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As filed with the Securities and Exchange Commission on June 3, 1998.
Registration Statement No. 333-50637
================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
------------------------
AMENDMENT NO. 2
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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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
============================== ==================== ===================== ===================== ====================
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Common Stock, $.01 par value
per share 2,500,000 $18.3125 $45,781,250.00 $13,505.47(2)
============================== ==================== ===================== ===================== ====================
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(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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This Amendment No. 2 to the Registration Statement on Form S-4 is filed
to provide (1) revised proforma financial information, and (2) to include the
results for the quarter ended March 31, 1998, and all of the financial
statements, information and discussion have been updated to reflect such
results. Otherwise the Registration Statement remains virtually unchanged from
Amendment No. 1.
SWIFT ENERGY COMPANY
CROSS REFERENCE SHEET
PURSUANT TO REGULATION S-K ITEM 501(b)
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FORM S-4 ITEM NUMBER AND CAPTION LOCATION/CAPTION IN JOINT PROXY STATEMENT/PROSPECTUS
-------------------------------- ----------------------------------------------------
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A. INFORMATION ABOUT THE TRANSACTION
1. Forepart of the Registration Statement and Outside Outside Front Cover Page of
Front Cover Page of Prospectus......................... Joint Proxy Statement/Prospectus
2. Inside Front and Outside Back Cover Pages of Inside Front and Outside Back
Prospectus.............................................. 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 Regarding the Proposals
to Sell the Partnerships' Oil and Gas Properties;
The Proposals
5. Pro Forma Financial Information......................... Unaudited Pro Forma Consolidated
Financial Statements
6. Material Contracts with Company being Acquired.......... Business and Properties of Swift Energy Company
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 Incorporation of Certain
Reference............................................... Information by Reference;
Description of Capital Stock
12. Information with Respect to S-2 or S-3 Registrants...... Business and Properties of Swift Energy Company
13. Incorporation of Certain Information by Reference....... Not Applicable
14. Information with Respect to Registrants Other Than
S-3 or S-2 Registrants.................................. Not Applicable
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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 Stockholders;
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 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 JUNE ___, 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, Houston, Texas,
on Tuesday, June ___, 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 "Termination"). 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 May __,
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
June ____, 1998
[Variable Page]
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June __, 1998
[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 ultimate sale of substantially all of your Partnership's
property interests 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 of
three independent Appraisers, one such estimate by two petroleum engineering
firms and the other estimate by an investment banking firm, plus a premium of
7.5% above such higher fair market value estimate. In order for the sale and
liquidation to take place, Investors 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.
The Managing General Partner recommends that you vote in favor of 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.
See "The Proposal--Estimates of Liquidating Distribution Amount." 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 "The
Proposal--Reasons for the Proposals" and "--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 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 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.
Joint Proxy Statement/Prospectus
SUBJECT TO COMPLETION
DATED ________________, 1998
SPECIAL MEETINGS
OF INVESTORS
OF THE PARTNERSHIPS
Swift Energy Company, a Texas corporation ("Swift" or the "Company"), is
the Managing General Partner (the "Managing General Partner") of 63 Texas
limited partnerships (individually, a "Partnership" and, collectively, the
"Partnerships") formed between 1986 and 1994 to invest in producing oil and gas
properties. These Partnerships are comprised of Pension and Operating
Partnerships of which a Pension Partnership owns 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. This Joint Proxy
Statement/Prospectus is being furnished to limited partners or interest holders
in the Partnerships (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 proposals for the
ultimate sale of substantially all of the assets of each of the Partnerships to
the Company and the subsequent termination of such Partnerships (the
"Proposals," or singly for each Partnership, the "Proposal"). Upon approval of
the Proposals by companion Partnerships and sale of such Partnerships'
properties, the Partnerships' assets will consist solely of cash which each
Investor of such Partnerships will be entitled to receive as a distribution
pursuant to the terms of the Partnership Agreement of each Partnership.
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 2,500,000 shares of Common Stock, $.01 par value
(the "Common Stock") of the Company being made solely to those Investors in
Partnerships which approve the Proposals along with their companion
partnerships, if appropriate ("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 cash
distribution such Eligible Purchaser will be entitled to receive, provided that
a minimum round lot of 100 shares must be purchased. 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 purchasable with their cash
distribution, subject to prorata limitations in the event of oversubscription.
Swift 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
closing price on the NYSE for the Common Stock on ________________, 1998, was
$______ per share.
NEITHER THIS TRANSACTION NOR THESE SECURITIES HAVE BEEN APPROVED OR
DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION ("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.
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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, 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 New York Stock Exchange, Inc., 20 Broad Street, New York, New
York 10005 and the Pacific Exchange, Inc., 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 SUCH 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 March 31, 1998, or for a Partnership not subject to the
informational requirements of the 1934 Act, unaudited financials for the quarter
ended March 31, 1998, and (3) a Partnership Supplement for the specific
Partnership which has 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 of J.R.
Butler and Company and H.J. Gruy and Associates, Inc., and of 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 March 31,
1998; and (3) 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.
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
SPECIAL FACTORS REGARDING THE PROPOSALS TO SELL THE PARTNERSHIPS' OIL AND GAS ASSETS ........................... 21
RISK FACTORS ................................................................................................... 36
THE PROPOSALS .................................................................................................. 44
COMPARISON OF OWNERSHIP OF UNITS AND SHARES .................................................................... 50
FEDERAL INCOME TAX CONSEQUENCES OF ADOPTION OF THE PROPOSALS.................................................... 60
INVESTOR ELECTION TO PARTICIPATE IN OFFERING OF 2,500,000 SHARES OF
SWIFT COMMON STOCK TO ELIGIBLE PURCHASERS .................................................................... 65
MATERIAL FEDERAL INCOME TAX CONSIDERATION OF ELECTING TO RECEIVE COMMON STOCK
IN LIEU OF CASH UPON PARTNERSHIP LIQUIDATION ................................................................. 68
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY OF THE COMPANY ................................................. 69
CAPITALIZATION OF SWIFT ENERGY COMPANY ......................................................................... 70
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS .......................................................... 71
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS ................................................. 84
SELECTED CONSOLIDATED HISTORICAL FINANCIAL DATA ................................................................ 85
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS ........................................................................................ 86
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BUSINESS AND PROPERTIES OF SWIFT ENERGY COMPANY ................................................................ 97
MANAGEMENT ..................................................................................................... 113
PRINCIPAL SHAREHOLDERS ......................................................................................... 115
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ................................................................. 117
DESCRIPTION OF SWIFT ENERGY COMPANY CAPITAL STOCK .............................................................. 118
LEGAL MATTERS .................................................................................................. 122
EXPERTS ........................................................................................................ 122
GLOSSARY OF TERMS .............................................................................................. 123
OTHER BUSINESS ................................................................................................. 127
CONSOLIDATED FINANCIAL STATEMENTS OF THE COMPANY ............................................................... F-1
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SUMMARY
THE PROPOSALS; DISTRIBUTIONS TO INVESTORS
Swift is the Managing General Partner of 63 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 the Proposal to sell all of that
particular Partnership's oil and gas assets to the Managing General Partner at a
price based upon the higher of two fair market value estimates of those assets
determined by three independent appraisers, plus a 7.5% premium above such fair
market value estimate. The total purchase price for all of the oil and gas
assets of all 63 partnerships is $80.94 million. If the Proposals are approved
by Investors in companion Partnerships, after the sale of substantially all of
their properties such Partnerships will dissolve, wind up and terminate, and 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.
