company (in which the Company has
an indirect interest of less than 1%), to assist in the development and
production of reserves from two fields in Western Siberia. The agreement
provides the Company with a minimum of 5% net profits interest from the sale
of hydrocarbon products from the fields in exchange for the Company's
managerial, technical and financial support to Senega. Additionally, the
Company purchased a 1% net profits interest from Senega for $0.3 million.
On December 10, 1997, the Company amended and restated a Participation
Agreement with Senega that it originally entered into in 1995. Under the
amended and restated Participation Agreement, the Company retains its 6% net
profits interest in the Samburg Field and has agreed to assist Senega in
obtaining investments necessary to develop the field. Senega is charged with
the management and control of the field development. At December 31, 1997, the
Company's investment in Russia was approximately $10.2 million and is included
in the unproved properties portion of oil and gas properties.
Venezuela
The Company formed a wholly owned subsidiary, Swift Energy de
Venezuela, C.A., for the purpose of submitting a bid on August 5, 1993, under
the Venezuelan Marginal Oil Field Reactivation Program. Although the Company
did not win the bid, it has continued to pursue cooperative ventures involving
other fields and opportunities in Venezuela. The Company evaluated a number of
blocks being offered by Petroleos de Venezuela, S.A. under the Third Operating
Agreement Round in 1997, but decided against submitting any bid on these
blocks. The Company has entered into an agreement with Tecnoconsult, S.A., a
Venezuelan company, to jointly formulate and submit a proposal to Petroleos de
Venezuela, S.A. for the construction and operation of a methane pipeline.
Currently, the technical and economic feasibility of the project is under
study. At December 31, 1997, the Company's investment in Venezuela was
approximately $2.4 million and is included in the unproved properties portion
of oil and gas properties, net of impairments of $45,668.
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<PAGE> 153
OIL AND GAS RESERVES
The following table presents information regarding proved reserves of
oil and gas attributable to the Company's interests in producing properties as
of December 31, 1997, 1996 and 1995. The information set forth in the table is
based on proved reserves reports prepared by the Company and audited by H.J.
Gruy, independent petroleum engineers. H.J. Gruy's estimates were based upon
review of production histories and other geological, economic, ownership and
engineering data provided by the Company. In accordance with Commission
guidelines, the Company's estimates of future net revenues from the Company's
proved reserves and the PV-10 Value are made using oil and gas sales prices in
effect as of the dates of such estimates and are held constant throughout the
life of the properties, except where such guidelines permit alternate
treatment, including, in the case of gas contracts, the use of fixed and
determinable contractual price escalations. Proved reserves as of December 31,
1997, were estimated based upon weighted average prices of $2.78 per Mcf and
$15.76 per barrel, compared to $4.47 and $2.41 per Mcf and $23.75 and $18.07
per barrel as of December 31, 1996 and 1995, respectively. As of June 30,
1998, such prices were $2.59 per Mcf and $12.32 per barrel. The Company has
interests in certain tracts that are estimated to have additional hydrocarbon
reserves that cannot be classified as proved and are not reflected in the
following table. The proved reserves presented for all periods also exclude
any reserves attributable to the volumetric production payment.
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<PAGE> 154
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------------------
1997 1996 1995
------------------ ---------------------- ----------------------
<S> <C> <C> <C>
ESTIMATED PROVED OIL AND GAS RESERVES
Net natural gas reserves (Mcf):
Proved developed 191,108,214 135,424,880 81,532,025
Proved undeveloped 123,197,455 90,333,321 62,035,495
-------------- --------------- ---------------
Total 314,305,669 225,758,201 143,567,520
============== =============== ===============
Net oil reserves (Bbl):
Proved developed 4,288,696 3,622,480 3,313,226
Proved undeveloped 3,570,222 1,861,829 2,108,755
-------------- --------------- ---------------
Total 7,858,918 5,484,309 5,421,981
============== =============== ===============
ESTIMATED PRESENT VALUE OF PROVED RESERVES
Estimated present value of future net cash
flows from proved reserves discounted at 10%
per annum:
Proved developed $ 244,365,044 $ 310,408,949 $ 85,536,873
Proved undeveloped 105,979,738 160,776,008 61,501,536
-------------- --------------- ---------------
Total $ 350,344,782 $ 471,184,957 $ 147,038,409
============== =============== ===============
</TABLE>
The table also sets forth estimates of future net revenues presented
on the basis of unescalated prices and costs in accordance with criteria
prescribed by the Commission and their PV-10 Value. Operating costs,
development costs and certain production-related taxes were deducted in
arriving at the estimated future net revenues. No provision was made for
income taxes. The estimates of future net revenues and their present value
differ in this respect from the standardized measure of discounted future net
cash flows set forth in Supplemental Information to the Consolidated Financial
Statements of the Company, which is calculated after provision for future
income taxes. In cases where producing properties are subject to gas purchase
contracts and the amount of gas purchased thereunder was reduced during 1997,
gas projections used to estimate future net revenues were based on the reduced
gas purchases for the affected producing properties. The assumption was made
that purchases in 1998 and thereafter will be made at an unrestricted level.
The Company's total proved developed and undeveloped reserves have
increased substantially (40%) at December 31, 1997, when compared to December
31, 1996, as shown above and in Supplemental Information to the Company's
Consolidated Financial Statements. A substantial portion (40%) of the reserves
are proved undeveloped reserves, which reflects the increased emphasis on
development and
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<PAGE> 155
exploration activities, and is consistent with the proportions in 1996 of 39%
proved undeveloped and 61% proved developed.
Changes in quantity estimates and the estimated present value of
proved reserves are affected by the change in crude oil and natural gas prices
at the end of each year. While the Company's total proved reserves quantities
(on an equivalent Bcfe basis) at year-end 1997 increased by 40% over reserves
quantities a year earlier, the PV-10 Value of those reserves decreased 26% from
the PV-10 Value at year-end 1996. This decrease was primarily due to high
product prices at year-end 1997, with the price of gas declining 38% during
1997 from $4.47 at December 31, 1996, to $2.78 at year-end 1997, matched by a
34% decrease in the price of oil between the two dates, from $23.75 to $15.76.
Estimations of the PV-10 Value and other reserve data are subject to a number
of factors. [See "Risk Factors - Uncertainty of Estimates of Reserves and
Future Net Revenues."]
A portion of the Company's proved reserves has been accumulated
through the Company's interests in the limited partnerships for which it serves
as general partner. The estimates of future net cash flows and their present
values, based on period end prices, assume that some of the limited
partnerships in which the Company owns interests will achieve payout status in
the future. Four of the limited partnerships had achieved payout status at
June 30, 1998.
No other reports on the Company's reserves have been filed with any
federal agency. Estimates of the PV-10 Value and other reserve data are
subject to a number of factors. [See "Risk Factors - Uncertainty of Estimates
of Reserves and Future Net Revenues."]
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<PAGE> 156
OIL AND GAS WELLS
The following table sets forth the gross and net wells in which the
Company owned an interest at the following dates:
<TABLE>
<CAPTION>
Oil Wells Gas Wells Total Wells(1)
-------------------- ------------------- ------------------
<S> <C> <C> <C>
December 31, 1997
Gross . . . . . . . . 625 926 1,551
Net . . . . . . . . . 48.1 381.7 429.8
December 31, 1996
Gross . . . . . . . . 734 1,068 1,802
Net . . . . . . . . . 59.5 222.9 282.4
December 31, 1995
Gross . . . . . . . . 3,049 995 4,044
Net . . . . . . . . . 88.5 121.6 210.1
</TABLE>
_________________
(1) Excludes 16 service wells in 1997, 26 service wells in 1996 and 39
service wells in 1995.
OIL AND GAS ACREAGE
As is customary in the industry, the Company generally acquires oil
and gas acreage without any warranty of title except as to claims made by,
through or under the transferor. See "Risk Factors--Risks Associated with
Acquisitions" for a discussion of the risks associated with such a policy. The
following table sets forth the developed and undeveloped domestic leasehold
acreage held by the Company at December 31, 1997:
<TABLE>
<CAPTION>
Developed Undeveloped
-------------------------------- ---------------------------------
Gross Net Gross Net
------------- ------------- -------------- -------------
<S> <C> <C> <C> <C>
Alabama . . . . . . . . . . . . . . . 4,495.38 616.70 292.00 41.17
Arkansas . . . . . . . . . . . . . . 4,139.49 2,070.92 9,608.55 6,858.86
Kansas . . . . . . . . . . . . . . . -- -- 4,600.00 1,988.80
Louisiana . . . . . . . . . . . . . . 44,481.57 13,610.37 20,085.44 11,750.85
Mississippi . . . . . . . . . . . . . 5,236.49 3,379.84 1,828.22 489.42
Montana . . . . . . . . . . . . . . . -- -- 4,851.28 4,851.28
Nebraska . . . . . . . . . . . . . . -- -- 1,707.04 1,029.53
Oklahoma . . . . . . . . . . . . . . 38,554.53 14,976.93 3,733.90 1,251.50
Texas . . . . . . . . . . . . . . . . 117,016.60 64,543.20 173,589.65 124,198.13
Wyoming . . . . . . . . . . . . . . . 7,859.27 2,060.84 69,278.53 53,824.64
All other states . . . . . . . . . . 157.64 6.80 4,850.44 285.33
------------- ------------- -------------- -------------
Total . . . . . . . . . . . . . . 221,940.97 101,265.60 294,425.05 206,569.51
============= ============= ============== =============
</TABLE>
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<PAGE> 157
PARTNERSHIPS
For many years, the Company relied on limited partnerships as its
principal financing vehicle to fund its activities. The Company has formed and
served as managing general partner of 108 limited partnerships which have
raised a total of approximately $505.6 million at June 30, 1998. However, in
recent years as the Company has increasingly shifted its emphasis to
development and exploration activities and its reserves base has grown, the
Company has significantly reduced its reliance on limited partnership
financing. The Company is hereby submitting the Proposals to the Investors in
63 Partnerships to sell substantially all of their oil and gas assets to the
Company and thereafter liquidate the Partnerships. If all such proposals are
approved, only four public production partnerships and 12 private drilling
partnerships will remain.
The Company intends to continue offering private drilling partnerships
in the future. The existing private drilling partnerships have been offered on
a no-load basis under which the Company pays all selling and offering expenses
of the partnership offering. Amounts paid by the Company are treated as a
capital contribution to each partnership. The Company also is entitled to a
general and administrative overhead allowance and an incentive amount. In
certain partnerships, the Company does not bear any of the costs incurred in
acquiring or drilling properties. The Company pays approximately 20% of all
continuing costs (approximately 30% after payout and 35% after 200% payout),
and the Company is entitled to receive 20% of net revenues distributed by each
such partnership prior to payout, 30% distributed after payout, and 35%
distributed after 200% payout. As managing general partner of certain other
partnerships, the Company pays out of its own corporate funds the capital costs
(consisting of all prospect costs and the non-deductible, tangible portion of
drilling and completion costs). The Company pays approximately 40% of all
continuing costs (approximately 45% after payout and 50% after 200% payout),
and the Company is entitled to receive 40% of net revenues distributed by each
such partnership prior to payout, 45% distributed after payout and 50%
distributed after 200% payout.
Under the terms of the Company's limited partnership programs, the
Company generally retains the right to engage in oil and gas exploration and
production for its own account. The partnership agreement for each limited
partnership contains detailed provisions regarding the terms upon which a
variety of transactions between the Company and the limited partnerships may be
carried out. These restrictions, which may limit the ability of the Company to
take certain actions, are intended to ensure that transactions between the
Company and the limited partnerships are fair to such limited partnerships.
REGULATIONS
Environmental Regulations
The Company's operations are subject to numerous laws and regulations
governing the use, management and disposal of hazardous and non-hazardous
substances and wastes, and otherwise relating to environmental protection and
employee health and safety. These laws and regulations may require the
acquisition of a permit before drilling commences, restrict the types,
quantities and concentration of various substances that can be released into
the environment in connection with drilling and production activities, limit or
prohibit drilling activities on certain lands lying within wilderness areas,
wildlife refuges or preserves, wetlands and other protected areas, and impose
substantial liabilities for pollution resulting from the Company's operations.
Changes in environmental laws and regulations occur frequently, and any changes
that result in more stringent and costly waste handling, disposal and cleanup
requirements could
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have a significant impact on the operating costs of the Company, as well as the
oil and gas industry in general. Although Management believes that the Company
is in substantial compliance with current applicable environmental laws and
regulations, there can be no assurance the costs of maintaining compliance with
existing and future requirements will not have a material adverse impact on the
Company's business, results of operations and financial condition.
The Company frequently buys interests in underdeveloped crude oil and
natural gas properties that have been operated by others in the past, and
therefore may become liable for damage or pollution caused by the former
operators of such properties. Future site restoration, net of salvage values,
is estimated on a property-by-property basis and amortized to expense as the
Company's capitalized oil and gas property costs are amortized. The Company
computes the provision for such amortization on the unit-of-production method.
The Company's operations also are subject to all of the risks normally incident
to the operation and development of crude oil and natural gas properties,
including encountering unexpected formations or pressures, blowouts, cratering
and fires, any of which could result in personal injuries, loss of life,
pollution damage and other damage to the properties of the Company and others.
The Company maintains insurance against certain losses or liabilities arising
from its operations in accordance with customary industry practices and in
amounts that Management believes to be reasonable. For certain operational
risks, however, insurance is either unavailable or prohibitively expensive. A
significant liability for which the Company is uninsured or not fully insured
could have a material adverse effect on the Company's business, results of
operations and financial condition.
The Oil Pollution Act of 1990 ("OPA") imposes a variety of
requirements on "responsible parties" related to the prevention of crude oil
spills and liability for damages resulting from such spills into U.S. waters.
"Responsible parties" include, among others, the owners and operators of
onshore facilities, vessels and pipelines, and such parties may be held
strictly, jointly and severally liable for removal costs and certain other
damages caused by covered oil spills. Failure to comply with OPA's operating
requirements or to cooperate with removal activities after a spill event may
result in civil or criminal enforcement. The Company is not subject to any
enforcement proceedings under OPA.
The Federal Water Pollution Control Act of 1972, as amended (the
"FWPCA"), imposes restrictions and strict controls regarding the discharge of
produced waters and other oil and gas wastes into navigable waters. The
Company is required to obtain and maintain compliance with permits authorizing
it to discharge pollutants into state and federal waters. Certain state
discharge regulations and the Federal national Pollutant Discharge Elimination
System permits prohibit the discharge of produced water and sand, drilling
fluids, drill cutting and certain other substances related to the oil and gas
industry into coastal waters. The FWPCA provides for civil, criminal and
administrative penalties for any unauthorized discharges of oil and other
hazardous substances in reportable quantities and, along with OPA, imposes
substantial potential liability for the costs of removal, remediation and
damages. State laws for the control of water pollution also provide varying
civil, criminal and administrative penalties and impose liability for
discharges of petroleum or its derivatives, or other pollutants, into state
waters.
The Comprehensive Environmental Response, Compensation, and Liability
Act ("CERCLA"), and certain analogous state laws, impose strict, joint and
several liability on certain classes of persons concerning the release or
threatened release of hazardous substances into the environment. These persons
may include the current or past owner or operator of property on which a
release occurred, as well as persons that disposed or arranged for the disposal
of the hazardous substances found at the site. Responsible parties under
CERCLA may be strictly, jointly and severally liable to both the government
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and private third parties for investigation and cleanup costs, including
natural resources damages. In addition, neighboring landowners and other third
parties frequently file claims for personal injury and property damage relating
to such matters. Currently, the Company is not aware of any pending or
threatened claims, actions or investigations under CERCLA or similar state
laws.
The Resource Conversation and Recovery Act ("RCRA") is the principal
federal statute governing the treatment, storage and disposal of hazardous
wastes. RCRA imposes stringent operating requirements (and liability for
failure to meet such requirements) on persons who generate or transport
hazardous waste, and so those who own or operate hazardous waste treatment,
storage or disposal facilities. At present, RCRA includes a statutory
exemption that allows most crude oil and natural gas exploration and production
wastes to be classified as non-hazardous waste. A similar exemption is
contained in many of the state counterparts to RCRA. At various times in the
past, proposals have been made to amend RCRA and various state statutes to
rescind the exemption that excludes crude oil and natural gas exploration and
production wastes from regulation as hazardous waste under such statutes.
Repeal or modification of this exemption by administrative, legislative or
judicial process, or through changes in applicable state statutes, would
increase the volume of hazardous waste that the Company would be required to
manage and dispose. Hazardous wastes are subject to more rigorous and costly
disposal requirements than are non-hazardous wastes. Any such change in the
applicable statutes may require the Company to make additional capital
expenditures or incur increased operating expenses.
Federal Regulation of Natural Gas
The transportation and sale of natural gas in interstate commerce is
heavily regulated by agencies of the federal government. The following
discussion is intended only as a brief summary of the principal statutes,
regulations and agency orders that may affect the production and sale of the
Company's natural gas. This summary should not be relied upon as a complete
review of applicable natural gas regulatory provisions.
FERC Orders. Several major regulatory changes were implemented by the
Federal Energy Regulatory Commission ("FERC") after 1985 that affect the
economics of natural gas production, transportation and sales. In addition,
the FERC continues to promulgate revisions to various aspects of the rules and
regulations affecting those segments of the natural gas industry that remain
subject to the FERC's jurisdiction. In April 1992, the FERC issued Order No.
636 pertaining to pipeline restructuring. This rule requires interstate
pipelines to unbundle transportation and sales services by separately stating
the price of each service and by providing customers only the particular
service desired, without regard to the source for purchase of the gas. The
rule also requires pipelines to (i) provide nondiscriminatory "no-notice"
service allowing firm commitment shippers to receive delivery of gas on demand
up to certain limits without penalties, (ii) establish a basis for release and
reallocation of firm upstream pipeline capacity and (iii) provide non-
discriminatory access to capacity by firm transportation shippers on a
downstream pipeline. The rule requires interstate pipelines to use a straight
fixed variable rate design.
FERC Order No. 500 affects the transportation and marketability of
natural gas. Traditionally, natural gas has been sold by producers to pipeline
companies, which then resold the gas to end-users. FERC Order No. 500 alters
this market structure by requiring interstate pipelines that transport gas for
others to provide transportation service to producers, distributors and all
other shippers of natural gas on a nondiscriminatory, "first-come,
first-served" basis ("open access transportation"), so that producers and
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other shippers can sell natural gas directly to end-users. FERC Order No. 500
contains additional provisions intended to promote greater competition in
natural gas markets.
It is not anticipated that the marketability of and price obtainable
for the Company's natural gas production will be significantly affected by FERC
Order No. 500. Gas produced normally will be sold to intermediaries who have
entered into transportation arrangements with pipeline companies. These
intermediaries will accumulate gas purchased from a number of producers and
sell the gas to end-users through open access transportation.
State Regulations
Production of any oil and gas by the Company will be affected to some
degree by state regulations. Many states in which the Company operates have
statutory provisions regulating the production and sale of oil and gas,
including provisions regarding deliverability. Such statutes, and the
regulations promulgated in connection therewith, are generally intended to
prevent waste of oil and gas and to protect correlative rights to produce oil
and gas between owners of a common reservoir. Certain state and regulatory
authorities also regulate the amount of oil and gas produced by assigning
allowable rates of production to each well or proration unit.
Federal Leases
Some of the Company's properties are located on federal oil and gas
leases administered by various federal agencies, including the Bureau of Land
Management. Various regulations and orders affect the terms of leases,
development and exploration plans, methods of operation and related matters.
EMPLOYEES
At December 31, 1997, the Company employed 194 persons. None of the
Company's employees are represented by a union. Relations with employees are
considered to be good.
FACILITIES
The Company and Swift Energy Marketing Company occupy approximately
75,000 square feet of office space at 16825 Northchase Drive, Houston, Texas,
under a ten year lease expiring in 2005. The lease requires payments of
approximately $85,000 per month. A subsidiary of the Company maintains an
office in Denver, Colorado. The Company has field offices in various locations
from which Company employees supervise local oil and gas operations.
LEGAL PROCEEDINGS
No material legal proceedings are pending other than ordinary routine
litigation incidental to the Company's business.
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MANAGEMENT
DIRECTORS, EXECUTIVE OFFICERS AND CERTAIN OTHER OFFICERS
<TABLE>
<S> <C>
A. Earl Swift . . . . . . . . . Chief Executive Officer and Chairman of the Board
Terry E. Swift . . . . . . . . . President and Chief Operating Officer
Virgil N. Swift . . . . . . . . Vice Chairman of the Board and Executive Vice President- Business
Development
John R. Alden . . . . . . . . . Senior Vice President-Finance, Chief Financial Officer and Secretary
Bruce H. Vincent . . . . . . . . Senior Vice President-Funds Management
James M. Kitterman . . . . . . . Senior Vice President-Operations
Joseph A. D'Amico . . . . . . . Senior Vice President-Exploration and Development
James R. Stewart . . . . . . . . Vice President-Drilling and Production
Alton D. Heckaman, Jr. . . . . . Vice President and Controller
G. Robert Evans . . . . . . . . Director
Raymond O. Loen . . . . . . . . Director
Henry C. Montgomery . . . . . . Director
Clyde W. Smith, Jr. . . . . . . Director
Harold J. Withrow . . . . . . . Director
</TABLE>
A. Earl Swift, 64, is Chief Executive Officer and Chairman of the
Board of Directors of the Company and has served in such capacity since its
founding in 1979. He previously served as President from 1979 to November
1997, at which time Terry E. Swift was appointed President. For the 17 years
prior to 1979, he was employed by affiliates of American Natural Resources
Company. Mr. Swift is a registered professional engineer and holds a degree in
Petroleum Engineering, a degree of Doctor of Jurisprudence and a Master's
degree in Business Administration. He is the father of Terry E. Swift and the
brother of Virgil N. Swift.
Terry E. Swift, 42, was appointed President of the Company in 1997 and
Chief Operating Officer of the Company in 1991. He also served as Executive
Vice President of the Company from 1991 to 1997, as Senior Vice
President-Exploration and Joint Ventures from 1990 to 1991 and as Vice
President-Exploration and Joint Ventures from 1988 to 1990. Mr. Swift is a
registered professional engineer and holds a degree in Chemical Engineering and
a Master's degree in Business Administration.
Virgil N. Swift, 69, has been a director of the Company since 1981,
and has acted as Vice Chairman of the Board and Executive Vice
President-Business Development since November 1991. He previously served as
Executive Vice President and Chief Operating Officer from 1982 to November
1991. Mr. Swift joined the Company in 1981 as Vice President-Drilling and
Production. For the preceding 28 years, he held various production, drilling
and engineering positions with Gulf Oil Corporation and its subsidiaries, last
serving as General Manager-Drilling for Gulf Canada Resources, Inc. Mr. Swift
is a registered professional engineer and holds a degree in Petroleum
Engineering.
John R. Alden, 52, Senior Vice President-Finance, Chief Financial
Officer and Secretary, joined the Company in 1981. Mr. Alden was appointed to
his current offices in 1990. Prior to that time, he served the Company as its
principal financial officer under a variety of titles. Mr. Alden holds a
degree in Accounting and a Master's degree in Business Administration.
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Bruce H. Vincent, 50, joined the Company as Senior Vice
President-Funds Management in 1990. Mr. Vincent acted as Chief Operating
Officer of Energy Assets International Corp. from 1986 to 1988, and as
President of Vincent & Company, an investment banking firm, from 1988 to 1990.
Mr. Vincent holds a degree in Business Administration and a Master's degree in
Finance.
James M. Kitterman, 54, was appointed Senior Vice President-Operations
in May 1993. He had previously served as Vice President-Operations since
joining the Company in 1983 with 16 years of prior experience in oil and gas
exploration, drilling and production. Mr. Kitterman holds a degree in
Petroleum Engineering and a Master's degree in Business Administration.
Joseph A. D'Amico, 50, was appointed Senior Vice President-Exploration
and Development of the Company in February 1998. He served as the Company's
Vice President of Exploration and Development from 1993 to 1998, Director of
Exploration and Development from 1992 to 1993 and Funds Manager from 1988 to
1992. He served in the funds management division and as Director of
Exploration and Development of the Company from 1988 to 1993. Mr. D'Amico
holds a degree in Petroleum Engineering and Master's degrees in Petroleum
Engineering and Finance.
James R. Stewart, 61, was appointed Vice President-Drilling and
Production in August 1993. He joined the Company as Manager of Operations in
1990. He has 30 years experience in drilling, production, reservoir
engineering and geology. During his 30 years in the oil and gas industry, Mr.
Stewart has held a variety of management level positions. Mr. Stewart holds a
degree in Petroleum Engineering.
Alton D. Heckaman, Jr., 41, was appointed Vice President and
Controller in May 1993. He had previously served as Assistant Vice
President-Finance and Controller since 1986. Mr. Heckaman joined the Company
in 1982. He is a Certified Public Accountant and holds a degree in Accounting.
G. Robert Evans, 67, has been a director of the Company since 1994.
Effective January 1, 1998, Mr. Evans retired as Chairman of Material Sciences
Corporation, having held that position since 1991. Material Sciences
Corporation develops and commercializes continuously processed, coated
materials technologies. He remains a director of Material Sciences
Corporation. He is also currently serving as a director of Consolidated
Freightways, Inc. (transportation). From 1990 until 1991, he served as
President, Chief Executive Officer and a Director of Corporate Finance
Associates of Illinois, Inc., a financial intermediary and consulting firm.
From 1987 until 1990, he served as President, Chief Executive Officer and a
Director of Bemrose Group USA, a British holding company engaged in value-added
manufacturing and sale of products to the advertising specialty industry.
Raymond O. Loen, 74, has served as a director of the Company since its
founding in 1979. Since 1963, he has been President of R.O. Loen Company, a
privately held management consulting firm headquartered in Lake Oswego, Oregon.
Henry C. Montgomery, 62, has served as a director of the Company since
1987. Mr. Montgomery served as Executive Vice President of SyQuest Technology,
Inc., a public company engaged in the development, manufacture and sale of
computer hard drives from November 1996 through July 1997. He served as
President and Chief Executive Officer of New Media Corporation, a privately
held company engaged in developing, manufacturing and selling PCMCIA cards for
the computer industry, from March 1995 through November 1996. Since 1980, Mr.
Montgomery has been the Chairman of the Board of
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Montgomery Financial Services Corporation, a management consulting and
financial services firm. Mr. Montgomery also previously served as director of
Catalyst Semiconductor, Inc., a public company engaged in the design and
manufacture of semiconductors (1990 to 1995), and Southwall Technologies, Inc.,
a public company engaged in thin film deposition technologies (1982 to 1995).
Clyde W. Smith, Jr., 49, has served as a director of the Company since
1984. He has served as President of Somerset Properties, Inc., a real estate
and investment company, since 1985, as President of AdVision, Inc., which
markets video display merchandising systems, since 1988, as President of H&R
Precision, Inc., a general contractor, since 1994, and President of Millennium
Technology Services, Inc., a White City, Oregon based electronics manufacturer,
since August 1997. On May 5, 1997, Mr. Smith filed a petition under Chapter 7
of the U.S. Bankruptcy Code. Mr. Smith formerly acted as Chief Executive
Officer of California Video Sales, Inc. from 1987 to 1990.
Harold J. Withrow, 70, has been a director of the Company since 1988.
Mr. Withrow worked as an independent oil and gas consultant from 1988 until he
retired at the end of 1995. From 1975 until 1988, Mr. Withrow served as Senior
Vice President-Gas Supply for Michigan Wisconsin Pipe Line Company and its
successor, ANR Pipeline Company.
PRINCIPAL SHAREHOLDERS
The following table sets forth information concerning the
shareholdings, as of September 1, 1998 (unless otherwise indicated), of the
seven current members of the Board of Directors, each of the Company's five
most highly compensated executive officers, all executive officers and
directors as a group and each person who beneficially owned more than five
percent of the Company's outstanding Common Stock.
<TABLE>
<CAPTION>
Shares of Common Stock
Beneficially Owned at
September 1, 1998(1)
------------------------------
Percent of
Class
Name of Person or Group Position Number Outstanding
----------------------- -------- ------ -----------
<S> <C> <C> <C>
A. Earl Swift . . . . . . . . Chairman of the Board, Chief Executive [331,243] [2.0%]
Officer
Virgil N. Swift . . . . . . . Vice Chairman of the Board, Executive [351,039](2) [2.1%]
Vice President--Business Development
G. Robert Evans . . . . . . . Director [14,960] (3)
Raymond O. Loen . . . . . . . Director [155,601](4) (3)
Henry C. Montgomery . . . . . Director [49,445] (3)
Clyde W. Smith, Jr. . . . . . Director [18,700] (3)
</TABLE>
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<TABLE>
<CAPTION>
Shares of Common Stock
Beneficially Owned at
September 1, 1998(1)
---------------------------------
Percent of
Class
Name of Person or Group Position Number Outstanding
----------------------- -------- ------ -----------
<S> <C> <C> <C>
Harold J. Withrow . . . . . . Director [39,134] (3)
Terry E. Swift . . . . . . . President, Chief Operating Officer [130,975] (3)
John R. Alden . . . . . . . . Senior Vice President--Finance, Chief [108,574] (3)
Financial Officer, Secretary
James M. Kitterman . . . . . Senior Vice President--Operations [97,897] (3)
All executive officers & directors as a group (13 persons) . . . . . . [1,459,650] 8.5%
FMR Corp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . [1,772,300](5) 10.8%
82 Devonshire Street
Boston, Massachusetts 02109
Franklin Resources, Inc. . . . . . . . . . . . . . . . . . . . . . . . [1,797,444](6) 9.9%
Franklin Advisers, Inc.
Charles B. Johnson
Rupert H. Johnson, Jr.
777 Mariners Island Blvd.
San Mateo, California 94403
</TABLE>
_________________
(1) Unless otherwise indicated in the footnotes below, the number of
shares of Common Stock held and percent outstanding are as of
September 1, 1998. Unless otherwise indicated below, the persons
named have sole voting and investment power over the number of shares
of the Company's Common Stock shown as being owned by them. The table
includes the following shares that were acquirable within 60 days
following September 1, 1998 by exercise of options granted under the
Company's stock option plans: Mr. A. E. Swift - [74,408]; Mr. V. N.
Swift - [60,095]; Mr. Evans - [10,560]; Mr. Loen - [29,950]; Mr.
Montgomery - [8,646]; Mr. Smith - [18,700]; Mr. Withrow - [26,378];
Mr. T. E. Swift - [109,088]; Mr. Alden - [82,324]; Mr. Kitterman -
[79,805]; and all executive officers and directors as a group -
[634,245].
(2) Includes [121] shares held jointly by Mr. Swift and his wife.
(3) Less than one percent.
(4) Includes [70,000] shares held by Mr. Loen's wife (who holds sole
voting and investment power as to those shares and [4,047] shares held
in her IRA), and [2,809] shares held in Mr. Loen's IRA.
(5) Based on a Schedule 13G dated March 10, 1998, reflecting shares held
at February 28, 1998, filed with the Commission, FMR Corp., as a
parent holding company in accordance with Section 240
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of the Investment Adviser's Act of 1940, is deemed to be the
beneficial owner, with sole power to dispose and direct the
disposition of 1,772,300 shares. Fidelity Management & Research
Company ("Fidelity"), a wholly- owned subsidiary of FMR Corp., an
Investment Adviser registered under Section 203 of the Investment
Advisers Act of 1940, is deemed to be the beneficial owner of
1,770,100 shares of the Company's stock as a result of acting as an
investment adviser to several investment companies registered under
Section 8 of the Investment Company Act of 1940 (the "Funds").
Members of the Edward C. Johnson 3d family and trusts for their
benefit are the predominant owners of Class B shares of Common Stock
of FMR Corp., representing approximately 49% of the voting power of
FMR Corp. Mr. Johnson 3d owns 12.0% and Ms. Abigail P. Johnson owns
24.5% of the aggregate outstanding voting stock of FMR Corp. The
Johnson family group and all other Class B shareholders have entered
into a shareholders' voting agreement under which all Class B shares
will be voted in accordance with the majority vote of Class B shares.
Accordingly, through their ownership of voting common stock and the
execution of the shareholder's voting agreement, members of the
Johnson family may be deemed, under the Investment Company Act of
1940, to form a controlling group with respect to FMR Corp. Neither
FMR Corp. nor Edward C. Johnson 3d, Chairman of FMR Corp., has any
power to vote or direct the voting of the shares owned directly by the
Funds, which power resides with the Funds' Boards of Trustees.
(6) Based on Schedule 13G dated January 30, 1998, reflecting shares held
at December 31, 1997, filed with the Commission, Franklin Advisers
Inc. ("Advisers"), a wholly-owned subsidiary of Franklin Resources,
Inc. ("FRI") and an Investment Adviser registered under Section 203 of
the Investment Advisers Act of 1940, is deemed to be the beneficial
owner of 1,797,444 shares of the Company's Common Stock as a result of
acting as an investment adviser to one or more open or closed-end
investment companies or other managed accounts. All of these shares
of the Company's Common Stock are shares that would result upon
conversion of 57,000,000 units of the Company's Convertible Notes.
Charles B. Johnson and Rupert H. Johnson, Jr. each own in excess of
10% of the outstanding common stock of FRI and are the principal
shareholders of FRI. Accordingly, Messrs. Charles B. and Rupert H.
Johnson and FRI may each be deemed to be the beneficial owner of the
shares of the Company's Common Stock managed by Advisers.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In the ordinary course of its business, the Company acquires interests
in exploratory and developmental oil and gas prospects and sells interests in
such prospects to unaffiliated third parties. For the past several years, the
Company has made available for sale to its executive officers and certain other
employees a portion of the interests in certain prospects that would otherwise
have been sold to third parties. Interests in a prospect are sold to the
Company's employees on terms identical to those at which interests are sold to
third party investors in that prospect. As a result of enhanced drilling
activity, the amounts invested by executive officers in such prospects in 1997
increased significantly over previous years. During 1997, 1996 and 1995,
leasehold and drilling costs associated with such investments in excess of
$60,000 were incurred as follows, respectively: A. Earl Swift - $322,261,
$135,957 and $69,358; Virgil N. Swift - $390,784, $259,379 and $312,122; Terry
E. Swift - $207,426, $106,621 and $66,618; John R. Alden - $246,270, $95,080
and $79,927; and only during 1997 for: James M. Kitterman - $133,068, and Bruce
H. Vincent - $220,458. In connection with these investments in oil and gas
drilling prospects, certain executive officers deferred paying cash for their
investments in such properties, instead assigning the proceeds of production
which over time repay amounts owed, resulting in indebtedness from
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time to time, of such officers to the Company. Prior to 1997, the amount of
such indebtedness for any one officer never exceeded $60,000. In late 1997,
due to increased levels of drilling activity, the balances owed to the Company
grew, with the greatest amounts of indebtedness that exceeded $60,000 during
1998 occurring at July 24, 1998 as follows: Virgil N. Swift - $174,200; John R.
Alden - $130,000; Bruce H. Vincent - $124,000; and James M. Kitterman -
$61,900. Individual executive officers do not pay any interest to the Company
on any such loan balances.
The Company is the operator of a substantial number of properties
owned by its affiliated limited partnerships and joint ventures and accordingly
charges these entities and third party joint interest owners operating fees.
The Company is also reimbursed for direct, administrative and overhead costs
incurred in conducting the business of the limited partnerships, which totaled
approximately $6,300,000, $6,100,000 and $4,800,000 in 1997, 1996 and 1995,
respectively. The Company was also reimbursed by the limited partnerships and
joint ventures for costs incurred in the screening, evaluation and acquisition
of producing oil and gas properties on their behalf. Such costs totaled
approximately $490,000, $250,000 and $600,000 in 1997, 1996 and 1995,
respectively. In the case where the limited partners voted to sell their
remaining properties and liquidate the limited partnerships, the Company was
also reimbursed for direct, administrative and overhead costs incurred in the
disposition of such properties, which costs totaled approximately $675,000,
$805,000 and $80,000 in 1997, 1996 and 1995, respectively.
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DESCRIPTION OF SWIFT ENERGY COMPANY CAPITAL STOCK
The following summary description of the capital stock of the Company
does not purport to be complete and is qualified in its entirety by reference
to the Company's Articles of Incorporation, the bylaws of the Company and to
the Certificate of Designation for Series A Junior Participating Preferred
Stock, $.01 par value, copies of which are incorporated by reference as
exhibits to the Registration Statement of which this Prospectus is a part.
PREFERRED STOCK
The Company is authorized to issue 5,000,000 shares of preferred
stock, par value $.01, of which no shares have been issued. Under the
Company's Articles of Incorporation, the Company's Board of Directors is
authorized, without shareholder action, to issue preferred stock in one or more
series and to fix the number of shares and the rights, preferences and
limitation of each series. Among the specific matters that may be determined
by the Board of Directors are the dividend rate, the redemption price, if any,
conversion rights, if any, the amount payable in the event of any voluntary
liquidation or dissolution of the Company and voting rights, if any.
Preferred Stock Purchase Rights
On August 1, 1997, the Board of Directors of the Company declared a
dividend of one preferred share purchase right (a "Right") for each outstanding
share of Common Stock payable to the stockholders of record on August 12, 1997.
Each Right entitles the holder to purchase from the Company one one-thousandth
of a share of Series A Junior Participating Preferred Stock, par value $.01 per
share, of the Company (the "Preferred Stock") at a price of $150 per one
one-thousandth of a share of Preferred Stock (the "Purchase Price"), subject to
adjustment. The description and terms of the Rights are set forth in a Rights
Agreement dated as of August 1, 1997, as the same may be amended from time to
time (the "Rights Amendment"), between the Company and American Stock Transfer
& Trust Company, as Rights Agent (the "Rights Agent").
Until the earlier to occur of (i) 10 days following a public
announcement that a person or group of affiliated or associated persons (with
certain exceptions, an "Acquiring Person") has acquired beneficial ownership of
15% or more of the outstanding shares of Common Stock or (ii) 10 business days
(or such later date as may be determined by action of the Board of Directors
prior to such time as any person or group of affiliated person becomes an
Acquiring Person) following the commencement of, or announcement of an
intention to make, a tender offer or exchange offer the consummation of which
would result in the beneficial ownership by a person or group of 15% or more of
the outstanding shares of Common Stock (the earlier of such dates being called
the "Distribution Date"), the Rights are evidenced by such Common Stock
certificate outstanding on August 12, 1997, together with a copy of the summary
of rights.
The Rights Agreement provides that, until the Distribution Date (or
earlier expiration of the Rights), the Rights will be transferred with and only
with the Common Stock. Until the Distribution Date (or earlier expiration of
the Rights), new Common Stock certificates issued after August 12, 1997, upon
transfer of new issuances of Common Stock will contain a notation incorporating
the Rights Agreement by reference. Until the Distribution Date (or earlier
expiration of the Rights), the surrender for transfer of any certificates for
shares of Common Stock outstanding as of August 12, 1997, even without such
151
<PAGE> 168
notation or a copy of this Summary of Rights, will also constitute the transfer
of the Rights associated with the shares of Common Stock represented by such
certificates. Following the Distribution Date, separate certificates
evidencing the Rights ("Right Certificates") will be mailed to holders of
record of the Common Stock as of the close of business on the Distribution Date
and such separate Right Certificates alone will evidence the Rights.
The Rights are not exercisable until the Distribution Date. The
Rights will expire on July 31, 2007 (the "Final Expiration Date"), unless the
Final Expiration Date is advanced or extended or unless the Rights are earlier
redeemed or exchanged by the Company, in each case as described below.
In the event that any person or group of affiliated or associated
persons becomes an Acquiring Person, each holder of a Right, other than Rights
beneficially owned by the Acquiring Person (which will thereupon become void),
will thereafter have the right to receive upon exercise of a Right that number
of shares of Common Stock or other securities or assets having a market value
of two times the exercise price of the Right.
In the event that, after a person or group has become an Acquiring
Person, the Company is acquired in a merger or other business combination
transaction or 50% or more of its consolidated assets or earning power are
sold, proper provisions will be made so that each holder of a Right (other than
Rights beneficially owned by an Acquiring Person which will have become void )
will thereafter have the right to receive upon the exercise of a Right that
number of shares of Common Stock of the person with whom the Company has
engaged in the foregoing transaction (or its parent) that at the time of such
transaction have a market value of two times the exercise price of the Right.
At any time after any person or group becomes an Acquiring Person and
prior to the earlier of one of the events described in the previous paragraph
or the acquisition by such Acquiring Person of 50% or more of the outstanding
shares of Common Stock, the Board of Directors of the Company may exchange the
Rights (other than Rights owned by such Acquiring Person which will have become
void), in whole or in part, for shares of Common Stock or Preferred Stock (or a
series of the Company's preferred stock having equivalent rights, preferences
and privileges), at an exchange ratio of one share of Common Stock, or a
fractional share of Preferred Stock (or other preferred stock) equivalent in
value thereto, per Right.
Shares of Preferred Stock purchasable upon exercise of the Rights will
not be redeemable. Each share of Preferred Stock will be entitled, when, as
and if declared, to a dividend payment per share equal to an aggregate dividend
of 1000 times the dividend declared per share of Common Stock. In the event of
liquidation, dissolution or winding up of the Company, the holders of the
Preferred Stock will be entitled to a minimum preferential payment of $1.00 per
share (plus any accrued but unpaid dividends) but will be entitled to an
aggregate payment of 1000 times the payment made per share of Common Stock.
Each share of Preferred Stock will have 1000 votes, voting together with the
Common Stock. Finally, in the event of any merger, consolidation or other
transaction in which outstanding shares of Common Stock are converted or
exchanged, each share of Preferred Stock will be entitled to receive 1000 times
the amount received per share of Common Stock. These Rights are protected by
customary antidilution provisions.
Because of the nature of the Preferred Stock's dividend, liquidation
and voting rights, the value of the one one-thousandth of a share of Preferred
Stock purchasable upon exercise of each Right should approximate the value of
one share of Common Stock.
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<PAGE> 169
The offer and sale of the Preferred Shares or Common Shares issuable
upon exercise of the Rights will be registered pursuant to the Securities Act
of 1933, as amended; such registration will not become effective until the
Rights become exercisable.
The number of one one-thousandths of a Preferred Share or other
securities or property issuable upon exercise of the Rights, and the Purchase
Price payable, are subject to customary adjustments from time to time to
prevent dilution.
At any time prior to the earlier of (i) the Distribution Date or (ii)
the Final Expiration Date, the Board of Directors of the Company may redeem all
but not less than all of the then outstanding Rights at a price of $0.01 per
Right (the "Redemption Price"). The redemption of the Rights may be made
effective at such time, on such basis and with such conditions as the Board of
Directors in its sole discretion may establish. At the effective time of such
redemption, the right to exercise the Rights will terminate and the only right
of the holders of Rights will be to receive the Redemption Price.
Until a Right is exercised, the holder thereof, as such, will have no
rights as a stockholder of the Company, including, without limitation, the
right to vote or to receive dividends.
For so long as the Rights are then redeemable, the Company may, except
with respect to the redemption price, amend the Rights Agreement in any manner.
After the Rights are no longer redeemable, the Company may, except with respect
to the redemption price, amend the Rights Agreement in any manner that does not
adversely affect the interests of holders of the Rights.
COMMON STOCK
The Company is authorized to issue 35,000,000 shares of Common Stock,
par value $.01, of which [16,515,038] were issued and outstanding at September
1, 1998. Holders of Common Stock are entitled to one vote for each share held.
Shareholders do not have preemptive rights or the right to cumulate votes for
the election of directors. Shares are not subject to redemption nor to any
liability for further calls. All shares of Common Stock issued and outstanding
are, and all the shares issued on conversion of the Notes offered by the
Company hereby when issued will be, validly issued, fully paid and
non-assessable. Holders of the Common Stock are entitled to receive dividends
as they are declared by the Board of Directors out of funds legally available
therefor and are entitled to participate in the assets of the Company available
for distribution in the event of liquidation or dissolution. See "Price Range
of Common Stock and Dividend Policy." At September 1, 1998, there were
[3,192,933] shares, in the aggregate, reserved for issuance under the Company's
stock option or employee benefits plans, of which [1,822,987], in the
aggregate, were subject to outstanding options. No shares were reserved for
issuance upon the exercise of outstanding options granted outside the Company's
option plans. The Company does not currently have any plans to issue
additional shares of Common Stock other than pursuant to its 1990 Stock
Compensation Plan, its 1990 Non-Qualified Plan or its Employee Stock Purchase
Plan.
ANTITAKEOVER MEASURES
The Board of Directors adopted amendments ("Antitakeover Measures") to
the Company's bylaws on August 14, 1995, designed to protect shareholders'
rights in the event of an acquisition of control by an outsider that does not
have the support of the Board of Directors. The primary amendment classifies
the Board of Directors. Other Antitakeover Measures adopted by the Board of
Directors include
153
<PAGE> 170
supermajority approval by the shareholders for (i) sale of substantially all of
the assets of the Company, merger or issuances of stock to certain shareholders
unless approved by Continuing Directors (as herein defined); (ii) removal of
directors; and (iii) amendment or repeal of Antitakeover Measures. The
Antitakeover Measures could result in a denial or reduction to shareholders of
potential premiums over market often afforded by tender offers, the ability of
management or less than a majority of shareholders to thwart transactions which
may be desirable or beneficial to shareholders and increased difficulty to
alter management of the Company.
As amended, the bylaws provide that the Board of Directors shall
consist of seven (7) directors, and the number may be increased or decreased by
a majority of the Continuing Directors, provided that the number of directors
shall never be less than three (3) nor more than nine (9) members. Under the
amended bylaws, at the Annual Meeting held on May 14, 1996, two directors were
elected to serve terms expiring at the 1997 Annual Meeting, three directors
were elected to serve terms expiring at the 1998 Annual Meeting, and two
directors were elected to serve terms expiring at the 1999 Annual Meeting of
shareholders. In all cases, the directors will hold office until their
respective successors have been duly elected and have qualified. Vacancies
occurring on the Board of Directors may be filled by the Board of Directors for
the unexpired term of the replacement director's predecessor in office. At
future annual meetings, each nominee for director that is elected will be
elected to serve a three year term.
The Antitakeover Measures also provide for the affirmative vote of at
least sixty-six and two thirds percent (66-2/3%) of the outstanding shares of
the capital stock of the Company entitled to vote generally in the election of
directors ("Supermajority Vote") on certain corporate actions. A Supermajority
Vote is required to sell, assign or dispose of the Company's assets or to merge
with another corporation or entity if such transaction is not approved by a
majority of the directors then in office who were directors for the two-year
period ending on the date notice of the meeting or written consent is first
provided to shareholders (the "Continuing Directors") or to enter into any
transaction, including the issuance or transfer of securities of the Company,
to any holder of twenty percent (20%) of the outstanding capital stock of the
Company. A Supermajority Vote is also required to remove one or more directors
or to amend or repeal the provisions that contain Antitakeover Measures in the
bylaws adopted by the Board of Directors.
TRANSFER AGENT
American Stock Transfer & Trust Company, New York, New York is the
transfer agent and registrar for the Notes.
154
<PAGE> 171
LEGAL MATTERS
The validity of the Common Stock offered hereby will be passed upon
for the Company by Jenkens & Gilchrist, a Professional Corporation, Houston,
Texas. The information contained in "Tax Risks", "Federal Income Tax
Consequences of Adoption of the Proposals" and "Material Federal Income Tax
Considerations of Electing to Receive Common Stock in Lieu of Cash Upon
Partnership Liquidation" will be passed upon by Hoops & Levy, L.L.P., Houston,
Texas.
EXPERTS
The following financial statements included or incorporated by
reference in this Joint Proxy Statement/Prospectus and elsewhere in the
Registration Statement, to the extent and for the periods indicated in their
reports, have been audited by Arthur Andersen LLP, independent public
accountants, and are included or incorporated by reference herein in reliance
upon the authority of said firm as experts in giving said reports: (i) Swift
Energy Company Annual Report on Form 10-K for the year ended December 31, 1997,
which is incorporated by reference herein; (ii) the Combined Financial
Statements of the Partnerships included herein; (iii) the Annual Report on Form
10-K for the year ended December 31, 1997 for those Partnerships referenced in
Note 1 to the Notes to the Combined Financial Statements of the Partnership
which are registered under the Securities Exchange Act of 1934 (the
"Partnership Forms 10- K"); and (iv) the annual reports for the year ended
December 31, 1997 for the remaining Partnerships referenced in Note 1 to the
Notes to the Combined Financial Statements of the Partnerships, which are not
registered under the 1934 Act, the annual reports of which are incorporated by
reference from Swift Energy Company's Form 8-K dated June 5, 1998.
The historical statements of revenues and direct operating expenses of
the Sonat Properties Acquisition for the three years ended December 31, 1997
included in the Joint Proxy Statement/Prospectus of Swift Energy Company, which
is referred to and made a part of this Registration Statement, have been
audited by Ernst & Young LLP, independent auditors, as set forth in their
report appearing elsewhere herein, and are included in reliance upon such
report given upon the authority of such firm as experts in accounting and
auditing.
The reference to the appraisals of H.J. Gruy and Associates, Inc., J.
R. Butler and Company and CIBC Oppenheimer Corp. contained herein with respect
to the fair market value of Partnerships' Property Interests is made in
reliance upon the authority of such firms as experts with respect to such
matters.
The reference to H. J. Gruy and Associates, Inc. as reserve auditors
incorporated herein by reference to the Partnership Forms 10-K is made in
reliance upon the authority of such firm as experts with respect to such
matters.
155
<PAGE> 172
GLOSSARY OF TERMS
The following abbreviations and terms have the indicated meanings when
used in this Joint Proxy Statement/Prospectus:
APPRAISERS mean H. J. Gruy & Associates, Inc., J. R. Butler & Company and CIBC
Oppenheimer Corp., who have determined the fair market value of the
Partnership's Property Interests.
BBL means barrel or barrels of oil.
BCF means billion cubic feet of natural gas.
BCFE means billion cubic feet of natural gas equivalent (see Mcfe).
BOE means one revenue interests barrel of oil equivalent using the ratio of one
barrel of crude oil, condensate or
natural gas liquids to six Mcf of natural gas.
BTU means British thermal unit, which is a heating equivalent measure for
natural gas (see MMBtu).
DEVELOPMENT WELL means a well drilled within the presently proved productive
area of an oil or natural gas reservoir, as indicated by reasonable
interpretation of available data, with the objective of completing in that
reservoir.
DRY WELL means an exploratory or development well that is not a producing well.
EXPLORATORY WELL means a well drilled either in search of a new, as yet
undiscovered oil or natural gas reservoir or to greatly extend the known limits
of a previously discovered reservoir.
FAIR MARKET VALUE is defined as the maximum price that a willing buyer will pay
and a willing seller will sell at a given point in time at which the buyer is
under no compulsion to buy and the seller is not compelled to sell, both having
reasonable knowledge of all the material circumstances.
GROSS ACRE means an acre in which a working interest is owned. The number of
gross acres is the total number of acres in which a working interest is owned.
GROSS WELL means a well in which a working interest is owned. The number of
gross wells is the total number of wells in which a working interest is owned.
MBBL means thousand barrels of oil.
MCF means thousand cubic feet of natural gas.
MCFE means thousand cubic feet of natural gas equivalent, which is determined
using the ratio of one barrel of oil,
condensate or natural gas liquids to six Mcf of natural gas.
MMBBL means million barrels of oil.
156
<PAGE> 173
MMBTU means million British thermal units, which is a heating equivalent
measure for natural gas and is an alternate measure of natural gas reserves, as
opposed to Mcf, which is strictly a measure of natural gas volumes. Typically
prices quoted for natural gas are designated as prices per MMBtu, the same
basis on which natural gas is contracted for sale.
MMCF means million cubic feet of natural gas.
MMCFE means million cubic feet of natural gas equivalent (see Mcfe).
NET ACRE means the sum of fractional ownership working interests in gross acres
equals one. The number of net acres is the sum of fractional working interests
owned in gross acres expressed as whole numbers and fractions thereof.
NET PROFITS INTEREST means an interest in oil and gas property which entitles
the owner to a specified percentage share of the Gross Proceeds generated by
such property, net of aggregate operating costs. Under the NP/OR Agreement or
Net Profits Agreement, a Pension Partnership receives a Net Profits Interest
entitling it to a specified percentage of the aggregate Gross Proceeds
generated by, less the aggregate operating costs attributable to, those depths
of all Producing Properties acquired pursuant to such agreement that are
evaluated at the respective dates of acquisition to contain Proved Reserves, to
the extent such depths underlie specified surface acreage.
NP/OR AGREEMENT OR NET PROFITS AGREEMENT means the form of Net Profits and
Overriding Royalty Interest Agreement or Net Profits Agreement entered into
between a Pension Partnership and an Operating Partnership pursuant to which a
Pension Partnership acquired a Net Profits Interest, or in certain instances
various Overriding Royalty Interests, from the Operating Partnership in a group
of Producing Properties. The Working Interest in such group of properties is
held by the Operating Partnership.
PRODUCING WELL means an exploratory or development well found to be capable of
producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well.
PROVED DEVELOPED OIL AND GAS RESERVES means reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
PROVED OIL AND GAS RESERVES means the estimated quantities of crude oil,
natural gas, and natural gas liquids that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, that is,
prices and costs as of the date the estimate is made.
PV-10 VALUE means, in accordance with the Commission guidelines, the estimated
future net cash flow to be generated from the production of proved reserves
discounted to present value using an annual discount rate of 10%. These
amounts are calculated net of estimated production costs and future development
costs, using prices and costs in effect as of a certain date, without
escalation and without giving effect to non-property related expenses such as
general and administrative expenses, debt services, future income, tax expenses
or depreciation, depletion and amortization.
PETROLEUM ENGINEERING CONSULTANTS means the independent petroleum engineering
firms of H. J. Gruy & Associates, Inc. and J. R. Butler & Company, both located
in Houston, Texas.
157
<PAGE> 174
PRODUCING PROPERTIES means properties (or interests in properties) producing
oil and gas in commercial quantities. Producing Properties include associated
well machinery and equipment, gathering systems, storage facilities or
processing installations or other equipment and property associated with the
production and field processing of oil or gas. Interests in Producing
Properties may include Working Interests, production payments, Royalty
Interests, Overriding Royalty Interest, Net Profits Interests and other
non-operating interests. Producing Properties may include gas gathering lines
or pipelines. The geographical limits of a Producing Property may be enlarged
or contracted on the basis of subsequently acquired geological data to define
the productive limits of a reservoir, or as a result of action by a regulatory
agency employing such criteria as the regulatory agency may determine.
PROVED RESERVES means those quantities of crude oil, natural gas and natural
gas liquids which, upon analysis of geologic and engineering data, appear with
reasonable certainty to be recoverable in the future from known oil and gas
reservoirs under existing economic and operating conditions. Proved Reserves
are limited to those quantities of oil and gas which can be reasonably expected
to be recoverable commercially at current prices and costs, under existing
regulatory practices and with existing conventional equipment and operating
methods.
RESERVE REPLACEMENT COST means, with respect to proved reserves, a three-year
average (unless otherwise indicated) calculated by dividing total incurred
acquisition, exploration and development costs (exclusive of future development
costs) by net reserves added during the period.
ROYALTY INTEREST means a fractional interest in the gross production, or the
gross proceeds therefrom, of oil and gas and other minerals under a lease; free
of any expenses of exploration, development, operation and maintenance.
VOLUMETRIC PRODUCTION PAYMENT means the 1992 agreement pursuant to which the
Company financed the purchase of certain oil and natural gas interests and
committed to deliver certain monthly quantities of natural gas.
WORKING INTEREST means the operating interest under an oil, gas and mineral
lease or other property interest covering a specific tract or tracts of land.
The owner of a Working Interest has the right to explore for, drill and produce
the oil, gas and other minerals covered by such lease or other property
interest and the obligation to bear the costs of exploration, development,
operation or maintenance applicable to that owner's interest.
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<PAGE> 175
OTHER BUSINESS
The Managing General Partner does not intend to bring any other
business before the Meetings and has not been informed that any other matters
are to be presented at the Meetings by any other person.
SWIFT ENERGY COMPANY
as Managing General Partner of
each of the Partnerships
------------------------------
John R. Alden
Secretary
159
<PAGE> 176
SWIFT ENERGY COMPANY AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<S> <C>
Report of Independent Public Accountants.................... F-2
Consolidated Balance Sheets................................. F-3
Consolidated Statements of Income........................... F-4
Consolidated Statements of Stockholders' Equity............. F-5
Consolidated Statements of Cash Flows....................... F-6
Notes to Consolidated Financial Statements.................. F-7
THE PARTNERSHIPS
INDEX TO COMBINED FINANCIAL STATEMENTS OF THE PARTNERSHIPS
Report of Independent Public Accountants.................... F-23
Combined Balance Sheets..................................... F-24
Combined Statements of Income............................... F-25
Combined Statements of Partners' Capital.................... F-26
Combined Statements of Cash Flows........................... F-27
Notes to Combined Financial Statements...................... F-28
THE SONAT PROPERTIES ACQUISITION
INDEX TO HISTORICAL STATEMENT OF REVENUES AND
DIRECT OPERATING EXPENSES
Report of Independent Accountants........................... F-34
Historical Statement of Revenues and Direct Operating
Expenses.................................................. F-35
Notes to Historical Statement of Revenues and Direct
Operating Expenses........................................ F-36
</TABLE>
F-1
<PAGE> 177
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of Swift Energy Company:
We have audited the accompanying consolidated balance sheets of Swift
Energy Company (a Texas corporation) and subsidiaries as of December 31, 1997
and 1996, and the related consolidated statements of income, stockholders'
equity, and cash flows for each of the three years in the period ended December
31, 1997. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these combined
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 combined financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Swift Energy Company and
subsidiaries as of December 31, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
February 10, 1998
F-2
<PAGE> 178
SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
JUNE 30, ---------------------------
1998 1997 1996
------------ ------------ ------------
(UNAUDITED)
<S> <C> <C> <C>
Current Assets:
Cash and cash equivalents................................. $ 11,505,900 $ 2,047,332 $ 77,794,974
Accounts receivable
Oil and gas sales....................................... 10,384,687 11,143,033 13,637,390
Associated limited partnerships and joint ventures...... 7,931,842 8,498,702 6,396,149
Joint interest owners................................... 7,711,519 7,357,660 3,079,619
Other current assets...................................... 1,748,143 935,059 711,346
------------ ------------ ------------
Total Current Assets............................... 39,282,091 29,981,786 101,619,478
------------ ------------ ------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized....................... 387,959,666 326,836,431 216,310,033
Unproved properties not being amortized................. 49,936,056 41,839,809 27,620,462
------------ ------------ ------------
437,895,722 368,676,240 243,930,495
Furniture, fixtures, and other equipment.................. 6,487,617 6,242,927 5,729,228
------------ ------------ ------------
444,383,339 374,919,167 249,659,723
Less -- Accumulated depreciation, depletion, and
amortization............................................ (84,614,965) (70,700,240) (46,685,736)
------------ ------------ ------------
359,768,374 304,218,927 202,973,987
------------ ------------ ------------
Other Assets:
Receivables from associated limited partnerships, net of
current portion......................................... 424,461 433,444 759,711
Limited partnership formation and marketing costs......... 775,267 297,219 510,607
Deferred charges.......................................... 4,008,426 4,184,014 4,511,481
------------ ------------ ------------
5,208,154 4,914,677 5,781,799
------------ ------------ ------------
$404,258,619 $339,115,390 $310,375,264
============ ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities.................. $ 22,189,702 $ 16,518,240 $ 20,416,589
Payable to associated limited partnerships................ 284,185 3,245,445 1,444,648
Undistributed oil and gas revenues........................ 6,463,300 8,753,979 11,054,379
------------ ------------ ------------
Total Current Liabilities.......................... 28,937,187 28,517,664 32,915,616
------------ ------------ ------------
6.25% Convertible Subordinated Notes........................ 115,000,000 115,000,000 115,000,000
Bank Borrowings............................................. 64,000,000 7,915,000 --
Deferred Revenues........................................... 2,302,147 2,927,656 4,404,081
Deferred Income Taxes....................................... 28,082,571 25,354,150 15,293,957
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding............................ -- -- --
Common stock, $.01 par value, 35,000,000 shares
authorized, 16,969,631, 16,846,956, and 15,176,417
shares issued, and 16,534,357, 16,459,156, and
15,176,417 shares outstanding, respectively............. 169,696 168,470 151,764
Additional paid-in capital................................ 148,695,638 147,542,977 102,018,861
Treasury stock held, at cost, 435,274 and 387,800 shares,
respectively............................................ (9,346,511) (8,519,665) --
Unearned ESOP compensation................................ (66,926) (150,055) (521,354)
Retained earnings......................................... 26,484,817 20,359,193 41,112,339
------------ ------------ ------------
165,936,714 159,400,920 142,761,610
------------ ------------ ------------
$404,258,619 $339,115,390 $310,375,264
============ ============ ============
</TABLE>
See accompanying notes to Consolidated Financial Statements
F-3
<PAGE> 179
SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, YEAR ENDED DECEMBER 31,
------------------------- ---------------------------------------
1998 1997 1997 1996 1995
----------- ----------- ----------- ----------- -----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales........... $31,482,915 $32,441,177 $69,015,189 $52,770,672 $22,527,892
Fees from limited
partnerships and joint
ventures................. 204,879 264,103 745,856 937,238 590,441
Interest income............. 62,875 1,750,176 2,395,406 433,352 212,329
Other, net.................. 1,065,290 1,195,124 2,555,729 2,156,764 1,761,568
----------- ----------- ----------- ----------- -----------
32,815,959 35,650,580 74,712,180 56,298,026 25,092,230
----------- ----------- ----------- ----------- -----------
Costs and Expenses:
General and administrative,
net of reimbursement..... 1,880,424 1,808,430 3,523,604 4,149,964 3,336,776
Depreciation, depletion, and
amortization............. 13,985,240 11,108,541 24,247,142 16,526,379 8,838,657
Oil and gas production...... 4,874,997 4,171,782 8,778,876 6,141,941 4,906,899
Interest expense, net....... 2,969,643 2,393,308 5,032,952 693,959 1,115,361
----------- ----------- ----------- ----------- -----------
23,710,304 19,482,061 41,582,574 27,512,243 18,197,693
----------- ----------- ----------- ----------- -----------
Income Before Income Taxes.... 9,105,655 16,168,519 33,129,606 28,785,783 6,894,537
Provision for Income Taxes.... 2,979,570 5,285,567 10,819,417 9,760,333 1,982,025
----------- ----------- ----------- ----------- -----------
Net Income.................... $ 6,126,085 $10,882,952 $22,310,189 $19,025,450 $ 4,912,512
=========== =========== =========== =========== ===========
Per Share Amounts
Basic....................... $ 0.37 $ 0.66 $ 1.35 $ 1.27 $ 0.49
=========== =========== =========== =========== ===========
Diluted..................... $ 0.37 $ 0.61 $ 1.26 $ 1.25 $ 0.49
=========== =========== =========== =========== ===========
Weighted Average Shares
Outstanding................. 16,512,562 16,552,349 16,492,856 15,000,901 10,035,143
=========== =========== =========== =========== ===========
</TABLE>
See accompanying notes to Consolidated Financial Statements
F-4
<PAGE> 180
SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
ADDITIONAL UNEARNED
COMMON PAID-IN TREASURY ESOP RETAINED
STOCK(1) CAPITAL STOCK COMPENSATION EARNINGS TOTAL
-------- ------------ ----------- ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1994................... $66,851 $ 24,885,903 $ -- $ -- $ 17,174,377 $ 42,127,131
Stock issued for benefit plans (31,113
shares).................................. 311 283,463 -- -- -- 283,774
Stock options exercised (5,761 shares)..... 58 33,736 -- -- -- 33,794
Employee stock purchase plan (37,689
shares).................................. 377 289,465 -- -- -- 289,842
Stock issued in public offering (5,750,000
shares).................................. 57,500 45,641,412 -- -- -- 45,698,912
Net income................................. -- -- -- -- 4,912,512 4,912,512
-------- ------------ ----------- --------- ------------ ------------
Balance, December 31, 1995................... $125,097 $ 71,133,979 $ -- $ -- $ 22,086,889 $ 93,345,965
Stock issued for benefit plans (30,015
shares).................................. 300 347,345 -- -- -- 347,645
Stock options exercised (257,207 shares)... 2,572 2,630,959 -- -- -- 2,633,531
Employee stock purchase plan (36,387
shares).................................. 364 272,178 -- -- -- 272,542
Loan to ESOP for purchase of shares........ -- -- -- (568,750) -- (568,750)
Allocation of ESOP shares.................. -- 5,382 -- 47,396 -- 52,778
Debenture conversion (2,343,108 shares).... 23,431 27,629,018 -- -- -- 27,652,449
Net income................................. -- -- -- -- 19,025,450 19,025,450
-------- ------------ ----------- --------- ------------ ------------
Balance, December 31, 1996................... $151,764 $102,018,861 $ -- $(521,354) $ 41,112,339 $142,761,610
Stock issued for benefit plans (12,227
shares).................................. 122 371,359 -- -- -- 371,481
Stock options exercised (137,155 shares)... 1,372 1,613,071 -- -- -- 1,614,443
Employee stock purchase plan (26,551
shares).................................. 266 403,145 -- -- -- 403,411
10% stock dividend (1,494,606 shares)...... 14,946 43,048,389 -- -- (43,063,335) --
Allocation of ESOP shares.................. -- 88,152 -- 371,299 -- 459,451
Purchase of 387,800 shares as treasury
stock.................................... -- -- (8,519,665) -- -- (8,519,665)
Net income................................. -- -- -- -- 22,310,189 22,310,189
-------- ------------ ----------- --------- ------------ ------------
Balance, December 31, 1997................... $168,470 $147,542,977 $(8,519,665) $(150,055) $ 20,359,193 $159,400,920
Stock issued for benefit plans (20,032
shares)(2)............................... 200 367,058 -- -- -- 367,258
Stock options exercised (81,871
shares)(2)............................... 818 493,222 -- -- -- 494,040
Employee stock purchase plan (20,756
shares)(2)............................... 208 317,340 -- -- -- 317,548
10% stock dividend adjustment (16
shares)(2)............................... -- 461 -- -- (461) --
Allocation of ESOP shares(2)............... -- (25,420) -- 83,129 -- 57,709
Purchase of 47,474 shares as treasury
stock(2)................................. -- -- (826,846) -- -- (826,846)
Net income(2).............................. -- -- -- -- 6,126,085 6,126,085
-------- ------------ ----------- --------- ------------ ------------
Balance, June 30, 1998(2).................... $169,696 $148,695,638 $(9,346,511) $ (66,926) $ 26,484,817 $165,936,714
======== ============ =========== ========= ============ ============
</TABLE>
- ---------------
(1) $.01 par value.
(2) Unaudited
See accompanying notes to Consolidated Financial Statements
F-5
<PAGE> 181
SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, YEAR ENDED DECEMBER 31,
--------------------------- -------------------------------------------
1998 1997 1997 1996 1995
------------ ------------ ------------- ------------ ------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash Flows from Operating Activities:
Net income............................... $ 6,126,085 $ 10,882,952 $ 22,310,189 $ 19,025,450 $ 4,912,512
Adjustments to reconcile net income to
net cash provided by operating
activities --
Depreciation, depletion, and
amortization......................... 13,985,240 11,108,541 24,247,142 16,526,379 8,838,657
Deferred income taxes.................. 2,728,421 4,767,566 10,060,193 8,449,283 2,326,162
Deferred revenue amortization related
to production payment................ (647,279) (763,088) (1,449,808) (1,670,172) (1,787,974)
Other.................................. 233,297 616,794 786,917 140,047 112,890
Change in assets and liabilities --
(Increase) decrease in accounts
receivable......................... 2,864,171 3,432,911 (204,475) (5,008,592) (488,599)
Increase (decrease) in accounts
payable and accrued liabilities,
excluding income taxes payable..... (20,211) (294,150) (564,323) (444,966) 1,074,532
Increase (decrease) in income taxes
payable............................ 221,223 533,737 70,130 85,149 (611,717)
------------ ------------ ------------- ------------ ------------
Net Cash Provided by Operating
Activities....................... 25,490,947 30,285,263 55,255,965 37,102,578 14,376,463
------------ ------------ ------------- ------------ ------------
Cash Flows from Investing Activities:
Additions to property and equipment...... (66,968,334) (64,042,926) (131,967,444) (91,487,176) (40,032,944)
Proceeds from the sale of property and
equipment.............................. 1,199,061 1,648,477 3,369,982 2,247,799 230,242
Net cash received (distributed) as
operator of oil and gas properties..... (6,749,156) (1,740,833) (1,829,008) (2,074,104) 7,662,419
Net cash received (distributed) as
operator of partnerships and joint
ventures............................... 575,843 2,364,071 (2,102,553) 11,284,793 5,316,693
Other.................................... (526,793) (97,676) (259,255) 840 (41,181)
------------ ------------ ------------- ------------ ------------
Net Cash Used in Investing
Activities....................... (72,469,379) (61,868,887) (132,788,278) (80,027,848) (26,864,771)
------------ ------------ ------------- ------------ ------------
Cash Flows from Financing Activities:
Proceeds from long-term debt............. -- -- -- 115,000,000 --
Net proceeds from (payments of) bank
borrowings............................. 56,085,000 -- 7,915,000 -- (27,229,000)
Net proceeds from issuances of common
stock.................................. 1,178,846 1,428,708 2,389,336 3,264,482 46,306,322
Purchase of treasury stock............... (826,846) (8,417,228) (8,519,665) -- --
Loan to ESOP for purchase of shares...... -- -- -- (568,750) --
Payments of debt issuance costs.......... -- -- -- (4,550,000) --
------------ ------------ ------------- ------------ ------------
Net Cash Provided by (Used in)
Financing Activities............. 56,437,000 (6,988,520) 1,784,671 113,145,732 19,077,322
------------ ------------ ------------- ------------ ------------
Net Increase (Decrease) in Cash and Cash
Equivalents.............................. $ 9,458,568 $(38,572,144) $ (75,747,642) $ 70,220,462 $ 6,589,014
Cash and Cash Equivalents at Beginning of
Period................................... 2,047,332 77,794,974 77,794,974 7,574,512 985,498
------------ ------------ ------------- ------------ ------------
Cash and Cash Equivalents at End of
Period................................... $ 11,505,900 $ 39,222,830 $ 2,047,332 $ 77,794,974 $ 7,574,512
============ ============ ============= ============ ============
Supplemental Disclosures of Cash Flows
Information:
Cash paid during period for interest, net
of amounts capitalized................. $ 2,794,055 $ 2,036,002 $ 4,638,308 $ 831,516 $ 68,097
Cash paid during period for income
taxes.................................. $ 29,926 $ 150,000 $ 381,514 $ 676,920 $ 277,580
</TABLE>
See accompanying notes to Consolidated Financial Statements
F-6
<PAGE> 182
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation. The accompanying consolidated financial
statements include the accounts of Swift Energy Company (Swift) and its wholly
owned subsidiaries (collectively referred to as the "Company"), which are
engaged in the acquisition, development, operation, and exploration of oil and
natural gas properties, with particular emphasis on U.S. onshore natural gas
reserves. The Company also has oil and gas investments in Russia, Venezuela, and
New Zealand. The Company's investments in associated oil and gas partnerships
and its joint ventures are accounted for using the proportionate consolidation
method, whereby the Company's proportionate share of each entity's assets,
liabilities, revenues, and expenses is included in the appropriate
classifications in the consolidated financial statements. Intercompany balances
and transactions have been eliminated in preparing the consolidated statements.
In the second quarter 1998, the Company began netting supervision fees against
general and administrative expenses and oil and gas production costs. This
reclassification has been made to all periods presented. Certain other
reclassifications have been made to prior year amounts to conform to the current
year presentation.
Unaudited Interim Information. The unaudited interim consolidated financial
statements as of June 30, 1998 and for each of the six month periods ended June
30, 1998 and 1997, included herein, have been prepared pursuant to the rules and
regulations of the Securities and Exchange Commission. Accordingly, they do not
include all of the information and footnotes required by generally accepted
accounting principles for complete financial statements. In the opinion of the
Company's management, the unaudited interim consolidated financial statements
include all adjustments (consisting only of normal recurring adjustments) to
present fairly the information set forth herein. The interim financial results
should not be regarded as indicative of operating results for an entire year.
Use of Estimates. The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities, if any, at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from
estimates.
Property and Equipment. The Company follows the "full-cost" method of
accounting for oil and gas property and equipment costs. Under this method of
accounting, all productive and nonproductive costs incurred in the acquisition,
exploration, and development of oil and gas reserves are capitalized. Such costs
include lease acquisitions, geological and geophysical services, drilling,
completion, equipment, and certain general and administrative costs directly
associated with acquisition, exploration, and development activities. General
and administrative costs related to production and general overhead are expensed
as incurred. No gains or losses are recognized upon the sale or disposition of
oil and gas properties, except in transactions that involve a significant amount
of reserves. The proceeds from the sale of oil and gas properties are generally
treated as a reduction of oil and gas property costs. Fees from associated oil
and gas exploration and development limited partnerships are credited to oil and
gas property costs to the extent they do not represent reimbursement of general
and administrative expenses currently charged to expense.
Future development, site restoration, and dismantlement and abandonment
costs, net of salvage values, are estimated on a property-by-property basis
based on current economic conditions and are amortized to expense as the
Company's capitalized oil and gas property costs are amortized. The Company's
properties are all onshore and historically the salvage value of the tangible
equipment offsets the Company's site restoration and dismantlement and
abandonment costs. The Company expects this relationship will continue.
The Company computes the provision for depreciation, depletion, and
amortization of oil and gas properties on the unit-of-production method. Under
this method, the Company computes the provision by multiplying the total
unamortized costs of oil and gas properties -- including future development,
site restoration, and dismantlement and abandonment costs but excluding costs of
unproved properties -- by an
F-7
<PAGE> 183
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
overall rate determined by dividing the physical units of oil and gas produced
during the period by the total estimated units of proved oil and gas reserves.
This calculation is done on a country by country basis for those countries with
oil and gas production. The Company currently has production in the United
States only. The cost of unproved properties not being amortized is assessed
quarterly to determine whether the value has been impaired below the capitalized
cost. Any impairment assessed is added to the cost of proved properties being
amortized. To the extent costs accumulated in the Company's international
initiatives will not result in the addition of proved reserves, an impairment
would be charged to income upon such determination.
At the end of each quarterly reporting period, the unamortized cost of oil
and gas properties, net of related deferred income taxes, is limited to the sum
of the estimated future net revenues from proved properties using current
prices, discounted at 10%, and the lower of cost or fair value of unproved
properties, adjusted for related income tax effects ("Ceiling Limitation"). This
calculation is done on a country by country basis for those countries with
proved reserves. Currently, the Company has proved reserves in the United States
only.
The calculation of the Ceiling Limitation and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves. There are
numerous uncertainties inherent in estimating quantities of proved reserves and
in projecting the future rates of production, timing, and plan of development.
The accuracy of any reserves estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. Results of
drilling, testing, and production subsequent to the date of the estimate may
justify revision of such estimate. Accordingly, reserves estimates are often
different from the quantities of oil and gas that are ultimately recovered.
All other equipment is depreciated by the straight-line method at rates
based on the estimated useful lives of the property. Repairs and maintenance are
charged to expense as incurred. Renewals and betterments are capitalized.
Oil and Gas Revenues. Gas revenues generally are recorded using the
entitlement method in which the Company recognized its ownership interest in
natural gas production as revenue. If the Company's sales exceed its ownership
share of production, the differences are recorded as deferred revenue. Natural
gas balancing receivables are recorded when the Company's ownership share of
production exceeds sales. As of December 31, 1997 the Company did not have any
material natural gas imbalances.
Deferred Charges. Legal and accounting fees, underwriting fees, printing
costs, and other direct expenses associated with the issuance of the Company's
6.5% Convertible Subordinated Debentures due 2003 ("Debentures") were
capitalized in June 1993 and through June 1996 were being amortized over the
life of the Debentures. Due to the conversion of all outstanding Debentures into
common stock in August 1996, the related unamortized costs ($1,097,551) were
transferred to the Company's appropriate capital accounts in the third quarter
of 1996. The issuance costs associated with the public offering in November 1996
of the Company's 6.25% Convertible Subordinated Notes (the "Notes") have been
capitalized and are being amortized, using the effective interest method, over
the life of the Notes, which mature on November 15, 2006. The balance of these
issuance costs at December 31, 1997, ($4,184,014) is net of accumulated
amortization of $365,986.
Limited Partnerships and Joint Ventures. Between 1991 and 1995 (and for
prior periods), the Company formed limited partnerships and joint ventures for
the purpose of acquiring interests in producing oil and gas properties and,
since 1993, partnerships engaged in drilling for oil and gas reserves. The
Company serves as managing general partner or manager of these entities. Because
the Company serves as the general partner of these entities, under state
partnership law it is contingently liable for the liabilities of these
partnerships, virtually all of which are owed to the Company and are not
material for any of the periods presented in relation to the partnerships'
respective assets.
F-8
<PAGE> 184
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company acquired producing oil and gas properties and transferred those
properties to the partnership entities which invested in producing oil and gas
properties at cost, including interest, other carrying costs, closing costs, and
screening and evaluation costs of properties not acquired, or in certain
instances at fair market value based upon the opinion of an independent expert.
These costs were reduced by net operating revenues from the effective date of
the acquisition to the date of transfer to these entities. Such net operating
revenue amounts totaled approximately $100,000, $300,000, and $600,000 in 1997,
1996, and 1995, respectively. The Company, with the acquisitions made in 1997,
has fulfilled its responsibility of acquiring properties for such partnerships,
as these partnerships are fully invested in properties.
Commencing September 15, 1993, the Company began offering, on a private
placement basis, general and limited partnership interests in limited
partnerships to be formed to drill for oil and gas. As managing general partner,
the Company pays for all front-end costs incurred in connection with these
offerings, for which the Company receives an interest in the partnerships.
Through December 31, 1997, approximately $58.6 million had been raised in eleven
partnerships, one formed in each of 1993 and 1994 and three in each of 1995,
1996, and 1997. In May, July, and September 1997, the Company closed the ninth,
tenth, and eleventh partnerships with total subscriptions of approximately $4.4
million, $3.0 million, and $9.4 million, respectively. Costs of syndication and
qualification of these limited partnerships incurred by the Company have been
deferred. Under the current private limited partnership offerings, selling and
formation costs borne by the Company serve as the Company's general partner
contribution to such partnerships.
During 1996, the limited partners in 18 partnerships, which had been in
operation over nine years and had produced a substantial majority of their
reserves, voted to sell their remaining properties and liquidate the limited
partnerships. Of these partnerships, 10 were the earliest public income
partnerships (formed in 1984 to 1986) and were liquidated in 1996, and in early
1997 eight private drilling partnerships (formed in 1979 to 1985) were
liquidated. During 1997, the limited partners in an additional 11 partnerships,
formed in 1990 and 1991, voted to sell their properties and liquidate the
limited partnerships, which liquidation is expected in early 1998. As the public
income partnerships formed since 1986 grow older, it is anticipated that
proposals will continue to be made to the investors in those partnerships to
sell their properties and liquidate the partnerships.
Hedging Activities. The Company's revenues are primarily the result of
sales of its oil and natural gas production. Market prices of oil and natural
gas may fluctuate and adversely affect operating results. To mitigate some of
this risk, the Company does engage periodically in certain limited hedging
activities, but only to the extent of buying protection price floors for
portions of its and the limited partnerships' oil and gas production. Costs and
any benefits derived from these price floors are accordingly recorded as a
reduction or increase, as applicable, in oil and gas sales revenue and were not
significant for any year presented. The costs to purchase put options are
amortized over the option period. The costs related to the open contracts
totaled approximately $95,308 and had a market value of $121,600 as of December
31, 1997.
Income Taxes. The Company accounts for income taxes using Statement of
Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes."
SFAS No. 109 utilizes the liability method, and deferred taxes are determined
based on the estimated future tax effects of differences between the financial
statement and tax bases of assets and liabilities given the provisions of the
enacted tax laws.
Deferred Revenues. In May 1992, the Company purchased interests in certain
wells using funds provided by the Company's sale of a volumetric production
payment in these properties. Under the production payment agreement, the Company
is required to deliver to Enron approximately 9.5 Bcf over an eight-year period,
or for such longer period as is necessary to deliver a specified heating
equivalent quantity at an average price of $1.115 per MMBtu. The Company is
responsible for all production-related costs associated with operating these
properties. The amount to be delivered varies from month to month in generally
decreasing quantities. To the extent monthly gas production from the properties
exceeds the agreed upon deliverable quantities (as it has in every year since
the purchase date), the Company receives all proceeds from sale of such excess
gas at
F-9
<PAGE> 185
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
current market prices plus the proceeds from sale of oil or condensate. Volumes
remaining to be delivered through October 2000 under the volumetric production
payment (approximately 2.0 Bcf at December 31, 1997) are not included in the
Company's proved reserves. Net proceeds from the sale of the production payment
were recorded as deferred revenues. Deliveries under the production payment
agreement are recorded as oil and gas sales revenues and a corresponding
reduction of deferred revenues. Hydrocarbons produced in excess of the amount
required to be delivered are sold by the Company for its own account.
Cash and Cash Equivalents. The Company considers all highly liquid debt
instruments with an initial maturity of three months or less to be cash
equivalents.
Credit Risk Due to Certain Concentrations. The Company extends credit,
primarily in the form of monthly oil and gas sales and joint interest owners
receivables, to various companies in the oil and gas industry, which results in
a concentration of credit risk. The concentration of credit risk may be affected
by changes in economic or other conditions and may accordingly impact the
Company's overall credit risk. However, the Company believes that the risk of
these unsecured receivables is mitigated by the size, reputation, and nature of
the companies to which the Company extends credit.
During the year ended December 31, 1997, three oil or gas purchasers each
accounted for 10% or more of the Company's revenues, with those purchasers
together accounting for approximately 42%. Three oil or gas purchasers accounted
for 10% or more of the Company's revenues during the year ended December 31,
1996, with those purchasers together accounting for approximately 51%. Because
of the availability of other purchasers, the Company does not believe that the
loss of any single oil or gas purchaser or contract would materially affect its
sales.
Fair Value of Financial Instruments. The Company's financial instruments
consist of cash and cash equivalents, accounts receivable, accounts payable, and
long-term debt. The carrying amounts of cash and cash equivalents, accounts
receivable, and accounts payable approximate fair value due to the highly liquid
nature of these short-term instruments. The fair value of long-term debt was
determined based upon interest rates currently available to the Company for
borrowings with similar terms. The fair value of long-term debt approximates the
carrying amount as of December 31, 1997.
New Accounting Pronouncements. In the first quarter of 1998, the Company
adopted SFAS No. 130, "Reporting Comprehensive Income," which requires the
display of comprehensive income and its components in the financial statements.
Comprehensive income represents all changes in equity during the reporting
period, including net income and charges directly to equity which are excluded
from net income. The adoption of this statement does not have a material impact
on the Company or its financial disclosures, as the Company has not historically
and currently does not enter into transactions which result in charges (or
credits) directly to equity (such as additional minimum pension liability
changes, currency translation adjustments, and unrealized gains and losses on
available for sale securities.)
In April 1998, the American Institute of Certified Public Accountants
issued Statement of Position 98-5, "Reporting on the Costs of Start-Up
Activities," which requires costs of start-up activities to be expensed as
incurred. The statement is effective for financial statements beginning after
December 15, 1998. The Company expects to expense currently capitalized costs
related to start-up activities as a cumulative effect of a change in accounting
principle when the statement is adopted in January 1999. The adoption of this
standard is not expected to have a significant effect on the Company's financial
position or results of operations.
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." The Statement
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allow as derivative's gains
F-10
<PAGE> 186
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
and losses to offset related results on the hedged item in the income statement,
and requires that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15, 1999. A
company may also implement SFAS No. 133 as of the beginning of any fiscal
quarter after issuance (that is, fiscal quarters beginning June 16, 1998 and
thereafter). SFAS No. 133 cannot be applied retroactively. SFAS No. 133 must be
applied to (a) derivative instrument and (b) certain derivative instruments
embedded in hybrid contracts that were issued, acquired, or substantively
modified after December 31, 1997 (and, at the Company's election, before January
1, 1998).
The Company has not yet quantified the impacts of adopting SFAS No. 133 on
its financial statements and has not determined the timing of or method of our
adoption of SFAS No. 133.
2. INCOME PER SHARE
The Company has adopted SFAS No. 128, "Earnings per Share," which
establishes new standards for computing and presenting earnings per share. Basic
income per share has been computed using the weighted average number of common
shares outstanding during the respective periods. Basic income per share has
been retroactively restated in all periods presented to give recognition to the
adoption of SFAS No. 128, as well as to give recognition to an equivalent change
in capital structure as a result of a 10% stock dividend declared in October
1997 that resulted in an additional 1,494,606 shares being issued.
The calculation of diluted income per share assumes conversion of the
Company's Notes as of the beginning of the respective periods and the
elimination of the related after-tax interest expense and assumes, as of the
beginning of the period, exercise (using the treasury stock method) of stock
options and warrants. Diluted income per share has also been retroactively
restated for all periods presented to give effect to the adoption of SFAS No.
128 and the 10% stock dividend. For periods presented in which the Notes were
outstanding, the original conversion price of $34.6875 was revised to $31.534 to
reflect the October 1997 stock dividend declared.
The following is a reconciliation of the numerators and denominators used
in the calculation of basic and diluted earnings per share for the years ended
December 31, 1997, 1996, 1995, and for the six months ended June 30, 1998 and
1997:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------------------------------
1997 1996 1995
--------------------------------- --------------------------------- --------------------------------
PER PER PER
NET SHARE NET SHARE NET SHARE
INCOME SHARES AMOUNT INCOME SHARES AMOUNT INCOME SHARES AMOUNT
----------- ---------- ------ ----------- ---------- ------ ---------- ---------- ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Basic EPS:
Net Income and
Share Amounts.... $22,310,189 16,492,856 $1.35 $19,025,450 15,000,901 $1.27 $4,912,512 10,035,143 $0.49
Dilutive Securities:
6.25% Convertible
Notes............ 3,525,808 3,646,847 788,710 419,637 -- --
Stock Options...... -- 428,036 -- 407,108 -- --
----------- ---------- ----------- ---------- ---------- ----------
Diluted EPS:
Net Income and
Assumed Share
Conversions...... $25,835,997 20,567,739 $1.26 $19,814,160 15,827,646 $1.25 $4,912,512 10,035,143 $0.49
=========== ========== =========== ========== ========== ==========
</TABLE>
F-11
<PAGE> 187
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
--------------------------------------------------------------------
1998 1997
-------------------------------- ---------------------------------
PER PER
NET SHARE NET SHARE
INCOME SHARES AMOUNT INCOME SHARES AMOUNT
---------- ---------- ------ ----------- ---------- ------
<S> <C> <C> <C> <C> <C> <C>
Basic EPS:
Net Income and Share Amounts...................... $6,126,085 16,512,562 $0.37 $10,882,952 16,552,349 $0.66
Dilutive Securities:
6.25% Convertible Notes........................... 2,092,227 3,646,847 1,818,850 3,646,847
Stock Options..................................... -- 174,556 -- 493,985
---------- ---------- ----------- ----------
Diluted EPS:
Net Income and Assumed Share Conversions.......... $8,218,312 20,333,965 $0.37 $12,701,802 20,693,181 $0.61
========== ========== =========== ==========
</TABLE>
3. PROVISION FOR INCOME TAXES
The following is an analysis of the consolidated income tax provision:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------
1997 1996 1995
----------- ---------- ----------
<S> <C> <C> <C>
Current....................................... $ 77,402 $ 759,253 $ (344,137)
Deferred...................................... 10,742,015 9,001,080 2,326,162
----------- ---------- ----------
Total............................... $10,819,417 $9,760,333 $1,982,025
=========== ========== ==========
</TABLE>
There are differences between income taxes computed using the statutory
rate (34% for 1997, 1996, and 1995) and the Company's effective income tax rates
(32.7%, 33.9%, and 28.7% for 1997, 1996, and 1995, respectively), primarily as
the result of certain tax credits available to the Company. Reconciliations of
income taxes computed using the statutory rate to the effective income tax rates
are as follows:
<TABLE>
<CAPTION>
1997 1996 1995
----------- ---------- ----------
<S> <C> <C> <C>
Income taxes computed at federal statutory
rate........................................ $11,264,066 $9,787,166 $2,344,143
State tax provisions, net of federal
benefits.................................... 48,058 75,936 84,202
Nonconventional fuel source credit............ (294,000) (306,000) (370,000)
Depletion deductions in excess of basis....... (51,000) (26,520) (34,000)
Other, net.................................... (147,707) 229,751 (42,320)
----------- ---------- ----------
Provision for income taxes.................... $10,819,417 $9,760,333 $1,982,025
=========== ========== ==========
</TABLE>
The tax effects of significant temporary differences representing the net
deferred tax liability at December 31, 1997 and 1996, were as follows:
<TABLE>
<CAPTION>
1997 1996
----------- -----------
<S> <C> <C>
Deferred tax assets:
Alternative minimum tax credits......................... $ 1,831,299 $ 1,517,470
Other................................................... 237,587 --
----------- -----------
Total deferred tax assets....................... $ 2,068,886 $ 1,517,470
Deferred tax liabilities:
Oil and gas properties.................................. $26,785,212 $15,935,855
Other................................................... 637,824 875,572
----------- -----------
Total deferred tax liabilities.................. $27,423,036 $16,811,427
----------- -----------
Net deferred tax liability................................ $25,354,150 $15,293,957
=========== ===========
</TABLE>
F-12
<PAGE> 188
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company did not record any valuation allowances against deferred tax
assets at December 31, 1997, 1996, and 1995.
At December 31, 1997, the Company had alternative minimum tax credits of
$1,831,299 that carry forward indefinitely available to reduce future regular
tax liability to the extent they exceed the related tentative minimum tax
otherwise due.
4. LONG-TERM DEBT AND BANK BORROWINGS
Long-Term Debt. The Company's long-term debt at December 31, 1997 and 1996,
consists of $115,000,000 of 6.25% Convertible Subordinated Notes due 2006
("Notes"). The Notes were issued on November 25, 1996, and will mature on
November 15, 2006. The Notes are convertible into common stock of the Company at
the option of the holders at any time prior to maturity at an adjusted
conversion price of $31.534 per share, subject to adjustment upon the occurrence
of certain events. The original conversion price of $34.6875 was adjusted
downward to reflect the October 1997 10% stock dividend. Interest on the Notes
is payable semiannually on May 15 and November 15, commencing with the first
payment on May 15, 1997. On or after November 15, 1999, the Notes are redeemable
for cash at the option of the Company, with certain restrictions, at 104.375% of
principal, declining to 100.625% in 2005. Upon certain changes in control of the
Company, if the price of the Company's common stock is not above certain levels,
each holder of Notes will have the right to require the Company to repurchase
the Notes at the principal amount thereof, together with accrued and unpaid
interest to the date of repurchase but after the repayment of any Senior
indebtedness, as defined.
The Company's long-term debt previously consisted of $28,750,000 of 6.5%
Convertible Subordinated Debentures due 2003 ("Debentures") issued on June 30,
1993, which were convertible into common stock of the Company at an adjusted
conversion price of $12.27 per share. On July 1, 1996, the Company called all of
the Debentures for redemption on August 5, 1996, at 104.55% of their face
amount. Prior to the redemption date, the holders of all of the outstanding
Debentures elected to convert their Debentures into shares of common stock,
resulting in the issuance of 2.34 million shares of common stock in August 1996.
Upon conversion of the Debentures into common stock, the approximate $27,650,000
net carrying amount of the debt (the face amount less unamortized deferred
charges) was transferred to the Company's appropriate capital accounts during
the third quarter of 1996.
Interest expense on the Notes, including amortization of debt issuance
costs, totaled $7,514,967 in 1997, while interest expense on both the Notes and
Debentures, including amortization of debt issuance costs, totaled $1,731,194 in
1996.
Bank Borrowings. At the end of 1996, the Company had available, through a
two bank-group, a $100,000,000 unsecured revolving line of credit. The available
borrowing base at December 31, 1996, was $5,000,000. Prior to December 1, 1996,
the borrowing base was $30,000,000. At the Company's request, it was reduced to
the $5,000,000 amount effective December 1, 1996. This was requested in order to
reduce the amount of commitment fees paid on this facility, the calculation of
which is described below. Depending on the level of outstanding debt, the
interest rate is either the bank's base rate (8.25% at December 31, 1996) or the
bank's base rate plus 0.25%. This facility also allows, at the Company's option,
draws which bear interest for specific periods at the London Interbank Offered
Rate ("LIBOR"). The LIBOR option will now vary from LIBOR plus 1% to plus 1.5%.
There was no outstanding balance under this line of credit at December 31, 1996.
Effective December 1, 1997, the available borrowing base was increased to
$40,000,000 and will be redetermined periodically. The interest rate was 8.5% at
December 31, 1997, with an outstanding balance at that date of $2,431,000. The
revolving line of credit extends through September 30, 1999.
F-13
<PAGE> 189
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The terms of the revolving line of credit include, among other
restrictions, a limitation on the level of cash dividends (not to exceed
$2,000,000 in any fiscal year), requirements as to maintenance of certain
minimum financial ratios (principally pertaining to working capital, debt, and
equity ratios), and limitations on incurring other debt. Since inception, no
cash dividends have been declared on the Company's common stock. For all periods
presented, the Company was in compliance with the provisions of these
agreements.
The Company's other credit facility, which is the Company's only secured
facility, is an amended and restated revolving line of credit with the lead bank
of the two bank-group, secured by certain Company receivables. Effective April
30, 1996, this facility was increased to $7,000,000, with interest at the bank's
base rate less 0.25% (8% at December 31, 1996 and 8.25% at December 31, 1997).
The available borrowing base was $2,000,000 at December 31, 1996, and $5,484,000
at December 31, 1997, and is redetermined monthly. There were no outstanding
amounts under this facility at December 31, 1996, while at December 31, 1997,
the outstanding amount was $5,484,000. The restated credit facility extends
through September 30, 1999.
In addition to interest on these credit facilities, the Company pays a
commitment fee to compensate the banks for making funds available. The fee on
the revolving line of credit is calculated on the average daily remainder, if
any, of the commitment amount less the aggregate principal amounts outstanding,
plus the amount of all letters of credit outstanding during the period. The
aggregate amounts of commitment fees paid by the Company were $31,000 in 1997
and $120,000 in 1996.
5. COMMITMENTS AND CONTINGENCIES
Total rental and lease expenses were $1,039,210 in 1997, $957,797 in 1996,
and $998,714 in 1995. The Company's remaining minimum annual obligations under
non-cancelable operating lease commitments are $1,136,523 for 1998, $1,175,546
for 1999, $1,181,455 for 2000, $1,181,455 for 2001, and $1,303,130 for 2002.
As of December 31, 1997, the Company is the managing general partner of 89
limited partnerships. Because the Company serves as the general partner of these
entities, under state partnership law it is contingently liable for the
liabilities of these partnerships, which liabilities are not material for any of
the periods presented in relation to the partnerships' respective assets.
In the ordinary course of business, the Company has been party to various
legal actions, which arise primarily from its activities as operator of oil and
gas wells. In management's opinion, the outcome of any such currently pending
legal actions will not have a material adverse effect on the financial position
or results of operations of the Company.
6. STOCKHOLDERS' EQUITY
Common Stock. In October 1997, the Company declared a 10% stock dividend to
shareholders of record. The transaction was valued based on the closing price
($28.8125) of the Company's common stock on the New York Stock Exchange on
October 1, 1997. As a result of the issuance of 1,494,606 shares of the
Company's common stock as a dividend, retained earnings were reduced by
$43,063,335, with the common stock and additional paid-in capital accounts
increased by the same amount. Basic and diluted income per share was restated
for all periods presented to reflect the effect of the stock dividend.
In August 1996, the holders of the Company's Debentures converted such
Debentures into 2,343,108 shares of the Company's common stock, which resulted
in a third quarter 1996 increase in the Company's capital accounts of
approximately $27,650,000.
Stock-Based Compensation Plans. The Company has two stock option plans, the
1990 stock compensation plan and the 1990 nonqualified plan, as well as an
employee stock purchase plan.
Under the 1990 compensation plan, incentive stock options and other options
and awards may be granted to employees to purchase shares of common stock. Under
the 1990 non-qualified plan, non-employee
F-14
<PAGE> 190
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
members of the Company's Board of Directors may be granted options to purchase
shares of common stock. Both plans provide that the exercise prices equal 100%
of the fair value of the common stock on the date of grant. Options become
exercisable for 20% of the shares on the first anniversary of the grant of the
option and are exercisable for an additional 20% per year thereafter. Options
granted expire 10 years after the date of grant or earlier in the event of the
optionee's separation from employment. At the time the stock options are
exercised, the option price is credited to common stock and additional paid-in
capital.
The Company also granted certain stock options to individuals who were
neither employees, officers, nor directors for specific services rendered to the
Company. During 1996 all of these remaining options were either exercised
(57,555 shares) or canceled (11,195 shares) so that no such options remain
outstanding.
The employee stock purchase plan provides eligible employees the
opportunity to acquire shares of Company common stock at a discount through
payroll deductions. This plan was approved at the May 11, 1993, shareholders
meeting. The plan year is from June 1 to the following May 31. The first year of
the plan commenced June 1, 1993. Employees may authorize payroll deductions of
up to 10% of their base salary during the plan year by making an election to
participate prior to the start of a plan year. The purchase price for stock
acquired under the plan will be 85% of the lower of the closing price of the
Company's common stock as quoted on the New York Stock Exchange at the beginning
or end of the plan year or a date during the year chosen by the participant.
Under this plan the Company issued 26,551 shares at a price of $15.19 in 1997,
36,387 shares at a price range of $6.59 to $7.97 in 1996, and 37,689 shares at a
price range of $6.80 to $7.92 in 1995. The estimated weighted average fair value
of shares issued under this plan was $4.39 in 1997, $2.13 in 1996, and $2.59 in
1995. As of December 31, 1997, there remained 458,204 shares available for
issuance under this plan. There are no charges or credits to income in
connection with this plan.
The Company accounts for the two stock option plans under APB Opinion No.
25, under which no compensation cost has been recognized. Had compensation cost
for these plans been determined consistent with SFAS No. 123, "Accounting for
Stock-Based Compensation," the Company's net income and earnings per share would
have been reduced to the following pro forma amounts (1996 and 1995 amounts have
been restated to reflect the October 1997 10% stock dividend):
<TABLE>
<CAPTION>
1997 1996 1995
----------- ----------- ----------
<S> <C> <C> <C> <C>
Net Income: As Reported.................. $22,310,189 $19,025,450 $4,912,512
Pro Forma.................... $21,362,722 $18,750,064 $4,628,678
Basic EPS: As Reported.................. $ 1.35 $ 1.27 $ 0.49
Pro Forma.................... $ 1.30 $ 1.25 $ 0.46
Diluted EPS: As Reported.................. $ 1.26 $ 1.25 $ 0.49
Pro Forma.................... $ 1.21 $ 1.23 $ 0.46
</TABLE>
Because the SFAS No. 123 method of accounting has not been applied to
options granted prior to January 1, 1995, the resulting pro forma compensation
cost may not be representative of that to be expected in future years.
F-15
<PAGE> 191
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following is a summary of the Company's stock options under these plans
as of December 31, 1997, 1996, and 1995:
<TABLE>
<CAPTION>
1997 1996 1995
----------------------- ----------------------- -----------------------
WTD. AVG. WTD. AVG. WTD. AVG.
SHARES EXER. PRICE SHARES EXER. PRICE SHARES EXER. PRICE
--------- ----------- --------- ----------- --------- -----------
<S> <C> <C> <C> <C> <C> <C>
Options outstanding,
beginning of period... 1,399,769 $12.09 1,308,391 $ 8.83 1,166,920 $8.86
Options granted......... 401,390 $26.23 302,281 $23.78 227,502 $8.63
Options terminated...... (31,404) $12.99 (11,251) $ 8.81 (80,270) $8.78
Options exercised....... (137,155) $ 8.54 (199,652) $ 8.65 (5,761) $7.59
Options adjusted for 10%
stock dividend........ 128,912 -- --
--------- --------- ---------
Options outstanding, end
of period............. 1,761,512 $14.71 1,399,769 $12.09 1,308,391 $8.83
========= ========= =========
Options exercisable, end
of period............. 869,484 $ 9.05 700,271 $ 8.82 722,627 $8.81
========= ========= =========
Options available for
future grant, end of
period................ 1,501,622 38,546 343,344
========= ========= =========
Estimated weighted
average fair value per
share of options
granted during the
year.................. $ 13.98 $ 15.17 $ 4.76
========= ========= =========
</TABLE>
The fair value of each option grant, as opposed to its exercise price, is
estimated on the date of grant using the Black-Scholes option-pricing model with
the following weighted average assumptions in 1997, 1996, and 1995,
respectively: no dividend yield, expected volatility factors of 38.7%, 40.4%,
and 39.7%, risk-free interest rates of 6.02%, 6.42%, and 6.98%, and expected
lives of 7.5, 10.0, and 7.7 years. The following table summarizes information
about stock options outstanding at December 31, 1997:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------------- ------------------------
WTD. AVG. NUMBER
NUMBER REMAINING WTD. AVG. EXERCISABLE WTD. AVG.
OUTSTANDING CONTRACTUAL EXERCISE AT EXERCISE
RANGE OF EXERCISE PRICES AT 12/31/97 LIFE PRICE 12/13/97 PRICE
------------------------ ----------- ----------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C>
$4 to $9................. 787,384 4.8 $ 7.73 606,413 $ 7.63
$9 to $18................ 358,900 6.2 $10.67 220,631 $ 9.68
$18 to $27................ 615,228 9.5 $26.00 42,440 $25.91
--------- -------
$4 to $27................ 1,761,512 6.7 $14.71 869,484 $ 9.05
========= =======
</TABLE>
Employee Stock Ownership Plan. In 1996, the Company established an Employee
Stock Ownership Plan ("ESOP") effective January 1, 1996. All employees over the
age of 21 with one year of service are participants. The Plan has a five year
cliff vesting, and service is recognized after the Plan effective date. The ESOP
is designed to enable employees of the Company to accumulate stock ownership.
While there will be no employee contributions, participants will receive an
allocation of stock which has been contributed by the Company. Compensation
costs are reported when such shares are released to employees. The Plan may also
acquire Swift Energy Company common stock purchased at fair market value. The
ESOP can borrow money from the Company to buy Company stock. This was done in
September 1996 to purchase 25,000 shares (adjusted to 27,500 shares after the
October 1, 1997 10% stock dividend) from the Company's chairman. Benefits will
be paid in a lump sum or installments, and the participants generally have the
choice of receiving
F-16
<PAGE> 192
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
cash or stock. At December 31, 1997 and 1996, the unearned portion of the ESOP
($150,055) and ($521,354), respectively, was recorded as a contra-equity account
entitled "Unearned ESOP Compensation."
Common Stock Repurchase Program. In March 1997, the Company's Board of
Directors approved a common stock repurchase program for up to $20.0 million of
the Company's common stock and subsequently extended this program through June
30, 1998. Purchases of shares are made in the open market. Under the program,
through December 31, 1997, 387,800 shares have been acquired at a total cost of
$8,519,665 and are included in "Treasury stock held, at cost" on the balance
sheet.
Shareholder Rights Plan. In August 1997, the Board of Directors declared a
dividend of one preferred share purchase right on each outstanding share of the
Company's common stock. The rights are not currently exercisable, but would
become exercisable if certain events occurred relating to any person or group
acquiring or attempting to acquire 15% or more of the Company's outstanding
shares of common stock. Thereafter, upon certain triggers, each right not owned
by an acquiror allows its holder to purchase Company securities with a market
value of two times the $150 exercise price.
7. RELATED-PARTY TRANSACTIONS
The Company is the operator of a substantial number of properties owned by
its affiliated limited partnerships and joint ventures and accordingly charges
these entities and third party joint interest owners operating fees. The Company
is also reimbursed for direct, administrative, and overhead costs incurred in
conducting the business of the limited partnerships, which totaled approximately
$6,300,000, $6,100,000, and $4,800,000 in 1997, 1996, and 1995, respectively.
The Company was also reimbursed by the limited partnerships and joint ventures
for costs incurred in the screening, evaluation, and acquisition of producing
oil and gas properties on their behalf. Such costs totaled approximately
$490,000, $250,000, and $600,000 in 1997, 1996, and 1995, respectively. In the
case where the limited partners voted to sell their remaining properties and
liquidate the limited partnerships, the Company was also reimbursed for direct,
administrative, and overhead costs incurred in the disposition of such
properties, which costs totaled approximately $675,000, $805,000, and $80,000 in
1997, 1996, and 1995, respectively.
8. FOREIGN ACTIVITIES
On September 3, 1993, the Company signed a Participation Agreement with
Senega, a Russian Federation joint stock company (in which the Company has an
indirect interest of less than 1%), to assist in the development and production
of reserves from two fields in Western Siberia providing the Company with a
minimum 5% net profits interest from the sale of hydrocarbon products from the
fields for providing managerial, technical, and financial support to Senega.
Additionally, the Company purchased a 1% net profits interest from Senega for
$300,000. In May 1995, the Company executed a Management Agreement with Senega,
under which, in return for undertaking to obtain financing for development of
these fields, Swift would be entitled to receive a 49% interest in production
income derived by Senega from this project after repayment of costs.
On December 10, 1997, the Company agreed to terminate the Management
Agreement with Senega and to amend and restate the Participation Agreement.
Under the amended and restated Participation Agreement, the Company retains its
6% net profits interest in the Samburg Field and has agreed to assist Senega in
obtaining investments necessary to develop the field. Senega is charged with the
management and control of the field development. At December 31, 1997, the
Company's investment in Russia was approximately $10,190,000 and is included in
the unproved properties portion of oil and gas properties.
The Company formed a wholly-owned subsidiary, Swift Energy de Venezuela, C.
A., for the purpose of submitting a bid on August 5, 1993, under the Venezuelan
Marginal Oil Field Reactivation Program. Although the Company did not win the
bid, it has continued to pursue cooperative ventures involving other fields and
opportunities in Venezuela. The Company evaluated a number of Blocks being
offered by Petroleos
F-17
<PAGE> 193
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
de Venezuela, S. A. under the Third Operating Agreement Round in 1997, but
decided against submitting any bid on these Blocks. The Company has entered into
an agreement with Tecnoconsult, S. A., a Venezuelan company, to jointly
formulate and submit a proposal to Petroleos de Venezuela, S. A. for the
construction and operation of a methane pipeline. Currently, the technical and
economic feasibility of the project is under study. At December 31, 1997, the
Company's investment in Venezuela was approximately $2,435,000 and is included
in the unproved properties portion of oil and gas properties, net of impairments
of $45,668.
Since October 1995, the Company has been issued two Petroleum Exploration
Permits by the New Zealand Minister of Energy. The first permit covers
approximately 65,000 acres in the Onshore Taranaki Basin of New Zealand's North
Island, and the second covers approximately 69,300 adjacent acres. Under the
terms of these permits, the Company is obligated to analyze and interpret
certain seismic data, acquire certain new seismic data and drill one exploratory
well, to be followed by a development well or additional seismic work, all of
which is to be performed on a staged basis in order to maintain the permits,
over periods extending through July 2000 for the first permit and August 1999
for the second permit. The Company formed a wholly-owned subsidiary, Swift
Energy New Zealand Limited, for the purpose of conducting its New Zealand
activities and assigned its interest in the permits to that subsidiary during
the third quarter of 1997. At December 31, 1997, the Company's investment in New
Zealand was approximately $2,480,000 and is included in the unproved properties
portion of oil and gas properties.
(9) SUBSEQUENT EVENTS (SUBSEQUENT TO THE DATE OF AUDITOR'S REPORT AND UNAUDITED)
Sonat Properties Acquisition. On July 2, 1998, the Company entered into a
purchase agreement to acquire from Sonat Exploration Company ("Sonat"), a
subsidiary of Sonat Inc., effective April 1, 1998, certain producing oil and gas
properties (the "Sonat Properties") located in the Texas and Louisiana Austin
Chalk trend for approximately $87.6 million in cash, with a majority of the
purchase price being allocated to proved reserves. As of April 1, 1998,
estimated proved reserves for the Sonat Properties were 91.1 Bcfe, of which
approximately 56% was natural gas, with 1997 production of 22.0 Bcfe, of which
approximately 51% was natural gas. The properties include 156 producing oil and
natural gas wells in the Brookeland Field in Southeast Texas and the Masters
Creek Field in Western Louisiana, 21 saltwater disposal wells, a 20% interest in
two natural gas plants, associated production facilities and working interests
in approximately 200,000 undeveloped net acres containing more than 50 drilling
locations. The Company will become operator of 113 of the 156 wells. The two gas
plants are outside operated and have combined capacity of 250 Mmcfe per day, and
in 1997 had operating cash flow of $2.8 million. The acquisition was closed on
August 26, 1998.
New Credit Facility. On August 18, 1998, the Company closed on a $250.0
million revolving line of credit (the "New Credit Facility"), of which Bank One,
Texas, National Association, the lead bank, has committed $37.5 million and has
syndicated the balance with a group of nine other banks. The New Credit Facility
is subject to an initial borrowing base of $170.0 million. However, an
additional $30.0 million will be added to this borrowing base upon consummation
of the acquisition of the Partnership Properties. As of September 1, 1998, $19.2
million of the $170.0 million borrowing base was available to the Company. The
New Credit Facility replaces all of the Company's prior bank credit facilities.
The borrowing base will be redetermined semi-annually on the basis of reserve
reports and other information available to the lenders. In addition, the lenders
or the Company may, at their discretion, make a redetermination of the borrowing
base at any time including in connection with the incurrence of additional debt
and the sale or transfer of properties by the Company.
Borrowings under the New Credit Facility bear interest, at the option of
the Company, either at (i) the lead bank's prime rate, currently 8.5%, or (ii)
adjusted LIBOR plus the applicable margin, which increases as the level of
outstanding debt increases. The New Credit Facility extends until August 18,
2002. The terms of the New Credit Facility include restrictions such as
limitations on debt obligations, certain liens, dividends (not to exceed $2.0
million annually), a $15.0 million limit on repurchases by the Company of its
Common Stock, as well requirements as to maintenance of certain minimum
financial ratios (principally pertaining to working capital, debt and equity
ratios).
F-18
<PAGE> 194
SUPPLEMENTAL INFORMATION (UNAUDITED)
Capitalized Costs. The following table presents the Company's aggregate
capitalized costs relating to oil and gas producing activities and the related
depreciation, depletion, and amortization:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1997 1996
------------ ------------
<S> <C> <C>
Oil and Gas Properties:
Proved................................................ $326,836,431 $216,310,033
Unproved (not being amortized) -- Domestic............ 26,735,460 15,733,952
Unproved (not being amortized) -- Foreign............. 15,104,349 11,886,510
------------ ------------
368,676,240 243,930,495
Accumulated Depreciation, Depletion, and Amortization... (67,363,393) (43,920,120)
------------ ------------
$301,312,847 $200,010,375
============ ============
</TABLE>
Of the $26,735,460 of net domestic unproved property costs (primarily
seismic and lease acquisition costs) at December 31, 1997, being excluded from
the amortizable base, $16,902,647 was incurred in 1997, $5,244,450 was incurred
in 1996, $1,262,038 was incurred in 1995, and $3,326,325 was incurred in prior
years. The Company expects it will complete its evaluation of the properties
representing the majority of these domestic costs within the next two to three
years.
Of the $15,104,349 of net foreign unproved property costs at December 31,
1997, being excluded from the amortizable base, $3,217,838 was incurred in 1997,
$3,745,856 was incurred in 1996, $3,321,211 was incurred in 1995, and $4,819,444
was incurred in prior years. In New Zealand, the Company expects drilling to
commence in either late 1998 or in 1999. At this time the Company cannot predict
when it will complete the evaluation of its unproved properties in Russia and
Venezuela due to various economic and political factors associated with such
investments.
Capital Expenditures. The following table sets forth capital expenditures
related to the Company's oil and gas operations:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1997 1996 1995
------------ ----------- -----------
<S> <C> <C> <C>
Acquisition of proved properties........... $ 8,417,318 $ 1,529,611 $ 3,461,091
Lease acquisitions(1)(2)................... 21,603,732 16,426,327 9,742,543
Exploration................................ 10,705,115 2,704,281 2,289,814
Development................................ 90,329,619 69,067,024 23,555,988
------------ ----------- -----------
Total(3)................................... $131,055,784 $89,727,243 $39,049,436
============ =========== ===========
</TABLE>
- ---------------
(1) Lease acquisitions for 1997, 1996, and 1995 include expenditures of
$658,145, $2,712,278, and $2,814,395, respectively, relating to the
Company's initiatives in Russia; 1997, 1996, and 1995 expenditures of
$828,133, $487,597, and $304,610, respectively, relating to initiatives in
Venezuela; and 1997, 1996, and 1995 expenditures of $1,731,561, $545,980,
and $202,206, respectively, relating to initiatives in New Zealand.
(2) These are actual amounts as incurred by year, including both proved and
unproved lease costs. The annual lease acquisition amounts added to proved
oil and gas properties (being amortized) for 1997, 1996, and 1995,
respectively, were $7,384,385, $9,458,016, and $3,895,871.
(3) Includes capitalized general and administrative costs directly associated
with the acquisition, development, and exploration efforts of approximately
$11,700,000, $7,400,000, and $7,100,000 in 1997, 1996, and 1995,
respectively. In addition, total includes $2,326,691, $1,549,575, and
$1,442,022 in 1997, 1996, and 1995, respectively, of capitalized interest on
unproved properties.
F-19
<PAGE> 195
SWIFT ENERGY COMPANY AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION (UNAUDITED) -- (CONTINUED)
Results of Operations. The following table sets forth results of the
Company's oil and gas operations:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1997 1996 1995
------------ ------------ -----------
<S> <C> <C> <C>
Oil and gas sales......................... $ 69,015,189 $ 52,770,672 $22,527,892
Production costs.......................... (8,778,876) (6,141,941) (4,906,899)
Depreciation, depletion, and
amortization............................ (23,443,273) (15,812,134) (8,349,324)
------------ ------------ -----------
36,793,040 30,816,597 9,271,669
Income taxes.............................. (12,015,797) (10,446,826) (2,660,969)
------------ ------------ -----------
Results of producing activities........... $ 24,777,243 $ 20,369,771 $ 6,610,700
============ ============ ===========
Amortization per physical unit of
production (equivalent Mcf of gas)...... $ 0.92 $ 0.81 $ 0.75
============ ============ ===========
</TABLE>
Supplemental Reserve Information. The following information presents
estimates of the Company's proved oil and gas reserves, which are all located
onshore in the United States. All of the Company's reserves were determined by
Company personnel and audited by H. J. Gruy and Associates, Inc. ("Gruy"),
independent petroleum consultants. Gruy's summary report dated February 9, 1998,
is set forth as an exhibit to the Form 10-K Report for the year ended December
31, 1997, and includes definitions and assumptions that served as the basis for
the estimates of proved reserves and future net cash flows. Such definitions and
assumptions should be referred to in connection with the following information:
Estimates of Proved Reserves
<TABLE>
<CAPTION>
OIL AND
NATURAL GAS CONDENSATE
(MCF) (BBLS)
----------- ----------
<S> <C> <C>
Proved reserves as of December 31, 1994(1).................. 76,263,964 4,553,267
Revisions of previous estimates(2)........................ 6,982,317 (421,901)
Purchases of minerals in place............................ 4,166,922 254,211
Sales of minerals in place................................ (13,215) (10,617)
Extensions, discoveries, and other additions.............. 62,870,240 1,592,456
Production(3)............................................. (6,702,708) (545,435)
----------- ---------
Proved reserves as of December 31, 1995(1).................. 143,567,520 5,421,981
Revisions of previous estimates(2)........................ (9,544,391) (816,065)
Purchases of minerals in place............................ 2,676,393 97,178
Sales of minerals in place................................ (4,163,770) (340,706)
Extensions, discoveries, and other additions.............. 107,762,886 1,745,307
Production(3)............................................. (14,540,437) (623,386)
----------- ---------
Proved reserves as of December 31, 1996(1).................. 225,758,201 5,484,309
Revisions of previous estimates(2)........................ (22,774,899) (427,412)
Purchases of minerals in place............................ 30,342,398 580,278
Sales of minerals in place................................ (1,155,706) (50,909)
Extensions, discoveries, and other additions.............. 102,479,883 2,945,037
Production(3)............................................. (20,344,208) (672,385)
----------- ---------
Proved reserves as of December 31, 1997(1).................. 314,305,669 7,858,918
=========== =========
Proved developed reserves,
December 31, 1994......................................... 46,406,448 3,209,387
December 31, 1995......................................... 81,532,025 3,313,226
December 31, 1996......................................... 135,424,880 3,622,480
December 31, 1997......................................... 191,108,214 4,288,696
</TABLE>
- ---------------
(1) Proved reserves exclude quantities subject to the Company's volumetric
production payment agreement.
F-20
<PAGE> 196
SWIFT ENERGY COMPANY AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION (UNAUDITED) -- (CONTINUED)
(2) Revisions of previous quantity estimates are related to upward or downward
variations based on current engineering information for production rates,
volumetrics, and reservoir pressure. Additionally, changes in quantity
estimates are affected by the increase or decrease in crude oil and natural
gas prices at each year end. Proved reserves as of December 31, 1997, were
based upon prices of $2.78 per Mcf of natural gas and $15.76 per barrel of
oil, compared to $4.47 per Mcf and $23.75 per barrel as of December 31,
1996.
(3) Natural gas production for 1995, 1996, and 1997 excludes 1,211,255,
1,156,361, and 1,015,226 Mcf, respectively, delivered under the Company's
volumetric production payment agreement.
Standardized Measure of Discounted Future Net Cash Flows. The standardized
measure of discounted future net cash flows relating to proved oil and gas
reserves is as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------
1997 1996 1995
------------- -------------- ------------
<S> <C> <C> <C>
Future gross revenues................. $ 994,828,072 $1,141,831,786 $445,572,715
Future production costs............... (273,475,056) (228,626,881) (121,317,850)
Future development costs.............. (92,946,811) (59,988,855) (42,607,921)
------------- -------------- ------------
Future net cash flows before
income taxes........................ 628,406,205 853,216,050 281,646,944
Future income taxes................... (135,587,216) (211,375,632) (55,469,213)
------------- -------------- ------------
Future net cash flows after
income taxes........................ 492,818,989 641,840,418 226,177,731
Discount at 10% per annum............. (199,980,649) (274,608,116) (97,273,647)
------------- -------------- ------------
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves......... $ 292,838,340 $ 367,232,302 $128,904,084
============= ============== ============
</TABLE>
The standardized measure of discounted future net cash flows from
production of proved reserves was developed as follows:
1. Estimates are made of quantities of proved reserves and the future
periods during which they are expected to be produced based on year-end economic
conditions.
2. The estimated future gross revenues of proved reserves are priced on the
basis of year-end prices, except in those instances where fixed and determinable
gas price escalations are covered by contracts limited to the price the Company
reasonably expects to receive.
3. The future gross revenue streams are reduced by estimated future costs
to develop and to produce the proved reserves, as well as certain abandonment
costs based on year-end cost estimates and the estimated effect of future income
taxes.
4. Future income taxes are computed by applying the statutory tax rate to
future net cash flows reduced by the tax basis of the properties, the estimated
permanent differences applicable to future oil and gas producing activities, and
tax carry forwards.
The estimates of cash flows and reserves quantities shown above are based
on year-end oil and gas prices. Under Securities and Exchange Commission rules,
companies that follow the full-cost accounting method are required to make
quarterly Ceiling Limitation calculations, using prices in effect as of the
period end date presented (see Note 1). Application of these rules during
periods of relatively low oil and gas prices, even if of short-term seasonal
duration, may result in write-downs.
The standardized measure of discounted future net cash flows is not
intended to present the fair market value of the Company's oil and gas property
reserves. An estimate of fair value would also take into account, among other
things, the recovery of reserves in excess of proved reserves, anticipated
future changes in prices and costs, an allowance for return on investment, and
the risks inherent in reserve estimates.
F-21
<PAGE> 197
SWIFT ENERGY COMPANY AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION (UNAUDITED) -- (CONTINUED)
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Beginning balance................................ $367,232,302 $128,904,084 $ 66,471,967
------------ ------------ ------------
Revisions to reserves proved in prior years --
Net changes in prices, production costs, and
future development costs.................... (238,743,291) 144,386,724 25,415,116
Net changes due to revisions in quantity
estimates................................... (27,188,512) (25,755,091) 4,735,186
Accretion of discount.......................... 47,068,172 14,703,841 6,939,460
Other.......................................... (38,347,310) 6,649,394 (10,981,721)
------------ ------------ ------------
Total revisions.................................. (257,210,941) 139,984,868 26,108,041
New field discoveries and extensions, net of
future production and development costs........ 110,396,029 208,250,909 44,292,042
Purchases of minerals in place................... 29,290,334 6,835,362 4,928,563
Sales of minerals in place....................... (2,373,547) (8,084,581) (74,858)
Sales of oil and gas produced, net of production
costs.......................................... (56,181,494) (42,723,456) (13,913,612)
Previously estimated development costs
incurred....................................... 55,742,684 19,883,446 16,303,629
Net change in income taxes....................... 45,942,973 (85,818,330) (15,211,688)
------------ ------------ ------------
Net change in standardized measure of discounted
future net cash flows.......................... (74,393,962) 238,328,218 62,432,117
------------ ------------ ------------
Ending balance................................... $292,838,340 $367,232,302 $128,904,084
============ ============ ============
</TABLE>
Quarterly Results. The following table presents summarized quarterly
financial information for the years ended December 31, 1996, 1997 and for the
six months ended June 30, 1998:
<TABLE>
<CAPTION>
BASIC DILUTED
INCOME BEFORE INCOME INCOME
REVENUES INCOME TAXES NET INCOME PER SHARE(1) PER SHARE(1)
----------- ------------- ----------- ------------ ------------
<S> <C> <C> <C> <C> <C>
1996
First Quarter.................. $10,157,642 $ 4,561,523 $ 3,082,381 $ .22 $ .20
Second Quarter................. 11,462,114 5,480,944 3,678,316 .26 .24
Third Quarter.................. 14,282,064 7,178,573 4,641,953 .30 .29
Fourth Quarter................. 20,396,206 11,564,743 7,622,800 .46 .46
----------- ----------- -----------
Total................ $56,298,026 $28,785,783 $19,025,450 $1.27 $1.25
=========== =========== ===========
1997
First Quarter.................. $19,997,502 $10,161,045 $ 6,769,263 $ .41 $ .37
Second Quarter................. 15,653,078 6,007,474 4,113,689 .25 .24
Third Quarter.................. 17,895,979 7,024,524 4,685,689 .29 .27
Fourth Quarter................. 21,165,621 9,936,563 6,741,548 .41 .37
----------- ----------- -----------
Total................ $74,712,180 $33,129,606 $22,310,189 $1.35 $1.26
=========== =========== ===========
1998
First Quarter.................. $16,475,229 $ 4,835,502 $ 3,229,615 $ .20 $ .20
Second Quarter................. 16,340,730 4,270,153 2,896,470 .18 .18
----------- ----------- -----------
Total................ $32,815,959 $ 9,105,655 $ 6,126,085 $ .37 $ .37
=========== =========== ===========
</TABLE>
(1) Amounts prior to the fourth quarter of 1997 have been retroactively restated
to give recognition to: (a) an equivalent change in capital structure as a
result of a 10% stock dividend in October 1997 (see Note 2 to the Company's
financial statements); and (b) the adoption of Statement of Financial
Accounting Standards No. 128, "Earnings per Share" (see Note 2 to the
Company's financial statements).
F-22
<PAGE> 198
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Swift Energy Company as Managing General Partner:
We have audited the accompanying combined balance sheet of the Partnerships
(See Note 1) (Texas limited partnerships) as of December 31, 1997 and the
related combined statements of income, partners' capital and cash flows for the
year then ended. These combined financial statements are the responsibility of
the Partnerships' Managing General Partner. Our responsibility is to express an
opinion on these combined financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the combined financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the combined financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall combined
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the combined financial statements referred to above present
fairly, in all material respects, the financial position of the Partnerships as
of December 31, 1997, and the results of their operations and their cash flows
for the year then ended in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
Houston, Texas
April 13, 1998
F-23
<PAGE> 199
PARTNERSHIPS COMBINED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1998 1997
----------- ------------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C>
Current Assets:
Cash and cash equivalents................................. $ 6,805 $ 7,429
Accounts receivable --
Oil and gas sales...................................... 6,249 9,965
Other.................................................. 223 1,782
Other current assets...................................... 179 92
--------- ---------
Total Current Assets.............................. 13,456 19,268
--------- ---------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized...................... 329,152 328,373
Less-Accumulated depreciation, depletion, and
amortization........................................... (250,367) (239,044)
--------- ---------
78,785 89,329
--------- ---------
Total Assets...................................... $ 92,241 $ 108,597
========= =========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities:
Accounts payable.......................................... $ 1,474 $ 2,718
Other..................................................... 4,039 711
--------- ---------
Total Current Liabilities......................... 5,513 3,429
--------- ---------
Deferred Revenues........................................... 1,055 1,251
Investors' Capital.......................................... 84,280 101,783
General Partners' Capital................................... 1,393 2,134
--------- ---------
Total Liabilities and Partners' Capital........... $ 92,241 $ 108,597
========= =========
</TABLE>
See accompanying notes to Combined Financial Statements
F-24
<PAGE> 200
PARTNERSHIPS COMBINED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEAR ENDED
------------------ DECEMBER 31,
1998 1997 1997
------- ------- ------------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C>
Revenues:
Oil and gas sales......................................... $11,463 $21,743 $42,228
Interest income........................................... 201 169 330
Other..................................................... 91 144 266
------- ------- -------
11,755 22,056 42,824
------- ------- -------
Costs and Expenses:
General and administrative................................ 2,329 2,617 5,206
Depreciation, depletion, and amortization --
Normal provision....................................... 4,995 7,035 13,012
Additional provision................................... 6,328 3,664 3,845
Oil and gas production.................................... 5,144 7,170 13,774
Interest expense.......................................... 34 7 21
------- ------- -------
18,830 20,493 35,858
------- ------- -------
Net Income (Loss)................................. $(7,075) $ 1,563 $ 6,966
======= ======= =======
Investors' Net Income (Loss).............................. $(7,064) $ 761 $ 5,450
General Partners' Net Income (Loss)....................... 601 1,510 2,740
Combining Adjustment...................................... (612) (708) (1,224)
------- ------- -------
Net Income (Loss)................................. $(7,075) $ 1,563 $ 6,966
======= ======= =======
Investors' Net Income (Loss) per $100 investment.......... $ (2.13) $ 0.23 $ 1.64
======= ======= =======
</TABLE>
See accompanying notes to Combined Financial Statements
F-25
<PAGE> 201
PARTNERSHIPS COMBINED STATEMENTS OF PARTNERS' CAPITAL
<TABLE>
<CAPTION>
GENERAL COMBINING
INVESTORS PARTNERS ADJUSTMENT TOTAL
--------- -------- ---------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Balance, December 31, 1996......................... $109,589 $ 2,722 $10,125 $122,436
Net Income (Loss)................................ 5,450 2,740 (1,224) 6,966
Cash Distributions............................... (22,157) (3,328) -- (25,485)
-------- ------- ------- --------
Balance, December 31, 1997......................... 92,882 2,134 8,901 103,917
Net Income (Loss)(1)............................. (7,064) 601 (612) (7,075)
Cash Distributions(1)............................ (9,827) (1,342) -- (11,169)
-------- ------- ------- --------
Balance, June 30, 1998(1).......................... $ 75,991 $ 1,393 $ 8,289 $ 85,673
======== ======= ======= ========
</TABLE>
- ---------------
(1) Unaudited
See accompanying notes to Combined Financial Statements
F-26
<PAGE> 202
PARTNERSHIPS COMBINED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEAR ENDED
------------------ DECEMBER 31,
1998 1997 1997
------- ------- ------------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C>
Cash Flows From Operating Activities:
Net Income (Loss)......................................... $(7,075) $ 1,563 $ 6,966
Adjustments to reconcile income to net cash provided by
operations:
Depreciation, depletion, and amortization.............. 11,323 10,699 16,857
Change in gas imbalance receivable and deferred
revenues............................................. (196) (77) 123
Change in assets and liabilities:
Decrease in oil and gas sales receivable............. 5,274 2,796 774
(Increase) Decrease in other current assets.......... (86) 406 (64)
Increase (Decrease) in accounts payable.............. 2,084 (1,222) (914)
------- ------- --------
Net Cash Provided by Operating Activities......... 11,324 14,165 23,742
------- ------- --------
Cash Flows From Investing Activities:
Additions to oil and gas properties....................... (4,236) (1,923) (3,503)
Proceeds from sales of oil and gas properties............. 3,457 1,292 4,491
Decrease in receivable due to property dispositions....... -- 1,009 1,015
------- ------- --------
Net Cash (Used in) Provided by Investing
Activities...................................... (779) 378 2,003
------- ------- --------
Cash Flows From Financing Activities:
Cash distributions to partners............................ (11,169) (14,345) (25,485)
------- ------- --------
Net Cash Used in Financing Activities............. (11,169) (14,345) (25,485)
------- ------- --------
Net Increase (Decrease) In Cash and Cash Equivalents........ $ (624) $ 198 $ 260
------- ------- --------
Cash and Cash Equivalents At Beginning of Period............ 7,429 7,169 7,169
------- ------- --------
Cash and Cash Equivalents at End of Period.................. $ 6,805 $ 7,367 $ 7,429
======= ======= ========
Supplemental disclosure of cash flow information:
Cash paid during the period for interest.................. 34 7 $ 11
======= ======= ========
</TABLE>
See accompanying notes to Combined Financial Statements
F-27
<PAGE> 203
NOTES TO COMBINED FINANCIAL STATEMENTS OF THE PARTNERSHIPS
(1) BASIS OF PRESENTATION --
Swift Energy Company ("the Company") has proposed the sale of substantially
all the oil and gas assets of numerous partnerships for which it serves as
Managing General Partner and subsequent liquidation of the Partnerships ("the
Partnerships"). Upon approval of the sale of assets and liquidation, the
Partnerships' assets will consist solely of cash, which each limited partner or
interest holder in the Partnerships (the "Investors") will be entitled to
receive as a distribution. The Company is offering each Investor in the
Partnerships the opportunity to purchase shares of common stock of the Company
with all or part of the cash distribution such Investor will be entitled to
receive.
The accompanying financial statements present in the aggregate the combined
financial position, results of operations, and cash flows of the partnerships
listed below for the year ended December 31, 1997. The combined financial
statements include the Company's general partner and Investor interests. As of
December 31, 1997, the Company's share of partners' capital was $6,707,584.
Certain Partnerships' net profit ownership interests have been reclassified to
the appropriate income statement or balance sheet caption to conform with the
combined financial statement presentation.
Swift Energy Income Partners 1986-D, Ltd.
Swift Energy Income Partners 1987-A, Ltd.
Swift Energy Income Partners 1987-B, Ltd.
Swift Energy Income Partners 1987-C, Ltd.
Swift Energy Income Partners 1987-D, Ltd.
Swift Energy Income Partners 1988-A, Ltd.
Swift Energy Income Partners 1988-B, Ltd.
Swift Energy Income Partners 1988-C, Ltd.
Swift Energy Income Partners 1988-D, Ltd.
Swift Energy Income Partners 1989-A, Ltd.
Swift Energy Income Partners 1989-B, Ltd.
Swift Energy Income Partners 1989-C, Ltd.
Swift Energy Income Partners 1989-D, Ltd.
Swift Energy Income Partners 1990-A, Ltd.
Swift Energy Income Partners 1990-B, Ltd.
Swift Energy Managed Pension Assets Partnership 1988-A, Ltd.
Swift Energy Managed Pension Assets Partnership 1988-B, Ltd.
Swift Energy Managed Pension Assets Partnership 1988-C, Ltd.
Swift Energy Managed Pension Assets Partnership 1989-A, Ltd.
Swift Energy Managed Pension Assets Partnership 1989-B, Ltd.
Swift Energy Managed Pension Assets Partnership 1989-C, Ltd.
Swift Energy Managed Pension Assets Partnership 1989-D, Ltd.
Swift Energy Managed Pension Assets Partnership 1990-A, Ltd.
Swift Energy Managed Pension Assets Partnership 1990-B, Ltd.
Swift Energy Operating Partners 1991-C, Ltd.
Swift Energy Operating Partners 1992-A, Ltd.
Swift Energy Operating Partners 1992-B, Ltd.
Swift Energy Operating Partners 1992-C, Ltd.
Swift Energy Operating Partners 1992-D, Ltd.
Swift Energy Operating Partners 1993-A, Ltd.
Swift Energy Operating Partners 1993-B, Ltd.
Swift Energy Operating Partners 1993-C, Ltd.
Swift Energy Operating Partners 1993-D, Ltd.
Swift Energy Operating Partners 1994-A, Ltd.
Swift Energy Operating Partners 1994-B, Ltd.
Swift Energy Operating Partners 1994-C, Ltd.
Swift Energy Operating Partners 1994-D, Ltd.
Swift Energy Income Partners 1988-1, Ltd.
Swift Energy Income Partners 1988-2, Ltd.
Swift Energy Income Partners 1988-3, Ltd.
Swift Energy Income Partners 1989-1, Ltd.
Swift Energy Income Partners 1989-2, Ltd.
Swift Energy Income Partners 1989-3, Ltd.
Swift Energy Income Partners 1989-4, Ltd.
Swift Energy Income Partners 1990-1, Ltd.
Swift Energy Income Partners 1990-2, Ltd.
Swift Energy Pension Partners 1991-C, Ltd.
Swift Energy Pension Partners 1992-A, Ltd.
Swift Energy Pension Partners 1992-B, Ltd.
Swift Energy Pension Partners 1992-C, Ltd.
Swift Energy Pension Partners 1992-D, Ltd.
Swift Energy Pension Partners 1993-A, Ltd.
Swift Energy Pension Partners 1993-B, Ltd.
Swift Energy Pension Partners 1993-C, Ltd.
Swift Energy Pension Partners 1993-D, Ltd.
Swift Energy Pension Partners 1994-A, Ltd.
Swift Energy Pension Partners 1994-B, Ltd.
Swift Energy Pension Partners 1994-C, Ltd.
Swift Energy Pension Partners 1994-D, Ltd.
Swift Energy Managed Pension Assets Partnership 1988-1, Ltd.
Swift Energy Managed Pension Assets Partnership 1988-2, Ltd.
Swift Energy Managed Pension Assets Partnership 1989-1, Ltd.
Swift Energy Managed Pension Assets Partnership 1989-2, Ltd.
The financial statements were prepared for the purpose of complying with
Rule 3-05 of Regulation S-X of the Securities and Exchange Commission.
F-28
<PAGE> 204
NOTES TO COMBINED FINANCIAL STATEMENTS OF THE PARTNERSHIPS -- (CONTINUED)
(2) SIGNIFICANT ACCOUNTING POLICIES --
Use of Estimates --
The preparation of combined financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities at
the date of the combined financial statements and the reported amounts of
revenues, and expenses during the reporting period. Actual results could differ
from estimates.
Unaudited Interim Information --
The unaudited interim combined financial statements as of June 30, 1998 and
for each of the six month periods ended June 30, 1998 and 1997, included herein,
have been prepared pursuant to the rules and regulations of the Securities and
Exchange Commission. Accordingly, they do not include all of the information and
footnotes required by generally accepted accounting principles for complete
financial statements. In the opinion of the Managing General Partner, the
unaudited interim combined financial statements include all adjustments
(consisting only of normal recurring adjustments) necessary to present fairly
the information set forth herein. The interim financial results should not be
regarded as indicative of operating results for an entire year.
Investors' Net Income (Loss) Per $100 Investment --
The Investors' net income (loss) per $100 investment is based upon the
number of $100 investments into the combined Partnerships' Investor original
capital contributions. The per $100 investment is presented in order to achieve
a comparable measure for all Partnerships, as interests in the Partnerships were
sold on a basis of either $1.00 units, $100 units or $1,000 units.
Oil and Gas Properties --
The Partnerships account for their ownership interest in oil and gas
properties using the proportionate consolidation method, whereby the
Partnerships' share of assets, liabilities, revenues, and expenses are included
in the appropriate classification in the combined financial statements.
For financial reporting purposes, the Partnerships follow the "full-cost"
method of accounting for oil and gas property costs. Under this method of
accounting, all productive and nonproductive costs incurred in the acquisition
and development of oil and gas reserves are capitalized. Such costs include
lease acquisitions, geological and geophysical services, drilling, completion,
equipment, and certain general and administrative costs directly associated with
acquisition and development activities. General and administrative costs related
to production and general overhead are expensed as incurred. No general and
administrative costs were capitalized during the year ended December 31, 1997.
Future development, site restoration, dismantlement and abandonment costs,
net of salvage values, are estimated on a property-by-property basis based on
current economic conditions and are amortized to expense as the Partnerships'
capitalized oil and gas property costs are amortized.
The unamortized cost of oil and gas properties is limited to the "ceiling
limitation" (calculated separately for the Partnerships, Investors, and general
partners). The "ceiling limitation" is calculated on a quarterly basis and
represents the estimated future net revenues from proved properties using
current prices, discounted at ten percent. Proceeds from the sale or disposition
of oil and gas properties are treated as a reduction of oil and gas property
costs with no gains or losses being recognized except in significant
transactions.
The Partnerships compute the provision for depreciation, depletion, and
amortization of oil and gas properties on the units-of-production method. Under
this method, the provision is calculated by multiplying the total unamortized
cost of oil and gas properties, including future development, site restoration,
dismantlement and abandonment costs, by an overall amortization rate that is
determined by dividing the physical units
F-29
<PAGE> 205
NOTES TO COMBINED FINANCIAL STATEMENTS OF THE PARTNERSHIPS -- (CONTINUED)
of oil and gas produced during the period by the total estimated units of proved
oil and gas reserves at the beginning of the period.
The calculation of the "ceiling limitation" and the provision for
depreciation, depletion, and amortization is based on estimates of proved
reserves. There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production, timing, and
plan of development. The accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological interpretation and
judgment. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimate. Accordingly, reserve
estimates are often different from the quantities of oil and gas that are
ultimately recovered.
Cash and Cash Equivalents --
Highly liquid debt instruments with an initial maturity of three months or
less are considered to be cash equivalents.
(3) OIL AND GAS CAPITALIZED COSTS --
The following table sets forth capital expenditures related to the
Partnerships' oil and gas operations:
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
1997
------------
<S> <C>
Acquisition of proved properties............................ $ 49,542
Development................................................. 3,447,764
----------
$3,497,306
==========
</TABLE>
All oil and gas property acquisitions are made by the Company on behalf of
the Partnerships. The costs of the properties include the purchase price plus
any costs incurred by the Company in the evaluation and acquisition of
properties.
During 1997, the Partnerships' unamortized oil and gas property costs
exceeded the quarterly calculations of the "ceiling limitations" resulting in an
additional provision for depreciation, depletion, and amortization of
$3,845,484. In addition, the Investors' share of unamortized oil and gas
property costs exceeded their "ceiling limitation" in 1997, resulting in a
valuation allowance of $3,285,133. This amount is included in the income (loss)
attributable to the Investors shown in the statement of partners' capital
together with "combining adjustments" for the differences between the Investors'
valuation allowances and the Partnerships' full cost ceiling write down. The
"combining adjustments" change quarterly as the Partnerships' total
depreciation, depletion, and amortization provision is more or less than the
combined depreciation, depletion, and amortization provision attributable to the
general and Investors.
(4) RELATED-PARTY TRANSACTIONS --
During 1997, the Partnerships paid Swift $3,728,043 as general and
administrative overhead allowances, and $204,448 as incentive amounts.
(5) FEDERAL INCOME TAXES --
The Partnerships are not tax-paying entities. No provision is made in the
accounts of the Partnerships for federal or state income taxes, since such taxes
are liabilities of the individual partners, and the amounts thereof depend upon
their respective tax situations.
The tax returns and the amount of distributable Partnerships income are
subject to examination by the federal and state taxing authorities. If the
Partnerships' ordinary income for federal income tax purposes is
F-30
<PAGE> 206
NOTES TO COMBINED FINANCIAL STATEMENTS OF THE PARTNERSHIPS -- (CONTINUED)
ultimately changed by the taxing authorities, accordingly the tax liability of
the limited partners could be changed. Ordinary income reported on the
Partnerships' federal returns of income for the year ended December 31, 1997,
was $21,651,262. The difference between ordinary income for federal income tax
purposes reported by the Partnerships and net income or loss reported herein
primarily results from the exclusion of depletion (as described below) from
ordinary income reported in the Partnerships' federal returns of income.
For federal income tax purposes, depletion with respect to production of
oil and gas is computed separately by the partners and not by the Partnerships.
Since the amount of depletion on the production of oil and gas is not computed
at the Partnerships level, depletion is not included in the Partnerships' income
for federal income tax purposes but is charged directly to the partners' capital
accounts to the extent of the cost of the leasehold interests, and thus is
treated as a separate item on the partners' Schedule K-1. Depletion for federal
income tax purposes may vary from that computed for financial reporting purposes
in cases where a ceiling adjustment is recorded, as such amount is not
recognized for tax purposes.
(6) GAS IMBALANCES --
The Partnerships recognize their ownership interest in natural gas
production as revenue. Actual production quantities sold may be different than
the Partnerships' ownership share in a given period. If the Partnerships' sales
exceed their ownership share of production, the differences are recorded as
deferred revenue. Gas balancing receivables are recorded with the Partnerships'
ownership share of production exceeds sales.
(7) VULNERABILITY DUE TO CERTAIN CONCENTRATIONS --
The Partnerships' revenues are primarily the result of sales of their oil
and natural gas production. Market prices of oil and natural gas may fluctuate
and adversely affect operating results.
In the normal course of business, the Partnerships extend credit, primarily
in the form of monthly oil and gas sales receivables, to various companies in
the oil and gas industry which results in a concentration of credit risk. This
concentration of credit risk may be affected by changes in economic or other
conditions and may accordingly impact the Partnerships' overall credit risk.
However, the Managing General Partner believes that the risk is mitigated by the
size, reputation, and nature of the companies to which the Partnerships extend
credit. In addition, the Partnerships generally do not require collateral or
other security to support customer receivables.
(8) FAIR VALUE OF FINANCIAL INSTRUMENTS --
The Partnerships' financial instruments consist of cash and cash
equivalents and short-term receivables and payables. The carrying amounts
approximate fair value due to the highly liquid nature of the short-term
instruments.
SUPPLEMENTAL INFORMATION (UNAUDITED)
The following information presents estimates of the Partnerships' proved
oil and gas reserves, which are all located onshore in the United States. All of
the Partnerships' reserves were determined by the Managing General Partner's
personnel and audited by H.J. Gruy and Associates, Inc., independent petroleum
consultants.
F-31
<PAGE> 207
NOTES TO COMBINED FINANCIAL STATEMENTS OF THE PARTNERSHIPS -- (CONTINUED)
ESTIMATES OF PROVED RESERVES
<TABLE>
<CAPTION>
OIL AND
NATURAL GAS CONDENSATE
(MCF) (BBLS)
----------- ----------
<S> <C> <C>
Proved reserves as of December 31, 1996..................... 101,112,930 6,611,817
Revisions of previous estimates........................... (1,017,466) (206,207)
Sales of minerals in place................................ (5,896,984) (394,349)
Production................................................ (10,199,919) (747,666)
----------- ---------
Proved reserves as of December 31, 1997..................... 83,998,561 5,263,595
=========== =========
Proved developed reserves as of December 31, 1997........... 67,715,958 3,857,468
=========== =========
</TABLE>
- At December 31, 1997, the Company's general partner and Investor share of
proved reserves were 16,227,735 Mcf and 981,541 Bbls.
The pre-tax standardized measure of discounted future net cash flows
related to proved oil and gas reserves is as follows:
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, 1997
-----------------
(IN THOUSANDS)
<S> <C>
Future gross revenues....................................... $299,765
Future production costs..................................... (93,074)
Future development costs.................................... (12,949)
--------
Future net cash flows....................................... 193,742
Discount at 10% per annum................................... (85,133)
--------
Pre-tax standardized measure of discounted future net cash
flows..................................................... $108,609
========
</TABLE>
- The Partnerships are not tax-paying entities and accordingly,
standardized measure of discounted future net cash flows does not include
future income taxes. Had income taxes been considered, standardized
measure of discounted future net cash flows for the year ended December
31, 1997 would have been $85,175,294.
- The Company's general partner and Investor share of pre-tax standardized
measure of discounted future net cash flows for the year ended December
31, 1997 was approximately $18,448,873.
The pre-tax standardized measure of discounted future net cash flows from
production of proved reserves was developed as follows:
1. Estimates are made of quantities of proved reserves and the future
periods during which they are expected to be produced based on year-end
economic conditions.
2. The estimated future gross revenues of proved reserves are priced
on the basis of year-end prices, except in those instances where fixed and
determinable gas price escalations are covered by contracts limited to the
price the Partnerships reasonably expect to receive.
3. The future gross revenue streams are reduced by estimated future
costs to develop and to produce the proved reserves, as well as certain
abandonment costs based on year-end cost estimates and the estimated effect
of future income taxes.
The estimates of cash flows and reserves quantities shown above are based
on year-end oil and gas prices. The standardized measure of discounted future
net cash flows is not intended to present the fair market value of the
Partnerships' oil and gas property reserves. An estimate of fair value would
also take into account,
F-32
<PAGE> 208
NOTES TO COMBINED FINANCIAL STATEMENTS OF THE PARTNERSHIPS -- (CONTINUED)
among other things, the recovery of reserves in excess of proved reserves,
anticipated future changes in prices and costs, and allowance for return on
investment, and the risks inherent in reserve estimates.
The following are the principal sources of change in the pre-tax
standardized measure of discounted future net cash flows:
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, 1997
-----------------
(IN THOUSANDS)
<S> <C>
Pre-tax standardized measure at beginning of period......... $ 252,603
Changes resulting from:
Net change in prices and revisions of previous
estimates.............................................. (126,619)
Sales of production....................................... (28,454)
Sales of minerals in place................................ (14,181)
Accretion of discount..................................... 25,260
---------
Pre-tax standardized measure at end of period............... $ 108,609
=========
</TABLE>
F-33
<PAGE> 209
REPORT OF INDEPENDENT ACCOUNTANTS
Board of Directors
Swift Energy Company
We have audited the accompanying historical statements of revenues and
direct operating expenses of certain oil and gas properties to be acquired by
Swift Energy Company (the "Company") from Sonat Exploration Company (the "Sonat
Properties Acquisition") for the years ended December 31, 1997, 1996 and 1995.
These historical statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these historical 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 historical statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting amounts and disclosures in the historical statements. An audit also
includes assessing the accounting principles used and significant estimates made
by management, as well as evaluating the overall presentation of the historical
statements. We believe that our audits provide a reasonable basis for our
opinion.
The accompanying historical statements were prepared as described in Note 1
for the purpose of complying with the rules and regulations of the Securities
and Exchange Commission and is not intended to be a complete presentation of the
revenues and direct operating expenses of the Sonat Properties Acquisition.
In our opinion, the historical statements referred to above present fairly,
in all material respects, the revenues and direct operating expenses of the
Sonat Properties Acquisition for the years ended December 31, 1997, 1996 and
1995 in conformity with generally accepted accounting principles.
Ernst & Young LLP
July 28, 1998
F-34
<PAGE> 210
SONAT PROPERTIES ACQUISITION
HISTORICAL STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEAR ENDED DECEMBER 31,
--------------------- ---------------------------
1998 1997 1997 1996 1995
----------- ------- ------- ------- -------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and condensate....................... $17,831 $13,819 $34,294 $42,935 $22,125
Gas...................................... 9,367 9,074 20,003 24,483 17,381
Plant products........................... 5,727 5,425 10,575 16,007 4,595
------- ------- ------- ------- -------
32,925 28,318 64,872 83,425 44,101
Direct operating expenses.................. 5,744 5,217 11,322 9,800 8,153
------- ------- ------- ------- -------
Revenues in excess of direct operating
expenses................................. $27,181 $23,101 $53,550 $73,625 $35,948
======= ======= ======= ======= =======
</TABLE>
See accompanying notes.
F-35
<PAGE> 211
SONAT PROPERTIES ACQUISITION
NOTES TO HISTORICAL STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES
1. BASIS OF PRESENTATION
On July 2, 1998, Swift Energy Company (the "Company") signed an agreement
dated June 1, 1998 to acquire from Sonat Exploration Company ("Sonat
Exploration"), effective April 1, 1998, certain oil and gas properties located
in the Texas and Louisiana Austin Chalk trend (the "Sonat Properties
Acquisition") for approximately $87.6 million. The acquisition is expected to
close in August 1998.
The revenues and direct operating expenses associated with the Sonat
Properties Acquisition were derived from Sonat Exploration's accounting records.
Revenues and direct operating expenses, as set forth in the accompanying
historical statements, include oil, gas, and plant product revenues and
associated direct operating expenses related to the net revenue interest (and
acquired royalty interest, as applicable) and net working interest,
respectively, in the acquired properties. Each owner recognizes revenue and
expenses based on its proportionate share of the related production and costs.
The historical statements include oil, gas, and plant product revenues net of
royalties and applicable transportation costs. Expenses include labor, services,
repairs and maintenance, and supplies utilized to operate and maintain the wells
and related equipment as well as severance and ad valorem taxes.
The accompanying historical statements vary from an income statement in
that they do not show certain expenses which were incurred in connection with
ownership of the acquired properties including general and administrative
expenses and income taxes. These costs were not separately allocated to the
acquired properties in Sonat Exploration's accounting records and any pro forma
allocation would be both time consuming and expensive and would not be a
reliable estimate of what these costs would actually have been had the acquired
properties been operated historically as a stand alone entity. In addition,
these allocations, if made using historical general and administrative
structures and tax burdens, would not produce allocations that would be
indicative of the historical performance of the acquired properties had they
been assets of the Company due to the greatly varying size, structure,
operations and accounting of the two companies. The accompanying historical
statements also do not include provisions for depreciation, depletion and
amortization as such amounts would not be indicative of those costs which would
be incurred by the Company upon allocation of the purchase price.
For the same reason, primarily the lack of segregated or easily obtainable
reliable data on asset values and related liabilities, a balance sheet is not
presented for the Sonat Properties Acquisition.
At the end of the economic life of these fields, certain restoration and
abandonment costs will be incurred by the respective owners of these fields. No
accrual for these costs is included in direct operating expenses.
With respect to gas sales, the entitlement method is used for recording
revenues. Under this approach, revenues are based on the acquired properties'
proportionate share of the related production.
The interim financial data for the six months ended June 30, 1998 and 1997
is unaudited; however, in the opinion of the Company, the interim data includes
all adjustments, consisting only of normal recurring adjustments, necessary for
a fair statement of the results for the interim periods.
2. RELATED PARTY TRANSACTIONS
Affiliates of Sonat Exploration acquired substantially all of the natural
gas production from the acquired properties during each of the three years ended
December 31, 1997. Such sales, attributable to the net revenue interest (and
acquired royalty interest, as applicable) of the acquired properties, amounted
to $20,003,000, $24,483,000 and $17,381,000 for the years ended December 31,
1997, 1996 and 1995, respectively.
F-36
<PAGE> 212
SONAT PROPERTIES ACQUISITION
NOTES TO HISTORICAL STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES -- (CONTINUED)
3. SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)
Proved Reserve Estimates
Oil and gas proved reserves cannot be measured exactly. Reserve estimates
are based on many factors related to reservoir performance which require
evaluations by the engineers interpreting the available data, as well as price
and other economic factors. The reliability of these estimates at any point in
time depends on both the quality and quantity of the technical and economic
data, the production performance of the reservoirs, as well as extensive
engineering judgment. Consequently, reserve estimates are subject to revision as
additional data becomes available during the producing life of a reservoir. When
a commercial reservoir is discovered, proved reserves are initially determined
based on limited data from the first well or wells. Subsequent data may better
define the extent of the reservoir and additional production performance, well
tests and engineering studies will likely improve the reliability of the reserve
estimate. The evolution of technology may also result in the application of
improved recovery techniques such as supplemental or enhanced recovery projects,
or both, which have the potential to increase reserves beyond those envisioned
during the early years of a reservoir's producing life.
Proved reserves are those quantities which, upon analysis of geological and
engineering data, appear with reasonable certainty to be recoverable in the
future from known oil and gas reservoirs under current prices and costs as of
the date the estimate is made. Proved undeveloped reserves are those 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. Proved
reserves represent the estimated recoverable volumes after deducting from gross
reserves the portion due land owners or others as royalty or operating
interests.
Estimates of proved reserves include and rely upon a production and
development strategy. The Company's estimates, as determined by in-house
reservoir engineers, are based upon plans developed using current information
and reflect the Company's risk tolerance with respect to developing proved
undeveloped reserves. Such reserves typically involve a higher degree of
uncertainty. As a result, the Company's estimates may not be comparable to other
oil and gas producers. In any case, many factors such as changes in prices or
costs or errors in sound technical judgment made on the best information
available may cause actual production to vary significantly from estimated
reserves. Estimates of proved reserves for prior periods reflect the Company's
estimate of proved reserves as determined retrospectively using current
information.
F-37
<PAGE> 213
SONAT PROPERTIES ACQUISITION
NOTES TO HISTORICAL STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES -- (CONTINUED)
Estimated quantities of proved and proved developed oil and gas reserves
and of changes in quantities of proved reserves for each of the periods
indicated were as follows:
<TABLE>
<CAPTION>
OIL GAS
(MBBLS) (MMCF)
------- -------
<S> <C> <C>
Proved reserves at December 31, 1994........................ 4,092 43,529
Production................................................ (1,341) (11,954)
Extensions, discoveries and improved recovery............. 2,777 15,058
Revisions of previous estimates........................... 580 5,748
------ -------
Proved reserves at December 31, 1995........................ 6,108 52,381
Production................................................ (2,159) (13,236)
Extensions, discoveries and improved recovery............. 2,846 13,179
Revisions of previous estimates........................... 1,369 10,100
------ -------
Proved reserves at December 31, 1996........................ 8,164 62,424
Production................................................ (1,890) (12,184)
Extensions, discoveries and improved recovery............. 866 3,831
Revisions of previous estimates........................... 530 (388)
------ -------
Proved reserves at December 31, 1997........................ 7,670 53,683
====== =======
Proved developed reserves at:
December 31, 1995......................................... 1,913 21,672
December 31, 1996......................................... 3,119 30,492
December 31, 1997......................................... 4,218 31,163
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows
The following disclosures concerning the standardized measure of discounted
future cash flows from proved oil and gas reserves are presented in accordance
with the Statement of Financial Accounting Standards No. 69 ("SFAS 69"). As
prescribed by SFAS 69, the amounts shown are based on prices and costs at the
end of each period and a 10 percent annual discount factor. Since prices and
costs do not remain static, and no price or cost changes have been considered,
the results are not necessarily indicative of the fair market value of the
estimated proved reserves, but they do provide a common benchmark which may
enhance the user's ability to project future cash flows.
The standardized measure of discounted future net cash flows related to
proved oil and gas reserves at December 31 was as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Future cash flows...................................... $269,958 $462,431 $220,903
Future production costs................................ (60,648) (74,200) (53,350)
Future development costs............................... (41,069) (59,680) (53,672)
-------- -------- --------
Future net cash inflows................................ 168,241 328,551 113,881
10% annual discount for estimated timing of cash
flows................................................ (30,283) (78,852) (22,776)
-------- -------- --------
Standardized measure of discounted future net cash
flows (before income taxes).......................... $137,958 $249,699 $ 91,105
======== ======== ========
</TABLE>
F-38
<PAGE> 214
SONAT PROPERTIES ACQUISITION
NOTES TO HISTORICAL STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES -- (CONTINUED)
The standardized measure of discounted future net cash flows is based on
the following oil and gas prices at December 31:
<TABLE>
<CAPTION>
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
Oil (per Bbl)............................................... $16.30 $23.00 $17.30
Gas (per Mcf)............................................... $ 2.70 $ 4.40 $ 2.20
</TABLE>
The principal sources of changes in the standardized measure for the years
ended December 31 were as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
--------- -------- --------
<S> <C> <C> <C>
Balance at beginning of the year...................... $ 249,699 $ 91,105 $ 52,495
Sales and transfers of oil and gas produced, net
of production costs................................. (53,550) (73,625) (35,948)
Net change in prices and costs........................ (112,881) 134,259 18,874
Extensions, discoveries and improved recovery......... 6,433 21,554 24,105
Development costs incurred during the year............ 27,187 22,731 13,388
Revisions of quantity estimates....................... 4,494 59,721 13,822
Accretion of discount................................. 24,970 9,111 5,249
Changes in production rates (timing) and other........ (8,394) (15,157) (880)
--------- -------- --------
Balance at the end of the year........................ $ 137,958 $249,699 $ 91,105
========= ======== ========
</TABLE>
F-39
<PAGE> 215
SWIFT ENERGY MANAGED PENSION ASSETS PARTNERSHIP 1988-A, LTD.
(THE "PARTNERSHIP")
SUPPLEMENT
TO
JOINT PROXY STATEMENT/PROSPECTUS
DATED ___________, 1998
SPECIAL MEETINGS OF THE PARTNERSHIPS
AND
OFFERING OF COMMON STOCK OF
SWIFT ENERGY COMPANY
For the definition of capitalized terms herein which are not otherwise
defined, see "Glossary" in the Joint Proxy Statement/Prospectus. Other
discussions which are cross-referenced in this Supplement are contained in the
Joint Proxy Statement/Prospectus, unless otherwise noted.
Swift Energy Company ("Swift" or the "Company") is the Managing
General Partner ("Managing General Partner") of 63 Texas limited partnerships
(the "Partnerships"), including the Partnership, formed between 1986 and 1994
to invest in producing oil and gas properties. Swift is asking limited
partners (referred to herein as "Investors") in the Partnership (and similarly
in the other 62 Partnerships) to approve a Proposal to ultimately sell all of
the Partnership's oil and gas assets to the Managing General Partner (the
"Proposal") for $373,244, which is a purchase price derived by choosing the
higher of two estimates of fair market value of those assets determined by
three independent Appraisers, and adding to that higher number a 7.5% premium.
If the Proposal is approved by Investors in the Partnership and its
Companion Partnership, after the ultimate sale of all of its oil and gas assets
the Partnership will dissolve, wind up and terminate. The Partnership will
receive cash for its oil and gas assets, which in turn is to be distributed to
the Investors in the Partnership (along with the net of all assets less
liabilities of the Partnership) in accordance with their respective percentage
ownership interests in the Partnership. If Investors in the Partnership
approve the Proposal, then each Investor can elect, in their sole individual
discretion, to receive shares of Common Stock of the Company (without payment
of any brokerage commissions) instead of some or all of the cash which they are
entitled to receive upon the Partnership's liquidation.
The reasons for and effects of the Proposals may be different for
investors in each of the Partnerships. This Supplement has been prepared to
highlight for the Investors in the Partnership the particular risks, effects
and fairness of the Proposal to the Investors in the Partnership and to provide
information on the Partnership to its Investors, in connection with the
solicitation of proxies by the
<PAGE> 216
Managing General Partner for use at the Special Meeting of the Investors in the
Partnership in voting upon the Proposal and to transact such other business as
may be properly presented at the Special Meeting or any adjournments or
postponements thereof.
BOTH THE VOTE UPON THE PROPOSAL AND ANY ELECTION MADE BY AN INDIVIDUAL
INVESTOR TO RECEIVE SHARES OF SWIFT ENERGY COMPANY COMMON STOCK ARE SUBJECT TO
NUMEROUS RISK FACTORS, INCLUDING THOSE HIGHLIGHTED BELOW. SEE "RISK FACTORS"
IN THIS SUPPLEMENT AND IN THE JOINT PROXY STATEMENT/PROSPECTUS FOR A FULL
DISCUSSION OF ALL RISK FACTORS.
o Substantial conflicts of interest exist because if the Proposal is
approved by the Partnership and its Companion Partnership, the
Managing General Partner will purchase all of the oil and gas assets
from the Partnership while it serves as its Managing General Partner.
o The purchase price for the Partnership's Property Interests may not be
the highest possible price.
o No independent representative negotiated the terms of the purchase
price with the Managing General Partner.
o No fairness opinion was acquired regarding the fairness of the
purchase price.
o The Managing General Partner may profit from acquisition of the
Partnership's oil and gas assets by investing capital in order to
develop non-producing reserves of the acquired Property Interests and
possibly through improvement in oil and gas prices.
o Estimates of distributions to Investors from continuing operations of
the Partnership for the life of its reserves are higher than amounts
anticipated to be received if Investors vote in favor of the Proposal.
See "Special Factors--Fairness of Proposal of Sale of Assets as
Compare to Continuing Operations."
o An election by an Investor to receive shares of Swift Common Stock in
lieu of cash distributable to Investors subjects such Investors to the
risks of investing in the Company.
This Supplement is dated ______________, 1998
2
<PAGE> 217
THE PARTNERSHIP
The Partnership was formed over ten years ago and owns non-operating
Property Interests in producing oil and gas properties in five states in which
its companion partnership, Swift Energy Income Partners 1988-B, Ltd.
("Companion Partnership"), formed at approximately the same time and also
managed by the Managing General Partner, owns the working interests. The
Partnership had expended all of its original capital contributions by the end
of February 1989. The Partnership's oil and gas properties are principally
natural gas properties, representing approximately 93% of the Partnership's
1997 production and approximately 92% of its total proved reserves at December
31, 1997. The Companion Partnership has, from time to time, performed
workovers and recompletions on wells in which the Partnership has Property
Interests, using funds advanced by the Managing General Partner or third
parties, to perform these operations, which amounts have been subsequently
repaid. The Partnership owns interest in 200 wells in 14 fields.
The following table presents information on those fields in which the
Partnership has Property Interests which constitute 10% or more of the
Partnership's PV-10 Value at December 31, 1997. The Partnership's "PV-10
Value" is the estimated future net cash flows (using unescalated prices) from
production of proved reserves attributed to the Partnership's Property
Interests, discounted to present value at 10% per annum. Attachment D to this
Supplement is the report dated February 10, 1998 of the audit by H.J. Gruy and
Associates, Inc., Independent Petroleum Consultants, of the oil and gas
reserves underlying the Partnership's Property Interests, and future net cash
flow expected from the production of those reserves as of December 31, 1997,
presented both for the Partnership as a whole and as to those reserves solely
attributable to the Investors in the Partnership. This report has not been
updated to include the effect of production since year-end 1997. In estimating
these reserves, the Managing General Partner, in accordance with criteria
prescribed by the Securities and Exchange Commission, has used year-end 1997
prices, without escalation, except in those instances where fixed and
determinable gas price escalations are covered by contracts, limited to the
price the Partnership reasonably expects to receive. The Managing General
Partner is not aware of any favorable or adverse event causing a significant
change in the estimated amount (as set forth in Attachment D hereto, which is
the report of H.J. Gruy and Associates, Inc.) of proved reserves of the
properties in which the Partnership owns an interest between December 31, 1997
and the date of this Supplement.
The information below includes the location of each field in which the
Partnership has an interest, the number of wells and operators, together with
information on the percentage of the Partnership's total PV-10 Value on
December 31, 1997 attributable to each of these fields. Information is also
provided regarding the percentage of the Partnership's 1997 production (on a
volumetric basis) from each of these fields. Of the remaining other fields in
which the Partnership owns a Property Interest, four of such fields each
comprise less than 1% of the Partnership's PV-10 Value at December 31, 1997,
and the PV-10 Value of each of the other six fields averages less than 5% of
the Partnership's PV-10 Value at the same date.
3
<PAGE> 218
<TABLE>
<CAPTION>
North 10
Ulrich Grapeland Reydon Tuttle Other
Field Field Field Field Fields
--------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Harris Houston Roger Canadian AR(1)
County and State County, County, Mills County, LA(1)
Texas Texas County, OK MS(1)
OK OK(5)
TX(2)
Number of Wells 5 6 1 3 185
Marquee Fair Oil Apache Apache 11 others
Corp.;
Operator(s) Columbus
Energy
% of 12/31/97 PV-10 Value 21% 21% 19% 11% 28%
% of 1997 Production Volumes 20% 21% 20% 7% 32%
</TABLE>
The Partnership's total assets at year-end 1997 were $480,570 and the
PV-10 Value of its total proved reserves at the same date was $484,518. Based
upon the audit of the Partnership's Total Proved Reserves at year-end 1997,
those reserves were comprised of the following three categories:
<TABLE>
<S> <C>
Proved Producing1 66%
Behind-Pipe2 33%
Non-Developed3 1%
---
100%
===
</TABLE>
- ----------------
(1) Proved producing reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
(2) Behind-pipe reserves are proved reserves that will not contribute
to cash flows until recompletion projects have been implemented to place them
into production. The impact of these recompletion projects will also be limited
until the costs of implementation have been recovered. In general, it is not
appropriate to bring behind-pipe reserves into production until the formation
that is currently producing has been depleted. Premature recompletions can lead
to permanent reductions in a well's proved reserves.
(3) Non-developed reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Therefore,
significant additional expenditures are usually required before undeveloped
reserves can be produced.
Attachment Dis the annual reserves audit and independent reserves
report prepared by H.J. Gruy and Associates, Inc. as to the Partnership's
remaining proved oil and gas reserves available for production over a period in
excess of 15 years. These quantities have been given a value based upon prices
for oil and gas at December 31, 1997. The value is determined based upon the
assumption that these prices will remain in effect over the life of these
reserves. This value is then discounted at 10% per year to arrive at the value
(in today's dollars) of these revenues ("PV-10 Value"). This PV-10 Value for
the Partnership's Property Interests is $484,518. It is also estimated that
$13,325 in future capital costs must be spent to
4
<PAGE> 219
develop the Partnership's non-producing reserves. The small amount of these
future development costs reflects the very small percentage of the
Partnership's proved reserves which require drilling to be produced.
RISK FACTORS
o Although the fair market value of the Property Interests proposed to
be purchased from the Partnership by the Managing General Partner was
based upon a determination by three independent Appraisers, no opinion
was acquired as to the fairness of the ultimate purchase price, which
was determined in the Managing General Partner's sole judgment by
adding a 7.5% premium over the higher of the two fair market value
estimates for the Partnership's Property Interests determined by the
Appraisers. Therefore, the purchase price was not determined on an
impartial basis by a party not involved in the transaction, and
another party intent upon purchasing the Property Interests in the
Partnership might have offered a different purchase price. There is
no guarantee that the purchase price represents the highest possible
price that could be received for the Partnership's Property Interests
in all circumstances. It is possible that a higher (or lower) price
might be received if these assets were sold on another basis, such as
at auction or in negotiated sales. Furthermore, the assessment of the
value of the Partnership's proved non-producing reserves could vary
widely, given the typical discounting in valuing non-producing
reserves.
o The Managing General Partner did not retain an independent
representative to act on behalf of the Investors in the Partnership in
structuring and negotiating the terms or price of the Proposal or the
purchase price. The price at which it is proposed that the Company
purchase the Property Interests from the Partnership has not been
negotiated at arm's length and is subject to significant conflicts of
interest between the Company acting as the purchaser of such
properties while serving as the Managing General Partner of the
Partnership. If an independent representative had been retained for
the Partnership, the terms or price might have been different and
possibly more favorable to Investors.
o The fair market value (excluding the 7.5% premium) established for the
Partnership's Property Interests is based upon the Appraisers'
evaluation of that value. Year-end 1997 prices, along with other
current market factors, were used as a starting point for the
Appraisers' analysis, and prices and costs were then escalated at a
rate of 3.5% per year over 15 years. Substantial increases in the
prices for oil and gas in the future might result in Investors
receiving higher distributions from continued operations of the
Partnership, although the effect of any higher prices is somewhat
limited because the Partnership has already produced a substantial
majority of its oil and gas reserves.
o In order to effectuate the sale of its Property Interests, the
Proposal must not only be approved by the Partnership, but a similar
Proposal must be approved by the Companion Partnership. This
requirement exists because of the significant lowering of the value of
either (i) a working interest burdened by a large non- operating
interest controlled by a different party, or (ii) a non-operating
interest in properties the operations of which are controlled by a
third party. Therefore, even if the Investors in the Partnership
approve the Proposal to sell their Property Interests, this may not be
done without the approval of a similar Proposal by investors in the
Companion Partnership. If either Partnership does not approve its
Proposal, then the Managing General Partner will reassess the value of
the Property Interests of each Partnership and attempt to formulate a
new proposal for the investors in each such Partnership.
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<PAGE> 220
o Investors that are subject to federal income tax on an investment in
the Partnership are required to recognize gain or loss on the sale of
oil and gas assets by the Partnership and the subsequent liquidation
of the Partnership. The character of the gain or loss depends on
certain factors specific to individual Investors. It is anticipated
that Investors that acquired their interests in the original offering
and that are subject to federal income tax will recognize a loss for
federal income tax purposes. Any tax that may be due must be paid
even if such Investors choose to acquire Company Common Stock with
some or all of their proceeds from property sales. Investors also
should consult their individual tax advisors to determine whether they
are subject to any state tax. For a broader discussion of the tax
consequences, Investors should read "Federal Income Tax Consequences
of Adoption of the Proposals" in the Joint Proxy Statement/Prospectus,
and "Summary of Federal Income Tax Consequences" in this Supplement.
o Investors that are Tax Exempt Plans that have directly or indirectly
acquired their Partnership interests through debt financing, as
defined in the Internal Revenue Code of 1986, as amended, may be
subject to taxation on the Partnership's sale of property and the
liquidation of the Partnership, while other Tax Exempt Plans are not
expected to be subject to taxation on the sale and liquidation. See
"Federal Income Tax Consequences of Adoption of the Proposal--Tax
Treatment of Tax Exempt Plans--Debt-Financed Property" in this
Supplement. It is anticipated that Tax Exempt Plans that acquired
their interests in the original offering and that are subject to
federal income tax will recognize a loss for federal income tax
purposes.
o As currently proposed, Investors that subscribe for Company Common
Stock pursuant to this Offering may not receive some or all of the
cash which otherwise would be distributed to them as part of the
liquidating distribution of their Partnership. The amount of any cash
liquidating distribution they actually receive depends upon the
purchase price to be paid for any Company Common Stock they elect to
and are entitled to receive pursuant to the terms of this Offering.
For federal income tax purposes, Investors subscribing for shares of
Company Common Stock will be treated as though they had purchased
those shares for cash, even though they never had actual possession of
the cash used to acquire the shares. Additionally, the fact that such
Investors elect to acquire Company Common Stock rather than receive
cash in liquidation of their Partnership interests will not affect the
federal income tax consequences attending the liquidation of their
Partnership interests. Because the purchase of shares of Company
Common Stock will reduce the cash received by Investors upon the
Partnership's liquidation, to the extent that Investors owe federal
income tax as a result of the liquidation, they may not receive
sufficient cash to pay some or all of any tax they may owe on the
liquidation. Such Investors owing tax as a result of the liquidation
will have to pay such tax from sources other than any cash liquidating
distribution from the Partnership.
See "Risk Factors" in the Joint Proxy Statement/Prospectus.
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<PAGE> 221
CONFLICTS OF INTEREST
There are substantial conflicts of interest which exist by virtue of
the Managing General Partner acting in that capacity on behalf of the
Partnership while at the same time acting as the proposed purchaser of all of
the oil and gas assets of the Partnership. These conflicts of interest are
discussed below.
o The terms of the Proposal are established by the Company which is also
the Managing General Partner of the Partnership.
o Neither the Managing General Partner nor a majority of its independent
directors retained an independent representative to act on behalf of
the Partnership's Investors for the purposes of negotiating the terms
upon which any such sale to the Managing General Partner would be made
or for the preparation of a report concerning the fairness of the
entire transaction.
See "Summary--Conflicts of Interest" and "Conflicts of Interests" in the Joint
Proxy Statement/Prospectus.
SPECIAL FACTORS
BACKGROUND AND PURPOSE OF THE PROPOSAL
[VARIABLE PARA. BY P'SHIP TYPE] A number of factors have led to the
decision of the Company in its capacity as Managing General Partner to solicit
approval of the Proposal by Investors in the Partnership. As contemplated when
the Partnership was organized, and given the expenditure of virtually all of
the Partnership's capital to purchase producing properties over nine years ago,
the production from Partnership oil and gas assets declined over time. It was
always anticipated that a time would arrive when the Managing General Partner
would propose that the business of the Partnership be concluded, its assets
sold or otherwise disposed of and the Partnership liquidated and dissolved.
The general improvement in the prices for natural gas over the last several
years, relative to such prices in the mid-1990's, make this an appropriate
time, especially in light of the age of the Partnership and the high percentage
of its reserves comprised of natural gas, to consider the Proposal to sell the
Partnership's Property Interests. The structure being proposed, which involves
the sale of the Partnership's oil and gas assets to the Managing General
Partner, is being submitted for approval by Investors in an attempt to realize
the highest value for those assets. For the reasons set out below, the
Managing General Partner believes that the Proposal is fair to Investors in the
Partnership, given that the purchase price for these assets has been determined
by taking the higher of two fair market value estimates by three independent
Appraisers and adding to it a 7.5% premium.
Approval of the Proposal will have the following effects:
1. The Managing General Partner will purchase all of the oil and gas
assets of the Partnership, provided its Companion Partnership has
approved its proposal.
2. When the Partnership sells all of its oil and gas assets, it will be
required to liquidate and distribute its remaining assets (principally
the cash proceeds from the sale) to its partners (including the
general partners) in accordance with their respective ownership
interests in the Partnership.
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<PAGE> 222
3. Investors will be given the option of electing to receive shares of
Swift Common Stock, in amounts that they choose on an individual
basis, in lieu of some or all of the cash they would be entitled to
receive upon the Partnership's liquidation.
4. Investors in the Partnership may be taxed on the sale of the
Partnership's oil and gas assets, although such sale is expected to
result in a taxable loss to Investors that acquired their interests in
the original offering.
PROPOSED PURCHASE PRICE
As discussed in greater detail below, the Petroleum Engineering
Consultants estimated that the aggregate fair market value of the Partnership's
Property Interests as of December 31, 1997 is $342,030. CIBC Oppenheimer
estimated a fair market value of the same Property Interests at the same date
of $347,204. The Special Transactions Committee chose the higher of these two
determinations as the "Fair Market Value" for the purchase of these interests
and the Board of Directors of the Company determined to pay a 7.5% premium
($26,040) above the Fair Market Value to purchase the Partnership's Property
Interests, resulting in a purchase price of $373,244. This compares to the
total purchase price for all of the oil and gas assets of all 63 Partnerships
which are considering similar proposals of approximately $81 million. The
valuation estimates of the Appraisers are attached to this Supplement and
incorporated herein by reference as follows: Attachment A is the fair market
value estimate of H.J. Gruy and Associates, Inc., Attachment B is the fair
market value estimate of J.R. Butler and Company, and Attachment C is the fair
market value estimate of CIBC Oppenheimer Corp. The PV-10 Value prepared on an
annual basis by H.J. Gruy of the same Property Interests as of the same date is
$484,518.
REASONS FOR THE PROPOSAL
The Managing General Partner believes that it is in the best interest
of the Investors for the Partnership to sell its Property Interests at this
time and to dissolve the Partnership and make a final liquidating distribution
to its partners for the reasons discussed below.
Current Liquidating Distribution Lowers Volatility Risk. The
Partnership has been in existence for over ten years. The Managing General
Partner believes that the ability to receive the estimated liquidating
distribution in one lump sum at this time, rather than in smaller amounts over
a longer period, is one of the benefits of the Proposal, without the risk of
such distributions being negatively affected by oil and gas price decreases and
the inherent risks associated with geological, engineering and operational
matters. It is also the Managing General Partner's belief that improvements
over the last several years in the level of gas prices, relative to such prices
in the mid-1990's, makes this an appropriate time to consider the sale of the
Partnership's Property Interests and increase the likelihood of maximizing the
value of the Partnership's assets, although future prices and market volatility
cannot be predicted with any accuracy.
Decreasing Cash Flow While Expenses Continue. As of December 31,
1997, approximately 83% of the Partnership's ultimate recoverable reserves had
been produced. As a result of such depletion of the Partnership's oil and gas
reserves, the Managing General Partner believes the Partnership's asset base
and future net revenues no longer justify the continuation of operations. The
Partnership's underlying interests in oil and gas reserves are expected to
continue to decline as remaining reserves are produced. Declines in well
production are based principally upon the maturity of the wells, not on market
factors. These declines will continue to occur while oil field overhead and
operating costs ($9,090 in 1997) and direct and
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<PAGE> 223
general and administrative expenses ($34,649 in 1997) continue, which are
relatively fixed amounts. Each producing well requires a certain amount of
operating and other costs, which are incurred regardless of the level of
production. Likewise, direct costs and/or general and administrative expenses,
such as compliance with the securities laws, producing reports to partners and
filing partnership tax returns, do not decline as revenues decline. By
accelerating the liquidation of the Partnership, those future administrative
costs will be avoided by the Partnership.
Effect of Gas Prices on Value. The Managing General Partner believes
that the key factor affecting the Partnership's long-term performance has been
the decrease in oil and particularly gas prices that occurred subsequent to the
purchase of the Partnership's Property Interests. Additionally, prices are
expected to continue to vary widely over the remaining life of the Partnership,
and such changes in gas prices will affect future estimates of revenues from
continued operations of the Partnership. Based on 1997 year-end reserve
calculations, the Partnership had only about 17% of its ultimate recoverable
reserves remaining for future production. Because of this small amount of
remaining reserves, even if oil and gas prices were to increase in the future,
such increases would be unlikely to have a material positive impact on the
total return on investment to Investors in view of the expenses of the
Partnership as described above. Approximately 93% of the Partnership's 1997
production and approximately 92% of its total proved reserves at year-end 1997
were comprised of natural gas. As of the summer of 1998, oil prices are
significantly lower than those for natural gas. Historically when there has
been significant difference between the price of gas and oil, those prices have
adjusted to become reasonably equivalent. Consequently, there may be a benefit
in selling the Partnership's Property Interests at this time and avoiding any
future decreases in prices of natural gas, although the direction and severity
of adjustments in prices for gas and/or oil are impossible to predict.
Behind-Pipe Reserves. It is estimated that approximately 33% of the
remaining reserves attributable to properties in which the Partnership has an
interest are behind-pipe reserves, which are unlikely to be producible for many
years because behind-pipe reserves always require completion of a well in a
different producing zone which does not take place until production is depleted
from the currently producing zones. Recovery in amounts great enough to
significantly impact the results of the Partnership's operations and the
ultimate cash distributions to partners can only occur with the investment of
new capital. As provided in its Partnership Agreement, the Partnership
expended all of the Investors' net commitments for the acquisition of Property
Interests many years ago and it no longer has capital to invest. No additional
development activities are contemplated by the Companion Partnership on the
properties in which the Partnership has an interest.
Limited Partners' Tax Reporting. Each Investor will continue to have
an income tax reporting obligation with respect to his Units as long as the
Partnership continues to exist. There is no trading market for the Units, so
Investors generally are unable to dispose of their Units. See "Partnership
Business and Financial Condition--No Trading Market" in this Supplement.
Following the sale of the Partnership's Property Interests and dissolution of
the Partnership, Investors will realize gain or loss, or a combination of both,
under federal income tax laws. See "Summary of Federal Income Tax
Consequences--Taxable Gain or Loss upon Sale of Properties" herein.
Thereafter, Investors will have no further tax reporting obligations with
respect to the Partnership. The dissolution of the Partnership will also allow
Investors to take a capital loss deduction for syndication costs incurred in
connection with formation of the Partnership. See "Summary of Federal Income
Tax Consequences--Liquidation of the Partnership" in this Supplement.
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<PAGE> 224
See "Summary--Background and Reasons for the Proposals," "--Purpose and Effect
of the Proposals," "--Reasons for the Proposals" and "--Managing General
Partner's Recommendations" in the Joint Proxy Statement/Prospectus.
COLLECTIVE ANALYSIS OF PURCHASE PRICE; PREMIUM OVER FAIR MARKET VALUE
The Special Transactions Committee selected H.J. Gruy and Associates,
Inc. ("H.J. Gruy" or "Gruy"), J.R. Butler and Company ("J.R. Butler" or
"Butler"), which are both petroleum engineering consultants, and CIBC
Oppenheimer Corp. ("CIBC Oppenheimer"), an investment banking firm, to
estimate the fair market value of the Property Interests of each of the
Partnerships. Collectively, H.J. Gruy, J.R. Butler and CIBC Oppenheimer are
referred to herein as the "Appraisers," and H.J. Gruy and J.R. Butler together
are sometimes referred to herein as the "Petroleum Engineering Consultants."
The following subsections of the "Special Factors" section of the
Joint Proxy Statement/Prospectus should be reviewed for information concerning
the selection and qualification of the Appraisers and the parameters of the
valuation estimates: "Independent Appraisal of the Fair Market Value of
Property Interests of the Partnerships," "Qualification of Appraisers," and
"Fair Market Value."
The Petroleum Engineering Consultants arrived at a fair market
valuation estimate of the Partnership's Property Interests based upon appraisal
of the projected discounted cash flow from its various Property Interests. On
the other hand, the investment banking firm of CIBC Oppenheimer made a
valuation estimate of the Partnership's Property Interests based upon the
application of multiple quantitative and qualitative factors. The quantitative
factors include, among other things, a review of relevant valuation criteria
from comparable acquisitions of both oil and gas properties and companies that
are predominantly active in the oil and gas industry, and a review of valuation
criteria for relevant publicly traded oil and gas companies.
The process used by the Petroleum Engineering Consultants in preparing
their valuation estimate is discussed at length in the Joint Proxy
Statement/Prospectus under "Special Factors--Valuation by Petroleum Engineering
Consultants." As described therein, the Petroleum Engineering Consultants
individually audited the estimate of present value of future net cash flows
from the 44 property groups in which Property Interests are owned by the
Partnerships to whom similar proposals are being made to sell all of their oil
and gas assets and liquidate their Partnerships. The Partnership owns Property
Interests in four of these property groups. The Petroleum Engineering
Consultants began their analysis based upon the year-end 1997 PV-10 Value of
each property audited by H.J. Gruy and together they re-evaluated reserve
quantities, projected operating costs and cash flows. The present value of
this reserves analysis was then derived by escalating year-end 1997 prices
($2.38 per MMBtu and $16.00 per barrel before adjustments for Btu content for
gas and gravity variances for oil as well as transportation charges and
geographic location) and costs by 3.5% per year for 15 years. This present
value was then adjusted for various individual field risks and risk adjustments
of proved non-producing reserves and proved undeveloped reserves. The result
of this collective analysis by the Petroleum Consulting Engineers was their
estimation that the fair market value of Property Interests owned by the
Partnership was $342,030 as of December 31, 1997.
The methodology used by CIBC Oppenheimer to prepare its valuation
estimate is discussed at length under "Special Factors--Valuation by CIBC
Oppenheimer" in the Joint Proxy Statement/Prospectus. CIBC Oppenheimer's
evaluation of the Partnership's Property Interests began with
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<PAGE> 225
the PV-10 Value of each property group, as calculated by Swift and audited by
H.J. Gruy, which Gruy report dated February 10, 1998 is Attachment D to this
Supplement. CIBC Oppenheimer then divided the property groups into two
categories. Those property groups with reserves consisting primarily of proved
developed producing reserves were placed in the "Conventional Case" category.
Those property groups with significant proved developed non-producing or
undeveloped reserves were placed in the "Non-Conventional Case" category.
[NEXT IS VARIABLE SENTENCE:] The Partnership has interests in property groups
which were in both the "Conventional Case" and the "Non-Conventional Case"
categories. CIBC Oppenheimer then valued each property group (including those
groups in both the "Conventional Case" and "Non- Conventional Case" categories)
by applying the multiples discussed under "Special Factors--Valuation by CIBC
Oppenheimer--Valuation Multiples" in the Joint Proxy Statement/Prospectus to
each property group's PV-10 Value, proved reserves on a BOE basis, and
projected 1998 EBIDTA. A separate set of multiples was used for property
groups in the Conventional Case category and the Non-Conventional Case
category, respectively. This provided CIBC Oppenheimer with three estimated
values for each property group. The average of these three values yielded CIBC
Oppenheimer's estimation of the fair market value of each property group. CIBC
Oppenheimer then allocated the appropriate portion of each property group's
estimated fair market value to the Partnership based upon the Partnership's
Property Interests in each property group. The result of this analysis by CIBC
Oppenheimer was an estimation that the fair market value of the Partnership's
Property Interests was $347,204 on December 31, 1997.
The Special Transactions Committee has determined that, in keeping
with the definition of Fair Market Value, the higher of these two estimations
of fair market value, or $347,204, represents the Fair Market Value of the
Partnership's Property Interests. Accordingly, the fair market value
estimation of the Petroleum Consulting Engineers and the fair market value
determined by CIBC Oppenheimer were compared to each other and the higher of
the two was chosen as the Fair Market Value of the Property Interests owned by
the Partnership. The variation between the fair market value estimate of the
Partnership's Property Interests prepared by the Petroleum Consulting
Engineers, on one hand, and CIBC Oppenheimer on the other was 1.0%.
DETERMINATION OF PREMIUM OVER FAIR MARKET VALUE BY THE COMPANY
The Special Transactions Committee presented its recommendation to the
Board of Directors of the Company as to the Fair Market Value of the Property
Interests of the Partnership. The Board of Directors of the Company then
determined that paying a 7.5% premium over the Fair Market Value of the
Partnership's Property Interests was appropriate and fair based upon the
factors and for the reasons discussed below. Because the Company has served as
Managing General Partner of the Partnership for over ten years, it is
intimately familiar with the Property Interests owned by the Partnership. The
Managing General Partner believes that if the Property Interests were to be
sold to a third party purchaser that was not equally familiar with those
interests, it is likely that the purchaser would discount the purchase price to
account for that lack of familiarity and associated risks. If these interests
are purchased by the Company, then the additional cost and personnel often
inherent in making a property acquisition are not required, because the files
and deed records already exist in the Company's lease and computer systems, and
conveyance and title issues do not exist.
In the judgment of the Company, the purchase of the Partnership's
Property Interests together with interests in many of the same properties owned
by other Partnerships at approximately the same time will result in
efficiencies to the Company in aggregating such interests. Swift's long-term
knowledge of the risks involved in these properties means that it is in a
better position to evaluate these risks than third parties.
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<PAGE> 226
Based upon the Company's experience in purchasing properties, the lack
of additional costs often incurred in purchasing oil and gas properties in
which the purchaser has owned no interest, and the Company's intimate
familiarity with these Property Interests and consequent ability to evaluate
acquisition risks, it was deemed appropriate to pay a premium representing the
benefit to the Company arising from these factors.
The amount of the premium principally was based upon management's
experience in purchasing properties which contain both producing reserves and
drilling potential, without any statistical or analytical study prepared by the
Company in the course of determining the amount of this premium. Since 1979,
the Company, on behalf of itself and others, has gained a wide range of
experience with the valuation of oil and gas properties and the prices for
their purchase and sale, having purchased $478 million of such properties in
129 separate transactions. Other purchasers might have determined it
inappropriate to pay a premium, or if so, to pay a premium based upon other
factors or in a different amount. Because there has been no independent third
party involved in the decision to pay this premium or in the determination of
its amount, and no fairness opinion has been requested regarding this premium,
conflicts of interest exist in its determination, although the Managing General
Partner believes, based upon its knowledge of the oil and gas industry, its
knowledge of the properties involved, its experience in purchasing and selling
oil and gas properties, and the benefits from purchasing the Property Interests
which are particular to the Company, that the amount being offered to the
Partnership to purchase its Property Interests is fair.
"SPECIAL FACTORS" SECTION IN THE JOINT PROXY STATEMENT/PROSPECTUS
The Special Factors section in the Joint Proxy Statement/Prospectus
contains a full discussion of the determination of the purchase price proposed
to be paid by the Managing General Partner to purchase the Partnership's
Property Interests. In addition to those topics discussed at length in this
Supplement, the Joint Proxy Statement/Prospectus addresses alternative
transactions that were considered but not proposed for the Partnership and the
other 62 partnerships to whom similar proposals are being made simultaneously.
It also contains information regarding the prior relationships between the
Appraisers, the Partnerships and the Managing General Partner, the absence of a
request that an independent representative negotiate the terms of the purchase
of the Partnership's Property Interests by the Managing General Partner, the
manner in which expenses are to be borne for the transaction, the Managing
General Partner's source of funds to purchase the Partnership's Property
Interests, and the benefits that the Managing General Partner would receive
from purchasing such Property Interests.