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. No fractional shares will be sold.
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 oversubscription. The Common Stock will be
listed on the New York Stock Exchange ("NYSE") and the Pacific Exchange, Inc.
(the "Pacific Exchange") under the symbol "SFY" since July 1991. The price at
which the Common Stock is offered hereby to Eligible Purchasers is based upon
its price on the NYSE during a period contemporaneous with completion of voting
upon the Proposals.
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, 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.
PARTNERSHIP PROPERTY INTERESTS
The oil and gas assets of the Partnerships (the "Property Interests")
consist either of working interests or non-operating interests in producing oil
and gas properties. Certain Partnerships, sometimes referred to herein as
"Operating Partnerships," were formed to purchase working interests in such
properties. Other Partnerships, sometimes referred to herein as "Pension
Partnerships," were designed for tax-exempt investors, and were formed to
purchase non-operating interests in 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 such Partnerships approve their Proposals, the Pension Partnerships will
sell their interests in oil and gas assets to their companion Operating
Partnerships, which will immediately thereafter sell the properties they have
received as well as their oil and gas assets to the Managing General Partner.
The most significant fields in which Partnerships own Property Interests are set
out in detail in each Partnership's specific Partnership Supplement (as defined
below) under "Partnership Property Interests."
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DOCUMENTS 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 particular to each
Investor's specific Partnership, and 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.
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" below. The Proposals present a potential
conflict 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 "--Conflicts
of Interest" below. 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 potential conflict of interest was 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 mitigating the potential conflict of interest in the sale of such
Property Interests to the Managing General Partner.
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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 Partnerships' Property Interests." 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 Sales." Also discussed under "The Proposals--Reasons for the Proposals"
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 Transaction." In addition to the
foregoing, there are certain risks involved in the Proposals. See "--Risks"
below and "Risk Factors."
RISKS
o There is no guarantee that the fair market value estimates of the
Appraisers 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, although
such prices likely would be offset by any additional general and
administrative costs, production costs or sales costs incurred during
the period necessary to close any such sales. See "Risk
Factors--Conflicts of Interest in Purchase of Property Interests by
Managing General Partner."
o The fair market values (excluding the 7.5% premium) at which the
Managing General Partner will purchase the Partnerships' Property
Interests is based upon the Appraisers' estimation of such values.
Year-end 1997 prices, along with other current market factors, were
used as a starting point for the Appraisers' analyses, 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 Partnerships, although the effect of any higher
prices 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 It is likely that if the Proposals are approved by Investors and the
Partnerships' Property Interests are purchased by the Managing General
Partner, the Managing General Partner will further develop the Property
Interests by spending required capital on recovery of behind-pipe
reserves or developing undeveloped reserves. Investors will not
directly share in any possible improvement of cash flow from such
Property Interests upon consummation of the Proposals. However, the
Managing General Partner is hereby providing an opportunity for
Investors to purchase Common Stock of the Company on a direct basis so
that they might share indirectly in any such improvement.
o In the event an Investor does not otherwise hold Swift Common Stock
but purchases shares hereunder, such Investor will become a shareholder
of the Company. The Company's business is different 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. 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. See "Risk Factors--Dependence on Vote of Companion Partnership"
and "The Proposals--Simultaneous Proposal to Companion Partnership."
3
<PAGE> 14
BACKGROUND AND REASONS FOR THE PROPOSALS; MANAGING GENERAL PARTNER'S
RECOMMENDATIONS
Background
A number of factors have led to the decision of the Company in its
capacity as Managing General Partner to solicit Investor approval 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 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 properties owned by the
Partnerships is fair to Investors and is structured in a manner so as to attempt
to realize the highest value for the Partnerships' Property Interests, given
that the purchase prices are based upon the higher of two estimates of the fair
market value of the Partnerships' Property Interests by three independent
Appraisers and contains a 7.5% premium above such fair market value. The
purchase of the assets of any particular Partnership is not conditioned upon the
purchase of the assets of any Partnership other than a Partnership's companion
Partnership.
Reasons
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 "The Proposal--Reasons for the Proposal," and vary from Partnership to
Partnership depending upon, among other factors, a Partnership's age and the
Property Interests which it owns. These reasons 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.
Although the amount differs among Partnerships, a majority of the
estimated ultimate recoverable reserves in which the Partnerships have an
interest have been produced. Because of steadily declining levels of production,
the Managing General Partner believes that the asset base and future net
revenues of many Partnerships no longer justify the continuation of the
Partnerships' operations, especially when a Partnership has been in existence
for six to twelve years. In many cases, a substantial portion of the estimated
ultimate recoverable reserves attributable to a Partnership's 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 always require completion in a different
producing zone, which does not take place until production is depleted from the
currently producing zone. The negative impact on levels of cash flow from sale
of production from
4
<PAGE> 15
Property Interests with significant 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, additional capital to drill wells to produce
undeveloped reserves is not available from the Partnerships or possibly other
third party owners of interests in the same wells. All of the Partnerships
expended their funds within the first or second year after their organization.
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 to consider the sale of the
Partnerships' Property Interests and increases the likelihood of maximizing the
value of the Partnerships' assets. 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 extreme volatility of oil and
gas prices, as well as inherent geological, engineering and operational risks,
which could affect future returns.
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 and "Background and Reasons for Proposals--Fairness of
Proposed Sale" for the Managing General Partner's assessment of the fairness of
the Proposals.
CONFLICTS OF INTEREST
A number of conflicts of interest are inherent in the relationships
among the Partnerships, the Managing General Partner and its directors and
officers. Certain of these conflicts of interest (to the extent not otherwise
discussed above) are summarized below:
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, including 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.
5
<PAGE> 16
o If Investors of all of the Partnerships approve the Proposals,
the Company anticipates that its total proved reserves on an
equivalent basis would increase by approximately 26% and would
increase the Company's cash flow and total assets by
approximately 25% and 19%, respectively.
See "Conflicts of Interest."
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
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
6
<PAGE> 17
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.
DETERMINATION OF PRICE TO BE PAID TO PURCHASE PARTNERSHIP PROPERTY INTERESTS
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 of fair market value
represents the Fair Market Value of each Partnership's Property Interests. In
the judgment of the Board of Directors of the Company, the simultaneous purchase
of the Partnerships' Property Interests 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. Because these benefits are particular to the
Company, the Company believes that it is fair to pay a premium of 7.5% over the
Fair Market Value of the Property Interests to purchase those interests. The
total purchase price for all oil and gas assets of all 63 partnerships is
approximately $81 million.
FAIRNESS OF PROPOSED SALE
The Managing General Partner believes that this proposed method of sale
of the Partnerships' Property Interests is fair to Investors for a variety of
reasons including, without giving weight to the order, the following:
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 (not including the 7.5% premium above Fair
Market Value) are based on the higher of two valuation
estimates of three qualified independent Appraisers, two of
which are petroleum engineering firms and one of which 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 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 bring various non-producing reserves into
production 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. In order to allow Investors
to benefit from any increase in value of the Property
Interests realized from the Managing General Partner's
investment of capital in such properties, the Company is
hereby offering to Eligible Purchasers the opportunity to
purchase up to 2,500,000 shares of Common Stock. There is no
requirement that any purchase of Swift's Common Stock be made.
See "Offer to Eligible Purchasers" below.
7
<PAGE> 18
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 "The Proposals--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.
FEDERAL INCOME TAX CONSEQUENCES
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 stock by Investors, see "Tax Risks" herein. 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. For a discussion of the federal income tax
consequences of a sale of properties and Partnership liquidation, see "Federal
Income Tax Consequences of the Proposals" herein. 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.
ACCOUNTING TREATMENT
The purchase by the Company of substantially all of the assets of the
Partnerships will be treated for accounting purposes in accordance with the
rules for purchase accounting. Accordingly, the assets of each
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<PAGE> 19
of the Partnerships will be recorded on the Company's books at their fair value.
See the "Notes to Unaudited Pro Forma Combined Financial Statements" included
elsewhere in this Joint Proxy Statement/Prospectus.
NO APPRAISAL OR DISSENTERS' RIGHTS PROVIDED; INVESTOR LISTS
In connection with the Proposals to sell substantially all of the
Partnerships' 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. 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 list 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. See "Comparison and Ownership of Units and Shares-- Review of
Investor List."
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.
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 proxy, both of which must be
9
<PAGE> 20
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."
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 Partnerships 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. 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 March 31, 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 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.
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<PAGE> 21
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.
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.
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<PAGE> 22
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
PARTNERSHIP COMPANY
- -----------------------------------------------------------------------------------------------------------------
<S> <C>
Form of Organization
--------------------
o Partnerships formed as Texas limited o Company formed as a Texas corporation
partnerships
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.
Length of Investment
--------------------
o Expected holding period of five to ten years after o Company to be operated as an infinite life entity,
acquisition, subject to the Managing General with no plans or expectations as to the liquidation of
Partner's judgment as to the timing of sales Company assets
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.
Additional Equity
-----------------
o Not authorized to issue equity securities beyond o Board of Directors may issue additional equity
the Units initially offered to the public securities consisting of Common Stock or
Preferred Stock, plus various debt securities, as
a combination of the above
o Company expected to issue additional securities
to finance future investments
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.
Debt Policy
-----------
o Partnerships not intended to borrow any o Expected that the Company may incur
substantial funds more leverage than the Partnerships
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>
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<PAGE> 23
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
PARTNERSHIP COMPANY
- -----------------------------------------------------------------------------------------------------------------
<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
Incorporation and By-Laws
o Investors have no right to participate in o Shareholders elect members of the Board of
management, except for limited matters that Directors on a staggered basis annually
might be submitted to a vote of the Investors,
such as the Proposals
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.
Compensation, Fees and Distribution
-----------------------------------
o General and administrative cost reimbursement of o No fees payable to the Company
up to 2.0% of a Partnership's original
subscriptions and for partnerships formed after
May 1991, an incentive of 1.25% of net
revenues. The Managing General Partner bears
its proportionate share of these costs and fees
Under the Partnership Agreement, each of the Partnerships pay cost reimbursements, and in some cases,
fees to the Managing General Partner, which the Managing General Partner will not receive if the Proposals are
approved. See "Comparison of Ownership of Units and Shares, Fees and Distributions" for a detailed description
of the compensation and expenses of the Partnerships.
</TABLE>
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<PAGE> 24
SWIFT ENERGY COMPANY
The Company is engaged in the exploration, development, 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, with 93% of its proved reserves
base concentrated in Texas. As of the same date, the Company had estimated
proved reserves of 361.5 Bcfe, approximately 87% of which were natural gas, and
operated 650 wells representing 91% of its proved reserves base.
The Company's primary focus is exploration and development drilling in
its 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 more 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. Primarily in these areas, the Company has substantially
accelerated its drilling activities during the last several years, drilling 42,
116, and 135 net wells in 1995, 1996, and 1997, respectively. The Company is
also actively pursuing exploratory and development drilling opportunities in
other basins in Texas, Arkansas, Louisiana and Wyoming. As a complement to these
domestic activities, the Company is participating in several high potential
international projects with limited capital exposure to the Company in New
Zealand, Russia and Venezuela.
14
<PAGE> 25
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
three months ended March 31, 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 three months ended March 31, 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 three months ended March 31, 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>
THREE MONTHS ENDED
MARCH 31, 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....................... $ 15,802 $ 18,370 $ 69,015 $ 52,771 $ 22,528 $ 19,802 $ 15,536
Fees and Earned Interests(b)............ 80 99 746 937 590 702 4,072
Supervision fees........................ 1,286 1,248 5,210 4,470 3,839 3,751 3,719
Interest income......................... 19 999 2,395 433 212 48 201
Other, net.............................. 575 530 2,556 2,157 1,762 1,073 604
-------- -------- -------- -------- -------- -------- --------
Total Revenues.................... 17,762 21,246 79,922 60,768 28,931 25,376 24,132
-------- -------- -------- -------- -------- -------- --------
Costs and Expenses:
General and administrative, net of
reimbursement......................... 1,643 1,575 6,129 6,385 5,256 5,198 5,065
Depreciation, depletion, and
amortization.......................... 6,735 5,397 24,247 16,526 8,839 7,905 7,301
Oil and gas production.................. 3,163 2,763 11,384 8,377 6,826 5,640 4,540
Interest expense, net................... 1,385 1,350 5,033 694 1,115 1,795 598
-------- -------- -------- -------- -------- -------- --------
Total Costs and Expenses.......... 12,926 11,085 46,793 31,982 22,036 20,538 17,504
-------- -------- -------- -------- -------- -------- --------
Income before Income Taxes................ 4,836 10,161 33,129 28,786 6,895 4,838 6,628
Provision for Income Taxes................ 1,606 3,392 10,819 9,760 1,982 1,112 1,732
-------- -------- -------- -------- -------- -------- --------
Income Before Cumulative Effect of Change
in Accounting Principle................. $ 3,230 $ 6,769 $ 22,310 $ 19,026 $ 4,913 $ 3,726 $ 4,896
======== ======== ======== ======== ======== ======== ========
Per share amounts (c)--
Basic................................... $ 0.20 $ 0.41 $ 1.35 $ 1.27 $ 0.49 $ 0.51 $ 0.68
======== ======== ======== ======== ======== ======== ========
Diluted................................. $ 0.20 $ 0.37 $ 1.26 $ 1.25 $ 0.49 $ 0.51 $ 0.64
======== ======== ======== ======== ======== ======== ========
Weighted Average Shares Outstanding(c).... 16,500 16,703 16,493 15,001 10,035 7,309 7,247
======== ======== ======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
EBITDA(d)................................. $ 12,956 $ 16,908 $ 62,410 $ 46,006 $ 16,849 $ 14,538 $ 14,527
Net cash provided by operating
activities.............................. 13,020 19,539 55,256 37,103 14,376 10,395 7,238
Capital expenditures...................... 27,980 28,409 131,967 91,487 40,033 34,531 24,229
Ratio of earnings to fixed charges(e)..... 2.9x 6.4x 5.2x 12.6x 3.1x 2.6x 6.8x
BALANCE SHEET DATA:
Working capital........................... $(13,700) $ 52,509 $ 1,464 $ 68,704 $ 3,247 $(13,137) $ 9,742
Total assets.............................. 358,831 318,334 339,115 310,375 175,253 135,673 160,893
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
Bank borrowings......................... 15,124 -- 7,915 -- -- -- --
Stockholders' equity...................... 162,945 146,911 159,401 142,762 93,346 42,127 54,466
</TABLE>
- ---------------
(a) For a discussion of the significant items affecting comparability of 1997,
1996, 1995, and for the three months ended March 31, 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
three months ended March 31, 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) EBITDA represents income from continuing operations before interest
expense, income tax, and depreciation, depletion, and amortization. EBITDA
is not a calculation based upon generally accepted accounting principles
("GAAP"); however, the amounts included in the EBITDA calculation are
derived from amounts included in the Consolidated Historical Statements of
Income of the Company. In addition, EBITDA should not be considered as an
alternative to net income or operating income, as an indication of the
operating performance of the Company or as an alternative to cash flow from
operating activities as a measure of liquidity.