ESTIMATES OF LIQUIDATING NET CASH DISTRIBUTION AMOUNT IF THE PROPOSAL IS
APPROVED
The purchase price proposed to be paid to the Partnership for its oil
and gas assets is the Fair Market Value plus the purchase premium. As is the
case with all oil and gas properties purchases, the purchase is proposed to be
made as of the date which the properties were evaluated (in this case December
31, 1997). A portion of the reserves used to establish the Fair Market Value
has been produced during 1998. Most of the net revenue received by the
Partnership from the sale of such production since the proposed purchase date
(December 31, 1997) has been distributed to the partners during 1998 through
quarterly cash distributions or, to the extent not already distributed, will be
distributed as part of the Partnership's liquidating distributions.
Accordingly, the actual purchase price which will be paid to the Partnership
will be reduced by the amount of net production revenue received by the
Partnership after December 31, 1997.
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Set forth in the table below are estimated net proceeds that the
Partnership may realize from the sale of the Partnership's Property Interests,
estimated expenses of the related dissolution and liquidation of the
Partnership and estimated interim net cash distributions from January 1, 1998
until September 30, 1998, resulting in an estimate of the amount of net cash
distributions available for partners as a result of such sale.
ESTIMATE OF NET CASH DISTRIBUTIONS
FROM PROPERTY INTEREST SALES AND LIQUIDATION
<TABLE>
<S> <C> <C>
Fair Market Value of Partnership Property Interests(1) $ 347,204
(Gross Sales Proceeds)
Purchase Premium (7.5% of Fair Market Value)(2) $ 26,040
Estimated Selling and Dissolution Expenses(3) $ (10,416)
(3% of the Fair Market Value)
Net Assets(4) $ 81,595
Estimated Interim Cash Distributions(5) $ (77,205)
------------------
Estimated Net Distributions to Partners(6) $ 367,218
==================
Amount Distributable
to Investors(6) $ 329,881
Amount Distributable
to General Partners(6)(7) $ 37,337
----------------
$ 367,218
================
ESTIMATED NET CASH DISTRIBUTIONS TO INVESTORS PER $100 UNIT $ 6.92
==================
MINIMUM NUMBER OF UNITS NECESSARY TO PURCHASE 100 SHARES OF SWIFT
ENERGY COMMON STOCK WITH CASH DISTRIBUTIONS(8) 261
==================
</TABLE>
- ------------------------------------------
(1) Represents the higher of two fair market value estimates by the
Appraisers.
(2) As determined by the Board of Directors of Swift.
(3) Includes estimated costs associated with dissolution and liquidation
of the Partnership.
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(4) Includes cash and net receivables of the Partnership as of December
31, 1997.
(5) Estimated cash distributions paid to the partners from January 1, 1998
to September 30, 1998.
(6) Estimated net cash distributions are allocated to the Investors and
the General Partners pursuant to the Partnership's limited partnership
agreement.
(7) Includes amount distributable to Special General Partner and Managing
General Partner.
(8) Under the terms of the offer of Swift Common Stock to Eligible
Purchasers, if the Investors in the Partnership approve the Proposal
and its Companion Partnership approves a similar Proposal, such
Investors will be Eligible Purchasers. The minimum number of shares
which can be purchased by an Eligible Purchaser is a round lot of 100
shares. Based upon estimated net cash distribution of $6.92 per $100
Unit, the number of Units shown above is the minimum number of Units
which it will be necessary for an Investor to own in order to purchase
a minimum 100 share round lot of Swift Common Stock without providing
any additional funds from other sources. This calculation is based
upon an assumed purchase price of Swift Common Stock of $18.00 per
share (which is the same price upon which the proforma financial
statements contained in the Joint Proxy Statement/Prospectus are
based) for an aggregate purchase price for 100 shares of Swift Common
Stock of $1,800. The minimum number of Units shown is subject to
change, based upon the price for Swift Common Stock at a future date
as specified under "Offering of Shares of Swift Energy Company Common
Stock if Investors Approve the Proposal--Offer of Swift Common
Stock--Purchase Price" in this Supplement. However, if an Eligible
Purchaser has interests in more than one Partnership, the cash
distributions he will be entitled to receive may be aggregated to meet
the minimum share purchase requirement of a round lot of 100 shares.
ESTIMATES OF NET CASH DISTRIBUTIONS AVAILABLE FROM CONTINUED OPERATIONS
If the Partnership were to retain its Property Interests until they
have reached their economic limit, the table below estimates the return to
Investors, without regard to amounts distributable to the General Partners,
discounted to present value, based upon 1997 year-end pricing without
escalation and upon the discount assumptions used above. The estimates of the
present value of future net cash distributions have been further reduced by
estimates of continuing audit, tax return preparation and reserve engineering
fees associated with continued operations of the Partnership, along with direct
and general and administrative expenses estimated to occur during this time.
The following estimated future net revenues do not take into account any
additional costs which might be incurred by the Partnership's Companion
Partnership due to needed future maintenance or remedial work on the properties
in which the Partnership has an interest, which would reduce such net revenues.
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ESTIMATED SHARE OF INVESTORS'
NET CASH DISTRIBUTIONS FROM CONTINUED OPERATIONS
<TABLE>
<S> <C>
Estimated Future Net Revenues from Continued Operations until $ 811,554
Depletion(1)
Estimated Interim Net Cash Distributions(2) $ (70,400)
Estimated Partnership Direct and Administrative Expenses(3) $ (121,733)
Net Assets(4) $ 73,736
--------------
Net Cash Distributions to Investors(5) $ 693,157
==============
NET CASH DISTRIBUTIONS PER $100 UNIT $ 14.53
PRESENT VALUE OF NET CASH DISTRIBUTIONS PER $100 UNIT(5)(6) $ 7.83
</TABLE>
- ---------------------------------------------
(1) Investors' future net revenues are based on the reserve estimates at
December 31, 1997 using year-end 1997 prices without escalation. To a
limited extent, future net revenues may be influenced by a material
change in the selling prices of oil or gas. For further discussion of
this, see "Special Factors--Reasons for the Proposal" in this
Supplement. The actual prices that will be received and the
associated costs are likely to vary and may be more or less than those
projected. See "Partnership Business and Financial Condition" in this
Supplement.
(2) Estimated net cash distributions paid to Investors from January 1,
1998 to September 30, 1998 in order to present this information on a
comparative basis (in relation to the preceding table) as of September
30, 1998.
(3) Includes Investors' share of general and administrative expenses, and
audit, tax, and reserve engineering fees.
(4) Includes Investors' share of cash and net receivables of the
Partnership as of December 31, 1997.
(5) Based upon the Partnership's reserves until they have reached their
economic limit.
(6) Discounted at 10% per annum.
The proceeds of all sales, to the extent available for net cash
distribution, are to be distributed to the partners in accordance with the
Partnership's limited partnership agreement. The amounts finally distributed
will depend on results of operations until liquidation of the Partnership,
final costs and other contingencies and circumstances.
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FAIRNESS OF PROPOSED SALE OF ASSETS TO THE MANAGING GENERAL PARTNER
AS COMPARED TO CONTINUING OPERATIONS
Based on the above tables, it is estimated that an Investor could
expect to receive $6.92 per $100 Unit upon the sale of the Partnership's
Property Interests as of September 30, 1998. In comparison, it is estimated
that an Investor could expect to receive $7.83 per $100 Unit, discounted to
present value at 10% per annum ($14.53 per $100 Unit on an undiscounted basis)
if the Partnership continued operations. The Managing General Partner believes
that the Proposal to sell the Partnership's Property Interest as compared to
continuing operations is fair to Investors for the reasons discussed below.
Although the estimates contained in the two tables above show that
estimated net cash distributions to Investors (based on net present value) from
continued operations would be approximately 13% higher than estimated net cash
distributions from selling the Partnership's Property Interests and liquidating
the Partnership currently, the Managing General Partner believes there is a
substantial advantage in receiving the liquidating net cash distribution in one
lump sum at this time. The estimates of net cash distributions from continued
operations are based upon 1997 year-end pricing. It is highly likely that
over such a long period of time, oil and gas prices will vary often and
possibly widely, as has been demonstrated historically, from the prices used to
prepare these estimates. Continued operations over such a long period of time
subject Investors to the risk of receiving lower levels of net cash
distributions if oil and gas prices over this period are lower on average than
those used in preparing the estimates of net cash distributions from continued
operations. Continued operations also subject Investors' potential net cash
distributions to the risks of possible changes in costs or need for workover or
similar significant remedial work on the properties in which the Partnership
owns Property Interests. The Managing General Partner also believes that there
is an advantage to Investors taking any funds to be received upon liquidation
and redeploying those assets in other investments, rather than continuing to
receive decreasing levels of net cash distributions over such a long period of
time.
Because there is no active trading market for Units in the
Partnership, the only other comparable value for Units is the 1997 "Unit
Value," which, as explained below, is the amount calculated on an annual basis
under the terms of the limited partnership agreement at which the Managing
General Partner can offer to repurchase Units from Investors. As of January 1,
1997, this "Unit Value" was $10.66 per $100 Unit. In 1997, the Investors
received net cash distributions of $1.50 per $100 Unit, and are estimated to
receive another $1.48 per $100 Unit before September 30, 1998, which converts
to a comparable value of $7.68 per $100 Unit before any adjustments to
quantities of reserves or oil and gas prices during this almost two year
period. Under the terms set out in the limited partnership agreement, each
year the Managing General Partner is required to furnish to Investors the Unit
Value, and Investors have the right to present their Units for purchase by the
Managing General Partner for the Unit Value. The Unit Value amount is
determined on an entirely different basis than the estimates of fair market
value by the Appraisers. Furthermore, the Unit Value was calculated over one
year ago, with a valuation date of January 1, 1997, as opposed to the date for
assessment of Fair Market Value being December 31, 1997. Because of significant
changes in oil and gas prices within a year's time, in addition to the changes
in reserve quantities during that period, the calculation of Unit Value as of
January 1, 1997, and the Fair Market Value as of December 31, 1997, are not
comparable. Unit Value is derived by taking 70% of the present value of proved
oil and gas reserves (discounted at 10% per annum) calculated on an escalated
pricing basis, plus cash and accounts receivable less outstanding debts and
obligations of the Partnership.
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Although the PV-10 Value of the Partnership's Property Interests is
higher than the purchase price proposed if the Proposal is approved, the
Managing General Partner does not believe that the PV-10 Value accurately
reflects the amount that oil and gas industry members are currently paying to
purchase producing properties on the open market.
FAIRNESS OF PROPOSED SALE
The Managing General Partner believes that the entire transaction
related to the Proposal involving the proposed method of sale of the
Partnership's Property Interests is fair to Investors for the following
reasons, without giving any particular weight to any reason:
1. The Managing General Partner believes that the most important
element of the Proposal is the determination of the Fair
Market Value of the Partnership's Property Interests. The
price to be paid by the Company to purchase the Partnership's
Property Interests was determined in the Managing General
Partner's sole judgment by adding a 7.5% premium to the higher
of the two estimates by the Appraisers of the fair market
value of the Partnership's Property Interests. Two of the
three Appraisers are qualified independent petroleum
engineering firms and the other is an investment banking firm.
The factors and methods used by the Appraisers in determining
Fair Market Value are discussed in detail under "Special
Factors--Independent Appraisal of the Fair Market Value of
Property Interests of the Partnership," "--Fair Market Value,"
"--Valuation by Petroleum Engineering Consultants,"
"--Valuation by CIBC Oppenheimer" and "--Collective Analysis
of Purchase Price" in the Joint Proxy Statement/Prospectus.
2. No transaction will take place unless the Proposal is approved
by Investors holding at least a majority of the interests in
such Partnership (without any vote by the Managing General
Partner) and a similar Proposal is approved by the
Partnership's Companion Partnership.
3. The Special Transactions Committee made the determination as
to the retention of the Appraisers and approved the fair
market value estimates provided by the Appraisers and
recommended the reports of the Appraisers to the Board of
Directors of the Company. The Special Transactions Committee
is comprised solely of independent directors of the Company.
4. If the Proposals are approved by investors in any of the 63
Partnerships considering similar proposals, it is likely that
the Managing General Partner will expend the capital necessary
to develop non- producing reserves on the Property Interests
purchased by the Managing General Partner from those
Partnerships. If all of the Property Interests which are the
subject of the Proposals are acquired by the Company, such
Property Interests in the aggregate will constitute less than
20% of the Company's total assets. Because the Managing
General Partner would be the beneficiary of any such increase
in value, the Managing General Partner is hereby offering to
Eligible Purchasers the opportunity to purchase up to
2,500,000 shares of Common Stock of the Company. There is no
requirement that any purchase of Swift's Common Stock be made.
See "Offer of Swift Common Stock" below.
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5. In structuring the Proposal and related transactions, the
Managing General Partner considered that any sale of
Partnership Property Interests, whether to the Managing
General Partner or to a third party, would be a taxable
transaction. Thus, if an Investor subject to federal income
tax chooses to use the proceeds received on liquidation of
that Investor's Partnership to purchase Swift Common Stock,
tax will still have to be paid on any taxable income resulting
from the Partnership's sale of oil and gas assets, without
regard to whether the Investor has cash proceeds remaining
from his liquidating distribution to pay such tax. Investors
that purchased their interests in the original offering,
however, are not expected to recognize gain on the sale.
The determination by the Special Transactions Committee to pay the
purchase premium, the independent Appraisers' determination of the fair market
value of the properties and the payment of a 7.5% premium do not necessarily
remove the substantial conflicts of interest which exist in the transaction
between the Managing General Partner's serving in that capacity on behalf of
the Partnership and also acting as the purchaser of the Property Interests from
the Partnership. No fairness opinion was requested or received regarding the
ultimate purchase price to be paid by the Managing General Partner to purchase
the Partnership's oil and gas assets. The Managing General Partner determined
that rather than setting the purchase price for Partnership Property Interests
itself, it would be preferable to instead request three different independent
Appraisers to determine two sets of fair market values at which such Property
Interests should be purchased, and then to choose the higher of those two
values. The Managing General Partner believes that when the Appraisers
rendered their opinions as to the "fair market value" of the Partnership's
Property Interests, inherent within their appraisal opinions were the
Appraisers' determination that these "fair market values" were "fair," or such
determinations would not have been made. Consequently, no independent fairness
opinion was requested regarding "fair market values" or upon the premium. The
Managing General Partner believes that adding a 7.5% premium to the highest of
the two fair market value determinations made by the three Appraisers only
serves to increase the amount to be paid to Investors upon liquidation of the
Partnership and does not require a separate fairness opinion. The
determination by a third party purchaser as to the purchase price might be more
or less than that being proposed by the Managing General Partner as a purchase
price for these Property Interests.
The determination to submit the Proposal to Investors in which the
Company would purchase the Property Interests of the Partnership was deemed by
the Managing General Partner to be the most appropriate time and method for
liquidation of the Partnership. This decision was made in light of full
consideration by the Managing General Partner of its fiduciary obligations to
Investors. Furthermore, the decision to use three Appraisers, rather than one,
and to have the Appraisers actually set the fair market value for purchase of
the Property Interests, rather than the Managing General Partner setting that
value and requesting a fairness opinion, were based upon the Managing General
Partner's consideration of the substantial conflicts of interest which exist in
the transactions covered hereby.
See "Special Factors--Fairness of Proposed Sale" in the Joint Proxy
Statement/Prospectus.
MANAGING GENERAL PARTNER BENEFITS
Benefits accruing to the Company resulting from the purchase of the
Partnerships' Property Interests include the following: the Managing General
Partner will share the benefits available to Investors through liquidating its
Partnership interests (including both its general partner interests and any
Units it owns) and receiving the same value of those interests as Investors.
Additionally, the Company intends to
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<PAGE> 233
profit from purchasing the Partnership's Property Interests through a return on
capital used to purchase those oil and gas assets and invest in their
development. By purchasing the Partnership's Property Interests itself, the
Managing General Partner will be able to maintain its position as operator of
certain properties in which the Partnership owns an interest. Consequently,
the Managing General Partner would continue to receive operating fees as
operator of those properties. The sale of the Partnership's Property Interests
to the Managing General Partner will have no effect or an inconsequential
effect on the Managing General Partner's net book value and net earnings.
However, the purchase of all of the oil and gas assets of the Partnerships
would increase the Company's proved reserves, cash flow and total assets by a
significant amount. Lastly, if individual Investors which approve the Proposal
elect to purchase Company Common Stock, rather than receiving cash upon
liquidation of the Partnership, the Company will benefit by using stock to pay
the purchase price, rather than using its available cash resources or borrowing
facilities.
See "Special Factors--Managing General Partner Benefits" in the Joint Proxy
Statement/Prospectus.
SIMULTANEOUS PROPOSALS TO COMPANION PARTNERSHIPS
Simultaneous Proposals are being made to investors in the
Partnership's Companion Partnership. If both the Partnership and its Companion
Partnership do not approve their respective Proposals, it is likely to affect
the ability of the Partnership to consummate the sale of its Property
Interests. Although the Investors in the Partnership may desire to sell their
Property Interests, the separation of the working interest and the
non-operating interests in the same properties may affect the salability of
those interests on a permanent basis. If, for example, the Partnership
approves the Proposal but the Companion Partnership does not, the value of a
non-operating interest is likely to be negatively affected by the lack of
control over operations. [VARIABLE REVERSAL: If, for example, the Partnership
approves the Proposal but the Companion Partnership does not, the value of a
working interest burdened by a large non- operating interest is likely to be
lowered significantly.] If the Partnership's Companion Partnership does not
approve its Proposal, then the Managing General Partner will advise the
Investors in the Partnership. If the Investors in the Partnership's Companion
Partnership do not vote in favor of its Proposal, then it is likely that the
Partnership will continue operations and will produce its reserves until
depletion, with steadily decreasing rates of cash flow, and consequently
steadily decreasing amounts of cash distributions to the Investors.
VOTING ON THE PROPOSAL
The Joint Proxy Statement/Prospectus and the Form of Proxy enclosed
with this Supplement are being provided for use at the Special Meeting of
Investors of the Partnership and at any adjournment or postponement of such
meeting (the "Meeting") to be held at 16825 Northchase Drive, Houston, Texas at
4:00 p.m. Central Time on ______, ___________, 1998. The Meeting is being
called for the purpose of considering and voting upon the Proposal to
ultimately sell all of the oil and gas assets of the Partnership to the
Company, and to dissolve, wind up and terminate the Partnership and to transact
such other business as may be properly presented at the Meeting, all in
accordance with the terms and provisions of the Partnership's limited
partnership agreement (the "Partnership Agreement"), and the Texas Revised
Limited Partnership Act (the "Texas Act"). This Joint Proxy
Statement/Prospectus and enclosed Form of Proxy are first being mailed to
Investors on or about _____________, 1998.
Pursuant to the terms of the Partnership Agreement, the Partnership,
if not terminated earlier, will continue in being through January 1, 2021, at
which point it will terminate automatically.
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Under the Partnership Agreement, the Proposal must be approved by the
affirmative vote of Investors holding 51% or more of the Units in the
Partnership as of the Record Date (defined below). Therefore, an abstention by
an Investor will have the same effect as a vote against the Proposal. The
solicitations are being made for votes in favor of the Proposal (which will
result in liquidation and dissolution of the Partnership). As of the Record
Date, 45,181 Units were outstanding and held by record holders (excluding the
Units held by the Managing General Partner as discussed below). Accordingly,
the affirmative vote of holders of at least 23,042 Units is required to approve
the Proposal. Each Investor appearing on the records of the Partnership as of
______, 1998 (the "Record Date") is entitled to notice of the Meeting and is
entitled to one vote for each Unit held by such Investor. VJM Corporation, a
California corporation, is the Special General Partner of the Partnership, and
owns a 1.0% interest in the Partnership as a general partner, but owns no
Units. The Managing General Partner owns a general partner interest in the
Partnership of 9.0%. Additionally, the Managing General Partner owns 2,523
outstanding Units in the Partnership, which ownership results from the Managing
General Partner's purchase over the life of the Partnership of Units from
Investors under the right of presentment, contained in the Partnership
Agreement. Under the Partnership Agreement, the Managing General Partner may
not vote any Units owned by it for matters such as the Proposal. The Managing
General Partner's non-vote, in contrast to abstention by Investors, will not
affect the outcome, because for purposes of adopting the Proposal, its Units
are excluded from the total number of voting Units.
VOTE REQUIRED
The actual proxy to be used to register the vote on the Proposal
before you is the separate green sheet of paper included with this Supplement
and Joint Proxy Statement/Prospectus. PLEASE USE THE GREEN PROXY TO CAST YOUR
VOTE ON THE PROPOSAL.
If a proxy is properly signed and is not revoked by an Investor, the
Units it represents will be voted in accordance with the instructions of the
Investor. If no specific instructions are given, the Units [VARIABLE: SDIS]
will be voted FOR the Proposal. An Investor may revoke his proxy at any time
before it is voted at the Meeting. Any Investor who attends the Meeting and
wishes to vote in person may revoke his proxy at that time. Otherwise, an
Investor must advise the Managing General Partner of revocation of his proxy in
writing, which revocation must be received by the Managing General Partner at
16825 Northchase Drive, Suite 400, Houston, Texas 77060 prior to the time the
vote is taken.
SOLICITATION
The solicitation is being made by the Partnership. The Partnership
will bear the costs of the preparation of the Joint Proxy Statement/Prospectus
and of the solicitation of proxies and such costs will be allocated 90% to the
Investors and 10% to the general partners pursuant to the terms of the
Partnership Agreement. As the Managing General Partner holds approximately
5.26% [VARIABLE PERCENTAGES] of the Units held by all Investors, 5.26% of the
costs borne by the Investors will be borne by the Managing General Partner, in
addition to the portion of the Partnership's total costs borne by the general
partners by virtue of their interest in the Partnership as general partners.
Solicitations will be made primarily by mail. In addition, a number of regular
or temporary employees of the Managing General Partner may, if necessary to
ensure the presence of a quorum, solicit proxies in person or by telephone.
The Managing General Partner also may retain a proxy solicitor to assist in
contacting brokers or Investors to encourage the return of proxies, although it
does not anticipate doing so.
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<PAGE> 235
PARTNERSHIP BUSINESS AND FINANCIAL CONDITION
The Partnership is a Texas limited partnership formed June 2, 1988.
Units in the Partnership are registered under Section 12(g) of the Securities
Exchange Act of 1934. The Partnership owns non-operating interests in producing
oil and gas properties within the continental United States in which the
Companion Partnership also managed by the Managing General Partner owns the
working interests. By the end of February 1989, the Partnership had expended
all of its original capital contributions for the purchase of Property
Interests in oil and gas producing properties. During 1997, approximately 91%
of the Partnership's revenue was attributable to natural gas production. From
time to time, the Companion Partnership has performed workovers and
recompletions of wells in which the Partnership has non-operating interests,
using funds advanced by the Managing General Partner or third parties to
perform these operations, which amounts have been subsequently repaid. For
information about the business of the Partnership, see the attached Annual
Report on Form 10-K for the year ended December 31, 1997 and Quarterly Report
on Form 10-Q for the quarter ended June 30, 1998.
Investors made contributions of $4,770,363 in the aggregate to the
Partnership, the net proceeds of which have all been invested. The Managing
General Partner has made capital contributions with respect to its general
partner interest of $38,125. Additionally, pursuant to the right of
presentment set forth in the Partnership Agreement, it has purchased 2,523
Units from Investors. From inception through July 31, 1998, the Partnership
has made net cash distributions to its Investors totaling $2,772,700. Details
of the amounts of cash distributions made to partners over the past three years
and nine months are set out under "Cash Distributions" below. Through July 31,
1998, the Managing General Partner has received net cash distributions from the
Partnership of $257,787 with respect to its general partner interest, and
$18,515 related to its limited partner interest. On a per Unit basis,
Investors had received, as of July 31, 1998, $58.12 per $100 Unit, or
approximately 58.1% of their initial capital contributions.
The Partnership acquired its Property Interests at a time when oil and
gas prices and industry projections of future prices were much higher than
actually occurred in subsequent years. When the Managing General Partner
projected future oil and gas prices to evaluate the economic viability of an
acquisition, it compared its forecasts with those made by banks, oil and gas
industry sources, the U.S. government and other companies acquiring producing
properties. Acquisition decisions for the Partnership were based upon a range
of increasing prices that were within the mainstream of the forecasts made by
these outside parties. At the time that the Partnership's Property Interests
covering producing properties were acquired, prices averaged about $15.37 per
barrel of oil and $1.80 per Mcf of natural gas. The majority of the
Partnership's Property Interests were acquired by the end of February 1989 and
were comprised principally of natural gas reserves. At that time current
prices were predicted to escalate according to certain parameters from then
current levels to approximately $29.37 per barrel of oil and $3.43 per Mcf of
natural gas during 1997. The predicted price increases did not occur, and
prices fell precipitously from 1990 to 1991. Most of the Partnership's
reserves were produced from 1989 to 1993, during which time the oil prices
received by the Partnership for its production in fact averaged $18.79 per
barrel, but the prices for the Partnership's principal asset, natural gas,
averaged approximately $1.67 per Mcf. A comparison of gas prices as described
in this paragraph appears in the graph presented below.
The following graphs illustrate the effect on Partnership performance
of the variance between gas prices projected at the time of acquisition of the
Partnership's Property Interests and actual gas prices received for production
(as illustrated in the second graph) during the Partnership's existence.
Information is presented as to gas prices only due to the fact that a
substantial majority of the Partnership's production has been natural gas.
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[GRAPH: 1 page of gas properties info]
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<PAGE> 237
Lower prices also have had an effect on the Partnership's interest in
proved reserves. Estimates of proved reserves represent quantities of oil and
gas which, upon analysis of engineering and geologic data, appear with
reasonable certainty to be recoverable in the future from known oil and gas
reservoirs under existing economic and operating conditions. When economic or
operating conditions change, proved reserves can be revised either up or down.
If prices had risen as predicted, the volumes of oil and gas reserves that are
economically recoverable might have been higher than the year-end levels
actually reported because higher prices typically extend the life of reserves
as production rates from mature wells remain economical for a longer period of
time. Production enhancement projects that are not economically feasible at
low prices can also be implemented as prices rise. At present, because of the
small remaining amount of reserves, further price increases would not have a
significant impact on the Partnership's performance.
CASH DISTRIBUTIONS
Cash distributions are made to the partners in the Partnership on a
quarterly basis. During the past three years and the first nine months of
1998, aggregate cash distributions made to all partners in the Partnership
(including the Managing General Partner) and the cash distributions per Unit
made to the Investors were:
<TABLE>
<S> <C> <C> <C>
1995 $ 79,856 $ 1.55 per $100 Unit
1996 $ 48,338 $ 0.82 per $100 Unit
1997 $ 84,664 $ 1.50 per $100 Unit
9 Mo. Ended 9/30/98 $ 77,205 $ 1.48 per $100 Unit
</TABLE>
TRANSACTIONS BETWEEN THE MANAGING GENERAL PARTNER AND THE PARTNERSHIP
Under the Partnership Agreement, the Managing General Partner has
received certain compensation for its services and reimbursement for
expenditures made on behalf of the Partnership, which was paid at closing of
the offering of interests in the Partnership, in addition to revenues
distributable to the Managing General Partner with respect to its general
partner interest or with respect to Units it has purchased under the Investors'
right of presentment. In addition to those revenues, compensation and
reimbursements, the following summarizes the transactions between the Managing
General Partner and the Partnership pursuant to which the Managing General
Partner has been paid or has had its expenses reimbursed on an ongoing basis:
o The Managing General Partner has received management fees of
$119,259, internal acquisition costs reimbursements of
$155,605 and formation costs reimbursements of $95,407 from
the Partnership from inception through December 31, 1997, none
of which has been received during the two years ended December
31, 1997.
o In the past, the Managing General Partner has received
operating fees for wells in which the Partnership has Property
Interests and for which the Managing General Partner or its
affiliates serve as operator. During the years ended December
31, 1997 and December 31, 1996 the aggregate operating fees
paid to the Company as operator by the Partnership were $1,920
and $7,136, respectively. Monthly operating fees ranged from
$100 to $125 per well on an 8/8th's basis (i.e., the total
amount of operating fees paid by all interest owners in the
well). The Managing General Partner no longer serves as
operator of any properties in which the Partnership owns an
interest and, consequently, no longer receives per-well
operating fees.
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o The Managing General Partner is entitled to be reimbursed for
general and administrative costs incurred on behalf of and
allocable to the Partnership, including employee salaries and
office overhead. Amounts are calculated on the basis of
Investors' original capital contributions to the Partnership
relative to investor contributions to all public partnerships
formed to purchase interests in producing properties for which
the Managing General Partner serves in that capacity. Through
December 31, 1997, the Managing General Partner had received
$312,053 in the general and administrative overhead allowance
from the Partnership, of which $16,058 and $15,140 have been
reimbursed during the years ended December 31, 1997 and
December 31, 1996, respectively.
o The Managing General Partner has been reimbursed $25,064 in
direct expenses by the Partnership, all of which was billed
by, and then paid directly to, third party vendors, of which
$1,744 and $2,368 have been reimbursed during the years ended
December 31, 1997 and December 31, 1996, respectively.
NO TRADING MARKET
There is no trading market for the Units, and none is expected to
develop, as described above under "Special Factors--Fairness of Proposed Sale
of Assets to the Managing General Partner as Compared to Continuing
Operations." Under the Partnership Agreement, Investors have the right to
present their Units to the Managing General Partner for repurchase at a price
determined in accordance with the formula established by the Partnership
Agreement. Originally 426 Investors invested in the Partnership. As of
__________, 1998, there were 411 Investors (excluding the Managing General
Partner). The number of Units in the Partnership issued and outstanding at
that date was 47,703.63. Through December 31, 1997, the Managing General
Partner had purchased 2,523 Units from Investors pursuant to the right of
presentment. The Managing General Partner does not have an obligation to
repurchase Investor interests pursuant to this right of presentment, but merely
an option to do so when such interests are presented for repurchase.
PRINCIPAL HOLDERS OF INVESTOR UNITS
The Managing General Partner holds 5.26% of all outstanding Units of
the Partnership, resulting from the purchase of Units from Investors under
their right of presentment. To the knowledge of the Managing General Partner,
there are two other holders of Units that hold more than 5% of the Units, each
representing approximately 5.2% of the total Units outstanding.
APPROVALS
No federal or state regulatory requirements must be satisfied or
approvals obtained in connection with the sale of the Partnership's Property
Interests.
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LEGAL PROCEEDINGS
The Managing General Partner is not aware of any material pending
legal proceedings to which the Partnership is a party or of which any of its
property is the subject.
SUMMARY OF FEDERAL INCOME TAX CONSEQUENCES
GENERAL
The following briefly summarizes the federal income tax consequences
set forth under "Federal Income Tax Consequences of Adoption of the Proposals"
in the Joint Proxy Statement/Prospectus. Statements of legal conclusions
herein regarding tax consequences are based upon an opinion of Hoops & Levy,
L.L.P., Special Tax Counsel, relevant provisions of the Internal Revenue Code
of 1986, as amended (the "Code"), and accompanying Treasury Regulations, as in
effect on the date hereof, upon reported judicial decisions and published
positions of the Internal Revenue Service (the "Service"), private letter
rulings dated October 6, 1987 and August 22, 1991 and upon further assumptions
that the Partnership constitutes a partnership for federal tax purposes and
that the Partnership will be liquidated as described herein. The laws,
regulations, administrative rulings and judicial decisions which form the basis
for conclusions with respect to the tax consequences described herein are
complex and are subject to prospective or retroactive change at any time and
any change may adversely affect Investors.
A MORE COMPLETE SUMMARY OF THE FEDERAL INCOME TAX CONSEQUENCES TO
INVESTORS MAY BE FOUND IN THE REGISTRATION STATEMENT IN "FEDERAL INCOME TAX
CONSEQUENCES OF ADOPTION OF THE PROPOSALS." THIS SUMMARY DOES NOT DESCRIBE ALL
THE TAX ASPECTS WHICH MAY AFFECT INVESTORS NOR IS IT A COMPLETE DESCRIPTION OF
THE TAX ASPECTS IT DOES DESCRIBE. It is generally directed to Tax Exempt Plans
that are Investors who are the original purchasers of the Units and hold
interests in the Partnership as "capital assets" (generally, property held for
investment). Each Investor that is a corporation, trust, estate, or other
partnership is strongly encouraged to consult its own tax advisor as to the
rules which are specifically applicable to it. Except as otherwise
specifically set forth herein, this summary does not address foreign, state or
local tax consequences, and is inapplicable to nonresident aliens, foreign
corporations, debtors under the jurisdiction of a court in a case under federal
bankruptcy laws or in a receivership, foreclosure or similar proceeding, or an
investment company, financial institution or insurance company.
TAX TREATMENT OF TAX EXEMPT PLANS
SALE OF PROPERTY INTEREST AND LIQUIDATION OF PARTNERSHIP
Tax Exempt Plans are subject to tax on their unrelated business
taxable income ("UBTI"). Royalty interests, dividends, interest and gain from
the disposition of capital assets are generally excluded from classification
as UBTI. Notwithstanding these exclusions, royalties, interest, dividends, and
gains will create UBTI if they are received from debt-financed property, as
discussed below.
The Internal Revenue Service has previously ruled that the
Partnership's net profits interest, as structured under the net profits
agreement, is a royalty, as are any overriding royalties the Partnership may
own. To the extent that the Property Interest is not debt-financed property,
neither the sale of the Property Interest by the Partnership nor the
liquidation of the Partnership is expected to cause Investors that are Tax
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Exempt Plans either taxable gain or loss for federal income tax purposes, even
though there may be gain or loss upon the sale of the Property Interest for
federal income tax purposes.
DEBT-FINANCED PROPERTY
Debt-financed property is property held to produce income that is
subject to acquisition indebtedness. The income is taxable in the same
proportion which the debt bears to the total cost of acquiring the property.
Generally, acquisition indebtedness is the unpaid amount of (i) indebtedness
incurred by a Tax Exempt Plan to acquire an interest in a partnership, (ii)
indebtedness incurred in acquiring or improving property, or (iii) indebtedness
incurred either before or after the acquisition or improvement of property or
the acquisition of a partnership interest if such indebtedness would not have
been incurred but for such acquisition or improvement, and if incurred
subsequent to such acquisition or improvement, the incurrence of such
indebtedness was reasonably foreseeable at the time of such acquisition or
improvement.
If an Investor that is a Tax Exempt Plan borrowed to acquire its
Partnership interest or had borrowed funds either before or after it acquired
its Partnership Interest, its pro rata share of Partnership gain on the sale of
the Property Interest may be UBTI. If a Tax Exempt Plan has not caused its
Partnership Interest to be debt-financed property, and based upon
representations of the Managing General, the Property Interest is not expected
to be considered debt-financed property.
TAX TREATMENT OF INVESTORS SUBJECT TO FEDERAL INCOME TAX DUE TO DEBT-FINANCING
All references hereinbelow to Investors refers solely to Investors
that either are not Tax Exempt Plans or are Tax Exempt Plans whose Partnership
Interest is debt-financed. To the extent that a Tax Exempt Plan's Partnership
Interest is only partially debt-financed, the percentage of gain or loss from
the sale of the Property Interest and liquidation of the Partnership that will
be subject to taxation as UBTI is the percentage of the Tax Exempt Plan's share
of Partnership income, gain, loss and deduction adjusted by the following
calculation. Section 514(a)(1) includes, with respect to each debt-financed
property, as gross income from an unrelated trade or business an amount which
is the same percentage of the total gross income derived during the taxable
year from or on account of the property as (i) the average acquisition
indebtedness for the taxable year with respect to the property is of (ii) the
average amount of the adjusted basis of the property during the period it is
held by the organization during the taxable year (the "debt/basis percentage").
A similar calculation is used to determine the allowable deductions.
Tax Exempt Plans with debt-financed Partnership Interests should
consult their tax advisors to determine the portion of gain or loss that may be
recognized for federal income tax purposes. The following discussion of the
tax consequences of the sale of the Partnership Property Interest and the
liquidation of the Partnership assumes that all of an Investor's income, gain,
loss and deduction from the Partnership is subject to federal taxation.
TAXABLE GAIN OR LOSS UPON SALE OF PROPERTIES
Investors will realize and recognize gain or loss, or a combination of
both, upon the Partnership's sale of its properties prior to liquidation. It
is projected, however, that Investors will realize a net taxable loss upon the
sale of the Partnership properties.
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LIQUIDATION OF THE PARTNERSHIP
After sale of its properties, the Partnership's assets will consist
solely of cash which it will distribute to its partners in complete
liquidation. The Partnership will not realize gain or loss upon such
distribution of cash to its partners in liquidation. If the amount of cash
distributed to an Investor in liquidation is less than such Investor's adjusted
tax basis in his Partnership interest, the Investor will realize and recognize
a capital loss to the extent of the excess. If the amount of cash distributed
is greater than such Investor's adjusted tax basis in his Partnership interest,
the Investor will recognize a capital gain to the extent of the excess.
Because each Investor paid a portion of syndication and formation costs upon
entering the Partnership, neither of which costs were deductible expenses, it
is anticipated that liquidating distributions to Investors will be less than
such Investors' bases in their Partnership interests and thus will generate
capital losses.
CAPITAL GAIN TAX
Net long-term capital gains of individuals, trusts and estates
generally will be taxed at a maximum rate of 20%, while ordinary income,
including income from the recapture of intangible drilling and development
costs, depreciation and depletion, will be taxed at a maximum rate depending on
that Investor's taxable income of 36% or 39.6%.
PASSIVE LOSS LIMITATIONS
Investors that are individuals, trusts, estates, or personal service
corporations are subject to the passive activity loss limitations rules that
were enacted as part of the Tax Reform Act of 1986.
An Investor's allocable share of Partnership income, gain, loss, and
deduction is treated as derived from a passive activity, except to the extent
of Partnership portfolio income, which includes interest, dividends, royalty
income and gains from the sale of property held for investment purposes. An
Investor's share of any gain or loss realized upon the sale of the net profits
interest is expected to be characterized as portfolio income or loss and may
not offset, or be offset by, passive activity gains or losses.
THE FOREGOING DISCUSSION IS A SUMMARY OF THE INCOME TAX CONSEQUENCES
SET FORTH UNDER "FEDERAL INCOME TAX CONSEQUENCES OF ADOPTION OF THE PROPOSALS"
IN THE JOINT PROXY STATEMENT/PROSPECTUS. IT IS NOT INTENDED AS AN ALTERNATIVE
FOR INDIVIDUAL TAX PLANNING. EACH INVESTOR SHOULD CONSULT HIS, HER OR ITS OWN
TAX ADVISOR CONCERNING THE PARTICULAR FEDERAL, STATE, LOCAL, FOREIGN AND OTHER
TAX CONSEQUENCES APPLICABLE TO HIM, HER OR IT OF THE SALE OF PROPERTIES AND THE
LIQUIDATION OF THE PARTNERSHIP.
SELECTED FINANCIAL INFORMATION AND
PROFORMA FINANCIAL STATEMENTS
For selected financial information and financial statements of the
Partnership, see the Annual Report on Form 10-K for the year ended December 31,
1997 and the Quarterly Report on Form 10-Q for the quarter ended June 30, 1998
attached hereto.
27
<PAGE> 242
Proforma Financial Statements showing the effect of approval of the
Proposals by the 63 Partnerships to whom similar proposals are being made (both
in the event of the decision by investors to purchase the maximum number of
shares of Swift Common Stock purchasable with their cash distributions and in
the event that investors choose to take all of their distributions from sale of
the properties in cash) and the effect of the Sonat Properties Acquisition are
contained in the Joint Proxy Statement/Prospectus under "Unaudited Proforma
Consolidated Financial Statements".
OFFERING OF SHARES OF SWIFT ENERGY COMPANY COMMON STOCK
IF INVESTORS APPROVE THE PROPOSAL
VOTING PROCEDURES
The Joint Proxy Statement/Prospectus contains detailed procedures to
be followed by investors in voting as to the Partnerships' Proposals. Strict
compliance with these procedures must be followed in order for the elections of
the investors marked on the subscription agreement to be effective. The
following is a summary of certain of these procedures:
(a) Investors may make their elections on the subscription agreement
signed by all subscribers commencing upon delivery of this Joint Proxy
Statement/Prospectus and continuing until the Due Date (as defined below).
(b) If Investors in the Partnership (and its Companion Partnership)
vote to approve the Proposal, Investors may revoke their election to purchase
Shares offered hereby at any time until the Due Date by delivering or faxing a
letter so stating or a later dated subscription agreement, both of which must
be signed by such revoking subscribers, to the Company at 16825 Northchase
Drive, Suite 400, Houston, Texas 77060, fax number (281) 874-2818; Attention:
Investor Relations Department.
(c) Investors failing to submit proxies by the Due Date will be
deemed to have voted against their Partnership's Proposal and, if their
Partnership approves its Proposal, will receive, along with non-subscribing
investors who timely submitted proxies, their distribution in cash. See "The
Proposals--Vote Required" in the Joint Proxy Statement/Prospectus.
OFFER OF SWIFT COMMON STOCK
Investor Election to Purchase Shares
In connection with the concurrent Proposals for sale of all of the oil
and gas assets of 63 Partnerships to the Company and the subsequent termination
of such Partnerships, the Company is offering up to 2,500,000 shares of the
Company's Common Stock. Upon approval of the Proposals by the Partnership and
its Companion Partnership and sale of the Partnership's oil and gas assets, the
Partnership's assets will consist solely of cash which each investor as an
Eligible Purchaser of such Partnerships will be entitled to receive as a
distribution. The Company hereby offers to each such Eligible Purchaser the
opportunity to purchase shares of Common Stock with all or any portion of the
cash distribution such Eligible Purchaser will be entitled to receive, provided
that a minimum round lot of 100 shares must be purchased. If an Eligible
Purchaser has interests in more than one Partnership, the cash distributions he
will be entitled to receive may be aggregated to meet the minimum round lot of
100 shares requirement. Each such Eligible Purchaser may purchase shares of
Common Stock with funds in addition to their cash
28
<PAGE> 243
distributions in order to purchase (i) the minimum round lot of 100 shares, or
(ii) shares in addition to the number of shares for which their cash
distribution will be applied, subject to prorata limitations in the event of
oversubscription. No fractional shares will be sold.
Purchase Price
The price at which the Common Stock offered hereby will be issued will
be the average price of the Common Stock as reported by the NYSE for the period
between ________ and __________, 1998.
New York Stock Exchange and Pacific Exchange Listings
The Common Stock is traded on the NYSE and the Pacific Exchange under
the symbol "SFY." Application will be made to list the Shares offered hereby
on the NYSE and the Pacific Exchange.
Closing Date
The Company will issue checks representing full or partial
distributions and/or stock certificates representing the shares of Common Stock
subscribed for hereunder approximately forty-five (45) days after the date of
the Prospectus Supplement (the "Closing Date"), unless earlier terminated or
extended by the Company.
Due Date
All subscriptions, revocations of prior subscriptions or additional
required consideration must be received no later than thirty (30) days after
the date of the Prospectus Supplement (the "Due Date"), unless extended by the
Company.
Oversubscription
In the event this Offering is oversubscribed, all subscribing Eligible
Purchasers will first be sold a round lot of 100 shares and then, if
applicable, that number of shares of Common Stock the purchase price of which
is equal to such Eligible Purchaser's cash distribution, rounded down to the
next whole share. Any remaining shares will be sold on a prorata basis based
on the number of shares such subscribers wish to purchase.
Revocation
Eligible Purchasers may revoke their subscriptions to purchase of the
Shares offered hereby at any time until the Due Date by delivering or faxing a
letter so stating or a later dated subscription agreement, either of which must
be signed by such revoking subscribers, to the Company at 16825 Northchase
Drive, Suite 400, Houston, Texas 77060, fax number (281) 874-2818; Attention:
Investor Relations Department.
29
<PAGE> 244
TABLE OF CONTENTS
<TABLE>
<S> <C>
THE PARTNERSHIP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
CONFLICTS OF INTEREST . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
SPECIAL FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Background and Purpose of the Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Proposed Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Reasons for the Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Current Liquidating Distribution Lowers Volatility Risk . . . . . . . . . . . . . . . . . . . . . . . 8
Decreasing Cash Flow While Expenses Continue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Effect of Gas Prices on Value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Behind-Pipe Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Limited Partners' Tax Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Collective Analysis of Purchase Price; Premium over Fair Market Value . . . . . . . . . . . . . . . . . . . . 9
Determination of Premium Over Fair Market Value by the Company . . . . . . . . . . . . . . . . . . . . . . . 11
"Special Factors" Section in the Joint Proxy Statement/Prospectus . . . . . . . . . . . . . . . . . . . . . 12
Estimates of Liquidating Net Cash Distribution Amount if the Proposal is Approved . . . . . . . . . . . . . 12
Estimates of Net Cash Distributions Available from Continued Operations . . . . . . . . . . . . . . . . . . 14
Fairness of Proposed Sale of Assets to the Managing General Partner
as Compared to Continuing Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Fairness of Proposed Sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Managing General Partner Benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Simultaneous Proposals to Companion Partnerships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
VOTING ON THE PROPOSAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Vote Required . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Solicitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
PARTNERSHIP BUSINESS AND FINANCIAL CONDITION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Cash Distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Transactions Between the Managing General Partner and the Partnership . . . . . . . . . . . . . . . . . . . 23
No Trading Market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Principal Holders of Investor Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Approvals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
SUMMARY OF FEDERAL INCOME TAX CONSEQUENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Tax Treatment of Tax Exempt Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Sale of Property Interest and Liquidation of Partnership . . . . . . . . . . . . . . . . . . . . . . 25
Debt-Financed Property . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Tax Treatment of Investors Subject to Federal Income Tax Due to Debt-Financing . . . . . . . . . . . . . . . 26
</TABLE>
(i)
<PAGE> 245
<TABLE>
<S> <C>
Taxable Gain or Loss Upon Sale of Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Liquidation of the Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Capital Gain Tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Passive Loss Limitations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
SELECTED FINANCIAL INFORMATION AND PROFORMA FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . 27
OFFERING OF SHARES OF SWIFT ENERGY COMPANY COMMON STOCKIF INVESTORS APPROVE THE PROPOSAL . . . . . . . . . . . . . . 28
Voting Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Offer of Swift Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Investor Election to Purchase Shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
New York Stock Exchange and Pacific Exchange Listings . . . . . . . . . . . . . . . . . . . . . . . 29
Closing Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Due Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Oversubscription . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Revocation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
FORM OF PROXY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (A)
</TABLE>
(ii)
<PAGE> 246
ATTACHMENT A
April 17, 1998
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Attn: Special Transactions Committee FAIR MARKET VALUE ESTIMATE
Board of Directors SWIFT ENERGY MANAGED PENSION
ASSETS 1988-A, LTD.
97-003-133
Gentlemen:
At your request, we have audited the proved, probable and possible reserves and
future net cash flow as of December 31, 1997, prepared by Swift Energy Company
("Swift") for certain interests owned by the partners in Swift Energy Managed
Pension Assets 1988-A, Ltd. This audit has been conducted according to the
Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve
Information approved by the Board of Directors of the Society of Petroleum
Engineers on October 30, 1979. We have reviewed these properties and where we
disagreed with the Swift reserve estimates, Swift revised its estimates to be in
agreement.
From this audit, and in consultation with J.R. Butler and Company, our estimate
of the fair market value of this partnership is $342,030.
Fair market value as used herein is defined as that price that a willing buyer
will pay and a willing seller will accept at a given point in time, with neither
the buyer nor the seller under any compulsion to buy or sell, and both having
reasonable knowledge of all the material circumstances.
To estimate the fair market value attributable to the proved developed producing
reserves, the 10 percent discounted future net cash flow was multiplied by a
suitable factor (less than one) to account for the risk associated with the
reserves, operating expenses, and prices and to approximate tax consequences.
The internal rate of return and payout time were computed for this quantity and
compared with those at which current acquisitions are completed. Suitable
adjustments are then made to correspond to these two financial indices. Proved
developed nonproducing, proved undeveloped, probable and possible reserves
require capital investments and must be treated appropriately. For these cases,
the capital is added to the discounted net cash flow, then multiplied by a
suitable risk factor and the capital then subtracted. This has the effect that
capital is spent with certainty and the operating cash income is burdened with
the risk. Internal rate of return and payout time is calculated for each
estimate to establish reasonableness based upon the risk associated with the
reserve category.
<PAGE> 247
Swift Energy Company -2- April 17, 1998
The estimated future net cash flow is that cash flow which will be realized from
the sale of the estimated net reserves after deduction of royalties, ad valorem
and production taxes, direct operating costs and capital expenditures, when
applicable. Surface and well equipment salvage values and well plugging and
field abandonment costs have not been considered in the cash flow projections.
Future net cash flow as stated in this report is before the deduction of federal
income tax.
The following parameters are incorporated in the economic projections referenced
in this report. Initial oil prices are the existing prices on December 31, 1997,
and are escalated 3.5 percent per year beginning in 1999 through the year 2012
after adjusting for transportation and gravity variances. Initial natural gas
prices are those existing on December 31, 1997, and are escalated 3.5 percent
per year beginning in 1999 through the year 2012 after adjusting for
transportation and Btu content. Operating expenses are escalated at an annual
rate of 3.5 percent until the year 2012. The actual prices that will be received
and the associated costs may be more or less than those projected.
For those wells with sufficient production history, reserve estimates and rate
projections are based on the extrapolation of established performance trends.
Reserves for other producing and nonproducing properties have been estimated
from volumetric calculations and analogy with the performance of comparable
wells. The reserves referenced in this study are estimates only and should not
be construed as exact quantities. Future conditions may affect recovery of
estimated reserves and cash flow, and all categories of reserves may be subject
to revision as more performance data become available. The proved reserves are
estimated in accordance with the definitions included in the Securities and
Exchange Commission Regulation S-X, Rule 4-10(a) except for the price and cost
escalations. The definitions are included in part as Attachment I. The probable
and possible reserves conform to the definitions approved by the Society of
Petroleum Engineers, Inc. The definitions are included as Attachment II.
Extent and character of ownership, oil and gas prices, production data, direct
operating costs, capital expenditure estimates and other data provided by Swift
have been accepted as represented. The production data available to us were
through the month of October 1997, except in those instances in which data were
available through December. Interim production to December 31, 1997, has been
estimated. Operating expenses as supplied by Swift were not audited, but were
reviewed for reasonableness. No independent well tests, property inspections or
audits of operating expenses were conducted by our staff in conjunction with
this study. We did not verify or determine the extent, character, obligations,
status or liabilities, if any, arising from any current or possible future
environmental liabilities that might be applicable.
In order to audit the reserves, costs and future cash flows referenced in this
report, we have relied in part on geological, engineering and economic data
furnished by our client. Although we have made a best efforts attempt to acquire
all pertinent data and to analyze it carefully with methods accepted by the
petroleum industry, there is no guarantee that the volumes of oil or gas or the
cash flows projected will be realized. The reserve and cash flow projections
referenced in this report may require revision as additional data become
available.
<PAGE> 248
Swift Energy Company -3- April 17, 1998
H.J. Gruy and Associates, Inc. is unrelated to Swift and has no interest in the
properties included in this report. In particular:
1. We do not own a financial interest in Swift or its oil and gas
properties.
2. Our fee is not contingent on the outcome of our work or report.
3. We have not performed other services for or have any other
relationship with Swift that would affect our independence.
4. No instructions were given and no limitations were imposed by Swift
on the scope or methodology to be used by us in preparing such
estimates; we did not accept or incorporate any assumptions from
Swift, but merely called upon Swift to the extent customary in the
oil and gas industry to gather and provide certain background
information which we determined to be relevant and appropriate; we
determined what information to use; and how and to what extent such
information should be relied upon, in estimating the fair market
values shown above.
If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such person with the approval of our
client is invited to visit our offices at his expense so that he can evaluate
the assumptions made and the completeness and extent of the data available on
which our estimates are based.
Any distribution or publication of this report or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
/s/ JAMES H. HARTSOCK
James H. Hartsock, Ph.D., P.E.
Executive Vice President
JHH:akr
Attachment
<PAGE> 249
ATTACHMENT I
DEFINITIONS OF PROVED OIL AND GAS RESERVES(1)
PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquid which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
PROVED DEVELOPED OIL AND GAS RESERVES
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be 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.
PROVED UNDEVELOPED RESERVES
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
- --------
(1) Contained in Securities and Exchange Commission Regulation S-X,
Rule 4-10(a)
H.J. GRUY AND ASSOCIATES, INC. 1200 Smith Street, Suite 3040,
Houston, Texas 77002 (713) 739-1000
<PAGE> 250
ATTACHMENT II
PETROLEUM RESERVES DEFINITIONS
SOCIETY OF PETROLEUM ENGINEERS (SPE) AND WORLD PETROLEUM CONGRESS (WPC)(1)
Reserves are those quantities of petroleum which are anticipated to be
commercially recovered from known accumulations from a given date forward. All
reserve estimates involve some degree of uncertainty. The uncertainty depends
chiefly on the amount of reliable geologic and engineering data available at the
time of the estimate and the interpretation of these data. The relative degree
of uncertainty may be conveyed by placing reserves into one of two principal
classifications, either proved or unproved. Unproved reserves are less certain
to be recovered than proved reserves and may be further sub-classified as
probable and possible reserves to denote progressively increasing uncertainty in
their recoverability.
The intent of the SPE and WPC in approving additional classifications beyond
proved reserves is to facilitate consistency among professionals using such
terms. In presenting these definitions, neither organization is recommending
public disclosure of reserves classified as unproved. Public disclosure of the
quantities classified as unproved reserves is left to the discretion of the
countries or companies involved.
Estimation of reserves is done under conditions of uncertainty. The method of
estimation is called deterministic if a single best estimate of reserves is made
based on known geological, engineering and economic data. The method of
estimation is called probabilistic when the known geological, engineering, and
economic data are used to generate a range of estimates and their associated
probabilities. Identifying reserves as proved, probable, and possible has been
the most frequent classification method and gives an indication of the
probability of recovery. Because of potential differences in uncertainty,
caution should be exercised when aggregating reserves of different
classifications.
Reserves estimates will generally be revised as additional geologic or
engineering data become available or as economic conditions change. Reserves do
not include quantities of petroleum being held in inventory, and may be reduced
for usage of processing losses if required for financial reporting.
Reserves may be attributed to either natural energy or improved recovery
methods. Improved recovery methods include all methods for supplementing natural
energy or altering natural forces in the reservoir to increase ultimate
recovery. Examples of such methods are pressure maintenance, cycling,
waterflooding, thermal methods, chemical flooding, and the use of miscible and
immiscible displacement fluids. Other improved recovery methods may be developed
in the future as petroleum technology continues to evolve.
PROVED RESERVES
Proved reserves are those quantities of petroleum which, by analysis of
geological and engineering data, can be estimated with reasonable certainty to
be commercially recoverable, from a given date forward, from known reservoirs
and under current economic conditions, operating methods, and government
regulations. Proved reserves can be categorized as developed or undeveloped.
If deterministic methods are used, the term reasonable certainty is intended to
express a high degree of confidence that the quantities will be recovered. If
probabilistic methods are used, there should be at least a 90% probability that
the quantities actually recovered will equal or exceed the estimate.
Establishment of current economic conditions should include relevant historical
petroleum prices and associated costs and may involve an averaging period that
is consistent with the purpose of the reserve estimate, appropriate contract
obligations, corporate procedures, and government regulations involved in
reporting these reserves.
In general, reserves are considered proved if the commercial producibility of
the reservoir is supported by actual production or formation tests. In this
context, the term proved refers to the actual quantities of petroleum reserves
and not just the productivity of the well or reservoir. In certain cases,
proved reserves may be assigned on the basis of well logs and/or core analysis
that indicate the subject reservoir is hydrocarbon bearing and is analogous to
reservoirs in the same area that are producing or have demonstrated the ability
to produce on formation tests.
The area of the reservoir considered as proved includes (1) the area delineated
by drilling and defined by fluid contacts, if any, and (2) the undrilled
portions of the reservoir that can reasonably be judged as commercially
productive on the basis of available geological and engineering data. In the
absence of data on fluid contacts, the lowest known occurrence of hydrocarbons
controls the proved limit unless otherwise indicated by definitive geological,
engineering or performance data.
- --------------------------
(1) Approved by the Board of Directors. Society of Petroleum Engineers (SPE),
Inc. on March 7, 1997.
<PAGE> 251
Reserves may be classified as proved if facilities to process and transport
those reserves to market are operational at the time of the estimate or there is
a reasonable expectation that such facilities will be installed. Reserves in
undeveloped locations may be classified as proved undeveloped provided (1) the
locations are direct offsets to wells that have indicated commercial production
in the objective formation, (2) it is reasonably certain such locations are
within the known proved productive limits of the objective formation, (3) the
locations conform to existing well spacing regulations where applicable, and (4)
it is reasonably certain the locations will be developed. Reserves from other
locations are categorized as proved undeveloped only where interpretations of
geological and engineering data from wells indicate with reasonable certainty
that the objective formation is laterally continuous and contains commercially
recoverable petroleum at locations beyond direct offsets.
Reserve which are to be produced through the application of established improved
recovery methods are included in the proved classification when (1) successful
testing by a pilot project or favorable response of an installed program in the
same or an analogous reservoir with similar rock and fluid properties provides
support for the analysis on which the project was based, and, (2) it is
reasonably certain that project will proceed. Reserves to be recovered by
improved recovery methods that have yet to be established through commercially
successful applications are included in the proved classification only (1) after
a favorable production response from the subject reservoir from either (a) a
representative pilot or (b) an installed program where the response provides
support for the analysis on which the project is based and (2) it is reasonably
certain the project will proceed.
UNPROVED RESERVES
Unproved reserves are based on geologic and/or engineering data similar to that
used in estimates of proved reserves; but technical, contractual, economic, or
regulatory uncertainties preclude such reserves being classified as proved.
Unproved reserves may be further classified as probable reserves and possible
reserves.
Unproved reserves may be estimated assuming future economic conditions different
from those prevailing at the time of the estimate. The effect of possible future
improvements in economic conditions and technological developments can be
expressed by allocating appropriate quantities of reserves to the probable and
possible classifications.
PROBABLE RESERVES
Probable reserves are those unproved reserves which analysis of geological and
engineering data suggests are more likely than not to be recoverable. In this
context, when probabilistic methods are used, there should be a least a 50%
probability that the quantities actually recovered will equal or exceed the sum
of estimated proved plus probable reserves.
In general, probable reserves may include (1) reserves anticipated to be proved
by normal step-out drilling where subsurface control is inadequate to classify
these reserves as proved, (2) reserves in formations that appear to be
productive based on well log characteristics but lack core data or definitive
tests and which are not analogous to producing or proved reservoirs in the area,
(3) incremental reserves attributable to infill drilling that could have been
classified as proved if closer statutory spacing had been approved at the time
of the estimate, (4) reserves attributable to improved recovery methods that
have been established by repeated commercially successful applications when (a)
a project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir characteristics appear favorable for commercial application, (5)
reserves in an area of the formation that appears to be separated from the
proved area by faulting and the geologic interpretation indicates the subject
area is structurally higher than the proved area, (6) reserves attributable to a
future workover, treatment, re-treatment, change of equipment, or other
mechanical procedures, where such procedure has not been proved successful in
wells which exhibit similar behavior in analogous reservoirs, and (7)
incremental reserves in proved reservoirs where an alternative interpretation of
performance or volumetric data indicates more reserves than can be classified as
proved.
POSSIBLE RESERVES
Possible reserves are those unproved reserves which analysis of geological and
engineering data suggests are less likely to be recoverable than probable
reserves. In this context, when probabilistic methods are used, there should be
a least a 10% probability that the quantities actually recovered will equal or
exceed the sum of estimated proved plus probable plus possible reserves.
In general, possible reserves may include (1) reserves which, based on
geological interpretations, could possibly exist beyond areas classified as
probable, (2) reserves in formations that appear to be petroleum bearing based
on log and core analysis but may not be productive at commercial rates, (3)
incremental reserves attributed to infill drilling that are subject to technical
uncertainty, (4) reserves attributed to improved recovery methods when (a) a
project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir
<PAGE> 252
characteristics are such that a reasonable doubt exists that the project will be
commercial, and (5) reserves in an area of the formation that appears to be
separated from the proved area by faulting and geological interpretation
indicates the subject area is structurally lower than the proved area.
RESERVE STATUS CATEGORIES
Reserve status categories define the development and producing status of wells
and reservoirs.
DEVELOPED: Developed reserves are expected to be recovered from existing
wells including reserves behind pipe. Improved recovery reserves are
considered developed only after the necessary equipment has been installed,
or when the costs to do so are relatively minor. Developed reserves may be
sub-categorized as producing or non-producing.
PRODUCING: Reserves subcategorized as producing are expected to be
recovered from completion intervals which are open and producing at the
time of the estimate. Improved recovery reserves are considered
producing only after the improved recovery project is in operation.
NON-PRODUCING. Reserves subcategorized as non-producing include shut-in
and behind-pipe reserves. Shut-in reserves are expected to be recovered
from (1) completion intervals which are open at the time of the
estimate but which have not started producing, (2) wells which were
shut-in for market conditions or pipeline connections (3) wells not
capable of production for mechanical reasons. Behind-pipe reserves are
expected to be recovered from zones in existing wells, which will
require additional completion work or future recompletion prior to the
start of production.
UNDEVELOPED RESERVES: Undeveloped reserves are expected to be recovered:
(1) from new wells on undrilled acreage, (2) from deepening existing wells
to a different reservoir, or (3) where a relatively large expenditure is
required to (a) recomplete an existing well or (b) install production or
transportation facilities for primary or improved recovery projects.
<PAGE> 253
ATTACHMENT B
APRIL 17, 1998
SWIFT ENERGY COMPANY
16825 Northchase Drive
Suite 400
Houston, Texas 77060
RE: FAIR MARKET VALUE OPINION
AS OF DECEMBER 31, 1997
SWIFT ENERGY MANAGED PENSION ASSETS
1988-A, LTD.
ATTENTION: SPECIAL TRANSACTIONS COMMITTEE
SWIFT ENERGY COMPANY BOARD OF DIRECTORS
At the request of SWIFT ENERGY COMPANY (SWIFT), J. R. BUTLER AND COMPANY
(JRBCO) has conducted an evaluation audit of the hydrocarbon reserves and
future net cash flow as of December 31, 1997, associated with 44 Acquisition
Programs located in the U.S.A. From this audit, and in consultation with H. J.
Gruy and Associates, Inc. (Gruy), JRBCO has generated its opinion of a "fair
market value" for these properties. The market values of the properties were
distributed to various partnerships based on ownership to determine the fair
market value of each partnership. In JRBCO'S opinion, utilizing the
distribution of properties into the proper partnerships, the estimated market
value of SWIFT ENERGY MANAGED PENSION ASSETS 1988-A, LTD. is $342,030.
Proved reserves in this instance are defined as those estimated volumes of
crude oil, condensate, natural gas, and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty to be commercially
recoverable in the future from known reservoirs under a reasonable price and
cost escalation scenario. Probable reserves are the estimated quantities of
commercially recoverable hydrocarbons associated with known accumulations which
are based on engineering and geological data similar to those used in the
estimates of proved reserves but, for various reasons, these data lack the
certainty required to classify the reserves as proved. Possible reserves are
the estimated quantities of commercially recoverable hydrocarbons associated
with known accumulations, which are based on engineering and geological data
which are less complete and less conclusive than the data used in estimates of
probable reserves. In some cases, economic or regulatory uncertainties may
dictate a probable or possible classification.
Recovery of proved reserves is not without risk but, as generally considered in
the industry, the risk of recovering probable reserves is substantially greater
than that associated with proved categories. Likewise, possible reserves are
less certain to be recovered than probable.
The reserves and future performance estimates were prepared utilizing standard
petroleum engineering methods. For properties with sufficient production
history,
1
<PAGE> 254
reserves estimates and rate projections were based primarily on extrapolation
of established performance trends and reconciled, whenever possible, with
volumetric and/or material balance calculations. For the non-producing zones
and undeveloped locations, reserves were determined by a combination of
volumetric calculations and analogy. Volumetrically determined reserves or
those determined by analogy are generally subject to greater qualifications
than reserves estimates supported by established production decline curves
and/or material balance calculations. Determination and classification of
proved reserves were performed (with exception of the use of escalated prices
and costs) in accordance with Securities and Exchange Commission guidelines.
The definitions used also conform to those promulgated by the Society of
Petroleum Engineers (SPE) and the World Petroleum Congresses (WPC).
The reserves and resulting "value estimates" included in this study are not
exact quantities. Future conditions may affect the recovery of estimated
reserves, revenue and net cash flow, and all categories of reserves may be
subject to revision and/or reclassification as more performance and well data
become available. Please note, the reserves estimates made by JRBCO were done
in conjuction with an evaluation audit and are not the result of in-depth field
studies. In conducting this audit JRBCO reviewed approximately 65% of SWIFT'S
proved "PV 10 value" (SEC PV10 as of December 31, 1997) for the total 44
Acquisition Programs.
Basic evaluation data were obtained principally from SWIFT and public sources.
The production data available to JRBCO were generally through August 1997.
Gas and liquid prices were year end (CY 1997) prices as used in SWIFT'S
December 31, 1997, SEC cash flow runs.
Estimates of drilling, completion and workover costs were based on information
supplied by SWIFT. Operating costs were also based on data supplied by SWIFT
in their Lease Operating Statement which was reviewed by JRBCO. Surface and
well equipment salvage values and well plugging and field abandonment costs
were not considered in the revenue projections.
The estimates of future net cash flow used in market value calculations are
those revenues which should be realized from the sale of the estimated reserves
after deduction of royalties, ad valorem and production taxes, direct operating
costs and required capital expenditures, when applicable. Future net cash flow
as used in this evaluation is before the deduction of federal income tax.
Market value estimates were obtained by applying qualitative risk adjustments
considered appropriate for the various reserves categories and "profit factors"
(as applicable) against discounted future net cash flow values obtained from an
escalated cost and pricing scenario. Prices, costs and investments were
escalated at 3.5%/year for 15 years. Final market value estimates were derived
in conjunction and consultation with Gruy.
In the conduct of our review, we have not independently verified the accuracy
and completeness of information and data furnished by SWIFT with respect to
ownership interests, oil and gas production volumes and rates, historical costs
of operation and development, product prices, agreements relating to current
and future operations and sales of production and other information relative to
such things as timing or scheduling of drilling or recompletion operations.
Field inspections were not made in connection with the preparation of this
report. Furthermore, no judgments were made relative to environmental or other
legal liabilities.
It should be recognized that any oil or gas reserves estimate or forecast of
production and income is a function of engineering and geological
interpretation and judgment. Such estimates should, therefore, be accepted and
used with the understanding that technical data, economic criteria or
regulatory information obtained subsequent to a study may justify revisions
which could increase or decrease the original estimates of reserves and value.
Neither JRBCO, nor any of its personnel, have any direct or indirect interest
in SWIFT or its affiliates. JRBCO is an independent consulting firm as
provided in the Standards Pertaining to the Estimating and Auditing of Oil and
Gas Reserves Information promulgated by the Society of Petroleum Engineers.
2
<PAGE> 255
JRBCO'S compensation is not contingent upon the results of its reserves
estimates, cash flow analyses or "market value opinion" which result from its
review of the subject properties.
READ AND APPROVED:
/s/ BRIAN E. AUSBURN
- ---------------------------
BRIAN E. AUSBURN, PRESIDENT
DATE: April 17, 1998
----------------------
BEA:mlc
3
<PAGE> 256
ATTACHMENT C
April 20, 1998
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, TX 77060
Attention: Special Transactions Committee
Swift Energy Company Board of Directors
Gentlemen:
Pursuant to that certain letter agreement dated February 27, 1998 (the
"Agreement") between the Special Transactions Committee (the "Committee") of the
Board of Directors of Swift Energy Company ("Swift" or the "Company") and CIBC
Oppenheimer Corp. ("CIBC Oppenheimer"), you have retained CIBC Oppenheimer to
prepare an independent financial analysis as to the estimated fair market value
(the "CIBC Oppenheimer Valuation") of various interests (the "Assets") in oil
and gas properties (the "Properties'), which Assets are owned by Swift Energy
Managed Pension Assets 1988-A Ltd. (the "Partnership") of which the Company is
the managing general partner ("General Partner"). CIBC Oppenheimer performed a
similar analysis for 62 other partnerships (the "Partnerships") of which the
Company is the General Partner. It is CIBC Oppenheimer's understanding that the
General Partner has proposed to purchase substantially all of the Partnership's
Assets and, in turn, dissolve and wind up the Partnership. It is also CIBC
Oppenheimer's understanding that the Committee has also retained the reserve
engineering firms of H.J. Gruy & Associates, Inc. and J.R. Butler & Company
(collectively, the "Engineering Consultants") to prepare a separate analysis as
to the estimated fair market value of the Assets (the "Engineering Consultants'
Valuation").
In arriving at the CIBC Oppenheimer Valuation, we, among other things:
(i) Reviewed the historical financial returns to the limited
partners of the Partnership;
(ii) Held discussions with senior management of the Company as to
the Partnership's operational and financial prospects;
<PAGE> 257
Swift Energy Company
April 20,1998
Page 2
(iii) Held discussions with senior management of the Company
regarding the general characteristics of the Properties
underlying the Assets, including location, productive
geological formations, future development potential and oil
and gas marketing arrangements;
(iv) Held discussions with the Engineering Consultants regarding
the general characteristics of the Properties underlying the
Assets, including location, productive geological formations
and future development potential;
(v) Reviewed the reserve engineering reports supplied to us by the
Engineering Consultants and, particularly, reviewed the
estimated future net cash flow to be generated from the
production of proved reserves of the Properties underlying the
Assets discounted to present value using an annual discount
rate of 10% (the "PV-10 Value") dated as of December 31, 1997;
these amounts were calculated net of estimated production
costs and future development costs, using prices and costs in
effect as of a certain date, without escalation and without
giving effect to non-property related expenses such as future
income tax expense or depreciation, depletion and
amortization;
(vi) Reviewed the Engineering Consultants' Valuation of the
Properties underlying the Assets;
(vii) Reviewed historical operating and financial results of the
Properties underlying the Assets which included PV-10 Value,
proved reserves on a barrel of oil equivalent ("BOE") basis
and projected earnings before interest, taxes and
depreciation, depletion and amortization ("EBITDA") as
prepared by the Engineering Consultants and discussed with
senior management of the Company;
(viii) Reviewed and analyzed financial terms of similar transactions
in which public oil and gas companies liquidated partnerships
of which they were the general partner;
(ix) Reviewed and analyzed transactions involving the sale of oil
and gas companies we deemed comparable to the Partnership(s)
individually and collectively and to the Company;
<PAGE> 258
Swift Energy Company
April 20, 1998
Page 3
(x) Reviewed and analyzed transactions involving the sale of oil
and gas properties we deemed comparable to the Properties
underlying the Assets;
(xi) Reviewed financial and market data for certain public
companies we deemed comparable to the Partnership(s)
individually and collectively and to the Company; and
(xii) Performed such other analyses and reviewed such other
information as we deemed appropriate.
In determining the CIBC Oppenheimer Valuation, we have relied upon and assumed,
without independent verification or investigation and at the direction of the
Committee, (i) the accuracy and completeness of all of the financial and other
information available to us from public sources or provided to us by the Company
and their representatives (including the Engineering Consultants), (ii) that the
reserve engineering reports supplied to us by the Engineering Consultants as
described in clause (v) above have been reasonably prepared and are based on
their best business judgment, (iii) that the information with respect to the
Partnership's ownership of the Assets, as provided to the Engineering
Consultants and to us was accurate in all respects, (iv) with respect to the
historical operating and financial results and projections provided to us as
described in clause and (vii) above, that such information and projections were
reasonably prepared and were based on the best currently available information,
estimates and good faith judgment of the Company's management and their
representatives (including the Engineering Consultants).
Not being experts in the geological evaluation of oil and gas reserves, we have,
with your consent, relied without independent verification upon the audit of the
reserve estimates prepared by the Engineering Consultants for the purpose of
estimating fair market value of the Assets. In addition, we have not made a
physical inspection of the Properties underlying the Assets, nor have we made
any independent evaluations, appraisals or inspections of the Company's or the
Partnership's other assets or the Company's or the Partnership's liabilities
(contingent or otherwise). We have not reviewed any relevant agreements which
may exist between the General Partner and the limited partners governing the
Partnership, nor have we considered the effect which the ownership structure of
the Partnership and the terms of the agreements of the Partnership may have upon
the fairness of the consideration offered by any general partner of the
Partnership. We have not reviewed the books and records of the Partnership and
have assumed, with your consent, that the Partnership's ownership interests in
the Properties underlying the Assets, as provided to us by you, is true and
correct.
<PAGE> 259
Swift Energy Company
April 20, 1998
Page 4
The CIBC Oppenheimer Valuation is based upon analyses of the foregoing factors
in light of our assessment of general economic, financial, market and other
conditions and circumstances as of the date of this letter and any changes in
such conditions and circumstances may affect the validity or fairness of the
CIBC Oppenheimer Valuation. CIBC Oppenheimer disclaims any obligations to
update, revise or reaffirm the CIBC Oppenheimer Valuation. The CIBC Oppenheimer
Valuation reflects our estimate of the consideration that could have been
received by the Partnership in a sale of the Assets in an orderly manner in a
private market transaction in which neither buyer nor seller is under any
compunction to complete such transaction. The CIBC Oppenheimer Valuation falls
within a range of values which we believe, subject to the foregoing conditions,
represent possible fair market value estimates of the Partnership's interest in
the Assets. The CIBC Oppenheimer Valuation should not be viewed as a guarantee
of the price that a willing buyer might have paid for the Assets.
CIBC Oppenheimer, as part of its investment banking services, is regularly
engaged in the valuation of businesses and securities in connection with
mergers, acquisitions, underwritings, sales and distributions of listed and
unlisted securities and private placements. CIBC Oppenheimer has provided
certain investment banking and financial advisory services to the Company from
time to time, including acting as co-manager of the Company's Convertible
Subordinated Notes financing in November 1996 and lead manager of the public
offering of the Company's Common Stock in July 1995, and may be involved in
future investment banking activities on behalf of the Company. CIBC Oppenheimer
will also receive a fee upon delivery of this CIBC Oppenheimer Valuation. In the
ordinary course of business, CIBC Oppenheimer actively trades in the equity
securities of the Company for CIBC Oppenheimer's own account and for the
accounts of CIBC Oppenheimer's customers and, accordingly, may at any time hold
a long or short position in such securities.
Based upon and subject to the foregoing, and based upon such other matters as we
consider relevant, it is CIBC Oppenheimer's estimate that the value of Swift
Energy Managed Pension Assets 1988-A Ltd. interest in the Assets as of the date
hereof is $347,204.
This letter is being provided for the use of the Committee in its evaluation of
a possible proposal that the Partnership sell the Assets to the Managing General
Partner and dissolve and wind up its affairs. This letter is not intended to
confer rights or remedies upon any stockholder of the Company or any partner of
the Partnership and may not be relied upon by any person or entity other than
the Committee. Neither this letter nor the CIBC
<PAGE> 260
Swift Energy Company
April 20, 1998
Page 5
Oppenheimer Valuation may be published or otherwise used or referred to, in
whole or part, nor shall any public reference to CIBC Oppenheimer, this letter
or the CIBC Oppenheimer Valuation be made without the prior written consent of
CIBC Oppenheimer; provided, however, that the Company and the Partnership may
include a copy of this letter and a reference to CIBC Oppenheimer in the proxy
statement to be distributed to limited partners of the Partnership in connection
with the solicitation of the approval of the proposal that the Partnership sell
the Assets to the General Partner and dissolve and wind up its affairs. Neither
this letter nor the CIBC Oppenheimer Valuation constitutes a recommendation to
any partner of the Partnership as to how such partner should vote on or respond
to the proposal that the Partnership sell the Assets to the General Partner and
dissolve and wind up its affairs.
Sincerely yours,
/s/ BRIAN MYERS
CIBC Oppenheimer Corp.
<PAGE> 261
ATTACHMENT D
February 10, 1998
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
SWIFT ENERGY MANAGED PENSION ASSETS 1988-A
97-003-133
Gentlemen:
At your request, we have made an audit of the reserves and future net cash flow
as of December 31, 1997, prepared by Swift Energy Company ("Swift") for certain
interests in Swift Energy Managed Pension Assets 1988-A. This audit has been
conducted according to the standards pertaining to the estimating and auditing
of oil and gas reserve information approved by the Board of Directors of the
Society of Petroleum Engineers on October 30, 1979. We have reviewed these
properties and where we disagreed with the Swift reserve estimates, Swift
revised its estimates to be in agreement. The estimated net reserves, future net
cash flow and discounted future net cash flow are summarized by reserve category
in Table 1 for both the 100% Fund Level Partnership and the Limited Partnership
Interest.
The discounted future net cash flow is not represented to be the fair market
value of these reserves and the estimated reserves included in this report have
not been adjusted for risk.
The estimated future net cash flow shown is that cash flow which will be
realized from the sale of the estimated net reserves after deduction of
royalties, ad valorem and production taxes, direct operating costs and required
capital expenditures, when applicable. Surface and well equipment salvage values
and well plugging and field abandonment costs have not been considered in the
cash flow projections. Future net cash flow as stated in this report is before
the deduction of state and federal income tax.
In the economic projections, prices, operating costs and development costs
remain constant for the projected life of each lease.
The reserves included in this study are estimates only and should not be
construed as exact quantities. Future conditions may affect recovery of
estimated reserves and cash flow, and all categories of reserves may be subject
to revision as more performance data become available. Proved reserves are
estimated in accordance with the definitions contained in Securities and
Exchange Commission Regulation S-X, Rule 4-10(a). The definitions are included
in part as Attachment I.
Extent and character of ownership, oil and gas prices, production data, direct
operating costs, capital expenditure estimates and other data provided by Swift
have been accepted as represented. The production data available to us were
through the month of October 1997, except in those instances in which data were
available through December. Interim production to December 31, 1997, has been
estimated. No independent well tests, property inspections or audits of
operating expenses were conducted by our staff in conjunction with this study.
We did not verify or determine the extent, character, obligations, status or
liabilities, if any, arising from any current or possible future environmental
liabilities that might be applicable.
<PAGE> 262
Swift Energy Company -2- February 10, 1998
In order to audit the reserves, costs and future net cash flows shown in this
report, we have relied in part on geological, engineering and economic data
furnished by our client. Although we have made a best efforts attempt to acquire
all pertinent data and to analyze it carefully with methods accepted by the
petroleum industry, there is no guarantee that the volumes of oil or gas or the
cash flows projected will be realized.
Production rates may be subject to regulation and contract provisions, and may
fluctuate according to market demand or other factors beyond the control of the
operator. The reserve and cash flow projections presented in this report may
require revision as additional data become available.
We are unrelated to Swift and we have no interest in the properties included in
the information reviewed by us. In particular:
1. We do not own a financial interest in Swift or its oil and gas
properties.
2. Our fee is not contingent on the outcome of our work or report.
3. We have not performed other services for or have any other
relationship with Swift that would affect our independence.
If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such person with the approval of our
client is invited to visit our offices at his expense so that he can evaluate
the assumptions made and the completeness and extent of the data available on
which our estimates are based.
Any distribution or publication of this report or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
/s/ JAMES H. HARTSOCK
James H. Hartsock, Ph.D., P.E.
Executive Vice President
<PAGE> 263
TABLE 1
100% FUND LEVEL PARTNERSHIP INTEREST
<TABLE>
<CAPTION>
Estimated Estimated
Net Reserves Future Net Cash Flow
------------------------ --------------------------
Oil & Discounted
Condensate at 10%
(Barrels) Gas (Mcf) Nondiscounted Per Year
---------- --------- ------------- ----------
<S> <C> <C> <C> <C>
Proved Developed 6,779 475,422 $ 893,122 $ 477,924
Proved Undeveloped -0- 3,433 $ 9,942 $ 6,594
----- ------- --------- ---------
Total Proved 6,779 478,855 $ 903,064 $ 484,518
G&A $(135,460) $ (72,723)
----- ------- --------- ---------
Total 6,779 478,855 $ 767,604 $ 411,795
</TABLE>
LIMITED PARTNERSHIP INTEREST
<TABLE>
<CAPTION>
Estimated Estimated
Net Reserves Future Net Cash Flow
------------------------ --------------------------
Oil & Discounted
Condensate at 10%
(Barrels) Gas (Mcf) Nondiscounted Per Year
---------- --------- ------------- ----------
<S> <C> <C> <C> <C>
Proved Developed 6,101 427,878 $ 802,908 $ 429,709
Proved Undeveloped -0- 3,090 $ 8,646 $ 5,661
----- ------- --------- ---------
Total Proved 6,101 430,968 $ 811,554 $ 435,370
G&A $(121,733) $ (65,353)
----- ------- --------- ---------
Total 6,101 430,968 $ 689,821 $ 370,017
</TABLE>
PENN88-A.TBL
H.J. GRUY AND ASSOCIATES, INC. 1200 Smith Street, Suite 3040,
Houston, Texas 77002 (713) 739-1000
<PAGE> 264
ATTACHMENT I
DEFINITIONS OF PROVED OIL AND GAS RESERVES(1)
PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquid which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
PROVED DEVELOPED OIL AND GAS RESERVES
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be 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.
PROVED UNDEVELOPED RESERVES
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
- --------
(1) Contained in Securities and Exchange Commission Regulation S-X,
Rule 4-10(a)
H.J. GRUY AND ASSOCIATES, INC. 1200 Smith Street, Suite 3040,
Houston, Texas 77002 (713) 739-1000
<PAGE> 265
FORM OF PROXY
SWIFT ENERGY MANAGED PENSION ASSETS PARTNERSHIP 1988-A, LTD.
THIS PROXY IS SOLICITED BY THE MANAGING GENERAL PARTNER FOR A
SPECIAL MEETING OF LIMITED PARTNERS TO BE HELD ON _______, 1998
The undersigned hereby constitutes and appoints A. Earl Swift, Bruce
H. Vincent, Terry E. Swift or John R. Alden, duly authorized officers of Swift
Energy Company acting in its capacity as Managing General Partner of the
Partnership, or any of them, as Proxies, each with full power to appoint his
substitute, and hereby authorizes the Proxies or any of them to represent the
undersigned at a Special Meeting of the Limited Partners (the "Meeting") of
SWIFT ENERGY MANAGED PENSION ASSETS PARTNERSHIP 1988-A, LTD. (the
"Partnership") to be held on ______, 1998 at 4:00 p.m. Houston time, at 16825
Northchase Drive, Houston, Texas, and any adjournments thereof, and to vote as
designated, on the matter specified below, the Partnership Units standing in
the name of the undersigned on the books of the Partnership (or which the
undersigned may be entitled to vote) on the record date for the Meeting, and
hereby revokes any proxy or proxies heretofore given by the undersigned.
<TABLE>
<S> <C> <C> <C>
1. The adoption of a proposal FOR AGAINST ABSTAIN
("Proposal") for the ultimate sale
of substantially all of the assets [ ] [ ] [ ]
of the Partnership to the Managing
General Partner and the dissolution,
winding up and termination of the
Partnership. The undersigned hereby
directs said proxies to vote:
</TABLE>
2. In their discretion, the proxies are authorized to vote upon such other
matters as may properly come before the meeting or any adjournments or
postponements thereof.
THIS PROXY WHEN PROPERLY EXECUTED, WILL BE VOTED IN ACCORDANCE WITH
THE DIRECTIONS MADE HEREON. IF NO DIRECTION IS MADE, IT WILL BE VOTED FOR THE
PROPOSAL.
Receipt of the Partnership's Notice of Special Meeting of Limited
Partners and Proxy Statement dated ______, 1998 is acknowledged.
PLEASE SIGN EXACTLY AS NAME APPEARS BELOW AND RETURN THE PROXY IN THE
ENCLOSED, POSTAGE-PAID, PRE-ADDRESSED ENVELOPE BY _________, 1998.
SIGNATURE DATE
----------------------------- ---------------
SIGNATURE DATE
----------------------------- ---------------
SIGNATURE DATE
----------------------------- ---------------
IF LIMITED PARTNERSHIP UNITS ARE HELD JOINTLY, ALL JOINT TENANTS MUST
SIGN. WHEN SIGNING AS ATTORNEY, EXECUTOR, ADMINISTRATOR, TRUSTEE OR GUARDIAN,
PLEASE GIVE FULL TITLE AS SUCH. IF A CORPORATION, PLEASE SIGN IN FULL
CORPORATE NAME BY PRESIDENT OR OTHER AUTHORIZED OFFICER. IF A PARTNERSHIP,
PLEASE SIGN IN PARTNERSHIP NAME BY AUTHORIZED PERSON.
<PAGE> 266
SWIFT ENERGY INCOME PARTNERS 1989-B, LTD.
(THE "PARTNERSHIP")
SUPPLEMENT
TO
JOINT PROXY STATEMENT/PROSPECTUS
DATED _________, 1998
SPECIAL MEETINGS OF THE PARTNERSHIPS
AND
OFFERING OF COMMON STOCK OF
SWIFT ENERGY COMPANY
For the definition of capitalized terms herein which are not otherwise
defined, see "Glossary" in the Joint Proxy Statement/Prospectus. Other
discussions which are cross-referenced in this Supplement are contained in the
Joint Proxy Statement/Prospectus, unless otherwise noted.
Swift Energy Company ("Swift" or the "Company") is the Managing
General Partner ("Managing General Partner") of 63 Texas limited partnerships
(the "Partnerships"), including the Partnership, formed between 1986 and 1994
to invest in producing oil and gas properties. Swift is asking limited
partners (referred to herein as "Investors") in the Partnership (and similarly
in the other 62 Partnerships) to approve a Proposal to sell all of the
Partnership's oil and gas assets to the Managing General Partner (the
"Proposal") for $3,314,557, which is a purchase price derived by choosing the
higher of two estimates of fair market value of those assets determined by
three independent Appraisers, and adding to that higher number a 7.5% premium.
If the Proposal is approved by Investors in the Partnership and its
Companion Partnership, after the sale of all of its oil and gas assets the
Partnership will dissolve, wind up and terminate. The Partnership will receive
cash for its oil and gas assets, which in turn is to be distributed to the
Investors in the Partnership (along with the net of all assets less liabilities
of the Partnership) in accordance with their respective percentage ownership
interests in the Partnership. If Investors in the Partnership approve the
Proposal, then each Investor can elect, in their sole individual discretion, to
receive shares of Common Stock of the Company (without payment of any brokerage
commissions) instead of some or all of the cash which they are entitled to
receive upon the Partnership's liquidation.
The reasons for and effects of the Proposals may be different for
investors in each of the Partnerships. This Supplement has been prepared to
highlight for the Investors in the Partnership the particular risks, effects
and fairness of the Proposal to the Investors in the Partnership and to provide
information on the Partnership to its Investors, in connection with the
solicitation of proxies by the
<PAGE> 267
Managing General Partner for use at the Special Meeting of the Investors in the
Partnership in voting upon the Proposal and to transact such other business as
may be properly presented at the Special Meeting or any adjournments or
postponements thereof.
BOTH THE VOTE UPON THE PROPOSAL AND ANY ELECTION MADE BY AN INDIVIDUAL
INVESTOR TO RECEIVE SHARES OF SWIFT ENERGY COMPANY COMMON STOCK ARE SUBJECT TO
NUMEROUS RISK FACTORS, INCLUDING THOSE HIGHLIGHTED BELOW. SEE "RISK FACTORS"
IN THIS SUPPLEMENT AND IN THE JOINT PROXY STATEMENT/PROSPECTUS FOR A FULL
DISCUSSION OF ALL RISK FACTORS.
o Substantial conflicts of interest exist because if the Proposal is
approved by the Partnership and its Companion Partnership, the
Managing General Partner will purchase all of the oil and gas assets
from the Partnership while it serves as its Managing General Partner.
o The purchase price for the Partnership's Property Interests may not be
the highest possible price.
o No independent representative negotiated the terms of the purchase
price with the Managing General Partner.
o No fairness opinion was acquired regarding the fairness of the
purchase price.
o The Managing General Partner may profit from acquisition of the
Partnership's oil and gas assets by investing capital in order to
develop non-producing reserves of the acquired Property Interests and
possibly through improvement in oil and gas prices.
o Estimates of distributions to Investors from continuing operations of
the Partnership for the life of its reserves are higher than amounts
anticipated to be received if Investors vote in favor of the Proposal.
See "Special Factors--Fairness of Proposal of Sale of Assets as
Compared to Continuing Operations."
o An election by an Investor to receive shares of Swift Common Stock in
lieu of cash distributable to Investors subjects such Investors to the
risks of investing in the Company.
This Supplement is dated ______________, 1998
2
<PAGE> 268
THE PARTNERSHIP
The Partnership was formed over nine years ago and owns working
interests in producing oil and gas properties in six states in which its
companion partnership, Swift Energy Managed Pension Assets Partnership 1989-B,
Ltd. ("Companion Partnership"), formed at approximately the same time and also
managed by the Managing General Partner, owns the non-operating interests. The
Partnership had expended all of its original capital contributions by the end
of October 1989. The Partnership's oil and gas properties are generally evenly
divided between gas and oil properties, with approximately 50% of the
Partnership's 1997 production and approximately 60% of its total proved
reserves at December 31, 1997, attributable to natural gas. The Partnership
has, from time to time, performed workovers and recompletions on wells in which
the Partnership has Property Interests, using funds advanced by the Managing
General Partner or third parties to perform these operations, which amounts
have been subsequently repaid. The Partnership owns interest in 643 wells in 34
fields.
The following table presents information on those fields in which the
Partnership has Property Interests which constitute 10% or more of the
Partnership's PV-10 Value at December 31, 1997. The Partnership's "PV-10
Value" is the estimated future net cash flows (using unescalated prices) from
production of proved reserves attributed to the Partnership's Property
Interests, discounted to present value at 10% per annum. Attachment D to this
Supplement is the report dated February 10, 1998 of the audit by H.J. Gruy and
Associates, Inc., Independent Petroleum Consultants, of the oil and gas
reserves underlying the Partnership's Property Interests, and future net cash
flow expected from the production of those reserves as of December 31, 1997,
presented both for the Partnership as a whole and as to those reserves solely
attributable to the Investors in the Partnership. This report has not been
updated to include the effect of production since year-end 1997. In estimating
these reserves, the Managing General Partner, in accordance with criteria
prescribed by the Securities and Exchange Commission, has used year-end 1997
prices, without escalation, except in those instances where fixed and
determinable gas price escalations are covered by contracts, limited to the
price the Partnership reasonably expects to receive. The Managing General
Partner is not aware of any favorable or adverse event causing a significant
change in the estimated amount (as set forth in Attachment D hereto, which is
the report of H.J. Gruy and Associates, Inc.) of proved reserves of the
properties in which the Partnership owns an interest between December 31, 1997
and the date of this Supplement.
The information below includes the location of each field in which the
Partnership has an interest, the number of wells and operators, together with
information on the percentage of the Partnership's total PV-10 Value on
December 31, 1997 attributable to each of these fields. Information is also
provided regarding the percentage of the Partnership's 1997 production (on a
volumetric basis) from each of these fields. Of the remaining other fields in
which the Partnership owns a Property Interest, 21 of such fields each comprise
less than 1% of the Partnership's PV-10 Value at December 31, 1997, and the
PV-10 Value of each of the other ten fields averages less than 3% of the
Partnership's PV- 10 Value at the same date.
3
<PAGE> 269
<TABLE>
<CAPTION>
Shawnee 31
AWP Townsite Caprito Other
Field Field Field Fields
---------------------------------------------------------
<S> <C> <C> <C> <C>
McMullen Pottawatomie Ward AL(2)
County and State County, County, County, AR(3)
Texas OK OK LA(5)
OK(10)
TX(7)
WY(4)
Number of Wells 96 34 36 477
Swift Vintage Titan Swift
Petroleum; Resources and 42
Operator(s) Estoril others
Producing
% of 12/31/97 PV-10 Value 40% 14% 8% 38%
% of 1997 Production Volumes 25% 18% 10% 47%
</TABLE>
The Partnership's total assets at year-end 1997 were $3,871,732 and
the PV-10 Value of its total proved reserves at the same date was $4,009,417.
Based upon the audit of the Partnership's Total Proved Reserves at year-end
1997, those reserves were comprised of the following three categories:
Proved Producing(1) 83%
Behind-Pipe(2) 5%
Non-Developed(3) 12%
---
100%
===
- -------------
(1) Proved producing reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
(2) Behind-pipe reserves are proved reserves that will not contribute
to cash flows until recompletion projects have been implemented to place them
into production. The impact of these recompletion projects will also be limited
until the costs of implementation have been recovered. In general, it is not
appropriate to bring behind-pipe reserves into production until the formation
that is currently producing has been depleted. Premature recompletions can lead
to permanent reductions in a well's proved reserves.
(3) Non-developed reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Therefore,
significant additional expenditures are usually required before undeveloped
reserves can be produced.
Attachment Dis the annual reserves audit and independent reserves
report prepared by H.J. Gruy and Associates, Inc. as to the Partnership's
remaining proved oil and gas reserves available for production over a period in
excess of 15 years. These quantities have been given a value based upon prices
for oil and gas at December 31, 1997. The value is determined based upon the
assumption that these prices will remain in effect over the life of these
reserves. This value is then discounted at 10% per year to arrive at
4
<PAGE> 270
the value (in today's dollars) of these revenues ("PV-10 Value"). This PV-10
Value for the Partnership's Property Interests is $4,009,417. It is also
estimated that $343,575 in future capital costs must be spent to develop the
Partnership's non-producing reserves.