(e) For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expense 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.
15
<PAGE> 26
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 three month period ended March
31, 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 purchase of
substantially all of the assets (the "Acquisitions") of (i) 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 (ii) the effect of the approval
of the Proposals by those 51 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 three months ended March 31, 1998
of all 63 Partnerships ("50% Case") for (a) all cash or (b) 2.3 million shares
of Common Stock at an assumed price of $18 per share. The unaudited summary pro
forma statements of income data assumes the Acquisitions occurred January 1,
1997. The unaudited summary balance sheet data assumes the Acquisitions occurred
as of March 31, 1998. The unaudited summary pro forma data is not necessarily
indicative of the results that actually would have occurred if the Acquisitions
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 PRO FORMA 50% CASE 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 $104,495 $104,495 $ 92,990 $ 92,990
Fees from limited partnerships......................... 746 542 542 623 623
Supervision fees....................................... 5,210 5,210 5,210 5,210 5,210
Interest income........................................ 2,395 2,395 2,395 2,395 2,395
Other, net............................................. 2,556 2,778 2,778 2,709 2,709
-------- -------- -------- -------- --------
Total Revenues................................... 79,922 115,420 115,420 103,927 103,927
-------- -------- -------- -------- --------
Costs and Expenses:
General and administrative, net of reimbursement....... 6,129 10,288 10,288 9,119 9,119
Depreciation, depletion, and amortization.............. 24,247 33,801 33,801 30,569 30,569
Oil and gas production................................. 11,384 22,937 22,937 19,184 19,184
Interest expense, net.................................. 5,033 9,799 6,312 8,179 5,033
-------- -------- -------- -------- --------
Total Costs and Expenses......................... 46,793 76,825 73,338 67,051 63,905
-------- -------- -------- -------- --------
Income before Income Taxes............................... 33,129 38,595 42,082 36,876 40,022
Provision for Income Taxes............................... 10,819 13,122 14,308 12,538 13,607
-------- -------- -------- -------- --------
Income Before Cumulative Effect of Change in Accounting
Principle.............................................. $ 22,310 $ 25,473 $ 27,774 $ 24,338 $ 26,415
======== ======== ======== ======== ========
Per share amounts --
Basic.................................................. $ 1.35 $ 1.54 $ 1.46 $ 1.48 $ 1.41
======== ======== ======== ======== ========
Diluted................................................ $ 1.26 $ 1.41 $ 1.36 $ 1.35 $ 1.31
======== ======== ======== ======== ========
Weighted Average Shares Outstanding...................... 16,493 16,493 18,993 16,493 18,748
======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
EBITDA(a)................................................ $ 62,410 $ 82,195 $ 82,195 $ 75,624 $ 75,624
Net cash provided by operating activities................ 55,256 67,769 70,070 63,402 65,479
Capital expenditures..................................... 131,967 196,615 196,615 175,715 175,715
Ratio of earnings to fixed charges(b).................... 5.2x 4.0x 5.5x 4.3x 6.0x
</TABLE>
(Pro forma data and notes thereto continued on following page)
16
<PAGE> 27
SUMMARY PRO FORMA CONSOLIDATED FINANCIAL DATA
OF SWIFT ENERGY COMPANY -- (CONTINUED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31, 1998
-------------------------------------------------------------
100% CASE PRO FORMA 50% CASE 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..................................... $ 15,802 $ 20,539 $ 20,539 $ 18,760 $ 18,760
Fees from limited partnerships........................ 80 48 48 66 66
Supervision fees...................................... 1,286 1,286 1,286 1,286 1,286
Interest income....................................... 19 19 19 19 19
Other, net............................................ 575 609 609 598 598
-------- -------- -------- -------- --------
Total Revenues.................................. 17,762 22,501 22,501 20,729 20,729
-------- -------- -------- -------- --------
Costs and Expenses:
General and administrative, net of reimbursement...... 1,643 2,585 2,585 2,350 2,350
Depreciation, depletion, and amortization............. 6,735 8,376 8,376 7,783 7,783
Oil and gas production................................ 3,163 5,241 5,241 4,576 4,576
Interest expense, net................................. 1,385 2,576 1,704 2,171 1,385
-------- -------- -------- -------- --------
Total Costs and Expenses........................ 12,926 18,778 17,906 16,880 16,094
-------- -------- -------- -------- --------
Income before Income Taxes.............................. 4,836 3,723 4,595 3,849 4,635
Provision for Income Taxes.............................. 1,606 1,266 1,562 1,309 1,576
-------- -------- -------- -------- --------
Income Before Cumulative Effect of Change in Accounting
Principle............................................. $ 3,230 $ 2,457 $ 3,033 $ 2,540 $ 3,059
======== ======== ======== ======== ========
Per share amounts --
Basic................................................. $ 0.20 $ 0.15 $ 0.16 $ 0.15 $ 0.16
======== ======== ======== ======== ========
Diluted............................................... $ 0.20 $ 0.15 $ 0.16 $ 0.15 $ 0.16
======== ======== ======== ======== ========
Weighted Average Shares Outstanding..................... 16,500 16,500 19,000 16,500 18,756
======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
EBITDA(a)............................................... $ 12,956 $ 14,675 $ 14,675 $ 13,803 $ 13,803
Net cash provided by operating activities............... 13,020 14,335 14,911 13,825 14,344
Capital expenditures.................................... 27,980 90,181 90,181 69,164 69,164
Ratio of earnings to fixed charges(b)................... 2.9x 1.9x 2.6x 2.1x 2.8x
BALANCE SHEET DATA:
Working capital......................................... $(13,700) $(8,974) $ (9,270) $ (8,747) $ (9,014)
Total assets............................................ 358,831 424,266 424,266 402,729 402,729
Long-term debt:
6.25% Convertible Subordinated Notes.................. 115,000 115,000 115,000 115,000 115,000
Bank borrowings....................................... 15,124 76,624 31,624 55,724 15,124
Stockholders' equity.................................... 162,945 166,665 211,369 167,145 207,478
</TABLE>
- ---------------
(a) EBITDA represents income from continuing operations before interest
expense, income tax, and depreciation, depletion, and amortization. EBITDA
is not a calculation based upon GAAP; however, the amounts included in the
EBITDA calculation are derived from amounts included in the Consolidated
Historical Statements of Income of the Company. In addition, EBITDA should
not be considered as an alternative to net income or operating income, as
an indication of the operating performance of the Company or as an
alternative to cash flow from operating activities as a measure of
liquidity.
(b) For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expense 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.