RISK FACTORS
o Although the fair market value of the Property Interests proposed to
be purchased from the Partnership by the Managing General Partner was
based upon a determination by three independent Appraisers, no opinion
was acquired as to the fairness of the ultimate purchase price, which
was determined in the Managing General Partner's sole judgment by
adding a 7.5% premium over the higher of the two fair market value
estimates for the Partnership's Property Interests determined by the
Appraisers. Therefore, the purchase price was not determined on an
impartial basis by a party not involved in the transaction, and
another party intent upon purchasing the Property Interests in the
Partnership might have offered a different purchase price. There is
no guarantee that the purchase price represents the highest possible
price that could be received for the Partnership's Property Interests
in all circumstances. It is possible that a higher (or lower) price
might be received if these assets were sold on another basis, such as
at auction or in negotiated sales. Furthermore, the assessment of the
value of the Partnership's proved non-producing reserves could vary
widely, given the typical discounting in valuing non-producing
reserves.
o The Managing General Partner did not retain an independent
representative to act on behalf of the Investors in the Partnership in
structuring and negotiating the terms or price of the Proposal or the
purchase price. The price at which it is proposed that the Company
purchase the Property Interests from the Partnership has not been
negotiated at arm's length and is subject to significant conflicts of
interest between the Company acting as the purchaser of such
properties while serving as the Managing General Partner of the
Partnership. If an independent representative had been retained for
the Partnership, the terms or price might have been different and
possibly more favorable to Investors.
o The fair market value (excluding the 7.5% premium) established for the
Partnership's Property Interests is based upon the Appraisers'
evaluation of that value. Year-end 1997 prices, along with other
current market factors, were used as a starting point for the
Appraisers' analysis, and prices and costs were then escalated at a
rate of 3.5% per year over 15 years. Substantial increases in the
prices for oil and gas in the future might result in Investors
receiving higher distributions from continued operations of the
Partnership, although the effect of any higher prices is somewhat
limited because the Partnership has already produced a substantial
majority of its oil and gas reserves.
o In order to effectuate the sale of its Property Interests, the
Proposal must not only be approved by the Partnership, but a similar
Proposal must be approved by the Companion Partnership. This
requirement exists because of the significant lowering of the value of
either (i) a working interest burdened by a large non- operating
interest controlled by a different party, or (ii) a non-operating
interest in properties the operations of which are controlled by a
third party. Therefore, even if the Investors in the Partnership
approve the Proposal to sell their Property Interests, this may not be
done without the approval of a similar Proposal by investors in the
Companion Partnership. If either Partnership does not approve its
Proposal, then the Managing General Partner will
5
<PAGE> 271
reassess the value of the Property Interests of each Partnership and
attempt to formulate a new proposal for the investors in each such
Partnership.
o Investors that are subject to federal income tax on an investment in
the Partnership are required to recognize gain or loss on the sale of
oil and gas assets by the Partnership and the subsequent liquidation
of the Partnership. The amount and character of the gain or loss
depends on certain factors specific to individual Investors. It is
anticipated that Investors that acquired their interests in the
original offering will recognize a gain for federal income tax
purposes. Any tax that may be due must be paid even if such Investors
choose to acquire Company Common Stock with some or all of their
proceeds from property sales. Investors also should consult their
individual tax advisors to determine whether they are subject to any
state tax. For a broader discussion of the tax consequences,
Investors should read "Federal Income Tax Consequences of Adoption of
the Proposals" in the Joint Proxy Statement/Prospectus, and "Summary
of Federal Income Tax Consequences" in this Supplement.
o Investors that are Tax Exempt Plans will be subject to taxation on the
Partnership's sale of property and the liquidation of the Partnership,
while other Tax Exempt Plans are not expected to be subject to
taxation on the sale and liquidation. See "Summary of Federal Income
Tax Consequences--Tax Treatment of Tax Exempt Plans--Debt-Financed
Property" in this Supplement.
o As currently proposed, Investors that subscribe for Company Common
Stock pursuant to this Offering may not receive some or all of the
cash which would otherwise be distributed to them as part of the
liquidating distribution of their Partnership. The amount of any cash
liquidating distribution they actually receive depends upon the
purchase price to be paid for any Company Common Stock they elect to
and are entitled to receive pursuant to the terms of this Offering.
For federal income tax purposes, Investors subscribing for shares of
Company Common Stock will be treated as though they had purchased
those shares for cash, even though they never had actual possession of
the cash used to acquire the shares. Additionally, the fact that such
Investors elect to acquire Company Common Stock rather than receive
cash in liquidation of their Partnership interests will not affect the
federal income tax consequences attending the liquidation of their
Partnership interests. Because the purchase of shares of Company
Common Stock will reduce the cash received by Investors upon the
Partnership's liquidation, to the extent that Investors owe federal
income tax as a result of the liquidation, they may not receive
sufficient cash to pay some or all of any tax they may owe on the
liquidation. Such Investors owing tax as a result of the liquidation
will have to pay such tax from sources other than any cash liquidating
distribution from the Partnership.
See "Risk Factors" in the Joint Proxy Statement/Prospectus.
CONFLICTS OF INTEREST
There are substantial conflicts of interest which exist by virtue of
the Managing General Partner acting in that capacity on behalf of the
Partnership while at the same time acting as the proposed purchaser of all of
the oil and gas assets of the Partnership. These conflicts of interest are
discussed below.
o The terms of the Proposal are established by the Company which is also
the Managing General Partner of the Partnership.
6
<PAGE> 272
o Neither the Managing General Partner nor a majority of its independent
directors retained an independent representative to act on behalf of
the Partnership's Investors for the purposes of negotiating the terms
upon which any such sale to the Managing General Partner would be made
or for the preparation of a report concerning the fairness of the
entire transaction.
See "Summary--Conflicts of Interest" and "Conflicts of Interest" in the Joint
Proxy Statement/Prospectus.
SPECIAL FACTORS
BACKGROUND AND PURPOSE OF THE PROPOSAL
[VARIABLE PARA. BY P'SHIP TYPE] A number of factors have led to the
decision of the Company in its capacity as Managing General Partner to solicit
approval of the Proposal by Investors in the Partnership. As contemplated when
the Partnership was organized, and given the expenditure of virtually all of
the Partnership's capital to purchase producing properties over eight years
ago, the production from Partnership oil and gas assets declined over time. It
was always anticipated that a time would arrive when the Managing General
Partner would propose that the business of the Partnership be concluded, its
assets sold or otherwise disposed of, and the Partnership liquidated and
dissolved. The general improvement in the prices for natural gas over the last
several years, relative to such prices in the mid- 1990's, make this an
appropriate time, especially in light of the age of the Partnership, to
consider the Proposal to sell the Partnership's Property Interests. The
structure being proposed, which involves the sale of the Partnership's oil and
gas assets to the Managing General Partner, is being submitted for approval by
Investors in an attempt to realize the highest value for those assets. For the
reasons set out below, the Managing General Partner believes that the Proposal
is fair to Investors in the Partnership, given that the purchase price for
these assets has been determined by taking the higher of two fair market value
estimates by three independent Appraisers and adding to it a 7.5% premium.
Approval of the Proposal will have the following effects:
1. The Managing General Partner will purchase all of the oil and gas
assets of the Partnership, provided its Companion Partnership has
approved its proposal.
2. When the Partnership sells all of its oil and gas assets, it will be
required to liquidate and distribute its remaining assets (principally
the cash proceeds from the sale) to its partners (including the
general partners) in accordance with their respective ownership
interests in the Partnership.
3. Investors will be given the option of electing to receive shares of
Swift Common Stock, in amounts that they choose on an individual
basis, in lieu of some or all of the cash they would be entitled to
receive upon the Partnership's liquidation.
4. Investors in the Partnership will be taxed on the sale of the
Partnership's oil and gas assets, although such sale is expected to
result in a taxable gain to Investors that acquired their interests in
the original offering.
7
<PAGE> 273
PROPOSED PURCHASE PRICE
As discussed in greater detail below, the Petroleum Engineering
Consultants estimated that the aggregate fair market value of the Partnership's
Property Interests as of December 31, 1997 is $3,083,309. CIBC Oppenheimer
estimated a fair market value of the same Property Interests at the same date
of $3,028,036. The Special Transactions Committee chose the higher of these
two determinations as the "Fair Market Value" for the purchase of these
interests and the Board of Directors of the Company determined to pay a 7.5%
premium ($231,248) above the Fair Market Value to purchase the Partnership's
Property Interests, resulting in a purchase price of $3,314,557. This compares
to the total purchase price for all of the oil and gas assets of all 63
Partnerships which are considering similar proposals of approximately $81
million. The valuation estimates of the Appraisers are attached to this
Supplement and incorporated herein by reference as follows: Attachment A is
the fair market value estimate of H.J. Gruy and Associates, Inc., Attachment B
is the fair market value estimate of J.R. Butler and Company, and Attachment C
is the fair market value estimate of CIBC Oppenheimer Corp. The PV-10 Value
prepared on an annual basis by H.J. Gruy of the same Property Interests as of
the same date is $4,009,417.
REASONS FOR THE PROPOSAL
The Managing General Partner believes that it is in the best interest
of the Investors for the Partnership to sell its Property Interests at this
time and to dissolve the Partnership and make a final liquidating distribution
to its partners for the reasons discussed below.
Current Liquidating Distribution Lowers Volatility Risk. Although
Investors already have received cash distributions from the Partnership in
excess of their original capital contributions, future cash distributions are
likely to decrease over time. The Partnership has been in existence for over
nine years. The Managing General Partner believes that the ability to receive
the estimated liquidating distribution in one lump sum at this time, rather
than in smaller amounts over a longer period, is one of the benefits of the
Proposal, without the risk of such distributions being negatively affected by
oil and gas price decreases and the inherent risks associated with geological,
engineering and operational matters. It is also the Managing General Partner's
belief that improvements over the last several years in the level of gas
prices, relative to such prices in the mid-1990's, makes this an appropriate
time to consider the sale of the Partnership's Property Interests and increase
the likelihood of maximizing the value of the Partnership's assets, although
future prices and market volatility cannot be predicted with any accuracy.
Decreasing Cash Flow While Expenses Continue. The Partnership's oil
and gas reserves are expected to continue to decline as remaining reserves are
produced. Declines in well production are based principally upon the maturity
of the wells, not on market factors. These declines will continue to occur
while oil field overhead and operating costs ($80,297 in 1997) and direct
general and administrative expenses ($155,295 in 1997) continue, which are
relatively fixed amounts. Each producing well requires a certain amount of
overhead costs, as operating and other costs are incurred regardless of the
level of production. Likewise, direct costs and/or general and administrative
expenses, such as compliance with the securities laws, producing reports to
partners and filing partnership tax returns, do not decline as revenues
decline. By accelerating the liquidation of the Partnership, those future
administrative costs will be avoided by the Partnership.
Limited Partners' Tax Reporting. Each Investor will continue to have
an income tax reporting obligation with respect to his Units as long as the
Partnership continues to exist. There is no trading
8
<PAGE> 274
market for the Units, so Investors generally are unable to dispose of their
Units. See "Business of the Partnership Business and Financial Condition--No
Trading Market" in this Supplement. Following the sale of the Partnership's
Property Interests and dissolution of the Partnership, Investors will realize
gain or loss, or a combination of both, under federal income tax laws. See
"Summary of Federal Income Tax Consequences--Taxable Gain or Loss upon Sale of
Properties" herein. Thereafter, Investors will have no further tax reporting
obligations with respect to the Partnership. The dissolution of the
Partnership will also allow Investors to take a capital loss deduction for
syndication costs incurred in connection with formation of the Partnership.
See "Summary of Federal Income Tax Consequences--Liquidation of the
Partnership" in this Supplement.
See "Summary--Background and Reasons for the Proposals," "--Purpose and Effect
of the Proposals," "--Reasons for the Proposals" and "--Managing General
Partner's Recommendations" in the Joint Proxy Statement/Prospectus.
COLLECTIVE ANALYSIS OF PURCHASE PRICE; PREMIUM OVER FAIR MARKET VALUE
The Special Transactions Committee selected H.J. Gruy and Associates,
Inc. ("H.J. Gruy" or "Gruy"), J.R. Butler and Company ("J.R. Butler" or
"Butler"), which are both petroleum engineering consultants, and CIBC
Oppenheimer Corp. ("CIBC Oppenheimer"), an investment banking firm, to
estimate the fair market value of the Property Interests of each of the
Partnerships. Collectively, H.J. Gruy, J.R. Butler and CIBC Oppenheimer are
referred to herein as the "Appraisers," and H.J. Gruy and J.R. Butler together
are sometimes referred to herein as the "Petroleum Engineering Consultants."
The following subsections of the "Special Factors" section of the
Joint Proxy Statement/Prospectus should be reviewed for information concerning
the selection and qualification of the Appraisers and the parameters of the
valuation estimates: "Independent Appraisal of the Fair Market Value of
Property Interests of the Partnerships," "Qualification of Appraisers," and
"Fair Market Value."
The Petroleum Engineering Consultants arrived at a fair market
valuation estimate of the Partnership's Property Interests based upon appraisal
of the projected discounted cash flow from its various Property Interests. On
the other hand, the investment banking firm of CIBC Oppenheimer made a
valuation estimate based upon the application of multiple quantitative and
qualitative factors. The quantitative factors include, among other things, a
review of relevant valuation criteria from comparable acquisitions of both oil
and gas properties and companies that are predominantly active in the oil and
gas industry, and a review of valuation criteria for relevant publicly traded
oil and gas companies.
The process used by the Petroleum Engineering Consultants in preparing
their valuation estimate is discussed at length in the Joint Proxy
Statement/Prospectus under "Special Factors--Valuation by Petroleum Engineering
Consultants." As described therein, the Petroleum Engineering Consultants
individually audited the estimate of present value of future net cash flows
from the 44 property groups in which Property Interests are owned by the
Partnerships to whom similar proposals are being made to sell all of their oil
and gas assets and liquidate their Partnerships. The Partnership owns Property
Interests in eleven of these property groups. The Petroleum Engineering
Consultants began their analysis based upon the year-end 1997 PV-10 Value of
each property audited by H.J. Gruy and together they re-evaluated reserve
quantities, projected operating costs and cash flows. The present value of
this reserves analysis was then derived by escalating year-end 1997 prices
($2.38 per MMBtu and $16.00 per barrel before adjustments for Btu content for
gas and gravity variances for oil as well as transportation charges and
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geographic location) and costs by 3.5% per year for 15 years. This present
value was then adjusted for various individual field risks and risk adjustments
of proved non-producing reserves and proved undeveloped reserves. The result
of this collective analysis by the Petroleum Consulting Engineers was their
estimation that the fair market value of Property Interests owned by the
Partnership was $3,083,309 as of December 31, 1997.
The methodology used by CIBC Oppenheimer to prepare its valuation
estimate is discussed at length under "Special Factors--Valuation by CIBC
Oppenheimer" in the Joint Proxy Statement/Prospectus. CIBC Oppenheimer's
evaluation of the Partnership's Property Interests began with the PV-10 Value
of each property group, as calculated by Swift and audited by H.J. Gruy, which
Gruy report dated February 10, 1998 is Attachment D to this Supplement. CIBC
Oppenheimer then divided the property groups into two categories. Those
property groups with reserves consisting primarily of proved developed
producing reserves were placed in the "Conventional Case" category. Those
property groups with significant proved developed non-producing or undeveloped
reserves were placed in the "Non-Conventional Case" category. [NEXT IS
VARIABLE SENTENCE:] The Partnership has interests in property groups which
were in both the "Conventional Case" and the "Non-Conventional Case"
categories. CIBC Oppenheimer then valued each property group by applying the
multiples discussed under "Special Factors--Valuation by CIBC
Oppenheimer--Valuation Multiples" in the Joint Proxy Statement/Prospectus to
each property group's PV-10 Value, proved reserves on a BOE basis, and
projected 1998 EBIDTA. A separate set of multiples was used for property
groups in the Conventional Case category and the Non-Conventional Case
category, respectively. This provided CIBC Oppenheimer with three estimated
values for each property group. The average of these three values yielded CIBC
Oppenheimer's estimation of the fair market value of each property group. CIBC
Oppenheimer then allocated the appropriate portion of each property group's
estimated fair market value to the Partnership based upon the Partnership's
Property Interests in each property group. The result of this analysis by CIBC
Oppenheimer was an estimation that the fair market value of the Partnership's
Property Interests was $3,028,036 on December 31, 1997.
The Special Transactions Committee has determined that, in keeping
with the definition of Fair Market Value, the higher of these two estimations
of fair market value, or $3,083,309, represents the Fair Market Value of the
Partnership's Property Interests. Accordingly, the fair market estimation of
the Petroleum Consulting Engineers and the fair market value determined by CIBC
Oppenheimer were compared to each other and the higher of the two was chosen as
the Fair Market Value of the Property Interests owned by the Partnership. The
variation between the fair market value estimate of the Partnership's Property
Interests prepared by the Petroleum Consulting Engineers, on one hand, and CIBC
Oppenheimer on the other was 2%.
DETERMINATION OF PREMIUM OVER FAIR MARKET VALUE BY THE COMPANY
The Special Transactions Committee presented its recommendation to the
Board of Directors of the Company as to the Fair Market Value of the Property
Interests of the Partnership. The Board of Directors of the Company then
determined that paying a 7.5% premium over the Fair Market Value of the
Partnership's Property Interests was appropriate and fair based upon the
factors and for the reasons discussed below. Because the Company has served as
Managing General Partner of the Partnership for over nine years, it is
intimately familiar with the Property Interests owned by the Partnership. The
Managing General Partner believes that if the Property Interests were to be
sold to a third party purchaser that was not equally familiar with those
interests, it is likely that the purchaser would discount the purchase price to
account for that lack of familiarity and associated risks. If these interests
are purchased by the
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Company, then the additional cost and personnel often inherent in making a
property acquisition are not required, because the files and deed records
already exist in the Company's lease and computer systems, and conveyance and
title issues do not exist.
In the judgment of the Company, the purchase of the Partnership's
Property Interests together with interests in many of the same properties owned
by other Partnerships at approximately the same time will result in
efficiencies to the Company in aggregating such interests. Swift's long-term
knowledge of the risks involved in these properties means that it is in a
better position to evaluate these risks than third parties.
Based upon the Company's experience in purchasing properties, the lack
of additional costs often incurred in purchasing oil and gas properties in
which the purchaser has owned no interest, and the Company's intimate
familiarity with these Property Interests and consequent ability to evaluate
acquisition risks, it was deemed appropriate to pay a premium representing the
benefit to the Company arising from these factors.
The amount of the premium principally was based upon management's
experience in purchasing properties which contain both producing reserves and
drilling potential, without any statistical or analytical study prepared by the
Company in the course of determining the amount of this premium. Since 1979,
the Company, on behalf of itself and others, has gained a wide range of
experience with the valuation of oil and gas properties and the prices for
their purchase and sale, having purchased $478 million of such properties in
129 separate transactions. Other purchasers might have determined it
inappropriate to pay a premium, or if so, to pay a premium based upon other
factors or in a different amount. Because there has been no independent third
party involved in the decision to pay this premium or in the determination of
its amount, and no fairness opinion has been requested regarding this premium,
conflicts of interest exist in its determination, although the Managing General
Partner believes, based upon its knowledge of the oil and gas industry, its
knowledge of the properties involved, its experience in purchasing and selling
oil and gas properties, and the benefits from purchasing the Property Interests
which are particular to the Company, that the amount being offered to the
Partnership to purchase its Property Interests is fair.
"SPECIAL FACTORS" SECTION IN THE JOINT PROXY STATEMENT/PROSPECTUS
The Special Factors section in the Joint Proxy Statement/Prospectus
contains a full discussion of the determination of the purchase price proposed
to be paid by the Managing General Partner to purchase the Partnership's
Property Interests. In addition to those topics discussed at length in this
Supplement, the Joint Proxy Statement/Prospectus addresses alternative
transactions that were considered but not proposed for the Partnership and the
other 62 partnerships to whom similar proposals are being made simultaneously.
It also contains information regarding the prior relationships between the
Appraisers, the Partnerships and the Managing General Partner, the absence of a
request that an independent representative negotiate the terms of the purchase
of the Partnership's Property Interests by the Managing General Partner, the
manner in which expenses are to be borne for the transaction, the Managing
General Partner's source of funds to purchase the Partnership's Property
Interests, and the benefits that the Managing General Partner would receive
from purchasing such Property Interests.
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ESTIMATES OF LIQUIDATING NET CASH DISTRIBUTION AMOUNT IF THE PROPOSAL IS
APPROVED
The purchase price proposed to be paid to the Partnership for its oil
and gas assets is the Fair Market Value plus the purchase premium. As is the
case with all oil and gas properties purchases, the purchase is proposed to be
made as of the date which the properties were evaluated (in this case December
31, 1997). A portion of the reserves used to establish the Fair Market Value
has been produced during 1998. Most of the net revenue received by the
Partnership from the sale of such production since the proposed purchase date
(December 31, 1997) has been distributed to the partners during 1998 through
quarterly cash distributions or, to the extent not already distributed, will be
distributed as part of the Partnership's liquidating distribution.
Accordingly, the actual purchase price which will be paid to the Partnership
will be reduced by the amount of net production revenue received by the
Partnership after December 31, 1997.
Set forth in the table below are estimated net proceeds that the
Partnership may realize from the sale of the Partnership's Property Interests,
estimated expenses of the related dissolution and liquidation of the
Partnership and estimated interim net cash distributions from January 1, 1998
until September 30, 1998, resulting in an estimate of the amount of net cash
distributions available for partners as a result of such sale.
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ESTIMATE OF NET CASH DISTRIBUTIONS
FROM PROPERTY INTEREST SALES AND LIQUIDATION
<TABLE>
<S> <C>
Fair Market Value of Partnership Property Interests(1) $ 3,083,309
(Gross Sales Proceeds)
Purchase Premium (7.5% of Fair Market Value)(2) $ 231,248
Estimated Selling and Dissolution Expenses(3) $ (92,499)
(3% of the Fair Market Value)
Net Assets(4) $ 688,408
Estimated Interim Cash Distributions(5) $ (763,666)
------------------
Estimated Net Distributions to Partners(6) $ 3,146,800
==================
Amount Distributable
to Investors(6) $ 2,626,297
Amount Distributable
to General Partners(6)(7) $ 520,503
------------------
$ 3,146,800
==================
ESTIMATED NET CASH DISTRIBUTIONS TO INVESTORS PER $100 UNIT $ 31.53
==================
MINIMUM NUMBER OF UNITS NECESSARY TO PURCHASE 100 SHARES OF SWIFT
ENERGY COMMON STOCK WITH CASH DISTRIBUTIONS(8) 58
==================
</TABLE>
- --------------------
(1) Represents the higher of two fair market value estimates by the
Appraisers.
(2) As determined by the Board of Directors of Swift.
(3) Includes estimated costs associated with dissolution and liquidation
of the Partnership.
(4) Includes cash and net receivables of the Partnership as of December
31, 1997.
(5) Estimated cash distributions paid to the partners from January 1, 1998
to September 30, 1998.
(6) Estimated net cash distributions are allocated to the Investors and
the General Partners pursuant to the Partnership's limited partnership
agreement.
(7) Includes amount distributable to Special General Partner and Managing
General Partner.
(8) Under the terms of the offer of Swift Common Stock to Eligible
Purchasers if the Investors in the Partnership approve the Proposal
and its Companion Partnership approves a similar Proposal, such
Investors will be
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Eligible Purchasers. The minimum number of shares which can be
purchased by an Eligible Purchaser is a round lot of 100 shares.
Based upon estimated net cash distribution of $31.53 per $100 Unit,
the number of Units shown above is the minimum number of Units which
it will be necessary for an Investor to own in order to purchase a
minimum 100 share round lot of Swift Common Stock without providing
any additional funds from other sources. This calculation is based
upon an assumed purchase price of Swift Common Stock of $18.00 per
share (which is the same price upon which the proforma financial
statements contained in the Joint Proxy Statement/Prospectus are
based) for an aggregate purchase price for 100 shares of Swift Common
Stock of $1,800. The minimum number of Units shown is subject to
change, based upon the price for Swift Common Stock at a future date
as specified under "Offering of Shares of Swift Energy Company Common
Stock if Investors Approve the Proposal--Offer of Swift Common
Stock--Purchase Price" in this Supplement. However, if an Eligible
Purchaser has interests in more than one Partnership, the cash
distributions he will be entitled to receive may be aggregated to meet
the minimum share purchase requirement of a round lot of 100 shares.
ESTIMATES OF NET CASH DISTRIBUTIONS AVAILABLE FROM CONTINUED OPERATIONS
If the Partnership were to retain its Property Interests until they
have reached their economic limit, the table below estimates the return to
Investors, without regard to amounts distributable to the General Partners,
discounted to present value, based upon 1997 year-end pricing without
escalation and upon the discount assumptions used above. The estimates of the
present value of future net cash distributions have been further reduced by
estimates of continuing audit, tax return preparation and reserve engineering
fees associated with continued operations of the Partnership, along with direct
and general and administrative expenses estimated to occur during this time.
The following estimated future net revenues do not take into account any
additional costs which might be incurred by the Partnership due to needed
future maintenance or remedial work on the properties in which the Partnership
has an interest, which would reduce such net revenues.
ESTIMATED SHARE OF INVESTORS'
NET CASH DISTRIBUTIONS FROM CONTINUED OPERATIONS
<TABLE>
<S> <C>
Estimated Future Net Revenues from Continued Operations until $ 5,266,181
Depletion(1)
Estimated Interim Net Cash Distributions(2) $ (697,600)
Estimated Partnership Direct and Administrative Expenses(3) $ (663,540)
Net Assets(4) $ 585,147
---------------------
Net Cash Distributions to Investors(5) $ 4,490,188
=====================
NET CASH DISTRIBUTIONS PER $100 UNIT $ 53.91
PRESENT VALUE OF NET CASH DISTRIBUTIONS PER $100 UNIT(5)(6) $ 33.95
</TABLE>
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- -------------------
(1) Investors' future net revenues are based on the reserve estimates at
December 31, 1997 using year-end 1997 prices without escalation. To a
limited extent, future net revenues may be influenced by a material
change in the selling prices of oil or gas. For further discussion of
this, see "Special Factors--Reasons for the Proposal" in this
Supplement. The actual prices that will be received and the
associated costs are likely to vary and may be more or less than those
projected. See "Partnership Business and Financial Condition" in this
Supplement.
(2) Estimated net cash distributions paid to Investors from January 1,
1998 to September 30, 1998 in order to present this information on a
comparative basis (in relation to the preceding table) as of September
30, 1998.
(3) Includes Investors' share of general and administrative expenses, and
audit, tax, and reserve engineering fees.
(4) Includes Investors' share of cash and net receivables of the
Partnership as of December 31, 1997.
(5) Based upon the Partnership's reserves until they have reached their
economic limit.
(6) Discounted at 10% per annum.
The proceeds of all sales, to the extent available for net cash
distribution, are to be distributed to the partners in accordance with the
Partnership's limited partnership agreement. The amounts finally distributed
will depend on results of operations until liquidation of the Partnership,
final costs and other contingencies and circumstances.
FAIRNESS OF PROPOSED SALE OF ASSETS TO THE MANAGING GENERAL PARTNER
AS COMPARED TO CONTINUING OPERATIONS
Based on the above tables, it is estimated that an Investor could
expect to receive $31.53 per $100 Unit upon sale of the Partnership's Property
Interests at September 30, 1998. In comparison, it is estimated that an
Investor could expect to receive $33.95 per $100 Unit, discounted to present
value at 10% per annum ($53.91 per $100 Unit on an undiscounted basis) if the
Partnership continued operations. The Managing General Partner believes that
the Proposal to sell the Partnership's Property Interest as compared to
continuing operations is fair to Investors for the reasons discussed below.
Although the estimates contained in the two tables above show that
estimated net cash distributions to Investors (based on net present value) from
continued operations would be approximately 8% higher than estimated net cash
distributions from selling the Partnership's Property Interests and liquidating
the Partnership currently, the Managing General Partner believes there is a
substantial advantage in receiving the liquidating net cash distribution in one
lump sum at this time. The estimates of net cash distributions from continued
operations are based upon 1997 year- end pricing. It is highly likely that
over such a long period of time, oil and gas prices will vary often and
possibly widely, as has been demonstrated historically, from the prices used to
prepare these estimates. Continued operations over such a long period of time
subject Investors to the risk of receiving lower levels of net cash
distributions if oil and gas prices over this period are lower on average than
those used in preparing the estimates of net cash distributions from continued
operations. Continued operations also subject Investors' potential net cash
distributions to the risks of possible changes in costs or need for workover or
similar significant remedial work on the properties in which the Partnership
owns Property Interests. The Managing General Partner also believes that there
is an advantage to Investors taking any funds to be received upon liquidation
and redeploying
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<PAGE> 281
those assets in other investments, rather than continuing to receive decreasing
levels of net cash distributions over such a long period of time.
Because there is no active trading market for Units in the
Partnership, the only other comparable value for Units is the 1997 "Unit
Value," which, as explained below, is the amount calculated on an annual basis
under the terms of the limited partnership agreement at which the Managing
General Partner can offer to repurchase Units from Investors. As of January 1,
1997, this "Unit Value" was $54.65 per $100 Unit. In 1997, the Investors
received net cash distributions of $12.63 per $100 Unit, and are estimated to
receive another $8.38 per $100 Unit before September 30, 1998, which converts
to a comparable value of $33.64 per $100 Unit before any adjustments to
quantities of reserves or oil and gas prices during this almost two year
period. Under the terms set out in the limited partnership agreement, each
year the Managing General Partner is required to furnish to Investors the Unit
Value, and Investors have the right to present their Units for purchase by the
Managing General Partner for the Unit Value. The Unit Value amount is
determined on an entirely different basis than the estimates of fair market
value by the Appraisers. Furthermore, the Unit Value was calculated over one
year ago, with a valuation date of January 1, 1997, as opposed to the date for
assessment of Fair Market Value being December 31, 1997. Because of significant
changes in oil and gas prices within a year's time, in addition to the changes
in reserve quantities during that period, the calculation of Unit Value as of
January 1, 1997, and the Fair Market Value as of December 31, 1997, are not
comparable. Unit Value is derived by taking 70% of the present value of proved
oil and gas reserves (discounted at 10% per annum) calculated on an escalated
pricing basis, plus cash and accounts receivable, less outstanding debts and
obligations of the Partnership.
Although the PV-10 Value of the Partnership's Property Interests is
higher than the purchase price proposed if the Proposal is approved, the
Managing General Partner does not believe that the PV-10 Value accurately
reflects the amount that oil and gas industry members are currently paying to
purchase producing properties on the open market.
FAIRNESS OF PROPOSED SALE
The Managing General Partner believes that the entire transaction
related to the Proposal involving the proposed method of sale of the
Partnership's Property Interests is fair to Investors for the following
reasons, without giving any particular weight to any reason:
1. The Managing General Partner believes that the most important
element of the Proposal is the determination of the Fair
Market Value of the Partnership's Property Interests. The
price to be paid by the Company to purchase the Partnership's
Property Interests was determined in the Managing General
Partner's sole judgment by adding a 7.5% premium to the higher
of the two estimates by the Appraisers of the fair market
value of the Partnership's Property Interests. Two of the
three Appraisers are qualified independent petroleum
engineering firms and the other is an investment banking firm.
The factors and methods used by the Appraisers in determining
Fair Market Value are discussed in detail under "Special
Factors--Independent Appraisal of the Fair Market Value of
Property Interests of the Partnerships", "--Fair Market
Value," "--Valuation by Petroleum Engineering Consultants,"
"--Valuation by CIBC Oppenheimer" and "--Collective Analysis
of Purchase Price" in the Joint Proxy Statement/Prospectus.
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<PAGE> 282
2. No transaction will take place unless the Proposal is approved
by Investors holding at least a majority of the interests in
such Partnership (without any vote by the Managing General
Partner) and a similar Proposal is approved by the
Partnership's Companion Partnership.
3. The Special Transactions Committee made the determination as
to the retention of the Appraisers and approved the fair
market value estimates provided by the Appraisers and
recommended the reports of the Appraisers to the Board of
Directors of the Company. The Special Transactions Committee
is comprised solely of independent directors of the Company.
4. If the Proposals are approved by investors in any of the 63
Partnerships considering similar proposals, it is likely that
the Managing General Partner will expend the capital necessary
to develop non- producing reserves on the Property Interests
purchased by the Managing General Partner from those
Partnerships. If all of the Property Interests which are the
subject of the Proposals are acquired by the Company, such
Property Interests in the aggregate will constitute less than
20% of the Company's total assets. Because the Managing
General Partner would be the beneficiary of any such increase
in value, the Managing General Partner is hereby offering to
Eligible Purchasers the opportunity to purchase up to
2,500,000 shares of Common Stock of the Company. There is no
requirement that any purchase of Swift's Common Stock be made.
See "Offer of Swift Common Stock" below.
5. In structuring the Proposal and related transactions, the
Managing General Partner considered that any sale of
Partnership Property Interests, whether to the Managing
General Partner or to a third party, would be a taxable
transaction. Thus, if an Investor subject to federal income
tax chooses to use the proceeds received on liquidation of
that Investor's Partnership to purchase Swift Common Stock,
tax will still have to be paid on the amount of any taxable
income resulting from the Partnership's sale of oil and gas
assets, without regard to whether the Investor has cash
proceeds remaining from his liquidating distribution to pay
such tax.
The determination by the Special Transactions Committee to pay the
purchase premium, the independent Appraisers' determination of the Fair Market
Value of the Property Interests, and the payment of a 7.5% premium do not
necessarily remove the substantial conflicts of interest which exist in the
transaction between the Managing General Partner serving in that capacity on
behalf of the Partnership and also acting as the purchaser of the Property
Interests from the Partnership. No fairness opinion was requested or received
regarding the ultimate purchase price to be paid by the Managing General
Partner to purchase the Partnership's oil and gas assets. The Managing General
Partner determined that rather than setting the purchase price for Partnership
Property Interests itself, it would be preferable to request three different
independent Appraisers to determine two sets of fair market values at which
such Property Interests should be purchased, and then to choose the higher of
those two values. The Company believes that when the Appraisers rendered their
opinions as to the "fair market value" of the Partnership's Property Interests,
inherent within their appraisal opinions were the Appraisers' determination
that these "fair market values" were "fair," or such determinations would not
have been made. Consequently, no independent fairness opinion was requested
regarding "fair market values" or upon the premium. The Managing General
Partner believes that adding a 7.5% premium to the highest of the two fair
market value determinations made by the three Appraisers only serves to
increase the amount to be paid to Investors
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upon liquidation of the Partnership and does not require a separate fairness
opinion. The determinations by a third party purchaser as to the purchase
price might be more or less than that being proposed by the Managing General
Partner as a purchase price for these Property Interests.
The determination to submit the Proposal to Investors in which the
Company would purchase the Property Interests of the Partnership was deemed by
the Managing General Partner to be the most appropriate time and method for
liquidation of the Partnership. This decision was made in light of full
consideration by the Managing General Partner of its fiduciary obligations to
Investors. Furthermore, the decision to use three Appraisers, rather than one,
and to have the Appraisers actually set the fair market value for purchase of
the Property Interests, rather than the Managing General Partner setting that
value and requesting a fairness opinion, were based upon the Managing General
Partner's consideration of the substantial conflicts of interest which exist in
the transactions covered hereby.
See "Special Factors--Fairness of Proposed Sale" in the Joint Proxy
Statement/Prospectus.
MANAGING GENERAL PARTNER BENEFITS
Benefits accruing to the Company resulting from the purchase of the
Partnerships' Property Interests include the following: the Managing General
Partner will share the benefits available to Investors through liquidating its
Partnership interests (including both its general partner interests and any
Units it owns) and receiving the same value of those interests as Investors.
Additionally, the Company intends to profit from purchasing the Partnership's
Property Interests through a return on capital used to purchase those oil and
gas assets and invest in their development. By purchasing the Partnership's
Property Interests itself, the Managing General Partner will be able to
maintain its position as operator of certain properties in which the
Partnership owns an interest. Consequently, the Managing General Partner would
continue to receive operating fees as operator of those properties. The sale
of the Partnership's Property Interests to the Managing General Partner will
have no effect or an inconsequential effect on the Managing General Partner's
net book value and net earnings. However, the purchase of all of the oil and
gas assets of the Partnerships would increase the Company's proved reserves,
cash flow and total assets by a significant amount. Lastly, if individual
Investors which approve the Proposal elect to purchase Company Common Stock,
rather than receiving cash upon liquidation of the Partnership, the Company
will benefit by using stock to pay the purchase price, rather than using its
available cash resources or borrowing facilities.
See "Special Factors--Managing General Partner Benefits" in the Joint Proxy
Statement/Prospectus.
SIMULTANEOUS PROPOSALS TO COMPANION PARTNERSHIPS
Simultaneous Proposals are being made to investors in the
Partnership's Companion Partnership. If both the Partnership and its Companion
Partnership do not approve their respective Proposals, it is likely to affect
the ability of the Partnership to consummate the sale of its Property
Interests. Although the Investors in the Partnership may desire to sell their
Property Interests, the separation of the working interest and the
non-operating interests in the same properties may affect the salability of
those interests on a permanent basis. If, for example, the Partnership
approves the Proposal but the Companion Partnership does not, the value of a
working interest burdened by a large non- operating interest is likely to be
lowered significantly. [VARIABLE REVERSAL: If, for example, the Partnership
approves the Proposal but the Companion Partnership does not, the value of a
non-operating interest is likely to be negatively affected by the lack of
control over operations.] If the Partnership's Companion Partnership does not
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approve its Proposal, then the Managing General Partner will advise the
Investors in the Partnership. If the investors in the Partnership's Companion
Partnership do not vote in favor of its Proposal, then it is likely that the
Partnership will continue operations and will produce its reserves until
depletion, with steadily decreasing rates of cash flow, and consequently
steadily decreasing amounts of cash distributions to the Investors.
VOTING ON THE PROPOSAL
The Joint Proxy Statement/Prospectus and the Form of Proxy enclosed
with this Supplement are being provided for use at the Special Meeting of
Investors of the Partnership and at any adjournment or postponement of such
meeting (the "Meeting") to be held at 16825 Northchase Drive, Houston, Texas at
4:00 p.m. Central Time on _________, ____________, 1998. The Meeting is being
called for the purpose of considering and voting upon the Proposal to
ultimately sell all of the oil and gas assets of the Partnership to the
Company, and to dissolve, wind up and terminate the Partnership and to transact
such other business as may be properly presented at the Special Meeting or any
adjournments or postponements thereof, all in accordance with the terms and
provisions of the Partnership's limited partnership agreement (the "Partnership
Agreement"), and the Texas Revised Limited Partnership Act (the "Texas Act").
This Joint Proxy Statement/Prospectus and enclosed Form of Proxy are first
being mailed to Investors on or about ____________, 1998.
Pursuant to the terms of the Partnership Agreement, the Partnership,
if not terminated earlier, will continue in being through January 1, 2021, at
which point it will terminate automatically.
Under the Partnership Agreement, the Proposal must be approved by the
affirmative vote of Investors holding 51% or more of the Units in the
Partnership as of the Record Date (defined below). Therefore, an abstention by
an Investor will have the same effect as a vote against the Proposal. The
solicitations are being made for votes in favor of the Proposal (which will
result in liquidation and dissolution of the Partnership). As of the Record
Date, 75,781 Units were outstanding and held by record holders (excluding Units
held by the Managing General Partner as discussed below). Accordingly, the
affirmative vote of holders of at least 38,648 Units is required to approve the
Proposal. Each Investor appearing on the records of the Partnership as of
______, 1998 (the "Record Date") is entitled to notice of the Meeting and is
entitled to one vote for each Unit held by such Investor. VJM Corporation, a
California corporation, is the Special General Partner of the Partnership, and
owns a 1.5% interest in the Partnership as a general partner, but owns no
Units. The Managing General Partner owns a general partner interest in the
Partnership of 13.5%. Additionally, the Managing General Partner owns 7,514
outstanding Units in the Partnership, which ownership results from the Managing
General Partner's purchase over the life of the Partnership of Units from
Investors under the right of presentment, contained in the Partnership
Agreement. Under the Partnership Agreement, the Managing General Partner may
not vote any Units owned by it for matters such as the Proposal. The Managing
General Partner's non-vote, in contrast to abstention by Investors, will not
affect the outcome, because for purposes of adopting the Proposal, its Units
are excluded from the total number of voting Units.
VOTE REQUIRED
The actual proxy to be used to register the vote on the Proposal
before you is the separate green sheet of paper included with this Supplement
and Joint Proxy Statement/Prospectus. PLEASE USE THE GREEN PROXY TO CAST YOUR
VOTE ON THE PROPOSAL.
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If a proxy is properly signed and is not revoked by an Investor, the
Units it represents will be voted in accordance with the instructions of the
Investor. If no specific instructions are given, the Units will be voted FOR
the Proposal. An Investor may revoke his proxy at any time before it is voted
at the Meeting. Any Investor who attends the Meeting and wishes to vote in
person may revoke his proxy at that time. Otherwise, an Investor must advise
the Managing General Partner of revocation of his proxy in writing, which
revocation must be received by the Managing General Partner at 16825 Northchase
Drive, Suite 400, Houston, Texas 77060 prior to the time the vote is taken.
SOLICITATION
The solicitation is being made by the Partnership. The Partnership
will bear the costs of the preparation of the Joint Proxy Statement/Prospectus
and of the solicitation of proxies and such costs will be allocated 85% to the
Investors and 15% to the general partners pursuant to the terms of the
Partnership Agreement. As the Managing General Partner holds approximately
9.11% of the Units held by all Investors, 9.11% of the costs borne by the
Investors will be borne by the Managing General Partner, in addition to the
portion of the Partnership's total costs borne by the general partners by
virtue of their interest in the Partnership as general partners. Solicitations
will be made primarily by mail. In addition, a number of regular or temporary
employees of the Managing General Partner may, if necessary to ensure the
presence of a quorum, solicit proxies in person or by telephone. The Managing
General Partner also may retain a proxy solicitor to assist in contacting
brokers or Investors to encourage the return of proxies, although it does not
anticipate doing so.
PARTNERSHIP BUSINESS AND FINANCIAL CONDITION
The Partnership is a Texas limited partnership formed June 30, 1989.
Units in the Partnership are registered under Section 12(g) of the Securities
Exchange Act of 1934. The Partnership owns Property Interests in producing oil
and gas properties within the continental United States in which the Companion
Partnership also managed by the Managing General Partner owns the non-operating
interests. By the end of October 1989, the Partnership had expended all of its
original capital contributions for the purchase of Property Interests in oil and
gas producing properties. During 1997, approximately 48% of the Partnership's
revenue was attributable to natural gas production. The Partnership has, from
time to time, performed workovers and recompletions on wells in which the
Partnership has Property Interests, using funds advanced by the Managing General
Partner or third parties to perform these operations, which amounts have been
subsequently repaid. For information about the business of the Partnership, see
the attached Annual Report on Form 10-K for the year ended December 31, 1997 and
Quarterly Report on Form 10-Q for the quarter ended June 30, 1998.
Investors made contributions of $8,329,500 in the aggregate to the
Partnership, the net proceeds of which has all been invested. The Managing
General Partner has made capital contributions with respect to its general
partner interest of $70,596. Additionally, pursuant to the presentment right
set forth in the Partnership Agreement, it has purchased 7,514 Units from
Investors. From inception through July 31, 1998, the Partnership has made net
cash distributions to its Investors totaling $8,878,300. Details of the
amounts of cash distributions made to partners over the past three years and
nine months are set out under "Cash Distributions" below. Through July 31,
1998, the Managing General Partner has received net cash distributions from the
Partnership of $1,139,613 with respect to its general partner interest, and
$243,617
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related to its limited partner interest. On a per Unit basis, Investors had
received, as of July 31, 1998, $106.59 per $100 Unit, or approximately 106.6%
of their initial capital contributions.
At the time that the Partnership's Property Interests covering
producing properties were acquired, prices averaged about $16.73 per barrel of
oil and $1.74 per Mcf of natural gas. The majority of the Partnership's
Property Interests were acquired by the end of October 1989 when current prices
were predicted to escalate according to certain parameters from then current
levels to approximately $25.39 per barrel of oil and $3.05 per Mcf of natural
gas during 1997. Generally prices did not escalate at the rate anticipated.
Most of the Partnership's reserves were produced from 1990 to 1994, during
which time the oil prices received by the Partnership for its production in
fact averaged $17.45 per barrel and the prices for natural gas averaged
approximately $1.79 per Mcf. A comparison of oil and gas prices as described
in this paragraph appears in the graph presented below.
The following graphs illustrate the effect on Partnership performance
of the variance between oil and gas prices projected at the time of acquisition
of the Partnership's Property Interests and actual oil and gas prices received
for production (as illustrated in the second graph) during the Partnership's
existence.
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[GRAPH: 1 page of gas properties info]
22
<PAGE> 288
[GRAPH: 1 page of oil properties info]
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<PAGE> 289
Lower prices also have had an effect on the Partnership's interest in
proved reserves. Estimates of proved reserves represent quantities of oil and
gas which, upon analysis of engineering and geologic data, appear with
reasonable certainty to be recoverable in the future from known oil and gas
reservoirs under existing economic and operating conditions. When economic or
operating conditions change, proved reserves can be revised either up or down.
If prices had risen as predicted, the volumes of oil and gas reserves that are
economically recoverable might have been higher than the year-end levels
actually reported because higher prices typically extend the life of reserves
as production rates from mature wells remain economical for a longer period of
time. Production enhancement projects that are not economically feasible at
low prices can also be implemented as prices rise.
CASH DISTRIBUTIONS
Cash distributions are made to the partners in the Partnership on a
quarterly basis. During the past three years and the first nine months of
1998, aggregate cash distributions made to all partners in the Partnership
(including the Managing General Partner) and the cash distributions per Unit
made to the Investors were:
<TABLE>
<S> <C> <C>
1995 $ 327,156 $ 3.32 per $100 Unit
1996 $ 621,647 $ 6.25 per $100 Unit
1997 $ 1,171,200 $ 12.63 per $100 Unit
9 Mo. Ended 9/30/98 $ 763,666 $ 8.38 per $100 Unit
</TABLE>
TRANSACTIONS BETWEEN THE MANAGING GENERAL PARTNER AND THE PARTNERSHIP
Under the Partnership Agreement, the Managing General Partner has
received certain compensation for its services and reimbursement for
expenditures made on behalf of the Partnership, which was paid at closing of
the offering of Units, in addition to revenues distributable to the Managing
General Partner with respect to its general partner interest or with respect to
Units it has purchased under the Investors' right of presentment. In addition
to those revenues, compensation and reimbursements, the following summarizes
the transactions between the Managing General Partner and the Partnership
pursuant to which the Managing General Partner has been paid or has had its
expenses reimbursed on an ongoing basis:
o The Managing General Partner has received management fees of
$208,238, internal acquisition costs reimbursements of
$353,837 and formation costs reimbursements of $166,590 from
the Partnership from inception through December 31, 1997, none
of which has been received during the two years ended December
31, 1997.
o The Managing General Partner receives operating fees for wells
in which the Partnership has Property Interests and for which
the Managing General Partner or its affiliates serve as
operator. During the years ended December 31, 1997 and
December 31, 1996 the aggregate operating fees paid to the
Company as operator by the Partnership were $37,716 and
$39,208, respectively. Monthly operating fees range from $200
to $1,100 per well on an 8/8th's basis (i.e., the total amount
of operating fees paid by all interest owners in the well).
If the Property Interests are sold to the Managing General
Partner, there should be no change in its status as operator
for a number of the wells in which the Partnership has a
Property Interest. The Managing General Partner believes that
it will be positively
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<PAGE> 290
affected, on the other hand, by liquidation of the
Partnership, both on the basis of its ownership interest in
the Partnership and for other reasons set out under "Special
Factors--Managing General Partner Benefits" in this
Supplement.
o The Managing General Partner is entitled to be reimbursed for
general and administrative costs incurred on behalf of and
allocable to the Partnership, including employee salaries and
office overhead. Amounts are calculated on the basis of
Investors' original capital contributions to the Partnership
relative to investor contributions to all public partnerships
formed to purchase interests in producing properties for which
the Managing General Partner serves in that capacity. Through
December 31, 1997, the Managing General Partner had received
$1,093,481 in the general and administrative overhead
allowance from the Partnership, of which $124,942 and $124,943
has been reimbursed during the years ended December 31, 1997
and December 31, 1996, respectively.
o The Managing General Partner has been reimbursed $42,650 in
direct expenses by the Partnership, all of which was billed
by, and then paid directly to, third party vendors, of which
$3,070 and $4,107 has been reimbursed during the years ended
December 31, 1997 and December 31, 1996, respectively.
NO TRADING MARKET
There is no trading market for the Units, and none is expected to
develop, as described above under "Special Factors--Fairness of Proposed Sale
of Assets to the Managing General Partner as Compared to Continuing
Operations." Under the Partnership Agreement, Investors have the right to
present their Units to the Managing General Partner for repurchase at a price
determined in accordance with the formula established by the Partnership
Agreement. Originally 661 Investors invested in the Partnership. As of
__________, 1998, there were 626 Investors (excluding the Managing General
Partner). The number of Units in the Partnership issued and outstanding at
that date was 83,295. Through December 31, 1997, the Managing General Partner
had purchased 7,514 Units from Investors pursuant to the right of presentment.
The Managing General Partner does not have an obligation to repurchase Investor
interests pursuant to this right of presentment, but merely an option to do so
when such interests are presented for repurchase.
PRINCIPAL HOLDERS OF INVESTOR UNITS
The Managing General Partner holds 9.11% of all outstanding Units of
the Partnership, resulting from the purchase of Units from Investors under
their right of presentment. To the knowledge of the Managing General Partner,
there is one other holder of Units that holds more than 5% of the Units,
representing approximately 14.5% of the total Units outstanding.
APPROVALS
No federal or state regulatory requirements must be satisfied or
approvals obtained in connection with the sale of the Partnership's Property
Interests.
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LEGAL PROCEEDINGS
The Managing General Partner is not aware of any material pending
legal proceedings to which the Partnership is a party or of which any of its
property is the subject.
SUMMARY OF FEDERAL INCOME TAX CONSEQUENCES
GENERAL
The following briefly summarizes the federal income tax consequences
set forth under "Federal Income Tax Consequences of Adoption of the
Proposals"in the Joint Proxy Statement/Prospectus. Statements of legal
conclusions herein regarding tax consequences are based upon an opinion of
Hoops & Levy, L.L.P., Special Tax Counsel, relevant provisions of the Internal
Revenue Code of 1986, as amended (the "Code"), and accompanying Treasury
Regulations, as in effect on the date hereof, upon reported judicial decisions
and published positions of the Internal Revenue Service (the "Service"), and
upon further assumptions that the Partnership constitutes a partnership for
federal tax purposes and that the Partnership will be liquidated as described
herein. The laws, regulations, administrative rulings and judicial decisions
which form the basis for conclusions with respect to the tax consequences
described herein are complex and are subject to prospective or retroactive
change at any time and any change may adversely affect Investors.
A MORE COMPLETE SUMMARY OF THE FEDERAL INCOME TAX CONSEQUENCES TO
INVESTORS MAY BE FOUND IN THE REGISTRATION STATEMENT IN "FEDERAL INCOME TAX
CONSEQUENCES OF ADOPTION OF THE PROPOSALS." THIS SUMMARY DOES NOT DESCRIBE ALL
THE TAX ASPECTS WHICH MAY AFFECT INVESTORS NOR IS IT A COMPLETE DESCRIPTION OF
THE TAX ASPECTS IT DOES DESCRIBE. It is generally directed to individual
Investors who are the original purchasers of the Units and hold interests in
the Partnership as "capital assets" (generally, property held for investment).
Each Investor that is a corporation, trust, estate, tax exempt entity, or other
partnership is strongly encouraged to consult its own tax advisor as to the
rules which are specifically applicable to it. Except as otherwise
specifically set forth herein, this summary does not address foreign, state or
local tax consequences, and is inapplicable to nonresident aliens, foreign
corporations, debtors under the jurisdiction of a court in a case under federal
bankruptcy laws or in a receivership, foreclosure or similar proceeding, or an
investment company, financial institution or insurance company.
TAXABLE GAIN OR LOSS UPON SALE OF PROPERTIES
Investors will realize and recognize gain or loss, or a combination of
both, upon the Partnership's sale of its properties prior to liquidation. It
is projected, however, that Investors will realize a net taxable gain upon the
sale of the Partnership properties. Notwithstanding the foregoing, Investors
are not expected to realize any gain or loss upon the sale of properties the
Partnership receives from its Companion Partnership and sells to the Managing
General Partners. Because the oil and gas properties, and related assets,
owned by the Partnership are properties used in a trade or business, the
character of gains and losses realized by the Investors generally will be
governed by Section 1231 of the Code. Realized gains and losses generally must
be recognized and reported in the year the sale occurs. Each Investor's
recognized allocable share of the net Partnership 1231 gains or losses must be
netted with that Investor's individual section 1231 gains and losses recognized
during the year in order to determine the character of such net gains or net
losses under section 1231. Net gains will be treated as capital gains except
to the extent recharacterized as ordinary income due to recapture and net
losses will be treated as ordinary losses.
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<PAGE> 292
LIQUIDATION OF THE PARTNERSHIP
After sale of its properties, the Partnership's assets will consist
solely of cash which it will distribute to its partners in complete
liquidation. The Partnership will not realize gain or loss upon such
distribution of cash to its partners in liquidation. If the amount of cash
distributed to an Investor in liquidation is less than such Investor's adjusted
tax basis in his Partnership interest, the Investor will realize and recognize
a capital loss to the extent of the excess. If the amount of cash distributed
is greater than such Investor's adjusted tax basis in his Partnership interest,
the Investor will recognize a capital gain to the extent of the excess.
Because each Investor paid a portion of syndication and formation costs upon
entering the Partnership, neither of which costs were deductible expenses, it
is anticipated that liquidating distributions to Investors will be less than
such Investors' bases in their Partnership interests and thus will generate
capital losses.
CAPITAL GAIN TAX
Net long-term capital gains of individuals, trusts and estates
generally will be taxed at a maximum rate of 20%, while ordinary income,
including income from the recapture of intangible drilling and development
costs, depreciation and depletion, will be taxed at a maximum rate depending on
that Investor's taxable income of 36% or 39.6%.
PASSIVE LOSS LIMITATIONS
Investors that are individuals, trusts, estates, or personal service
corporations are subject to the passive activity loss limitations rules that
were enacted as part of the Tax Reform Act of 1986.
An Investor's allocable share of Partnership income, gain, loss, and
deduction is treated as derived from a passive activity, except to the extent
of Partnership portfolio income, which includes interest, dividends, royalty
income and gains from the sale of property held for investment purposes.
THE FOREGOING DISCUSSION IS A SUMMARY OF THE INCOME TAX CONSEQUENCES
SET FORTH UNDER "FEDERAL INCOME TAX CONSEQUENCES OF ADOPTION OF THE PROPOSALS"
IN THE JOINT PROXY STATEMENT/PROSPECTUS. IT IS NOT INTENDED AS AN ALTERNATIVE
FOR INDIVIDUAL TAX PLANNING. EACH INVESTOR SHOULD CONSULT HIS, HER OR ITS OWN
TAX ADVISOR CONCERNING THE PARTICULAR FEDERAL, STATE, LOCAL, FOREIGN AND OTHER
TAX CONSEQUENCES APPLICABLE TO HIM, HER OR IT OF THE SALE OF PROPERTIES AND THE
LIQUIDATION OF THE PARTNERSHIP.
SELECTED FINANCIAL INFORMATION AND
PROFORMA FINANCIAL STATEMENTS
For selected financial information and financial statements of the
Partnership, see the Annual Report on Form 10-K for the year ended December 31,
1997 and the Quarterly Report on Form 10-Q for the quarter ended June 30, 1998
attached hereto.
Proforma Financial Statements showing the effect of approval of the
Proposals by the 63 Partnerships to whom similar proposals are being made (both
in the event of the decision by investors to
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<PAGE> 293
purchase the maximum number of shares of Swift Common Stock purchasable with
their cash distributions and in the event that investors choose to take all of
their distributions from sale of the properties in cash) and the effect of the
Sonat Properties Acquisition are contained in the Joint Proxy
Statement/Prospectus under "Unaudited Proforma Consolidated Financial
Statements".
OFFERING OF SHARES OF SWIFT ENERGY COMPANY COMMON STOCK
IF INVESTORS APPROVE THE PROPOSAL
VOTING PROCEDURES
The Joint Proxy Statement/Prospectus contains detailed procedures to
be followed by investors in voting as to the Partnerships' Proposals. Strict
compliance with these procedures must be followed in order for the elections of
the investors marked on the Proxies to be effective. The following is a
summary of certain of these procedures:
(a) Investors may make their elections on the subscription signed by
all subscribers commencing upon delivery of this Joint Proxy
Statement/Prospectus and continuing until the Due Date.
(b) If Investors in the Partnership (and its Companion Partnership)
vote to approve the Proposal, Investors may revoke their election to purchase
Shares offered hereby at any time until the Due Date by delivering or faxing a
letter so stating or a later dated subscription agreement, both of which must
be signed by such revoking subscribers, to the Company at 16825 Northchase
Drive, Suite 400, Houston, Texas 77060, fax number (281) 874-2818; Attention:
Investor Relations Department.
(c) Investors failing to submit proxies by the Special Meeting Date
will be deemed to have voted against their Partnership's Proposal and, if their
Partnership approves its Proposal, will receive, along with non-subscribing
investors who timely submit proxies, their distribution in cash. See "The
Proposals--Vote Required" in the Joint Proxy Statement/Prospectus.
OFFER OF SWIFT COMMON STOCK
Investor Election to Purchase Shares
In connection with the concurrent Proposals for sale of all of the oil
and gas assets of 63 Partnerships to the Company and the subsequent termination
of such Partnerships, the Company is offering up to 2,500,000 shares of the
Company's Common Stock. Upon approval of the Proposals by the Partnership and
its Companion Partnership and sale of the Partnership's oil and gas assets, the
Partnership's assets will consist solely of cash which each investor as an
Eligible Purchaser of the Partnership will be entitled to receive as a
distribution. The Company hereby offers to each such Eligible Purchaser the
opportunity to purchase shares of Common Stock with all or any portion of the
cash distribution such Eligible Purchaser will be entitled to receive, provided
that a minimum round lot of 100 shares must be purchased. If an Eligible
Purchaser has interests in more than one Partnership, the cash distributions he
will be entitled to receive may be aggregated to meet the minimum round lot of
100 shares requirement. Each such Eligible Purchase may purchase shares of
Common Stock with funds in addition to their cash distributions in order to
purchase (i) the minimum round lot of 100 shares, or (ii) shares in addition to
the number of shares for which their cash distribution will be applied, subject
to prorata limitations in the event of oversubscription. No fractional shares
will be sold.
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Purchase Price
The price at which the Common Stock offered hereby will be issued will
be the average price of the Common Stock as reported by the NYSE for the period
between ________ and __________, 1998.
New York Stock Exchange and Pacific Exchange Listings
The Common Stock is traded on the NYSE and the Pacific Exchange under
the symbol "SFY." Application will be made to list the Shares offered hereby
on the NYSE and the Pacific Exchange.
Closing Date
The Company will issue checks representing full or partial
distributions and/or stock certificates representing the shares of Common Stock
subscribed for hereunder approximately forty-five (45) days after the date of
the Prospectus Supplement (the "Closing Date"), unless earlier terminated or
extended by the Company.
Due Date
All subscriptions, revocations of prior subscriptions or additional
required consideration must be received no later than thirty (30) days after
the date of the Prospectus Supplement (the "Due Date"), unless extended by the
Company.
Oversubscription
In the event this Offering is oversubscribed, all subscribing Eligible
Purchasers will first be sold a round lot of 100 shares and then, if
applicable, that number of shares of Common Stock the purchase price of which
is equal to such Eligible Purchaser's cash distribution, rounded down to the
next whole share. Any remaining shares will be sold on a prorata basis based
on the number of shares such subscribers wish to purchase.
Revocation
Eligible Purchasers may revoke their subscriptions to purchase of the
Shares offered hereby at any time until the Due Date by delivering or faxing a
letter so stating or a later dated subscription agreement, either of which must
be signed by such revoking subscribers, to the Company at 16825 Northchase
Drive, Suite 400, Houston, Texas 77060, fax number (281) 874-2818; Attention:
Investor Relations Department.
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TABLE OF CONTENTS
<TABLE>
<S> <C>
THE PARTNERSHIP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
CONFLICTS OF INTEREST . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
SPECIAL FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Background and Purpose of the Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Proposed Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Reasons for the Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Current Liquidating Distribution Lowers Volatility Risk . . . . . . . . . . . . . . . . . . . . . . . 8
Decreasing Cash Flow While Expenses Continue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Limited Partners' Tax Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Collective Analysis of Purchase Price; Premium over Fair Market Value . . . . . . . . . . . . . . . . . . . . 9
Determination of Premium Over Fair Market Value by the Company . . . . . . . . . . . . . . . . . . . . . . . 10
"Special Factors" Section in the Joint Proxy Statement/Prospectus . . . . . . . . . . . . . . . . . . . . . 11
Estimates of Liquidating Net Cash Distribution Amount if the Proposal is Approved . . . . . . . . . . . . . 11
Estimates of Net Cash Distributions Available from Continued Operations . . . . . . . . . . . . . . . . . . 13
Fairness of Proposed Sale of Assets to the Managing General Partner
as Compared to Continuing Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Fairness of Proposed Sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Managing General Partner Benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Simultaneous Proposals to Companion Partnerships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
VOTING ON THE PROPOSAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Vote Required . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Solicitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
PARTNERSHIP BUSINESS AND FINANCIAL CONDITION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Cash Distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Transactions Between the Managing General Partner and the Partnership . . . . . . . . . . . . . . . . . . . 23
No Trading Market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Principal Holders of Investor Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Approvals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
SUMMARY OF FEDERAL INCOME TAX CONSEQUENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Taxable Gain or Loss Upon Sale of Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Liquidation of the Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Capital Gain Tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Passive Loss Limitations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
</TABLE>
(i)
<PAGE> 296
<TABLE>
<S> <C>
SELECTED FINANCIAL INFORMATION AND PROFORMA FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . 26
OFFERING OF SHARES OF SWIFT ENERGY COMPANY COMMON STOCKIF INVESTORS APPROVE THE PROPOSAL . . . . . . . . . . . . . . 27
Voting Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Offer of Swift Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Investor Election to Purchase Shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
New York Stock Exchange and Pacific Exchange Listings . . . . . . . . . . . . . . . . . . . . . . . 28
Closing Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Due Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Oversubscription . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Revocation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
FORM OF PROXY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (A)
</TABLE>
(ii)
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ATTACHMENT A
April 17, 1998
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Attn: Special Transactions Committee FAIR MARKET VALUE ESTIMATE
Board of Directors SWIFT ENERGY INCOME PARTNERS 1989-B, LTD.
97-003-133
Gentlemen:
At your request, we have audited the proved, probable and possible reserves and
future net cash flow as of December 31, 1997, prepared by Swift Energy Company
("Swift") for certain interests owned by the partners in Swift Energy Income
Partners 1989-B, Ltd. This audit has been conducted according to the Standards
Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information
approved by the Board of Directors of the Society of Petroleum Engineers on
October 30, 1979. We have reviewed these properties and where we disagreed with
the Swift reserve estimates, Swift revised its estimates to be in agreement.
From this audit, and in consultation with J.R. Butler and Company, our estimate
of the fair market value of this partnership is $3,083,309.
Fair market value as used herein is defined as that price that a willing buyer
will pay and a willing seller will accept at a given point in time, with neither
the buyer nor the seller under any compulsion to buy or sell, and both having
reasonable knowledge of all the material circumstances.
To estimate the fair market value attributable to the proved developed producing
reserves, the 10 percent discounted future net cash flow was multiplied by a
suitable factor (less than one) to account for the risk associated with the
reserves, operating expenses, and prices and to approximate tax consequences.
The internal rate of return and payout time were computed for this quantity and
compared with those at which current acquisitions are completed. Suitable
adjustments are then made to correspond to these two financial indices. Proved
developed nonproducing, proved undeveloped, probable and possible reserves
require capital investments and must be treated appropriately. For these cases,
the capital is added to the discounted net cash flow, then multiplied by a
suitable risk factor and the capital then subtracted. This has the effect that
capital is spent with certainty and the operating cash income is burdened with
the risk. Internal rate of return and payout time is calculated for each
estimate to establish reasonableness based upon it the reserve category.
<PAGE> 298
Swift Energy Company -2- April 17, 1998
The estimated future net cash flow is that cash flow which will be realized from
the sale of the estimated net reserves after deduction of royalties, ad valorem
and production taxes, direct operating costs and capital expenditures, when
applicable. Surface and well equipment salvage values and well plugging and
field abandonment costs have not been considered in the cash flow projections.
Future net cash flow as stated in this report is before the deduction of federal
income tax.
The following parameters are incorporated in the economic projections referenced
in this report. Initial oil prices are the existing prices on December 31, 1997,
and are escalated 3.5 percent per year beginning in 1999 through the year 2012
after adjusting for transportation and gravity variances. Initial natural gas
prices are those existing on December 31, 1997, and are escalated 3.5 percent
per year beginning in 1999 through the year 2012 after adjusting for
transportation and Btu content. Operating expenses are escalated at an annual
rate of 3.5 percent until the year 2012. The actual prices that will be received
and the associated costs may be more or less than those projected.
For those wells with sufficient production history, reserve estimates and rate
projections are based on the extrapolation of established performance trends.
Reserves for other producing and nonproducing properties have been estimated
from volumetric calculations and analogy with the performance of comparable
wells. The reserves referenced in this study are estimates only and should not
be construed as exact quantities. Future conditions may affect recovery of
estimated reserves and cash flow, and all categories of reserves may be subject
to revision as more performance data become available. The proved reserves are
estimated in accordance with the definitions included in the Securities and
Exchange Commission Regulation S-X, Rule 4-10(a) except for the price and cost
escalations. The definitions are included in part as Attachment I. The probable
and possible reserves conform to the definitions approved by the Society of
Petroleum Engineers, Inc. The definitions are included as Attachment II.
Extent and character of ownership, oil and gas prices, production data, direct
operating costs, capital expenditure estimates and other data provided by Swift
have been accepted as represented. The production data available to us were
through the month of October 1997, except in those instances in which data were
available through December. Interim production to December 31, 1997, has been
estimated. Operating expenses as supplied by Swift were not audited, but were
reviewed for reasonableness. No independent well tests, property inspections or
audits of operating expenses were conducted by our staff in conjunction with
this study. We did not verify or determine the extent, character, obligations,
status or liabilities, if any, arising from any current or possible future
environmental liabilities that might be applicable.
In order to audit the reserves, costs and future cash flows referenced in this
report, we have relied in part on geological, engineering and economic data
furnished by our client. Although we have made a best efforts attempt to acquire
all pertinent data and to analyze it carefully with methods accepted by the
petroleum industry, there is no guarantee that the volumes of oil or gas or the
cash flows projected will be realized. The reserve and cash flow projections
referenced in this report may require revision as additional data become
available.
<PAGE> 299
Swift Energy Company -3- April 17, 1998
H.J. Gruy and Associates, Inc. is unrelated to Swift and has no interest in the
properties included in this report. In particular:
1. We do not own a financial interest in Swift or its oil and gas
properties.
2. Our fee is not contingent on the outcome of our work or report.
3. We have not performed other services for or have any other
relationship with Swift that would affect our independence.
4. No instructions were given and no limitations were imposed by
Swift on the scope or methodology to be used by us in preparing
such estimates; we did not accept or incorporate any assumptions
from Swift, but merely called upon Swift to the extent customary
in the oil and gas industry to gather and provide certain
background information which we determined to be relevant and
appropriate; we determined what information to use; and how and
to what extent such information should be relied upon, in
estimating the fair market values shown above.
If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such person with the approval of our
client is invited to visit our offices at his expense so that he can evaluate
the assumptions made and the completeness and extent of the data available on
which our estimates are based.
Any distribution or publication of this report or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
/s/ JAMES H. HARTSOCK
James H. Hartsock, Ph.D., P.E.
Executive Vice President
JHH:akr
Attachment
<PAGE> 300
ATTACHMENT I
DEFINITIONS OF PROVED OIL AND GAS RESERVES(1)
PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquid which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
PROVED DEVELOPED OIL AND GAS RESERVES
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be 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.
PROVED UNDEVELOPED RESERVES
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
- --------
(1) Contained in Securities and Exchange Commission Regulation S-X,
Rule 4-10(a)
H.J. GRUY AND ASSOCIATES, INC. 1200 Smith Street, Suite 3040,
Houston, Texas 77002 (713) 739-1000
<PAGE> 301
ATTACHMENT II
PETROLEUM RESERVES DEFINITIONS
SOCIETY OF PETROLEUM ENGINEERS (SPE) AND WORLD PETROLEUM CONGRESS (WPC)(1)
Reserves are those quantities of petroleum which are anticipated to be
commercially recovered from known accumulations from a given date forward. All
reserve estimates involve some degree of uncertainty. The uncertainty depends
chiefly on the amount of reliable geologic and engineering data available at the
time of the estimate and the interpretation of these data. The relative degree
of uncertainty may be conveyed by placing reserves into one of two principal
classifications, either proved or unproved. Unproved reserves are less certain
to be recovered than proved reserves and may be further sub-classified as
probable and possible reserves to denote progressively increasing uncertainty in
their recoverability.
The intent of the SPE and WPC in approving additional classifications beyond
proved reserves is to facilitate consistency among professionals using such
terms. In presenting these definitions, neither organization is recommending
public disclosure of reserves classified as unproved. Public disclosure of the
quantities classified as unproved reserves is left to the discretion of the
countries or companies involved.
Estimation of reserves is done under conditions of uncertainty. The method of
estimation is called deterministic if a single best estimate of reserves is made
based on known geological, engineering and economic data. The method of
estimation is called probabilistic when the known geological, engineering, and
economic data are used to generate a range of estimates and their associated
probabilities. Identifying reserves as proved, probable, and possible has been
the most frequent classification method and gives an indication of the
probability of recovery. Because of potential differences in uncertainty,
caution should be exercised when aggregating reserves of different
classifications.
Reserves estimates will generally be revised as additional geologic or
engineering data become available or as economic conditions change. Reserves do
not include quantities of petroleum being held in inventory, and may be reduced
for usage of processing losses if required for financial reporting.
Reserves may be attributed to either natural energy or improved recovery
methods. Improved recovery methods include all methods for supplementing natural
energy or altering natural forces in the reservoir to increase ultimate
recovery. Examples of such methods are pressure maintenance, cycling,
waterflooding, thermal methods, chemical flooding, and the use of miscible and
immiscible displacement fluids. Other improved recovery methods may be developed
in the future as petroleum technology continues to evolve.
PROVED RESERVES
Proved reserves are those quantities of petroleum which, by analysis of
geological and engineering data, can be estimated with reasonable certainty to
be commercially recoverable, from a given date forward, from known reservoirs
and under current economic conditions, operating methods, and government
regulations. Proved reserves can be categorized as developed or undeveloped.
If deterministic methods are used, the term reasonable certainty is intended to
express a high degree of confidence that the quantities will be recovered. If
probabilistic methods are used, there should be at least a 90% probability that
the quantities actually recovered will equal or exceed the estimate.
Establishment of current economic conditions should include relevant historical
petroleum prices and associated costs and may involve an averaging period that
is consistent with the purpose of the reserve estimate, appropriate contract
obligations, corporate procedures, and government regulations involved in
reporting these reserves.
In general, reserves are considered proved if the commercial producibility of
the reservoir is supported by actual production or formation tests. In this
context, the term proved refers to the actual quantities of petroleum reserves
and not just the productivity of the well or reservoir. In certain cases,
proved reserves may be assigned on the basis of well logs and/or core analysis
that indicate the subject reservoir is hydrocarbon bearing and is analogous to
reservoirs in the same area that are producing or have demonstrated the ability
to produce on formation tests.
The area of the reservoir considered as proved includes (1) the area delineated
by drilling and defined by fluid contacts, if any, and (2) the undrilled
portions of the reservoir that can reasonably be judged as commercially
productive on the basis of available geological and engineering data. In the
absence of data on fluid contacts, the lowest known occurrence of hydrocarbons
controls the proved limit unless otherwise indicated by definitive geological,
engineering or performance data.
- --------------------------
(1) Approved by the Board of Directors. Society of Petroleum Engineers (SPE),
Inc. on March 7, 1997.
<PAGE> 302
Reserves may be classified as proved if facilities to process and transport
those reserves to market are operational at the time of the estimate or there is
a reasonable expectation that such facilities will be installed. Reserves in
undeveloped locations may be classified as proved undeveloped provided (1) the
locations are direct offsets to wells that have indicated commercial production
in the objective formation, (2) it is reasonably certain such locations are
within the known proved productive limits of the objective formation, (3) the
locations conform to existing well spacing regulations where applicable, and (4)
it is reasonably certain the locations will be developed. Reserves from other
locations are categorized as proved undeveloped only where interpretations of
geological and engineering data from wells indicate with reasonable certainty
that the objective formation is laterally continuous and contains commercially
recoverable petroleum at locations beyond direct offsets.
Reserve which are to be produced through the application of established improved
recovery methods are included in the proved classification when (1) successful
testing by a pilot project or favorable response of an installed program in the
same or an analogous reservoir with similar rock and fluid properties provides
support for the analysis on which the project was based, and, (2) it is
reasonably certain that project will proceed. Reserves to be recovered by
improved recovery methods that have yet to be established through commercially
successful applications are included in the proved classification only (1) after
a favorable production response from the subject reservoir from either (a) a
representative pilot or (b) an installed program where the response provides
support for the analysis on which the project is based and (2) it is reasonably
certain the project will proceed.
UNPROVED RESERVES
Unproved reserves are based on geologic and/or engineering data similar to that
used in estimates of proved reserves; but technical, contractual, economic, or
regulatory uncertainties preclude such reserves being classified as proved.
Unproved reserves may be further classified as probable reserves and possible
reserves.
Unproved reserves may be estimated assuming future economic conditions different
from those prevailing at the time of the estimate. The effect of possible future
improvements in economic conditions and technological developments can be
expressed by allocating appropriate quantities of reserves to the probable and
possible classifications.
PROBABLE RESERVES
Probable reserves are those unproved reserves which analysis of geological and
engineering data suggests are more likely than not to be recoverable. In this
context, when probabilistic methods are used, there should be a least a 50%
probability that the quantities actually recovered will equal or exceed the sum
of estimated proved plus probable reserves.
In general, probable reserves may include (1) reserves anticipated to be proved
by normal step-out drilling where subsurface control is inadequate to classify
these reserves as proved, (2) reserves in formations that appear to be
productive based on well log characteristics but lack core data or definitive
tests and which are not analogous to producing or proved reservoirs in the area,
(3) incremental reserves attributable to infill drilling that could have been
classified as proved if closer statutory spacing had been approved at the time
of the estimate, (4) reserves attributable to improved recovery methods that
have been established by repeated commercially successful applications when (a)
a project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir characteristics appear favorable for commercial application, (5)
reserves in an area of the formation that appears to be separated from the
proved area by faulting and the geologic interpretation indicates the subject
area is structurally higher than the proved area, (6) reserves attributable to a
future workover, treatment, re-treatment, change of equipment, or other
mechanical procedures, where such procedure has not been proved successful in
wells which exhibit similar behavior in analogous reservoirs, and (7)
incremental reserves in proved reservoirs where an alternative interpretation of
performance or volumetric data indicates more reserves than can be classified as
proved.
POSSIBLE RESERVES
Possible reserves are those unproved reserves which analysis of geological and
engineering data suggests are less likely to be recoverable than probable
reserves. In this context, when probabilistic methods are used, there should be
a least a 10% probability that the quantities actually recovered will equal or
exceed the sum of estimated proved plus probable plus possible reserves.
In general, possible reserves may include (1) reserves which, based on
geological interpretations, could possibly exist beyond areas classified as
probable, (2) reserves in formations that appear to be petroleum bearing based
on log and core analysis but may not be productive at commercial rates, (3)
incremental reserves attributed to infill drilling that are subject to technical
uncertainty, (4) reserves attributed to improved recovery methods when (a) a
project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir
<PAGE> 303
characteristics are such that a reasonable doubt exists that the project will be
commercial, and (5) reserves in an area of the formation that appears to be
separated from the proved area by faulting and geological interpretation
indicates the subject area is structurally lower than the proved area.
RESERVE STATUS CATEGORIES
Reserve status categories define the development and producing status of wells
and reservoirs.
DEVELOPED: Developed reserves are expected to be recovered from existing
wells including reserves behind pipe. Improved recovery reserves are
considered developed only after the necessary equipment has been installed,
or when the costs to do so are relatively minor. Developed reserves may be
sub-categorized as producing or non-producing.
PRODUCING: Reserves subcategorized as producing are expected to be
recovered from completion intervals which are open and producing at the
time of the estimate. Improved recovery reserves are considered
producing only after the improved recovery project is in operation.
NON-PRODUCING. Reserves subcategorized as non-producing include shut-in
and behind-pipe reserves. Shut-in reserves are expected to be recovered
from (1) completion intervals which are open at the time of the
estimate but which have not started producing, (2) wells which were
shut-in for market conditions or pipeline connections (3) wells not
capable of production for mechanical reasons. Behind-pipe reserves are
expected to be recovered from zones in existing wells, which will
require additional completion work or future recompletion prior to the
start of production.
UNDEVELOPED RESERVES: Undeveloped reserves are expected to be recovered:
(1) from new wells on undrilled acreage, (2) from deepening existing wells
to a different reservoir, or (3) where a relatively large expenditure is
required to (a) recomplete an existing well or (b) install production or
transportation facilities for primary or improved recovery projects.
<PAGE> 304
ATTACHMENT B
APRIL 17, 1998
SWIFT ENERGY COMPANY
16825 Northchase Drive
Suite 400
Houston, Texas 77060
RE: FAIR MARKET VALUE OPINION
AS OF DECEMBER 31, 1997
SWIFT ENERGY INCOME PARTNERS
1989-B, LTD.
ATTENTION: SPECIAL TRANSACTIONS COMMITTEE
SWIFT ENERGY COMPANY BOARD OF DIRECTORS
At the request of SWIFT ENERGY COMPANY (SWIFT), J. R. BUTLER AND COMPANY
(JRBCO) has conducted an evaluation audit of the hydrocarbon reserves and
future net cash flow as of December 31, 1997, associated with 44 Acquisition
Programs located in the U.S.A. From this audit, and in consultation with H. J.
Gruy and Associates, Inc. (Gruy), JRBCO has generated its opinion of a "fair
market value" for these properties. The market values of the properties were
distributed to various partnerships based on ownership to determine the fair
market value of each partnership. In JRBCO'S opinion, utilizing the
distribution of properties into the proper partnerships, the estimated market
value of SWIFT ENERGY INCOME PARTNERS 1989-B, LTD. is $3,083,309.
Proved reserves in this instance are defined as those estimated volumes of
crude oil, condensate, natural gas, and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty to be commercially
recoverable in the future from known reservoirs under a reasonable price and
cost escalation scenario. Probable reserves are the estimated quantities of
commercially recoverable hydrocarbons associated with known accumulations which
are based on engineering and geological data similar to those used in the
estimates of proved reserves but, for various reasons, these data lack the
certainty required to classify the reserves as proved. Possible reserves are
the estimated quantities of commercially recoverable hydrocarbons associated
with known accumulations, which are based on engineering and geological data
which are less complete and less conclusive than the data used in estimates of
probable reserves. In some cases, economic or regulatory uncertainties may
dictate a probable or possible classification.
Recovery of proved reserves is not without risk but, as generally considered in
the industry, the risk of recovering probable reserves is substantially greater
than that associated with proved categories. Likewise, possible reserves are
less certain to be recovered than probable.
The reserves and future performance estimates were prepared utilizing standard
petroleum engineering methods. For properties with sufficient production
history,
1
<PAGE> 305
reserves estimates and rate projections were based primarily on extrapolation
of established performance trends and reconciled, whenever possible, with
volumetric and/or material balance calculations. For the non-producing zones
and undeveloped locations, reserves were determined by a combination of
volumetric calculations and analogy. Volumetrically determined reserves or
those determined by analogy are generally subject to greater qualifications
than reserves estimates supported by established production decline curves
and/or material balance calculations. Determination and classification of
proved reserves were performed (with exception of the use of escalated prices
and costs) in accordance with Securities and Exchange Commission guidelines.
The definitions used also conform to those promulgated by the Society of
Petroleum Engineers (SPE) and the World Petroleum Congresses (WPC).
The reserves and resulting "value estimates" included in this study are not
exact quantities. Future conditions may affect the recovery of estimated
reserves, revenue and net cash flow, and all categories of reserves may be
subject to revision and/or reclassification as more performance and well data
become available. Please note, the reserves estimates made by JRBCO were done
in conjuction with an evaluation audit and are not the result of in-depth field
studies. In conducting this audit JRBCO reviewed approximately 65% of SWIFT'S
proved "PV 10 value" (SEC PV10 as of December 31, 1997) for the total 44
Acquisition Programs.
Basic evaluation data were obtained principally from SWIFT and public sources.
The production data available to JRBCO were generally through August 1997.
Gas and liquid prices were year end (CY 1997) prices as used in SWIFT'S
December 31, 1997, SEC cash flow runs.
Estimates of drilling, completion and workover costs were based on information
supplied by SWIFT. Operating costs were also based on data supplied by SWIFT
in their Lease Operating Statement which was reviewed by JRBCO. Surface and
well equipment salvage values and well plugging and field abandonment costs
were not considered in the revenue projections.
The estimates of future net cash flow used in market value calculations are
those revenues which should be realized from the sale of the estimated reserves
after deduction of royalties, ad valorem and production taxes, direct operating
costs and required capital expenditures, when applicable. Future net cash flow
as used in this evaluation is before the deduction of federal income tax.
Market value estimates were obtained by applying qualitative risk adjustments
considered appropriate for the various reserves categories and "profit factors"
(as applicable) against discounted future net cash flow values obtained from an
escalated cost and pricing scenario. Prices, costs and investments were
escalated at 3.5%/year for 15 years. Final market value estimates were derived
in conjunction and consultation with Gruy.
In the conduct of our review, we have not independently verified the accuracy
and completeness of information and data furnished by SWIFT with respect to
ownership interests, oil and gas production volumes and rates, historical costs
of operation and development, product prices, agreements relating to current
and future operations and sales of production and other information relative to
such things as timing or scheduling of drilling or recompletion operations.
Field inspections were not made in connection with the preparation of this
report. Furthermore, no judgments were made relative to environmental or other
legal liabilities.
It should be recognized that any oil or gas reserves estimate or forecast of
production and income is a function of engineering and geological
interpretation and judgment. Such estimates should, therefore, be accepted and
used with the understanding that technical data, economic criteria or
regulatory information obtained subsequent to a study may justify revisions
which could increase or decrease the original estimates of reserves and value.
Neither JRBCO, nor any of its personnel, have any direct or indirect interest
in SWIFT or its affiliates. JRBCO is an independent consulting firm as
provided in the Standards Pertaining to the Estimating and Auditing of Oil and
Gas Reserves Information promulgated by the Society of Petroleum Engineers.
2
<PAGE> 306
JRBCO'S compensation is not contingent upon the results of its reserves
estimates, cash flow analyses or "market value opinion" which result from its
review of the subject properties.
READ AND APPROVED:
/s/ BRIAN E. AUSBURN
- ------------------------------
BRIAN E. AUSBURN, PRESIDENT
DATE: April 17, 1998
-------------------------
BEA:mlc
3
<PAGE> 307
ATTACHMENT C
April 20, 1998
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, TX 77060
Attention: Special Transactions Committee
Swift Energy Company Board of Directors
Gentlemen:
Pursuant to that certain letter agreement dated February 27, 1998 (the
"Agreement") between the Special Transactions Committee (the "Committee") of the
Board of Directors of Swift Energy Company ("Swift" or the "Company") and CIBC
Oppenheimer Corp. ("CIBC Oppenheimer"), you have retained CIBC Oppenheimer to
prepare an independent financial analysis as to the estimated fair market value
(the "CIBC Oppenheimer Valuation") of various interests (the "Assets") in oil
and gas properties (the "Properties'), which Assets are owned by Swift Energy
Income Partners 1989-B Ltd. (the "Partnership") of which the Company is the
managing general partner ("General Partner"). CIBC Oppenheimer performed a
similar analysis for 62 other partnerships (the "Partnerships") of which the
Company is the General Partner. It is CIBC Oppenheimer's understanding that the
General Partner has proposed to purchase substantially all of the Partnership's
Assets and, in turn, dissolve and wind up the Partnership. It is also CIBC
Oppenheimer's understanding that the Committee has also retained the reserve
engineering firms of H.J. Gruy & Associates, Inc. and J.R. Butler & Company
(collectively, the "Engineering Consultants") to prepare a separate analysis as
to the estimated fair market value of the Assets (the "Engineering Consultants'
Valuation").
In arriving at the CIBC Oppenheimer Valuation, we, among other things:
(i) Reviewed the historical financial returns to the limited
partners of the Partnership;
(ii) Held discussions with senior management of the Company as to
the Partnership's operational and financial prospects;
<PAGE> 308
Swift Energy Company
April 20, 1998
Page 2
(iii) Held discussions with senior management of the Company
regarding the general characteristics of the Properties
underlying the Assets, including location, productive
geological formations, future development potential and oil
and gas marketing arrangements;
(iv) Held discussions with the Engineering Consultants regarding
the general characteristics of the Properties underlying the
Assets, including location, productive geological formations
and future development potential;
(v) Reviewed the reserve engineering reports supplied to us by the
Engineering Consultants and, particularly, reviewed the
estimated future net cash flow to be generated from the
production of proved reserves of the Properties underlying the
Assets discounted to present value using an annual discount
rate of 10% (the "PV-10 Value") dated as of December 31, 1997;
these amounts were calculated net of estimated production
costs and future development costs, using prices and costs in
effect as of a certain date, without escalation and without
giving effect to non-property related expenses such as future
income tax expense or depreciation, depletion and
amortization;
(vi) Reviewed the Engineering Consultants' Valuation of the
Properties underlying the Assets;
(vii) Reviewed historical operating and financial results of the
Properties underlying the Assets which included PV-10 Value,
proved reserves on a barrel of oil equivalent ("BOE") basis
and projected earnings before interest, taxes and
depreciation, depletion and amortization ("EBITDA") as
prepared by the Engineering Consultants and discussed with
senior management of the Company;
(viii) Reviewed and analyzed financial terms of similar transactions
in which public oil and gas companies liquidated partnerships
of which they were the general partner;
(ix) Reviewed and analyzed transactions involving the sale of oil
and gas companies we deemed comparable to the Partnership(s)
individually and collectively and to the Company;
<PAGE> 309
Swift Energy Company
April 20, 1998
Page 3
(x) Reviewed and analyzed transactions involving the sale of oil
and gas properties we deemed comparable to the Properties
underlying the Assets;
(xi) Reviewed financial and market data for certain public
companies we deemed comparable to the Partnership(s)
individually and collectively and to the Company; and
(xii) Performed such other analyses and reviewed such other
information as we deemed appropriate.
In determining the CIBC Oppenheimer Valuation, we have relied upon and assumed,
without independent verification or investigation and at the direction of the
Committee, (i) the accuracy and completeness of all of the financial and other
information available to us from public sources or provided to us by the Company
and their representatives (including the Engineering Consultants), (ii) that the
reserve engineering reports supplied to us by the Engineering Consultants as
described in clause (v) above have been reasonably prepared and are based on
their best business judgment, (iii) that the information with respect to the
Partnership's ownership of the Assets, as provided to the Engineering
Consultants and to us was accurate in all respects, (iv) with respect to the
historical operating and financial results and projections provided to us as
described in clause and (vii) above, that such information and projections were
reasonably prepared and were based on the best currently available information,
estimates and good faith judgment of the Company's management and their
representatives (including the Engineering Consultants).
Not being experts in the geological evaluation of oil and gas reserves, we have,
with your consent, relied without independent verification upon the audit of the
reserve estimates prepared by the Engineering Consultants for the purpose of
estimating fair market value of the Assets. In addition, we have not made a
physical inspection of the Properties underlying the Assets, nor have we made
any independent evaluations, appraisals or inspections of the Company's or the
Partnership's other assets or the Company's or the Partnership's liabilities
(contingent or otherwise). We have not reviewed any relevant agreements which
may exist between the General Partner and the limited partners governing the
Partnership, nor have we considered the effect which the ownership structure of
the Partnership and the terms of the agreements of the Partnership may have upon
the fairness of the consideration offered by any general partner of the
Partnership. We have not reviewed the books and records of the Partnership and
have assumed, with your consent, that the Partnership's ownership interests in
the Properties underlying the Assets, as provided to us by you, is true and
correct.
<PAGE> 310
Swift Energy Company
April 20, 1998
Page 4
The CIBC Oppenheimer Valuation is based upon analyses of the foregoing factors
in light of our assessment of general economic, financial, market and other
conditions and circumstances as of the date of this letter and any changes in
such conditions and circumstances may affect the validity or fairness of the
CIBC Oppenheimer Valuation. CIBC Oppenheimer disclaims any obligations to
update, revise or reaffirm the CIBC Oppenheimer Valuation. The CIBC Oppenheimer
Valuation reflects our estimate of the consideration that could have been
received by the Partnership in a sale of the Assets in an orderly manner in a
private market transaction in which neither buyer nor seller is under any
compunction to complete such transaction. The CIBC Oppenheimer Valuation falls
within a range of values which we believe, subject to the foregoing conditions,
represent possible fair market value estimates of the Partnership's interest in
the Assets. The CIBC Oppenheimer Valuation should not be viewed as a guarantee
of the price that a willing buyer might have paid for the Assets.
CIBC Oppenheimer, as part of its investment banking services, is regularly
engaged in the valuation of businesses and securities in connection with
mergers, acquisitions, underwritings, sales and distributions of listed and
unlisted securities and private placements. CIBC Oppenheimer has provided
certain investment banking and financial advisory services to the Company from
time to time, including acting as co-manager of the Company's Convertible
Subordinated Notes financing in November 1996 and lead manager of the public
offering of the Company's Common Stock in July 1995, and may be involved in
future investment banking activities on behalf of the Company. CIBC Oppenheimer
will also receive a fee upon delivery of this CIBC Oppenheimer Valuation. In the
ordinary course of business, CIBC Oppenheimer actively trades in the equity
securities of the Company for CIBC Oppenheimer's own account and for the
accounts of CIBC Oppenheimer's customers and, accordingly, may at any time hold
a long or short position in such securities.
Based upon and subject to the foregoing, and based upon such other matters as we
consider relevant, it is CIBC Oppenheimer's estimate that the value of Swift
Energy Income Partners 1989-B Ltd. interest in the Assets as of the date hereof
is $3,028,036.
This letter is being provided for the use of the Committee in its evaluation of
a possible proposal that the Partnership sell the Assets to the Managing General
Partner and dissolve and wind up its affairs. This letter is not intended to
confer rights or remedies upon any stockholder of the Company or any partner of
the Partnership and may not be relied upon by any person or entity other than
the Committee. Neither this letter nor the CIBC Oppenheimer Valuation may be
published or otherwise used or referred to, in whole or
<PAGE> 311
Swift Energy Company
April 20, 1998
Page 5
part, nor shall any public reference to CIBC Oppenheimer, this letter or the
CIBC Oppenheimer Valuation be made without the prior written consent of CIBC
Oppenheimer; provided, however, that the Company and the Partnership may include
a copy of this letter and a reference to CIBC Oppenheimer in the proxy statement
to be distributed to limited partners of the Partnership in connection with the
solicitation of the approval of the proposal that the Partnership sell the
Assets to the General Partner and dissolve and wind up its affairs. Neither this
letter nor the CIBC Oppenheimer Valuation constitutes a recommendation to any
partner of the Partnership as to how such partner should vote on or respond to
the proposal that the Partnership sell the Assets to the General Partner and
dissolve and wind up its affairs.
Sincerely yours,
/s/ BRIAN MYERS
CIBC Oppenheimer Corp.
<PAGE> 312
ATTACHMENT D
February 10, 1998
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
SWIFT ENERGY INCOME PARTNERS 1989-B
97-003-133
Gentlemen:
At your request, we have made an audit of the reserves and future net cash flow
as of December 31, 1997, prepared by Swift Energy Company ("Swift") for certain
interests in Swift Energy Income Partners 1989-B. This audit has been conducted
according to the standards pertaining to the estimating and auditing of oil and
gas reserve information approved by the Board of Directors of the Society of
Petroleum Engineers on October 30, 1979. We have reviewed these properties and
where we disagreed with the Swift reserve estimates, Swift revised its estimates
to be in agreement. The estimated net reserves, future net cash flow and
discounted future net cash flow are summarized by reserve category in Table 1
for both the 100% Fund Level Partnership and the Limited Partnership Interest.
The discounted future net cash flow is not represented to be the fair market
value of these reserves and the estimated reserves included in this report have
not been adjusted for risk.
The estimated future net cash flow shown is that cash flow which will be
realized from the sale of the estimated net reserves after deduction of
royalties, ad valorem and production taxes, direct operating costs and required
capital expenditures, when applicable. Surface and well equipment salvage values
and well plugging and field abandonment costs have not been considered in the
cash flow projections. Future net cash flow as stated in this report is before
the deduction of state and federal income tax.
In the economic projections, prices, operating costs and development costs
remain constant for the projected life of each lease.
The reserves included in this study are estimates only and should not be
construed as exact quantities. Future conditions may affect recovery of
estimated reserves and cash flow, and all categories of reserves may be subject
to revision as more performance data become available. Proved reserves are
estimated in accordance with the definitions contained in Securities and
Exchange Commission Regulation S-X, Rule 4-10 (a). The definitions are included
in part as Attachment I.
Extent and character of ownership, oil and gas prices, production data, direct
operating costs, capital expenditure estimates and other data provided by Swift
have been accepted as represented. The production data available to us were
through the month of October 1997, except in those instances in which data were
available through December. Interim production to December 31, 1997, has been
estimated. No independent well tests, property inspections or audits of
operating expenses were conducted by our staff in conjunction with this study.
We did not verify or determine the extent, character, obligations, status or
liabilities, if any, arising from any current or possible future environmental
liabilities that might be applicable.
<PAGE> 313
Swift Energy Company -2- February 10, 1998
In order to audit the reserves, costs and future net cash flows shown in this
report, we have relied in part on geological, engineering and economic data
furnished by our client. Although we have made a best efforts attempt to acquire
all pertinent data and to analyze it carefully with methods accepted by the
petroleum industry, there is no guarantee that the volumes of oil or gas or the
cash flows projected will be realized.
Production rates may be subject to regulation and contract provisions, and may
fluctuate according to market demand or other factors beyond the control of the
operator. The reserve and cash flow projections presented in this report may
require revision as additional data become available.
We are unrelated to Swift and we have no interest in the properties included in
the information reviewed by us. In particular:
1. We do not own a financial interest in Swift or its oil and gas
properties.
2. Our fee is not contingent on the outcome of our work or report.
3. We have not performed other services for or have any other
relationship with Swift that would affect our independence.
If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such person with the approval of our
client is invited to visit our offices at his expense so that he can evaluate
the assumptions made and the completeness and extent of the data available on
which our estimates are based.
Any distribution or publication of this report or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
/s/ JAMES H. HARTSOCK
James H. Hartsock, Ph.D., P.E.
Executive Vice President
JHH:llb
Attachment
<PAGE> 314
TABLE 1
100% FUND LEVEL PARTNERSHIP INTEREST
<TABLE>
<CAPTION>
Estimated Estimated
Net Reserves Future Net Cash Flow
------------------------ ---------------------------
Oil & Discounted
Condensate at 10%
(Barrels) Gas (Mcf) Nondiscounted Per Year
---------- --------- ------------- -----------
<S> <C> <C> <C> <C>
Proved Developed 234,286 1,958,153 $ 5,432,973 $ 3,534,920
Proved Undeveloped 23,967 325,869 $ 819,122 $ 474,497
------- --------- ----------- -----------
Total Proved 258,253 2,284,022 $ 6,252,095 $ 4,009,417
G&A $ (787,764) $ (506,180)
------- --------- ----------- -----------
Total 258,253 2,284,022 $ 5,464,331 $ 3,503,237
</TABLE>
LIMITED PARTNERSHIP INTEREST
<TABLE>
<CAPTION>
Estimated Estimated
Net Reserves Future Net Cash Flow
------------------------ ---------------------------
Oil & Discounted
Condensate at 10%
(Barrels) Gas (Mcf) Nondiscounted Per Year
---------- --------- ------------- -----------
<S> <C> <C> <C> <C>
Proved Developed 199,144 1,664,430 $ 4,608,853 $ 2,997,197
Proved Undeveloped 20,372 276,989 $ 657,328 $ 367,763
------- --------- ----------- -----------
Total Proved 219,516 1,941,419 $ 5,266,181 $ 3,364,960
G&A $ (663,540) $ (424,947)
------- --------- ----------- -----------
Total 219,516 1,941,419 $ 4,602,641 $ 2,940,013
</TABLE>
INC89-B.TBL
H.J. GRUY AND ASSOCIATES, INC. 1200 Smith Street, Suite 3040,
Houston, Texas 77002 (713) 739-1000
<PAGE> 315
ATTACHMENT I
DEFINITIONS OF PROVED OIL AND GAS RESERVES(1)
PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquid which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
PROVED DEVELOPED OIL AND GAS RESERVES
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be 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.
PROVED UNDEVELOPED RESERVES
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
- --------
(1) Contained in Securities and Exchange Commission Regulation S-X,
Rule 4-10(a)
H.J. GRUY AND ASSOCIATES, INC. 1200 Smith Street, Suite 3040,
Houston, Texas 77002 (713) 739-1000
<PAGE> 316
FORM OF PROXY
SWIFT ENERGY INCOME PARTNERS 1989-B, LTD.
THIS PROXY IS SOLICITED BY THE MANAGING GENERAL PARTNER FOR A
SPECIAL MEETING OF LIMITED PARTNERS TO BE HELD ON _________, 1998
The undersigned hereby constitutes and appoints A. Earl Swift, Bruce
H. Vincent, Terry E. Swift or John R. Alden, duly authorized officers of Swift
Energy Company acting in its capacity as Managing General Partner of the
Partnership, or any of them, as Proxies, each with full power to appoint his
substitute, and hereby authorizes the Proxies or any of them to represent the
undersigned at a Special Meeting of the Limited Partners (the "Meeting") of
SWIFT ENERGY INCOME PARTNERS 1989-B, LTD. (the "Partnership") to be held on
__________, 1998 at 4:00 p.m. Houston time, at 16825 Northchase Drive, Houston,
Texas, and any adjournments thereof, and to vote as designated, on the matter
specified below, the Partnership Units standing in the name of the undersigned
on the books of the Partnership (or which the undersigned may be entitled to
vote) on the record date for the Meeting, and hereby revokes any proxy or
proxies heretofore given by the undersigned.
1. The adoption of a proposal FOR AGAINST ABSTAIN
("Proposal") for the sale of
substantially all of the assets of
the Partnership to the Managing [ ] [ ] [ ]
General Partner and the dissolution,
winding up and termination of the
Partnership. The undersigned hereby
directs said proxies to vote:
2. In their discretion, the proxies are authorized to vote upon such other
matters as may properly come before the meeting or any adjournments or
postponements thereof.
THIS PROXY WHEN PROPERLY EXECUTED, WILL BE VOTED IN ACCORDANCE WITH
THE DIRECTIONS MADE HEREON. IF NO DIRECTION IS MADE, IT WILL BE VOTED FOR THE
PROPOSAL.
Receipt of the Partnership's Notice of Special Meeting of Limited
Partners and Proxy Statement dated ________, 1998 is acknowledged.
PLEASE SIGN EXACTLY AS NAME APPEARS BELOW AND RETURN THE PROXY IN THE
ENCLOSED, POSTAGE-PAID, PRE-ADDRESSED ENVELOPE BY __________, 1998.
SIGNATURE DATE
----------------------------------- --------------
SIGNATURE DATE
----------------------------------- --------------
SIGNATURE DATE
----------------------------------- --------------
IF LIMITED PARTNERSHIP UNITS ARE HELD JOINTLY, ALL JOINT TENANTS MUST
SIGN. WHEN SIGNING AS ATTORNEY, EXECUTOR, ADMINISTRATOR, TRUSTEE OR GUARDIAN,
PLEASE GIVE FULL TITLE AS SUCH. IF A CORPORATION, PLEASE SIGN IN FULL
CORPORATE NAME BY PRESIDENT OR OTHER AUTHORIZED OFFICER. IF A PARTNERSHIP,
PLEASE SIGN IN PARTNERSHIP NAME BY AUTHORIZED PERSON.
<PAGE> 317
SWIFT ENERGY PENSION PARTNERS 1993-B, LTD.
(THE "PARTNERSHIP")
SUPPLEMENT
TO
JOINT PROXY STATEMENT/PROSPECTUS
DATED ________, 1998
SPECIAL MEETINGS OF THE PARTNERSHIPS
AND
OFFERING OF COMMON STOCK OF
SWIFT ENERGY COMPANY
For the definition of capitalized terms herein which are not otherwise
defined, see "Glossary" in the Joint Proxy Statement/Prospectus. Other
discussions which are cross-referenced in this Supplement are contained in the
Joint Proxy Statement/Prospectus, unless otherwise noted.
Swift Energy Company ("Swift" or the "Company") is the Managing
General Partner ("Managing General Partner") of 63 Texas limited partnerships
(the "Partnerships"), including the Partnership, formed between 1986 and 1994
to invest in producing oil and gas properties. Swift is asking interest
holders (referred to herein as "Investors") in the Partnership (and similarly
in the other 62 Partnerships) to approve a Proposal to ultimately sell all of
the Partnership's oil and gas assets to the Managing General Partner (the
"Proposal") for $1,427,367, which is a purchase price derived by choosing the
higher of two estimates of fair market value of those assets determined by
three independent Appraisers, and adding to that higher number a 7.5% premium.
If the Proposal is approved by Investors in the Partnership and its
Companion Partnership, after the ultimate sale of all of its oil and gas assets
the Partnership will dissolve, wind up and terminate. The Partnership will
receive cash for its oil and gas assets, which in turn is to be distributed to
the Investors in the Partnership (along with the net of all assets less
liabilities of the Partnership) in accordance with their respective percentage
ownership interests in the Partnership. If Investors in the Partnership
approve the Proposal, then each Investor can elect, in their sole individual
discretion, to receive shares of Common Stock of the Company (without payment
of any brokerage commissions) instead of some or all of the cash which they are
entitled to receive upon the Partnership's liquidation.
The reasons for and effects of the Proposals may be different for
investors in each of the Partnerships. This Supplement has been prepared to
highlight for the Investors in the Partnership the particular risks, effects
and fairness of the Proposal to the Investors in the Partnership and to provide
information on the Partnership to its Investors, in connection with the
solicitation of proxies by the
<PAGE> 318
Managing General Partner for use at the Special Meeting of the Investors in the
Partnership in voting upon the Proposal and to transact such other business as
may be properly presented at the Special Meeting or any adjournments or
postponements thereof.
BOTH THE VOTE UPON THE PROPOSAL AND ANY ELECTION MADE BY AN INDIVIDUAL
INVESTOR TO RECEIVE SHARES OF SWIFT ENERGY COMPANY COMMON STOCK ARE SUBJECT TO
NUMEROUS RISK FACTORS, INCLUDING THOSE HIGHLIGHTED BELOW. SEE "RISK FACTORS"
IN THIS SUPPLEMENT AND IN THE JOINT PROXY STATEMENT/PROSPECTUS FOR A FULL
DISCUSSION OF ALL RISK FACTORS.
o Substantial conflicts of interest exist because if the Proposal is
approved by the Partnership and its Companion Partnership, the
Managing General Partner will purchase all of the oil and gas assets
from the Partnership while it serves as its Managing General Partner.
o The purchase price for the Partnership's Property Interests may not be
the highest possible price.
o No independent representative negotiated the terms of the purchase
price with the Managing General Partner.
o No fairness opinion was acquired regarding the fairness of the
purchase price.
o The Managing General Partner may profit from acquisition of the
Partnership's oil and gas assets by investing capital in order to
develop non-producing reserves of the acquired Property Interests and
possibly through improvement in oil and gas prices.
o Estimates of distributions to Investors from continuing operations of
the Partnership for the life of its reserves are higher than amounts
anticipated to be received if Investors vote in favor of the Proposal.
See "Special Factors--Fairness of Proposal of Sale of Assets as
Compared to Continuing Operations."
o An election by an Investor to receive shares of Swift Common Stock in
lieu of cash distributable to Investors subjects such Investors to the
risks of investing in the Company.
This Supplement is dated ______________, 1998
2
<PAGE> 319
THE PARTNERSHIP
The Partnership was formed over five years ago and owns non-operating
Property Interests in producing oil and gas properties in six states in which
its companion partnership, Swift Energy Operating Partners 1993-B, Ltd.
("Companion Partnership"), formed at approximately the same time and also
managed by the Managing General Partner, owns the working interests. The
Partnership had expended all of its original capital contributions by the end
of October 1993. A majority of the Partnership's oil and gas properties are
natural gas properties, representing approximately 60% of the Partnership's
1997 production and approximately 59% of its total proved reserves at December
31, 1997. From time to time, the Companion Partnership has performed workovers
and recompletions of wells in which the Partnership has non- operating
interests, using funds advanced by the Managing General Partner to perform
these operations, which amounts have been subsequently repaid. The Partnership
owns interest in 245 wells in 25 fields.
The following table presents information on those fields in which the
Partnership has Property Interests which constitute 10% or more of the
Partnership's PV-10 Value at December 31, 1997. The Partnership's "PV-10
Value" is the estimated future net cash flows (using unescalated prices) from
production of proved reserves attributed to the Partnership's Property
Interests, discounted to present value at 10% per annum. Attachment D to this
Supplement is the report dated February 10, 1998 of the audit by H.J. Gruy and
Associates, Inc., Independent Petroleum Consultants, of the oil and gas
reserves underlying the Partnership's Property Interests, and future net cash
flow expected from the production of those reserves as of December 31, 1997,
presented both for the Partnership as a whole and as to those reserves solely
attributable to the Investors in the Partnership. This report has not been
updated to include the effect of production since year-end 1997. In estimating
these reserves, the Managing General Partner, in accordance with criteria
prescribed by the Securities and Exchange Commission, has used year-end 1997
prices, without escalation, except in those instances where fixed and
determinable gas price escalations are covered by contracts, limited to the
price the Partnership reasonably expects to receive. The Managing General
Partner is not aware of any favorable or adverse event causing a significant
change in the estimated amount (as set forth in Attachment D hereto, which is
the report of H.J. Gruy and Associates, Inc.) of proved reserves of the
properties in which the Partnership owns an interest has occurred between
December 31, 1997 and the date of this Supplement.
The information below includes the location of each field in which the
Partnership has an interest, the number of wells and operators, together with
information on the percentage of the Partnership's total PV-10 Value on
December 31, 1997 attributable to each of these fields. Information is also
provided regarding the percentage of the Partnership's 1997 production (on a
volumetric basis) from each of these fields. Of the remaining other fields in
which the Partnership owns a Property Interest, 13 of such fields each comprise
less than 1% of the Partnership's PV-10 Value at December 31, 1997, and the
PV-10 Value of each of the other ten fields averages less than 3% of the
Partnership's PV- 10 Value at the same date.
3
<PAGE> 320
<TABLE>
<CAPTION>
Second Green 23
Bayou Branch Other
Field Field Fields
--------------------------------------------
<S> <C> <C> <C>
Cameron McMullen AL(1)
County and State Parish, County, LA(2)
LA OK MS(5)
NM(1)
OK(2)
TX(12)
Number of Wells 28 43 174
Fina Swift; Swift and
Operator(s) Vintage 19 others
Petroleum
% of 12/31/97 PV-10 Value 43% 26% 31%
% of 1997 Production Volumes 23% 45% 32%
</TABLE>
The Partnership's total assets at year-end 1997 were $2,472,675 and
the PV-10 Value of its total proved reserves at the same date was $2,048,682.
Based upon the audit of the Partnership's Total Proved Reserves at year-end
1997, those reserves were comprised of the following three categories:
<TABLE>
<S> <C>
Proved Producing(1) 41%
Behind-Pipe(2) 25%
Non-Developed(3) 34%
----
100%
====
</TABLE>
- --------------
(1)Proved producing reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
(2)Behind-pipe reserves are proved reserves that will not contribute to
cash flows until recompletion projects have been implemented to place them into
production. The impact of these recompletion projects will also be limited
until the costs of implementation have been recovered. In general, it is not
appropriate to bring behind-pipe reserves into production until the formation
that is currently producing has been depleted. Premature recompletions can
lead to permanent reductions in a well's proved reserves.
(3)Non-developed reserves are reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion. Therefore, significant
additional expenditures are usually required before undeveloped reserves can be
produced.
Attachment D is the annual reserves audit and independent reserves
report prepared by H.J. Gruy and Associates, Inc. as to the Partnership's
remaining proved oil and gas reserves available for production over a period in
excess of 15 years. These quantities have been given a value based upon prices
for oil and gas at December 31, 1997. The value is determined based upon the
assumption that these prices will remain in effect over the life of these
reserves. This value is then discounted at 10% per year to arrive at
4
<PAGE> 321
the value (in today's dollars) of these revenues ("PV-10 Value"). This PV-10
Value for the Partnership's Property Interests is $2,048,682. It is also
estimated that $235,443 in future capital costs must be spent to develop the
Partnership's non-producing reserves.
RISK FACTORS
o Although the fair market value of the Property Interests proposed to
be purchased from the Partnership by the Managing General Partner was
based upon a determination by three independent Appraisers, no opinion
was acquired as to the fairness of the ultimate purchase price, which
was determined in the Managing General Partner's sole judgment by
adding a 7.5% premium over the higher of the two fair market value
estimates for the Partnership's Property Interests determined by the
Appraisers. Therefore, the purchase price was not determined on an
impartial basis by a party not involved in the transaction, and
another party intent upon purchasing the Property Interests in the
Partnership might have offered a different purchase price. There is
no guarantee that the purchase price represents the highest possible
price that could be received for the Partnership's Property Interests
in all circumstances. It is possible that a higher (or lower) price
might be received if these assets were sold on another basis, such as
at auction or in negotiated sales. Furthermore, the assessment of the
value of the Partnership's proved non-producing reserves could vary
widely, given the typical discounting in valuing non-producing
reserves.
o The Managing General Partner did not retain an independent
representative to act on behalf of the Investors in the Partnership in
structuring and negotiating the terms or price of the Proposal or the
purchase price. The price at which it is proposed that the Company
purchase the Property Interests from the Partnership has not been
negotiated at arm's length and is subject to significant conflicts of
interest between the Company acting as the purchaser of such
properties while serving as the Managing General Partner of the
Partnership. If an independent representative had been retained for
the Partnership, the terms or price might have been different and
possibly more favorable to Investors.
o The fair market value (excluding the 7.5% premium) established for the
Partnership's Property Interests is based upon the Appraisers'
evaluation of that value. Year-end 1997 prices, along with other
current market factors, were used as a starting point for the
Appraisers' analysis, and prices and costs were then escalated at a
rate of 3.5% per year over 15 years. Substantial increases in the
prices for oil and gas in the future might result in Investors
receiving higher distributions from continued operations of the
Partnership, although such distributions could be negatively affected
by oil and gas decreases.
o In order to effectuate the sale of its Property Interests, the
Proposal must not only be approved by the Partnership, but a similar
Proposal must be approved by the Companion Partnership. This
requirement exists because of the significant lowering of the value of
either (i) a working interest burdened by a large non- operating
interest controlled by a different party, or (ii) a non-operating
interest in properties the operations of which are controlled by a
third party. Therefore, even if the Investors in the Partnership
approve the Proposal to sell their Property Interests, this may not be
done without the approval of a similar Proposal by investors in the
Companion Partnership. If either Partnership does not approve its
Proposal, then the Managing General Partner will reassess the value
of the Property Interests of each Partnership and attempt to formulate
a new proposal for the investors in each such Partnership.
5
<PAGE> 322
o A majority of the Partnership's proved oil and gas reserves are
non-producing. Because non-producing reserves are traditionally
discounted due to future costs which must be incurred to recover those
reserves and the risk that any drilling will be unsuccessful, there is
a risk that the discount applied to the non-producing reserves by the
Petroleum Engineering Consultants could be greater than the discount
applied by a third party purchaser. Likewise, it is likely that any
drilling conducted on Property Interests acquired from the Partnership
has upside potential, the benefit of which will go to the Managing
General Partner if it acquires those properties.
o Investors that are subject to federal income tax on an investment in
the Partnership are required to recognize gain or loss on the sale of
oil and gas assets by the Partnership and the subsequent liquidation
of the Partnership. The character of the gain or loss depends on
certain factors specific to individual Investors. It is anticipated
that Investors that acquired their interests in the original offering
and that are subject to federal income tax will recognize a loss for
federal income tax purposes. Any tax that may be due must be paid
even if such Investors choose to acquire Company Common Stock with
some or all of their proceeds from property sales. Investors also
should consult their individual tax advisors to determine whether they
are subject to any state tax. For a broader discussion of the tax
consequences, Investors should read "Federal Income Tax Consequences
of Adoption of the Proposals" in the Joint Proxy Statement/Prospectus,
and "Summary of Federal Income Tax Consequences" in this Supplement.
o Investors that are Tax Exempt Plans that have directly or indirectly
acquired their Partnership interests through debt financing, as
defined in the Internal Revenue Code of 1986, as amended, may be
subject to taxation on the Partnership's sale of property and the
liquidation of the Partnership, while other Tax Exempt Plans are not
expected to be subject to taxation on the sale and liquidation. See
"Summary of Federal Income Tax Consequences--Tax Treatment of Tax
Exempt Plans--Debt-Financed Property" in this Supplement. It is
anticipated that Tax Exempt Plans that acquired their interests in the
original offering and that are subject to federal income tax will
recognize a loss for federal income tax purposes.
o As currently proposed, Investors that subscribe for Company Common
Stock pursuant to this Offering may not receive some or all of the
cash which otherwise would be distributed to them as part of the
liquidating distribution of their Partnership. The amount of any cash
liquidating distribution they actually receive depends upon the
purchase price to be paid for any Company Common Stock they elect to
and are entitled to receive pursuant to the terms of this Offering.
For federal income tax purposes, Investors subscribing for shares of
Company Common Stock will be treated as though they had purchased
those shares for cash, even though they never had actual possession of
the cash used to acquire the shares. Additionally, the fact that such
Investors elect to acquire Company Common Stock rather than receive
cash in liquidation of their Partnership interests will not affect the
federal income tax consequences attending the liquidation of their
Partnership interests. Because the purchase of shares of Company
Common Stock will reduce the cash received by Investors upon the
Partnership's liquidation, to the extent that Investors owe federal
income tax as a result of the liquidation, they may not receive
sufficient cash to pay some or all of any tax they may owe on the
liquidation. Such Investors owing tax as a result of the liquidation
will have to pay such tax from sources other than any cash liquidating
distribution from the Partnership.
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See "Risk Factors" in the Joint Proxy Statement/Prospectus.
CONFLICTS OF INTEREST
There are substantial conflicts of interest which exist by virtue of
the Managing General Partner acting in that capacity on behalf of the
Partnership while at the same time acting as the proposed purchaser of all of
the oil and gas assets of the Partnership. These conflicts of interest are
discussed below.
o The terms of the Proposal are established by the Company which is also
the Managing General Partner of the Partnership.
o Neither the Managing General Partner nor a majority of its independent
directors retained an independent representative to act on behalf of
the Partnership's Investors for the purposes of negotiating the terms
upon which any such sale to the Managing General Partner would be made
or for the preparation of a report concerning the fairness of the
entire transaction.
See "Summary--Conflicts of Interest" and "Conflicts of Interests" in the Joint
Proxy Statement/Prospectus.
SPECIAL FACTORS
BACKGROUND AND PURPOSE OF THE PROPOSAL
A number of factors have led to the decision of the Company in its
capacity as Managing General Partner to solicit approval of the Proposal by
Investors in the Partnership. The general improvement in the prices for
natural gas over the last several years, relative to such prices in the
mid-1990's, make this an appropriate time to consider the Proposal to sell the
Partnership's Property Interests. The structure being proposed, which involves
the sale of the Partnership's oil and gas assets to the Managing General
Partner, is being submitted for approval by Investors in an attempt to realize
the highest value for those assets. For the reasons set out below, the
Managing General Partner believes that the Proposal is fair to Investors in the
Partnership, given that the purchase price for these assets has been determined
by taking the higher of two fair market value estimates by three independent
Appraisers and adding to it a 7.5% premium.
Approval of the Proposal will have the following effects:
1. The Managing General Partner will purchase all of the oil and gas
assets of the Partnership, provided its Companion Partnership has
approved its proposal.
2. When the Partnership sells all of its oil and gas assets, it will be
required to liquidate and distribute its remaining assets (principally
the cash proceeds from the sale) to its partners (including the
general partners) in accordance with their respective ownership
interests in the Partnership.
3. Investors will be given the option of electing to receive shares of
Swift Common Stock, in amounts that they choose on an individual
basis, in lieu of some or all of the cash they would be entitled to
receive upon the Partnership's liquidation.
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4. The Managing General Partner may spend capital to develop
non-producing reserves on properties which it acquires from the
Partnership, although the properties in which such investment will be
made have not yet been determined.
5. Investors in the Partnership may be taxed on the sale of the
Partnership's oil and gas assets, although such sale is expected to
result in a taxable loss to Investors that acquired their interests in
the original offering.
PROPOSED PURCHASE PRICE
As discussed in greater detail below, the Petroleum Engineering
Consultants estimated that the aggregate fair market value of the Partnership's
Property Interests as of December 31, 1997 is $1,234,678. CIBC Oppenheimer
estimated a fair market value of the same Property Interests at the same date
of $1,327,783. The Special Transactions Committee chose the higher of these
two determinations as the" Fair Market Value" for the purchase of these
interests and the Board of Directors of the Company determined to pay a 7.5%
premium ($99,584) above the Fair Market Value to purchase the Partnership's
Property Interests, resulting in a purchase price of $1,427,367. This compares
to the total purchase price for all of the oil and gas assets of all 63
Partnerships which are considering similar proposals of approximately $81
million. The valuation estimates of the Appraisers are attached to this
Supplement and incorporated herein by reference as follows: Attachment A is
the fair market value estimate of H.J. Gruy and Associates, Inc., Attachment B
is the fair market value estimate of J.R. Butler and Company, and Attachment C
is the fair market value estimate of CIBC Oppenheimer Corp. The PV-10 Value
prepared on an annual basis by H.J. Gruy of the same Property Interests as of
the same date is $2,048,682.
REASONS FOR THE PROPOSAL
The Managing General Partner believes that it is in the best interest
of the Investors for the Partnership to sell its Property Interests at this
time and to dissolve the Partnership and make a final liquidating distribution
to its partners for the reasons discussed below.
Current Liquidating Distribution Lowers Volatility Risk. The
Partnership has been in existence for over five years. The Managing General
Partner believes that the ability to receive the estimated liquidating
distribution in one lump sum at this time, rather than in smaller amounts over
a longer period, is one of the benefits of the Proposal, without the risk of
such distributions being negatively affected by oil and gas price decreases and
the inherent risks associated with geological, engineering and operational
matters. It is also the Managing General Partner's belief that improvements
over the last several years in the level of gas prices, relative to such prices
in the mid-1990s, makes this an appropriate time to consider the sale of the
Partnership's Property Interests and increases the likelihood of maximizing the
value of the Partnership's assets, although the future prices and market
volatility cannot be predicted with any accuracy.
Decreasing Cash Flow While Expenses Continue. The Partnership's
underlying interests in oil and gas reserves are expected to continue to
decline as remaining reserves are produced. Declines in well production are
based principally upon the maturity of the wells, not on market factors. These
declines will continue to occur while oil field overhead and operating costs
($47,299 in 1997) and direct and general and administrative expenses ($116,395
in 1997) continue, which are relatively fixed amounts. Each producing well
requires a certain amount of overhead costs, as operating and other costs are
incurred regardless of the level of production. Likewise, direct costs and/or
general and administrative expenses, such as
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compliance with the securities laws, producing reports to partners and filing
partnership tax returns, do not decline as revenues decline. By accelerating
the liquidation of the Partnership, those future administrative costs will be
avoided by the Partnership.
Undeveloped and Behind Pipe Reserves. The Managing General Partner
believes that the key factor affecting the Partnership's long-term performance
has been the decrease in oil and gas prices that occurred subsequent to the
purchase of the Partnership's Property Interests, especially the precipitous
decline of gas prices in 1995. Gas prices are expected to continue to vary
widely over the remaining life of the Partnership, and such changes in gas
prices will affect future estimates of revenues from continued operations of
the Partnership. Reduced cash flow affected the ability of the Companion
Partnership to develop the significant undeveloped proved reserves in which the
Partnership has an interest. Although at December 31, 1997, it was estimated
that approximately 44% of the ultimate recoverable reserves in which the
Partnership has a non-operating interest were still available for future
production, less than half (41%) of these available reserves were proved
producing reserves. Of the non-producing reserves (59%), approximately 34%
consisted of undeveloped reserves, which require substantial expenditures to
drill new wells to recover such reserves. Recovery in amounts great enough to
significantly impact the results of the Partnership's operations and the
ultimate cash distributions to partners can only occur with the investment of
new capital. As provided in the Partnership Agreement, the Partnership
expended all of the Investors' net commitments for the acquisition of Property
Interests many years ago, and it no longer has capital to invest. No
additional development activities are contemplated by the Companion Partnership
on the properties in which the Partnership has a non-operating interest. The
remaining non-producing reserves (25%) are estimated to be behind-pipe
reserves, which are unlikely to be producible for many years because
behind-pipe reserves always require completion in a different producing zone,
which does not take place until production is depleted from the currently
producing zone.
Interest Holders' Tax Reporting. Each Investor will continue to have
an income tax reporting obligation with respect to his SDIs as long as the
Partnership continues to exist. There is no trading market for the SDIs, so
Investors generally are unable to dispose of their SDIs. See "Partnership
Business and Financial Condition--No Trading Market" in this Supplement.
Following the sale of the Partnership's Property Interests and dissolution of
the Partnership, Investors will realize gain or loss under federal income tax
laws. See "Summary of Federal Income Tax Consequences--Taxable Gain or Loss
upon Sale of Properties" herein. Thereafter, Investors will have no further
tax reporting obligations with respect to the Partnership. See "Summary of
Federal Income Tax Consequences--Liquidation of the Partnership" in this
Supplement.
See "Summary--Background of the Proposals," "--Purpose and Effect of the
Proposals," "--Reasons for the Proposals" and "--Managing General Partner's
Recommendations" in the Joint Proxy Statement/Prospectus.
COLLECTIVE ANALYSIS OF PURCHASE PRICE; PREMIUM OVER FAIR MARKET VALUE
The Special Transactions Committee selected H.J. Gruy and Associates,
Inc. ("H.J. Gruy" or "Gruy"), J.R. Butler and Company ("J.R. Butler" or
"Butler"), which are both petroleum engineering consultants, and CIBC
Oppenheimer Corp. ("CIBC Oppenheimer"), an investment banking firm, to
estimate the fair market value of the Property Interests of each of the
Partnerships. Collectively, H.J. Gruy, J.R. Butler and CIBC Oppenheimer are
referred to herein as the "Appraisers," and H.J. Gruy and J.R. Butler together
are sometimes referred to herein as the "Petroleum Engineering Consultants."
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The following subsections of the "Special Factors" section of the
Joint Proxy Statement/Prospectus should be reviewed for information concerning
the selection and qualification of the Appraisers and the parameters of the
valuation estimates: "Independent Appraisal of the Fair Market Value of
Property Interests of the Partnerships," "Qualification of Appraisers," and
"Fair Market Value."
The Petroleum Engineering Consultants arrived at a fair market
valuation estimate based upon appraisal of the projected discounted cash flow
from its various Property Interests. On the other hand, the investment banking
firm of CIBC Oppenheimer made a valuation estimate of the Partnership's
Property Interests based upon the application of multiple quantitative and
qualitative factors. The quantitative factors include, among other things, a
review of relevant valuation criteria from comparable acquisitions of both oil
and gas properties and companies that are predominantly active in the oil and
gas industry, and a review of valuation criteria for relevant publicly traded
oil and gas companies.
The process used by the Petroleum Engineering Consultants in preparing
their valuation estimate is discussed at length in the Joint Proxy
Statement/Prospectus under "Special Factors--Valuation by Petroleum Engineering
Consultants." As described therein, the Petroleum Engineering Consultants
individually audited the estimate of present value of future net cash flows
from the 44 property groups in which Property Interests are owned by the
Partnerships to whom similar proposals are being made to sell all of their oil
and gas assets and liquidate their Partnerships. The Partnership owns Property
Interests in five of these property groups. The Petroleum Engineering
Consultants began their analysis based upon the year-end 1997 PV-10 Value of
each property audited by H.J. Gruy and together they re-evaluated reserve
quantities, projected operating costs and cash flows. The present value of
this reserves analysis was then derived by escalating year-end 1997 prices
($2.38 per MMBtu and $16.00 per barrel before adjustments for Btu content for
gas and gravity variances for oil as well as transportation charges and
geographic location) and costs by 3.5% per year for 15 years. This present
value was then adjusted for various individual field risks and risk adjustments
of proved non- producing reserves and proved undeveloped reserves. The result
of this collective analysis by the Petroleum Consulting Engineers was their
estimation that the fair market value of Property Interests owned by the
Partnership was $1,234,678 as of December 31, 1997.
The methodology used by CIBC Oppenheimer to prepare its valuation
estimate is discussed at length under "Special Factors--Valuation by CIBC
Oppenheimer" in the Joint Proxy Statement/Prospectus. CIBC Oppenheimer's
evaluation of the Partnership's Property Interests began with the PV-10 Value
of each property group, as calculated by Swift and audited by H.J. Gruy which
Gruy report dated February 10, 1998 is Attachment D to this Supplement. CIBC
Oppenheimer then divided the property groups into two categories. Those
property groups with reserves consisting primarily of proved developed
producing reserves were placed in the "Conventional Case" category. Those
property groups with significant proved developed non-producing or undeveloped
reserves were placed in the "Non-Conventional Case" category. [NEXT IS
VARIABLE SENTENCE:] The Partnership has interests in property groups which were
in both the "Conventional Case" and the "Non-Conventional Case" categories.
CIBC Oppenheimer then valued each property group by applying the multiples
discussed under "Special Factors--Valuation by CIBC Oppenheimer--Valuation
Multiples" in the Joint Proxy Statement/Prospectus to each property group's
PV-10 Value, proved reserves on a BOE basis, and projected 1998 EBIDTA. A
separate set of multiples was used for property groups in the Conventional Case
category and the Non-Conventional Case category, respectively. This provided
CIBC Oppenheimer with three estimated values for each property group. The
average of these three values yielded CIBC Oppenheimer's estimation of the fair
market value of each property group. CIBC Oppenheimer then allocated the
appropriate portion of each property group's
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estimated fair market value to the Partnership based upon the Partnership's
Property Interests in each property group. The result of this analysis by CIBC
Oppenheimer was an estimation that the fair market value of the Partnership's
Property Interests was $1,327,783 on December 31, 1997.
The Special Transactions Committee has determined that, in keeping
with the definition of Fair Market Value, the higher of these two estimations
of fair market value, or $1,327,783, represents the Fair Market Value of the
Partnership's Property Interests. Accordingly, the fair market value
estimation of the Petroleum Consulting Engineers and the fair market value
determined by CIBC Oppenheimer were compared to each other and the higher of
the two was chosen as the Fair Market Value of the Property Interests owned by
the Partnership. The variation between the fair market value estimate of the
Partnership's Property Interests prepared by the Petroleum Consulting
Engineers, on one hand, and CIBC Oppenheimer on the other was 7%.
DETERMINATION OF PREMIUM OVER FAIR MARKET VALUE BY THE COMPANY
The Special Transactions Committee presented its recommendation to the
Board of Directors of the Company as to the Fair Market Value of the Property
Interests of the Partnership. The Board of Directors of the Company then
determined that paying a 7.5% premium over the Fair Market Value of the
Partnership's Property Interests was appropriate and fair based upon the
factors and for the reasons discussed below. Because the Company has served as
Managing General Partner of the Partnership for over five years, it is
intimately familiar with the Property Interests owned by the Partnership. The
Managing General Partner believes that if the Property Interests were to be
sold to a third party purchaser that was not equally familiar with those
interests, it is likely that the purchaser would discount the purchase price to
account for that lack of familiarity and associated risks. If these interests
are purchased by the Company, then the additional cost and personnel often
inherent in making a property acquisition are not required, because the files
and deed records already exist in the Company's lease and computer systems, and
conveyance and title issues do not exist.
In the judgment of the Company, the purchase of the Partnership's
Property Interests together with interests in many of the same properties owned
by other Partnerships at approximately the same time will result in
efficiencies to the Company in aggregating such interests. Swift's long-term
knowledge of the risks involved in these properties means that it is in a
better position to evaluate these risks than third parties.
Based upon the Company's experience in purchasing properties, the lack
of additional costs often incurred in purchasing oil and gas properties in
which the purchaser has owned no interest, and the Company's intimate
familiarity with these Property Interests and consequent ability to evaluate
acquisition risks, it was deemed appropriate to pay a premium representing the
benefit to the Company arising from these factors.
The amount of the premium principally was based upon management's
experience in purchasing properties which contain both producing reserves and
drilling potential, without any statistical or analytical study prepared by the
Company in the course of determining the amount of this premium. Since 1979,
the Company, on behalf of itself and others, has gained a wide range of
experience with the valuation of oil and gas properties and the prices for
their purchase and sale, having purchased $478 million of such properties in
129 separate transactions. Other purchasers might have determined it
inappropriate to pay a premium, or if so, to pay a premium based upon other
factors or in a different amount. Because there
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has been no independent third party involved in the decision to pay this
premium or in the determination of its amount, and no fairness opinion has been
requested regarding this premium, conflicts of interest exist in its
determination, although the Managing General Partner believes, based upon its
knowledge of the oil and gas industry, its knowledge of the properties
involved, its experience in purchasing and selling oil and gas properties, and
the benefits from purchasing the Property Interests which are particular to the
Company, that the amount being offered to the Partnership to purchase its
Property Interests is fair.
"SPECIAL FACTORS" SECTION IN THE JOINT PROXY STATEMENT/PROSPECTUS
The Special Factors section in the Joint Proxy Statement/Prospectus
contains a full discussion of the determination of the purchase price proposed
to be paid by the Managing General Partner to purchase the Partnership's
Property Interests. In addition to those topics discussed at length in this
Supplement, the Joint Proxy Statement/Prospectus addresses alternative
transactions that were considered but not proposed for the Partnership and the
other 62 partnerships to whom similar proposals are being made simultaneously.
It also contains information regarding the prior relationships between the
Appraisers, the Partnerships and the Managing General Partner, the absence of a
request that an independent representative negotiate the terms of the purchase
of the Partnership's Property Interests by the Managing General Partner, the
manner in which expenses are to be borne for the transaction, the Managing
General Partner's source of funds to purchase the Partnership's Property
Interests, and the benefits that the Managing General Partner would receive
from purchasing such Property Interests.
ESTIMATES OF LIQUIDATING NET CASH DISTRIBUTION AMOUNT IF THE PROPOSAL IS
APPROVED
The purchase price proposed to be paid to the Partnership for its oil
and gas assets is the Fair Market Value plus the purchase premium. As is the
case with all oil and gas properties purchases, the purchase is proposed to be
made as of the date which the properties were evaluated (in this case December
31, 1997). A portion of the reserves used to establish the Fair Market Value
has been produced during 1998. Most of the net revenue received by the
Partnership from the sale of such production since the proposed purchase date
(December 31, 1997) has been distributed to the partners during 1998 through
quarterly cash distributions or, to the extent not already distributed, will be
distributed as part of the Partnership's liquidating distribution.
Accordingly, the actual purchase price which will be paid to the Partnership
will be reduced by the amount of net production revenue received by the
Partnership after December 31, 1997.
Set forth in the table below are estimated net proceeds that the
Partnership may realize from the sale of the Partnership's Property Interests,
estimated expenses of the related dissolution and liquidation of the
Partnership and estimated interim net cash distributions from January 1, 1998
until September 30, 1998, resulting in an estimate of the amount of net cash
distributions available for Investors as a result of such sale.
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ESTIMATE OF NET CASH DISTRIBUTIONS
FROM PROPERTY INTEREST SALES AND LIQUIDATION
<TABLE>
<S> <C>
Fair Market Value of Partnership Property Interests(1)
(Gross Sales Proceeds) $ 1,327,783
Purchase Premium (7.5% of Fair Market Value)(2) $ 99,584
Estimated Selling and Dissolution Expenses(3) $ (39,833)
(3% of the Fair Market Value)
Net Assets(4) $ 407,365
Estimated Interim Cash Distributions(5) $ (309,950)
-----------------
Estimated Net Distributions to Partners(6) $ 1,484,949
=================
Amount Distributable
to Investors(6) $ 1,244,964
Amount Distributable
to General Partners(6)(7) $ 239,985
-----------------
$ 1,484,949
=================
ESTIMATED NET CASH DISTRIBUTIONS TO INVESTORS PER $1.00 SDI $ 0.20
=================
MINIMUM NUMBER OF SDIS NECESSARY TO PURCHASE 100 SHARES OF SWIFT
ENERGY COMMON STOCK WITH CASH DISTRIBUTIONS(8) 9,000
=================
</TABLE>
- ----------------------------------------------
(1) Represents the higher of two fair market value estimates by the
Appraisers.
(2) As determined by the Board of Directors of Swift.
(3) Includes estimated costs associated with dissolution and liquidation
of the Partnership.
(4) Includes cash and net receivables of the Partnership as of December
31, 1997.
(5) Estimated cash distributions paid to the partners from January 1, 1998
to September 30, 1998.
(6) Estimated net cash distributions are allocated to the Investors and
the General Partners pursuant to the Partnership's limited partnership
agreement.
(7) Includes amount distributable to Special General Partner and Managing
General Partner.
(8) Under the terms of the offer of Swift Common Stock to Eligible
Purchasers, if the Investors in the Partnership approve the Proposal
and its Companion Partnership approves a similar Proposal, such
Investors will be Eligible Purchasers. The minimum number of shares
which can be purchased by an Eligible Purchaser is a round lot of 100
shares. Based upon estimated net cash distribution of $0.20 per $1.00
SDI, the number of SDIs shown above is the minimum number of SDIs
which it will be necessary for an Investor
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to own in order to purchase a minimum 100 share round lot of Swift
Common Stock without providing any additional funds from other
sources. This calculation is based upon an assumed purchase price of
Swift Common Stock of $18.00 per share (which is the same price upon
which the proforma financial statements contained in the Joint Proxy
Statement/Prospectus are based) for an aggregate purchase price for
100 shares of Swift Common Stock of $1,800. The minimum number of
Units shown is subject to change, based upon the price for Swift
Common Stock at a future date as specified under "Offering of Shares
of Swift Energy Company Common Stock if Investors Approve the
Proposal--Offer of Swift Common Stock--Purchase Price" in this
Supplement. However, if an Eligible Purchaser has interests in more
than one Partnership, the cash distributions he will be entitled to
receive may be aggregated to meet the minimum share purchase
requirement of a round lot of 100 shares.
ESTIMATES OF NET CASH DISTRIBUTIONS AVAILABLE FROM CONTINUED OPERATIONS
If the Partnership were to retain its Property Interests until they
have reached their economic limit, the table below estimates the return to
Investors, without regard to amounts distributable to the General Partners,
discounted to present value, based upon 1997 year-end pricing without
escalation and upon the discount assumptions used above. The estimates of the
present value of future net cash distributions have been further reduced by
estimates of continuing audit, tax return preparation and reserve engineering
fees associated with continued operations of the Partnership, along with direct
and general and administrative expenses estimated to occur during this time.
The following estimated future net revenues do not take into account any
additional costs which might be incurred by the Partnership's Companion
Partnership due to needed future maintenance or remedial work on the properties
in which the Partnership has an interest, which would reduce such net revenues.
ESTIMATED SHARE OF INVESTORS'
NET CASH DISTRIBUTIONS FROM CONTINUED OPERATIONS
<TABLE>
<S> <C> <C>
Estimated Future Net Revenues from Continued Operations until $ 2,689,779
Depletion(1)
Estimated Interim Net Cash Distributions(2) $ (280,700)
Estimated Partnership Direct and Administrative Expenses(3) $ (338,912)
Net Assets(4) $ 346,260
---------------------
Net Cash Distributions to Investors(5) $ 2,416,427
=====================
NET CASH DISTRIBUTIONS PER $1.00 SDI $ 0.39
PRESENT VALUE OF NET CASH DISTRIBUTIONS PER $1.00 SDI(5)(6) $ 0.25
</TABLE>
- -----------------------------------------
(1) Investors' future net revenues are based on the reserve estimates at
December 31, 1997 using year-end 1997 prices without escalation. To a
limited extent, future net revenues may be influenced by a material
change in the selling prices of oil or gas. For further discussion of
this, see "Special Factors--Reasons for the Proposal" in this
Supplement. The actual prices that will be received and the
associated costs are likely to vary and may be more or less than those
projected. See "Partnership Business and Financial Condition" in this
Supplement.
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(2) Estimated net cash distributions paid to Investors from January 1,
1998 to September 30, 1998 in order to present this information on a
comparative basis (in relation to the preceding table) as of September
30, 1998.
(3) Includes Investors' share of general and administrative expenses, and
audit, tax, and reserve engineering fees.
(4) Includes Investors' share of cash and net receivables of the
Partnership as of December 31, 1997.
(5) Based upon the Partnership's reserves until they have reached their
economic limit.
(6) Discounted at 10% per annum.
The proceeds of all sales, to the extent available for net cash
distribution, are to be distributed to the partners in accordance with the
Partnership's limited partnership agreement. The amounts finally distributed
will depend on the actual sales prices received for the Partnership assets,
results of operations until liquidation of the Partnership, final costs and
other contingencies and circumstances.
FAIRNESS OF PROPOSED SALE OF ASSETS TO THE MANAGING GENERAL PARTNER
AS COMPARED TO CONTINUING OPERATIONS
Based on the above tables, it is estimated that an Investor could
expect to receive $0.20 per $1.00 SDI upon the sale of the Partnership's
Property Interests as of September 30, 1998. In comparison, it is estimated
that an Investor could expect to receive $0.25 per $1.00 SDI, discounted to
present value at 10% per annum ($0.39 per $1.00 SDI on an undiscounted basis)
if the Partnership continued operations. The Managing General Partner believes
that the Proposal to sell the Partnership's Property Interest as compared to
continuing operations is fair to Investors for the reasons discussed below.
Although the estimates contained in the two tables above show that
estimated net cash distributions to Investors (based on net present value) from
continued operations would be approximately 25% higher than estimated net cash
distributions from selling the Partnership's Property Interests and liquidating
the Partnership currently, the Managing General Partner believes there is a
substantial advantage in receiving the liquidating net cash distribution in one
lump sum at this time. The estimates of net cash distributions from continued
operations are based upon 1997 year- end pricing. It is highly likely that
over such a long period of time, oil and gas prices will vary often and
possibly widely, as has been demonstrated historically, from the prices used to
prepare these estimates. Continued operations over such a long period of time
subject Investors to the risk of receiving lower levels of net cash
distributions if oil and gas prices over this period are lower on average than
those used in preparing the estimates of net cash distributions from continued
operations. Continued operations also subject Investors' potential net cash
distributions to the risks of possible changes in costs or need for workover or
similar significant remedial work on the properties in which the Partnership
owns Property Interests. The Managing General Partner also believes that there
is an advantage to Investors taking any funds to be received upon liquidation
and redeploying those assets in other investments, rather than continuing to
receive decreasing levels of net cash distributions over such a long period of
time.
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Because there is no active trading market for SDIs in the Partnership,
the only other comparable value for SDIs is the 1997 "SDI Value," which, as
explained below, is the amount calculated on an annual basis under the terms of
the limited partnership agreement at which the Managing General Partner can
offer to repurchase SDIs from Investors. As of January 1, 1997, this "SDI
Value" was $0.37 per $1.00 SDI. In 1997, the Investors received net cash
distributions of $0.08 per $1.00 SDI, and are estimated to receive another
$0.05 per $1.00 SDI before September 30, 1998, which converts to a comparable
value of $0.24 per $1.00 SDI before any adjustments to quantities of reserves
or oil and gas prices during this almost two year period. Under the terms set
out in the partnership agreement, each year the Managing General Partner is
required to furnish to Investors the SDI Value, and Investors have the right to
present their SDIs for purchase by the Managing General Partner for the SDI
Value. The SDI Value amount is determined on an entirely different basis than
the estimates of fair market value by the Appraisers. Furthermore, the SDI
Value was calculated over one year ago, with a valuation date of January 1,
1997, as opposed to the date for assessment of Fair Market Value being December
31, 1997. Because of significant changes in oil and gas prices within a year's
time, in addition to the changes in reserve quantities during that period, the
calculation of SDI Value as of January 1, 1997, and the Fair Market Value as of
December 31, 1997, are not comparable. SDI Value is derived by taking 70% of
the present value of proved oil and gas reserves (discounted at 10% per annum)
calculated on an escalated pricing basis, plus cash and accounts receivable
less outstanding debts and obligations of the Partnership.
Although the PV-10 Value of the Partnership's Property Interests is
higher than the purchase price proposed if the Proposal is approved, the
Managing General Partner does not believe that the PV-10 Value accurately
reflects the amount that oil and gas industry members are currently paying to
purchase producing properties on the open market.
FAIRNESS OF PROPOSED SALE
The Managing General Partner believes that the entire transaction
related to the Proposals involving the proposed method of sales of the
Partnerships' Property Interests is fair to Investors for the following
reasons, without giving any particular weight to any reason:
1. The Managing General Partner believes that the most important
element of the Proposal is the determination of the Fair
Market Value of the Partnership's Property Interests. The
price to be paid by the Company to purchase the Partnership's
Property Interests was determined in the Managing General
Partner's sole judgment by adding a 7.5% premium to the higher
of the two estimates by the Appraisers of the fair market
value of the Partnership's Property Interests. Two of the
three Appraisers are qualified independent petroleum
engineering firms and the other is an investment banking firm.
The factors and methods used by the Appraisers in determining
Fair Market Value are discussed in detail under "Special
Factors--Independent Appraisal of the Fair Market Value of
Property Interests of the Partnerships", "--Fair Market
Value," "--Valuation by Petroleum Engineering Consultants,"
"--Valuation by CIBC Oppenheimer" and "--Collective Analysis
of Purchase Price" in the Joint Proxy Statement/Prospectus.
2. No transaction will take place unless the Proposal is approved
by Investors holding at least a majority of the interests in
such Partnership (without any vote by the Managing General
Partner) and a similar Proposal is approved by the
Partnership's Companion Partnership.
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3. The Special Transactions Committee made the determination as
to the retention of the Appraisers and approved the fair
market value estimates provided by the Appraisers and
recommended the reports of the Appraisers to the Board of
Directors of the Company. The Special Transactions Committee
is comprised solely of independent directors of the Company.
4. If the Proposals are approved by investors in any of the 63
Partnerships considering similar proposals, it is likely that
the Managing General Partner will expend the capital necessary
to develop non- producing reserves on the Property Interests
purchased by the Managing General Partner from those
Partnerships. If all of the Property Interests which are the
subject of the Proposals are acquired by the Company, such
Property Interests in the aggregate will constitute less than
20% of the Company's total assets. Because the Managing
General Partner would be the beneficiary of any such increase
in value, the Managing General Partner is hereby offering to
Eligible Purchasers the opportunity to purchase up to
2,500,000 shares of Common Stock of the Company. There is no
requirement that any purchase of Swift's Common Stock be made.
See "Offer of Swift Common Stock" below.
5. In structuring the Proposal and related transactions, the
Managing General Partner considered that any sale of
Partnership Property Interests, whether to the Managing
General Partner or to a third party, would be a taxable
transaction. Thus, if an Investor subject to federal income
tax chooses to use the proceeds received on liquidation of
that Investor's Partnership to purchase Swift Common Stock,
tax will still have to be paid on any taxable income resulting
from the Partnership's sale of oil and gas assets, without
regard to whether the Investor has cash proceeds remaining
from his liquidating distribution to pay such tax. Investors
that purchased their interests in the original offering,
however, are not expected to recognize gain on the sale.
The determination by the Special Transactions Committee to pay the
purchase premium, the independent Appraisers' determination of the fair market
value of the properties, and the payment of a 7.5% premium do not necessarily
remove the substantial conflicts of interest which exist in the transaction
between the Company serving as Managing General Partner of the Partnership and
also acting as the purchaser of the Property Interests from the Partnership.
No fairness opinion was requested or received regarding the ultimate purchase
price to be paid by the Company to purchase the Partnership's oil and gas
assets. The Company determined that rather than setting the purchase price for
Partnership Property Interests itself, it would be preferable to instead
request three different independent Appraisers to determine two sets of fair
market values at which such Property Interests should be purchased and then to
choose the higher of those two values. The Managing General Partner believes
that when the Appraisers rendered their opinions as to the "fair market value"
of the Partnership's Property Interests, inherent within their appraisal
opinions were the Appraisers' determination that these "fair market values"
were "fair," or such determinations would not have been made. Consequently, no
independent fairness opinion was requested regarding "fair market values" or
upon the premium. The Managing General Partner believes that adding a 7.5%
premium to the highest of the two fair market value determinations made by the
three Appraisers only serves to increase the amount to be paid to Investors
upon liquidation of the Partnership and does not require a separate fairness
opinion. The determination by a third party purchaser as to the purchase price
might be more or less than that being proposed by the Managing General Partner
as a purchase price for these Property Interests.
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<PAGE> 334
The determination to submit the Proposal to Investors in which the
Company would purchase the Property Interests of the Partnership was deemed by
the Managing General Partner to be the most appropriate time and method for
liquidation of the Partnership. This decision was made in light of full
consideration by the Managing General Partner of its fiduciary obligations to
Investors. Furthermore, the decision to use three Appraisers, rather than one,
and to have the Appraisers actually set the fair market value for purchase of
the Property Interests, rather than the Managing General Partner setting that
value and requesting a fairness opinion, were based upon the Managing General
Partner's consideration of the substantial conflicts of interest which exist in
the transactions covered hereby.
See "Special Factors--Fairness of Proposed Sale" in the Joint Proxy
Statement/Prospectus.
MANAGING GENERAL PARTNER BENEFITS
Benefits accruing to the Company resulting from the purchase of the
Partnerships' Property Interests include the following: the Managing General
Partner will share the benefits available to Investors through liquidating its
Partnership interests (including both its general partner interests and any
SDIs it owns) and receiving the same value of those interests as Investors.
Additionally, the Company intends to profit from purchasing the Partnership's
Property Interests through a return on capital used to purchase those oil and
gas assets and invest in their development. By purchasing the Partnership's
Property Interests itself, the Managing General Partner will be able to
maintain its position as operator of certain properties in which the
Partnership owns an interest. Consequently, the Managing General Partner would
continue to receive operating fees as operator of those properties. The sale
of the Partnership's Property Interests to the Managing General Partner will
have no effect or an inconsequential effect on the Managing General Partner's
net book value and net earnings. However, the purchase of all of the oil and
gas assets of the Partnerships would increase the Company's proved reserves,
cash flow and total assets by a significant amount. Lastly, if individual
Investors which approve the Proposal elect to purchase Company Common Stock,
rather than receiving cash upon liquidation of the Partnership, the Company
will benefit by using stock to pay the purchase price, rather than using its
available cash resources or borrowing facilities.
See "Special Factors--Managing General Partner Benefits" in the Joint Proxy
Statement/Prospectus.
SIMULTANEOUS PROPOSALS TO COMPANION PARTNERSHIPS
Simultaneous Proposals are being made to investors in the
Partnership's Companion Partnership. If both the Partnership and its Companion
Partnership do not approve their respective Proposals, it is likely to affect
the ability of the Partnership to consummate the sale of its Property
Interests. Although the Investors in the Partnership may desire to sell their
Property Interests, the separation of the working interest and the
non-operating interests in the same properties may affect the salability of
those interests on a permanent basis. If, for example, the Partnership
approves the Proposal but the Companion Partnership does not, the value of a
non-operating interest is likely to be negatively affected by the lack of
control over operations. [VARIABLE REVERSAL: If, for example, the Partnership
approves the Proposal but the Companion Partnership does not, the value of a
working interest burdened by a large non- operating interest is likely to be
lowered significantly.] If the Partnership's Companion Partnership does not
approve its Proposal, then the Managing General Partner will advise the
Investors in the Partnership. If the investors in the Partnership's Companion
Partnership do not vote in favor of its Proposal, then it is likely that the
Partnership will continue operations and will produce its reserves until
depletion, with steadily decreasing rates of cash flow, and consequently
steadily decreasing amounts of cash distributions to the Investors.
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VOTING ON THE PROPOSAL
The Joint Proxy Statement/Prospectus and the Proxy enclosed with this
Supplement are being provided for use at the Special Meeting of Investors of
the Partnership and at any adjournment or postponement of such meeting (the
"Meeting") to be held at 16825 Northchase Drive, Houston, Texas at 4:00 p.m.
Central Time on _______, __________, 1998. The Meeting is being called for the
purpose of considering and voting upon the Proposal to ultimately sell all of
the oil and gas assets of the Partnership to the Company, and to dissolve, wind
up and terminate the Partnership, and to transact such other business as may be
properly presented at the Meeting, all in accordance with the terms and
provisions of the Partnership's limited partnership agreement (the "Partnership
Agreement"), and the Texas Revised Limited Partnership Act (the "Texas Act").
This Joint Proxy Statement/Prospectus and enclosed Form of Proxy are first
being mailed to Investors on or about ____________, 1998.
Pursuant to the terms of the Partnership Agreement, the Partnership,
if not terminated earlier, will continue in being through December 31, 2021, at
which point it will terminate automatically.
Under the Partnership Agreement, the Proposal must be approved by the
affirmative vote of Investors holding more than 50% of SDIs in the Partnership
as of the Record Date (defined below). Therefore, an abstention by an Investor
will have the same effect as a vote against the Proposal. The solicitations
are being made for votes in favor of the Proposal (which will result in
liquidation and dissolution of the Partnership). As of the Record Date,
6,076,102 SDIs were outstanding and held by record holders (excluding the SDIs
held by the Managing General Partner). Accordingly, the affirmative vote of
holders of at least 3,038,052 SDIs is required to approve the Proposal. Each
Investor appearing on the records of the Partnership as of ______, 1998 (the
"Record Date") is entitled to notice of the Meeting and is entitled to one vote
for each SDI held by such Investor. VJM Corporation, a California corporation,
is the Special General Partner of the Partnership, and owns a 0.75% interest in
the Partnership as a general partner, but owns no SDIs. The Managing General
Partner owns a general partner interest in the Partnership of 14.25%.
Additionally, the Managing General Partner owns 161,000 outstanding SDIs in the
Partnership, which ownership results from the Managing General Partner's
purchase over the life of the Partnership of SDIs from Investors under the
right of presentment, contained in the Partnership Agreement. Under the
Partnership Agreement, the Managing General Partner may not vote any SDIs owned
by it for matters such as the Proposal. The Managing General Partner's
non-vote, in contrast to abstention by Investors, will not affect the outcome,
because for purposes of adopting the Proposal, its SDIs are excluded from the
total number of voting SDIs.
VOTE REQUIRED
The actual proxy to be used to register the vote on the Proposal
before you is the separate green sheet of paper included with this Supplement
and Joint Proxy Statement/Prospectus. PLEASE USE THE GREEN PROXY TO CAST YOUR
VOTE ON THE PROPOSAL.
If a proxy is properly signed and is not revoked by an Investor, the
SDIs it represents will be voted in accordance with the instructions of the
Investor. If no specific instructions are given, the SDIs will be voted FOR
the Proposal. An Investor may revoke his proxy at any time before it is voted
at the Meeting.
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Any Investor who attends the Meeting and wishes to vote in person may revoke
his proxy at that time. Otherwise, an Investor must advise the Managing
General Partner of revocation of his proxy in writing, which revocation must be
received by the Managing General Partner at 16825 Northchase Drive, Suite 400,
Houston, Texas 77060 prior to the time the vote is taken.
SOLICITATION
The solicitation is being made by the Partnership. The Partnership
will bear the costs of the preparation of the Joint Proxy Statement/Prospectus
and of the solicitation of proxies and such costs will be allocated 85% to the
Investors and 15% to the general partners pursuant to the terms of the
Partnership Agreement. As the Managing General Partner holds approximately
2.58% of the SDIs held by all Investors, 2.58% of the costs borne by the
Investors will be borne by the Managing General Partner, in addition to the
portion of the Partnership's total costs borne by the general partners by
virtue of their interest in the Partnership as general partners. Solicitations
will be made primarily by mail. In addition, a number of regular or temporary
employees of the Managing General Partner may, if necessary to ensure the
presence of a quorum, solicit proxies in person or by telephone. The Managing
General Partner also may retain a proxy solicitor to assist in contacting
brokers or Investors to encourage the return of proxies, although it does not
anticipate doing so.
PARTNERSHIP BUSINESS AND FINANCIAL CONDITION
The Partnership is a Texas limited partnership formed June 30, 1993.
SDIs in the Partnership are registered under Section 12(g) of the Securities
Exchange Act of 1934. The Partnership owns non-operating Property Interests in
producing oil and gas properties within the continental United States in which
the Companion Partnership also managed by the Managing General Partner owns the
working interests. By the end of October 1993, the Partnership had expended
all of its original capital contributions for the purchase of Property
Interests in oil and gas producing properties. During 1997, approximately 58%
of the Partnership's revenue was attributable to natural gas production. From
time to time, the Companion Partnership has performed workovers and
recompletions on wells in which the Partnership has non- operating interests,
using funds advanced by the Managing General Partner to perform these
operations, which amounts have been subsequently repaid. For information about
the business of the Partnership, see the attached Annual Report on Form 10-K
for the year ended December 31, 1997 and Quarterly Report on Form 10-Q for the
quarter ended June 30, 1998.
Investors made contributions of $6,237,102, in the aggregate to the
Partnership, the net proceeds of which has all been invested. The Managing
General Partner has made capital contributions with respect to its general
partner interest of $810,823. Additionally, pursuant to the right of
presentment set forth in the Partnership Agreement, it has purchased 161,000
SDIs from Investors. From inception through July 31, 1998, the Partnership has
made net cash distributions to its Investors totaling $2,760,200. Details of
the amounts of cash distributions made to partners over the past three years
and nine months are set out under "Cash Distributions" below. Through July 31,
1998, the Managing General Partner has received net cash distributions from the
Partnership of $453,472 with respect to its general partner interest, and
$35,724 related to the number of SDIs it purchased from Investors. On a per
SDI basis, Investors had received, as of July 31, 1998, $0.44 per $1.00 SDI, or
approximately 44.3% of their initial capital contributions.
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The Partnership acquired its Property Interests at a time when oil and
gas prices and industry projections of future prices were much higher than
actually occurred in subsequent years. When the Managing General Partner
projected future oil and gas prices to evaluate the economic viability of an
acquisition, it compared its forecasts with those made by banks, oil and gas
industry sources, the U.S. government and other companies acquiring producing
properties. Acquisition decisions for the Partnership were based upon a range
of increasing prices that were within the mainstream of the forecasts made by
these outside parties. At the time that the Partnership's Property Interests
covering producing properties were acquired, prices averaged about $19.70 per
barrel of oil and $2.06 per Mcf of natural gas. The majority of the
Partnership's Property Interests were acquired by the end of October 1993 and
were comprised principally of natural gas reserves. At that time current
prices were predicted to escalate according to certain parameters from then
current levels to approximately $25.05 per barrel of oil and $2.63 per Mcf of
natural gas during 1997. The predicted price increases did not occur, and
prices fell precipitously from 1994 to 1995. Most of the Partnership's
reserves were produced from 1993 to 1997, during which time the oil prices
received by the Partnership for its production in fact averaged $16.48 per
barrel, but the prices for the Partnership's principal asset, natural gas,
averaged approximately $2.14 per Mcf. A comparison of oil and gas prices as
described in this paragraph appears in the graph presented below.
The following graphs illustrate the effect on Partnership performance
of the variance between oil and gas prices projected at the time of acquisition
of the Partnership's Property Interests and actual oil and gas prices received
for production (as illustrated in the second graph) during the Partnership's
existence.
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[GRAPH: 1 page of gas properties info]
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[GRAPH: 1 page of oil properties info]
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Lower prices also have had an effect on the Partnership's interest in
proved reserves. Estimates of proved reserves represent quantities of oil and
gas which, upon analysis of engineering and geologic data, appear with
reasonable certainty to be recoverable in the future from known oil and gas
reservoirs under existing economic and operating conditions. When economic or
operating conditions change, proved reserves can be revised either up or down.
If prices had risen as predicted, the volumes of oil and gas reserves that are
economically recoverable might have been higher than the year-end levels
actually reported because higher prices typically extend the life of reserves
as production rates from mature wells remain economical for a longer period of
time. Production enhancement projects that are not economically feasible at
low prices can also be implemented as prices rise.
CASH DISTRIBUTIONS
Cash distributions are made to the partners in the Partnership on a
quarterly basis. During the past three years and the first nine months of
1998, aggregate cash distributions made to all partners in the Partnership
(including the Managing General Partner) and the cash distributions per SDI
made to the Investors were:
<TABLE>
<S> <C> <C> <C>
1995 $ 612,756 $ 0.09 per $1.00 SDI
1996 $ 503,718 $ 0.07 per $1.00 SDI
1997 $ 575,226 $ 0.08 per $1.00 SDI
9 Mo. Ended 9/30/98 $ 309,950 $ 0.05 per $1.00 SDI
</TABLE>
TRANSACTIONS BETWEEN THE MANAGING GENERAL PARTNER AND THE PARTNERSHIP
Under the Partnership Agreement, the Managing General Partner has
received certain compensation for its services and reimbursement for
expenditures made on behalf of the Partnership, which was paid at closing of
the offering of SDIs, in addition to revenues distributable to the Managing
General Partner with respect to its general partner interest or with respect to
SDIs it has purchased under the Investors' right of presentment. In addition
to those revenues, compensation and reimbursements, the following summarizes
the transactions between the Managing General Partner and the Partnership
pursuant to which the Managing General Partner has been paid or has had its
expenses reimbursed on an ongoing basis:
o The Managing General Partner has received internal acquisition
costs reimbursements of $297,224 from the Partnership from
inception through December 31, 1997, none of which has been
received during the two years ended December 31, 1997.
o The Managing General Partner receives operating fees for wells
in which the Partnership has Property Interests and for which
the Managing General Partner or its affiliates serve as
operator. During the years ended December 31, 1997 and
December 31, 1996 the aggregate operating fees paid to the
Company as operator by the Partnership were $38,127 and
$43,502, respectively. Monthly operating fees range from $400
to $1,500 per well on an 8/8th's basis (i.e., the total amount
of operating fees paid by all interest owners in the well).
If the Property Interests are sold to the Managing General
Partner, there should be no change in its status as operator
for a number of the wells in which the Partnership has a
Property Interest. The Managing General Partner believes that
it will be positively affected, on the other hand, by
liquidation of the Partnership, both on the basis of its
ownership interest in the Partnership and for other reasons
set out under "Special Factors--Managing General Partner
Benefits" in this Supplement.
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o The Managing General Partner is entitled to be reimbursed for
general and administrative costs incurred on behalf of and
allocable to the Partnership, including employee salaries and
office overhead. Amounts are calculated on the basis of
Investors' original capital contributions to the Partnership
relative to investor contributions to all public partnerships
formed to purchase interests in producing properties for which
the Managing General Partner serves in that capacity. Through
December 31, 1997, the Managing General Partner had received
$458,444 in the general and administrative overhead allowance
from the Partnership, of which $93,557 and $93,557 have been
reimbursed during the years ended December 31, 1997 and
December 31, 1996, respectively.
o The Managing General Partner has been reimbursed $12,908 in
direct expenses by the Partnership, all of which was billed
by, and then paid directly to, third party vendors, of which
$2,280 and $3,127 have been reimbursed during the years ended
December 31, 1997 and December 31, 1996, respectively.
o The Managing General Partner has received a nonaccountable
incentive amount of $123,405 for services rendered from
inception through December 31, 1997, of which $8,029 and
$9,218 have been reimbursed during the years ended December
31, 1997 and December 31, 1996, respectively.
NO TRADING MARKET
There is no trading market for the SDIs, and none is expected to
develop, as described above under "Special Factors--Fairness of Proposed Sale
of Assets to the Managing General Partner as Compared to Continuing
Operations." Under the Partnership Agreement, Investors have the right to
present their SDIs to the Managing General Partner for repurchase at a price
determined in accordance with the formula established by the Partnership
Agreement. Originally 576 Investors invested in the Partnership. As of
__________, 1998, there were 559 Investors (excluding the Managing General
Partner). The number of SDIs in the Partnership issued and outstanding at that
date was 6,237,102. Through December 31, 1997, the Managing General Partner
had purchased 161,000 SDIs from Investors pursuant to the right of presentment.
The Managing General Partner does not have an obligation to repurchase Investor
interests pursuant to this right of presentment, but merely an option to do so
when such interests are presented for repurchase.
PRINCIPAL HOLDERS OF INVESTOR SDIS
The Managing General Partner holds 2.58% of all outstanding SDIs of
the Partnership, resulting from the purchase of SDIs from Investors under their
right of presentment. To the knowledge of the Managing General Partner, there
is no holder of SDIs that holds more than 5% of the SDIs.
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APPROVALS
No federal or state regulatory requirements must be satisfied or
approvals obtained in connection with the sale of the Partnership's Property
Interests.
LEGAL PROCEEDINGS
The Managing General Partner is not aware of any material pending
legal proceedings to which the Partnership is a party or of which any of its
property is the subject.
SUMMARY OF FEDERAL INCOME TAX CONSEQUENCES
GENERAL
The following briefly summarizes the federal income tax consequences
set forth under "Federal Income Tax Consequences of Adoption of the Proposals"
in the Joint Proxy Statement/Prospectus. Statements of legal conclusions
herein regarding tax consequences are based upon an opinion of Hoops and Levy,
L.L.P., Special Tax Counsel, relevant provisions of the Internal Revenue Code
of 1986, as amended (the "Code"), and accompanying Treasury Regulations, as in
effect on the date hereof, upon reported judicial decisions and published
positions of the Internal Revenue Service (the "Service"), a private letter
ruling dated February 6, 1991 and upon further assumptions that the Partnership
constitutes a partnership for federal tax purposes and that the Partnership
will be liquidated as described herein. The laws, regulations, administrative
rulings and judicial decisions which form the basis for conclusions with
respect to the tax consequences described herein are complex and are subject to
prospective or retroactive change at any time and any change may adversely
affect Investors.
A MORE COMPLETE SUMMARY OF THE FEDERAL INCOME TAX CONSEQUENCES TO
INVESTORS MAY BE FOUND IN THE REGISTRATION STATEMENT IN "FEDERAL INCOME TAX
CONSEQUENCES OF ADOPTION OF THE PROPOSALS." THIS SUMMARY DOES NOT DESCRIBE ALL
THE TAX ASPECTS WHICH MAY AFFECT INVESTORS NOR IS IT A COMPLETE DESCRIPTION OF
THE TAX ASPECTS IT DOES DESCRIBE. It is generally directed to Tax Exempt Plans
that are Investors who are the original purchasers of the SDIs and hold
interests in the Partnership as "capital assets" (generally, property held for
investment). Each Investor that is a corporation, trust, estate, or other
partnership is strongly encouraged to consult its own tax advisor as to the
rules which are specifically applicable to it. Except as otherwise
specifically set forth herein, this summary does not address foreign, state or
local tax consequences, and is inapplicable to nonresident aliens, foreign
corporations, debtors under the jurisdiction of a court in a case under federal
bankruptcy laws or in a receivership, foreclosure or similar proceeding, or an
investment company, financial institution or insurance company.
TAX TREATMENT OF TAX EXEMPT PLANS
SALE OF PROPERTY INTEREST AND LIQUIDATION OF PARTNERSHIP
Tax Exempt Plans are subject to tax on their unrelated business
taxable income ("UBTI"). Royalty interests, dividends, interest and gain from
the disposition of capital assets are generally excluded from classification
as UBTI. Notwithstanding these exclusions, royalties, interest, dividends, and
gains will create UBTI if they are received from debt-financed property, as
discussed below.
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The Internal Revenue Service has previously ruled that the
Partnership's net profits interest, as structured under the net profits
agreement, is a royalty, as are any overriding royalties the Partnership may
own. To the extent that the Property Interest is not debt-financed property,
neither the sale of the Property Interest by the Partnership nor the
liquidation of the Partnership is expected to cause Investors that are Tax
Exempt Plans either taxable gain or loss for federal income tax purposes, even
though there may be gain or loss upon the sale of the Property Interest for
federal income tax purposes.
DEBT-FINANCED PROPERTY
Debt-financed property is property held to produce income that is
subject to acquisition indebtedness. The income is taxable in the same
proportion which the debt bears to the total cost of acquiring the property.
Generally, acquisition indebtedness is the unpaid amount of (i) indebtedness
incurred by a Tax Exempt Plan to acquire an interest in a partnership, (ii)
indebtedness incurred in acquiring or improving property, or (iii) indebtedness
incurred either before or after the acquisition or improvement of property or
the acquisition of a partnership interest if such indebtedness would not have
been incurred but for such acquisition or improvement, and if incurred
subsequent to such acquisition or improvement, the incurrence of such
indebtedness was reasonably foreseeable at the time of such acquisition or
improvement.
If an Investor that is a Tax Exempt Plan borrowed to acquire its
Partnership interest or had borrowed funds either before or after it acquired
its Partnership Interest, its pro rata share of Partnership gain on the sale of
the Property Interest may be UBTI. If a Tax Exempt Plan has not caused its
Partnership Interest to be debt-financed property, and based upon
representations of the Managing General, the Property Interest is not expected
to be considered debt-financed property.
TAX TREATMENT OF INVESTORS SUBJECT TO FEDERAL INCOME TAX DUE TO DEBT-FINANCING
All references hereinbelow to Investors refers solely to Investors
that either are not Tax Exempt Plans or are Tax Exempt Plans whose Partnership
Interest is debt-financed. To the extent that a Tax Exempt Plan's Partnership
Interest is only partially debt-financed, the percentage of gain or loss from
the sale of the Property Interest and liquidation of the Partnership that will
be subject to taxation as UBTI is the percentage of the Tax Exempt Plan's share
of Partnership income, gain, loss and deduction adjusted by the following
calculation. Section 514(a)(1) includes, with respect to each debt-financed
property, as gross income from an unrelated trade or business an amount which
is the same percentage of the total gross income derived during the taxable
year from or on account of the property as (i) the average acquisition
indebtedness for the taxable year with respect to the property is of (ii) the
average amount of the adjusted basis of the property during the period it is
held by the organization during the taxable year (the "debt/basis percentage").
A similar calculation is used to determine the allowable deductions.
Tax Exempt Plans with debt-financed Partnership Interests should
consult their tax advisors to determine the portion of gain or loss that may be
recognized for federal income tax purposes. The following discussion of the
tax consequences of the sale of the Partnership Property Interest and the
liquidation of the Partnership assumes that all of an Investor's income, gain,
loss and deduction from the Partnership is subject to federal taxation.
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TAXABLE GAIN OR LOSS UPON SALE OF PROPERTIES
Investors will realize and recognize gain or loss, or a combination of
both, upon the Partnership's sale of its properties prior to liquidation. It
is projected, however, that Investors will realize a net taxable loss upon the
sale of the Partnership properties.
LIQUIDATION OF THE PARTNERSHIP
After sale of its properties, the Partnership's assets will consist
solely of cash which it will distribute to its partners in complete
liquidation. The Partnership will not realize gain or loss upon such
distribution of cash to its partners in liquidation. If the amount of cash
distributed to an Investor in liquidation is less than such Investor's adjusted
tax basis in his Partnership interest, the Investor will realize and recognize
a capital loss to the extent of the excess. If the amount of cash distributed
is greater than such Investor's adjusted tax basis in his Partnership interest,
the Investor will recognize a capital gain to the extent of the excess.
CAPITAL GAIN TAX
Net long-term capital gains of individuals, trusts and estates
generally will be taxed at a maximum rate of 20%, while ordinary income,
including income from the recapture of intangible drilling and development
costs, depreciation and depletion, will be taxed at a maximum rate depending on
that Investor's taxable income of 36% or 39.6%.
PASSIVE LOSS LIMITATIONS
Investors that are individuals, trusts, estates, or personal service
corporations are subject to the passive activity loss limitations rules that
were enacted as part of the Tax Reform Act of 1986.
An Investor's allocable share of Partnership income, gain, loss, and
deduction is treated as derived from a passive activity, except to the extent
of Partnership portfolio income, which includes interest, dividends, royalty
income and gains from the sale of property held for investment purposes. An
Investor's share of any gain or loss realized upon the sale of the net profits
interest is expected to be characterized as portfolio income or loss and may
not be offset, or be offset by, passive activity gains or losses.
THE FOREGOING DISCUSSION IS A SUMMARY OF THE INCOME TAX CONSEQUENCES
SET FORTH UNDER "FEDERAL INCOME TAX CONSEQUENCES OF ADOPTION OF THE PROPOSALS"
IN THE JOINT PROXY STATEMENT/PROSPECTUS. IT IS NOT INTENDED AS AN ALTERNATIVE
FOR INDIVIDUAL TAX PLANNING. EACH INVESTOR SHOULD CONSULT HIS, HER OR ITS OWN
TAX ADVISOR CONCERNING THE PARTICULAR FEDERAL, STATE, LOCAL, FOREIGN AND OTHER
TAX CONSEQUENCES APPLICABLE TO HIM, HER OR IT OF THE SALE OF PROPERTIES AND THE
LIQUIDATION OF THE PARTNERSHIP.
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SELECTED FINANCIAL INFORMATION AND
PROFORMA FINANCIAL STATEMENTS
For selected financial information and financial statements of the
Partnership, see the Annual Report on Form 10-K for the year ended December 31,
1997 and the Quarterly Report on Form 10-Q for the quarter ended June 30, 1998
attached hereto.
Proforma Financial Statements showing the effect of approval of the
Proposals by the 63 Partnerships to whom similar proposals are being made (both
in the event of the decision by investors to purchase the maximum number of
shares of Swift Common Stock purchasable with their cash distributions and in
the event that investors choose to take all of their distributions from sale of
the properties in cash) and the effect of the Sonat Properties Acquisition are
contained in the Joint Proxy Statement/Prospectus under "Unaudited Proforma
Consolidated Financial Statements".
OFFERING OF SHARES OF SWIFT ENERGY COMPANY COMMON STOCK
IF INVESTORS APPROVE THE PROPOSAL
VOTING PROCEDURES
The Joint Proxy Statement/Prospectus contains detailed procedures to
be followed by investors in voting as to the Partnerships' Proposals. Strict
compliance with these procedures must be followed in order for the elections of
the investors marked on the Proxies and subscription agreement to be effective.
The following is a summary of certain of these procedures:
(a) Investors may make their elections on the subscription agreement
signed by all subscribers commencing upon delivery of this Joint Proxy
Statement/Prospectus and continuing until the Due Date.
(b) If Investors in the Partnership (and its Companion Partnership)
vote to approve the Proposal, Investors may revoke their election to purchase
Shares offered hereby at any time until the Due Date by delivering or faxing a
letter so stating or a later dated subscription agreement, both of which must
be signed by such revoking subscribers, to the Company at 16825 Northchase
Drive, Suite 400, Houston, Texas 77060, fax number (281) 874-2818; Attention:
Investor Relations Department.
(c) Investors failing to submit proxies by the Special Meeting Date
will be deemed to have voted against their Partnership's Proposal and, if their
Partnership approves its Proposal, will receive along with non-subscribing
investors who timely submitted proxies their distribution in cash. See "The
Proposals--Vote Required" in the Joint Proxy Statement/Prospectus.
OFFER OF SWIFT COMMON STOCK
Investor Election to Purchase Shares
In connection with the concurrent Proposals for sale of all of the oil
and gas assets of 63 Partnerships to the Company and the subsequent termination
of such Partnerships, the Company is offering up to 2,500,000 shares of the
Company's Common Stock. Upon approval of the Proposals by the Partnership and
its Companion Partnership and sale of the Partnership's oil and gas assets, the
Partnership's assets will consist solely of cash which each investor as an
Eligible Purchaser of such Partnerships will be
29
<PAGE> 346
entitled to receive as a distribution. The Company hereby offers to each such
Eligible Purchaser the opportunity to purchase shares of Common Stock with all
or any portion of the cash distribution such Investor will be entitled to
receive, provided that a minimum round lot of 100 shares must be purchased. If
an Eligible Purchaser has interests in more than one Partnership, the cash
distributions he will be entitled to receive may be aggregated to meet the
minimum round lot of 100 shares requirement. Each such Eligible Purchaser may
purchase shares of Common Stock with funds in addition to their cash
distributions in order to purchase (i) the minimum round lot of 100 shares, or
(ii) shares in addition to the number of shares for which their cash
distribution will be applied, subject to prorata limitations in the event of
oversubscription. No fractional shares will be sold.
Purchase Price
The price at which the Common Stock offered hereby will be issued will
be the average price of the Common Stock as reported by the NYSE for the period
between ________ and __________, 1998.
New York Stock Exchange and Pacific Exchange Listings
The Common Stock is traded on the NYSE and the Pacific Exchange under
the symbol "SFY." Application will be made to list the Shares offered hereby
on the NYSE and the Pacific Exchange.
Closing Date
The Company will issue checks representing full or partial
distributions and/or stock certificates representing the Shares of Common Stock
subscribed for hereunder approximately forty-five (45) days after the date of
the Prospectus Supplement (the "Closing Date"), unless earlier terminated or
extended by the Company.
Due Date
All subscriptions, revocations of prior subscriptions or additional
required consideration must be received no later than thirty (30) days after
the date of the Prospectus Supplement (the "Due Date"), unless extended by the
Company.
Oversubscription
In the event this Offering is oversubscribed, all subscribing Eligible
Purchasers will first be sold a round lot of 100 shares and then, if
applicable, that number of shares of Common Stock the purchase price of which
is equal to such Eligible Purchaser's cash distribution, rounded down to the
next whole share. Any remaining shares will be sold on a prorata basis based
on the number of shares such subscribers wish to purchase.
Revocation
Eligible Purchasers may revoke their subscriptions to purchase of the
Shares offered hereby at any time until the Due Date by delivering or faxing a
letter so stating or a later subscription agreement, either of which must be
signed by such revoking subscribers, to the Company at 16825 Northchase Drive,
Suite 400, Houston, Texas 77060, fax number (281) 874-2818; Attention:
Investor Relations Department.
30
<PAGE> 347
TABLE OF CONTENTS
<TABLE>
<S> <C>
THE PARTNERSHIP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
CONFLICTS OF INTEREST . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
SPECIAL FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Background and Purpose of the Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Proposed Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Reasons for the Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Current Liquidating Distribution Lowers Volatility Risk . . . . . . . . . . . . . . . . . . . . . . . 8
Decreasing Cash Flow While Expenses Continue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Undeveloped and Behind Pipe Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Interest Holders' Tax Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Collective Analysis of Purchase Price; Premium over Fair Market Value . . . . . . . . . . . . . . . . . . . . 9
Determination of Premium Over Fair Market Value by the Company . . . . . . . . . . . . . . . . . . . . . . . 11
"Special Factors" Section in the Joint Proxy Statement/Prospectus . . . . . . . . . . . . . . . . . . . . . 12
Estimates of Liquidating Net Cash Distribution Amount if the Proposal is Approved . . . . . . . . . . . . . 12
Estimates of Net Cash Distributions Available from Continued Operations . . . . . . . . . . . . . . . . . . 14
Fairness of Proposed Sale of Assets to the Managing General Partner
as Compared to Continuing Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Fairness of Proposed Sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Managing General Partner Benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Simultaneous Proposals to Companion Partnerships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
VOTING ON THE PROPOSAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Vote Required . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Solicitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
PARTNERSHIP BUSINESS AND FINANCIAL CONDITION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Cash Distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Transactions Between the Managing General Partner and the Partnership . . . . . . . . . . . . . . . . . . . 24
No Trading Market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Principal Holders of Investor SDIs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Approvals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
SUMMARY OF FEDERAL INCOME TAX CONSEQUENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Tax Treatment of Tax Exempt Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Sale of Property Interest and Liquidation of Partnership . . . . . . . . . . . . . . . . . . . . . . 26
Debt-Financed Property . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Tax Treatment of Investors Subject to Federal Income Tax Due to Debt-Financing . . . . . . . . . . . . . . . 27
</TABLE>
(i)
<PAGE> 348
<TABLE>
<S> <C>
Taxable Gain or Loss Upon Sale of Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Liquidation of the Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Capital Gain Tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Passive Loss Limitations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
SELECTED FINANCIAL INFORMATION AND
PROFORMA FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
OFFERING OF SHARES OF SWIFT ENERGY COMPANY COMMON STOCKIF INVESTORS APPROVE THE PROPOSAL . . . . . . . . . . . . . . 29
Voting Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Offer of Swift Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Investor Election to Purchase Shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
New York Stock Exchange and Pacific Exchange Listings . . . . . . . . . . . . . . . . . . . . . . . 30
Closing Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Due Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Oversubscription . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Revocation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
FORM OF PROXY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (A)
</TABLE>
(ii)
<PAGE> 349
ATTACHMENT A
April 17, 1998
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Attn: Special Transactions Committee FAIR MARKET VALUE ESTIMATE
Board of Directors SWIFT ENERGY PENSION PARTNERS 1993-B, LTD.
97-003-133
Gentlemen:
At your request, we have audited the proved, probable and possible reserves and
future net cash flow as of December 31, 1997, prepared by Swift Energy Company
("Swift") for certain interests owned by the partners in Swift Energy Pension
Partners 1993-B, Ltd. This audit has been conducted according to the Standards
Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information
approved by the Board of Directors of the Society of Petroleum Engineers on
October 30, 1979. We have reviewed these properties and where we disagreed with
the Swift reserve estimates, Swift revised its estimates to be in agreement.
From this audit, and in consultation with J.R. Butler and Company, our estimate
of the fair market value of this partnership is $1,234,678.
Fair market value as used herein is defined as that price that a willing buyer
will pay and a willing seller will accept at a given point in time, with neither
the buyer nor the seller under any compulsion to buy or sell, and both having
reasonable knowledge of all the material circumstances.
To estimate the fair market value attributable to the proved developed producing
reserves, the 10 percent discounted future net cash flow was multiplied by a
suitable factor (less than one) to account for the risk associated with the
reserves, operating expenses, and prices and to approximate tax consequences.
The internal rate of return and payout time were computed for this quantity and
compared with those at which current acquisitions are completed. Suitable
adjustments are then made to correspond to these two financial indices. Proved
developed nonproducing, proved undeveloped, probable and possible reserves
require capital investments and must be treated appropriately. For these cases,
the capital is added to the discounted net cash flow, then multiplied by a
suitable risk factor and the capital then subtracted. This has the effect that
capital is spent with certainty and the operating cash income is burdened with
the risk. Internal rate of return and payout time is calculated for each
estimate to establish reasonableness based upon it the reserve category.
<PAGE> 350
Swift Energy Company -2- April 17, 1998
The estimated future net cash flow is that cash flow which will be realized from
the sale of the estimated net reserves after deduction of royalties, ad valorem
and production taxes, direct operating costs and capital expenditures, when
applicable. Surface and well equipment salvage values and well plugging and
field abandonment costs have not been considered in the cash flow projections.
Future net cash flow as stated in this report is before the deduction of federal
income tax.
The following parameters are incorporated in the economic projections referenced
in this report. Initial oil prices are the existing prices on December 31, 1997,
and are escalated 3.5 percent per year beginning in 1999 through the year 2012
after adjusting for transportation and gravity variances. Initial natural gas
prices are those existing on December 31, 1997, and are escalated 3.5 percent
per year beginning in 1999 through the year 2012 after adjusting for
transportation and Btu content. Operating expenses are escalated at an annual
rate of 3.5 percent until the year 2012. The actual prices that will be received
and the associated costs may be more or less than those projected.
For those wells with sufficient production history, reserve estimates and rate
projections are based on the extrapolation of established performance trends.
Reserves for other producing and nonproducing properties have been estimated
from volumetric calculations and analogy with the performance of comparable
wells. The reserves referenced in this study are estimates only and should not
be construed as exact quantities. Future conditions may affect recovery of
estimated reserves and cash flow, and all categories of reserves may be subject
to revision as more performance data become available. The proved reserves are
estimated in accordance with the definitions included in the Securities and
Exchange Commission Regulation S-X, Rule 4-10(a) except for the price and cost
escalations. The definitions are included in part as Attachment I. The probable
and possible reserves conform to the definitions approved by the Society of
Petroleum Engineers, Inc. The definitions are included as Attachment II.
Extent and character of ownership, oil and gas prices, production data, direct
operating costs, capital expenditure estimates and other data provided by Swift
have been accepted as represented. The production data available to us were
through the month of October 1997, except in those instances in which data were
available through December. Interim production to December 31, 1997, has been
estimated. Operating expenses as supplied by Swift were not audited, but were
reviewed for reasonableness. No independent well tests, property inspections or
audits of operating expenses were conducted by our staff in conjunction with
this study. We did not verify or determine the extent, character, obligations,
status or liabilities, if any, arising from any current or possible future
environmental liabilities that might be applicable.
In order to audit the reserves, costs and future cash flows referenced in this
report, we have relied in part on geological, engineering and economic data
furnished by our client. Although we have made a best efforts attempt to acquire
all pertinent data and to analyze it carefully with methods accepted by the
petroleum industry, there is no guarantee that the volumes of oil or gas or the
cash flows projected will be realized. The reserve and cash flow projections
referenced in this report may require revision as additional data become
available.
<PAGE> 351
ATTACHMENT I
DEFINITIONS OF PROVED OIL AND GAS RESERVES(1)
PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquid which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
PROVED DEVELOPED OIL AND GAS RESERVES
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be 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.
PROVED UNDEVELOPED RESERVES
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
- --------
(1) Contained in Securities and Exchange Commission Regulation S-X,
Rule 4-10(a)
H.J. GRUY AND ASSOCIATES, INC. 1200 Smith Street, Suite 3040,
Houston, Texas 77002 (713) 739-1000
<PAGE> 352
ATTACHMENT II
PETROLEUM RESERVES DEFINITIONS
SOCIETY OF PETROLEUM ENGINEERS (SPE) AND WORLD PETROLEUM CONGRESS (WPC)(1)
Reserves are those quantities of petroleum which are anticipated to be
commercially recovered from known accumulations from a given date forward. All
reserve estimates involve some degree of uncertainty. The uncertainty depends
chiefly on the amount of reliable geologic and engineering data available at the
time of the estimate and the interpretation of these data. The relative degree
of uncertainty may be conveyed by placing reserves into one of two principal
classifications, either proved or unproved. Unproved reserves are less certain
to be recovered than proved reserves and may be further sub-classified as
probable and possible reserves to denote progressively increasing uncertainty in
their recoverability.
The intent of the SPE and WPC in approving additional classifications beyond
proved reserves is to facilitate consistency among professionals using such
terms. In presenting these definitions, neither organization is recommending
public disclosure of reserves classified as unproved. Public disclosure of the
quantities classified as unproved reserves is left to the discretion of the
countries or companies involved.
Estimation of reserves is done under conditions of uncertainty. The method of
estimation is called deterministic if a single best estimate of reserves is made
based on known geological, engineering and economic data. The method of
estimation is called probabilistic when the known geological, engineering, and
economic data are used to generate a range of estimates and their associated
probabilities. Identifying reserves as proved, probable, and possible has been
the most frequent classification method and gives an indication of the
probability of recovery. Because of potential differences in uncertainty,
caution should be exercised when aggregating reserves of different
classifications.
Reserves estimates will generally be revised as additional geologic or
engineering data become available or as economic conditions change. Reserves do
not include quantities of petroleum being held in inventory, and may be reduced
for usage of processing losses if required for financial reporting.
Reserves may be attributed to either natural energy or improved recovery
methods. Improved recovery methods include all methods for supplementing natural
energy or altering natural forces in the reservoir to increase ultimate
recovery. Examples of such methods are pressure maintenance, cycling,
waterflooding, thermal methods, chemical flooding, and the use of miscible and
immiscible displacement fluids. Other improved recovery methods may be developed
in the future as petroleum technology continues to evolve.
PROVED RESERVES
Proved reserves are those quantities of petroleum which, by analysis of
geological and engineering data, can be estimated with reasonable certainty to
be commercially recoverable, from a given date forward, from known reservoirs
and under current economic conditions, operating methods, and government
regulations. Proved reserves can be categorized as developed or undeveloped.
If deterministic methods are used, the term reasonable certainty is intended to
express a high degree of confidence that the quantities will be recovered. If
probabilistic methods are used, there should be at least a 90% probability that
the quantities actually recovered will equal or exceed the estimate.
Establishment of current economic conditions should include relevant historical
petroleum prices and associated costs and may involve an averaging period that
is consistent with the purpose of the reserve estimate, appropriate contract
obligations, corporate procedures, and government regulations involved in
reporting these reserves.
In general, reserves are considered proved if the commercial producibility of
the reservoir is supported by actual production or formation tests. In this
context, the term proved refers to the actual quantities of petroleum reserves
and not just the productivity of the well or reservoir. In certain cases,
proved reserves may be assigned on the basis of well logs and/or core analysis
that indicate the subject reservoir is hydrocarbon bearing and is analogous to
reservoirs in the same area that are producing or have demonstrated the ability
to produce on formation tests.
The area of the reservoir considered as proved includes (1) the area delineated
by drilling and defined by fluid contacts, if any, and (2) the undrilled
portions of the reservoir that can reasonably be judged as commercially
productive on the basis of available geological and engineering data. In the
absence of data on fluid contacts, the lowest known occurrence of hydrocarbons
controls the proved limit unless otherwise indicated by definitive geological,
engineering or performance data.
- --------------------------
(1) Approved by the Board of Directors. Society of Petroleum Engineers (SPE),
Inc. on March 7, 1997.
<PAGE> 353
Reserves may be classified as proved if facilities to process and transport
those reserves to market are operational at the time of the estimate or there is
a reasonable expectation that such facilities will be installed. Reserves in
undeveloped locations may be classified as proved undeveloped provided (1) the
locations are direct offsets to wells that have indicated commercial production
in the objective formation, (2) it is reasonably certain such locations are
within the known proved productive limits of the objective formation, (3) the
locations conform to existing well spacing regulations where applicable, and (4)
it is reasonably certain the locations will be developed. Reserves from other
locations are categorized as proved undeveloped only where interpretations of
geological and engineering data from wells indicate with reasonable certainty
that the objective formation is laterally continuous and contains commercially
recoverable petroleum at locations beyond direct offsets.
Reserve which are to be produced through the application of established improved
recovery methods are included in the proved classification when (1) successful
testing by a pilot project or favorable response of an installed program in the
same or an analogous reservoir with similar rock and fluid properties provides
support for the analysis on which the project was based, and, (2) it is
reasonably certain that project will proceed. Reserves to be recovered by
improved recovery methods that have yet to be established through commercially
successful applications are included in the proved classification only (1) after
a favorable production response from the subject reservoir from either (a) a
representative pilot or (b) an installed program where the response provides
support for the analysis on which the project is based and (2) it is reasonably
certain the project will proceed.
UNPROVED RESERVES
Unproved reserves are based on geologic and/or engineering data similar to that
used in estimates of proved reserves; but technical, contractual, economic, or
regulatory uncertainties preclude such reserves being classified as proved.
Unproved reserves may be further classified as probable reserves and possible
reserves.
Unproved reserves may be estimated assuming future economic conditions different
from those prevailing at the time of the estimate. The effect of possible future
improvements in economic conditions and technological developments can be
expressed by allocating appropriate quantities of reserves to the probable and
possible classifications.
PROBABLE RESERVES
Probable reserves are those unproved reserves which analysis of geological and
engineering data suggests are more likely than not to be recoverable. In this
context, when probabilistic methods are used, there should be a least a 50%
probability that the quantities actually recovered will equal or exceed the sum
of estimated proved plus probable reserves.
In general, probable reserves may include (1) reserves anticipated to be proved
by normal step-out drilling where subsurface control is inadequate to classify
these reserves as proved, (2) reserves in formations that appear to be
productive based on well log characteristics but lack core data or definitive
tests and which are not analogous to producing or proved reservoirs in the area,
(3) incremental reserves attributable to infill drilling that could have been
classified as proved if closer statutory spacing had been approved at the time
of the estimate, (4) reserves attributable to improved recovery methods that
have been established by repeated commercially successful applications when (a)
a project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir characteristics appear favorable for commercial application, (5)
reserves in an area of the formation that appears to be separated from the
proved area by faulting and the geologic interpretation indicates the subject
area is structurally higher than the proved area, (6) reserves attributable to a
future workover, treatment, re-treatment, change of equipment, or other
mechanical procedures, where such procedure has not been proved successful in
wells which exhibit similar behavior in analogous reservoirs, and (7)
incremental reserves in proved reservoirs where an alternative interpretation of
performance or volumetric data indicates more reserves than can be classified as
proved.
POSSIBLE RESERVES
Possible reserves are those unproved reserves which analysis of geological and
engineering data suggests are less likely to be recoverable than probable
reserves. In this context, when probabilistic methods are used, there should be
a least a 10% probability that the quantities actually recovered will equal or
exceed the sum of estimated proved plus probable plus possible reserves.
In general, possible reserves may include (1) reserves which, based on
geological interpretations, could possibly exist beyond areas classified as
probable, (2) reserves in formations that appear to be petroleum bearing based
on log and core analysis but may not be productive at commercial rates, (3)
incremental reserves attributed to infill drilling that are subject to technical
uncertainty, (4) reserves attributed to improved recovery methods when (a) a
project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir
<PAGE> 354
characteristics are such that a reasonable doubt exists that the project will be
commercial, and (5) reserves in an area of the formation that appears to be
separated from the proved area by faulting and geological interpretation
indicates the subject area is structurally lower than the proved area.