17
<PAGE> 28
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 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 50% CASE
1997 PRO 1997 PRO
FORMA(A) 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.................. 245,543 229,845 191,108 135,425 81,532 46,406 50,937
Proved undeveloped................ 136,523 133,183 123,198 90,333 62,036 29,858 13,526
-------- -------- -------- -------- -------- ------- -------
Total...................... 382,066 363,028 314,306 225,758 143,568 76,264 64,463
======== ======== ======== ======== ======== ======= =======
Net oil reserves (MBbl):
Proved developed.................. 7,421 6,506 4,289 3,622 3,313 3,209 3,110
Proved undeveloped................ 4,723 4,344 3,570 1,862 2,109 1,344 1,161
-------- -------- -------- -------- -------- ------- -------
Total...................... 12,144 10,850 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.................. $314,944 $294,792 $244,365 $310,409 $ 85,537 $47,172 $66,310
Proved undeveloped................ 125,303 120,015 105,980 160,776 61,501 22,223 17,451
-------- -------- -------- -------- -------- ------- -------
Total PV-10 Value (before
income taxes)(b)......... $440,247 $414,807 $350,345 $471,185 $147,038 $69,395 $83,761
======== ======== ======== ======== ======== ======= =======
Standardized measure of discounted
estimated future net cash flows
after income taxes................ $363,545 $341,078 $292,838 $367,232 $128,904 $66,472 $74,968
======== ======== ======== ======== ======== ======= =======
Prices used in calculating end of
year proved reserves:
Oil (Per Bbl)..................... $ 15.76 $ 15.76 $ 15.76 $ 23.75 $ 18.07 $ 15.09 $ 12.87
======== ======== ======== ======== ======== ======= =======
Gas (Per Mcf)..................... $ 2.78 $ 2.78 $ 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 the Acquisitions 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)
18
<PAGE> 29
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 50% CASE
1997 PRO 1997 PRO
FORMA(A) FORMA(A) 1997 1996 1995 1994 1993
--------- -------- ------- ------- ------- ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
PRODUCTION:
Net Sales Volume:
Oil (MBbls)....................... 1,303 1,101 672 623 545 467 324
Gas (MMcf)(b)..................... 29,930 27,086 21,359 15,697 7,914 6,799 5,422
Gas equivalents (MMcfe)........... 37,747 33,695 25,394 19,437 11,187 9,601 7,369
WEIGHTED AVERAGE SALES PRICES:
Oil (Per Bbl)....................... $ 17.49 $ 17.53 $ 17.59 $ 19.82 $ 15.66 $14.35 $15.10
Gas (Per Mcf)....................... $ 2.73 $ 2.72 $ 2.68 $ 2.57 $ 1.77 $ 1.93 $ 1.96
SELECTED DATA PER MCFE:
Production Costs.................... $ 0.61 $ 0.57 $ 0.45 $ 0.43 $ 0.61 $ 0.59 $ 0.62
Depreciation, depletion, and
amortization...................... $ 0.90 $ 0.91 $ 0.95 $ 0.85 $ 0.79 $ 0.82 $ 0.99
General and administrative, net of
reimbursement..................... $ 0.27 $ 0.27 $ 0.24 $ 0.33 $ 0.47 $ 0.54 $ 0.69
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 the Acquisitions 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.
19
<PAGE> 30
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 three months ended March 31, 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 three months ended March 31, 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 three months ended March 31, 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>
THREE MONTHS ENDED
MARCH 31, 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................. $ 5,659 $13,856 $ 42,228 $ 52,512 $ 43,430 $ 54,902 $ 58,061
Net income (loss).................... $ (1,600) $ 1,889 $ 6,966 $ 11,938 $ (8,346) $(14,094) $ 13,573
Investor's net income (loss)
per $100 investment................ $ (0.58) $ 0.24 $ 1.64 $ 2.91 $ (2.62) $ (8.08) $ 2.51
BALANCE SHEET DATA:
Cash and cash equivalents............ $ 6,270 $ 7,429 $ 7,169 $ 3,622 $ 11,904 $ 16,269
Total assets......................... $100,323 $108,597 $127,839 $144,418 $174,105 $195,942
Total liabilities.................... $ 4,207 $ 4,680 $ 5,403 $ 14,755 $ 17,606 $ 28,179
Limited Partners' equity............. $ 94,569 $101,783 $119,714 $127,264 $154,111 $165,006
General Partners' equity............. $ 1,547 $ 2,134 $ 2,722 $ 2,399 $ 2,388 $ 2,757
Investors' book value per $100
investment......................... $ 28.53 $ 30.71 $ 36.12 $ 38.40 $ 46.50 $ 49.79
OTHER DATA:
Net cash provided by operating
activities......................... $ 2,566 $ 23,742 $ 20,694 $ 24,305 $ 32,788 $ 33,679
Net increase (decrease) in cash and
cash equivalents................... $ (1,159) $ 260 $ 3,547 $ (8,282) $ (4,365) $ 16,269
Total assets at the value assigned
for the Transaction................ $ 75,291
Investor's value assigned for the
Transaction Per $100 investment.... $ 19.53
Cash distributions................... $ 6,201 $ 6,925 $ 25,484 $ 19,165 $ 18,490 $ 29,243 $ 29,471
Investors' cash distributions per
$100 investment.................... $ 1.59 $ 1.75 $ 6.69 $ 4.75 $ 4.91 $ 7.56 $ 7.60
Ratio of earnings to fixed
charges(a)......................... NM 462.1x 325.6x 59.3x NM NM 42.2x
</TABLE>
- ---------------
(a) For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expense. Earnings represents income before income
taxes and before fixed charges. Earnings were inadequate to cover fixed
charges for the years ended December 31, 1995, 1994 and for the three
months ended March 31, 1998 by $8.3 million, $14.1 million and $1.6
million, respectively.
20
<PAGE> 31
SPECIAL FACTORS REGARDING THE PROPOSALS TO SELL
THE PARTNERSHIPS' OIL AND GAS ASSETS
PROPERTY INTERESTS OF PARTNERSHIPS
Tabulations presenting information specific to a Partnership are set
out in each Partnership's specific 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 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.
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") 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
mitigating the potential conflict 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
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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.
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
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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 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 any given 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
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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 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.
EVALUATION PROCEDURES
In summary, the evaluation procedures used by the Petroleum
Engineering Consultants included:
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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.
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
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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.
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
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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.
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
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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 financial analysis as to
the estimated fair market value of Property Interests held by the Partnership.
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 Valuation Letters set forth in this Joint Proxy Statement/Prospectus is
qualified in its entirety by reference to
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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; PREMIUM OVER FAIR MARKET VALUE
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, 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 ____. 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 "_____________________" in the Joint Proxy Statement/Prospectus 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. 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. Because these
benefits are particular to the Company, the Company believes that it is fair to
pay a premium of 7.5% over the Fair Market Value of the Property Interests to
purchase those interests.
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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.
FAIRNESS OF PROPOSED SALE
The Managing General Partner believes that this proposed method of
sale of the Partnerships' Property Interests is fair to Investors for a variety
of reasons, none of which is given greater weight than another:
1. The Managing General Partner believes that the most important
element of the Proposal is the determination of the Fair
Market Value of the Partnerships' Property Interests based on
the estimations of such value by third party independent
Appraisers. Instead of the Managing General Partner
attempting to set the Fair Market Value of the Property
Interests, the price to be paid by the Managing General
Partner for the Partnerships' Property Interests (not
including the 7.5% premium above Fair Market Value) was based
on the valuation estimates of three qualified independent
Appraisers, two of which are petroleum engineering firms and
one of which is an investment banking firm. Using three
different firms from two different disciplines has been
designed to provide a comprehensive analysis of valuation
factors. 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 the
Partnerships' Property Interests."