RESERVE STATUS CATEGORIES
Reserve status categories define the development and producing status of wells
and reservoirs.
DEVELOPED: Developed reserves are expected to be recovered from existing
wells including reserves behind pipe. Improved recovery reserves are
considered developed only after the necessary equipment has been installed,
or when the costs to do so are relatively minor. Developed reserves may be
sub-categorized as producing or non-producing.
PRODUCING: Reserves subcategorized as producing are expected to be
recovered from completion intervals which are open and producing at the
time of the estimate. Improved recovery reserves are considered
producing only after the improved recovery project is in operation.
NON-PRODUCING. Reserves subcategorized as non-producing include shut-in
and behind-pipe reserves. Shut-in reserves are expected to be recovered
from (1) completion intervals which are open at the time of the
estimate but which have not started producing, (2) wells which were
shut-in for market conditions or pipeline connections (3) wells not
capable of production for mechanical reasons. Behind-pipe reserves are
expected to be recovered from zones in existing wells, which will
require additional completion work or future recompletion prior to the
start of production.
UNDEVELOPED RESERVES: Undeveloped reserves are expected to be recovered:
(1) from new wells on undrilled acreage, (2) from deepening existing wells
to a different reservoir, or (3) where a relatively large expenditure is
required to (a) recomplete an existing well or (b) install production or
transportation facilities for primary or improved recovery projects.
<PAGE> 355
ATTACHMENT B
APRIL 17, 1998
SWIFT ENERGY COMPANY
16825 Northchase Drive
Suite 400
Houston, Texas 77060
RE: FAIR MARKET VALUE OPINION
AS OF DECEMBER 31, 1997
SWIFT ENERGY PENSION PARTNERS
1993-B, LTD.
ATTENTION: SPECIAL TRANSACTIONS COMMITTEE
SWIFT ENERGY COMPANY BOARD OF DIRECTORS
At the request of SWIFT ENERGY COMPANY (SWIFT), J. R. BUTLER AND COMPANY
(JRBCO) has conducted an evaluation audit of the hydrocarbon reserves and
future net cash flow as of December 31, 1997, associated with 44 Acquisition
Programs located in the U.S.A. From this audit, and in consultation with H. J.
Gruy and Associates, Inc. (Gruy), JRBCO has generated its opinion of a "fair
market value" for these properties. The market values of the properties were
distributed to various partnerships based on ownership to determine the fair
market value of each partnership. In JRBCO'S opinion, utilizing the
distribution of properties into the proper partnerships, the estimated market
value of SWIFT ENERGY PENSION PARTNERS 1993-B, LTD. is $1,234,678.
Proved reserves in this instance are defined as those estimated volumes of
crude oil, condensate, natural gas, and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty to be commercially
recoverable in the future from known reservoirs under a reasonable price and
cost escalation scenario. Probable reserves are the estimated quantities of
commercially recoverable hydrocarbons associated with known accumulations which
are based on engineering and geological data similar to those used in the
estimates of proved reserves but, for various reasons, these data lack the
certainty required to classify the reserves as proved. Possible reserves are
the estimated quantities of commercially recoverable hydrocarbons associated
with known accumulations, which are based on engineering and geological data
which are less complete and less conclusive than the data used in estimates of
probable reserves. In some cases, economic or regulatory uncertainties may
dictate a probable or possible classification.
Recovery of proved reserves is not without risk but, as generally considered in
the industry, the risk of recovering probable reserves is substantially greater
than that associated with proved categories. Likewise, possible reserves are
less certain to be recovered than probable.
The reserves and future performance estimates were prepared utilizing standard
petroleum engineering methods. For properties with sufficient production
history,
1
<PAGE> 356
reserves estimates and rate projections were based primarily on extrapolation
of established performance trends and reconciled, whenever possible, with
volumetric and/or material balance calculations. For the non-producing zones
and undeveloped locations, reserves were determined by a combination of
volumetric calculations and analogy. Volumetrically determined reserves or
those determined by analogy are generally subject to greater qualifications
than reserves estimates supported by established production decline curves
and/or material balance calculations. Determination and classification of
proved reserves were performed (with exception of the use of escalated prices
and costs) in accordance with Securities and Exchange Commission guidelines.
The definitions used also conform to those promulgated by the Society of
Petroleum Engineers (SPE) and the World Petroleum Congresses (WPC).
The reserves and resulting "value estimates" included in this study are not
exact quantities. Future conditions may affect the recovery of estimated
reserves, revenue and net cash flow, and all categories of reserves may be
subject to revision and/or reclassification as more performance and well data
become available. Please note, the reserves estimates made by JRBCO were done
in conjuction with an evaluation audit and are not the result of in-depth field
studies. In conducting this audit JRBCO reviewed approximately 65% of SWIFT'S
proved "PV 10 value" (SEC PV10 as of December 31, 1997) for the total 44
Acquisition Programs.
Basic evaluation data were obtained principally from SWIFT and public sources.
The production data available to JRBCO were generally through August 1997.
Gas and liquid prices were year end (CY 1997) prices as used in SWIFT'S
December 31, 1997, SEC cash flow runs.
Estimates of drilling, completion and workover costs were based on information
supplied by SWIFT. Operating costs were also based on data supplied by SWIFT
in their Lease Operating Statement which was reviewed by JRBCO. Surface and
well equipment salvage values and well plugging and field abandonment costs
were not considered in the revenue projections.
The estimates of future net cash flow used in market value calculations are
those revenues which should be realized from the sale of the estimated reserves
after deduction of royalties, ad valorem and production taxes, direct operating
costs and required capital expenditures, when applicable. Future net cash flow
as used in this evaluation is before the deduction of federal income tax.
Market value estimates were obtained by applying qualitative risk adjustments
considered appropriate for the various reserves categories and "profit factors"
(as applicable) against discounted future net cash flow values obtained from an
escalated cost and pricing scenario. Prices, costs and investments were
escalated at 3.5%/year for 15 years. Final market value estimates were derived
in conjunction and consultation with Gruy.
In the conduct of our review, we have not independently verified the accuracy
and completeness of information and data furnished by SWIFT with respect to
ownership interests, oil and gas production volumes and rates, historical costs
of operation and development, product prices, agreements relating to current
and future operations and sales of production and other information relative to
such things as timing or scheduling of drilling or recompletion operations.
Field inspections were not made in connection with the preparation of this
report. Furthermore, no judgments were made relative to environmental or other
legal liabilities.
It should be recognized that any oil or gas reserves estimate or forecast of
production and income is a function of engineering and geological
interpretation and judgment. Such estimates should, therefore, be accepted and
used with the understanding that technical data, economic criteria or
regulatory information obtained subsequent to a study may justify revisions
which could increase or decrease the original estimates of reserves and value.
Neither JRBCO, nor any of its personnel, have any direct or indirect interest
in SWIFT or its affiliates. JRBCO is an independent consulting firm as
provided in the Standards Pertaining to the Estimating and Auditing of Oil and
Gas Reserves Information promulgated by the Society of Petroleum Engineers.
2
<PAGE> 357
JRBCO'S compensation is not contingent upon the results of its reserves
estimates, cash flow analyses or "market value opinion" which result from its
review of the subject properties.
READ AND APPROVED:
/s/ BRIAN E. AUSBURN
- ----------------------------------------
BRIAN E. AUSBURN, PRESIDENT
DATE: April 17, 1998
-----------------------------------
BEA:mlc
3
<PAGE> 358
ATTACHMENT C
April 20, 1998
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, TX 77060
Attention: Special Transactions Committee
Swift Energy Company Board of Directors
Gentlemen:
Pursuant to that certain letter agreement dated February 27, 1998 (the
"Agreement") between the Special Transactions Committee (the "Committee") of the
Board of Directors of Swift Energy Company ("Swift" or the "Company") and CIBC
Oppenheimer Corp. ("CIBC Oppenheimer"), you have retained CIBC Oppenheimer to
prepare an independent financial analysis as to the estimated fair market value
(the "CIBC Oppenheimer Valuation") of various interests (the "Assets") in oil
and gas properties (the "Properties'), which Assets are owned by Swift Energy
Pension Partners 1993-B Ltd. (the "Partnership") of which the Company is the
managing general partner ("General Partner"). CIBC Oppenheimer performed a
similar analysis for 62 other partnerships (the "Partnerships") of which the
Company is the General Partner. It is CIBC Oppenheimer's understanding that the
General Partner has proposed to purchase substantially all of the Partnership's
Assets and, in turn, dissolve and wind up the Partnership. It is also CIBC
Oppenheimer's understanding that the Committee has also retained the reserve
engineering firms of H.J. Gruy & Associates, Inc. and J.R. Butler & Company
(collectively, the "Engineering Consultants") to prepare a separate analysis as
to the estimated fair market value of the Assets (the "Engineering Consultants'
Valuation").
In arriving at the CIBC Oppenheimer Valuation, we, among other things:
(i) Reviewed the historical financial returns to the limited
partners of the Partnership;
(ii) Held discussions with senior management of the Company as to
the Partnership's operational and financial prospects;
<PAGE> 359
Swift Energy Company
April 20, 1998
Page 2
(iii) Held discussions with senior management of the Company
regarding the general characteristics of the Properties
underlying the Assets, including location, productive
geological formations, future development potential and oil
and gas marketing arrangements;
(iv) Held discussions with the Engineering Consultants regarding
the general characteristics of the Properties underlying the
Assets, including location, productive geological formations
and future development potential;
(v) Reviewed the reserve engineering reports supplied to us by the
Engineering Consultants and, particularly, reviewed the
estimated future net cash flow to be generated from the
production of proved reserves of the Properties underlying the
Assets discounted to present value using an annual discount
rate of 10% (the "PV-10 Value") dated as of December 31, 1997;
these amounts were calculated net of estimated production
costs and future development costs, using prices and costs in
effect as of a certain date, without escalation and without
giving effect to non-property related expenses such as future
income tax expense or depreciation, depletion and
amortization;
(vi) Reviewed the Engineering Consultants' Valuation of the
Properties underlying the Assets;
(vii) Reviewed historical operating and financial results of the
Properties underlying the Assets which included PV-10 Value,
proved reserves on a barrel of oil equivalent ("BOE") basis
and projected earnings before interest, taxes and
depreciation, depletion and amortization ("EBITDA") as
prepared by the Engineering Consultants and discussed with
senior management of the Company;
(viii) Reviewed and analyzed financial terms of similar transactions
in which public oil and gas companies liquidated partnerships
of which they were the general partner;
(ix) Reviewed and analyzed transactions involving the sale of oil
and gas companies we deemed comparable to the Partnership(s)
individually and collectively and to the Company;
<PAGE> 360
Swift Energy Company
April 20, 1998
Page 3
(x) Reviewed and analyzed transactions involving the sale of oil
and gas properties we deemed comparable to the Properties
underlying the Assets;
(xi) Reviewed financial and market data for certain public
companies we deemed comparable to the Partnership(s)
individually and collectively and to the Company; and
(xii) Performed such other analyses and reviewed such other
information as we deemed appropriate.
In determining the CIBC Oppenheimer Valuation, we have relied upon and assumed,
without independent verification or investigation and at the direction of the
Committee, (i) the accuracy and completeness of all of the financial and other
information available to us from public sources or provided to us by the Company
and their representatives (including the Engineering Consultants), (ii) that the
reserve engineering reports supplied to us by the Engineering Consultants as
described in clause (v) above have been reasonably prepared and are based on
their best business judgment, (iii) that the information with respect to the
Partnership's ownership of the Assets, as provided to the Engineering
Consultants and to us was accurate in all respects, (iv) with respect to the
historical operating and financial results and projections provided to us as
described in clause and (vii) above, that such information and projections were
reasonably prepared and were based on the best currently available information,
estimates and good faith judgment of the Company's management and their
representatives (including the Engineering Consultants).
Not being experts in the geological evaluation of oil and gas reserves, we have,
with your consent, relied without independent verification upon the audit of the
reserve estimates prepared by the Engineering Consultants for the purpose of
estimating fair market value of the Assets. In addition, we have not made a
physical inspection of the Properties underlying the Assets, nor have we made
any independent evaluations, appraisals or inspections of the Company's or the
Partnership's other assets or the Company's or the Partnership's liabilities
(contingent or otherwise). We have not reviewed any relevant agreements which
may exist between the General Partner and the limited partners governing the
Partnership, nor have we considered the effect which the ownership structure of
the Partnership and the terms of the agreements of the Partnership may have upon
the fairness of the consideration offered by any general partner of the
Partnership. We have not reviewed the books and records of the Partnership and
have assumed, with your consent, that the Partnership's ownership interests in
the Properties underlying the Assets, as provided to us by you, is true and
correct.
<PAGE> 361
Swift Energy Company
April 20, 1998
Page 4
The CIBC Oppenheimer Valuation is based upon analyses of the foregoing factors
in light of our assessment of general economic, financial, market and other
conditions and circumstances as of the date of this letter and any changes in
such conditions and circumstances may affect the validity or fairness of the
CIBC Oppenheimer Valuation. CIBC Oppenheimer disclaims any obligations to
update, revise or reaffirm the CIBC Oppenheimer Valuation. The CIBC Oppenheimer
Valuation reflects our estimate of the consideration that could have been
received by the Partnership in a sale of the Assets in an orderly manner in a
private market transaction in which neither buyer nor seller is under any
compunction to complete such transaction. The CIBC Oppenheimer Valuation falls
within a range of values which we believe, subject to the foregoing conditions,
represent possible fair market value estimates of the Partnership's interest in
the Assets. The CIBC Oppenheimer Valuation should not be viewed as a guarantee
of the price that a willing buyer might have paid for the Assets.
CIBC Oppenheimer, as part of its investment banking services, is regularly
engaged in the valuation of businesses and securities in connection with
mergers, acquisitions, underwritings, sales and distributions of listed and
unlisted securities and private placements. CIBC Oppenheimer has provided
certain investment banking and financial advisory services to the Company from
time to time, including acting as co-manager of the Company's Convertible
Subordinated Notes financing in November 1996 and lead manager of the public
offering of the Company's Common Stock in July 1995, and may be involved in
future investment banking activities on behalf of the Company. CIBC Oppenheimer
will also receive a fee upon delivery of this CIBC Oppenheimer Valuation. In the
ordinary course of business, CIBC Oppenheimer actively trades in the equity
securities of the Company for CIBC Oppenheimer's own account and for the
accounts of CIBC Oppenheimer's customers and, accordingly, may at any time hold
a long or short position in such securities.
Based upon and subject to the foregoing, and based upon such other matters as we
consider relevant, it is CIBC Oppenheimer's estimate that the value of Swift
Energy Pension Partners 1993-B Ltd. interest in the Assets as of the date hereof
is $1,327,783.
This letter is being provided for the use of the Committee in its evaluation of
a possible proposal that the Partnership sell the Assets to the Managing General
Partner and dissolve and wind up its affairs. This letter is not intended to
confer rights or remedies upon any stockholder of the Company or any partner of
the Partnership and may not be relied upon by any person or entity other than
the Committee. Neither this letter nor the CIBC Oppenheimer Valuation may be
published or otherwise used or referred to, in whole or
<PAGE> 362
Swift Energy Company
April 20, 1998
Page 5
part, nor shall any public reference to CIBC Oppenheimer, this letter or the
CIBC Oppenheimer Valuation be made without the prior written consent of CIBC
Oppenheimer; provided, however, that the Company and the Partnership may include
a copy of this letter and a reference to CIBC Oppenheimer in the proxy statement
to be distributed to limited partners of the Partnership in connection with the
solicitation of the approval of the proposal that the Partnership sell the
Assets to the General Partner and dissolve and wind up its affairs. Neither this
letter nor the CIBC Oppenheimer Valuation constitutes a recommendation to any
partner of the Partnership as to how such partner should vote on or respond to
the proposal that the Partnership sell the Assets to the General Partner and
dissolve and wind up its affairs.
Sincerely yours,
/s/ BRIAN MYERS
CIBC Oppenheimer Corp.
<PAGE> 363
ATTACHMENT D
February 10, 1998
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
SWIFT ENERGY PENSION PARTNERS 1993-B
97-003-133
Gentlemen:
At your request, we have made an audit of the reserves and future net cash flow
as of December 31, 1997, prepared by Swift Energy Company ("Swift") for certain
interests in Swift Energy Pension Partners 1993-B. This audit has been conducted
according to the standards pertaining to the estimating and auditing of oil and
gas reserve information approved by the Board of Directors of the Society of
Petroleum Engineers on October 30, 1979. We have reviewed these properties and
where we disagreed with the Swift reserve estimates, Swift revised its estimates
to be in agreement. The estimated net reserves, future net cash flow and
discounted future net cash flow are summarized by reserve category in Table 1
for both the 100% Fund Level Partnership and the Limited Partnership Interest.
The discounted future net cash flow is not represented to be the fair market
value of these reserves and the estimated reserves included in this report have
not been adjusted for risk.
The estimated future net cash flow shown is that cash flow which will be
realized from the sale of the estimated net reserves after deduction of
royalties, ad valorem and production taxes, direct operating costs and required
capital expenditures, when applicable. Surface and well equipment salvage values
and well plugging and field abandonment costs have not been considered in the
cash flow projections. Future net cash flow as stated in this report is before
the deduction of state and federal income tax.
In the economic projections, prices, operating costs and development costs
remain constant for the projected life of each lease.
The reserves included in this study are estimates only and should not be
construed as exact quantities. Future conditions may affect recovery of
estimated reserves and cash flow, and all categories of reserves may be subject
to revision as more performance data become available. Proved reserves are
estimated in accordance with the definitions contained in Securities and
Exchange Commission Regulation S-X, Rule 4-10(a). The definitions are included
in part as Attachment I.
Extent and character of ownership, oil and gas prices, production data, direct
operating costs, capital expenditure estimates and other data provided by Swift
have been accepted as represented. The production data available to us were
through the month of October 1997, except in those instances in which data were
available through December. Interim production to December 31, 1997, has been
estimated. No independent well tests, property inspections or audits of
operating expenses were conducted by our staff in conjunction with this study.
We did not verify or determine the extent, character, obligations, status or
liabilities, if any, arising from any current or possible future environmental
liabilities that might be applicable.
<PAGE> 364
Swift Energy Company -2- February 10, 1998
In order to audit the reserves, costs and future net cash flows shown in this
report, we have relied in part on geological, engineering and economic data
furnished by our client. Although we have made a best efforts attempt to acquire
all pertinent data and to analyze it carefully with methods accepted by the
petroleum industry, there is no guarantee that the volumes of oil or gas or the
cash flows projected will be realized.
Production rates may be subject to regulation and contract provisions, and may
fluctuate according to market demand or other factors beyond the control of the
operator. The reserve and cash flow projections presented in this report may
require revision as additional data become available.
We are unrelated to Swift and we have no interest in the properties included in
the information reviewed by us. In particular:
1. We do not own a financial interest in Swift or its oil and gas
properties.
2. Our fee is not contingent on the outcome of our work or report.
3. We have not performed other services for or have any other
relationship with Swift that would affect our independence.
If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such person with the approval of our
client is invited to visit our offices at his expense so that he can evaluate
the assumptions made and the completeness and extent of the data available on
which our estimates are based.
Any distribution or publication of this report or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
/s/ JAMES H. HARTSOCK
James H. Hartsock, Ph.D., P.E.
Executive Vice President
<PAGE> 365
TABLE 1
100% FUND LEVEL PARTNERSHIP INTEREST
<TABLE>
<CAPTION>
Estimated Estimated
Net Reserves Future Net Cash Flow
----------------------- ----------------------------
Oil & Discounted
Condensate at 10%
(Barrels) Gas (Mcf) Nondiscounted Per Year
---------- --------- ------------- -----------
<S> <C> <C> <C> <C>
Proved Developed 86,068 767,586 $ 2,009,694 $ 1,379,900
Proved Undeveloped 47,447 388,334 $ 1,154,759 $ 668,782
------- --------- ----------- -----------
Total Proved 133,515 1,155,920 $ 3,164,453 $ 2,048,682
G&A $ (398,720) $ (259,119)
------- --------- ----------- -----------
Total 133,515 1,155,920 $ 2,765,733 $ 1,789,563
</TABLE>
LIMITED PARTNERSHIP INTEREST
<TABLE>
<CAPTION>
Estimated Estimated
Net Reserves Future Net Cash Flow
-------------------------- --------------------------
Oil & Discounted
Condensate at 10%
(Barrels) Gas (Mcf) Nondiscounted Per Year
---------- --------- ------------- ----------
<S> <C> <C> <C> <C>
Proved Developed 73,158 652,444 $1,708,233 $1,172,915
Proved Undeveloped 40,330 330,084 $ 981,546 $ 568,465
------- ------- ---------- ----------
Total Proved 113,488 982,528 $2,689,779 $1,741,380
G&A $ (338,912) $ (220,251)
------- ------- ---------- ----------
Total 113,488 982,528 $2,350,867 $1,521,129
</TABLE>
PEN93-B.TBL
H.J. GRUY AND ASSOCIATES, INC. 1200 Smith Street, Suite 3040,
Houston, Texas 77002 (713) 739-1000
<PAGE> 366
ATTACHMENT I
DEFINITIONS OF PROVED OIL AND GAS RESERVES(1)
PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquid which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
PROVED DEVELOPED OIL AND GAS RESERVES
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be 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.
PROVED UNDEVELOPED RESERVES
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
- --------
(1) Contained in Securities and Exchange Commission Regulation S-X,
Rule 4-10(a)
H.J. GRUY AND ASSOCIATES, INC. 1200 Smith Street, Suite 3040,
Houston, Texas 77002 (713) 739-1000
<PAGE> 367
FORM OF PROXY
SWIFT ENERGY PENSION PARTNERS 1993-B, LTD.
THIS PROXY IS SOLICITED BY THE MANAGING GENERAL PARTNER FOR A
SPECIAL MEETING OF INTEREST HOLDERS TO BE HELD ON __________, 1998
The undersigned hereby constitutes and appoints A. Earl Swift, Bruce
H. Vincent, Terry E. Swift or John R. Alden, duly authorized officers of Swift
Energy Company acting in its capacity as Managing General Partner of the
Partnership, or any of them, as Proxies, each with full power to appoint his
substitute, and hereby authorizes the Proxies or any of them to represent the
undersigned at a Special Meeting of the Interest Holders (the "Meeting") of
SWIFT ENERGY PENSION PARTNERS 1993-B, LTD. (the "Partnership") to be held on
__________, 1998 at 4:00 p.m. Houston time, at 16825 Northchase Drive, Houston,
Texas, and any adjournments thereof, and to vote as designated, on the matter
specified below, the Partnership SDIs standing in the name of the undersigned
on the books of the Partnership (or which the undersigned may be entitled to
vote) on the record date for the Meeting, and hereby revokes any proxy or
proxies heretofore given by the undersigned.
<TABLE>
<S> <C> <C> <C>
1. The adoption of a proposal FOR AGAINST ABSTAIN
("Proposal") for the ultimate sale [ ] [ ] [ ]
of substantially all of the assets
of the Partnership to the Managing
General Partner and the dissolution,
winding up and termination of the
Partnership. The undersigned hereby
directs said proxies to vote:
</TABLE>
2. In their discretion, the proxies are authorized to vote upon such other
matters as may properly come before the meeting or any adjournments or
postponements thereof.
THIS PROXY WHEN PROPERLY EXECUTED, WILL BE VOTED IN ACCORDANCE WITH
THE DIRECTIONS MADE HEREON. IF NO DIRECTION IS MADE, IT WILL BE VOTED FOR THE
PROPOSAL.
Receipt of the Partnership's Notice of Special Meeting of Interest
Holders and Proxy Statement dated __________, 1998 is acknowledged.
PLEASE SIGN EXACTLY AS NAME APPEARS BELOW AND RETURN THE PROXY IN THE
ENCLOSED, POSTAGE-PAID, PRE-ADDRESSED ENVELOPE BY _________, 1998.
SIGNATURE DATE
---------------------------- -------------------
SIGNATURE DATE
---------------------------- -------------------
SIGNATURE DATE
---------------------------- -------------------
IF INTEREST HOLDER SDIS ARE HELD JOINTLY, ALL JOINT TENANTS MUST SIGN.
WHEN SIGNING AS ATTORNEY, EXECUTOR, ADMINISTRATOR, TRUSTEE OR GUARDIAN, PLEASE
GIVE FULL TITLE AS SUCH. IF A CORPORATION, PLEASE SIGN IN FULL CORPORATE NAME
BY PRESIDENT OR OTHER AUTHORIZED OFFICER. IF A PARTNERSHIP, PLEASE SIGN IN
PARTNERSHIP NAME BY AUTHORIZED PERSON.
<PAGE> 368
[REPRESENTS INITIAL FILING WITH SEC]
SWIFT ENERGY INCOME PARTNERS 1986-D, LTD.
(THE "PARTNERSHIP")
SUPPLEMENT
TO
JOINT PROXY STATEMENT/PROSPECTUS
DATED ________, 1998
SPECIAL MEETINGS OF THE PARTNERSHIPS
AND
OFFERING OF COMMON STOCK OF
SWIFT ENERGY COMPANY
For the definition of capitalized terms herein which are not otherwise
defined, see "Glossary" in the Joint Proxy Statement/Prospectus. Other
discussions which are cross-referenced in this Supplement are contained in the
Joint Proxy Statement/Prospectus, unless otherwise noted.
Swift Energy Company ("Swift" or the "Company") is the Managing
General Partner ("Managing General Partner") of 63 Texas limited partnerships
(the "Partnerships"), including the Partnership, formed between 1986 and 1994
to invest in producing oil and gas properties. Swift is asking limited
partners (referred to herein as "Investors") in the Partnership (and similarly
in the other 62 Partnerships) to approve a Proposal to sell all of the
Partnership's oil and gas assets to the Managing General Partner (the
"Proposal") for $1,684,539, which is a purchase price derived by choosing the
higher of two estimates of fair market value of those assets determined by
three independent Appraisers, and adding to that higher number a 7.5% premium.
If the Proposal is approved by Investors in the Partnership, after the
sale of all of its oil and gas assets the Partnership will dissolve, wind up
and terminate. The Partnership will receive cash for its oil and gas assets,
which in turn is to be distributed to the Investors in the Partnership (along
with the net of all assets less liabilities of the Partnership) in accordance
with their respective percentage ownership interests in the Partnership. If
Investors in the Partnership approve the Proposal, then each Investor can
elect, in their sole individual discretion, to receive shares of Common Stock
of the Company (without payment of any brokerage commissions) instead of some
or all of the cash which they are entitled to receive upon the Partnership's
liquidation.
The reasons for and effects of the Proposals may be different for
investors in each of the Partnerships. This Supplement has been prepared to
highlight for the Investors in the Partnership the particular risks, effects
and fairness of the Proposal to the Investors in the Partnership and to provide
information on the Partnership to its Investors, in connection with the
solicitation of proxies by the
<PAGE> 369
Managing General Partner for use at the Special Meeting of the Investors in the
Partnership in voting upon the Proposal and to transact such other business as
may be properly presented at the Special Meeting or any adjournments or
postponements thereof.
BOTH THE VOTE UPON THE PROPOSAL AND ANY ELECTION MADE BY AN INDIVIDUAL
INVESTOR TO RECEIVE SHARES OF SWIFT ENERGY COMPANY COMMON STOCK ARE SUBJECT TO
NUMEROUS RISK FACTORS, INCLUDING THOSE HIGHLIGHTED BELOW. SEE "RISK FACTORS"
IN THIS SUPPLEMENT AND IN THE JOINT PROXY STATEMENT/PROSPECTUS FOR A FULL
DISCUSSION OF ALL RISK FACTORS.
o Substantial conflicts of interest exist because if the Proposal is
approved by the Partnership, the Managing General Partner will
purchase all of the oil and gas assets from the Partnership while it
serves as its Managing General Partner.
o The purchase price for the Partnership's Property Interests may not be
the highest possible price.
o No independent representative negotiated the terms of the purchase
price with the Managing General Partner.
o No fairness opinion was acquired regarding the fairness of the
purchase price.
o The Managing General Partner may profit from acquisition of the
Partnership's oil and gas assets by investing capital in order to
develop non-producing reserves of the acquired Property Interests and
possibly through improvement in oil and gas prices.
o Estimates of distributions to Investors from continuing operations of
the Partnership for the life of its reserves are higher than amounts
anticipated to be received if Investors vote in favor of the Proposal.
See "Special Factors--Fairness of Proposal of Sale of Assets as
Compared to Continuing Operations."
o An election by an Investor to receive shares of Swift Common Stock in
lieu of cash distributable to Investors subjects such Investors to the
risks of investing in the Company.
This Supplement is dated ______________, 1998
2
<PAGE> 370
THE PARTNERSHIP
The Partnership was formed over eleven years ago and owns working
interests in producing oil and gas properties in two states. The Partnership
had expended all of its original capital contributions by the end of December
1987. The Partnership's oil and gas properties are principally natural gas
properties, representing approximately 78% of the Partnership's 1997 production
and approximately 81% of its total proved reserves at December 31, 1997. From
time to time, the Partnership has performed workovers and recompletions on
wells in which the Partnership has working interests, using funds advanced by
the Managing General Partner or third parties, to perform these operations,
which amounts have been subsequently repaid. The Partnership owns interest in
128 wells in six fields.
The following table presents information on those fields in which the
Partnership has Property Interests which constitute 10% or more of the
Partnership's PV-10 Value at December 31, 1997. The Partnership's "PV-10
Value" is the estimated future net cash flows (using unescalated prices) from
production of proved reserves attributed to the Partnership's Property
Interests, discounted to present value at 10% per annum. Attachment D to this
Supplement is the report dated February 10, 1998 of the audit by H.J. Gruy and
Associates, Inc., Independent Petroleum Consultants, of the oil and gas
reserves underlying the Partnership's Property Interests, and future net cash
flow expected from the production of those reserves as of December 31, 1997,
presented both for the Partnership as a whole and as to those reserves solely
attributable to the Investors in the Partnership. This report has not been
updated to include the effect of production since year-end 1997. In estimating
these reserves, the Managing General Partner, in accordance with criteria
prescribed by the Securities and Exchange Commission, has used year-end 1997
prices, without escalation, except in those instances where fixed and
determinable gas price escalations are covered by contracts, limited to the
price the Partnership reasonably expects to receive. The Managing General
Partner is not aware of any favorable or adverse event causing a significant
change in the estimated amount (as set forth in Attachment D hereto, which is
the report of H.J. Gruy and Associates, Inc.) of proved reserves of the
properties in which the Partnership owns an interest has occurred between
December 31, 1997 and the date of this Supplement.
The information below includes the location of each field in which the
Partnership has an interest, the number of wells and operators, together with
information on the percentage of the Partnership's total PV-10 Value on
December 31, 1997 attributable to each of these fields. Information is also
provided regarding the percentage of the Partnership's 1997 production (on a
volumetric basis) from each of these fields. Of the remaining other fields in
which the Partnership owns a Property Interest, two of such fields each
comprise less than 1% of the Partnership's PV-10 Value at December 31, 1997,
and the PV-10 Value of each of the other two fields averages less than 8% of
the Partnership's PV- 10 Value at the same date.
3
<PAGE> 371
<TABLE>
<CAPTION>
4
GIDDINGS AWP OTHER
FIELD FIELD FIELDS
-----------------------------------------
<S> <C> <C> <C>
County and State Fayette McMullen OK (3)
County, County, TX (1)
Texas Texas
Number of Wells 19 66 43
Operator(s) Swift; Swift Swift and
Petrocorp; 3 others
Geosouthern;
Clayton Williams
% of 12/31/97 PV-10 Value 60% 22% 18%
% of 1997 Production Volumes 39% 26% 35%
</TABLE>
The Partnership's total assets at year-end 1997 were $2,519,671 and
the PV-10 Value of its total proved reserves at the same date was $2,327,010.
Based upon the audit of the Partnership's Total Proved Reserves at year-end
1997, those reserves were comprised of the following three categories:
Proved Producing(1) 34%
Behind-Pipe(2) 49%
Non-Developed(3) 17%
---
100%
===
_________________
(1) Proved producing reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
(2) Behind-pipe reserves are proved reserves that will not contribute
to cash flows until recompletion projects have been implemented to place them
into production. The impact of these recompletion projects will also be limited
until the costs of implementation have been recovered. In general, it is not
appropriate to bring behind-pipe reserves into production until the formation
that is currently producing has been depleted. Premature recompletions can lead
to permanent reductions in a well's proved reserves.
(3) Non-developed reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Therefore,
significant additional expenditures are usually required before undeveloped
reserves can be produced.
Attachment Dis the annual reserves audit and independent reserves
report prepared by H.J. Gruy and Associates, Inc. as to the Partnership's
remaining proved oil and gas reserves available for production over a period in
excess of 15 years. These quantities have been given a value based upon prices
for oil and gas at December 31, 1997. The value is determined based upon the
assumption that these prices will remain in effect over the life of these
reserves. This value is then discounted at 10% per year to arrive at the value
(in today's dollars) of these revenues ("PV-10 Value"). This PV-10 Value for
the Partnership's Property Interests is $2,327,010. It is also estimated that
$366,621 in future capital costs must be spent to develop the Partnership's
non-producing reserves.
4
<PAGE> 372
RISK FACTORS
o Although the fair market value of the Property Interests proposed to
be purchased from the Partnership by the Managing General Partner was
based upon a determination by three independent Appraisers, no opinion
was acquired as to the fairness of the ultimate purchase price, which
was determined in the Managing General Partner's sole judgment by
adding a 7.5% premium over the higher of the two fair market value
estimates for the Partnership's Property Interests determined by the
Appraisers. Therefore, the purchase price was not determined on an
impartial basis by a party not involved in the transaction, and
another party intent upon purchasing the Property Interests in the
Partnership might have offered a different purchase price. There is
no guarantee that the purchase price represents the highest possible
price that could be received for the Partnership's Property Interests
in all circumstances. It is possible that a higher (or lower) price
might be received if these assets were sold on another basis, such as
at auction or in negotiated sales. Furthermore, the assessment of the
value of the Partnership's proved non-producing reserves could vary
widely, given the typical discounting in valuing non-producing
reserves.
o The Managing General Partner did not retain an independent
representative to act on behalf of the Investors in the Partnership in
structuring and negotiating the terms or price of the Proposal or the
purchase price. The price at which it is proposed that the Company
purchase the Property Interests from the Partnership has not been
negotiated at arm's length and is subject to significant conflicts of
interest between the Company acting as the purchaser of such
properties while serving as the Managing General Partner of the
Partnership. If an independent representative had been retained for
the Partnership, the terms or price might have been different and
possibly more favorable to Investors.
o The fair market value (excluding the 7.5% premium) established for the
Partnership's Property Interests is based upon the Appraisers'
evaluation of that value. Year-end 1997 prices, along with other
current market factors, were used as a starting point for the
Appraisers' analysis, and prices and costs were then escalated at a
rate of 3.5% per year over 15 years. Substantial increases in the
prices for oil and gas in the future might result in Investors
receiving higher distributions from continued operations of the
Partnership, although the effect of any higher prices is somewhat
limited because the Partnership has already produced a substantial
majority of its oil and gas reserves.
o A majority of the Partnership's proved oil and gas reserves are
non-producing. Because non-producing reserves are traditionally
discounted due to future costs which must be incurred to recover those
reserves and the risk that any drilling will be unsuccessful, there is
a risk that the discount applied to the non-producing reserves by the
Petroleum Engineering Consultants could be greater than the discount
applied by a third party purchaser. Likewise, it is likely that any
drilling conducted on Property Interests acquired from the Partnership
has upside potential, the benefit of which will go to the Managing
General Partner if it acquires those properties.
o Investors that are subject to federal income tax on an investment in
the Partnership are required to recognize gain or loss on the sale of
oil and gas assets by the Partnership and the subsequent liquidation
of the Partnership. The amount and character of the gain or loss
depends on certain factors specific to individual Investors. It is
anticipated that Investors that acquired their interests
5
<PAGE> 373
in the original offering will recognize a gain for federal income tax
purposes. Any tax that may be due must be paid even if such Investors
choose to acquire Company Common Stock with some or all of their
proceeds from property sales. Investors also should consult their
individual tax advisors to determine whether they are subject to any
state tax. For a broader discussion of the tax consequences,
Investors should read "Federal Income Tax Consequences of Adoption of
the Proposals" in the Joint Proxy Statement/Prospectus and "Summary of
Federal Income Tax Consequences" in this Supplement.
o Investors that are Tax Exempt Plans will be subject to taxation on the
Partnership's sale of property and the liquidation of the Partnership,
while other Tax Exempt Plans are not expected to be subject to
taxation on the sale and liquidation. See "Summary of Federal Income
Tax Consequences--Tax Treatment of Tax Exempt Plans--Debt-Financed
Property" in this Supplement.
o As currently proposed, Investors that subscribe for Company Common
Stock pursuant to this Offering may not receive some or all of the
cash which otherwise would be distributed to them as part of the
liquidating distribution of their Partnership. The amount of any cash
liquidating distribution they actually receive depends upon the
purchase price to be paid for any Company Common Stock they elect to
and are entitled to receive pursuant to the terms of this Offering.
For federal income tax purposes, Investors subscribing for shares of
Company Common Stock will be treated as though they had purchased
those shares for cash, even though they never had actual possession of
the cash used to acquire the shares. Additionally, the fact that such
Investors elect to acquire Company Common Stock rather than receive
cash in liquidation of their Partnership interests will not affect the
federal income tax consequences attending the liquidation of their
Partnership interests. Because the purchase of shares of Company
Common Stock will reduce the cash received by Investors upon the
Partnership's liquidation, to the extent that Investors owe federal
income tax as a result of the liquidation, they may not receive
sufficient cash to pay some or all of any tax they may owe on the
liquidation. Such Investors owing tax as a result of the liquidation
will have to pay such tax from sources other than any cash liquidating
distribution from the Partnership.
See "Risk Factors" in the Joint Proxy Statement/Prospectus.
CONFLICTS OF INTEREST
There are substantial conflicts of interest which exist by virtue of
the Managing General Partner acting in that capacity on behalf of the
Partnership while at the same time acting as the proposed purchaser of all of
the oil and gas assets of the Partnership. These conflicts of interest are
discussed below.
o The terms of the Proposal are established by the Company which is also
the Managing General Partner of the Partnership.
o Neither the Managing General Partner nor a majority of its independent
directors retained an independent representative to act on behalf of
the Partnership's Investors for the purposes of negotiating the terms
upon which any such sale to the Managing General Partner would be made
or for the preparation of a report concerning the fairness of the
entire transaction.
See "Summary--Conflicts of Interest" and "Conflicts of Interests" in the Joint
Proxy Statement/Prospectus.
6
<PAGE> 374
SPECIAL FACTORS
BACKGROUND AND PURPOSE OF THE PROPOSAL
A number of factors have led to the decision of the Company in its
capacity as Managing General Partner to solicit approval of the Proposal by
Investors in the Partnership. As contemplated when the Partnership was
organized, and given the expenditure of virtually all of the Partnership's
capital to purchase producing properties over ten years ago, the production
from Partnership oil and gas assets declined over time. It was always
anticipated that a time would arrive when the Managing General Partner would
propose that the business of the Partnership be concluded, its assets sold or
otherwise disposed of and the Partnership liquidated and dissolved. The
general improvement in the prices for natural gas over the last several years,
relative to such prices in the mid-1990's, make this an appropriate time,
especially in light of the age of the Partnership and the high percentage of
its reserves comprised of natural gas, to consider the Proposal to sell the
Partnership's Property Interests. The structure being proposed, which involves
the sale of the Partnership's oil and gas assets to the Managing General
Partner, is being submitted for approval by Investors in an attempt to realize
the highest value for those assets. For the reasons set out below, the
Managing General Partner believes that the Proposal is fair to Investors in the
Partnership, given that the purchase price for these assets has been determined
by taking the higher of two fair market value estimates by three independent
Appraisers and adding to it a 7.5% premium.
Approval of the Proposal will have the following effects:
1. The Managing General Partner will purchase all of the oil and gas
assets of the Partnership.
2. When the Partnership sells all of its oil and gas assets, it will be
required to liquidate and distribute its remaining assets (principally
the cash proceeds from the sale) to its partners (including the
general partners) in accordance with their respective ownership
interests in the Partnership.
3. Investors will be given the option of electing to receive shares of
Swift Common Stock, in amounts that they choose on an individual
basis, in lieu of some or all of the cash they would be entitled to
receive upon the Partnership's liquidation.
4. The Managing General Partner may spend capital to develop
non-producing reserves on properties which it acquires from the
Partnership, although the properties in which such investment will be
made have not yet been determined.
5. Investors in the Partnership will be taxed on the sale of the
Partnership's oil and gas assets, although such sale is expected to
result in a taxable gain to Investors that acquired their interests in
the original offering.
PROPOSED PURCHASE PRICE
As discussed in greater detail below, the Petroleum Engineering
Consultants estimated that the aggregate fair market value of the Partnership's
Property Interests as of December 31, 1997 is $1,567,013. CIBC Oppenheimer
estimated a fair market value of the same Property Interests at the same date
of $1,369,233. The Special Transactions Committee chose the higher of these
two determinations as the "Fair Market Value" for the purchase of these
interests and the Board of Directors of the Company determined
7
<PAGE> 375
to pay a 7.5% premium ($117,526) above the Fair Market Value to purchase the
Partnership's Property Interests, resulting in a purchase price of $1,684,539.
This compares to the total purchase price for all of the oil and gas assets of
all 63 Partnerships which are considering similar proposals of approximately
$81 million. The valuation estimates of the Appraisers are attached to this
Supplement and incorporated herein by reference as follows: Attachment A is
the fair market value estimate of H.J. Gruy and Associates, Inc., Attachment B
is the fair market value estimate of J.R. Butler and Company, and Attachment C
is the fair market value estimate of CIBC Oppenheimer Corp. The PV-10 Value
prepared on an annual basis by H.J. Gruy of the same Property Interests as of
the same date is $2,327,010.
REASONS FOR THE PROPOSAL
The Managing General Partner believes that it is in the best interest
of the Investors for the Partnership to sell its Property Interests at this
time and to dissolve the Partnership and make a final liquidating distribution
to its partners for the reasons discussed below.
Current Liquidating Distribution Lowers Volatility Risk. The
Partnership has been in existence for over eleven years. The Managing General
Partner believes that the ability to receive the estimated liquidating
distribution in one lump sum at this time, rather than in smaller amounts over
a longer period, is one of the benefits of the Proposal, without the risk of
such distributions being negatively affected by oil and gas price decreases and
the inherent risks associated with geological, engineering and operational
matters. It is also the Managing General Partner's belief that improvements
over the last several years in the level of gas prices, relative to such prices
in the mid-1990's, makes this an appropriate time to consider the sale of the
Partnership's Property Interests and increase the likelihood of maximizing the
value of the Partnership's assets, although future prices and market volatility
cannot be predicted with any accuracy.
Decreasing Cash Flow While Expenses Continue. As of December 31,
1997, approximately 78% of the Partnership's ultimate recoverable reserves had
been produced. As a result of such depletion of the Partnership's oil and gas
reserves, the Managing General Partner believes the Partnership's asset base
and future net revenues no longer justify the continuation of operations. The
Partnership's oil and gas reserves are expected to continue to decline as
remaining reserves are produced. Declines in well production are based
principally upon the maturity of the wells, not on market factors. These
declines will continue to occur while oil field overhead and operating costs
($34,766 in 1997) and direct and general and administrative expenses ($98,342
in 1997) continue, which are relatively fixed amounts. Each producing well
requires a certain amount of operating and other costs, which are incurred
regardless of the level of production. Likewise, direct costs and/or general
and administrative expenses, such as compliance with the securities laws,
producing reports to partners and filing partnership tax returns, do not
decline as revenues decline. By accelerating the liquidation of the
Partnership, those future administrative costs will be avoided by the
Partnership.
Effect of Gas Prices on Value. The Managing General Partner believes
that the key factor affecting the Partnership's long-term performance has been
the decrease in oil and particularly gas prices that occurred subsequent to the
purchase of the Partnership's Property Interests. Additionally, prices are
expected to continue to vary widely over the remaining life of the Partnership,
and such changes in gas prices will affect future estimates of revenues from
continued operations of the Partnership. Based on 1997 year-end reserve
calculations, the Partnership had only about 22% of its ultimate recoverable
reserves remaining for future production. Because of this small amount of
remaining reserves, even if oil and gas prices were to increase in the future,
such increases would be unlikely to have a material positive impact
8
<PAGE> 376
on the total return on investment to Investors in view of the expenses of the
Partnership as described above. Approximately 78% of the Partnership's 1997
production and approximately 81% of its total proved reserves at year-end 1997
were comprised of natural gas. As of the summer of 1998, oil prices are
significantly lower than those for natural gas. Historically when there has
been significant difference between the price of gas and oil, those prices have
adjusted to become reasonably equivalent. Consequently, there may be a benefit
in selling the Partnership's Property Interests at this time and avoiding any
future decreases in prices of natural gas, although the direction and severity
of adjustments in prices for gas and/or oil are impossible to predict.
Behind-Pipe Reserves. It is estimated that approximately 49% of the
remaining reserves attributable to properties in which the Partnership has an
interest are behind-pipe reserves, which are unlikely to be producible for many
years because behind-pipe reserves always require completion of a well in a
different producing zone which does not take place until production is depleted
from the currently producing zones. Recovery in amounts great enough to
significantly impact the results of the Partnership's operations and the
ultimate cash distributions to partners can only occur with the investment of
new capital. As provided in its Partnership Agreement, the Partnership
expended all of the Investors' net commitments for the acquisition of Property
Interests many years ago and it no longer has capital to invest. No additional
development activities are contemplated by the Partnership on the properties in
which the Partnership has an interest.
Limited Partners' Tax Reporting. Each Investor will continue to have
an income tax reporting obligation with respect to his Units as long as the
Partnership continues to exist. There is no trading market for the Units, so
Investors generally are unable to dispose of their Units. See "Partnership
Business and Financial Condition--No Trading Market" in this Supplement.
Following the sale of the Partnership's Property Interests and dissolution of
the Partnership, Investors will realize gain or loss, or a combination of both,
under federal income tax laws. See "Summary of Federal Income Tax
Consequences--Taxable Gain or Loss upon Sale of Properties" herein.
Thereafter, Investors will have no further tax reporting obligations with
respect to the Partnership. The dissolution of the Partnership will also allow
Investors to take a capital loss deduction for syndication costs incurred in
connection with formation of the Partnership. See "Summary of Federal Income
Tax Consequences--Liquidation of the Partnership" in this Supplement.
See "Summary--Background and Reasons for the Proposals," "--Purpose and Effect
of the Proposals," "--Reasons for the Proposals" and "--Managing General
Partner's Recommendations" in the Joint Proxy Statement/Prospectus.
COLLECTIVE ANALYSIS OF PURCHASE PRICE; PREMIUM OVER FAIR MARKET VALUE
The Special Transactions Committee selected H.J. Gruy and Associates,
Inc. ("H.J. Gruy" or "Gruy"), J.R. Butler and Company ("J.R. Butler" or
"Butler"), which are both petroleum engineering consultants, and CIBC
Oppenheimer Corp. ("CIBC Oppenheimer"), an investment banking firm, to
estimate the fair market value of the Property Interests of each of the
Partnerships. Collectively, H.J. Gruy, J.R. Butler and CIBC Oppenheimer are
referred to herein as the "Appraisers," and H.J. Gruy and J.R. Butler together
are sometimes referred to herein as the "Petroleum Engineering Consultants."
The following subsections of the "Special Factors" section of the
Joint Proxy Statement/Prospectus should be reviewed for information concerning
the selection and qualification of the Appraisers and the
9
<PAGE> 377
parameters of the valuation estimates: "Independent Appraisal of the Fair
Market Value of Property Interests of the Partnerships," "Qualification of
Appraisers," and "Fair Market Value."
The Petroleum Engineering Consultants arrived at a fair market
valuation estimate of the Partnership's Property Interests based upon appraisal
of the projected discounted cash flow from its various Property Interests. On
the other hand, the investment banking firm of CIBC Oppenheimer made a
valuation estimate of the Partnership's Property Interests based upon the
application of multiple quantitative and qualitative factors. The quantitative
factors include, among other things, a review of relevant valuation criteria
from comparable acquisitions of both oil and gas properties and companies that
are predominantly active in the oil and gas industry, and a review of valuation
criteria for relevant publicly traded oil and gas companies.
The process used by the Petroleum Engineering Consultants in preparing
their valuation estimate is discussed at length in the Joint Proxy
Statement/Prospectus under "Special Factors--Valuation by Petroleum Engineering
Consultants." As described therein, the Petroleum Engineering Consultants
individually audited the estimate of present value of future net cash flows
from the 44 property groups in which Property Interests are owned by the
Partnerships to whom similar proposals are being made to sell all of their oil
and gas assets and liquidate their Partnerships. The Partnership owns Property
Interests in four of these property groups. The Petroleum Engineering
Consultants began their analysis based upon the year-end 1997 PV-10 Value of
each property audited by H.J. Gruy and together they re-evaluated reserve
quantities, projected operating costs and cash flows. The present value of
this reserves analysis was then derived by escalating year-end 1997 prices
($2.38 per MMBtu and $16.00 per barrel before adjustments for Btu content for
gas and gravity variances for oil as well as transportation charges and
geographic location) and costs by 3.5% per year for 15 years. This present
value was then adjusted for various individual field risks and risk adjustments
of proved non- producing reserves and proved undeveloped reserves. The result
of this collective analysis by the Petroleum Consulting Engineers was their
estimation that the fair market value of Property Interests owned by the
Partnership was $1,567,013 as of December 31, 1997.
The methodology used by CIBC Oppenheimer to prepare its valuation
estimate is discussed at length under "Special Factors--Valuation by CIBC
Oppenheimer" in the Joint Proxy Statement/Prospectus. CIBC Oppenheimer's
evaluation of the Partnership's Property Interests began with the PV-10 Value
of each property group, as calculated by Swift and audited by H.J. Gruy, which
Gruy report dated February 10, 1998 is Attachment D to this Supplement. CIBC
Oppenheimer then divided the property groups into two categories. Those
property groups with reserves consisting primarily of proved developed
producing reserves were placed in the "Conventional Case" category. Those
property groups with significant proved developed non-producing or undeveloped
reserves were placed in the "Non-Conventional Case" category. The Partnership
has interests in property groups which were in both the "Conventional Case" and
"Non-Conventional Case" categories. CIBC Oppenheimer then valued each property
group (including those groups in both the "Conventional Case" and
"Non-Conventional Case" categories) by applying the multiples discussed under
"Special Factors--Valuation by CIBC Oppenheimer--Valuation Multiples" in the
Joint Proxy Statement/Prospectus to each property group's PV-10 Value, proved
reserves on a BOE basis, and projected 1998 EBIDTA. A separate set of
multiples was used for property groups in the Conventional Case category and
the Non-Conventional Case category, respectively. This provided CIBC
Oppenheimer with three estimated values for each property group. The average
of these three values yielded CIBC Oppenheimer's estimation of the fair market
value of each property group. CIBC Oppenheimer then allocated the appropriate
portion of each property group's
10
<PAGE> 378
estimated fair market value to the Partnership based upon the Partnership's
Property Interests in each property group. The result of this analysis by CIBC
Oppenheimer was an estimation that the fair market value of the Partnership's
Property Interests was $1,369,233 on December 31, 1997.
The Special Transactions Committee has determined that, in keeping
with the definition of Fair Market Value, the higher of these two estimations
of fair market value, or $1,567,013, represents the Fair Market Value of the
Partnership's Property Interests. Accordingly, the fair market value
estimation of the Petroleum Consulting Engineers and the fair market value
determined by CIBC Oppenheimer were compared to each other and the higher of
the two was chosen as the Fair Market Value of the Property Interests owned by
the Partnership. The variation between the fair market value estimate of the
Partnership's Property Interests prepared by the Petroleum Consulting
Engineers, on one hand, and CIBC Oppenheimer on the other was 14%.
DETERMINATION OF PREMIUM OVER FAIR MARKET VALUE BY THE COMPANY
The Special Transactions Committee presented its recommendation to the
Board of Directors of the Company as to the Fair Market Value of the Property
Interests of the Partnership. The Board of Directors of the Company then
determined that paying a 7.5% premium over the Fair Market Value of the
Partnership's Property Interests was appropriate and fair based upon the
factors and for the reasons discussed below. Because the Company has served as
Managing General Partner of the Partnership for over eleven years, it is
intimately familiar with the Property Interests owned by the Partnership. The
Managing General Partner believes that if the Property Interests were to be
sold to a third party purchaser that was not equally familiar with those
interests, it is likely that the purchaser would discount the purchase price to
account for that lack of familiarity and associated risks. If these interests
are purchased by the Company, then the additional cost and personnel often
inherent in making a property acquisition are not required, because the files
and deed records already exist in the Company's lease and computer systems, and
conveyance and title issues do not exist.
In the judgment of the Company, the purchase of the Partnership's
Property Interests together with interests in many of the same properties owned
by other Partnerships at approximately the same time will result in
efficiencies to the Company in aggregating such interests. Swift's long-term
knowledge of the risks involved in these properties means that it is in a
better position to evaluate these risks than third parties.
Based upon the Company's experience in purchasing properties, the lack
of additional costs often incurred in purchasing oil and gas properties in
which the purchaser has owned no interest, and the Company's intimate
familiarity with these Property Interests and consequent ability to evaluate
acquisition risks, it was deemed appropriate to pay a premium representing the
benefit to the Company arising from these factors.
The amount of the premium principally was based upon management's
experience in purchasing properties which contain both producing reserves and
drilling potential, without any statistical or analytical study prepared by the
Company in the course of determining the amount of this premium. Since 1979,
the Company, on behalf of itself and others, has gained a wide range of
experience with the valuation of oil and gas properties and the prices for
their purchase and sale, having purchased $478 million of such properties in
129 separate transactions. Other purchasers might have determined it
inappropriate to pay a premium, or if so, to pay a premium based upon other
factors or in a different amount. Because there
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<PAGE> 379
has been no independent third party involved in the decision to pay this
premium or in the determination of its amount, and no fairness opinion has been
requested regarding this premium, conflicts of interest exist in its
determination, although the Managing General Partner believes, based upon its
knowledge of the oil and gas industry, its knowledge of the properties
involved, its experience in purchasing and selling oil and gas properties, and
the benefits from purchasing the Property Interests which are particular to the
Company, that the amount being offered to the Partnership to purchase its
Property Interests is fair.
"SPECIAL FACTORS" SECTION IN THE JOINT PROXY STATEMENT/PROSPECTUS
The Special Factors section in the Joint Proxy Statement/Prospectus
contains a full discussion of the determination of the purchase price proposed
to be paid by the Managing General Partner to purchase the Partnership's
Property Interests. In addition to those topics discussed at length in this
Supplement, the Joint Proxy Statement/Prospectus addresses alternative
transactions that were considered but not proposed for the Partnership and the
other 62 partnerships to whom similar proposals are being made simultaneously.
It also contains information regarding the prior relationships between the
Appraisers, the Partnerships and the Managing General Partner, the absence of a
request that an independent representative negotiate the terms of the purchase
of the Partnership's Property Interests by the Managing General Partner, the
manner in which expenses are to be borne for the transaction, the Managing
General Partner's source of funds to purchase the Partnership's Property
Interests, and the benefits that the Managing General Partner would receive
from purchasing such Property Interests.
ESTIMATES OF LIQUIDATING NET CASH DISTRIBUTION AMOUNT IF THE PROPOSAL IS
APPROVED
The purchase price proposed to be paid to the Partnership for its oil
and gas assets is the Fair Market Value plus the purchase premium. As is the
case with all oil and gas properties purchases, the purchase is proposed to be
made as of the date which the properties were evaluated (in this case December
31, 1997). A portion of the reserves used to establish the Fair Market Value
has been produced during 1998. Most of the net revenue received by the
Partnership from the sale of such production since the proposed purchase date
(December 31, 1997) has been distributed to the partners during 1998 through
quarterly cash distributions or, to the extent not already distributed, will be
distributed as part of the Partnership's liquidating distributions.
Accordingly, the actual purchase price which will be paid to the Partnership
will be reduced by the amount of net production revenue received by the
Partnership after December 31, 1997.
Set forth in the table below are estimated net proceeds that the
Partnership may realize from the sale of the Partnership's Property Interests,
estimated expenses of the related dissolution and liquidation of the
Partnership and estimated interim net cash distributions from January 1, 1998
until September 30, 1998, resulting in an estimate of the amount of net cash
distributions available for partners as a result of such sale.
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<PAGE> 380
ESTIMATE OF NET CASH DISTRIBUTIONS
FROM PROPERTY INTEREST SALES AND LIQUIDATION
<TABLE>
<S> <C>
Fair Market Value of Partnership Property Interests(1) $ 1,567,013
(Gross Sales Proceeds)
Purchase Premium (7.5% of Fair Market Value)(2) $ 117,526
Estimated Selling and Dissolution Expenses(3) $ (47,010)
(3% of the Fair Market Value)
Net Assets(4) $ 229,918
Estimated Interim Cash Distributions(5) $ (175,640)
------------------
Estimated Net Distributions to Partners(6) $ 1,691,807
=================
Amount Distributable
to Investors(6) $ 1,532,402
Amount Distributable
to General Partners(6)(7) $ 159,405
-----------------
$ 1,691,807
================
ESTIMATED NET CASH DISTRIBUTIONS TO INVESTORS PER $1,000 UNIT $ 108.52
=================
MINIMUM NUMBER OF UNITS NECESSARY TO PURCHASE 100 SHARES OF SWIFT
ENERGY COMMON STOCK WITH CASH DISTRIBUTIONS(8) 17
=================
</TABLE>
___________________________________________________
(1) Represents the higher of two fair market value estimates by the
Appraisers.
(2) As determined by the Board of Directors of Swift.
(3) Includes estimated costs associated with dissolution and liquidation
of the Partnership.
(4) Includes cash and net receivables of the Partnership as of December
31, 1997.
(5) Estimated cash distributions paid to the partners from January 1, 1998
to September 30, 1998.
(6) Estimated net cash distributions are allocated to the Investors and
the General Partners pursuant to the Partnership's limited partnership
agreement.
(7) Includes amount distributable to Special General Partner and Managing
General Partner.
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<PAGE> 381
(8) Under the terms of the offer of Swift Common Stock to Eligible
Purchasers, if the Investors in the Partnership approve the Proposal,
such Investors will be Eligible Purchasers. The minimum number of
shares which can be purchased by an Eligible Purchaser is a round lot
of 100 shares. Based upon estimated net cash distribution of $108.52
per $1,000 Unit, the number of Units shown above is the minimum number
of Units which it will be necessary for an Investor to own in order to
purchase a minimum 100 share round lot of Swift Common Stock without
providing any additional funds from other sources. This calculation
is based upon an assumed purchase price of Swift Common Stock of
$18.00 per share (which is the same price upon which the proforma
financial statements contained in the Joint Proxy Statement/Prospectus
are based) for an aggregate purchase price for 100 shares of Swift
Common Stock of $1,800. The minimum number of Units shown is subject
to change, based upon the price for Swift Common Stock at a future
date as specified under "Offering of Shares of Swift Energy Company
Common Stock if Investors Approve the Proposal--Offer of Swift Common
Stock--Purchase Price" in this Supplement. However, if an Eligible
Purchaser has interests in more than one Partnership, the cash
distributions he will be entitled to receive may be aggregated to meet
the minimum share purchase requirement of a round lot of 100 shares.
ESTIMATES OF NET CASH DISTRIBUTIONS AVAILABLE FROM CONTINUED OPERATIONS
If the Partnership were to retain its Property Interests until they
have reached their economic limit, the table below estimates the return to
Investors, without regard to amounts distributable to the General Partners,
discounted to present value, based upon 1997 year-end pricing without
escalation and upon the discount assumptions used above. The estimates of the
present value of future net cash distributions have been further reduced by
estimates of continuing audit, tax return preparation and reserve engineering
fees associated with continued operations of the Partnership, along with direct
and general and administrative expenses estimated to occur during this time.
The following estimated future net revenues do not take into account any
additional costs which might be incurred by the Partnership due to needed
future maintenance or remedial work on the properties in which the Partnership
has an interest, which would reduce such net revenues.
ESTIMATED SHARE OF INVESTORS'
NET CASH DISTRIBUTIONS FROM CONTINUED OPERATIONS
<TABLE>
<S> <C> <C>
Estimated Future Net Revenues from Continued Operations until $ 4,734,498
Depletion(1)
Estimated Interim Net Cash Distributions(2) $ (148,300)
Estimated Partnership Direct and Administrative Expenses(3) $ (596,548)
Net Assets(4) $ 206,926
---------------------
Net Cash Distributions to Investors(5) $ 4,196,576
=====================
NET CASH DISTRIBUTIONS PER $1,000 UNIT $ 297.18
PRESENT VALUE OF NET CASH DISTRIBUTIONS PER $1,000 UNIT(5)(6) $ 131.95
</TABLE>
___________________________________________
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<PAGE> 382
(1) Investors' future net revenues are based on the reserve estimates at
December 31, 1997 using year-end 1997 prices without escalation. To a
limited extent, future net revenues may be influenced by a material
change in the selling prices of oil or gas. For further discussion of
this, see "Special Factors--Reasons for the Proposal" in this
Supplement. The actual prices that will be received and the
associated costs are likely to vary and may be more or less than those
projected. See "Partnership Business and Financial Condition" in this
Supplement.
(2) Estimated net cash distributions paid to Investors from January 1,
1998 to September 30, 1998 in order to present this information on a
comparative basis (in relation to the preceding table) as of September
30, 1998.
(3) Includes Investors' share of general and administrative expenses, and
audit, tax, and reserve engineering fees.
(4) Includes Investors' share of cash and net receivables of the
Partnership as of December 31, 1997.
(5) Based upon the Partnership's reserves until they have reached their
economic limit.
(6) Discounted at 10% per annum.
The proceeds of all sales, to the extent available for net cash
distribution, are to be distributed to the partners in accordance with the
Partnership's limited partnership agreement. The amounts finally distributed
will depend on results of operations until liquidation of the Partnership,
final costs and other contingencies and circumstances.
FAIRNESS OF PROPOSED SALE OF ASSETS TO THE MANAGING GENERAL PARTNER
AS COMPARED TO CONTINUING OPERATIONS
Based on the above tables, it is estimated that an Investor could
expect to receive $108.52 per $1,000 Unit upon the sale of the Partnership's
Property Interests as of September 30, 1998. In comparison, it is estimated
that an Investor could expect to receive $131.95 per $1,000 Unit, discounted to
present value at 10% per annum ($297.18 per $1,000 Unit on an undiscounted
basis) if the Partnership continued operations. The Managing General Partner
believes that the Proposal to sell the Partnership's Property Interest as
compared to continuing operations is fair to Investors for the reasons
discussed below.
Although the estimates contained in the two tables above show that
estimated net cash distributions to Investors (based on net present value) from
continued operations would be approximately 22% higher than estimated net cash
distributions from selling the Partnership's Property Interests and liquidating
the Partnership currently, the Managing General Partner believes there is a
substantial advantage in receiving the liquidating net cash distribution in one
lump sum at this time. The estimates of net cash distributions from continued
operations are based upon 1997 year- end pricing. It is highly likely that
over such a long period of time, oil and gas prices will vary often and
possibly widely, as has been demonstrated historically, from the prices used to
prepare these estimates. Continued operations over such a long period of time
subject Investors to the risk of receiving lower levels of net cash
distributions if oil and gas prices over this period are lower on average than
those used in preparing the estimates of net cash distributions from continued
operations. Continued operations also subject Investors' potential net cash
distributions to the risks of possible changes in costs or need for workover or
similar significant remedial work on the properties in which the Partnership
owns Property Interests. The Managing General Partner also believes that there
is an advantage to Investors taking any funds to be received upon liquidation
and redeploying
15
<PAGE> 383
those assets in other investments, rather than continuing to receive decreasing
levels of net cash distributions over such a long period of time.
Because there is no active trading market for Units in the
Partnership, the only other comparable value for Units is the 1997 "Unit
Value," which, as explained below, is the amount calculated on an annual basis
under the terms of the limited partnership agreement at which the Managing
General Partner can offer to repurchase Units from Investors. As of January 1,
1997, this "Unit Value" was $157.73 per $1,000 Unit. In 1997, the Investors
received net cash distributions of $18.26 per $1,000 Unit, and are estimated to
receive another $10.50 per $1,000 Unit before September 30, 1998, which
converts to a comparable value of $128.97 per $1,000 Unit before any
adjustments to quantities of reserves or oil and gas prices during this almost
two year period. Under the terms set out in the limited partnership agreement,
each year the Managing General Partner is required to furnish to Investors the
Unit Value, and Investors have the right to present their Units for purchase by
the Managing General Partner for the Unit Value. The Unit Value amount is
determined on an entirely different basis than the estimates of fair market
value by the Appraisers. Furthermore, the Unit Value was calculated over one
year ago, with a valuation date of January 1, 1997, as opposed to the date for
assessment of Fair Market Value being December 31, 1997. Because of significant
changes in oil and gas prices within a year's time, in addition to the changes
in reserve quantities during that period, the calculation of Unit Value as of
January 1, 1997, and the Fair Market Value as of December 31, 1997, are not
comparable. Unit Value is derived by taking 70% of the present value of proved
oil and gas reserves (discounted at 10% per annum) calculated on an escalated
pricing basis, plus cash and accounts receivable less outstanding debts and
obligations of the Partnership.
Although the PV-10 Value of the Partnership's Property Interests is
higher than the purchase price proposed if the Proposal is approved, the
Managing General Partner does not believe that the PV-10 Value accurately
reflects the amount that oil and gas industry members are currently paying to
purchase producing properties on the open market.
FAIRNESS OF PROPOSED SALE
The Managing General Partner believes that the entire transaction
related to the Proposal involving the proposed method of sale of the
Partnership's Property Interests is fair to Investors for the following
reasons, without giving any particular weight to any reason:
1. The Managing General Partner believes that the most important
element of the Proposal is the determination of the Fair
Market Value of the Partnership's Property Interests. The
price to be paid by the Company to purchase the Partnership's
Property Interests was determined in the Managing General
Partner's sole judgment by adding a 7.5% premium to the higher
of the two estimates by the Appraisers of the fair market
value of the Partnership's Property Interests. Two of the
three Appraisers are qualified independent petroleum
engineering firms and the other is an investment banking firm.
The factors and methods used by the Appraisers in determining
Fair Market Value are discussed in detail under "Special
Factors--Independent Appraisal of the Fair Market Value of
Property Interests of the Partnerships," "--Fair Market
Value," "--Valuation by Petroleum Engineering Consultants,"
"--Valuation by CIBC Oppenheimer" and "--Collective Analysis
of Purchase Price" in the Joint Proxy Statement/Prospectus.
16
<PAGE> 384
2. No transaction will take place unless the Proposal is approved
by Investors holding at least a majority of the interests in
such Partnership (without any vote by the Managing General
Partner).
3. The Special Transactions Committee made the determination as
to the retention of the Appraisers and approved the fair
market value estimates provided by the Appraisers and
recommended the reports of the Appraisers to the Board of
Directors of the Company. The Special Transactions Committee
is comprised solely of independent directors of the Company.
4. If the Proposals are approved by investors in any of the 63
Partnerships considering similar proposals, it is likely that
the Managing General Partner will expend the capital necessary
to develop non- producing reserves on the Property Interests
purchased by the Managing General Partner from those
Partnerships. If all of the Property Interests which are the
subject of the Proposals are acquired by the Company, such
Property Interests in the aggregate will constitute less than
20% of the Company's total assets. Because the Managing
General Partner would be the beneficiary of any such increase
in value, the Managing General Partner is hereby offering to
Eligible Purchasers the opportunity to purchase up to
2,500,000 shares of Common Stock of the Company. There is no
requirement that any purchase of Swift's Common Stock be made.
See "Offer of Swift Common Stock" below.
5. In structuring the Proposal and related transactions, the
Managing General Partner considered that any sale of
Partnership Property Interests, whether to the Managing
General Partner or to a third party, would be a taxable
transaction. Thus, if an Investor subject to federal income
tax chooses to use the proceeds received on liquidation of
that Investor's Partnership to purchase Swift Common Stock,
tax will still have to be paid on any taxable income resulting
from the Partnership's sale of oil and gas assets, without
regard to whether the Investor has cash proceeds remaining
from his liquidating distribution to pay such tax.
The determination by the Special Transactions Committee to pay the
purchase premium, the independent Appraisers' determination of the fair market
value of the properties and the payment of a 7.5% premium do not necessarily
remove the substantial conflicts of interest which exist in the transaction
between the Managing General Partner's serving in that capacity on behalf of
the Partnership and also acting as the purchaser of the Property Interests from
the Partnership. No fairness opinion was requested or received regarding the
ultimate purchase price to be paid by the Managing General Partner to purchase
the Partnership's oil and gas assets. The Managing General Partner determined
that rather than setting the purchase price for Partnership Property Interests
itself, it would be preferable to instead request three different independent
Appraisers to determine two sets of fair market values at which such Property
Interests should be purchased, and then to choose the higher of those two
values. The Managing General Partner believes that when the Appraisers
rendered their opinions as to the "fair market value" of the Partnership's
Property Interests, inherent within their appraisal opinions were the
Appraisers' determination that these "fair market values" were "fair," or such
determinations would not have been made. Consequently, no independent fairness
opinion was requested regarding "fair market values" or upon the premium. The
Managing General Partner believes that adding a 7.5% premium to the highest of
the two fair market value determinations made by the three Appraisers only
serves to increase the amount to be
17
<PAGE> 385
paid to Investors upon liquidation of the Partnership and does not require a
separate fairness opinion. The determination by a third party purchaser as to
the purchase price might be more or less than that being proposed by the
Managing General Partner as a purchase price for these Property Interests.
The determination to submit the Proposal to Investors in which the
Company would purchase the Property Interests of the Partnership was deemed by
the Managing General Partner to be the most appropriate time and method for
liquidation of the Partnership. This decision was made in light of full
consideration by the Managing General Partner of its fiduciary obligations to
Investors. Furthermore, the decision to use three Appraisers, rather than one,
and to have the Appraisers actually set the fair market value for purchase of
the Property Interests, rather than the Managing General Partner setting that
value and requesting a fairness opinion, were based upon the Managing General
Partner's consideration of the substantial conflicts of interest which exist in
the transactions covered hereby.
See "Special Factors--Fairness of Proposed Sale" in the Joint Proxy
Statement/Prospectus.
MANAGING GENERAL PARTNER BENEFITS
Benefits accruing to the Company resulting from the purchase of the
Partnerships' Property Interests include the following: the Managing General
Partner will share the benefits available to Investors through liquidating its
Partnership interests (including both its general partner interests and any
Units it owns) and receiving the same value of those interests as Investors.
Additionally, the Company intends to profit from purchasing the Partnership's
Property Interests through a return on capital used to purchase those oil and
gas assets and invest in their development. By purchasing the Partnership's
Property Interests itself, the Managing General Partner will be able to
maintain its position as operator of certain properties in which the
Partnership owns an interest. Consequently, the Managing General Partner would
continue to receive operating fees as operator of those properties. The sale
of the Partnership's Property Interests to the Managing General Partner will
have no effect or an inconsequential effect on the Managing General Partner's
net book value and net earnings. However, the purchase of all of the oil and
gas assets of the Partnerships would increase the Company's proved reserves,
cash flow and total assets by a significant amount. Lastly, if individual
Investors which approve the Proposal elect to purchase Company Common Stock,
rather than receiving cash upon liquidation of the Partnership, the Company
will benefit by using stock to pay the purchase price, rather than using its
available cash resources or borrowing facilities.
See "Special Factors--Managing General Partner Benefits" in the Joint Proxy
Statement/Prospectus.
SIMULTANEOUS PROPOSALS TO COMPANION PARTNERSHIPS
The Partnership does not have a Companion Partnership, therefore no
approval of a simultaneous proposal by any other partnership is required in
order for the sale of the Partnership's Property Interests to take place
following approval of the Proposal by its Investors.
VOTING ON THE PROPOSAL
The Joint Proxy Statement/Prospectus and the Form of Proxy enclosed
with this Supplement are being provided for use at the Special Meeting of
Investors of the Partnership and at any adjournment or postponement of such
meeting (the "Meeting") to be held at 16825 Northchase Drive, Houston, Texas at
4:00 p.m. Central Time on ______, ___________, 1998. The Meeting is being
called for the purpose of
18
<PAGE> 386
considering and voting upon the Proposal to sell all of the oil and gas assets
of the Partnership to the Company, and to dissolve, wind up and terminate the
Partnership and to transact such other business as may be properly presented at
the Meeting, all in accordance with the terms and provisions of the
Partnership's limited partnership agreement (the "Partnership Agreement"), and
the Texas Revised Limited Partnership Act (the "Texas Act"). This Joint Proxy
Statement/Prospectus and enclosed Form of Proxy are first being mailed to
Investors on or about _____________, 1998.
Pursuant to the terms of the Partnership Agreement, the Partnership,
if not terminated earlier, will continue in being through January 1, 2016, at
which point it will terminate automatically.
Under the Partnership Agreement, the Proposal must be approved by the
affirmative vote of Investors holding 51% or more of the Units in the
Partnership as of the Record Date (defined below). Therefore, an abstention by
an Investor will have the same effect as a vote against the Proposal. The
solicitations are being made for votes in favor of the Proposal (which will
result in liquidation and dissolution of the Partnership). As of the Record
Date, 10,447 Units were outstanding and held by record holders (excluding the
Units held by the Managing General Partner as discussed below). Accordingly,
the affirmative vote of holders of at least 5,328 Units is required to approve
the Proposal. Each Investor appearing on the records of the Partnership as of
______, 1998 (the "Record Date") is entitled to notice of the Meeting and is
entitled to one vote for each Unit held by such Investor. VJM Corporation, a
California corporation, is the Special General Partner of the Partnership, and
owns a 1.0% interest in the Partnership as a general partner, but owns no
Units. The Managing General Partner owns a general partner interest in the
Partnership of 9.0%. Additionally, the Managing General Partner owns 3,674
outstanding Units in the Partnership, which ownership results from the Managing
General Partner's purchase over the life of the Partnership of Units from
Investors under the right of presentment, contained in the Partnership
Agreement. Under the Partnership Agreement, the Managing General Partner may
not vote any Units owned by it for matters such as the Proposal. The Managing
General Partner's non-vote, in contrast to abstention by Investors, will not
affect the outcome, because for purposes of adopting the Proposal, its Units
are excluded from the total number of voting Units.
VOTE REQUIRED
The actual proxy to be used to register the vote on the Proposal
before you is the separate green sheet of paper included with this Supplement
and Joint Proxy Statement/Prospectus. PLEASE USE THE GREEN PROXY TO CAST YOUR
VOTE ON THE PROPOSAL.
If a proxy is properly signed and is not revoked by an Investor, the
Units it represents will be voted in accordance with the instructions of the
Investor. If no specific instructions are given, the Units will be voted FOR
the Proposal. An Investor may revoke his proxy at any time before it is voted
at the Meeting. Any Investor who attends the Meeting and wishes to vote in
person may revoke his proxy at that time. Otherwise, an Investor must advise
the Managing General Partner of revocation of his proxy in writing, which
revocation must be received by the Managing General Partner at 16825 Northchase
Drive, Suite 400, Houston, Texas 77060 prior to the time the vote is taken.
19
<PAGE> 387
SOLICITATION
The solicitation is being made by the Partnership. The Partnership
will bear the costs of the preparation of the Joint Proxy Statement/Prospectus
and of the solicitation of proxies and such costs will be allocated 90% to the
Investors and 10% to the general partners pursuant to the terms of the
Partnership Agreement. As the Managing General Partner holds approximately
26.01% of the Units held by all Investors, 26.01% of the costs borne by the
Investors will be borne by the Managing General Partner, in addition to the
portion of the Partnership's total costs borne by the general partners by
virtue of their interest in the Partnership as general partners. Solicitations
will be made primarily by mail. In addition, a number of regular or temporary
employees of the Managing General Partner may, if necessary to ensure the
presence of a quorum, solicit proxies in person or by telephone. The Managing
General Partner also may retain a proxy solicitor to assist in contacting
brokers or Investors to encourage the return of proxies, although it does not
anticipate doing so.
PARTNERSHIP BUSINESS AND FINANCIAL CONDITION
The Partnership is a Texas limited partnership formed January 9, 1987.
Units in the Partnership are registered under Section 12(g) of the Securities
Exchange Act of 1934. The Partnership owns Property Interests in producing oil
and gas properties within the continental United States. By the end of
December 1987, the Partnership had expended all of its original capital
contributions for the purchase of Property Interests in oil and gas producing
properties. During 1997, approximately 75% of the Partnership's revenue was
attributable to natural gas production. From time to time, the Partnership has
performed workovers and recompletions on wells in which the Partnership has
Property Interests, using funds advanced by the Managing General Partner or
third parties, to perform these operations, which amounts have been
subsequently repaid. For information about the business of the Partnership,
see the attached Annual Report on Form 10-K for the year ended December 31,
1997 and Quarterly Report on Form 10-Q for the quarter ended June 30, 1998.
Investors made contributions of $14,121,095 in the aggregate to the
Partnership, the net proceeds of which have all been invested. The Managing
General Partner has made capital contributions with respect to its general
partner interest of $112,295. Additionally, pursuant to the right of
presentment set forth in the Partnership Agreement, it has purchased 3,674
Units from Investors. From inception through July 31, 1998, the Partnership
has made net cash distributions to its Investors totaling $7,964,607. Details
of the amounts of cash distributions made to partners over the past three years
and nine months are set out under "Cash Distributions" below. Through July 31,
1998, the Managing General Partner has received net cash distributions from the
Partnership of $848,331 with respect to its general partner interest, and
$199,956 related to its limited partner interest. On a per Unit basis,
Investors had received, as of July 31, 1998, $564.02 per $1,000 Unit, or
approximately 56.4% of their initial capital contributions.
The Partnership acquired its Property Interests at a time when oil and
gas prices and industry projections of future prices were much higher than
actually occurred in subsequent years. When the Managing General Partner
projected future oil and gas prices to evaluate the economic viability of an
acquisition, it compared its forecasts with those made by banks, oil and gas
industry sources, the U.S. government and other companies acquiring producing
properties. Acquisition decisions for the Partnership were based upon a range
of increasing prices that were within the mainstream of the forecasts made by
these outside parties. At the time that the Partnership's Property Interests
covering producing properties were acquired, prices averaged about $18.59 per
barrel of oil and $1.53 per Mcf of natural gas. The
20
<PAGE> 388
majority of the Partnership's Property Interests were acquired by the end of
December 1987 and were comprised principally of natural gas reserves. At that
time current prices were predicted to escalate according to certain parameters
from then current levels to approximately $32.22 per barrel of oil and $3.82
per Mcf of natural gas during 1997. The predicted price increases did not
occur, and prices fell precipitously from 1990 to 1991. Most of the
Partnership's reserves were produced from 1987 to 1991, during which time the
oil prices received by the Partnership for its production in fact averaged
$18.22 per barrel, but the prices for the Partnership's principal asset,
natural gas, averaged approximately $1.55 per Mcf. A comparison of gas prices
as described in this paragraph appears in the graph presented below.
The following graphs illustrate the effect on Partnership performance of the
variance between gas prices projected at the time of acquisition of the
Partnership's Property Interests and actual gas prices received for production
(as illustrated in the second graph) during the Partnership's existence.
Information is presented as to gas prices only due to the fact that a
substantial majority of the Partnership's production has been natural gas.
21
<PAGE> 389
[GRAPH: 1 page of gas properties info]
22
<PAGE> 390
Lower prices also have had an effect on the Partnership's interest in
proved reserves. Estimates of proved reserves represent quantities of oil and
gas which, upon analysis of engineering and geologic data, appear with
reasonable certainty to be recoverable in the future from known oil and gas
reservoirs under existing economic and operating conditions. When economic or
operating conditions change, proved reserves can be revised either up or down.
If prices had risen as predicted, the volumes of oil and gas reserves that are
economically recoverable might have been higher than the year-end levels
actually reported because higher prices typically extend the life of reserves
as production rates from mature wells remain economical for a longer period of
time. Production enhancement projects that are not economically feasible at
low prices can also be implemented as prices rise. At present, because of the
small remaining amount of reserves, further price increases would not have a
significant impact on the Partnership's performance.
CASH DISTRIBUTIONS
Cash distributions are made to the partners in the Partnership on a
quarterly basis. During the past three years and the first nine months of
1998, aggregate cash distributions made to all partners in the Partnership
(including the Managing General Partner) and the cash distributions per Unit
made to the Investors were:
<TABLE>
<S> <C> <C> <C>
1995 $ 202,275 $ 12.75 per $1,000 Unit
1996 $ 147,521 $ 7.51 per $1,000 Unit
1997 $ 283,972 $ 18.26 per $1,000 Unit
9 Mo. Ended 9/30/98 $ 175,640 $ 10.50 per $1,000 Unit
</TABLE>
TRANSACTIONS BETWEEN THE MANAGING GENERAL PARTNER AND THE PARTNERSHIP
Under the Partnership Agreement, the Managing General Partner has
received certain compensation for its services and reimbursement for
expenditures made on behalf of the Partnership, which was paid at closing of
the offering of interests in the Partnership, in addition to revenues
distributable to the Managing General Partner with respect to its general
partner interest or with respect to Units it has purchased under the Investors'
right of presentment. In addition to those revenues, compensation and
reimbursements, the following summarizes the transactions between the Managing
General Partner and the Partnership pursuant to which the Managing General
Partner has been paid or has had its expenses reimbursed on an ongoing basis:
o The Managing General Partner has received management fees of
$353,027, internal acquisition costs reimbursements of
$297,124 and formation costs reimbursements of $282,422 from
the Partnership from inception through December 31, 1997, none
of which has been received during the two years ended December
31, 1997.
o The Managing General Partner receives operating fees for wells
in which the Partnership has Property Interests and for which
the Managing General Partner or its affiliates serve as
operator. During the years ended December 31, 1997 and
December 31, 1996 the aggregate operating fees paid to the
Company as operator by the Partnership were $29,245 and
$38,456, respectively. Monthly operating fees range from $500
to $900 per well on an 8/8th's basis (i.e., the total amount
of operating fees paid by all interest owners in the well).
If the Property Interests are sold to the Managing General
Partner, there should be
23
<PAGE> 391
no change in its status as operator for a number of the wells
in which the Partnership has a Property Interest. The
Managing General Partner believes that it will be positively
affected, on the other hand, by liquidation of the
Partnership, both on the basis of its ownership interest in
the Partnership and for other reasons set out under "Special
Factors--Managing General Partner Benefits" in this
Supplement.
o The Managing General Partner is entitled to be reimbursed for
general and administrative costs incurred on behalf of and
allocable to the Partnership, including employee salaries and
office overhead. Amounts are calculated on the basis of
Investors' original capital contributions to the Partnership
relative to investor contributions to all public partnerships
formed to purchase interests in producing properties for which
the Managing General Partner serves in that capacity. Through
December 31, 1997, the Managing General Partner had received
$1,008,876 in the general and administrative overhead
allowance from the Partnership, of which $43,568 and $107,566
have been reimbursed during the years ended December 31, 1997
and December 31, 1996, respectively.
o The Managing General Partner has been reimbursed $72,761 in
direct expenses by the Partnership, all of which was billed
by, and then paid directly to, third party vendors, of which
$5,161 and $7,134 have been reimbursed during the years ended
December 31, 1997 and December 31, 1996, respectively.
NO TRADING MARKET
There is no trading market for the Units, and none is expected to
develop, as described above under "Special Factors--Fairness of Proposed Sale
of Assets to the Managing General Partner as Compared to Continuing
Operations." Under the Partnership Agreement, Investors have the right to
present their Units to the Managing General Partner for repurchase at a price
determined in accordance with the formula established by the Partnership
Agreement. Originally 1,580 Investors invested in the Partnership. As of
__________, 1998, there were 1,201 Investors (excluding the Managing General
Partner). The number of Units in the Partnership issued and outstanding at
that date was 14,121.10. Through December 31, 1997, the Managing General
Partner had purchased 3,674 Units from Investors pursuant to the right of
presentment. The Managing General Partner does not have an obligation to
repurchase Investor interests pursuant to this right of presentment, but merely
an option to do so when such interests are presented for repurchase.
PRINCIPAL HOLDERS OF INVESTOR UNITS
The Managing General Partner holds 26.01% of all outstanding Units of
the Partnership, resulting from the purchase of Units from Investors under
their right of presentment. To the knowledge of the Managing General Partner,
there is no other holder of Units that holds more than 5% of the Units.
APPROVALS
No federal or state regulatory requirements must be satisfied or
approvals obtained in connection with the sale of the Partnership's Property
Interests.
24
<PAGE> 392
LEGAL PROCEEDINGS
The Managing General Partner is not aware of any material pending
legal proceedings to which the Partnership is a party or of which any of its
property is the subject.
SUMMARY OF FEDERAL INCOME TAX CONSEQUENCES
GENERAL
The following briefly summarizes the federal income tax consequences
set forth under "Federal Income Tax Consequences of Adoption of the Proposals"
in the Joint Proxy Statement/Prospectus. Statements of legal conclusions
herein regarding tax consequences are based upon an opinion of Hoops & Levy,
L.L.P., Special Tax Counsel, relevant provisions of the Internal Revenue Code
of 1986, as amended (the "Code"), and accompanying Treasury Regulations, as in
effect on the date hereof, upon reported judicial decisions and published
positions of the Internal Revenue Service (the "Service"), and upon further
assumptions that the Partnership constitutes a partnership for federal tax
purposes and that the Partnership will be liquidated as described herein. The
laws, regulations, administrative rulings and judicial decisions which form the
basis for conclusions with respect to the tax consequences described herein are
complex and are subject to prospective or retroactive change at any time and
any change may adversely affect Investors.
A MORE COMPLETE SUMMARY OF THE FEDERAL INCOME TAX CONSEQUENCES TO
INVESTORS MAY BE FOUND IN THE REGISTRATION STATEMENT IN "FEDERAL INCOME TAX
CONSEQUENCES OF ADOPTION OF THE PROPOSALS." THIS SUMMARY DOES NOT DESCRIBE ALL
THE TAX ASPECTS WHICH MAY AFFECT INVESTORS NOR IS IT A COMPLETE DESCRIPTION OF
THE TAX ASPECTS IT DOES DESCRIBE. It is generally directed to individual
Investors who are the original purchasers of the Units and hold interests in
the Partnership as "capital assets" (generally, property held for investment).
Each Investor that is a corporation, trust, estate, tax exempt entity, or other
partnership is strongly encouraged to consult its own tax advisor as to the
rules which are specifically applicable to it. Except as otherwise
specifically set forth herein, this summary does not address foreign, state or
local tax consequences, and is inapplicable to nonresident aliens, foreign
corporations, debtors under the jurisdiction of a court in a case under federal
bankruptcy laws or in a receivership, foreclosure or similar proceeding, or an
investment company, financial institution or insurance company.
TAXABLE GAIN OR LOSS UPON SALE OF PROPERTIES
Investors will realize and recognize gain or loss, or a combination of
both, upon the Partnership's sale of its properties prior to liquidation. It
is projected, however, that Investors will realize a net taxable gain upon the
sale of the Partnership properties. Because the oil and gas properties, and
related assets, owned by the Partnership are properties used in a trade or
business, the character of gains and losses realized by the Investors generally
will be governed by Section 1231 of the Code. Realized gains and losses
generally must be recognized and reported in the year the sale occurs. Each
Investor's recognized allocable share of the net Partnership 1231 gains or
losses must be netted with that Investor's individual section 1231 gains and
losses recognized during the year in order to determine the character of such
net gains or net losses under section 1231. Net gains will be treated as
capital gains except to the extent recharacterized as ordinary income due to
recapture and net losses will be treated as ordinary losses.
25
<PAGE> 393
LIQUIDATION OF THE PARTNERSHIP
After sale of its properties, the Partnership's assets will consist
solely of cash which it will distribute to its partners in complete
liquidation. The Partnership will not realize gain or loss upon such
distribution of cash to its partners in liquidation. If the amount of cash
distributed to an Investor in liquidation is less than such Investor's adjusted
tax basis in his Partnership interest, the Investor will realize and recognize
a capital loss to the extent of the excess. If the amount of cash distributed
is greater than such Investor's adjusted tax basis in his Partnership interest,
the Investor will recognize a capital gain to the extent of the excess.
Because each Investor paid a portion of syndication and formation costs upon
entering the Partnership, neither of which costs were deductible expenses, it
is anticipated that liquidating distributions to Investors will be less than
such Investors' bases in their Partnership interests and thus will generate
capital losses.
CAPITAL GAIN TAX
Net long-term capital gains of individuals, trusts and estates
generally will be taxed at a maximum rate of 20%, while ordinary income,
including income from the recapture of intangible drilling and development
costs, depreciation and depletion, will be taxed at a maximum rate depending on
that Investor's taxable income of 36% or 39.6%.
PASSIVE LOSS LIMITATIONS
Investors that are individuals, trusts, estates, or personal service
corporations are subject to the passive activity loss limitations rules that
were enacted as part of the Tax Reform Act of 1986.
An Investor's allocable share of Partnership income, gain, loss, and
deduction is treated as derived from a passive activity, except to the extent
of Partnership portfolio income, which includes interest, dividends, royalty
income and gains from the sale of property held for investment purposes.
THE FOREGOING DISCUSSION IS A SUMMARY OF THE INCOME TAX CONSEQUENCES
SET FORTH UNDER "FEDERAL INCOME TAX CONSEQUENCES OF ADOPTION OF THE PROPOSALS"
IN THE JOINT PROXY STATEMENT/PROSPECTUS. IT IS NOT INTENDED AS AN ALTERNATIVE
FOR INDIVIDUAL TAX PLANNING. EACH INVESTOR SHOULD CONSULT HIS, HER OR ITS OWN
TAX ADVISOR CONCERNING THE PARTICULAR FEDERAL, STATE, LOCAL, FOREIGN AND OTHER
TAX CONSEQUENCES APPLICABLE TO HIM, HER OR IT OF THE SALE OF PROPERTIES AND THE
LIQUIDATION OF THE PARTNERSHIP.
SELECTED FINANCIAL INFORMATION AND
PROFORMA FINANCIAL STATEMENTS
For selected financial information and financial statements of the
Partnership, see the Annual Report on Form 10-K for the year ended December 31,
1997 and the Quarterly Report on Form 10-Q for the quarter ended June 30, 1998
attached hereto.
Proforma Financial Statements showing the effect of approval of the
Proposals by the 63 Partnerships to whom similar proposals are being made (both
in the event of the decision by investors to purchase the maximum number of
shares of Swift Common Stock purchasable with their cash distributions
26
<PAGE> 394
and in the event that investors choose to take all of their distributions from
sale of the properties in cash) and the effect of the Sonat Properties
Acquisition are contained in the Joint Proxy Statement/Prospectus under
"Unaudited Proforma Consolidated Financial Statements".
OFFERING OF SHARES OF SWIFT ENERGY COMPANY COMMON STOCK
IF INVESTORS APPROVE THE PROPOSAL
VOTING PROCEDURES
The Joint Proxy Statement/Prospectus contains detailed procedures to
be followed by investors in voting as to the Partnerships' Proposals. Strict
compliance with these procedures must be followed in order for the elections of
the investors marked on the subscription agreement to be effective. The
following is a summary of certain of these procedures:
(a) Investors may make their elections on the subscription agreement
signed by all subscribers commencing upon delivery of this Joint Proxy
Statement/Prospectus and continuing until the Due Date (as defined below).
(b) If Investors in the Partnership vote to approve the Proposal,
Investors may revoke their election to purchase Shares offered hereby at any
time until the Due Date by delivering or faxing a letter so stating or a later
dated subscription agreement, both of which must be signed by such revoking
subscribers, to the Company at 16825 Northchase Drive, Suite 400, Houston,
Texas 77060, fax number (281) 874-2818; Attention: Investor Relations
Department.
(c) Investors failing to submit proxies by the Due Date will be
deemed to have voted against their Partnership's Proposal and, if their
Partnership approves its Proposal, will receive, along with non-subscribing
investors who timely submitted proxies, their distribution in cash. See "The
Proposals--Vote Required" in the Joint Proxy Statement/Prospectus.
OFFER OF SWIFT COMMON STOCK
Investor Election to Purchase Shares
In connection with the concurrent Proposals for sale of all of the oil
and gas assets of 63 Partnerships to the Company and the subsequent termination
of such Partnerships, the Company is offering up to 2,500,000 shares of the
Company's Common Stock. Upon approval of the Proposals by the Partnership and
sale of the Partnership's oil and gas assets, the Partnership's assets will
consist solely of cash which each investor as an Eligible Purchaser of such
Partnerships will be entitled to receive as a distribution. The Company hereby
offers to each such Eligible Purchaser the opportunity to purchase shares of
Common Stock with all or any portion of the cash distribution such Eligible
Purchaser will be entitled to receive, provided that a minimum round lot of 100
shares must be purchased. If an Eligible Purchaser has interests in more than
one Partnership, the cash distributions he will be entitled to receive may be
aggregated to meet the minimum round lot of 100 shares requirement. Each such
Eligible Purchaser may purchase shares of Common Stock with funds in addition
to their cash distributions in order to purchase (i) the minimum round lot of
100 shares, or (ii) shares in addition to the number of shares for which their
cash distribution will be applied, subject to prorata limitations in the event
of oversubscription. No fractional shares will be sold.
27
<PAGE> 395
Purchase Price
The price at which the Common Stock offered hereby will be issued will
be the average price of the Common Stock as reported by the NYSE for the period
between ________ and __________, 1998.
New York Stock Exchange and Pacific Exchange Listings
The Common Stock is traded on the NYSE and the Pacific Exchange under
the symbol "SFY." Application will be made to list the Shares offered hereby
on the NYSE and the Pacific Exchange.
Closing Date
The Company will issue checks representing full or partial
distributions and/or stock certificates representing the shares of Common Stock
subscribed for hereunder approximately forty-five (45) days after the date of
the Prospectus Supplement (the "Closing Date"), unless earlier terminated or
extended by the Company.
Due Date
All subscriptions, revocations of prior subscriptions or additional
required consideration must be received no later than thirty (30) days after
the date of the Prospectus Supplement (the "Due Date"), unless extended by the
Company.
Oversubscription
In the event this Offering is oversubscribed, all subscribing Eligible
Purchasers will first be sold a round lot of 100 shares and then, if
applicable, that number of shares of Common Stock the purchase price of which
is equal to such Eligible Purchaser's cash distribution, rounded down to the
next whole share. Any remaining shares will be sold on a prorata basis based
on the number of shares such subscribers wish to purchase.
Revocation
Eligible Purchasers may revoke their subscriptions to purchase of the
Shares offered hereby at any time until the Due Date by delivering or faxing a
letter so stating or a later dated subscription agreement, either of which must
be signed by such revoking subscribers, to the Company at 16825 Northchase
Drive, Suite 400, Houston, Texas 77060, fax number (281) 874-2818; Attention:
Investor Relations Department.
28
<PAGE> 396
TABLE OF CONTENTS
<TABLE>
<S> <C>
THE PARTNERSHIP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
CONFLICTS OF INTEREST . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
SPECIAL FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Background and Purpose of the Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Proposed Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Reasons for the Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Current Liquidating Distribution Lowers Volatility Risk . . . . . . . . . . . . . . . . . . . . . . . 8
Decreasing Cash Flow While Expenses Continue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Effect of Gas Prices on Value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Behind-Pipe Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Limited Partners' Tax Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Collective Analysis of Purchase Price; Premium over Fair Market Value . . . . . . . . . . . . . . . . . . . . 9
Determination of Premium Over Fair Market Value by the Company . . . . . . . . . . . . . . . . . . . . . . . 11
"Special Factors" Section in the Joint Proxy Statement/Prospectus . . . . . . . . . . . . . . . . . . . . . 12
Estimates of Liquidating Net Cash Distribution Amount if the Proposal is Approved . . . . . . . . . . . . . 12
Estimates of Net Cash Distributions Available from Continued Operations . . . . . . . . . . . . . . . . . . 14
Fairness of Proposed Sale of Assets to the Managing General Partner as Compared to Continuing Operations . 15
Fairness of Proposed Sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Managing General Partner Benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Simultaneous Proposals to Companion Partnerships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
VOTING ON THE PROPOSAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Vote Required . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Solicitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
PARTNERSHIP BUSINESS AND FINANCIAL CONDITION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Cash Distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Transactions Between the Managing General Partner and the Partnership . . . . . . . . . . . . . . . . . . . 22
No Trading Market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Principal Holders of Investor Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Approvals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
SUMMARY OF FEDERAL INCOME TAX CONSEQUENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Taxable Gain or Loss Upon Sale of Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Liquidation of the Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Capital Gain Tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Passive Loss Limitations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
</TABLE>
(i)
<PAGE> 397
<TABLE>
<S> <C>
SELECTED FINANCIAL INFORMATION AND PROFORMA FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . 25
OFFERING OF SHARES OF SWIFT ENERGY COMPANY COMMON STOCKIF INVESTORS APPROVE THE PROPOSAL . . . . . . . . . . . . . . 26
Voting Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Offer of Swift Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Investor Election to Purchase Shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
New York Stock Exchange and Pacific Exchange Listings . . . . . . . . . . . . . . . . . . . . . . . 27
Closing Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Due Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Oversubscription . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Revocation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
FORM OF PROXY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (A)
</TABLE>
(ii)
<PAGE> 398
ATTACHMENT A
April 17, 1998
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Attn: Special Transactions Committee FAIR MARKET VALUE ESTIMATE
Board of Directors SWIFT ENERGY INCOME PARTNERS 1986-D LTD.
97-003-133
Gentlemen:
At your request, we have audited the proved, probable and possible reserves and
future net cash flow as of December 31, 1997, prepared by Swift Energy Company
("Swift") for certain interests owned by the partners in Swift Energy Income
Partners 1986-D Ltd. This audit has been conducted according to the Standards
Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information
approved by the Board of Directors of the Society of Petroleum Engineers on
October 30, 1979. We have reviewed these properties and where we disagreed
with the Swift reserve estimates, Swift revised its estimates to be in
agreement.
From this audit, and in consultation with J.R. Butler and Company, our estimate
of the fair market value of this partnership is $1,567,013.
Fair market value as used herein is defined as that price that a willing buyer
will pay and a willing seller will accept at a given point in time, with
neither the buyer nor the seller under any compulsion to buy or sell, and both
having reasonable knowledge of all the material circumstances.
To estimate the fair market value attributable to the proved developed
producing reserves, the 10 percent discounted future net cash flow was
multiplied by a suitable factor (less than one) to account for the risk
associated with the reserves, operating expenses, and prices and to approximate
tax consequences. The internal rate of return and payout time were computed for
this quantity and compared with those at which current acquisitions are
completed. Suitable adjustments are then made to correspond to these two
financial indices. Proved developed nonproducing, proved undeveloped, probable
and possible reserves require capital investments and must be treated
appropriately. For these cases, the capital is added to the discounted net cash
flow, then multiplied by a suitable risk factor and the capital then
subtracted. This has the effect that capital is spent with certainty and the
operating cash income is burdened with the risk. Internal rate of return and
payout time are calculated for each estimate to establish reasonableness based
upon the reserve category. The estimated future net cash flow is that cash flow
which will be realized from the sale of the estimated net reserves after
deduction of royalties, ad valorem and production taxes, direct operating
<PAGE> 399
Swift Energy Company -2- April 17, 1998
costs and capital expenditures, when applicable. Surface and well equipment
salvage values and well plugging and field abandonment costs have not been
considered in the cash flow projections. Future net cash flow as stated in
this report is before the deduction of federal income tax.
The following parameters are incorporated in the economic projections
referenced in this report. Initial oil prices are the existing prices on
December 31, 1997, and are escalated 3.5 percent per year beginning in 1999
through the year 2013 after adjusting for transportation and gravity variances.
Initial natural gas prices are those existing on December 31, 1997, and are
escalated 3.5 percent per year beginning in 1999 through the year 2013 after
adjusting for transportation and Btu content. Operating expenses are escalated
at an annual rate of 3.5 percent until the year 2013. The actual prices that
will be received and the associated costs may be more or less than those
projected.
For those wells with sufficient production history, reserve estimates and rate
projections are based on the extrapolation of established performance trends.
Reserves for other producing and nonproducing properties have been estimated
from volumetric calculations and analogy with the performance of comparable
wells. The reserves referenced in this study are estimates only and should not
be construed as exact quantities. Future conditions may affect recovery of
estimated reserves and cash flow, and all categories of reserves may be subject
to revision as more performance data become available. The proved reserves are
estimated in accordance with the definitions included in the Securities and
Exchange Commission Regulation S-X, Rule 4-10(a) except for the price and cost
escalations. The definitions are included in part as Attachment I. The probable
and possible reserves conform to the definitions approved by the Society of
Petroleum Engineers, Inc. The definitions are included as Attachment II.
Extent and character of ownership, oil and gas prices, production data, direct
operating costs, capital expenditure estimates and other data provided by Swift
have been accepted as represented. The production data available to us were
through the month of October 1997, except in those instances in which data were
available through December. Interim production to December 31, 1997, has been
estimated. Operating expenses as supplied by Swift were not audited, but were
reviewed for reasonableness. No independent well tests, property inspections or
audits of operating expenses were conducted by our staff in conjunction with
this study. We did not verify or determine the extent, character, obligations,
status or liabilities, if any, arising from any current or possible future
environmental liabilities that might be applicable.
In order to audit the reserves, costs and future cash flows referenced in this
report, we have relied in part on geological, engineering and economic data
furnished by our client. Although we have made a best efforts attempt to
acquire all pertinent data and to analyze it carefully with methods accepted by
the petroleum industry, there is no guarantee that the volumes of oil or gas or
the cash flows projected will be realized. The reserve and cash flow
projections referenced in this report may require revision as additional data
become available.
<PAGE> 400
Swift Energy Company -3- April 17, 1998
H.J. Gruy and Associates, Inc. is unrelated to Swift and has no interest in the
properties included in this report. In particular:
1. We do not own a financial interest in Swift or its oil and gas
properties.
2. Our fee is not contingent on the outcome of our work or report.
3. We have not performed other services for or have any other
relationship with Swift that would affect our independence.
4. No instructions were given and no limitations were imposed by
Swift on the scope or methodology to be used by us in preparing
such estimates; we did not accept or incorporate any assumptions
from Swift, but merely called upon Swift to the extent customary
in the oil and gas industry to gather and provide certain
background information which we determined to be relevant and
appropriate; we determined what information to use; and how and
to what extent such information should be relied upon in
estimating the fair market values shown above.
If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such person with the approval of our
client is invited to visit our offices at his expense so that he can evaluate
the assumptions made and the completeness and extent of the data available on
which our estimates are based.
Any distribution or publication of this report or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
James H. Hartsock, Ph.D., P.E.
Executive Vice President
JHH:akr
<PAGE> 401
ATTACHMENT I
DEFINITIONS OF PROVED OIL AND GAS RESERVES(1)
PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquid which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
PROVED DEVELOPED OIL AND GAS RESERVES
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be 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.
PROVED UNDEVELOPED RESERVES
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
- --------
(1) Contained in Securities and Exchange Commission Regulation S-X,
Rule 4-10(a)
H.J. GRUY AND ASSOCIATES, INC. 1200 Smith Street, Suite 3040,
Houston, Texas 77002 (713) 739-1000
<PAGE> 402
ATTACHMENT II
PETROLEUM RESERVES DEFINITIONS
SOCIETY OF PETROLEUM ENGINEERS (SPE) AND WORLD PETROLEUM CONGRESS (WPC)(1)
Reserves are those quantities of petroleum which are anticipated to be
commercially recovered from known accumulations from a given date forward. All
reserve estimates involve some degree of uncertainty. The uncertainty depends
chiefly on the amount of reliable geologic and engineering data available at the
time of the estimate and the interpretation of these data. The relative degree
of uncertainty may be conveyed by placing reserves into one of two principal
classifications, either proved or unproved. Unproved reserves are less certain
to be recovered than proved reserves and may be further sub-classified as
probable and possible reserves to denote progressively increasing uncertainty in
their recoverability.
The intent of the SPE and WPC in approving additional classifications beyond
proved reserves is to facilitate consistency among professionals using such
terms. In presenting these definitions, neither organization is recommending
public disclosure of reserves classified as unproved. Public disclosure of the
quantities classified as unproved reserves is left to the discretion of the
countries or companies involved.
Estimation of reserves is done under conditions of uncertainty. The method of
estimation is called deterministic if a single best estimate of reserves is made
based on known geological, engineering and economic data. The method of
estimation is called probabilistic when the known geological, engineering, and
economic data are used to generate a range of estimates and their associated
probabilities. Identifying reserves as proved, probable, and possible has been
the most frequent classification method and gives an indication of the
probability of recovery. Because of potential differences in uncertainty,
caution should be exercised when aggregating reserves of different
classifications.
Reserves estimates will generally be revised as additional geologic or
engineering data become available or as economic conditions change. Reserves do
not include quantities of petroleum being held in inventory, and may be reduced
for usage of processing losses if required for financial reporting.
Reserves may be attributed to either natural energy or improved recovery
methods. Improved recovery methods include all methods for supplementing natural
energy or altering natural forces in the reservoir to increase ultimate
recovery. Examples of such methods are pressure maintenance, cycling,
waterflooding, thermal methods, chemical flooding, and the use of miscible and
immiscible displacement fluids. Other improved recovery methods may be developed
in the future as petroleum technology continues to evolve.
PROVED RESERVES
Proved reserves are those quantities of petroleum which, by analysis of
geological and engineering data, can be estimated with reasonable certainty to
be commercially recoverable, from a given date forward, from known reservoirs
and under current economic conditions, operating methods, and government
regulations. Proved reserves can be categorized as developed or undeveloped.
If deterministic methods are used, the term reasonable certainty is intended to
express a high degree of confidence that the quantities will be recovered. If
probabilistic methods are used, there should be at least a 90% probability that
the quantities actually recovered will equal or exceed the estimate.
Establishment of current economic conditions should include relevant historical
petroleum prices and associated costs and may involve an averaging period that
is consistent with the purpose of the reserve estimate, appropriate contract
obligations, corporate procedures, and government regulations involved in
reporting these reserves.
In general, reserves are considered proved if the commercial producibility of
the reservoir is supported by actual production or formation tests. In this
context, the term proved refers to the actual quantities of petroleum reserves
and not just the productivity of the well or reservoir. In certain cases,
proved reserves may be assigned on the basis of well logs and/or core analysis
that indicate the subject reservoir is hydrocarbon bearing and is analogous to
reservoirs in the same area that are producing or have demonstrated the ability
to produce on formation tests.
The area of the reservoir considered as proved includes (1) the area delineated
by drilling and defined by fluid contacts, if any, and (2) the undrilled
portions of the reservoir that can reasonably be judged as commercially
productive on the basis of available geological and engineering data. In the
absence of data on fluid contacts, the lowest known occurrence of hydrocarbons
controls the proved limit unless otherwise indicated by definitive geological,
engineering or performance data.
- --------------------------
(1) Approved by the Board of Directors. Society of Petroleum Engineers (SPE),
Inc. on March 7, 1997.
<PAGE> 403
Reserves may be classified as proved if facilities to process and transport
those reserves to market are operational at the time of the estimate or there is
a reasonable expectation that such facilities will be installed. Reserves in
undeveloped locations may be classified as proved undeveloped provided (1) the
locations are direct offsets to wells that have indicated commercial production
in the objective formation, (2) it is reasonably certain such locations are
within the known proved productive limits of the objective formation, (3) the
locations conform to existing well spacing regulations where applicable, and (4)
it is reasonably certain the locations will be developed. Reserves from other
locations are categorized as proved undeveloped only where interpretations of
geological and engineering data from wells indicate with reasonable certainty
that the objective formation is laterally continuous and contains commercially
recoverable petroleum at locations beyond direct offsets.
Reserve which are to be produced through the application of established improved
recovery methods are included in the proved classification when (1) successful
testing by a pilot project or favorable response of an installed program in the
same or an analogous reservoir with similar rock and fluid properties provides
support for the analysis on which the project was based, and, (2) it is
reasonably certain that project will proceed. Reserves to be recovered by
improved recovery methods that have yet to be established through commercially
successful applications are included in the proved classification only (1) after
a favorable production response from the subject reservoir from either (a) a
representative pilot or (b) an installed program where the response provides
support for the analysis on which the project is based and (2) it is reasonably
certain the project will proceed.
UNPROVED RESERVES
Unproved reserves are based on geologic and/or engineering data similar to that
used in estimates of proved reserves; but technical, contractual, economic, or
regulatory uncertainties preclude such reserves being classified as proved.
Unproved reserves may be further classified as probable reserves and possible
reserves.
Unproved reserves may be estimated assuming future economic conditions different
from those prevailing at the time of the estimate. The effect of possible future
improvements in economic conditions and technological developments can be
expressed by allocating appropriate quantities of reserves to the probable and
possible classifications.
PROBABLE RESERVES
Probable reserves are those unproved reserves which analysis of geological and
engineering data suggests are more likely than not to be recoverable. In this
context, when probabilistic methods are used, there should be a least a 50%
probability that the quantities actually recovered will equal or exceed the sum
of estimated proved plus probable reserves.
In general, probable reserves may include (1) reserves anticipated to be proved
by normal step-out drilling where subsurface control is inadequate to classify
these reserves as proved, (2) reserves in formations that appear to be
productive based on well log characteristics but lack core data or definitive
tests and which are not analogous to producing or proved reservoirs in the area,
(3) incremental reserves attributable to infill drilling that could have been
classified as proved if closer statutory spacing had been approved at the time
of the estimate, (4) reserves attributable to improved recovery methods that
have been established by repeated commercially successful applications when (a)
a project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir characteristics appear favorable for commercial application, (5)
reserves in an area of the formation that appears to be separated from the
proved area by faulting and the geologic interpretation indicates the subject
area is structurally higher than the proved area, (6) reserves attributable to a
future workover, treatment, re-treatment, change of equipment, or other
mechanical procedures, where such procedure has not been proved successful in
wells which exhibit similar behavior in analogous reservoirs, and (7)
incremental reserves in proved reservoirs where an alternative interpretation of
performance or volumetric data indicates more reserves than can be classified as
proved.
POSSIBLE RESERVES
Possible reserves are those unproved reserves which analysis of geological and
engineering data suggests are less likely to be recoverable than probable
reserves. In this context, when probabilistic methods are used, there should be
a least a 10% probability that the quantities actually recovered will equal or
exceed the sum of estimated proved plus probable plus possible reserves.
In general, possible reserves may include (1) reserves which, based on
geological interpretations, could possibly exist beyond areas classified as
probable, (2) reserves in formations that appear to be petroleum bearing based
on log and core analysis but may not be productive at commercial rates, (3)
incremental reserves attributed to infill drilling that are subject to technical
uncertainty, (4) reserves attributed to improved recovery methods when (a) a
project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir
<PAGE> 404
characteristics are such that a reasonable doubt exists that the project will be
commercial, and (5) reserves in an area of the formation that appears to be
separated from the proved area by faulting and geological interpretation
indicates the subject area is structurally lower than the proved area.
RESERVE STATUS CATEGORIES
Reserve status categories define the development and producing status of wells
and reservoirs.
DEVELOPED: Developed reserves are expected to be recovered from existing
wells including reserves behind pipe. Improved recovery reserves are
considered developed only after the necessary equipment has been installed,
or when the costs to do so are relatively minor. Developed reserves may be
sub-categorized as producing or non-producing.
PRODUCING: Reserves subcategorized as producing are expected to be
recovered from completion intervals which are open and producing at the
time of the estimate. Improved recovery reserves are considered
producing only after the improved recovery project is in operation.
NON-PRODUCING. Reserves subcategorized as non-producing include shut-in
and behind-pipe reserves. Shut-in reserves are expected to be recovered
from (1) completion intervals which are open at the time of the
estimate but which have not started producing, (2) wells which were
shut-in for market conditions or pipeline connections (3) wells not
capable of production for mechanical reasons. Behind-pipe reserves are
expected to be recovered from zones in existing wells, which will
require additional completion work or future recompletion prior to the
start of production.
UNDEVELOPED RESERVES: Undeveloped reserves are expected to be recovered:
(1) from new wells on undrilled acreage, (2) from deepening existing wells
to a different reservoir, or (3) where a relatively large expenditure is
required to (a) recomplete an existing well or (b) install production or
transportation facilities for primary or improved recovery projects.
<PAGE> 405
ATTACHMENT B
APRIL 17, 1998
SWIFT ENERGY COMPANY
16825 Northchase Drive
Suite 400
Houston, Texas 77060
RE: FAIR MARKET VALUE OPINION
AS OF DECEMBER 31, 1997
SWIFT ENERGY INCOME PARTNERS
1986-D, LTD.
ATTENTION: SPECIAL TRANSACTIONS COMMITTEE
SWIFT ENERGY COMPANY BOARD OF DIRECTORS
At the request of SWIFT ENERGY COMPANY (SWIFT), J. R. BUTLER AND COMPANY
(JRBCo) has conducted an evaluation audit of the hydrocarbon reserves and
future net cash flow as of December 31, 1997, associated with 44 Acquisition
Programs located in the U.S.A. From this audit, and in consultation with H. J.
Gruy and Associates, Inc. (Gruy), JRBCo has generated its opinion of a "fair
market value" for these properties. The market values of the properties were
distributed to various partnerships based on ownership to determine the fair
market value of each partnership. In JRBCo's opinion, utilizing the
distribution of properties into the proper partnerships, the estimated market
value of Swift Energy Income Partners 1986-D, Ltd. is $1,567,013.
Proved reserves in this instance are defined as those estimated volumes of
crude oil, condensate, natural gas, and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty to be commercially
recoverable in the future from known reservoirs under a reasonable price and
cost escalation scenario. Probable reserves are the estimated quantities of
commercially recoverable hydrocarbons associated with known accumulations which
are based on engineering and geological data similar to those used in the
estimates of proved reserves but, for various reasons, these data lack the
certainty required to classify the reserves as proved. Possible reserves are
the estimated quantities of commercially recoverable hydrocarbons associated
with known accumulations, which are based on engineering and geological data
which are less complete and less conclusive than the data used in estimates of
probable reserves. In some cases, economic or regulatory uncertainties may
dictate a probable or possible classification.
<PAGE> 406
Recovery of proved reserves is not without risk but, as generally considered in
the industry, the risk of recovering probable reserves is substantially greater
than that associated with proved categories. Likewise, possible reserves are
less certain to be recovered than probable.
The reserves and future performance estimates were prepared utilizing standard
petroleum engineering methods. For properties with sufficient production
history, reserves estimates and rate projections were based primarily on
extrapolation of established performance trends and reconciled, whenever
possible, with volumetric and/or material balance calculations. For the
non-producing zones and undeveloped locations, reserves were determined by a
combination of volumetric calculations and analogy. Volumetrically determined
reserves or those determined by analogy are generally subject to greater
qualifications than reserves estimates supported by established production
decline curves and/or material balance calculations. Determination and
classification of proved reserves were performed (with exception of the use of
escalated prices and costs) in accordance with Securities and Exchange
Commission guidelines. The definitions used also conform to those promulgated
by the_Society of Petroleum Engineers (SPE) and the World Petroleum Congresses
(WPC).
The reserves and resulting "value estimates" included in this study are not
exact quantities. Future conditions may affect the recovery of estimated
reserves, revenue and net cash flow, and all categories of reserves may be
subject to revision and/or reclassification as more performance and well data
become available. Please note, the reserves estimates made by JRBCo were done
in conjuction with an evaluation audit and are not the result of in-depth field
studies. In conducting this audit JRBCo reviewed approximately 65% of SWIFT's
proved "PV10 value" (SEC PV10 as of December 31, 1997) for the total 44
Acquisition Programs.
Basic evaluation data were obtained principally from SWIFT and public sources.
The production data available to JRBCo were generally through August 1997.
Gas and liquid prices were year end (CY 1997) prices as used in SWIFT's
December 31, 1997, SEC cash flow runs.
Estimates of drilling, completion and workover costs were based on information
supplied by SWIFT. Operating costs were also based on data supplied by SWIFT
in their Lease Operating Statement which was reviewed by JRBCo. Surface and
well equipment salvage values and well plugging and field abandonment costs
were not considered in the revenue projections.
The estimates of future net cash flow used in market value calculations are
those revenues which should be realized from the sale of the estimated reserves
after deduction of royalties, ad valorem and production taxes, direct operating
costs and required capital expenditures, when applicable. Future net cash flow
as used in this evaluation is before the deduction of federal income tax.
2
<PAGE> 407
Market value estimates were obtained by applying qualitative risk adjustments
considered appropriate for the various reserves categories and "profit factors"
(as applicable) against discounted future net cash flow values obtained from an
escalated cost and pricing scenario. Prices, costs and investments were
escalated at 3.5%/year for 15 years. Final market value estimates were derived
in conjunction and consultation with Gruy.
In the conduct of our review, we have not independently verified the accuracy
and completeness of information and data furnished by SWIFT with respect to
ownership interests, oil and gas production volumes and rates, historical costs
of operation and development, product prices, agreements relating to current
and future operations and sales of production and other information relative to
such things as timing or scheduling of drilling or recompletion operations.
Field inspections were not made in connection with the preparation of this
report. Furthermore, no judgments were made relative to environmental or other
legal liabilities.
It should be recognized that any oil or gas reserves estimate or forecast of
production and income is a function of engineering and geological
interpretation and judgment. Such estimates should, therefore, be accepted and
used with the understanding that technical data, economic criteria or
regulatory information obtained subsequent to a study may justify revisions
which could increase or decrease the original estimates of reserves and value.
Neither JRBCo, nor any of its personnel, have any direct or indirect interest
in SWIFT or its affiliates. JRBCo is an independent consulting firm as
provided in the Standards Pertaining to the Estimating and Auditing of Oil and
Gas Reserves Information promulgated by the Society of Petroleum Engineers.
JRBCo's compensation is not contingent upon the results of its reserves
estimates, cash flow analyses or "market value opinion" which result from its
review of the subject properties.
READ AND APPROVED:
___________________________
BRIAN E. AUSBURN, PRESIDENT
DATE:______________________
BEA:mlc
3
<PAGE> 408
ATTACHMENT C
April 20, 1998
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, TX 77060
Attention: Special Transactions Committee
Swift Energy Company Board of Directors
Gentlemen:
Pursuant to that certain letter agreement dated February 27, 1998 (the
"Agreement") between the Special Transactions Committee (the "Committee") of
the Board of Directors of Swift Energy Company ("Swift" or the "Company") and
CIBC Oppenheimer Corp. ("CIBC Oppenheimer"), you have retained CIBC Oppenheimer
to prepare an independent financial analysis as to the estimated fair market
value (the "CIBC Oppenheimer Valuation") of various interests (the "Assets") in
oil and gas properties (the "Properties'), which Assets are owned by Swift
Energy Income Partners 1986-D, Ltd. (the "Partnership") of which the Company is
the managing general partner ("General Partner"). CIBC Oppenheimer performed a
similar analysis for 62 other partnerships (the "Partnerships") of which the
Company is the General Partner. It is CIBC Oppenheimer's understanding that the
General Partner has proposed to purchase substantially all of the Partnership's
Assets and, in turn, dissolve and wind up the Partnership. It is also CIBC
Oppenheimer's understanding that the Committee has also retained the reserve
engineering firms of H.J. Gruy & Associates, Inc. and J.R. Butler & Company
(collectively, the "Engineering Consultants") to prepare a separate analysis as
to the estimated fair market value of the Assets (the "Engineering Consultants'
Valuation").
In arriving at the CIBC Oppenheimer Valuation, we, among other things:
(i) Reviewed the historical financial returns to the limited
partners of the Partnership;
(ii) Held discussions with senior management of the Company as to
the Partnership's operational and financial prospects;
<PAGE> 409
Swift Energy Company
April 20, 1998
Page 2
(iii) Held discussions with senior management of the Company
regarding the general characteristics of the Properties
underlying the Assets, including location, productive
geological formations, future development potential and oil
and gas marketing arrangements;
(iv) Held discussions with the Engineering Consultants regarding
the general characteristics of the Properties underlying the
Assets, including location, productive geological formations
and future development potential;
(v) Reviewed the reserve engineering reports supplied to us by the
Engineering Consultants and, particularly, reviewed the
estimated future net cash flow to be generated from the
production of proved reserves of the Properties underlying the
Assets discounted to present value using an annual discount
rate of 10% (the "PV-10 Value") dated as of December 31, 1997;
these amounts were calculated net of estimated production
costs and future development costs, using prices and costs in
effect as of a certain date, without escalation and without
giving effect to non- property related expenses such as future
income tax expense or depreciation, depletion and
amortization;
(vi) Reviewed the Engineering Consultants' Valuation of the
Properties underlying the Assets;
(vii) Reviewed historical operating and financial results of the
Properties underlying the Assets which included PV-10 Value,
proved reserves on a barrel of oil equivalent ("BOE") basis
and projected earnings before interest, taxes and
depreciation, depletion and amortization ("EBITDA") as
prepared by the Engineering Consultants and discussed with
senior management of the Company;
(viii) Reviewed and analyzed financial terms of similar transactions
in which public oil and gas companies liquidated partnerships
of which they were the general partner;
(ix) Reviewed and analyzed transactions involving the sale of oil
and gas companies we deemed comparable to the Partnership(s)
individually and collectively and to the Company;
<PAGE> 410
Swift Energy Company
April 20, 1998
Page 3
(x) Reviewed and analyzed transactions involving the sale of oil
and gas properties we deemed comparable to the Properties
underlying the Assets;
(xi) Reviewed financial and market data for certain public
companies we deemed comparable to the Partnership(s)
individually and collectively and to the Company; and
(xii) Performed such other analyses and reviewed such other
information as we deemed appropriate.
In determining the CIBC Oppenheimer Valuation, we have relied upon and assumed,
without independent verification or investigation and at the direction of the
Committee, (i) the accuracy and completeness of all of the financial and other
information available to us from public sources or provided to us by the
Company and their representatives (including the Engineering Consultants), (ii)
that the reserve engineering reports supplied to us by the Engineering
Consultants as described in clause (v) above have been reasonably prepared and
are based on their best business judgment, (iii) that the information with
respect to the Partnership's ownership of the Assets, as provided to the
Engineering Consultants and to us was accurate in all respects, (iv) with
respect to the historical operating and financial results and projections
provided to us as described in clause and (vii) above, that such information
and projections were reasonably prepared and were based on the best currently
available information, estimates and good faith judgment of the Company's
management and their representatives (including the Engineering Consultants).
Not being experts in the geological evaluation of oil and gas reserves, we
have, with your consent, relied without independent verification upon the audit
of the reserve estimates prepared by the Engineering Consultants for the
purpose of estimating fair market value of the Assets. In addition, we have not
made a physical inspection of the Properties underlying the Assets, nor have we
made any independent evaluations, appraisals or inspections of the Company's or
the Partnership's other assets or the Company's or the Partnership's
liabilities (contingent or otherwise). We have not reviewed any relevant
agreements which may exist between the General Partner and the limited partners
governing the Partnership, nor have we considered the effect which the
ownership structure of the Partnership and the terms of the agreements of the
Partnership may have upon the fairness of the consideration offered by any
general partner of the Partnership. We have not reviewed the books and records
of the Partnership and have assumed, with
<PAGE> 411
Swift Energy Company
April 20, 1998
Page 4
your consent, that the Partnership's ownership interests in the Properties
underlying the Assets, as provided to us by you, is true and correct.
The CIBC Oppenheimer Valuation is based upon analyses of the foregoing factors
in light of our assessment of general economic, financial, market and other
conditions and circumstances as of the date of this letter and any changes in
such conditions and circumstances may affect the validity or fairness of the
CIBC Oppenheimer Valuation. CIBC Oppenheimer disclaims any obligations to
update, revise or reaffirm the CIBC Oppenheimer Valuation. The CIBC Oppenheimer
Valuation reflects our estimate of the consideration that could have been
received by the Partnership in a sale of the Assets in an orderly manner in a
private market transaction in which neither buyer nor seller is under any
compunction to complete such transaction. The CIBC Oppenheimer Valuation falls
within a range of values which we believe, subject to the foregoing conditions,
represent possible fair market value estimates of the Partnership's interest in
the Assets. The CIBC Oppenheimer Valuation should not be viewed as a guarantee
of the price that a willing buyer might have paid for the Assets.
CIBC Oppenheimer, as part of its investment banking services, is regularly
engaged in the valuation of businesses and securities in connection with
mergers, acquisitions, underwritings, sales and distributions of listed and
unlisted securities and private placements. CIBC Oppenheimer has provided
certain investment banking and financial advisory services to the Company from
time to time, including acting as co-manager of the Company's Convertible
Subordinated Notes financing in November 1996 and lead manager of the public
offering of the Company's Common Stock in July 1995, and may be involved in
future investment banking activities on behalf of the Company. CIBC Oppenheimer
will also receive a fee upon delivery of this CIBC Oppenheimer Valuation. In
the ordinary course of business, CIBC Oppenheimer actively trades in the equity
securities of the Company for CIBC Oppenheimer's own account and for the
accounts of CIBC Oppenheimer's customers and, accordingly, may at any time hold
a long or short position in such securities.
Based upon and subject to the foregoing, and based upon such other matters as
we consider relevant, it is CIBC Oppenheimer's estimate that the value of Swift
Energy Income Partners 1986-D, Ltd. interest in the Assets as of the date
hereof is $1,369,233.
This letter is being provided for the use of the Committee in its evaluation of
a possible proposal that the Partnership sell the Assets to the Managing
General Partner and dissolve and wind up its affairs. This letter is not
intended to confer rights or remedies
<PAGE> 412
Swift Energy Company
April 20, 1998
Page 5
upon any stockholder of the Company or any partner of the Partnership and may
not be relied upon by any person or entity other than the Committee. Neither
this letter nor the CIBC Oppenheimer Valuation may be published or otherwise
used or referred to, in whole or part, nor shall any public reference to CIBC
Oppenheimer, this letter or the CIBC Oppenheimer Valuation be made without the
prior written consent of CIBC Oppenheimer; provided, however, that the Company
and the Partnership may include a copy of this letter and a reference to CIBC
Oppenheimer in the proxy statement to be distributed to limited partners of the
Partnership in connection with the solicitation of the approval of the proposal
that the Partnership sell the Assets to the General Partner and dissolve and
wind up its affairs. Neither this letter nor the CIBC Oppenheimer Valuation
constitutes a recommendation to any partner of the Partnership as to how such
partner should vote on or respond to the proposal that the Partnership sell the
Assets to the General Partner and dissolve and wind up its affairs.
Sincerely yours,
CIBC Oppenheimer Corp.
By: _________________________
Executive Director
<PAGE> 413
ATTACHMENT D
February 10, 1998
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
SWIFT ENERGY INCOME PARTNERS 1986-D
97-003-133
Gentlemen:
At your request, we have made an audit of the reserves and future net cash flow
as of December 31, 1997, prepared by Swift Energy Company ("Swift") for certain
interests in Swift Energy Income Partners 1986-D. This audit has been conducted
according to the standards pertaining to the estimating and auditing of oil and
gas reserve information approved by the Board of Directors of the Society of
Petroleum Engineers on October 30, 1979. We have reviewed these properties and
where we disagreed with the Swift reserve estimates, Swift revised its
estimates to be in agreement. The estimated net reserves, future net cash flow
and discounted future net cash flow are summarized by reserve category in Table
1 for both the 100% Fund Level Partnership and the Limited Partnership
Interest.
The discounted future net cash flow is not represented to be the fair market
value of these reserves and the estimated reserves included in this report have
not been adjusted for risk.
The estimated future net cash flow shown is that cash flow which will be
realized from the sale of the estimated net reserves after deduction of
royalties, ad valorem and production taxes, direct operating costs and required
capital expenditures, when applicable. Surface and well equipment salvage
values and well plugging and field abandonment costs have not been considered
in the cash flow projections. Future net cash flow as stated in this report is
before the deduction of state and federal income tax.
In the economic projections, prices, operating costs and development costs
remain constant for the projected life of each lease.
The reserves included in this study are estimates only and should not be
construed as exact quantities. Future conditions may affect recovery of
estimated reserves and cash flow, and all categories of reserves may be subject
to revision as more performance data become available. Proved reserves are
estimated in accordance with the definitions contained in Securities and
Exchange Commission Regulation S-X, Rule 4-10 (a). The definitions are
included in part as Attachment I.
Extent and character of ownership, oil and gas prices, production data, direct
operating costs, capital expenditure estimates and other data provided by Swift
have been accepted as represented. The production data available to us were
through the month of October 1997, except in those instances in which data were
available through December. Interim production to December 31, 1997, has been
estimated. No independent well tests, property inspections or audits of
operating expenses were conducted by our staff in conjunction with this study.
We did not verify or determine the extent, character, obligations, status or
liabilities, if any, arising from any current or possible future environmental
liabilities that might be applicable.
<PAGE> 414
Swift Energy Company -2- February 10, 1998
In order to audit the reserves, costs and future net cash flows shown in this
report, we have relied in part on geological, engineering and economic data
furnished by our client. Although we have made a best efforts attempt to
acquire all pertinent data and to analyze it carefully with methods accepted by
the petroleum industry, there is no guarantee that the volumes of oil or gas or
the cash flows projected will be realized.
Production rates may be subject to regulation and contract provisions, and may
fluctuate according to market demand or other factors beyond the control of the
operator. The reserve and cash flow projections presented in this report may
require revision as additional data become available.
We are unrelated to Swift and we have no interest in the properties included in
the information reviewed by us. In particular:
1. We do not own a financial interest in Swift or its oil and gas
properties.
2. Our fee is not contingent on the outcome of our work or report.
3. We have not performed other services for or have any other
relationship with Swift that would affect our independence.
If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such person with the approval of our
client is invited to visit our offices at his expense so that he can evaluate
the assumptions made and the completeness and extent of the data available on
which our estimates are based.
Any distribution or publication of this report or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
James H. Hartsock, Ph.D., P.E.
Executive Vice President
JHH:llb
<PAGE> 415
TABLE 1
100% FUND LEVEL PARTNERSHIP INTEREST
<TABLE>
<CAPTION>
Estimated Estimated
Net Reserves Future Net Cash Flow
-------------------------------- ------------------------------
Oil & Discounted
Condensate at 10%
(Barrels) Gas(Mcf) Nondiscounted Per Year
----------- ------------ ------------- -----------
<S> <C> <C> <C> <C>
Proved Developed 69,143 1,704,998 $ 4,669,352 $ 2,015,306
Proved Undeveloped 11,550 371,695 $ 627,863 $ 311,704
----------- ----------- ----------- -----------
TOTAL PROVED 80,693 2,076,693 $ 5,297,215 $ 2,327,010
G & A $ (667,450) $ (293,750)
----------- ----------- ----------- -----------
TOTAL 80,693 2,076,693 $ 4,629,765 $ 2,033,260
</TABLE>
LIMITED PARTNERSHIP INTEREST
<TABLE>
<CAPTION>
Estimated Estimated
Net Reserves Future Net Cash Flow
-------------------------------- ------------------------------
Oil & Discounted
Condensate at 10%
(Barrels) Gas (Mcf) Nondiscounted Per Year
----------- ------------ -------------- -----------
<S> <C> <C> <C> <C>
Proved Developed 62,228 1,534,498 $ 4,197,634 $ 1,811,332
Proved Undeveloped 10,395 334,525 $ 536,864 $ 254,116
----------- ----------- ----------- -----------
TOTAL PROVED 72,623 1,869,023 $ 4,734,498 $ 2,065,448
G & A $ (596,548) $ (260,769)
----------- ----------- ----------- -----------
TOTAL 72,623 1,869,023 $ 4,137,950 $ 1,804,679
</TABLE>
<PAGE> 416
ATTACHMENT I
DEFINITIONS OF PROVED OIL AND GAS RESERVES(1)
PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquid which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
PROVED DEVELOPED OIL AND GAS RESERVES
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be 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.
PROVED UNDEVELOPED RESERVES
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
- --------
(1) Contained in Securities and Exchange Commission Regulation S-X,
Rule 4-10(a)
H.J. GRUY AND ASSOCIATES, INC. 1200 Smith Street, Suite 3040,
Houston, Texas 77002 (713) 739-1000
<PAGE> 417
SAMPLE
FORM OF PROXY
SWIFT ENERGY INCOME PARTNERS 1986-D, LTD.
THIS PROXY IS SOLICITED BY THE MANAGING GENERAL PARTNER FOR A
SPECIAL MEETING OF LIMITED PARTNERS TO BE HELD ON _________, 1998
The undersigned hereby constitutes and appoints A. Earl Swift, Bruce
H. Vincent, Terry E. Swift or John R. Alden, duly authorized officers of Swift
Energy Company acting in its capacity as Managing General Partner of the
Partnership, or any of them, as Proxies, each with full power to appoint his
substitute, and hereby authorizes the Proxies or any of them to represent the
undersigned at a Special Meeting of the Limited Partners (the "Meeting") of
SWIFT ENERGY INCOME PARTNERS 1986-D, LTD. (the "Partnership") to be held on
__________, 1998 at 4:00 p.m. Houston time, at 16825 Northchase Drive, Houston,
Texas, and any adjournments thereof, and to vote as designated, on the matter
specified below, the Partnership Units standing in the name of the undersigned
on the books of the Partnership (or which the undersigned may be entitled to
vote) on the record date for the Meeting, and hereby revokes any proxy or
proxies heretofore given by the undersigned.
<TABLE>
<S> <C> <C> <C>
1. The adoption of a proposal FOR AGAINST ABSTAIN
("Proposal") for the sale of
substantially all of the assets of [ ] [ ] [ ]
the Partnership to the Managing
General Partner and the dissolution,
winding up and termination of the
Partnership. The undersigned hereby
directs said proxies to vote:
</TABLE>
2. In their discretion, the proxies are authorized to vote upon such other
matters as may properly come before the meeting or any adjournments or
postponements thereof.
THIS PROXY WHEN PROPERLY EXECUTED, WILL BE VOTED IN ACCORDANCE WITH
THE DIRECTIONS MADE HEREON. IF NO DIRECTION IS MADE, IT WILL BE VOTED FOR THE
PROPOSAL.
Receipt of the Partnership's Notice of Special Meeting of Limited
Partners and Proxy Statement dated ________, 1998 is acknowledged.
PLEASE SIGN EXACTLY AS NAME APPEARS BELOW AND RETURN THE PROXY IN THE
ENCLOSED, POSTAGE-PAID, PRE-ADDRESSED ENVELOPE BY __________, 1998.
<TABLE>
<S> <C>
SIGNATURE DATE
-------------------------------------------------- ------------------------------
SIGNATURE DATE
-------------------------------------------------- ------------------------------
SIGNATURE DATE
-------------------------------------------------- ------------------------------
</TABLE>
IF LIMITED PARTNERSHIP UNITS ARE HELD JOINTLY, ALL JOINT TENANTS MUST
SIGN. WHEN SIGNING AS ATTORNEY, EXECUTOR, ADMINISTRATOR, TRUSTEE OR GUARDIAN,
PLEASE GIVE FULL TITLE AS SUCH. IF A CORPORATION, PLEASE SIGN IN FULL
CORPORATE NAME BY PRESIDENT OR OTHER AUTHORIZED OFFICER. IF A PARTNERSHIP,
PLEASE SIGN IN PARTNERSHIP NAME BY AUTHORIZED PERSON.
<PAGE> 418
[REPRESENTS INITIAL FILING WITH SEC]
SWIFT ENERGY OPERATING PARTNERS 1992-B, LTD.
(THE "PARTNERSHIP")
SUPPLEMENT
TO
JOINT PROXY STATEMENT/PROSPECTUS
DATED ________, 1998
SPECIAL MEETINGS OF THE PARTNERSHIPS
AND
OFFERING OF COMMON STOCK OF
SWIFT ENERGY COMPANY
For the definition of capitalized terms herein which are not otherwise
defined, see "Glossary" in the Joint Proxy Statement/Prospectus. Other
discussions which are cross-referenced in this Supplement are contained in the
Joint Proxy Statement/Prospectus, unless otherwise noted.
Swift Energy Company ("Swift" or the "Company") is the Managing
General Partner ("Managing General Partner") of 63 Texas limited partnerships
(the "Partnerships"), including the Partnership, formed between 1986 and 1994
to invest in producing oil and gas properties. Swift is asking interest
holders (referred to herein as "Investors") in the Partnership (and similarly
in the other 62 Partnerships) to approve a Proposal to sell all of the
Partnership's oil and gas assets to the Managing General Partner (the
"Proposal") for $2,426,749, which is a purchase price derived by choosing the
higher of two estimates of fair market value of those assets determined by
three independent Appraisers, and adding to that higher number a 7.5% premium.
If the Proposal is approved by Investors in the Partnership and its
Companion Partnership, after the sale of all of its oil and gas assets the
Partnership will dissolve, wind up and terminate. The Partnership will receive
cash for its oil and gas assets, which in turn is to be distributed to the
Investors in the Partnership (along with the net of all assets less liabilities
of the Partnership) in accordance with their respective percentage ownership
interests in the Partnership. If Investors in the Partnership approve the
Proposal, then each Investor can elect, in their sole individual discretion, to
receive shares of Common Stock of the Company (without payment of any brokerage
commissions) instead of some or all of the cash which they are entitled to
receive upon the Partnership's liquidation.
The reasons for and effects of the Proposals may be different for
investors in each of the Partnerships. This Supplement has been prepared to
highlight for the Investors in the Partnership the particular risks, effects
and fairness of the Proposal to the Investors in the Partnership and to provide
<PAGE> 419
information on the Partnership to its Investors, in connection with the
solicitation of proxies by the Managing General Partner for use at the Special
Meeting of the Investors in the Partnership in voting upon the Proposal and to
transact such other business as may be properly presented at the Special
Meeting or any adjournments or postponements thereof.
BOTH THE VOTE UPON THE PROPOSAL AND ANY ELECTION MADE BY AN INDIVIDUAL
INVESTOR TO RECEIVE SHARES OF SWIFT ENERGY COMPANY COMMON STOCK ARE SUBJECT TO
NUMEROUS RISK FACTORS, INCLUDING THOSE HIGHLIGHTED BELOW. SEE "RISK FACTORS"
IN THIS SUPPLEMENT AND IN THE JOINT PROXY STATEMENT/PROSPECTUS FOR A FULL
DISCUSSION OF ALL RISK FACTORS.
o Substantial conflicts of interest exist because if the Proposal is
approved by the Partnership and its Companion Partnership, the
Managing General Partner will purchase all of the oil and gas assets
from the Partnership while it serves as its Managing General Partner.
o The purchase price for the Partnership's Property Interests may not be
the highest possible price.
o No independent representative negotiated the terms of the purchase
price with the Managing General Partner.
o No fairness opinion was acquired regarding the fairness of the
purchase price.
o The Managing General Partner may profit from acquisition of the
Partnership's oil and gas assets by investing capital in order to
develop non-producing reserves of the acquired Property Interests and
possibly through improvements in oil and gas prices.
o Estimates of distributions to Investors from continuing operations of
the Partnership for the life of its reserves are higher than amounts
anticipated to be received if Investors vote in favor of the Proposal.
See "Special Factors--Fairness of Proposal of Sale of Assets as
Compared to Continuing Operations."
o An election by an Investor to receive shares of Swift Common Stock in
lieu of cash distributable to Investors subjects such Investors to the
risks of investing in the Company.
This Supplement is dated ______________, 1998
2
<PAGE> 420
THE PARTNERSHIP
The Partnership was formed over six years ago and owns working
interests in producing oil and gas properties in five states in which its
companion partnership, Swift Energy Pension Partners 1992-B, Ltd. ("Companion
Partnership"), formed at approximately the same time and also managed by the
Managing General Partner, owns the non-operating interests. The Partnership had
expended all of its original capital contributions by the end of July 1992.
The Partnership's oil and gas properties are principally natural gas
properties, representing approximately 85% of the Partnership's 1997 production
and approximately 93% of its total proved reserves at December 31, 1997. The
Partnership has, from time to time, performed workovers and recompletions on
wells in which the Partnership has Property Interests, using funds advanced by
the Managing General Partner to perform these operations, which amounts have
been subsequently repaid. The Partnership owns interest in 315 wells in 18
fields.
The following table presents information on those fields in which the
Partnership has Property Interests which constitute 10% or more of the
Partnership's PV-10 Value at December 31, 1997. The Partnership's "PV-10
Value" is the estimated future net cash flows (using unescalated prices) from
production of proved reserves attributed to the Partnership's Property
Interests, discounted to present value at 10% per annum. Attachment D to this
Supplement is the report dated February 10, 1998 of the audit by H.J. Gruy and
Associates, Inc., Independent Petroleum Consultants, of the oil and gas
reserves underlying the Partnership's Property Interests, and future net cash
flow expected from the production of those reserves as of December 31, 1997,
presented both for the Partnership as a whole and as to those reserves solely
attributable to the Investors in the Partnership. This report has not been
updated to include the effect of production since year-end 1997. In estimating
these reserves, the Managing General Partner, in accordance with criteria
prescribed by the Securities and Exchange Commission, has used year-end 1997
prices, without escalation, except in those instances where fixed and
determinable gas price escalations are covered by contracts, limited to the
price the Partnership reasonably expects to receive. The Managing General
Partner is not aware of any favorable or adverse event causing a significant
change in the estimated amount (as set forth in Attachment D hereto, which is
the report of H.J. Gruy and Associates, Inc.) of proved reserves of the
properties in which the Partnership owns an interest has occurred between
December 31, 1997 and the date of this Supplement.
The information below includes the location of each field in which the
Partnership has an interest, the number of wells and operators, together with
information on the percentage of the Partnership's total PV-10 Value on
December 31, 1997 attributable to each of these fields. Information is also
provided regarding the percentage of the Partnership's 1997 production (on a
volumetric basis) from each of these fields. Of the remaining other fields in
which the Partnership owns a Property Interest, eleven of such fields each
comprise less than 1% of the Partnership's PV-10 Value at December 31, 1997,
and the PV-10 Value of each of the other five fields averages less than 4% of
the Partnership's PV-10 Value at the same date.
3
<PAGE> 421
<TABLE>
<CAPTION>
16
WEATHERFORD EAKLY OTHER
FIELD FIELD FIELDS
-----------------------------------------
<S> <C> <C> <C>
County and State Custer & Custer & LA (1)
Caddo Caddo MS (1)
Counties, Counties, OK (8)
Oklahoma Oklahoma TX (5)
WY (1)
Number of Wells 49 59 207
Operator(s) Swift and Swift and Swift and
11 others 15 others 7 others
% of 12/31/97 PV-10 Value 44% 33% 23%
% of 1997 Production Volumes 36% 29% 35%
</TABLE>
The Partnership's total assets at year-end 1997 were $3,205,916 and
the PV-10 Value of its total proved reserves at the same date was $3,357,192.
Based upon the audit of the Partnership's Total Proved Reserves at year-end
1997, those reserves were comprised of the following three categories:
Proved Producing(1) 67%
Behind-Pipe(2) 20%
Non-Developed(3) 13%
---
100%
===
- --------------
(1)Proved producing reserves are reserves that can be expected
to be recovered through existing wells with existing equipment and operating
methods.
(2) Behind-pipe reserves are proved reserves that will not contribute
to cash flows until recompletion projects have been implemented to place them
into production. The impact of these recompletion projects will also be limited
until the costs of implementation have been recovered. In general, it is not
appropriate to bring behind-pipe reserves into production until the formation
that is currently producing has been depleted. Premature recompletions can lead
to permanent reductions in a well's proved reserves.
(3)Non-developed reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Therefore,
significant additional expenditures are usually required before undeveloped
reserves can be produced.
Attachment Dis the annual reserves audit and independent reserves
report prepared by H.J. Gruy and Associates, Inc. as to the Partnership's
remaining proved oil and gas reserves available for production over a period in
excess of 15 years. These quantities have been given a value based
4
<PAGE> 422
upon prices for oil and gas at December 31, 1997. The value is determined
based upon the assumption that these prices will remain in effect over the life
of these reserves. This value is then discounted at 10% per year to arrive at
the value (in today's dollars) of these revenues ("PV-10 Value"). This PV-10
Value for the Partnership's Property Interests is $3,357,192. It is also
estimated that $241,771 in future capital costs must be spent to develop the
Partnership's non-producing reserves.
RISK FACTORS
o Although the fair market value of the Property Interests proposed to
be purchased from the Partnership by the Managing General Partner was
based upon a determination by three independent Appraisers, no opinion
was acquired as to the fairness of the ultimate purchase price, which
was determined in the Managing General Partner's sole judgment by
adding a 7.5% premium over the higher of the two fair market value
estimates for the Partnership's Property Interests determined by the
Appraisers. Therefore, the purchase price was not determined on an
impartial basis by a party not involved in the transaction, and
another party intent upon purchasing the Property Interests in the
Partnership might have offered a different purchase price. There is
no guarantee that the purchase price represents the highest possible
price that could be received for the Partnership's Property Interests
in all circumstances. It is possible that a higher (or lower) price
might be received if these assets were sold on another basis, such as
at auction or in negotiated sales. Furthermore, the assessment of the
value of the Partnership's proved non-producing reserves could vary
widely, given the typical discounting in valuing non-producing
reserves.
o The Managing General Partner did not retain an independent
representative to act on behalf of the Investors in the Partnership in
structuring and negotiating the terms or price of the Proposal or the
purchase price. The price at which it is proposed that the Company
purchase the Property Interests from the Partnership has not been
negotiated at arm's length and is subject to significant conflicts of
interest between the Company acting as the purchaser of such
properties while serving as the Managing General Partner of the
Partnership. If an independent representative had been retained for
the Partnership, the terms or price might have been different and
possibly more favorable to Investors.
o The fair market value (excluding the 7.5% premium) established for the
Partnership's Property Interests is based upon the Appraisers'
evaluation of that value. Year-end 1997 prices, along with other
current market factors, were used as a starting point for the
Appraisers' analysis, and prices and costs were then escalated at a
rate of 3.5% per year over 15 years. Substantial increases in the
prices for oil and gas in the future might result in Investors
receiving higher distributions from continued operations of the
Partnership, although the effect of any higher prices is somewhat
limited because the Partnership has already produced a substantial
majority of its oil and gas reserves.
5
<PAGE> 423
o In order to effectuate the sale of its Property Interests, the
Proposal must not only be approved by the Partnership, but a similar
Proposal must be approved by the Companion Partnership. This
requirement exists because of the significant lowering of the value of
either (i) a working interest burdened by a large non- operating
interest controlled by a different party, or (ii) a non-operating
interest in properties the operations of which are controlled by a
third party. Therefore, even if the Investors in the Partnership
approve the Proposal to sell their Property Interests, this may not be
done without the approval of a similar Proposal by investors in the
Companion Partnership. If either Partnership does not approve its
Proposal, then the Managing General Partner will reassess the value
of the Property Interests of each Partnership and attempt to formulate
a new proposal for the investors in each such Partnership.
o Investors that are subject to federal income tax on an investment in
the Partnership are required to recognize gain or loss on the sale of
oil and gas assets by the Partnership and the subsequent liquidation
of the Partnership. The amount and character of the gain or loss
depends on certain factors specific to individual Investors. It is
anticipated that Investors that acquired their interests in the
original offering and that are subject to federal income tax will
recognize a loss for federal income tax purposes. Any tax that may be
due must be paid even if such Investors choose to acquire Company
Common Stock with some or all of their proceeds from property sales.
Investors also should consult their individual tax advisors to
determine whether they are subject to any state tax. For a broader
discussion of the tax consequences, Investors should read "Federal
Income Tax Consequences of Adoption of the Proposals" in the Joint
Proxy Statement/Prospectus, and "Summary of Federal Income Tax
Consequences" in this Supplement.
o Investors that are Tax Exempt Plans will be subject to taxation on the
Partnership's sale of property and the liquidation of the Partnership,
while other Tax Exempt Plans are not expected to be subject to
taxation on the sale and liquidation. It is anticipated that Tax
Exempt Plans that acquired their interests in the original offering
will recognize a loss for federal income tax purposes. See "Summary
of Federal Income Tax Consequences--Tax Treatment of Tax Exempt
Plans--Debt-Financed Property" in this Supplement.
o As currently proposed, Investors that subscribe for Company Common
Stock pursuant to this Offering may not receive some or all of the
cash which otherwise would be distributed to them as part of the
liquidating distribution of their Partnership. The amount of any cash
liquidating distribution they actually receive depends upon the
purchase price to be paid for any Company Common Stock they elect to
and are entitled to receive pursuant to the terms of this Offering.
For federal income tax purposes, Investors subscribing for shares of
Company Common Stock will be treated as though they had purchased
those shares for cash, even though they never had actual possession of
the cash used to acquire the shares. Additionally, the fact that such
Investors elect to acquire Company Common Stock rather than receive
cash in liquidation of their Partnership interests will not affect the
federal income tax consequences attending the liquidation of their
Partnership interests. Because
6
<PAGE> 424
the purchase of shares of Company Common Stock will reduce the cash
received by Investors upon the Partnership's liquidation, to the
extent that Investors owe federal income tax as a result of the
liquidation, they may not receive sufficient cash to pay some or all
of any tax they may owe on the liquidation. Such Investors owing tax
as a result of the liquidation will have to pay such tax from sources
other than any cash liquidating distribution from the Partnership.
See "Risk Factors" in the Joint Proxy Statement/Prospectus.
CONFLICTS OF INTEREST
There are substantial conflicts of interest which exist by virtue of
the Managing General Partner acting in that capacity on behalf of the
Partnership while at the same time acting as the proposed purchaser of all of
the oil and gas assets of the Partnership. These conflicts of interest are
discussed below.
o The terms of the Proposal are established by the Company which is also
the Managing General Partner of the Partnership.
o Neither the Managing General Partner nor a majority of its independent
directors retained an independent representative to act on behalf of
the Partnership's Investors for the purposes of negotiating the terms
upon which any such sale to the Managing General Partner would be made
or for the preparation of a report concerning the fairness of the
entire transaction.
See "Summary--Conflicts of Interest" and "Conflicts of Interests" in the Joint
Proxy Statement/Prospectus.
SPECIAL FACTORS
BACKGROUND AND PURPOSE OF THE PROPOSAL
A number of factors have led to the decision of the Company in its
capacity as Managing General Partner to solicit approval of the Proposal by
Investors in the Partnership. The general improvement in the prices for
natural gas over the last several years, relative to such prices in the
mid-1990's, make this an appropriate time, especially in light of the high
percentage of the Partnership's reserves comprised of natural gas, to consider
the Proposal to sell the Partnership's Property Interests. The structure being
proposed, which involves the sale of the Partnership's oil and gas assets to
the Managing General Partner, is being submitted for approval by Investors in
an attempt to realize the highest value for those assets. For the reasons set
out below, the Managing General Partner believes that the Proposal is fair to
Investors in the Partnership, given
7
<PAGE> 425
that the purchase price for these assets has been determined by taking the
higher of two fair market value estimates by three independent Appraisers and
adding to it a 7.5% premium.
Approval of the Proposal will have the following effects:
1. The Managing General Partner will purchase all of the oil and gas
assets of the Partnership, provided its Companion Partnership has
approved its proposal.
2. When the Partnership sells all of its oil and gas assets, it will be
required to liquidate and distribute its remaining assets (principally
the cash proceeds from the sale) to its partners (including the
general partners) in accordance with their respective ownership
interests in the Partnership.
3. Investors will be given the option of electing to receive shares of
Swift Common Stock, in amounts that they choose on an individual
basis, in lieu of some or all of the cash they would be entitled to
receive upon the Partnership's liquidation.
4. Investors in the Partnership will be taxed on the sale of the
Partnership's oil and gas assets, although such sale is expected to
result in a taxable loss to Investors that acquired their interests in
the original offering.
PROPOSED PURCHASE PRICE
As discussed in greater detail below, the Petroleum Engineering
Consultants estimated that the aggregate fair market value of the Partnership's
Property Interests as of December 31, 1997 is $2,257,441. CIBC Oppenheimer
estimated a fair market value of the same Property Interests at the same date
of $2,118,171. The Special Transactions Committee chose the higher of these
two determinations as the "Fair Market Value" for the purchase of these
interests and the Board of Directors of the Company determined to pay a 7.5%
premium ($169,308) above the Fair Market Value to purchase the Partnership's
Property Interests, resulting in a purchase price of $2,426,749. This compares
to the total purchase price for all of the oil and gas assets of all 63
Partnerships which are considering similar proposals of approximately $81
million. The valuation estimates of the Appraisers are attached to this
Supplement and incorporated herein by reference as follows: Attachment A is
the fair market value estimate of H.J. Gruy and Associates, Inc., Attachment B
is the fair market value estimate of J.R. Butler and Company, and Attachment C
is the fair market value estimate of CIBC Oppenheimer Corp. The PV-10 Value
prepared on an annual basis by H.J. Gruy of the same Property Interests as of
the same date is $3,357,192.
8
<PAGE> 426
REASONS FOR THE PROPOSAL
The Managing General Partner believes that it is in the best interest
of the Investors for the Partnership to sell its Property Interests at this
time and to dissolve the Partnership and make a final liquidating distribution
to its partners for the reasons discussed below.
Current Liquidating Distribution Lowers Volatility Risk. The
Partnership has been in existence for over six years. The Managing General
Partner believes that the ability to receive the estimated liquidating
distribution in one lump sum at this time, rather than in smaller amounts over
a longer period, is one of the benefits of the Proposal, without the risk of
such distributions being negatively affected by oil and gas price decreases and
the inherent risks associated with geological, engineering and operational
matters. It is also the Managing General Partner's belief that improvements
over the last several years in the level of gas prices, relative to such prices
in the mid-1990s, makes this an appropriate time to consider the sale of the
Partnership's Property Interests and increases the likelihood of maximizing the
value of the Partnership's assets, although the future prices and market
volatility cannot be predicted with any accuracy.
Decreasing Cash Flow While Expenses Continue. The Partnership's oil
and gas reserves are expected to continue to decline as remaining reserves are
produced. Declines in well production are based principally upon the maturity
of the wells, not on market factors. These declines will continue to occur
while oil field overhead and operating costs ($80,445 in 1997) and direct and
general and administrative expenses ($160,174 in 1997) continue, which are
relatively fixed amounts. Each producing well requires a certain amount of
overhead costs, as operating and other costs are incurred regardless of the
level of production. Likewise, direct costs and/or general and administrative
expenses, such as compliance with the securities laws, producing reports to
partners and filing partnership tax returns, do not decline as revenues
decline. By accelerating the liquidation of the Partnership, those future
administrative costs will be avoided by the Partnership.
Interest Holders' Tax Reporting. Each Investor will continue to have
an income tax reporting obligation with respect to his SDIs as long as the
Partnership continues to exist. There is no trading market for the SDIs, so
Investors generally are unable to dispose of their SDIs. See "Partnership
Business and Financial Condition--No Trading Market" in this Supplement.
Following the sale of the Partnership's Property Interests and dissolution of
the Partnership, Investors will realize gain or loss under federal income tax
laws. See "Summary of Federal Income Tax Consequences--Taxable Gain or Loss
upon Sale of Properties" in this Supplement. Thereafter, Investors will have
no further tax reporting obligations with respect to the Partnership. See
"Summary of Federal Income Tax Consequences--Liquidation of the Partnership" in
this Supplement.
See "Summary--Background of the Proposals," "--Purpose and Effect of the
Proposals," "--Reasons for the Proposals" and "--Managing General Partner's
Recommendations" in the Joint Proxy Statement/Prospectus.
9
<PAGE> 427
COLLECTIVE ANALYSIS OF PURCHASE PRICE; PREMIUM OVER FAIR MARKET VALUE
The Special Transactions Committee selected H.J. Gruy and Associates,
Inc. ("H.J. Gruy" or "Gruy"), J.R. Butler and Company ("J.R. Butler" or
"Butler"), which are both petroleum engineering consultants, and CIBC
Oppenheimer Corp. ("CIBC Oppenheimer"), an investment banking firm, to
estimate the fair market value of the Property Interests of each of the
Partnerships. Collectively, H.J. Gruy, J.R. Butler and CIBC Oppenheimer are
referred to herein as the "Appraisers," and H.J. Gruy and J.R. Butler together
are sometimes referred to herein as the "Petroleum Engineering Consultants."
The following subsections of the "Special Factors" section of the
Joint Proxy Statement/Prospectus should be reviewed for information concerning
the selection and qualification of the Appraisers and the parameters of the
valuation estimates: "Independent Appraisal of the Fair Market Value of
Property Interests of the Partnerships," "Qualification of Appraisers," and
"Fair Market Value."
The Petroleum Engineering Consultants arrived at a fair market
valuation estimate based upon appraisal of the projected discounted cash flow
from its various Property Interests. On the other hand, the investment banking
firm of CIBC Oppenheimer made a valuation estimate of the Partnership's
Property Interests based upon the application of multiple quantitative and
qualitative factors. The quantitative factors include, among other things, a
review of relevant valuation criteria from comparable acquisitions of both oil
and gas properties and companies that are predominantly active in the oil and
gas industry, and a review of valuation criteria for relevant publicly traded
oil and gas companies.
The process used by the Petroleum Engineering Consultants in preparing
their valuation estimate is discussed at length in the Joint Proxy
Statement/Prospectus under "Special Factors--Valuation by Petroleum Engineering
Consultants." As described therein, the Petroleum Engineering Consultants
individually audited the estimate of present value of future net cash flows
from the 44 property groups in which Property Interests are owned by the
Partnerships to whom similar proposals are being made to sell all of their oil
and gas assets and liquidate their Partnerships. The Partnership owns Property
Interests in six of these property groups. The Petroleum Engineering
Consultants began their analysis based upon the year-end 1997 PV-10 Value of
each property audited by H.J. Gruy and together they re-evaluated reserve
quantities, projected operating costs and cash flows. The present value of
this reserves analysis was then derived by escalating year-end 1997 prices
($2.38 per MMBtu and $16.00 per barrel before adjustments for Btu content for
gas and gravity variances for oil as well as transportation charges and
geographic location) and costs by 3.5% per year for 15 years. This present
value was then adjusted for various individual field risks and risk adjustments
of proved non- producing reserves and proved undeveloped reserves. The result
of this collective analysis by the Petroleum Consulting Engineers was their
estimation that the fair market value of Property Interests owned by the
Partnership was $2,257,441 as of December 31, 1997.
10
<PAGE> 428
The methodology used by CIBC Oppenheimer to prepare its valuation
estimate is discussed at length under "Special Factors--Valuation by CIBC
Oppenheimer" in the Joint Proxy Statement/Prospectus. CIBC Oppenheimer's
evaluation of the Partnership's Property Interests began with the PV-10 Value
of each property group, as calculated by Swift and audited by H.J. Gruy which
Gruy report dated February 10, 1998 is Attachment D to this Supplement. CIBC
Oppenheimer then divided the property groups into two categories. Those
property groups with reserves consisting primarily of proved developed
producing reserves were placed in the "Conventional Case" category. Those
property groups with significant proved developed non-producing or undeveloped
reserves were placed in the "Non-Conventional Case" category. The Partnership
has interests in property groups which were in only the "Conventional Case"
category. [VARIABLE SENTENCE (CODED FIELD) RE EACH P'SHIP'S CASE CATEGORY]
CIBC Oppenheimer then valued each property group by applying the multiples
discussed under "Special Factors--Valuation by CIBC Oppenheimer--Valuation
Multiples" in the Joint Proxy Statement/Prospectus to each property group's
PV-10 Value, proved reserves on a BOE basis, and projected 1998 EBIDTA. A
separate set of multiples was used for property groups in the Conventional Case
category and the Non-Conventional Case category, respectively. This provided
CIBC Oppenheimer with three estimated values for each property group. The
average of these three values yielded CIBC Oppenheimer's estimation of the fair
market value of each property group. CIBC Oppenheimer then allocated the
appropriate portion of each property group's estimated fair market value to the
Partnership based upon the Partnership's Property Interests in each property
group. The result of this analysis by CIBC Oppenheimer was an estimation that
the fair market value of the Partnership's Property Interests was $2,118,171 on
December 31, 1997.
The Special Transactions Committee has determined that, in keeping
with the definition of Fair Market Value, the higher of these two estimations
of fair market value, or $2,257,441, represents the Fair Market Value of the
Partnership's Property Interests. Accordingly, the fair market value
estimation of the Petroleum Consulting Engineers and the fair market value
determined by CIBC Oppenheimer were compared to each other and the higher of
the two was chosen as the Fair Market Value of the Property Interests owned by
the Partnership. The variation between the fair market value estimate of the
Partnership's Property Interests prepared by the Petroleum Consulting
Engineers, on one hand, and CIBC Oppenheimer on the other was 7%.
DETERMINATION OF PREMIUM OVER FAIR MARKET VALUE BY THE COMPANY
The Special Transactions Committee presented its recommendation to the
Board of Directors of the Company as to the Fair Market Value of the Property
Interests of the Partnership. The Board of Directors of the Company then
determined that paying a 7.5% premium over the Fair Market Value of the
Partnership's Property Interests was appropriate and fair based upon the
factors and for the reasons discussed below. Because the Company has served as
Managing General Partner of the Partnership for over six years, it is
intimately familiar with the Property Interests owned by the Partnership. The
Managing General Partner believes that if the Property Interests were to be
sold to a third party purchaser that was not equally familiar with those
interests, it is likely that the purchaser would discount the purchase price to
account for that lack
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<PAGE> 429
of familiarity and associated risks. If these interests are purchased by the
Company, then the additional cost and personnel often inherent in making a
property acquisition are not required, because the files and deed records
already exist in the Company's lease and computer systems, and conveyance and
title issues do not exist.
In the judgment of the Company, the purchase of the Partnership's
Property Interests together with interests in many of the same properties owned
by other Partnerships at approximately the same time will result in
efficiencies to the Company in aggregating such interests. Swift's long-term
knowledge of the risks involved in these properties means that it is in a
better position to evaluate these risks than third parties.
Based upon the Company's experience in purchasing properties, the lack
of additional costs often incurred in purchasing oil and gas properties in
which the purchaser has owned no interest, and the Company's intimate
familiarity with these Property Interests and consequent ability to evaluate
acquisition risks, it was deemed appropriate to pay a premium representing the
benefit to the Company arising from these factors.
The amount of the premium principally was based upon management's
experience in purchasing properties which contain both producing reserves and
drilling potential, without any statistical or analytical study prepared by the
Company in the course of determining the amount of this premium. Since 1979,
the Company, on behalf of itself and others, has gained a wide range of
experience with the valuation of oil and gas properties and the prices for
their purchase and sale, having purchased $478 million of such properties in
129 separate transactions. Other purchasers might have determined it
inappropriate to pay a premium, or if so, to pay a premium based upon other
factors or in a different amount. Because there has been no independent third
party involved in the decision to pay this premium or in the determination of
its amount, and no fairness opinion has been requested regarding this premium,
conflicts of interest exist in its determination, although the Managing General
Partner believes, based upon its knowledge of the oil and gas industry, its
knowledge of the properties involved, its experience in purchasing and selling
oil and gas properties, and the benefits from purchasing the Property Interests
which are particular to the Company, that the amount being offered to the
Partnership to purchase its Property Interests is fair.
"SPECIAL FACTORS" SECTION IN THE JOINT PROXY STATEMENT/PROSPECTUS
The Special Factors section in the Joint Proxy Statement/Prospectus
contains a full discussion of the determination of the purchase price proposed
to be paid by the Managing General Partner to purchase the Partnership's
Property Interests. In addition to those topics discussed at length in this
Supplement, the Joint Proxy Statement/Prospectus addresses alternative
transactions that were considered but not proposed for the Partnership and the
other 62 partnerships to whom similar proposals are being made simultaneously.
It also contains information regarding the prior relationships between the
Appraisers, the Partnerships and the Managing General Partner, the absence of a
request that an independent representative negotiate the terms of the purchase
of the
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<PAGE> 430
Partnership's Property Interests by the Managing General Partner, the manner in
which expenses are to be borne for the transaction, the Managing General
Partner's source of funds to purchase the Partnership's Property Interests, and
the benefits that the Managing General Partner would receive from purchasing
such Property Interests.
ESTIMATES OF LIQUIDATING NET CASH DISTRIBUTION AMOUNT IF THE PROPOSAL IS
APPROVED
The purchase price proposed to be paid to the Partnership for its oil
and gas assets is the Fair Market Value plus the purchase premium. As is the
case with all oil and gas properties purchases, the purchase is proposed to be
made as of the date which the properties were evaluated (in this case December
31, 1997). A portion of the reserves used to establish the Fair Market Value
has been produced during 1998. Most of the net revenue received by the
Partnership from the sale of such production since the proposed purchase date
(December 31, 1997) has been distributed to the partners during 1998 through
quarterly cash distributions or, to the extent not already distributed, will be
distributed as part of the Partnership's liquidating distribution.
Accordingly, the actual purchase price which will be paid to the Partnership
will be reduced by the amount of net production revenue received by the
Partnership after December 31, 1997.
Set forth in the table below are estimated net proceeds that the
Partnership may realize from the sale of the Partnership's Property Interests,
estimated expenses of the related dissolution and liquidation of the
Partnership and estimated interim net cash distributions from January 1, 1998
until September 30, 1998, resulting in an estimate of the amount of net cash
distributions available for partners as a result of such sale.
13
<PAGE> 431
ESTIMATE OF NET CASH DISTRIBUTIONS
FROM PROPERTY INTEREST SALES AND LIQUIDATION
<TABLE>
<S> <C>
Fair Market Value of Partnership Property Interests(1) $ 2,257,441
(Gross Sales Proceeds)
Purchase Premium (7.5% of Fair Market Value)(2) $ 169,308
Estimated Selling and Dissolution Expenses(3) $ (67,723)
(3% of the Fair Market Value)
Net Assets(4) $ 156,163
Estimated Interim Cash Distributions(5) $ (577,428)
-----------------
Estimated Net Distributions to Partners(6) $ 1,937,761
=================
Amount Distributable
to Investors(6) $1,637,311
Amount Distributable
to General Partners(6)(7) $ 300,450
----------
$1,937,761
==========
ESTIMATED NET CASH DISTRIBUTIONS TO INVESTORS PER $1.00 SDI $ 0.19
=================
MINIMUM NUMBER OF SDIS NECESSARY TO PURCHASE 100 SHARES OF SWIFT 9474
=================
ENERGY COMMON STOCK WITH CASH DISTRIBUTIONS(8)
</TABLE>
- -------------
(1) Represents the higher of two fair market value estimates by the
Appraisers.
(2) As determined by the Board of Directors of Swift.
(3) Includes estimated costs associated with dissolution and liquidation
of the Partnership.
(4) Includes cash and net receivables of the Partnership as of December
31, 1997.
(5) Estimated cash distributions paid to the partners from January 1, 1998
to September 30, 1998.
(6) Estimated net cash distributions are allocated to the Investors and
the General Partners pursuant to the Partnership's limited partnership
agreement.
(7) Includes amount distributable to Special General Partner and Managing
General Partner.
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<PAGE> 432
(8) Under the terms of the offer of Swift Common Stock to Eligible
Purchasers, if the Investors in the Partnership approve the Proposal
and its Companion Partnership approves a similar Proposal, such
Investors will be Eligible Purchasers. The minimum number of shares
which can be purchased by an Eligible Purchaser is a round lot of 100
shares. Based upon estimated net cash distribution of $0.19 per $1.00
SDI, the number of SDIs shown above is the minimum number of SDIs
which it will be necessary for an Investor to own in order to purchase
a minimum 100 share round lot of Swift Common Stock without providing
any additional funds from other sources. This calculation is based
upon an assumed purchase price of Swift Common Stock of $18.00 per
share (which is the same price upon which the proforma financial
statements contained in the Joint Proxy Statement/Prospectus are
based) for an aggregate purchase price for 100 shares of Swift Common
Stock of $1,800. The minimum number of Units shown is subject to
change, based upon the price for Swift Common Stock at a future date
as specified under "Offering of Shares of Swift Energy Company Common
Stock if Investors Approve the Proposal--Offer of Swift Common
Stock--Purchase Price" in this Supplement. However, if an Eligible
Purchaser has interests in more than one Partnership, the cash
distributions he will be entitled to receive may be aggregated to meet
the minimum share purchase requirement of a round lot of 100 shares.
ESTIMATES OF NET CASH DISTRIBUTIONS AVAILABLE FROM CONTINUED OPERATIONS
If the Partnership were to retain its Property Interests until they
have reached their economic limit, the table below estimates the return to
Investors, without regard to amounts distributable to the General Partners,
discounted to present value, based upon 1997 year-end pricing without
escalation and upon the discount assumptions used above. The estimates of the
present value of future net cash distributions have been further reduced by
estimates of continuing audit, tax return preparation and reserve engineering
fees associated with continued operations of the Partnership, along with direct
and general and administrative expenses estimated to occur during this time.
The following estimated future net revenues do not take into account any
additional costs which might be incurred by the Partnership due to needed
future maintenance or remedial work on the properties in which the Partnership
has an interest, which would reduce such net revenues.
ESTIMATED SHARE OF INVESTORS'
NET CASH DISTRIBUTIONS FROM CONTINUED OPERATIONS
<TABLE>
<S> <C>
Estimated Future Net Revenues from Continued Operations until $ 4,550,577
Depletion(1)
Estimated Interim Net Cash Distributions(2) $ (500,600)
Estimated Partnership Direct and Administrative Expenses(3) $ (614,328)
Net Assets(4) $ 132,739
---------------------
Net Cash Distributions to Investors(5) $ 3,568,388
=====================
NET CASH DISTRIBUTIONS PER $1.00 SDI $ 0.41
PRESENT VALUE OF NET CASH DISTRIBUTIONS PER $1.00 SDI(5)(6) $ 0.24
</TABLE>
- -------------
(1) Investors' future net revenues are based on the reserve estimates at
December 31, 1997 using year-end 1997 prices without escalation. To a
limited extent, future net revenues may be influenced by a material
change in the selling prices
15
<PAGE> 433
of oil or gas. For further discussion of this, see "Special
Factors--Reasons for the Proposal" in this Supplement. The actual
prices that will be received and the associated costs are likely to
vary and may be more or less than those projected. See "Partnership
Business and Financial Condition" in this Supplement.
(2) Estimated net cash distributions paid to Investors from January 1,
1998 to September 30, 1998 in order to present this information on a
comparative basis (in relation to the preceding table) as of September
30, 1998.
(3) Includes Investors' share of general and administrative expenses, and
audit, tax, and reserve engineering fees.
(4) Includes Investors' share of cash and net receivables of the
Partnership as of December 31, 1997.
(5) Based upon the Partnership's reserves until they have reached their
economic limit.
(6) Discounted at 10% per annum.
The proceeds of all sales, to the extent available for net cash
distribution, are to be distributed to the partners in accordance with the
Partnership's limited partnership agreement. The amounts finally distributed
will depend on the actual sales prices received for the Partnership assets,
results of operations until liquidation of the Partnership, final costs and
other contingencies and circumstances.
FAIRNESS OF PROPOSED SALE OF ASSETS TO THE MANAGING GENERAL PARTNER
AS COMPARED TO CONTINUING OPERATIONS
Based on the above tables, it is estimated that an Investor could
expect to receive $0.19 per $1.00 SDI upon the sale of the Partnership's
Property Interests as of September 30, 1998. In comparison, it is estimated
that an Investor could expect to receive $0.24 per $1.00 SDI, discounted to
present value at 10% per annum ($0.41 per $1.00 SDI on an undiscounted basis)
if the Partnership continued operations. The Managing General Partner believes
that the Proposal to sell the Partnership's Property Interest as compared to
continuing operations is fair to Investors for the reasons discussed below.
Although the estimates contained in the two tables above show that
estimated net cash distributions to Investors (based on net present value) from
continued operations would be approximately 26% higher than estimated net cash
distributions from selling the Partnership's Property Interests and liquidating
the Partnership currently, the Managing General Partner believes there is a
substantial advantage in receiving the liquidating net cash distribution in one
lump sum at this time. The estimates of net cash distributions from continued
operations are based upon 1997 year- end pricing. It is highly likely that
over such a long period of time, oil and gas prices will vary often and
possibly widely, as has been demonstrated historically, from the prices used to
prepare these estimates. Continued operations over such a long period of time
subject Investors to the risk of receiving lower levels of net cash
distributions if oil and gas prices over this period are lower on average than
those used in preparing the estimates of net cash distributions from continued
operations. Continued operations also subject Investors' potential net cash
distributions to the risks of possible changes in costs or need for workover or
similar significant remedial work on the properties in which the Partnership
owns Property Interests. The Managing General Partner also believes that there
is an advantage to Investors taking any funds to be received upon liquidation
and redeploying those assets in other investments, rather than continuing to
receive decreasing levels of net cash distributions over such a long period of
time.
Because there is no active trading market for SDIs in the Partnership,
the only other comparable value for SDIs is the 1997 "SDI Value," which, as
explained below, is the amount calculated on an annual basis under the terms of
the limited partnership agreement at which the Managing General Partner can
offer to repurchase SDIs from Investors. As of January 1, 1997, this "SDI
Value" was $0.36 per $1.00 SDI.
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<PAGE> 434
In 1997, the Investors received net cash distributions of $0.10 per $1.00 SDI,
and are estimated to receive another $0.06 per $1.00 SDI before September 30,
1998, which converts to a comparable value of $0.20 per $1.00 SDI before any
adjustments to quantities of reserves or oil and gas prices during this almost
two year period. Under the terms set out in the partnership agreement, each
year the Managing General Partner is required to furnish to Investors the SDI
Value, and Investors have the right to present their SDIs for purchase by the
Managing General Partner for the SDI Value. The SDI Value amount is determined
on an entirely different basis than the estimates of fair market value by the
Appraisers. Furthermore, the SDI Value was calculated over one year ago, with
a valuation date of January 1, 1997, as opposed to the date for assessment of
Fair Market Value being December 31, 1997. Because of significant changes in
oil and gas prices within a year's time, in addition to the changes in reserve
quantities during that period, the calculation of SDI Value as of January 1,
1997, and the Fair Market Value as of December 31, 1997, are not comparable.
SDI Value is derived by taking 70% of the present value of proved oil and gas
reserves (discounted at 10% per annum) calculated on an escalated pricing
basis, plus cash and accounts receivable less outstanding debts and obligations
of the Partnership.
Although the PV-10 Value of the Partnership's Property Interests is
higher than the purchase price proposed if the Proposal is approved, the
Managing General Partner does not believe that the PV-10 Value accurately
reflects the amount that oil and gas industry members are currently paying to
purchase producing properties on the open market.
FAIRNESS OF PROPOSED SALE
The Managing General Partner believes that the entire transaction
related to the Proposals involving the proposed method of sales of the
Partnerships' Property Interests is fair to Investors for the following
reasons, without giving any particular weight to any reason:
1. The Managing General Partner believes that the most important
element of the Proposal is the determination of the Fair
Market Value of the Partnership's Property Interests. The
price to be paid by the Company to purchase the Partnership's
Property Interests was determined in the Managing General
Partner's sole judgment by adding a 7.5% premium to the higher
of the two estimates by the Appraisers of the fair market
value of the Partnership's Property Interests. Two of the
three Appraisers are qualified independent petroleum
engineering firms and the other is an investment banking firm.
The factors and methods used by the Appraisers in determining
Fair Market Value are discussed in detail under "Special
Factors--Independent Appraisal of the Fair Market Value of
Property Interests of the Partnerships", "--Fair Market
Value," "--Valuation by Petroleum Engineering Consultants,"
"--Valuation by CIBC Oppenheimer" and "--Collective Analysis
of Purchase Price" in the Joint Proxy Statement/Prospectus.
2. No transaction will take place unless the Proposal is approved
by Investors holding at least a majority of the interests in
such Partnership (without any vote by the Managing General
Partner) and a similar Proposal is approved by the
Partnership's Companion Partnership.
3. The Special Transactions Committee made the determination as
to the retention of the Appraisers and approved the fair
market value estimates provided by the Appraisers and
recommended the reports of the Appraisers to the Board of
Directors of the Company.
17
<PAGE> 435
The Special Transactions Committee is comprised solely of
independent directors of the Company.
4. If the Proposals are approved by investors in any of the 63
Partnerships considering similar proposals, it is likely that
the Managing General Partner will expend the capital necessary
to develop non- producing reserves on the Property Interests
purchased by the Managing General Partner from those
Partnerships. If all of the Property Interests which are the
subject of the Proposals are acquired by the Company, such
Property Interests in the aggregate will constitute less than
20% of the Company's total assets. Because the Managing
General Partner would be the beneficiary of any such increase
in value, the Managing General Partner is hereby offering to
Eligible Purchasers the opportunity to purchase up to
2,500,000 shares of Common Stock of the Company. There is no
requirement that any purchase of Swift's Common Stock be made.
See "Offer of Swift Common Stock" below.
5. In structuring the Proposal and related transactions, the
Managing General Partner considered that any sale of
Partnership Property Interests, whether to the Managing
General Partner or to a third party, would be a taxable
transaction. Thus, if an Investor subject to federal income
tax chooses to use the proceeds received on liquidation of
that Investor's Partnership to purchase Swift Common Stock,
tax will still have to be paid on any taxable income resulting
from the Partnership's sale of oil and gas assets, without
regard to whether the Investor has cash proceeds remaining
from his liquidating distribution to pay such tax. Investors
that purchased their interests in the original offering,
however, are not expected to recognize gain on the sale.
The determination by the Special Transactions Committee to pay the
purchase premium, the independent Appraisers' determination of the fair market
value of the properties, and the payment of a 7.5% premium do not necessarily
remove the substantial conflicts of interest which exist in the transaction
between the Company serving as Managing General Partner of the Partnership and
also acting as the purchaser of the Property Interests from the Partnership.
No fairness opinion was requested or received regarding the ultimate purchase
price to be paid by the Company to purchase the Partnership's oil and gas
assets. The Company determined that rather than setting the purchase price for
Partnership Property Interests itself, it would be preferable to instead
request three different independent Appraisers to determine two sets of fair
market values at which such Property Interests should be purchased and then to
choose the higher of those two values. The Managing General Partner believes
that when the Appraisers rendered their opinions as to the "fair market value"
of the Partnership's Property Interests, inherent within their appraisal
opinions were the Appraisers' determination that these "fair market values"
were "fair," or such determinations would not have been made. Consequently, no
independent fairness opinion was requested regarding "fair market values" or
upon the premium. The Managing General Partner believes that adding a 7.5%
premium to the highest of the two fair market value determinations made by the
three Appraisers only serves to increase the amount to be paid to Investors
upon liquidation of the Partnership and does not require a separate fairness
opinion. The determination by a third party purchaser as to the purchase price
might be more or less than that being proposed by the Managing General Partner
as a purchase price for these Property Interests.
The determination to submit the Proposal to Investors in which the
Company would purchase the Property Interests of the Partnership was deemed by
the Managing General Partner to be the most
18
<PAGE> 436
appropriate time and method for liquidation of the Partnership. This decision
was made in light of full consideration by the Managing General Partner of its
fiduciary obligations to Investors. Furthermore, the decision to use three
Appraisers, rather than one, and to have the Appraisers actually set the fair
market value for purchase of the Property Interests, rather than the Managing
General Partner setting that value and requesting a fairness opinion, were
based upon the Managing General Partner's consideration of the substantial
conflicts of interest which exist in the transactions covered hereby.
See "Special Factors--Fairness of Proposed Sale" in the Joint Proxy
Statement/Prospectus.
MANAGING GENERAL PARTNER BENEFITS
Benefits accruing to the Company resulting from the purchase of the
Partnerships' Property Interests include the following: the Managing General
Partner will share the benefits available to Investors through liquidating its
Partnership interests (including both its general partner interests and any
SDIs it owns) and receiving the same value of those interests as Investors.
Additionally, the Company intends to profit from purchasing the Partnership's
Property Interests through a return on capital used to purchase those oil and
gas assets and invest in their development. By purchasing the Partnership's
Property Interests itself, the Managing General Partner will be able to
maintain its position as operator of certain properties in which the
Partnership owns an interest. Consequently, the Managing General Partner would
continue to receive operating fees as operator of those properties. The sale
of the Partnership's Property Interests to the Managing General Partner will
have no effect or an inconsequential effect on the Managing General Partner's
net book value and net earnings. However, the purchase of all of the oil and
gas assets of the Partnerships would increase the Company's proved reserves,
cash flow and total assets by a significant amount. Lastly, if individual
Investors which approve the Proposal elect to purchase Company Common Stock,
rather than receiving cash upon liquidation of the Partnership, the Company
will benefit by using stock to pay the purchase price, rather than using its
available cash resources or borrowing facilities.
See "Special Factors--Managing General Partner Benefits" in the Joint Proxy
Statement/Prospectus.
SIMULTANEOUS PROPOSALS TO COMPANION PARTNERSHIPS
Simultaneous Proposals are being made to investors in the
Partnership's Companion Partnership. If both the Partnership and its Companion
Partnership do not approve their respective Proposals, it is likely to affect
the ability of the Partnership to consummate the sale of its Property
Interests. Although the Investors in the Partnership may desire to sell their
Property Interests, the separation of the working interest and the
non-operating interests in the same properties may affect the salability of
those interests on a permanent basis. If, for example, the Partnership
approves the Proposal but the Companion Partnership does not, the value of a
working interest burdened by a large non- operating interest is likely to be
lowered significantly. [VARIABLE FOR REVERSAL TEMPLATE: IF, FOR EXAMPLE, THE
PARTNERSHIP APPROVES THE PROPOSAL BUT THE COMPANION PARTNERSHIP DOES NOT, THE
VALUE OF A NON-OPERATING INTEREST IS LIKELY TO BE NEGATIVELY AFFECTED BY THE
LACK OF CONTROL OVER OPERATIONS.] If the Partnership's Companion Partnership
does not approve its Proposal, then the Managing General Partner will advise
the Investors in the Partnership. If the investors in the Partnership's
Companion Partnership do not vote in favor of its Proposal, then it is likely
that the Partnership will continue operations and will produce its reserves
until depletion, with steadily decreasing rates of cash flow, and consequently
steadily decreasing amounts of cash distributions to the Investors.
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<PAGE> 437
VOTING ON THE PROPOSAL
The Joint Proxy Statement/Prospectus and the Proxy enclosed with this
Supplement are being provided for use at the Special Meeting of Investors of
the Partnership and at any adjournment or postponement of such meeting (the
"Meeting") to be held at 16825 Northchase Drive, Houston, Texas at 4:00 p.m.
Central Time on ______, __________, 1998. The Meeting is being called for the
purpose of considering and voting upon the Proposal to sell all of the oil and
gas assets of the Partnership to the Company, and to dissolve, wind up and
terminate the Partnership, and to transact such other business as may be
properly presented at the Meeting, all in accordance with the terms and
provisions of the Partnership's limited partnership agreement (the "Partnership
Agreement") and the Texas Revised Limited Partnership Act (the "Texas Act").
This Joint Proxy Statement/Prospectus and enclosed Form of Proxy are first
being mailed to Investors on or about ____________, 1998.
Pursuant to the terms of the Partnership Agreement, the Partnership,
if not terminated earlier, will continue in being through December 31, 2021, at
which point it will terminate automatically.
Under the Partnership Agreement, the Proposal must be approved by the
affirmative vote of Investors holding more than 50% of the SDIs in the
Partnership as of the Record Date (defined below). Therefore, an abstention by
an Investor will have the same effect as a vote against the Proposal. The
solicitations are being made for votes in favor of the Proposal (which will
result in liquidation and dissolution of the Partnership). As of the Record
Date, 8,398,878 SDIs were outstanding and held by record holders (excluding the
SDIs held by the Managing General Partner as discussed below). Accordingly,
the affirmative vote of holders of at least 4,199,440 SDIs is required to
approve the Proposal. Each Investor appearing on the records of the
Partnership as of ______, 1998 (the "Record Date") is entitled to notice of the
Meeting and is entitled to one vote for each SDI held by such Investor. VJM
Corporation, a California corporation, is the Special General Partner of the
Partnership, and owns a 0.75% interest in the Partnership as a general partner,
but owns no SDIs. The Managing General Partner owns a general partner interest
in the Partnership of 14.25%. Additionally, the Managing General Partner owns
232,500 outstanding SDIs in the Partnership, which ownership results from the
Managing General Partner's purchase over the life of the Partnership of SDIs
from Investors under the right of presentment, contained in the Partnership
Agreement. Under the Partnership Agreement, the Managing General Partner may
not vote any SDIs owned by it for matters such as the Proposal. The Managing
General Partner's non-vote, in contrast to abstention by Investors, will not
affect the outcome, because for purposes of adopting the Proposal, its SDIs are
excluded from the total number of voting SDIs.
VOTE REQUIRED
The actual proxy to be used to register the vote on the Proposal
before you is the separate green sheet of paper included with this Supplement
and Joint Proxy Statement/Prospectus. PLEASE USE THE GREEN PROXY TO CAST YOUR
VOTE ON THE PROPOSAL.
If a proxy is properly signed and is not revoked by an Investor, the
SDIs it represents will be voted in accordance with the instructions of the
Investor. If no specific instructions are given, the SDIs will be voted FOR
the Proposal. An Investor may revoke his proxy at any time before it is voted
at the Meeting. Any Investor who attends the Meeting and wishes to vote in
person may revoke his proxy at that time. Otherwise, an Investor must advise
the Managing General Partner of revocation of his proxy in writing,
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<PAGE> 438
which revocation must be received by the Managing General Partner at 16825
Northchase Drive, Suite 400, Houston, Texas 77060 prior to the time the vote is
taken.
SOLICITATION
The solicitation is being made by the Partnership. The Partnership
will bear the costs of the preparation of the Joint Proxy Statement/Prospectus
and of the solicitation of proxies and such costs will be allocated 85% to the
Investors and 15% to the general partners pursuant to the terms of the
Partnership Agreement. As the Managing General Partner holds approximately
2.69% of the SDIs held by all Investors, 2.69% of the costs borne by the
Investors will be borne by the Managing General Partner, in addition to the
portion of the Partnership's total costs borne by the general partners by
virtue of their interest in the Partnership as general partners. Solicitations
will be made primarily by mail. In addition, a number of regular or temporary
employees of the Managing General Partner may, if necessary to ensure the
presence of a quorum, solicit proxies in person or by telephone. The Managing
General Partner also may retain a proxy solicitor to assist in contacting
brokers or Investors to encourage the return of proxies, although it does not
anticipate doing so.
PARTNERSHIP BUSINESS AND FINANCIAL CONDITION
The Partnership is a Texas limited partnership formed June 30, 1992.
SDIs in the Partnership are registered under Section 12(g) of the Securities
Exchange Act of 1934. The Partnership owns Property Interests in producing oil
and gas properties within the continental United States in which the Companion
Partnership also managed by the Managing General Partner owns the non-operating
interests. By the end of July 1992, the Partnership had expended all of its
original capital contributions for the purchase of Property Interests in oil
and gas producing properties. During 1997, approximately 85% of the
Partnership's revenue was attributable to natural gas production. The
Partnership has, from time to time, performed workovers and recompletions on
wells in which the Partnership has Property Interests, using funds advanced by
the Managing General Partner to perform these operations, which amounts have
been subsequently repaid. For information about the business of the
Partnership, see the attached Annual Report on Form 10-K for the year ended
December 31, 1997 and Quarterly Report on Form 10-Q for the quarter ended June
30, 1998.
Investors made contributions of $8,631,378, in the aggregate to the
Partnership, the net proceeds of which has all been invested. The Managing
General Partner has made capital contributions with respect to its general
partner interest of $1,018,865. Additionally, pursuant to the right of
presentment set forth in the Partnership Agreement, it has purchased 232,500
SDIs from Investors. From inception through July 31, 1998, the Partnership has
made net cash distributions to its Investors totaling $5,799,100. Details of
the amounts of cash distributions made to partners over the past three years
and nine months are set out under "Cash Distributions" below. Through July 31,
1998, the Managing General Partner has received net cash distributions from the
Partnership of $1,058,933 with respect to its general partner interest, and
$37,213 related to the number of SDIs it purchased from Investors. On a per
SDI basis, Investors had received, as of July 31, 1998, $0.67 per $1.00 SDI, or
approximately 67.2% of their initial capital contributions.
The Partnership acquired its Property Interests at a time when oil and
gas prices and industry projections of future prices were much higher than
actually occurred in subsequent years. When the Managing General Partner
projected future oil and gas prices to evaluate the economic viability of an
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<PAGE> 439
acquisition, it compared its forecasts with those made by banks, oil and gas
industry sources, the U.S. government and other companies acquiring producing
properties. Acquisition decisions for the Partnership were based upon a range
of increasing prices that were within the mainstream of the forecasts made by
these outside parties. At the time that the Partnership's Property Interests
covering producing properties were acquired, prices averaged about $16.82 per
barrel of oil and $1.51 per Mcf of natural gas. The majority of the
Partnership's Property Interests were acquired by the end of July 1992 and were
comprised principally of natural gas reserves. At that time current prices were
predicted to escalate according to certain parameters from then current levels
to approximately $26.27 per barrel of oil and $2.42 per Mcf of natural gas
during 1997. The predicted price increases did not occur, and prices fell
precipitously from 1994 to 1995. Most of the Partnership's reserves were
produced from 1992 to 1996, during which time the oil prices received by the
Partnership for its production in fact averaged $13.71 per barrel, but the
prices for the Partnership's principal asset, natural gas, averaged
approximately $1.89 per Mcf. A comparison of gas prices as described in this
paragraph appears in the graph presented below.