2. No transaction will take place unless the Proposal is approved
by Investors holding at least a majority of the interests in
the Partnerships, without the Managing General Partner voting
any limited partner interests in the Partnerships which it
owns, and a similar proposal is approved by each 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 Managing
General Partner.
4. If any of the Proposals are approved by Investors, it is
likely that the Managing General Partner will expend the
capital necessary to bring various non-producing reserves into
production 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. In order to allow Investors
to benefit from any increase in value of the Property
Interests realized from the Managing General Partner's
investment of capital in such properties, the Company is
hereby offering to Eligible Purchasers the opportunity to
purchase on a collective basis up to 2,500,000 shares of
Common Stock of Swift Energy Company. There is no requirement
that any such purchase of Swift's Common Stock be made. See
"Offer to Eligible Purchasers" below.
The terms and price of the proposed purchase of the Partnerships' oil
and gas assets by Swift Energy Company and the procedures established for such
purchase have been approved by unanimous vote of the Board of Directors of
Swift in approving a recommendation made by the Special Transactions Committee
comprised solely of outside directors of Swift. 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 purpose
of negotiating the terms upon which any purchase by Swift would be made or
preparing a report concerning the fairness of such transaction.
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.
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.
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
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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.
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,
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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.
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 a sale have been approved by vote of the Board of
Directors of Swift Energy Company based upon the recommendation of the Special
Transactions Committee. The funds for any such purchase by the Managing
General Partner of the Partnerships' Property Interests will be funded from the
Managing General Partner's working capital and cash flow.
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.
FEDERAL INCOME TAX CONSEQUENCES
For information concerning the federal income tax risks associated
with the sale of substantially all of the Partnerships' Property Interests,
distribution of sales proceeds to Investors and liquidation of the
Partnerships, see "Tax Risks" herein. 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. For a discussion of the federal income tax consequences of a
sale of properties and Partnership liquidation, see "Federal Income Tax
Consequences of the Proposals" herein.
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
Swift Energy Company will use internally generated cash resources and
borrowings available under its existing $100 million unsecured revolving line
of credit with two bank groups to purchase the Partnerships' Property
Interests. The principal terms and restrictions of these credit facilities are
described in detail in Note 4 to the Company's financial statements contained
herein. It is anticipated that these borrowings will be repaid through
internally generated cash flows, bank borrowings, and debt and/or equity
financing.
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MANAGING GENERAL PARTNER BENEFITS
The Managing General Partner will share the benefits available to
Investors through liquidating its partnership interests and receiving the
current value of those interests as a result of such sales. Additionally, by
purchasing the Partnerships' Property Interests itself, the Managing General
Partner will continue to serve as operator of many of the properties in which
the Partnerships own interests and will continue to receive operating fees.
However, the Managing General Partner is making similar Proposals to Investors
in the 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 substantially all of their properties to the Managing General Partner,
the Managing General Partner anticipates that the oil and gas interests
acquired would increase Swift's total proved reserves on a gas equivalent basis
of the Managing General Partner by approximately 26%, and would increase the
Company's cash flow and total assets by approximately 25% and 19%,
respectively.
If the Proposal is not approved by Investors holding at least a
majority of the Units then held by Investors and a similar proposal is not also
approved by the required vote of the Investors of the Partnerships' companion
Operating Partnership, such Partnerships will continue to exist.
INVESTORS ARE URGED TO COMPLETE, SIGN AND DATE THE ENCLOSED PROXY AND
TO RETURN IT TO THE MANAGING GENERAL PARTNER NO LATER
THAN JULY _____, 1998.
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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, 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. 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.
An Investor considering whether to vote in favor of a Proposal should
give careful consideration to the risks involved, including those summarized
below:
RISKS OF THE PROPOSALS
CONFLICTS OF INTEREST IN PURCHASE OF PROPERTY INTERESTS BY MANAGING GENERAL
PARTNER
If the Partnerships' Property Interests ultimately would be sold to
the Managing General Partner at the Fair Market Value, which has been set by
the Special Transactions Committee based on the valuation estimates of the
Appraisers plus a 7.5% premium. See "Dependence on Vote of Companion
Partnership." There is no guarantee that this purchase price represents the
highest possible price 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.
Furthermore, it is possible that proved non-producing reserves may have a
greater variance in value than attributed to them by the Appraisers. A
different price (either higher or lower) might also be received if certain
properties were sold at auction or in negotiated sales.
TIMING OF SALE AND PRICE VOLATILITY
The Fair Market Value of a Partnership's Property Interests has been
based on fair market value estimates set by the Appraisers, which in turn were
based upon numerous factors, including use of year-end 1997 prices which were
escalated thereafter (in conjunction with costs and compatible with current
industry pricing scenarios) and estimates of the reserves attributed thereto.
Reserves quantities and the value thereof vary based upon pricing, and it is
possible that either a higher or lower price could be received in open market
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transactions for a Partnership's Property Interests, depending upon future
prices for either or both of oil and gas.
DEPENDENCE ON VOTE OF COMPANION PARTNERSHIP
If a Partnership's companion Partnership does not approve its Proposal
to sell substantially all of its assets and liquidate, it is likely that the
Proposals to both 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. See "The Proposal--Simultaneous Proposal to Companion
Partnership." 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. If
the Proposals are approved by Investors of companion Pension Partnerships and
Operating Partnerships, the entire Property Interests owned by such
Partnerships will be sold.
POSSIBLE INCREASE IN VALUE OF PROPERTY INTERESTS DUE TO DRILLING ACTIVITY AFTER
THE SALE
If the Proposals to sell the Partnerships' Property Interests are
approved by Investors and the Managing General Partner ultimately purchases
these interests, it is likely that the Managing General Partner will invest
substantial capital in drilling activities in the fields covered by the
Partnerships' Property Interests, which may increase the value of those
interests. It is also possible that future drilling activity by third parties
in or near the fields in which the Partnerships own Property Interests could
increase the values of such Property Interests. The Partnerships cannot
participate in this drilling activity for a variety of reasons, including
having limited available capital. In addition, certain of this drilling
activity is likely to consist of higher risk development or exploratory
drilling. The Partnerships were not formed to engage or invest in these
activities because of their higher risk. In order to address any conflicts of
interest created by this situation, the Company is hereby offering up to
2,500,000 shares of Common Stock directly to Investors of Partnerships and
companion Partnerships which approve the Proposals as a method of sharing in
any gains which might be realized due to such activity.
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 as they 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.
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DEMAND IN MARKET
There can be no assurance that demand will rise for the Shares after
the consummation of the Proposals. Whether or not such demand arises 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.
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 is fundamentally changed.
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 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 expected to achieve
liquidity of their investments by trading the Shares on the secondary market.
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
Shareholders receive dividends only when declared by the Board of
Directors and are dependent upon the securities market in order to liquidate
their investments. 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.
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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
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 at prices below the then fair market value of such
securities, 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."
VOLATILITY OF OIL AND GAS PRICES AND MARKETS
The Company's profitability is substantially dependent on prevailing
prices for oil and natural gas. The amounts of and price obtainable for the
Company's oil and gas production will be affected by market factors beyond the
Company's control. Such factors include the extent of domestic production, the
level of imports of foreign oil and gas, the general level of market demand on
a regional, national and worldwide basis, domestic and foreign economic
conditions that determine levels of industrial production, political events in
foreign oil-producing regions and variations in governmental regulations and
tax laws or the imposition of new governmental requirements upon the oil and
gas industry. Prices for oil and gas are subject to wide fluctuation in
response to relatively minor changes in supply of and demand for oil and gas,
market uncertainty and a variety of additional factors that are beyond the
control of the Company. In addition, the marketability of the Company's
production depends in part upon the availability, proximity and capacity of
gathering systems, pipelines and processing facilities. A substantial and
prolonged decline in oil and gas prices could have a material adverse effect
upon the Company.
The Company currently emphasizes the exploration and development of
natural gas reserves. See "Business and Properties--General." As a result of
changes in recent years in the natural gas market regulatory structure and
volatility in the market price for 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 which 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. Thus, while the Company has never
been required to write down its asset base, and at December 31, 1997 there was
a substantial excess of reserves over capitalized costs under the ceiling test,
declines in oil and gas prices, if sustained, could require a writedown of the
value of the Company's oil and gas properties unless at the same time the
Company had sufficient net additional reserves to offset the effect of any such
decline in oil and gas prices. Although any such writedown would not affect
cash flow from operating activities, it would constitute a charge to earnings.
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 exploration for and
development of oil and gas reserves and the acquisition of
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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 exploration and development and acquisition activities will result in
the replacement of, or additions to, the Company's reserves.
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 $138 million for the last months of 1998. Cash flow from
operations and, to the extent available, proceeds from this offering 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. 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. Should sufficient capital not be available, the
exploration and development 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 Prospectus.
The estimates of future net revenues reflect oil and gas prices as of the date
of estimation, without escalation, 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 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."
The estimates of future net revenues and their present values assume
that some portion of the limited partnerships in which the Company owns
interests will achieve payout status. At payout, the Company's percentage
ownership of the limited partnerships' reserves increases. The primary
assumptions utilized for purposes of such estimates consist of (i) the
continuation of oil and gas prices realized by the Partnerships at year-end
1997 through the life of the properties owned by the Partnerships and (ii) the
continued ownership of such properties. Only ten of the limited Partnerships
in which the Company owns an interest had achieved payout status at the date of
this Prospectus and achievement of payout status for the remaining Partnerships
will depend not only upon prices at which future production is sold, but also
upon whether individual properties are sold prior to depletion and the prices
received in such sales. See "--Volatility of Oil and Gas Prices and Markets"
and "Business and Properties--Partnerships."
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EXPLORATION AND DEVELOPMENT RISKS
Exploration and development 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. The
Company's drilling operations may be curtailed, delayed or canceled as a 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--Exploration and Development Drilling Activities."
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 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. 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
considered prohibitive.
EFFECT OF PRICE RISK MANAGEMENT
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.
Therefore, the Company intends to expend only limited amounts to hedge pricing
risks. See "Business and Properties--Price Risk Management."
RISKS OF PURCHASING INTERESTS IN OIL AND GAS PROPERTIES
Although the Company emphasizes reserve growth through drilling, it
expects to make acquisitions of oil and gas properties from time to time. The
Company generally focuses most of its title and valuation efforts on the more
significant properties. It is generally not feasible for the Company to review
in-depth every property it purchases and all records with respect to such
properties. However, even an in-depth 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."
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FOREIGN ACTIVITIES
In the last five years, the Company has undertaken exploration and
development activities in New Zealand and Russia. The Company is also pursuing
opportunities in Venezuela. The Company is also performing certain seismic
work on approximately 88,000 acres in an onshore area located in New Zealand
pursuant to an Exploration Permit which provides for certain work to be
performed in stages through the year 2000. In Russia, the Company has entered
into and amended several agreements with a Russian joint stock company to
develop and produce reserves from two fields in Western Siberia, providing the
Company with a minimum 6% net profits interest in the properties. In addition,
the Company has entered into an agreement with a Venezuelan company to jointly
formulate and submit a proposal for the construction and operation of a methane
pipeline. 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. 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.
COMPETITION
The Company operates in a highly competitive environment. The Company
competes with major integrated and independent energy companies 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."
GOVERNMENTAL AND ENVIRONMENTAL REGULATION
The production of oil and natural gas is subject to regulation under a
wide range of United States federal and state statutes, rules, orders and
regulations. State and federal statutes and regulations require permits for
drilling, reworking and recompletion operations, drilling bonds and reports
concerning operations. 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. See "Business and Properties--Regulations."
Various federal, state and local laws and regulations relating to the
protection of the environment may affect the Company's operations and costs.
In particular, the Company's production operations and its use of facilities
for treating, processing or otherwise handling hydrocarbons and wastes
therefrom are subject to stringent environmental regulation. Although
compliance with these regulations increases the cost of Company operations,
such compliance has not had a material effect on the Company's capital
expenditures, earnings or competitive position. Environmental regulations have
historically been subject to frequent change by regulatory authorities and the
Company is unable to predict the ongoing cost of complying with these laws and
regulations or the future impact of such regulations on its operations. A
significant discharge of hydrocarbons into the environment could, to the extent
such event is not insured, subject the Company to substantial expense. See
"Business and Properties--Regulations--Environmental Regulations."
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<PAGE> 53
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. The loss of key personnel could have a material adverse
effect on the Company. See "Management."
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, private letter rulings(s)), 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.
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, 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."
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
As currently proposed, 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 income tax purposes, Investors subscribing for shares of Company
stock will be
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<PAGE> 54
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.
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"), 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 June ___, 1998.
REASONS FOR THE PROPOSAL
The Managing General Partner believes that it is in the best interest
of the Investors for their Partnerships to sell its Property Interests at this
time and to dissolve the Partnerships and make a final liquidating distribution
to its Partners for the reasons discussed below.
Current Liquidating Distribution Lowers Volatility Risk. The
Partnerships have been in existence for between four and twelve years. As
discussed above, 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 decreases. It is also the Managing General Partner's belief
that improvements over the last several years in the level of oil and gas
prices, particularly those for natural gas, relative to prices
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<PAGE> 55
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.
Decreasing Cash Flow While Expenses Continue. Although the amount
differs among Partnerships, 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 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
Partnership.
Effect of 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. 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.
Behind-Pipe Reserves. In many cases, a substantial portion of the
remaining reserves attributable to properties in which the Partnerships have 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 those Partnerships' operations and their
ultimate cash distributions can only occur 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. No additional development activities
are contemplated on the properties in which the Partnerships have an interest.
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."
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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 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 Partners 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.
NO APPRAISAL OR DISSENTERS' RIGHTS PROVIDED
In connection with the Proposals to sell substantially all of the
Partnerships' 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.
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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 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.
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);
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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
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."
Other. Any sale of the Partnerships' Property Interests and the
subsequent liquidating distributions to the Investors, if any, pursuant to the
Proposals will be taxable transactions under federal and state income tax laws,
even though certain Tax Exempt Investors may not be required to recognize any
taxable income or loss. See "Federal Income Tax Consequences of Adoption of
the Proposals."