The following graphs illustrate the effect on Partnership performance
of the variance between gas prices projected at the time of acquisition of the
Partnership's Property Interests and actual gas prices received for production
(as illustrated in the second graph) during the Partnership's existence.
Information has been presented as to gas prices only due to the fact that a
substantial majority of the Partnership's production has been natural gas.
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<PAGE> 440
[GRAPH: 1 page of gas properties info]
23
<PAGE> 441
Lower prices also have had an effect on the Partnership's interest in
proved reserves. Estimates of proved reserves represent quantities of oil and
gas which, upon analysis of engineering and geologic data, appear with
reasonable certainty to be recoverable in the future from known oil and gas
reservoirs under existing economic and operating conditions. When economic or
operating conditions change, proved reserves can be revised either up or down.
If prices had risen as predicted, the volumes of oil and gas reserves that are
economically recoverable might have been higher than the year-end levels
actually reported because higher prices typically extend the life of reserves
as production rates from mature wells remain economical for a longer period of
time. Production enhancement projects that are not economically feasible at
low prices can also be implemented as prices rise.
CASH DISTRIBUTIONS
Cash distributions are made to the partners in the Partnership on a
quarterly basis. During the past three years and the first nine months of
1998, aggregate cash distributions made to all partners in the Partnership
(including the Managing General Partner) and the cash distributions per SDI
made to the Investors were:
<TABLE>
<S> <C> <C>
1995 $ 809,918 $ 0.08 per $1.00 SDI
1996 $ 812,713 $ 0.08 per $1.00 SDI
1997 $ 978,382 $ 0.10 per $1.00 SDI
9 Mo. Ended 9/30/98 $ 577,428 $ 0.06 per $1.00 SDI
</TABLE>
TRANSACTIONS BETWEEN THE MANAGING GENERAL PARTNER AND THE PARTNERSHIP
Under the Partnership Agreement, the Managing General Partner has
received certain compensation for its services and reimbursement for
expenditures made on behalf of the Partnership, which was paid at closing of
the offering of SDIs, in addition to revenues distributable to the Managing
General Partner with respect to its general partner interest or with respect to
SDIs it has purchased under the Investors' right of presentment. In addition
to those revenues, compensation and reimbursements, the following summarizes
the transactions between the Managing General Partner and the Partnership
pursuant to which the Managing General Partner has been paid or has had its
expenses reimbursed on an ongoing basis:
o The Managing General Partner has received internal acquisition
costs reimbursements of $194,915 from the Partnership from
inception through December 31, 1997, none of which has been
received during the two years ended December 31, 1997.
o The Managing General Partner receives operating fees for wells
in which the Partnership has Property Interests and for which
the Managing General Partner or its affiliates serve as
operator. During the years ended December 31, 1997 and
December 31, 1996 the aggregate operating fees paid to the
Company as operator by the Partnership were $65,716 and
$68,584, respectively. Monthly operating fees range from $200
to $1,100 per well on an 8/8th's basis (i.e., the total amount
of operating fees paid by all interest owners in the well).
If the Property Interests are sold to the Managing General
Partner, there should be no change in its status as operator
for a number of the wells in which the Partnership has a
Property Interest. The Managing General Partner believes that
it will be positively affected, on the other hand, by
liquidation of the Partnership, both on the basis of its
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<PAGE> 442
ownership interest in the Partnership and for other reasons
set out under "Special Factors--Managing General Partner
Benefits" in this Supplement.
o The Managing General Partner is entitled to be reimbursed for
general and administrative costs incurred on behalf of and
allocable to the Partnership, including employee salaries and
office overhead. Amounts are calculated on the basis of
Investors' original capital contributions to the Partnership
relative to investor contributions to all public partnerships
formed to purchase interests in producing properties for which
the Managing General Partner serves in that capacity. Through
December 31, 1997, the Managing General Partner had received
$796,069 in the general and administrative overhead allowance
from the Partnership, of which $129,471 and $129,471 have been
reimbursed during the years ended December 31, 1997 and
December 31, 1996, respectively.
o The Managing General Partner has been reimbursed $20,541 in
direct expenses by the Partnership, all of which was billed
by, and then paid directly to, third party vendors, of which
$3,155 and $4,159 have been reimbursed during the years ended
December 31, 1997 and December 31, 1996, respectively.
o The Managing General Partner has received a nonaccountable
incentive amount of $213,301 for services rendered from
inception through December 31, 1997, of which $14,918 and
$21,387 have been reimbursed during the years ended December
31, 1997 and December 31, 1996, respectively.
NO TRADING MARKET
There is no trading market for the SDIs, and none is expected to
develop, as described above under "Special Factors--Fairness of Proposed Sale
of Assets to the Managing General Partner as Compared to Continuing
Operations." Under the Partnership Agreement, Investors have the right to
present their SDIs to the Managing General Partner for repurchase at a price
determined in accordance with the formula established by the Partnership
Agreement. Originally 585 Investors invested in the Partnership. As of
__________, 1998, there were 570 Investors (excluding the Managing General
Partner). The number of SDIs in the Partnership issued and outstanding at that
date was 8,631,378. Through December 31, 1997, the Managing General Partner
had purchased 232,500 SDIs from Investors pursuant to the right of presentment.
The Managing General Partner does not have an obligation to repurchase Investor
interests pursuant to this right of presentment, but merely an option to do so
when such interests are presented for repurchase.
PRINCIPAL HOLDERS OF INVESTOR SDIS
The Managing General Partner holds 2.69% of all outstanding SDIs of
the Partnership, resulting from the purchase of SDIs from Investors under their
right of presentment. To the knowledge of the Managing General Partner, there
is no holder of SDIs that holds more than 5% of the SDIs.
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<PAGE> 443
APPROVALS
No federal or state regulatory requirements must be satisfied or
approvals obtained in connection with the sale of the Partnership's Property
Interests.
LEGAL PROCEEDINGS
The Managing General Partner is not aware of any material pending
legal proceedings to which the Partnership is a party or of which any of its
property is the subject.
SUMMARY OF FEDERAL INCOME TAX CONSEQUENCES
GENERAL
The following briefly summarizes the federal income tax consequences
set forth under "Federal Income Tax Consequences of Adoption of the Proposals"
in the Joint Proxy Statement/Prospectus. Statements of legal conclusions
herein regarding tax consequences are based upon an opinion of Hoops & Levy,
L.L.P., Special Tax Counsel, relevant provisions of the Internal Revenue Code
of 1986, as amended (the "Code"), and accompanying Treasury Regulations, as in
effect on the date hereof, upon reported judicial decisions and published
positions of the Internal Revenue Service (the "Service"), and upon further
assumptions that the Partnership constitutes a partnership for federal tax
purposes and that the Partnership will be liquidated as described herein. The
laws, regulations, administrative rulings and judicial decisions which form the
basis for conclusions with respect to the tax consequences described herein are
complex and are subject to prospective or retroactive change at any time and
any change may adversely affect Investors.
A MORE COMPLETE SUMMARY OF THE FEDERAL INCOME TAX CONSEQUENCES TO
INVESTORS MAY BE FOUND IN THE REGISTRATION STATEMENT IN "FEDERAL INCOME TAX
CONSEQUENCES OF ADOPTION OF THE PROPOSALS." THIS SUMMARY DOES NOT DESCRIBE ALL
THE TAX ASPECTS WHICH MAY AFFECT INVESTORS NOR IS IT A COMPLETE DESCRIPTION OF
THE TAX ASPECTS IT DOES DESCRIBE. It is generally directed to individual
Investors who are the original purchasers of the SDIs and hold interests in the
Partnership as "capital assets" (generally, property held for investment).
Each Investor that is a corporation, trust, estate, tax exempt entity, or other
partnership is strongly encouraged to consult its own tax advisor as to the
rules which are specifically applicable to it. Except as otherwise
specifically set forth herein, this summary does not address foreign, state or
local tax consequences, and is inapplicable to nonresident aliens, foreign
corporations, debtors under the jurisdiction of a court in a case under federal
bankruptcy laws or in a receivership, foreclosure or similar proceeding, or an
investment company, financial institution or insurance company.
TAXABLE GAIN OR LOSS UPON SALE OF PROPERTIES
Investors will realize and recognize gain or loss, or a combination of
both, upon the Partnership's sale of its properties prior to liquidation. It
is projected, however, that Investors will realize a net taxable loss upon the
sale of Partnership properties. Notwithstanding the foregoing, Investors are
not expected to realize any gain or loss upon the sale of properties the
Partnership receives from its Companion Partnership and sells to the Managing
General Partners. Because the oil and gas properties, and related assets,
owned by the Partnership are properties used in a trade or business, the
character of gains and losses realized by the Investors generally will be
governed by Section 1231 of the Code. Realized gains and losses generally
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<PAGE> 444
must be recognized and reported in the year the sale occurs. Each Investor's
recognized allocable share of the net Partnership 1231 gains or losses must be
netted with that Investor's individual section 1231 gains and losses recognized
during the year in order to determine the character of such net gains or net
losses under section 1231. Net gains will be treated as capital gains except
to the extent recharacterized as ordinary income due to recapture and net
losses will be treated as ordinary losses.
LIQUIDATION OF THE PARTNERSHIP
After sale of its properties, the Partnership's assets will consist
solely of cash which it will distribute to its partners in complete
liquidation. The Partnership will not realize gain or loss upon such
distribution of cash to its partners in liquidation. If the amount of cash
distributed to an Investor in liquidation is less than such Investor's adjusted
tax basis in his Partnership interest, the Investor will realize and recognize
a capital loss to the extent of the excess. If the amount of cash distributed
is greater than such Investor's adjusted tax basis in his Partnership interest,
the Investor will recognize a capital gain to the extent of the excess.
CAPITAL GAIN TAX
Net long-term capital gains of individuals, trusts and estates
generally will be taxed at a maximum rate of 20%, while ordinary income,
including income from the recapture of intangible drilling and development
costs, depreciation and depletion, will be taxed at a maximum rate depending on
that Investor's taxable income of 36% or 39.6%.
PASSIVE LOSS LIMITATIONS
Investors that are individuals, trusts, estates, or personal service
corporations are subject to the passive activity loss limitations rules that
were enacted as part of the Tax Reform Act of 1986.
An Investor's allocable share of Partnership income, gain, loss, and
deduction is treated as derived from a passive activity, except to the extent
of Partnership portfolio income, which includes interest, dividends, royalty
income and gains from the sale of property held for investment purposes.
THE FOREGOING DISCUSSION IS A SUMMARY OF THE INCOME TAX CONSEQUENCES
SET FORTH UNDER "FEDERAL INCOME TAX CONSEQUENCES OF ADOPTION OF THE PROPOSALS"
IN THE JOINT PROXY STATEMENT/PROSPECTUS. IT IS NOT INTENDED AS AN ALTERNATIVE
FOR INDIVIDUAL TAX PLANNING. EACH INVESTOR SHOULD CONSULT HIS, HER OR ITS OWN
TAX ADVISOR CONCERNING THE PARTICULAR FEDERAL, STATE, LOCAL, FOREIGN AND OTHER
TAX CONSEQUENCES APPLICABLE TO HIM, HER OR IT OF THE SALE OF PROPERTIES AND THE
LIQUIDATION OF THE PARTNERSHIP.
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<PAGE> 445
SELECTED FINANCIAL INFORMATION AND
PROFORMA FINANCIAL STATEMENTS
For selected financial information and financial statements of the
Partnership, see the Annual Report on Form 10-K for the year ended December 31,
1997 and the Quarterly Report on Form 10-Q for the quarter ended June 30, 1998
attached hereto.
Proforma Financial Statements showing the effect of approval of the
Proposals by the 63 Partnerships to whom similar proposals are being made (both
in the event of the decision by investors to purchase the maximum number of
shares of Swift Common Stock purchasable with their cash distributions and in
the event that investors choose to take all of their distributions from sale of
the properties in cash) and the effect of the Sonat Properties Acquisition are
contained in the Joint Proxy Statement/Prospectus under "Unaudited Proforma
Consolidated Financial Statements".
OFFERING OF SHARES OF SWIFT ENERGY COMPANY COMMON STOCK
IF INVESTORS APPROVE THE PROPOSAL
VOTING PROCEDURES
The Joint Proxy Statement/Prospectus contains detailed procedures to
be followed by investors in voting as to the Partnerships' Proposals. Strict
compliance with these procedures must be followed in order for the elections of
the investors marked on the Proxies and subscription agreement to be effective.
The following is a summary of certain of these procedures:
(a) Investors may make their elections on the subscription agreement
signed by all subscribers commencing upon delivery of this Joint Proxy
Statement/Prospectus and continuing until the Due Date.
(b) If Investors in the Partnership (and its Companion Partnership)
vote to approve the Proposal, Investors may revoke their election to purchase
Shares offered hereby at any time until the Due Date by delivering or faxing a
letter so stating or a later dated subscription agreement, both of which must
be signed by such revoking subscribers, to the Company at 16825 Northchase
Drive, Suite 400, Houston, Texas 77060, fax number (281) 874-2818; Attention:
Investor Relations Department.
(c) Investors failing to submit proxies by the Special Meeting Date
will be deemed to have voted against their Partnership's Proposal and, if their
Partnership approves its Proposal, will receive along with non-subscribing
investors who timely submitted proxies their distribution in cash. See "The
Proposals--Vote Required" in the Joint Proxy Statement/Prospectus.
OFFER OF SWIFT COMMON STOCK
Investor Election to Purchase Shares
In connection with the concurrent Proposals for sale of all of the oil
and gas assets of 63 Partnerships to the Company and the subsequent termination
of such Partnerships, the Company is offering up to 2,500,000 shares of the
Company's Common Stock. Upon approval of the Proposals by the Partnership and
its Companion Partnership and sale of the Partnership's oil and gas assets, the
Partnership's
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<PAGE> 446
assets will consist solely of cash which each investor as an Eligible Purchaser
of such Partnerships will be entitled to receive as a distribution. The
Company hereby offers to each such Eligible Purchaser the opportunity to
purchase shares of Common Stock with all or any portion of the cash
distribution such Investor will be entitled to receive, provided that a minimum
round lot of 100 shares must be purchased. If an Eligible Purchase has
interests in more than one Partnership, the cash distributions he will be
entitled to receive may be aggregated to meet the minimum round lot of 100
shares requirement. Each such Eligible Purchaser may purchase shares of Common
Stock with funds in addition to their cash distributions in order to purchase
(i) the minimum round lot of 100 shares, or (ii) shares in addition to the
number of shares for which their cash distribution will be applied, subject to
prorata limitations in the event of oversubscription. No fractional shares
will be sold.
Purchase Price
The price at which the Common Stock offered hereby will be issued will
be the average price of the Common Stock as reported by the NYSE for the period
between ________ and __________, 1998.
New York Stock Exchange and Pacific Exchange Listings
The Common Stock is traded on the NYSE and the Pacific Exchange under
the symbol "SFY." Application will be made to list the Shares offered hereby
on the NYSE and the Pacific Exchange.
Closing Date
The Company will issue checks representing full or partial
distributions and/or stock certificates representing the Shares of Common Stock
subscribed for hereunder approximately forty-five (45) days after the date of
the Prospectus Supplement (the "Closing Date"), unless earlier terminated or
extended by the Company.
Due Date
All subscriptions, revocations of prior subscriptions or additional
required consideration must be received no later than thirty (30) days after
the date of the Prospectus Supplement (the "Due Date"), unless extended by the
Company.
Oversubscription
In the event this Offering is oversubscribed, all subscribing Eligible
Purchasers will first be sold a round lot of 100 shares and then, if
applicable, that number of shares of Common Stock the purchase price of which
is equal to such Eligible Purchaser's cash distribution, rounded down to the
next whole share. Any remaining shares will be sold on a prorata basis based
on the number of shares such subscribers wish to purchase.
Revocation
Eligible Purchasers may revoke their subscriptions to purchase of the
Shares offered hereby at any time until the Due Date by delivering or faxing a
letter so stating or a later subscription agreement, either of which must be
signed by such revoking subscribers, to the Company at 16825 Northchase Drive,
Suite 400, Houston, Texas 77060, fax number (281) 874-2818; Attention:
Investor Relations Department.
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TABLE OF CONTENTS
<TABLE>
<S> <C>
THE PARTNERSHIP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
CONFLICTS OF INTEREST . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
SPECIAL FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Background and Purpose of the Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Proposed Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Reasons for the Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Current Liquidating Distribution Lowers Volatility Risk . . . . . . . . . . . . . . . . . . . . . . . 8
Decreasing Cash Flow While Expenses Continue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Interest Holders' Tax Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Collective Analysis of Purchase Price; Premium over Fair Market Value . . . . . . . . . . . . . . . . . . . . 9
Determination of Premium Over Fair Market Value by the Company . . . . . . . . . . . . . . . . . . . . . . . 10
"Special Factors" Section in the Joint Proxy Statement/Prospectus . . . . . . . . . . . . . . . . . . . . . 11
Estimates of Liquidating Net Cash Distribution Amount if the Proposal is Approved . . . . . . . . . . . . . 11
Estimates of Net Cash Distributions Available from Continued Operations . . . . . . . . . . . . . . . . . . 13
Fairness of Proposed Sale of Assets to the Managing General Partner as Compared to Continuing Operations . 14
Fairness of Proposed Sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Managing General Partner Benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Simultaneous Proposals to Companion Partnerships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
VOTING ON THE PROPOSAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Vote Required . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Solicitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
PARTNERSHIP BUSINESS AND FINANCIAL CONDITION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Cash Distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Transactions Between the Managing General Partner and the Partnership . . . . . . . . . . . . . . . . . . . 22
No Trading Market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Principal Holders of Investor SDIs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Approvals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
SUMMARY OF FEDERAL INCOME TAX CONSEQUENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
</TABLE>
(i)
<PAGE> 448
<TABLE>
<S> <C>
Taxable Gain or Loss Upon Sale of Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Liquidation of the Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Capital Gain Tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Passive Loss Limitations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
SELECTED FINANCIAL INFORMATION AND PROFORMA FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . 26
OFFERING OF SHARES OF SWIFT ENERGY COMPANY COMMON STOCKIF INVESTORS APPROVE THE PROPOSAL . . . . . . . . . . . . . . 26
Voting Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Offer of Swift Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Investor Election to Purchase Shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
New York Stock Exchange and Pacific Exchange Listings . . . . . . . . . . . . . . . . . . . . . . . 27
Closing Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Due Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Oversubscription . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Revocation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
FORM OF PROXY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (A)
</TABLE>
(ii)
<PAGE> 449
ATTACHMENT A
April 17, 1998
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Attn: Special Transactions Committee FAIR MARKET VALUE ESTIMATE
Board of Directors SWIFT ENERGY OPERATING PARTNERS 1992-B LTD.
97-003-133
Gentlemen:
At your request, we have audited the proved, probable and possible reserves and
future net cash flow as of December 31, 1998, prepared by Swift Energy Company
("Swift") for certain interests owned by the partners in Swift Energy Operating
Partners 1992-B Ltd. This audit has been conducted according to the Standards
Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information
approved by the Board of Directors of the Society of Petroleum Engineers on
October 30, 1979. We have reviewed these properties and where we disagreed
with the Swift reserve estimates, Swift revised its estimates to be in
agreement.
From this audit, and in consultation with J.R. Butler and Company, our estimate
of the fair market value of this partnership is $2,257,441.
Fair market value as used herein is defined as that price that a willing buyer
will pay and a willing seller will accept at a given point in time, with
neither the buyer nor the seller under any compulsion to buy or sell, and both
having reasonable knowledge of all the material circumstances.
To estimate the fair market value attributable to the proved developed
producing reserves, the 10 percent discounted future net cash flow was
multiplied by a suitable factor (less than one) to account for the risk
associated with the reserves, operating expenses, and prices and to approximate
tax consequences. The internal rate of return and payout time were computed for
this quantity and compared with those at which current acquisitions are
completed. Suitable adjustments are then made to correspond to these two
financial indices. Proved developed nonproducing, proved undeveloped, probable
and possible reserves require capital investments and must be treated
appropriately. For these cases, the capital is added to the discounted net cash
flow, then multiplied by a suitable risk factor and the capital then
subtracted. This has the effect that capital is spent with certainty and the
operating cash income is burdened with the risk. Internal rate of return and
payout time is calculated for each estimate to establish reasonableness based
upon it the reserve category. The estimated future net cash flow is that cash
flow which will be realized from the sale of the estimated net reserves after
deduction of royalties, ad valorem and production taxes, direct operating
<PAGE> 450
Swift Energy Company -2- April 17, 1998
costs and capital expenditures, when applicable. Surface and well equipment
salvage values and well plugging and field abandonment costs have not been
considered in the cash flow projections. Future net cash flow as stated in
this report is before the deduction of federal income tax.
The following parameters are incorporated in the economic projections
referenced in this report. Initial oil prices are the existing prices on
December 31, 1997, and are escalated 3.5 percent per year beginning in 1999
through the year 2013 after adjusting for transportation and gravity variances.
Initial natural gas prices are those existing on December 31, 1997, and are
escalated 3.5 percent per year beginning in 1999 through the year 2013 after
adjusting for transportation and Btu content. Operating expenses are escalated
at an annual rate of 3.5 percent until the year 2013. The actual prices that
will be received and the associated costs may be more or less than those
projected.
For those wells with sufficient production history, reserve estimates and rate
projections are based on the extrapolation of established performance trends.
Reserves for other producing and nonproducing properties have been estimated
from volumetric calculations and analogy with the performance of comparable
wells. The reserves referenced in this study are estimates only and should not
be construed as exact quantities. Future conditions may affect recovery of
estimated reserves and cash flow, and all categories of reserves may be subject
to revision as more performance data become available. The proved reserves are
estimated in accordance with the definitions included in the Securities and
Exchange Commission Regulation S-X, Rule 4-10(a) except for the price and cost
escalations. The definitions are included in part as Attachment I. The probable
and possible reserves conform to the definitions approved by the Society of
Petroleum Engineers, Inc. The definitions are included as Attachment II.
Extent and character of ownership, oil and gas prices, production data, direct
operating costs, capital expenditure estimates and other data provided by Swift
have been accepted as represented. The production data available to us were
through the month of October 1997, except in those instances in which data were
available through December. Interim production to December 31, 1997, has been
estimated. Operating expenses as supplied by Swift were not audited, but were
reviewed for reasonableness. No independent well tests, property inspections or
audits of operating expenses were conducted by our staff in conjunction with
this study. We did not verify or determine the extent, character, obligations,
status or liabilities, if any, arising from any current or possible future
environmental liabilities that might be applicable.
In order to audit the reserves, costs and future cash flows referenced in this
report, we have relied in part on geological, engineering and economic data
furnished by our client. Although we have made a best efforts attempt to
acquire all pertinent data and to analyze it carefully with methods accepted by
the petroleum industry, there is no guarantee that the volumes of oil or gas or
the cash flows projected will be realized. The reserve and cash flow
projections referenced in this report may require revision as additional data
become available.
<PAGE> 451
H.J. Gruy and Associates, Inc. is unrelated to Swift and has no interest in the
properties included in this report. In particular:
1. We do not own a financial interest in Swift or its oil and gas
properties.
2. Our fee is not contingent on the outcome of our work or report.
3. We have not performed other services for or have any other
relationship with Swift that would affect our independence.
4. No instructions were given and no limitations were imposed by
Swift on the scope or methodology to be used by us in preparing
such estimates; we did not accept or incorporate any assumptions
from Swift, but merely called upon Swift to the extent customary
in the oil and gas industry to gather and provide certain
background information which we determined to be relevant and
appropriate; we determined what information to use; and how and
to what extent such information should be relied upon,in
estimating the fair market values shown above.
If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such person with the approval of our
client is invited to visit our offices at his expense so that he can evaluate
the assumptions made and the completeness and extent of the data available on
which our estimates are based.
Any distribution or publication of this report or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
James H. Hartsock, Ph.D., P.E.
Executive Vice President
JHH:akr
<PAGE> 452
ATTACHMENT I
DEFINITIONS OF PROVED OIL AND GAS RESERVES(1)
PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquid which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
PROVED DEVELOPED OIL AND GAS RESERVES
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be 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.
PROVED UNDEVELOPED RESERVES
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
- --------
(1) Contained in Securities and Exchange Commission Regulation S-X,
Rule 4-10(a)
H.J. GRUY AND ASSOCIATES, INC. 1200 Smith Street, Suite 3040,
Houston, Texas 77002 (713) 739-1000
<PAGE> 453
ATTACHMENT II
PETROLEUM RESERVES DEFINITIONS
SOCIETY OF PETROLEUM ENGINEERS (SPE) AND WORLD PETROLEUM CONGRESS (WPC)(1)
Reserves are those quantities of petroleum which are anticipated to be
commercially recovered from known accumulations from a given date forward. All
reserve estimates involve some degree of uncertainty. The uncertainty depends
chiefly on the amount of reliable geologic and engineering data available at the
time of the estimate and the interpretation of these data. The relative degree
of uncertainty may be conveyed by placing reserves into one of two principal
classifications, either proved or unproved. Unproved reserves are less certain
to be recovered than proved reserves and may be further sub-classified as
probable and possible reserves to denote progressively increasing uncertainty in
their recoverability.
The intent of the SPE and WPC in approving additional classifications beyond
proved reserves is to facilitate consistency among professionals using such
terms. In presenting these definitions, neither organization is recommending
public disclosure of reserves classified as unproved. Public disclosure of the
quantities classified as unproved reserves is left to the discretion of the
countries or companies involved.
Estimation of reserves is done under conditions of uncertainty. The method of
estimation is called deterministic if a single best estimate of reserves is made
based on known geological, engineering and economic data. The method of
estimation is called probabilistic when the known geological, engineering, and
economic data are used to generate a range of estimates and their associated
probabilities. Identifying reserves as proved, probable, and possible has been
the most frequent classification method and gives an indication of the
probability of recovery. Because of potential differences in uncertainty,
caution should be exercised when aggregating reserves of different
classifications.
Reserves estimates will generally be revised as additional geologic or
engineering data become available or as economic conditions change. Reserves do
not include quantities of petroleum being held in inventory, and may be reduced
for usage of processing losses if required for financial reporting.
Reserves may be attributed to either natural energy or improved recovery
methods. Improved recovery methods include all methods for supplementing natural
energy or altering natural forces in the reservoir to increase ultimate
recovery. Examples of such methods are pressure maintenance, cycling,
waterflooding, thermal methods, chemical flooding, and the use of miscible and
immiscible displacement fluids. Other improved recovery methods may be developed
in the future as petroleum technology continues to evolve.
PROVED RESERVES
Proved reserves are those quantities of petroleum which, by analysis of
geological and engineering data, can be estimated with reasonable certainty to
be commercially recoverable, from a given date forward, from known reservoirs
and under current economic conditions, operating methods, and government
regulations. Proved reserves can be categorized as developed or undeveloped.
If deterministic methods are used, the term reasonable certainty is intended to
express a high degree of confidence that the quantities will be recovered. If
probabilistic methods are used, there should be at least a 90% probability that
the quantities actually recovered will equal or exceed the estimate.
Establishment of current economic conditions should include relevant historical
petroleum prices and associated costs and may involve an averaging period that
is consistent with the purpose of the reserve estimate, appropriate contract
obligations, corporate procedures, and government regulations involved in
reporting these reserves.
In general, reserves are considered proved if the commercial producibility of
the reservoir is supported by actual production or formation tests. In this
context, the term proved refers to the actual quantities of petroleum reserves
and not just the productivity of the well or reservoir. In certain cases,
proved reserves may be assigned on the basis of well logs and/or core analysis
that indicate the subject reservoir is hydrocarbon bearing and is analogous to
reservoirs in the same area that are producing or have demonstrated the ability
to produce on formation tests.
The area of the reservoir considered as proved includes (1) the area delineated
by drilling and defined by fluid contacts, if any, and (2) the undrilled
portions of the reservoir that can reasonably be judged as commercially
productive on the basis of available geological and engineering data. In the
absence of data on fluid contacts, the lowest known occurrence of hydrocarbons
controls the proved limit unless otherwise indicated by definitive geological,
engineering or performance data.
- --------------------------
(1) Approved by the Board of Directors. Society of Petroleum Engineers (SPE),
Inc. on March 7, 1997.
<PAGE> 454
Reserves may be classified as proved if facilities to process and transport
those reserves to market are operational at the time of the estimate or there is
a reasonable expectation that such facilities will be installed. Reserves in
undeveloped locations may be classified as proved undeveloped provided (1) the
locations are direct offsets to wells that have indicated commercial production
in the objective formation, (2) it is reasonably certain such locations are
within the known proved productive limits of the objective formation, (3) the
locations conform to existing well spacing regulations where applicable, and (4)
it is reasonably certain the locations will be developed. Reserves from other
locations are categorized as proved undeveloped only where interpretations of
geological and engineering data from wells indicate with reasonable certainty
that the objective formation is laterally continuous and contains commercially
recoverable petroleum at locations beyond direct offsets.
Reserve which are to be produced through the application of established improved
recovery methods are included in the proved classification when (1) successful
testing by a pilot project or favorable response of an installed program in the
same or an analogous reservoir with similar rock and fluid properties provides
support for the analysis on which the project was based, and, (2) it is
reasonably certain that project will proceed. Reserves to be recovered by
improved recovery methods that have yet to be established through commercially
successful applications are included in the proved classification only (1) after
a favorable production response from the subject reservoir from either (a) a
representative pilot or (b) an installed program where the response provides
support for the analysis on which the project is based and (2) it is reasonably
certain the project will proceed.
UNPROVED RESERVES
Unproved reserves are based on geologic and/or engineering data similar to that
used in estimates of proved reserves; but technical, contractual, economic, or
regulatory uncertainties preclude such reserves being classified as proved.
Unproved reserves may be further classified as probable reserves and possible
reserves.
Unproved reserves may be estimated assuming future economic conditions different
from those prevailing at the time of the estimate. The effect of possible future
improvements in economic conditions and technological developments can be
expressed by allocating appropriate quantities of reserves to the probable and
possible classifications.
PROBABLE RESERVES
Probable reserves are those unproved reserves which analysis of geological and
engineering data suggests are more likely than not to be recoverable. In this
context, when probabilistic methods are used, there should be a least a 50%
probability that the quantities actually recovered will equal or exceed the sum
of estimated proved plus probable reserves.
In general, probable reserves may include (1) reserves anticipated to be proved
by normal step-out drilling where subsurface control is inadequate to classify
these reserves as proved, (2) reserves in formations that appear to be
productive based on well log characteristics but lack core data or definitive
tests and which are not analogous to producing or proved reservoirs in the area,
(3) incremental reserves attributable to infill drilling that could have been
classified as proved if closer statutory spacing had been approved at the time
of the estimate, (4) reserves attributable to improved recovery methods that
have been established by repeated commercially successful applications when (a)
a project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir characteristics appear favorable for commercial application, (5)
reserves in an area of the formation that appears to be separated from the
proved area by faulting and the geologic interpretation indicates the subject
area is structurally higher than the proved area, (6) reserves attributable to a
future workover, treatment, re-treatment, change of equipment, or other
mechanical procedures, where such procedure has not been proved successful in
wells which exhibit similar behavior in analogous reservoirs, and (7)
incremental reserves in proved reservoirs where an alternative interpretation of
performance or volumetric data indicates more reserves than can be classified as
proved.
POSSIBLE RESERVES
Possible reserves are those unproved reserves which analysis of geological and
engineering data suggests are less likely to be recoverable than probable
reserves. In this context, when probabilistic methods are used, there should be
a least a 10% probability that the quantities actually recovered will equal or
exceed the sum of estimated proved plus probable plus possible reserves.
In general, possible reserves may include (1) reserves which, based on
geological interpretations, could possibly exist beyond areas classified as
probable, (2) reserves in formations that appear to be petroleum bearing based
on log and core analysis but may not be productive at commercial rates, (3)
incremental reserves attributed to infill drilling that are subject to technical
uncertainty, (4) reserves attributed to improved recovery methods when (a) a
project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir
<PAGE> 455
characteristics are such that a reasonable doubt exists that the project will be
commercial, and (5) reserves in an area of the formation that appears to be
separated from the proved area by faulting and geological interpretation
indicates the subject area is structurally lower than the proved area.
RESERVE STATUS CATEGORIES
Reserve status categories define the development and producing status of wells
and reservoirs.
DEVELOPED: Developed reserves are expected to be recovered from existing
wells including reserves behind pipe. Improved recovery reserves are
considered developed only after the necessary equipment has been installed,
or when the costs to do so are relatively minor. Developed reserves may be
sub-categorized as producing or non-producing.
PRODUCING: Reserves subcategorized as producing are expected to be
recovered from completion intervals which are open and producing at the
time of the estimate. Improved recovery reserves are considered
producing only after the improved recovery project is in operation.
NON-PRODUCING. Reserves subcategorized as non-producing include shut-in
and behind-pipe reserves. Shut-in reserves are expected to be recovered
from (1) completion intervals which are open at the time of the
estimate but which have not started producing, (2) wells which were
shut-in for market conditions or pipeline connections (3) wells not
capable of production for mechanical reasons. Behind-pipe reserves are
expected to be recovered from zones in existing wells, which will
require additional completion work or future recompletion prior to the
start of production.
UNDEVELOPED RESERVES: Undeveloped reserves are expected to be recovered:
(1) from new wells on undrilled acreage, (2) from deepening existing wells
to a different reservoir, or (3) where a relatively large expenditure is
required to (a) recomplete an existing well or (b) install production or
transportation facilities for primary or improved recovery projects.
<PAGE> 456
ATTACHMENT B
APRIL 17, 1998
SWIFT ENERGY COMPANY
16825 Northchase Drive
Suite 400
Houston, Texas 77060
RE: FAIR MARKET VALUE OPINION
AS OF DECEMBER 31, 1997
SWIFT ENERGY OPERATING PARTNERS
1992-B, LTD.
ATTENTION: SPECIAL TRANSACTIONS COMMITTEE
SWIFT ENERGY COMPANY BOARD OF DIRECTORS
At the request of SWIFT ENERGY COMPANY (SWIFT), J. R. BUTLER AND COMPANY
(JRBCo) has conducted an evaluation audit of the hydrocarbon reserves and
future net cash flow as of December 31, 1997, associated with 44 Acquisition
Programs located in the U.S.A. From this audit, and in consultation with H. J.
Gruy and Associates, Inc. (Gruy), JRBCo has generated its opinion of a "fair
market value" for these properties. The market values of the properties were
distributed to various partnerships based on ownership to determine the fair
market value of each partnership. In JRBCo's opinion, utilizing the
distribution of properties into the proper partnerships, the estimated market
value of Swift Energy Operating Partners 1992-B, Ltd. is $2,257,441.
Proved reserves in this instance are defined as those estimated volumes of
crude oil, condensate, natural gas, and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty to be commercially
recoverable in the future from known reservoirs under a reasonable price and
cost escalation scenario. Probable reserves are the estimated quantities of
commercially recoverable hydrocarbons associated with known accumulations which
are based on engineering and geological data similar to those used in the
estimates of proved reserves but, for various reasons, these data lack the
certainty required to classify the reserves as proved. Possible reserves are
the estimated quantities of commercially recoverable hydrocarbons associated
with known accumulations, which are based on engineering and geological data
which are less complete and less conclusive than the data used in estimates of
probable reserves. In some cases, economic or regulatory uncertainties may
dictate a probable or possible classification.
<PAGE> 457
Recovery of proved reserves is not without risk but, as generally considered in
the industry, the risk of recovering probable reserves is substantially greater
than that associated with proved categories. Likewise, possible reserves are
less certain to be recovered than probable.
The reserves and future performance estimates were prepared utilizing standard
petroleum engineering methods. For properties with sufficient production
history, reserves estimates and rate projections were based primarily on
extrapolation of established performance trends and reconciled, whenever
possible, with volumetric and/or material balance calculations. For the
non-producing zones and undeveloped locations, reserves were determined by a
combination of volumetric calculations and analogy. Volumetrically determined
reserves or those determined by analogy are generally subject to greater
qualifications than reserves estimates supported by established production
decline curves and/or material balance calculations. Determination and
classification of proved reserves were performed (with exception of the use of
escalated prices and costs) in accordance with Securities and Exchange
Commission guidelines. The definitions used also conform to those promulgated
by the_Society of Petroleum Engineers (SPE) and the World Petroleum Congresses
(WPC).
The reserves and resulting "value estimates" included in this study are not
exact quantities. Future conditions may affect the recovery of estimated
reserves, revenue and net cash flow, and all categories of reserves may be
subject to revision and/or reclassification as more performance and well data
become available. Please note, the reserves estimates made by JRBCo were done
in conjuction with an evaluation audit and are not the result of in-depth field
studies. In conducting this audit JRBCo reviewed approximately 65% of SWIFT's
proved "PV10 value" (SEC PV10 as of December 31, 1997) for the total 44
Acquisition Programs.
Basic evaluation data were obtained principally from SWIFT and public sources.
The production data available to JRBCo were generally through August 1997.
Gas and liquid prices were year end (CY 1997) prices as used in SWIFT's
December 31, 1997, SEC cash flow runs.
Estimates of drilling, completion and workover costs were based on information
supplied by SWIFT. Operating costs were also based on data supplied by SWIFT
in their Lease Operating Statement which was reviewed by JRBCo. Surface and
well equipment salvage values and well plugging and field abandonment costs
were not considered in the revenue projections.
The estimates of future net cash flow used in market value calculations are
those revenues which should be realized from the sale of the estimated reserves
after deduction of royalties, ad valorem and production taxes, direct operating
costs and required capital expenditures, when applicable. Future net cash flow
as used in this evaluation is before the deduction of federal income tax.
2
<PAGE> 458
Market value estimates were obtained by applying qualitative risk adjustments
considered appropriate for the various reserves categories and "profit factors"
(as applicable) against discounted future net cash flow values obtained from an
escalated cost and pricing scenario. Prices, costs and investments were
escalated at 3.5%/year for 15 years. Final market value estimates were derived
in conjunction and consultation with Gruy.
In the conduct of our review, we have not independently verified the accuracy
and completeness of information and data furnished by SWIFT with respect to
ownership interests, oil and gas production volumes and rates, historical costs
of operation and development, product prices, agreements relating to current
and future operations and sales of production and other information relative to
such things as timing or scheduling of drilling or recompletion operations.
Field inspections were not made in connection with the preparation of this
report. Furthermore, no judgments were made relative to environmental or other
legal liabilities.
It should be recognized that any oil or gas reserves estimate or forecast of
production and income is a function of engineering and geological
interpretation and judgment. Such estimates should, therefore, be accepted and
used with the understanding that technical data, economic criteria or
regulatory information obtained subsequent to a study may justify revisions
which could increase or decrease the original estimates of reserves and value.
Neither JRBCo, nor any of its personnel, have any direct or indirect interest
in SWIFT or its affiliates. JRBCo is an independent consulting firm as
provided in the Standards Pertaining to the Estimating and Auditing of Oil and
Gas Reserves Information promulgated by the Society of Petroleum Engineers.
JRBCo's compensation is not contingent upon the results of its reserves
estimates, cash flow analyses or "market value opinion" which result from its
review of the subject properties.
READ AND APPROVED:
________________________
BRIAN E. AUSBURN, PRESIDENT
DATE:___________________
BEA:mlc
3
<PAGE> 459
ATTACHMENT C
April 20, 1998
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, TX 77060
Attention: Special Transactions Committee
Swift Energy Company Board of Directors
Gentlemen:
Pursuant to that certain letter agreement dated February 27, 1998 (the
"Agreement") between the Special Transactions Committee (the "Committee") of
the Board of Directors of Swift Energy Company ("Swift" or the "Company") and
CIBC Oppenheimer Corp. ("CIBC Oppenheimer"), you have retained CIBC Oppenheimer
to prepare an independent financial analysis as to the estimated fair market
value (the "CIBC Oppenheimer Valuation") of various interests (the "Assets") in
oil and gas properties (the "Properties'), which Assets are owned by Swift
Energy Operating Partners 1992-B, Ltd. (the "Partnership") of which the Company
is the managing general partner ("General Partner"). CIBC Oppenheimer performed
a similar analysis for 62 other partnerships (the "Partnerships") of which the
Company is the General Partner. It is CIBC Oppenheimer's understanding that the
General Partner has proposed to purchase substantially all of the Partnership's
Assets and, in turn, dissolve and wind up the Partnership. It is also CIBC
Oppenheimer's understanding that the Committee has also retained the reserve
engineering firms of H.J. Gruy & Associates, Inc. and J.R. Butler & Company
(collectively, the "Engineering Consultants") to prepare a separate analysis as
to the estimated fair market value of the Assets (the "Engineering Consultants'
Valuation").
In arriving at the CIBC Oppenheimer Valuation, we, among other things:
(i) Reviewed the historical financial returns to the limited
partners of the Partnership;
(ii) Held discussions with senior management of the Company as to
the Partnership's operational and financial prospects;
<PAGE> 460
Swift Energy Company
April 20, 1998
Page 2
(iii) Held discussions with senior management of the Company
regarding the general characteristics of the Properties
underlying the Assets, including location, productive
geological formations, future development potential and oil
and gas marketing arrangements;
(iv) Held discussions with the Engineering Consultants regarding
the general characteristics of the Properties underlying the
Assets, including location, productive geological formations
and future development potential;
(v) Reviewed the reserve engineering reports supplied to us by the
Engineering Consultants and, particularly, reviewed the
estimated future net cash flow to be generated from the
production of proved reserves of the Properties underlying the
Assets discounted to present value using an annual discount
rate of 10% (the "PV-10 Value") dated as of December 31, 1997;
these amounts were calculated net of estimated production
costs and future development costs, using prices and costs in
effect as of a certain date, without escalation and without
giving effect to non-property related expenses such as future
income tax expense or depreciation, depletion and
amortization;
(vi) Reviewed the Engineering Consultants' Valuation of the
Properties underlying the Assets;
(vii) Reviewed historical operating and financial results of the
Properties underlying the Assets which included PV-10 Value,
proved reserves on a barrel of oil equivalent ("BOE") basis
and projected earnings before interest, taxes and
depreciation, depletion and amortization ("EBITDA") as
prepared by the Engineering Consultants and discussed with
senior management of the Company;
(viii) Reviewed and analyzed financial terms of similar transactions
in which public oil and gas companies liquidated partnerships
of which they were the general partner;
(ix) Reviewed and analyzed transactions involving the sale of oil
and gas companies we deemed comparable to the Partnership(s)
individually and collectively and to the Company;
<PAGE> 461
Swift Energy Company
April 20, 1998
Page 3
(x) Reviewed and analyzed transactions involving the sale of oil
and gas properties we deemed comparable to the Properties
underlying the Assets;
(xi) Reviewed financial and market data for certain public
companies we deemed comparable to the Partnership(s)
individually and collectively and to the Company; and
(xii) Performed such other analyses and reviewed such other
information as we deemed appropriate.
In determining the CIBC Oppenheimer Valuation, we have relied upon and assumed,
without independent verification or investigation and at the direction of the
Committee, (i) the accuracy and completeness of all of the financial and other
information available to us from public sources or provided to us by the
Company and their representatives (including the Engineering Consultants), (ii)
that the reserve engineering reports supplied to us by the Engineering
Consultants as described in clause (v) above have been reasonably prepared and
are based on their best business judgment, (iii) that the information with
respect to the Partnership's ownership of the Assets, as provided to the
Engineering Consultants and to us was accurate in all respects, (iv) with
respect to the historical operating and financial results and projections
provided to us as described in clause and (vii) above, that such information
and projections were reasonably prepared and were based on the best currently
available information, estimates and good faith judgment of the Company's
management and their representatives (including the Engineering Consultants).
Not being experts in the geological evaluation of oil and gas reserves, we
have, with your consent, relied without independent verification upon the audit
of the reserve estimates prepared by the Engineering Consultants for the
purpose of estimating fair market value of the Assets. In addition, we have not
made a physical inspection of the Properties underlying the Assets, nor have we
made any independent evaluations, appraisals or inspections of the Company's or
the Partnership's other assets or the Company's or the Partnership's
liabilities (contingent or otherwise). We have not reviewed any relevant
agreements which may exist between the General Partner and the limited partners
governing the Partnership, nor have we considered the effect which the
ownership structure of the Partnership and the terms of the agreements of the
Partnership may have upon the fairness of the consideration offered by any
general partner of the Partnership. We have not reviewed the books and records
of the Partnership and have assumed, with
<PAGE> 462
Swift Energy Company
April 20, 1998
Page 4
your consent, that the Partnership's ownership interests in the Properties
underlying the Assets, as provided to us by you, is true and correct.
The CIBC Oppenheimer Valuation is based upon analyses of the foregoing factors
in light of our assessment of general economic, financial, market and other
conditions and circumstances as of the date of this letter and any changes in
such conditions and circumstances may affect the validity or fairness of the
CIBC Oppenheimer Valuation. CIBC Oppenheimer disclaims any obligations to
update, revise or reaffirm the CIBC Oppenheimer Valuation. The CIBC Oppenheimer
Valuation reflects our estimate of the consideration that could have been
received by the Partnership in a sale of the Assets in an orderly manner in a
private market transaction in which neither buyer nor seller under any
compunction to complete such transaction. The CIBC Oppenheimer Valuation falls
within a range of values which we believe, subject to the foregoing conditions,
represent possible fair market value estimates of the Partnership's interest in
the Assets. The CIBC Oppenheimer Valuation should not be viewed as a guarantee
of the price that a willing buyer might have paid for the Assets.
CIBC Oppenheimer, as part of its investment banking services, is regularly
engaged in the valuation of businesses and securities in connection with
mergers, acquisitions, underwritings, sales and distributions of listed and
unlisted securities and private placements. CIBC Oppenheimer has provided
certain investment banking and financial advisory services to the Company from
time to time, including acting as co-manager of the Company's Convertible
Subordinated Notes financing in November 1996 and lead manager of the public
offering of the Company's Common Stock in July 1995, and may be involved in
future investment banking activities on behalf of the Company. CIBC Oppenheimer
will also receive a fee upon delivery of this CIBC Oppenheimer Valuation. In
the ordinary course of business, CIBC Oppenheimer actively trades in the equity
securities of the Company for CIBC Oppenheimer's own account and for the
accounts of CIBC Oppenheimer's customers and, accordingly, may at any time hold
a long or short position in such securities.
Based upon and subject to the foregoing, and based upon such other matters as
we consider relevant, it is CIBC Oppenheimer's estimate that the value of Swift
Energy Operating Partners 1992-B, Ltd. interest in the Assets as of the date
hereof is $2,118,171.
This letter is being provided for the use of the Committee in its evaluation of
a possible proposal that the Partnership sell the Assets to the Managing
General Partner and dissolve and wind up its affairs. This letter is not
intended to confer rights or remedies
<PAGE> 463
Swift Energy Company
April 20, 1998
Page 5
upon any stockholder of the Company or any partner of the Partnership and may
not be relied upon by any person or entity other than the Committee. Neither
this letter nor the CIBC Oppenheimer Valuation may be published or otherwise
used or referred to, in whole or part, nor shall any public reference to CIBC
Oppenheimer, this letter or the CIBC Oppenheimer Valuation be made without the
prior written consent of CIBC Oppenheimer; provided, however, that the Company
and the Partnership may include a copy of this letter and a reference to CIBC
Oppenheimer in the proxy statement to be distributed to limited partners of the
Partnership in connection with the solicitation of the approval of the proposal
that the Partnership sell the Assets to the General Partner and dissolve and
wind up its affairs. Neither this letter nor the CIBC Oppenheimer Valuation
constitutes a recommendation to any partner of the Partnership as to how such
partner should vote on or respond to the proposal that the Partnership sell the
Assets to the General Partner and dissolve and wind up its affairs.
Sincerely yours,
CIBC Oppenheimer Corp.
By: /s/ STEVE REINER
-----------------------------
Steve Reiner
Executive Director
<PAGE> 464
ATTACHMENT D
February 10, 1998
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
SWIFT ENERGY OPERATING PARTNERS 1992-B
97-003-133
Gentlemen:
At your request, we have made an audit of the reserves and future net cash flow
as of December 31, 1997, prepared by Swift Energy Company ("Swift") for certain
interests in Swift Energy Operating Partners 1992-B. This audit has been
conducted according to the standards pertaining to the estimating and auditing
of oil and gas reserve information approved by the Board of Directors of the
Society of Petroleum Engineers on October 30, 1979. We have reviewed these
properties and where we disagreed with the Swift reserve estimates, Swift
revised its estimates to be in agreement. The estimated net reserves, future
net cash flow and discounted future net cash flow are summarized by reserve
category in Table 1 for both the 100% Fund Level Partnership and the Limited
Partnership Interest.
The discounted future net cash flow is not represented to be the fair market
value of these reserves and the estimated reserves included in this report have
not been adjusted for risk.
The estimated future net cash flow shown is that cash flow which will be
realized from the sale of the estimated net reserves after deduction of
royalties, ad valorem and production taxes, direct operating costs and required
capital expenditures, when applicable. Surface and well equipment salvage
values and well plugging and field abandonment costs have not been considered
in the cash flow projections. Future net cash flow as stated in this report is
before the deduction of state and federal income tax.
In the economic projections, prices, operating costs and development costs
remain constant for the projected life of each lease.
The reserves included in this study are estimates only and should not be
construed as exact quantities. Future conditions may affect recovery of
estimated reserves and cash flow, and all categories of reserves may be subject
to revision as more performance data become available. Proved reserves are
estimated in accordance with the definitions contained in Securities and
Exchange Commission Regulation S-X, Rule 4-10 (a). The definitions are
included in part as Attachment I.
Extent and character of ownership, oil and gas prices, production data, direct
operating costs, capital expenditure estimates and other data provided by Swift
have been accepted as represented. The production data available to us were
through the month of October 1997, except in those instances in which data were
available through December. Interim production to December 31, 1997, has been
estimated. No independent well tests, property inspections or audits of
operating expenses were conducted by our staff in conjunction with this study.
We did not verify or determine the extent, character, obligations, status or
liabilities, if any, arising from any current or possible future environmental
liabilities that might be applicable.
<PAGE> 465
Swift Energy Company -2 - February 10, 1998
In order to audit the reserves, costs and future net cash flows shown in this
report, we have relied in part on geological, engineering and economic data
furnished by our client. Although we have made a best efforts attempt to
acquire all pertinent data and to analyze it carefully with methods accepted by
the petroleum industry, there is no guarantee that the volumes of oil or gas or
the cash flows projected will be realized.
Production rates may be subject to regulation and contract provisions, and may
fluctuate according to market demand or other factors beyond the control of the
operator. The reserve and cash flow projections presented in this report may
require revision as additional data become available.
We are unrelated to Swift and we have no interest in the properties included in
the information reviewed by us. In particular:
1. We do not own a financial interest in Swift or its oil and gas
properties.
2. Our fee is not contingent on the outcome of our work or report.
3. We have not performed other services for or have any other
relationship with Swift that would affect our independence.
If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such person with the approval of our
client is invited to visit our offices at his expense so that he can evaluate
the assumptions made and the completeness and extent of the data available on
which our estimates are based.
Any distribution or publication of this report or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
James H. Hartsock, Ph.D., P.E.
Executive Vice President
JHH:llb
<PAGE> 466
TABLE 1
100% FUND LEVEL PARTNERSHIP INTEREST
<TABLE>
<CAPTION>
Estimated Estimated
Net Reserves Future Net Cash Flow
-------------------------------- ------------------------------
Oil & Discounted
Condensate at 10%
(Barrels) Gas(Mcf) Nondiscounted Per Year
----------- ------------ ------------- -----------
<S> <C> <C> <C> <C>
Proved Developed 34,760 2,683,745 $ 4,848,232 $ 2,914,245
Proved Undeveloped 3,473 400,073 $ 705,688 $ 442,947
----------- ----------- ----------- -----------
TOTAL PROVED 38,233 3,083,818 $ 5,553,920 $ 3,357,192
G & A $ (749,779) $ (454,351)
----------- ----------- ----------- -----------
TOTAL 38,233 3,083,818 $ 4,804,141 $ 2,902,841
</TABLE>
LIMITED PARTNERSHIP INTEREST
<TABLE>
<CAPTION>
Estimated Estimated
Net Reserves Future Net Cash Flow
-------------------------------- ------------------------------
Oil & Discounted
Condensate at 10%
(Barrels) Gas(Mcf) Nondiscounted Per Year
----------- ------------ ------------- -----------
<S> <C> <C> <C> <C>
Proved Developed 28,176 2,191,080 $ 3,963,606 $ 2,435,222
Proved Undeveloped 2,912 332,834 $ 586,971 $ 372,464
----------- ----------- ----------- -----------
TOTAL PROVED 31,088 2,523,914 $ 4,550,577 $ 2,807,686
G & A $ (614,328) $ (379,993)
----------- ----------- ----------- -----------
TOTAL 31,088 2,523,914 $ 3,936,249 $ 2,427,693
</TABLE>
<PAGE> 467
ATTACHMENT I
DEFINITIONS OF PROVED OIL AND GAS RESERVES(1)
PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquid which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
PROVED DEVELOPED OIL AND GAS RESERVES
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be 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.
PROVED UNDEVELOPED RESERVES
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
- --------
(1) Contained in Securities and Exchange Commission Regulation S-X,
Rule 4-10(a)
H.J. GRUY AND ASSOCIATES, INC. 1200 Smith Street, Suite 3040,
Houston, Texas 77002 (713) 739-1000
<PAGE> 468
FORM OF PROXY
SWIFT ENERGY OPERATING PARTNERS 1992-B, LTD.
THIS PROXY IS SOLICITED BY THE MANAGING GENERAL PARTNER FOR A
SPECIAL MEETING OF LIMITED PARTNERS TO BE HELD ON _______, 1998
The undersigned hereby constitutes and appoints A. Earl Swift, Bruce
H. Vincent, Terry E. Swift or John R. Alden, duly authorized officers of Swift
Energy Company acting in its capacity as Managing General Partner of the
Partnership, or any of them, as Proxies, each with full power to appoint his
substitute, and hereby authorizes the Proxies or any of them to represent the
undersigned at a Special Meeting of the Limited Partners (the "Meeting") of
SWIFT ENERGY OPERATING PARTNERS 1992-B, LTD. (the "Partnership") to be held on
______, 1998 at 4:00 p.m. Houston time, at 16825 Northchase Drive, Houston,
Texas, and any adjournments thereof, and to vote as designated, on the matter
specified below, the Partnership Units standing in the name of the undersigned
on the books of the Partnership (or which the undersigned may be entitled to
vote) on the record date for the Meeting, and hereby revokes any proxy or
proxies heretofore given by the undersigned.
1. The adoption of a proposal FOR AGAINST ABSTAIN
("Proposal") for the ultimate sale
of substantially all of the assets [ ] [ ] [ ]
of the Partnership to the Managing
General Partner and the dissolution,
winding up and termination of the
Partnership. The undersigned hereby
directs said proxies to vote:
2. In their discretion, the proxies are authorized to vote upon such other
matters as may properly come before the meeting or any adjournments or
postponements thereof.
THIS PROXY WHEN PROPERLY EXECUTED, WILL BE VOTED IN ACCORDANCE WITH
THE DIRECTIONS MADE HEREON. IF NO DIRECTION IS MADE, IT WILL BE VOTED FOR THE
PROPOSAL.
Receipt of the Partnership's Notice of Special Meeting of Limited
Partners and Proxy Statement dated ______, 1998 is acknowledged.
PLEASE SIGN EXACTLY AS NAME APPEARS BELOW AND RETURN THE PROXY IN THE
ENCLOSED, POSTAGE-PAID, PRE-ADDRESSED ENVELOPE BY _________, 1998.
SIGNATURE DATE
--------------------------------- --------------
SIGNATURE DATE
--------------------------------- --------------
SIGNATURE DATE
--------------------------------- --------------
IF LIMITED PARTNERSHIP UNITS ARE HELD JOINTLY, ALL JOINT TENANTS MUST
SIGN. WHEN SIGNING AS ATTORNEY, EXECUTOR, ADMINISTRATOR, TRUSTEE OR GUARDIAN,
PLEASE GIVE FULL TITLE AS SUCH. IF A CORPORATION, PLEASE SIGN IN FULL
CORPORATE NAME BY PRESIDENT OR OTHER AUTHORIZED OFFICER. IF A PARTNERSHIP,
PLEASE SIGN IN PARTNERSHIP NAME BY AUTHORIZED PERSON.
<PAGE> 469
IF YOU WISH TO SUBSCRIBE FOR ANY SHARES OF COMMON STOCK OF THE COMPANY, THIS
SUBSCRIPTION AGREEMENT MUST BE RETURNED. IF THIS SUBSCRIPTION AGREEMENT IS NOT
RETURNED, YOU WILL RECEIVE THE FULL AMOUNT OF YOUR DISTRIBUTION IN CASH.
SUBSCRIPTION AGREEMENT
TO: SWIFT ENERGY COMPANY
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060
ANY TERMS USED BUT NOT DEFINED HEREIN, HAVE THE SAME MEANINGS AS ASSIGNED THEM
IN THE PROSPECTUS ACCOMPANYING THIS SUBSCRIPTION AGREEMENT.
The undersigned (the "Subscriber") hereby subscribes for and agrees to
purchase the following number of shares (minimum round lot of 100 required) of
Common Stock, par value $.01 per share, (the "Common Stock") of Swift Energy
Company, a Texas corporation (the "Company") and for the following
consideration:
CHECK ONLY ONE OF THE FOLLOWING: (Be sure to complete any applicable blanks)
[ ] A. Apply all of my cash distribution towards the purchase of as many
shares of Common Stock, rounded down to the next whole share, as such
amount will purchase. In the event such amount is less than the amount
required to purchase the required minimum of 100 shares of Common
Stock, I hereby agree to submit the additional amount within thirty
(30) days from the date of the Company's request.
[ ] B. Apply all of my cash distribution towards the purchase of ________
[indicate number] shares of Common Stock. In the event my cash
distribution is less than the amount required to purchase such number
of shares, I hereby agree to submit the additional amount within thirty
(30) days from the date of the Company's request. In the event my cash
distribution is more than the amount required to purchase such number
of shares, I understand that the Company will remit such portion of my
cash distribution to me or for my account, as applicable.
[ ] C. Apply all of my cash distribution plus an additional amount of
$________ towards the purchase of as many shares of Common Stock as
such amount will purchase.
[ ] D. Apply $________ or ________% of my cash distribution towards the
purchase of as many shares of Common Stock as such amount will
purchase, and remit the remainder of my cash distribution to me or for
my account, as applicable.
SUBSCRIBER(S)
(If units to be held jointly, all joint tenants
must sign)
Date:
--------------------- --------------------------------
(Signature)
Social Security or Tax Identification No.:
------------------------------------------
Date:
--------------------- --------------------------------
(Signature)
Social Security or Tax Identification No.:
------------------------------------------
Please register the Certificate(s)
in the following Name:
Print Name(s):
- -------------------------- ------------------------------------------
(Print Clearly)
Please deliver the Certificate(s)
to the following address:
- --------------------------
- --------------------------
- --------------------------
(Print Clearly)
<PAGE> 470
NO DEALER, SALESPERSON, OR ANY OTHER PERSON
HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE
ANY REPRESENTATIONS, OTHER THAN THOSE CONTAINED OR
INCORPORATED BY REFERENCE IN THIS JOINT PROXY
STATEMENT/PROSPECTUS, AND, IF GIVEN OR MADE, SUCH
INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON
AS HAVING BEEN AUTHORIZED BY THE COMPANY. NEITHER THE
DELIVERY OF THIS JOINT PROXY STATEMENT/PROSPECTUS NOR
ANY SALE MADE HEREUNDER AND THEREUNDER SHALL UNDER ANY
CIRCUMSTANCES CREATE AN IMPLICATION THAT THERE HAS
BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE
DATE HEREOF. THIS JOINT PROXY STATEMENT/PROSPECTUS IS
NOT AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO
BUY ANY SECURITY IN ANY JURISDICTION TO ANY PERSON TO
WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR
SOLICITATION.
-----------------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Summary . . . . . . . . . . . . . . . . . . . . . . .
Risk Factors . . . . . . . . . . . . . . . . . . . .
Special Factors . . . . . . . . . . . . . . . . . . .
The Proposals . . . . . . . . . . . . . . . . . . . .
Conflicts of Interest . . . . . . . . . . . . . . . .
Fiduciary Responsibility . . . . . . . . . . . . . .
Comparison of Ownership of Units and Shares . . . . .
Federal Income Tax Consequences of Adoption
of the Proposals . . . . . . . . . . . . . . . . .
Investor Election to Participate in Offering of
2,500,000 Shares . . . . . . . . . . . . . . . . .
Material Federal Income Tax Considerations of
Electing to Receive Common Stock . . . . . . . . .
Price Range of Common Stock and Dividend Policy . . .
Capitalization of Swift Energy Company . . . . . . .
Unaudited Pro Forma Consolidated Financial
Statements . . . . . . . . . . . . . . . . . . .
Notes to Unaudited Pro Forma Financial Statements . .
Selected Historical Consolidated Financial Data of
Swift Energy Company . . . . . . . . . . . . . . .
Selected Historical Combined Financial Data of
the Partnerships . . . . . . . . . . . . . . . . .
Management's Discussion and Analysis of
Financial Condition and Results of Operations . .
Business and Properties . . . . . . . . . . . . . . .
Management . . . . . . . . . . . . . . . . . . . . .
Principal Shareholders . . . . . . . . . . . . . . .
Certain Relationship and Related Transactions . . . .
Description of Swift Energy Company Capital Stock . .
Legal Matters . . . . . . . . . . . . . . . . . . . .
Experts . . . . . . . . . . . . . . . . . . . . . . .
Glossary of Terms . . . . . . . . . . . . . . . . . .
Other Business . . . . . . . . . . . . . . . . . . .
Consolidated Financial Statements of the Company . .
Consolidated Financial Statements of the Partnerships
The Sonat Properties Acquisition-Historical Statements
of Revenues and Direct Operating Expenses . . . .
</TABLE>
SPECIAL MEETINGS
OF INVESTORS
OF THE PARTNERSHIPS
===================
OFFERING OF
2,500,000 SHARES OF
COMMON STOCK OF
SWIFT ENERGY COMPANY
[LOGO]
JOINT PROXY STATEMENT/PROSPECTUS
DATED ________, 1998
<PAGE> 471
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS
Article 2.02-1 of the Texas Business Corporation Act provides that a
corporation may indemnify its officers, directors, employees and agents for
expenses and costs incurred in certain proceedings arising out of actions taken
in their official capacity only if such persons were acting in good faith and
in a manner reasonably believed to be in or not opposed to the best interests
of the corporation, except in relation to matters in which they have been found
liable (i) to the corporation, or (ii) on the basis that personal benefit was
improperly received regardless of whether or not the benefit resulted from
action taken in their official capacity. In the case of any criminal
proceeding, such persons must also have had no reasonable cause to believe such
conduct was unlawful. Article 2.02-1 further provides that a corporation shall
indemnify its officers and directors against reasonable expenses incurred in
connection with proceedings arising out of actions taken in their official
capacity in which such persons have been wholly successful, on the merits or
otherwise, in the defense of such actions. The bylaws of the Company, as
amended, provide for indemnification in favor of the Company's directors,
officers, and employees to the fullest extent permitted by Article 2.02-1.
Additionally, the Company amended its Articles of Incorporation, with
shareholder approval, to confirm that the Company has the power to indemnify
certain persons in such circumstances as are provided in its bylaws. The
amendment further enables the Company to enter into additional insurance and
indemnity arrangements at the discretion of the Board of Directors. The
Company has entered into Indemnification Agreements with each of its officers
and directors, the form of which was approved by the shareholders of the
Company, that essentially indemnify such individuals to the fullest extent
permitted by law.
Article 7.06 of the Texas Miscellaneous Corporation Laws Act provides
that a corporation's articles of incorporation may provide for the elimination
or limitation of a director's liability. The Company's Articles of
Incorporation to eliminate the liability of directors to the corporation or its
shareholders for monetary damages for an act or omission in his capacity as a
director, with certain specified exceptions to the Company and its shareholders
to the fullest extent permitted by Article 7.06 of the Texas Miscellaneous
Corporation Laws Act.
The Company maintains insurance, the general effect of which is to
provide coverage for the Company with respect to amounts that it is required to
pay officers and directors under the indemnity provisions described above and
coverage for officers and directors against certain liabilities, including
certain liabilities under the federal securities law.
II-1
<PAGE> 472
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT DOCUMENT DESCRIPTION SEQUENTIAL
NO. -------------------- PAGE NO.
---- ----------
<S> <C>
3.1(I) Articles of Incorporation, as amended through June 3, 1988 (incorporated by
reference from Swift Energy Company Annual Report on Form 10-K for the fiscal
year ended December 31, 1988, File No. 1-8754)
3.2(I) Articles of Amendment to Articles of Incorporation filed on June 4, 1990
(incorporated by reference from Swift Energy Company Annual Report on Form 10-K
for the fiscal year ended December 31, 1992)
3.1(II) Bylaws, as amended through August 14, 1995 (incorporated by reference from
Swift Energy Company Quarterly Report on Form 10-Q filed for the quarterly
period ended September 30, 1995)
4 Indenture dated as of June 30, 1993, between Swift Energy Company and Bank One,
Texas, National Association as Trustee (incorporated by reference from
Registration Statement No. 33-63112 on Form S-1 filed on May 20, 1993)
***5 Form of Opinion of Jenkens & Gilchrist, A Professional Corporation, as to the
validity of the Securities being registered hereunder
*8 Form of Opinion of Hoops & Levy, L.L.P. as to Tax Matters
10.1 Indemnity Agreement dated July 8, 1988, between Swift Energy Company and A.
Earl Swift (plus schedule of other persons with whom Indemnity Agreements have
been entered into) (incorporated by reference from Swift Energy Company Annual
Report on Form 10-K for the fiscal year ended December 31, 1988, File No. 1-
8754)
10.2 Amended and Restated Credit Agreement dated March 4, 1992, between Swift Energy
Company and Bank One, Texas, National Association (incorporated by reference
from Registration Statement No. 33-63112 on Form S-1 filed on May 20, 1993)
10.3 Purchase and Sale Agreement dated May 27, 1992, between Swift Energy Company
and Enron Reserve Acquisition Corp. (incorporated by reference from
Registration Statement No. 33-63112 on Form S-1 filed on May 20, 1993)
10.4 Purchase and Sale Agreement dated May 12, 1992, between the Swift Energy
Company and Riverwood Energy Resources, Inc. (incorporated by reference from
Registration Statement No. 33-63112 on Form S-1 filed on May 20, 1993)
</TABLE>
II-2
<PAGE> 473
<TABLE>
<CAPTION>
EXHIBIT DOCUMENT DESCRIPTION SEQUENTIAL
NO. -------------------- PAGE NO.
---- ----------
<S> <C>
10.5 Swift Energy Company 1990 Nonqualified Stock Option Plan (incorporated by
reference from Registration Statement No. 33-36310 on Form S-8 filed on August
10, 1990)
10.6 First Amendment effective May 13, 1993, to Amended and Restated Credit
Agreement dated March 24, 1992, between Swift Energy Company and Bank One,
Texas, National Association (incorporated by reference from Swift Energy
Company Annual Report on Form 10-K for the fiscal year ended December 31, 1994)
10.7 Second Amendment Effective December 31, 1993, to Amended and Restated Credit
Agreement dated March 24, 1992, between Swift Energy Company and Bank One,
Texas, National Association (incorporated by reference from Swift Energy
Company Annual Report on Form 10-K for the fiscal year ended December 31, 1994)
10.8 Third Amendment dated December 31, 1994, to Amended and Restated Credit
Agreement dated March 24, 1992, between Swift Energy Company and Bank One,
Texas, National Association (incorporated by reference from Swift Energy
Company Annual Report on Form 10-K for the fiscal year ended December 31, 1994)
10.9 Amended and Restated Credit Agreement dated March 1, 1994, among Swift Energy
Company and Bank One, Texas, National Association and Bank of Montreal
(incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q filed for the quarterly period ended June 30, 1994)
10.10 First Amendment dated June 15, 1994, to Amended and Restated Credit Agreement
dated March 1, 1994, among Swift Energy Company and Bank One, Texas, National
Association and Bank of Montreal (incorporated by reference from Swift Energy
Company Quarterly Report on Form 10-Q filed for the quarterly period ended June
30, 1994)
10.11 Second Amended dated December 31, 1994, to Amended and Restated Credit
Agreement dated March 1, 1994, among Swift Energy Company and Bank One, Texas,
National Association and Bank of Montreal (incorporated by reference from Swift
Energy Company Annual Report on Form 10-K for the fiscal year ended December
31, 1994)
10.12 Credit Agreement dated April 30, 1996, among Swift Energy Company, Bank One,
Texas, National Association and Bank of Montreal (incorporated by reference
from Swift Energy Company Quarterly Report on Form 10-Q filed for the quarterly
period ended March 31, 1996)
</TABLE>
II-3
<PAGE> 474
<TABLE>
<CAPTION>
EXHIBIT DOCUMENT DESCRIPTION SEQUENTIAL
NO. -------------------- PAGE NO.
---- ----------
<S> <C>
10.13 Credit Agreement dated April 30, 1996, among Swift Energy Company, Bank One,
Texas, National Association (incorporated by reference from Swift Energy
Company Quarterly Report on Form 10-Q filed for the quarterly period ended
March 31, 1996)
10.14 Amended and Restated Swift Energy Company 1990 Stock Compensation Plan, as of
May 1993 (incorporated by reference from Registration Statement No. 33-60469
filed on June 22, 1995)
10.15 Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and Terry E. Swift (incorporated by reference from Swift Energy Company
Quarterly Report on Form 10-Q filed for the quarterly period ended September
30, 1995)
10.16 Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and John R. Alden (incorporated by reference from Swift Energy Company
Quarterly Report on Form 10-Q filed for the quarterly period ended September
30, 1995)
10.17 Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and James M. Kitterman (incorporated by reference from Swift Energy
Company Quarterly Report on Form 10-Q filed for the quarterly period ended
September 30, 1995)
10.18 Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and Bruce H. Vincent (incorporated by reference from Swift Energy
Company Quarterly Report on Form 10-Q filed for the quarterly period ended
September 30, 1995)
10.19 Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and A. Earl Swift (incorporated by reference from Swift Energy Company
Quarterly Report on Form 10-Q filed for the quarterly period ended September
30, 1995)
10.20 Agreement and Release between Swift Energy Company and Virgil Neil Swift
effective June 1, 1994 (incorporated by reference from Registration Statement
No. 33-60469 filed on June 22, 1995)
10.21 First Amendment to Agreement and Release dated as of 12/1/95, by and between
Swift Energy Company and Virgil Neil Swift (incorporated by reference from
Swift Energy Company Annual Report on Form 10-K for the fiscal year ended
December 31, 1996)
10.22 Second Amendment to Agreement and Release dated as of 2/2/96, by and between
Swift Energy Company and Virgil Neil Swift effective January 1, 1996
(incorporated by reference from Swift Energy Company Annual Report on Form 10-K
for the fiscal year ended December 31, 1996)
10.23 Second Amendment to Agreement and Release dated as of 1/14/97, by and between
Swift Energy Company and Virgil Neil Swift effective December 1, 1996
(incorporated by reference from Swift Energy Company Annual Report on Form 10-K
for the fiscal year ended December 31, 1996)
10.24 Indenture dated as of November 25, 1996, between Swift Energy Company and Bank
One, Columbus, National Association as Trustee (incorporated by reference from
Registration Statement No. 33-14785 on Form S-3 filed on October 24, 1996)
</TABLE>
II-4
<PAGE> 475
<TABLE>
<CAPTION>
EXHIBIT DOCUMENT DESCRIPTION SEQUENTIAL
NO. -------------------- PAGE NO.
---- ----------
<S> <C>
10.25 Rights Agreement dated as of August 1, 1997, between Swift Energy Company and
American Stock Transfer & Trust Company (incorporated by reference from Swift
Energy Company Report on Form 8-K dated August 1, 1997)
10.26 Purchase and Sale Agreement dated as of June 1, 1998, between Swift Energy
Company and Sonat Inc. (incorporated by reference from Swift Energy Company
Report on Form 8-K filed on July 10, 1998)
***12 Swift Energy Company Ratio of Earnings to Fixed Charges
***12.1 Partnerships Combined Ratio of Earnings to Fixed Charges
13.1 Swift Energy Company Annual Report on Form 10-K for the fiscal year ended
December 31, 1997 (incorporated by reference)
13.2 Swift Energy Company Quarterly Report on Form 10-Q for the quarterly period
ended March 31, 1998 (incorporated by reference)
13.3 Swift Energy Company Report on Form 8-K filed on June 5, 1998 (incorporated by
reference)
13.4 Swift Energy Company Report on Form 8-K filed on July 10, 1998 (incorporated by
reference)
21 List of Subsidiaries of Swift Energy Company (incorporated by reference from
Registration Statement No. 33-60469 filed on June 22, 1995)
***23.1 Consent of J.R. Butler & Company
***23.2 Consent of H.J. Gruy & Associates, Inc.
***23.3 Consent of CIBC Oppenheimer
*23.4 Consent of Arthur Anderson LLP
***23.5 orm of Consent of Jenkens & Gilchrist, A Professional Corporation (included in
Exhibit 5)
*23.6 Form of Consent of Hoops & Levy, L.L.P. (included in Exhibit 8)
*23.7 Consent of Ernst & Young LLP dated August 13, 1998 (incorporated by reference
from Swift Energy Company Report on Form 8-K/A filed on August 18, 1998)
***24 Power of Attorney
27 Financial Data Schedule (included in electronic filing only)
</TABLE>
- ----------------------------
* Filed herewith
** To be filed by amendment
*** Previously filed
II-5
<PAGE> 476
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 1933;
(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, represent a fundamental change
in the information set forth in the registration
statement. Notwithstanding the foregoing, any
increase or decrease in volume of securities offered
(if the total dollar value of securities offered
would not exceed that which was registered) and any
deviation from the low or high end of the estimated
maximum offering range may be reflected in the form
of prospectus filed with the Commission pursuant to
Rule 424(b) (Section 230.424(b) of this chapter) if,
in the aggregate, the changes in volume and price
represent no more than 20% change in the maximum
aggregate offering price set forth in the
"Calculation of Registration Fee" table in the
effective registration statement.
(iii) To include any material information with
respect to the plan of distribution not previously
disclosed in the registration statement or any
material change to such information in the
registration statement.
(2) That, for the purpose of determining any liability
under the Securities Act of 1933, each such post-effective
amendment shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering
of such securities at that time shall be deemed to be the
initial bona fide offering thereof.
(3) To remove from registration by means of a
post-effective amendment any of the securities being
registered which remain unsold at the termination of the
offering.
B. The undersigned registrant hereby undertakes that, for
purposes of determining any liability under the 1933 Act, each
filing of the registrant's annual report pursuant to Section
13(a) or Section 15(d) of the Securities Exchange Act of 1934
(the "1934 Act") (and, where applicable, each filing of an
employee benefit plan's annual report pursuant to Section
15(d) of the 1934 Act) that is incorporated by reference in
the Registration Statement shall be deemed to be a new
registration statement relating to the securities offered
therein, and the offering of such securities at that time
shall be deemed to be the initial bona fide offering thereof.
C. The undersigned registrant hereby undertakes to 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.
II-6
<PAGE> 477
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
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-7
<PAGE> 478
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
registrant has duly caused this Amendment No. 4 to Registration Statement to be
signed on its behalf by the undersigned, thereunto duly authorized, in the City
of Houston, State of Texas, on October 2, 1998.
SWIFT ENERGY COMPANY
By: /s/ JOHN R. ALDEN
---------------------------------------------
John R. Alden
Senior Vice President - Finance, Chief
Financial Officer, Swift Energy Company
Pursuant to the requirements of the Securities Act of 1933, as amended,
this Amendment No. 4 to the Registration Statement has been signed below in
multiple counterparts with the effect of one original by the following persons
in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
/s/ A. Earl Swift* Chairman of the Board October 2, 1998
- ------------------------------
A. EARL SWIFT and Chief Executive Officer,
Swift Energy Company
/s/ John R. Alden Senior Vice President -- Finance, October 2, 1998
- ------------------------------
JOHN R. ALDEN Chief Financial Officer,
Swift Energy Company
/s/ Alton D. Heckaman, Jr.* Vice President --Finance and October 2, 1998
- ------------------------------
ALTON D. HECKAMAN, JR. Controller, Principal Accounting Officer,
Swift Energy Company
/s/ G. Robert Evans* Director, Swift Energy Company October 2, 1998
- ------------------------------
G. ROBERT EVANS
/s/ Clyde W. Smith, Jr.* Director, Swift Energy Company October 2, 1998
- ------------------------------
CLYDE W. SMITH, JR.
</TABLE>
II-8
<PAGE> 479
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
/s/ Raymond O. Loen* Director, Swift Energy Company October 2, 1998
- ------------------------------
RAYMOND O. LOEN
/s/ Henry C. Montgomery* Director, Swift Energy Company October 2, 1998
- ------------------------------
HENRY C. MONTGOMERY
/s/ Virgil N. Swift* Director, Swift Energy Company October 2, 1998
- ------------------------------
VIRGIL N. SWIFT
/s/ Harold H. Withrow* Director, Swift Energy Company October 2, 1998
- ------------------------------
HAROLD J. WITHROW
</TABLE>
/s/ John R. Alden
- ------------------------------
*JOHN R. ALDEN,
Attorney-In-Fact pursuant
to power of attorney contained
in original filing of this
Registration Statement
II-9
<PAGE> 480
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT DOCUMENT DESCRIPTION
NO. --------------------
----
<S> <C>
3.1(I) Articles of Incorporation, as amended through June 3, 1988 (incorporated by
reference from Swift Energy Company Annual Report on Form 10-K for the fiscal
year ended December 31, 1988, File No. 1-8754)
3.2(I) Articles of Amendment to Articles of Incorporation filed on June 4, 1990
(incorporated by reference from Swift Energy Company Annual Report on Form 10-K
for the fiscal year ended December 31, 1992)
3.1(II) Bylaws, as amended through August 14, 1995 (incorporated by reference from
Swift Energy Company Quarterly Report on Form 10-Q filed for the quarterly
period ended September 30, 1995)
4 Indenture dated as of June 30, 1993, between Swift Energy Company and Bank One,
Texas, National Association as Trustee (incorporated by reference from
Registration Statement No. 33-63112 on Form S-1 filed on May 20, 1993)
***5 Form of Opinion of Jenkens & Gilchrist, A Professional Corporation, as to the
validity of the Securities being registered hereunder
*8 Form of Opinion of Hoops & Levy, L.L.P. as to Tax Matters
10.1 Indemnity Agreement dated July 8, 1988, between Swift Energy Company and A.
Earl Swift (plus schedule of other persons with whom Indemnity Agreements have
been entered into) (incorporated by reference from Swift Energy Company Annual
Report on Form 10-K for the fiscal year ended December 31, 1988, File No. 1-
8754)
10.2 Amended and Restated Credit Agreement dated March 4, 1992, between Swift Energy
Company and Bank One, Texas, National Association (incorporated by reference
from Registration Statement No. 33-63112 on Form S-1 filed on May 20, 1993)
10.3 Purchase and Sale Agreement dated May 27, 1992, between Swift Energy Company
and Enron Reserve Acquisition Corp. (incorporated by reference from
Registration Statement No. 33-63112 on Form S-1 filed on May 20, 1993)
10.4 Purchase and Sale Agreement dated May 12, 1992, between the Swift Energy
Company and Riverwood Energy Resources, Inc. (incorporated by reference from
Registration Statement No. 33-63112 on Form S-1 filed on May 20, 1993)
</TABLE>
<PAGE> 481
<TABLE>
<CAPTION>
EXHIBIT DOCUMENT DESCRIPTION
NO. --------------------
----
<S> <C>
10.5 Swift Energy Company 1990 Nonqualified Stock Option Plan (incorporated by
reference from Registration Statement No. 33-36310 on Form S-8 filed on August
10, 1990)
10.6 First Amendment effective May 13, 1993, to Amended and Restated Credit
Agreement dated March 24, 1992, between Swift Energy Company and Bank One,
Texas, National Association (incorporated by reference from Swift Energy
Company Annual Report on Form 10-K for the fiscal year ended December 31, 1994)
10.7 Second Amendment Effective December 31, 1993, to Amended and Restated Credit
Agreement dated March 24, 1992, between Swift Energy Company and Bank One,
Texas, National Association (incorporated by reference from Swift Energy
Company Annual Report on Form 10-K for the fiscal year ended December 31, 1994)
10.8 Third Amendment dated December 31, 1994, to Amended and Restated Credit
Agreement dated March 24, 1992, between Swift Energy Company and Bank One,
Texas, National Association (incorporated by reference from Swift Energy
Company Annual Report on Form 10-K for the fiscal year ended December 31, 1994)
10.9 Amended and Restated Credit Agreement dated March 1, 1994, among Swift Energy
Company and Bank One, Texas, National Association and Bank of Montreal
(incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q filed for the quarterly period ended June 30, 1994)
10.10 First Amendment dated June 15, 1994, to Amended and Restated Credit Agreement
dated March 1, 1994, among Swift Energy Company and Bank One, Texas, National
Association and Bank of Montreal (incorporated by reference from Swift Energy
Company Quarterly Report on Form 10-Q filed for the quarterly period ended June
30, 1994)
10.11 Second Amended dated December 31, 1994, to Amended and Restated Credit
Agreement dated March 1, 1994, among Swift Energy Company and Bank One, Texas,
National Association and Bank of Montreal (incorporated by reference from Swift
Energy Company Annual Report on Form 10-K for the fiscal year ended December
31, 1994)
10.12 Credit Agreement dated April 30, 1996, among Swift Energy Company, Bank One,
Texas, National Association and Bank of Montreal (incorporated by reference
from Swift Energy Company Quarterly Report on Form 10-Q filed for the quarterly
period ended March 31, 1996)
</TABLE>
<PAGE> 482
<TABLE>
<CAPTION>
EXHIBIT DOCUMENT DESCRIPTION
NO. --------------------
----
<S> <C>
10.13 Credit Agreement dated April 30, 1996, among Swift Energy Company, Bank One,
Texas, National Association (incorporated by reference from Swift Energy
Company Quarterly Report on Form 10-Q filed for the quarterly period ended
March 31, 1996)
10.14 Amended and Restated Swift Energy Company 1990 Stock Compensation Plan, as of
May 1993 (incorporated by reference from Registration Statement No. 33-60469
filed on June 22, 1995)
10.15 Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and Terry E. Swift (incorporated by reference from Swift Energy Company
Quarterly Report on Form 10-Q filed for the quarterly period ended September
30, 1995)
10.16 Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and John R. Alden (incorporated by reference from Swift Energy Company
Quarterly Report on Form 10-Q filed for the quarterly period ended September
30, 1995)
10.17 Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and James M. Kitterman (incorporated by reference from Swift Energy
Company Quarterly Report on Form 10-Q filed for the quarterly period ended
September 30, 1995)
10.18 Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and Bruce H. Vincent (incorporated by reference from Swift Energy
Company Quarterly Report on Form 10-Q filed for the quarterly period ended
September 30, 1995)
10.19 Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and A. Earl Swift (incorporated by reference from Swift Energy Company
Quarterly Report on Form 10-Q filed for the quarterly period ended September
30, 1995)
10.20 Agreement and Release between Swift Energy Company and Virgil Neil Swift
effective June 1, 1994 (incorporated by reference from Registration Statement
No. 33-60469 filed on June 22, 1995)
10.21 First Amendment to Agreement and Release dated as of 12/1/95, by and between
Swift Energy Company and Virgil Neil Swift (incorporated by reference from
Swift Energy Company Annual Report on Form 10-K for the fiscal year ended
December 31, 1996)
10.22 Second Amendment to Agreement and Release dated as of 2/2/96, by and between
Swift Energy Company and Virgil Neil Swift effective January 1, 1996
(incorporated by reference from Swift Energy Company Annual Report on Form 10-K
for the fiscal year ended December 31, 1996)
10.23 Second Amendment to Agreement and Release dated as of 1/14/97, by and between
Swift Energy Company and Virgil Neil Swift effective December 1, 1996
(incorporated by reference from Swift Energy Company Annual Report on Form 10-K
for the fiscal year ended December 31, 1996)
10.24 Indenture dated as of November 25, 1996, between Swift Energy Company and Bank
One, Columbus, National Association as Trustee (incorporated by reference from
Registration Statement No. 33-14785 on Form S-3 filed on October 24, 1996)
</TABLE>
<PAGE> 483
<TABLE>
<CAPTION>
EXHIBIT DOCUMENT DESCRIPTION
NO. --------------------
----
<S> <C>
10.25 Rights Agreement dated as of August 1, 1997, between Swift Energy Company and
American Stock Transfer & Trust Company (incorporated by reference from Swift
Energy Company Report on Form 8-K dated August 1, 1997)
10.26 Purchase and Sale Agreement dated as of June 1, 1998, between Swift Energy
Company and Sonat Inc. (incorporated by reference from Swift Energy Company
Report on Form 8-K filed on July 10, 1998)
***12 Swift Energy Company Ratio of Earnings to Fixed Charges
***12.1 Partnerships Combined Ratio of Earnings to Fixed Charges
13.1 Swift Energy Company Annual Report on Form 10-K for the fiscal year ended
December 31, 1997 (incorporated by reference)
13.2 Swift Energy Company Quarterly Report on Form 10-Q for the quarterly period
ended March 31, 1998 (incorporated by reference)
13.3 Swift Energy Company Report on Form 8-K filed on June 5, 1998 (incorporated by
reference)
13.4 Swift Energy Company Report on Form 8-K filed on July 10, 1998 (incorporated by
reference)
21 List of Subsidiaries of Swift Energy Company (incorporated by reference from
Registration Statement No. 33-60469 filed on June 22, 1995)
***23.1 Consent of J.R. Butler & Company
***23.2 Consent of H.J. Gruy & Associates, Inc.
***23.3 Consent of CIBC Oppenheimer
*23.4 Consent of Arthur Anderson LLP
***23.5 orm of Consent of Jenkens & Gilchrist, A Professional Corporation (included in
Exhibit 5)
*23.6 Form of Consent of Hoops & Levy, L.L.P. (included in Exhibit 8)
*23.7 Consent of Ernst & Young LLP dated August 13, 1998 (incorporated by reference
from Swift Energy Company Report on Form 8-K/A filed on August 18, 1998)
***24 Power of Attorney
27 Financial Data Schedule (included in electronic filing only)
</TABLE>
- ----------------------------
* Filed herewith
** To be filed by amendment
*** Previously filed
<PAGE> 1
EXHIBIT 8
FORM OF HOOPS & LEVY OPINION
[FORM OF OPINION]
_____________________, 1998
Each Limited Partnership on Exhibit A
Swift Energy Company
Managing General Partner
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Re: Form S-4 Swift Energy Company, Registrant -- Tax Aspects
Gentlemen:
We have acted as special tax counsel to the limited partnerships listed
on Exhibit A attached hereto (collectively the "Partnerships"), each of which
was formed under the Texas Revised Limited Partnership Act, in connection with
an offering of limited partnership interests pursuant to registered offerings
made by Swift Energy Company over a period of nine years. We also have acted as
special tax counsel to Swift Energy Company, a Texas corporation that acts as
Managing General Partner of each of the Partnerships in connection with the
"Federal Income Tax Consequences of Adoption of the Proposals" and "Material
Federal Income Tax Consideration of Electing to Receive Common Stock in Lieu of
Cash Upon Partnership Liquidation" of the Final Amendment to Form S-4
Registration Statement, dated ________ (the "Registration Statement") and the
Summary of Federal Income Tax Consequences in each Supplement to the
Registration Statement. You have requested our opinion regarding the federal
income tax consequences of (i) the sale of all of each Partnership's oil and gas
assets and the liquidation of each Partnership approving said sale and (ii) an
Investor's purchase of Swift Energy Company stock with Partnership property
sales proceeds, each in accordance with the terms of the Registration Statement,
the Supplement for each Partnership and each Partnership's Limited Partnership
Agreement.
The facts, as we understand them, are as set forth in the Registration
Statement, each Supplement thereto and all exhibits to each. As to various
questions of fact material to the opinions expressed below, we have relied in
part to the extent we deemed reasonably appropriate upon the disclosures made by
Swift Energy Company in the Registration Statement and all attachments thereto
including without limitation the Supplements, other representations made by
officers and employees of Swift Energy Company to us, and other documents,
records and instruments furnished to us by Swift Energy Company, without
independent verification of the accuracy of such representations, documents,
records or instruments. With regard to documents we have received or reviewed,
we have assumed the conformity of all copies to original documents and we also
have assumed the genuineness of signatures and the authenticity and accuracy of
all original documents or copies thereof. We also have assumed that the
Partnerships constitute partnerships for federal income tax purposes and have
relied upon certain private letter rulings received by the Managing General
Partner on behalf of the Partnerships.
Except to the extent affected by the individual circumstances of
Investors, as defined in the Registration Statement, and local law, the
disclosures contained under the "Federal Income Tax Consequences of Adoption of
the Proposals" and "Material Federal Income Tax Consideration of Electing to
Receive Common Stock in Lieu of Cash Upon Partnership Liquidation" in the
Registration Statement set forth our opinion of the federal income tax
considerations material to those individuals considering either the sale of
Partnership Properties pursuant to the Proposals or a purchase of Company stock,
or both. Additionally, the summary descriptions contained in the Supplements to
the Registration Statement under the heading "Summary of Federal Income Tax
Consequences" are reasonable summaries of the section of the Registration
Statement entitled "Federal Income Tax Consequences of Adoption of the
Proposals."
Our opinion as to the federal income tax consequences as stated under
"Federal Income Tax Consequences of Adoption of the Proposals" and "Material
Federal Income Tax Consideration of Electing to Receive Common Stock in Lieu of
Cash Upon Partnership Liquidation" is merely a statement as to what we regard
the federal income tax consequences to be. It is based upon our interpretations
of statutes, regulations, notices, published rulings, representations of the
Managing General Partner, certain specifically applicable private letter
rulings, and other legal precedents in effect as of the date hereof.
The Internal Revenue Service Restructuring and Reform Act of 1998 was
enacted on July 22, 1998. This act materially modifies the treatment and rights
of many taxpayers relative to the Internal Revenue Service and generally reduces
the long term capital gains holding period on most assets for individuals to
more than twelve months for sales made after December 31, 1997. The Taxpayer
Relief Act of 1997, enacted on August 5, 1997, significantly revised the
Internal Revenue Code of 1986 and may materially affect individual taxpayers.
There have been numerous other, recent changes in the taxing statutes, including
the Small Business Job Protection Act of 1996, other 1996 acts that made changes
to the tax laws, the Omnibus Budget Reconciliation Act of 1993, the Revenue
Reconciliation Act of 1990, and Comprehensive Energy Policy Act of 1992. The
taxing statutes also have been amended by other public laws pertaining to
non-tax matters. Certain provisions of each act, as well as previous acts,
remain unclear due to the limited amount of relevant legislative history and the
lack of proposed or final regulations interpreting the provisions of such acts
and previous acts.
It is reasonable to expect further changes in the federal income tax.
The authority upon which we rely as to any particular federal income tax
consequences is subject to change at any time and such change may have
retroactive effect.
We consent to the use of this opinion and the reference to our firm in
the Registration Statement.
Very truly yours,
HOOPS & LEVY, L.L.P.
<PAGE> 1
EXHIBIT 23.4
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the use of our
reports dated February 10, 1998 and April 13, 1998, included in this
Registration Statement and to the incorporation by reference in this
Registration Statement of (i) our reports dated February 10, 1998 included in
the Annual Reports on Form 10-K listed below and (ii) our reports dated February
10, 1998 included in Swift Energy Company's Form 8-K dated June 5, 1998 listed
below, and to all references to our Firm included in this Registration
Statement.
REPORTS INCORPORATED BY REFERENCE IN THIS REGISTRATION STATEMENT:
Swift Energy Company, Annual Report on Form 10-K for the year ended December 31,
1997
Swift Energy Income Partners 1989-B, Ltd., Annual Report on Form 10-K for the
year ended December 31, 1997
Swift Energy Managed Pension Assets Partnership 1988-A, Ltd., Annual Report on
Form 10-K for the year ended December 31, 1997
Swift Energy Pension Partners 1993-B, Ltd., Annual Report on Form 10-K for the
year ended December 31, 1997
Swift Energy Income Partners 1986-D, Ltd., Annual Report on Form 10-K for the
year ended December 31, 1997
Swift Energy Operating Partners 1992-B, Ltd., Annual Report on Form 10-K for the
year ended December 31, 1997
REPORTS INCLUDED IN SWIFT ENERGY COMPANY'S FORM 8-K DATED JUNE 5, 1998;
INCORPORATED BY REFERENCE IN THIS REGISTRATION STATEMENT:
Swift Energy Income Partners 1988-1, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Income Partners 1988-2, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Income Partners 1988-3, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Income Partners 1989-D, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Income Partners 1989-1, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Income Partners 1989-2, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Income Partners 1989-3, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Income Partners 1989-4, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Income Partners 1989-A, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Income Partners 1989-C, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Income Partners 1989-D, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Income Partners 1990-1, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Income Partners 1990-2, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Income Partners 1990-B, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Operating Partners 1991-C, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Operating Partners 1992-A, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Operating Partners 1992-D, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Operating Partners 1993-A, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Operating Partners 1993-C, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Operating Partners 1993-D, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Operating Partners 1994-A, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Operating Partners 1994-B, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Operating Partners 1994-C, Ltd., Annual Report for the Year Ended
12/31/97
Swift Energy Operating Partners 1994-D, Ltd., Annual Report for the Year Ended
12/31/97
ARTHUR ANDERSEN LLP
Houston, Texas
October 5, 1998
<PAGE> 1
EXHIBIT 23.7
CONSENT OF INDEPENDENT AUDITORS
We consent to the reference to our firm under the caption "Experts" and to
the use of our report dated July 28, 1998 with respect to the historical
statements of revenues and direct operating expenses of the Sonat Properties
Acquisition included in the Joint Proxy Statement/Prospectus of Swift Energy
Company that is made a part of Amendment No. 4 to the Registration Statement
(Form S-4 No. 333-50637) of Swift Energy Company for the registration of up to
2,500,000 shares of its common stock.
Ernst & Young LLP
Houston, Texas
October 1, 1998