IMPACT ON THE MANAGING GENERAL PARTNER
The Managing General Partner will purchase the Partnerships' Property
Interests if the Proposals are approved by the companion Partnerships. To the
extent of the Managing General Partner's ownership of Units, liquidation will
have the same effect on it as on the Investors. 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 that the oil and gas interests acquired would increase
Swift's total proved reserves on a gas equivalent basis of the Managing General
Partner by approximately 26%, and would increase the Company's cash flow and
total assets by approximately 25% and 19%, respectively. 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.
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RECOMMENDATION OF THE MANAGING GENERAL PARTNER
For the foregoing reasons, the Managing General Partner believes that
it is in the best interests of the Investors to dissolve and liquidate 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 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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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
- -----------------------------------------------------------------------------------------------------------------
<S> <C>
FORM OF ORGANIZATION
--------------------
Each of the Partnerships is a limited partnership The Company is a Texas business corporation.
organized under the laws of the State of Texas.
LENGTH OF INVESTMENT
--------------------
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.
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<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
PARTNERSHIP COMPANY
- -----------------------------------------------------------------------------------------------------------------
<S> <C>
PROPERTIES AND DIVERSIFICATION
------------------------------
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."
The investment portfolio for each Partnership was limited to the assets acquired with its initial
equity. Through consummation of the Proposals, and through additional investments that have been made from
time to time, the Company has an investment portfolio substantially larger and more diversified than the
portfolio of any of the Partnerships.
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>
51
<PAGE> 62
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
PARTNERSHIP COMPANY
- -----------------------------------------------------------------------------------------------------------------
<S> <C>
ADDITIONAL EQUITY
-----------------
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.
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.
BORROWING POLICIES
------------------
The Partnership Agreement of each of the The Company is permitted to borrow, on a secured or
Partnerships places various restrictions on the unsecured basis, funds to finance its business,
authority of the Partnership to borrow funds. subject to restrictions contained in its revolving
Furthermore, as a matter of overall policy, each of credit agreement [or the Indenture governing its
the Partnerships limited the amount it borrowed, if Convertible Subordinated Notes due 2006.]
any, to finance the Partnership's activities.
In conducting its business, the Company may incur Indebtedness to the extend 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.
MANAGEMENT CONTROL AND RESPONSIBILITY
-------------------------------------
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
</TABLE>
52
<PAGE> 63
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
PARTNERSHIP COMPANY
- -----------------------------------------------------------------------------------------------------------------
<S> <C>
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>
53
<PAGE> 64
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
PARTNERSHIP COMPANY
- -----------------------------------------------------------------------------------------------------------------
<S> <C>
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.
MANAGEMENT LIABILITY AND INDEMNIFICATION
----------------------------------------
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.
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.
</TABLE>
54
<PAGE> 65
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
PARTNERSHIP COMPANY
- -----------------------------------------------------------------------------------------------------------------
<S> <C>
VOTING RIGHTS
-------------
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.
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>
55
<PAGE> 66
COMPENSATION, FEES AND DISTRIBUTION
Under the Partnership Agreements, substantial compensation,
reimbursements and distributions have been paid to the Managing General
Partner. To the extent the Proposals are approved, these amounts will no
longer be paid to the Company. See the following table for a detailed
comparison of the compensation, reimbursements and distributions paid by the 63
Partnerships in the aggregate for 1997, 1996 and 1995 and the first three
months of 1998.
<TABLE>
<CAPTION>
63 PSHP 63 PSHP 63 PSHP
TOTALS TOTALS TOTALS
1995 1996 1997
----------------------------------------------------
<S> <C> <C> <C>
FEES AND REIMBURSEMENTS PAID TO
GENERAL PARTNERS
MANAGEMENT FEE $ 0 $ 0 $ 0
G&A OVERHEAD ALLOWANCE
REIMBURSED $ 4,534,301 $ 4,076,215 $ 3,728,043
INCENTIVE AMOUNT RECEIVED $ 255,783 $ 266,623 $ 204,448
INTERNAL ACQUISITION COSTS
REIMBURSED $ 645,108 $ 138,624 $ 4,200
DIRECT EXPENSES REIMBURSED $ 113,866 $ 165,089 $ 120,791
FORMATION COSTS REIMBURSED $ 0 $ 0 $ 0
DISTRIBUTIONS TO MANAGING GENERAL
PARTNER $ 2,064,569 $ 3,094,584 $ 3,111,476
</TABLE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
PARTNERSHIP COMPANY
- -----------------------------------------------------------------------------------------------------------------
<S> <C>
Limited Liability of Investors
------------------------------
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.
The limitation on personal liability of Shareholders of the Company is substantially the same as that of
Investors in the Partnerships.
</TABLE>
56
<PAGE> 67
The following compares certain of the investment attributes and legal
rights associated with the ownership of Units and Shares.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
UNITS SHARES
- -----------------------------------------------------------------------------------------------------------------
<S> <C>
NATURE OF INVESTMENT
--------------------
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.
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.
POTENTIAL DILUTION OF PAYMENT RIGHTS
------------------------------------
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."
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>
57
<PAGE> 68
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
UNITS SHARES
- -----------------------------------------------------------------------------------------------------------------
<S> <C>
LIQUIDITY
---------
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.
The Shares will be listed on the NYSE and the Pacific Exchange. Although a public market for the Common Stock
exists, the breadth of the market cannot yet be determined. While there has been a limited secondary market for the
Units, trading on that market has been sporadic and limited.
TAXATION OF TAXABLE INVESTORS IN SEIP AND SEOP PARTNERSHIPS
-----------------------------------------------------------
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>
58
<PAGE> 69
<TABLE>
<S> <C>
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.
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
UNITS SHARES
- -----------------------------------------------------------------------------------------------------------------
<S> <C>
TAXATION OF TAX-EXEMPT INVESTORS IN SEMPAP AND SEPP PARTNERSHIPS
----------------------------------------------------------------
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.
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.
</TABLE>
59
<PAGE> 70
FEDERAL INCOME TAX CONSEQUENCES OF ADOPTION OF THE PROPOSALS
GENERAL
The following summarizes certain 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. Investors herein are treated for federal income tax purposes as
limited partners and references to tax treatments of partners includes
Investors. Statements of legal conclusions 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 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.
Investors should recognize that an opinion of Special Tax Counsel represents
merely such counsel's best legal judgment and has no binding effect or official
status of any kind.
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
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 (Certain Investors in either a Swift Energy
Managed Pension Assets Partnership ("SEMPAP") or Swift Energy Pension
Partnership ("SEPP"))
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.
60
<PAGE> 71
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.
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. 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
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 (a) whose
Partnership Interests are debt-financed or (b) that have invested in SEIP or
SEOP Partnerships. 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").
61
<PAGE> 72
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.
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.
SEIP AND SEOP PARTNERSHIPS
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
62
<PAGE> 73
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 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 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.
63
<PAGE> 74
THE FOREGOING DISCUSSION IS INTENDED TO BE A SUMMARY OF CERTAIN INCOME
TAX CONSIDERATIONS OF THE SALE OF PROPERTIES AND LIQUIDATION OF THE
PARTNERSHIPS. EACH INVESTOR SHOULD CONSULT HIS 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.
64
<PAGE> 75
INVESTOR ELECTION TO PARTICIPATE IN
OFFERING OF 2,500,000 SHARES OF
SWIFT 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. 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 March 31, 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.
65
<PAGE> 76
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 the 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 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
66
<PAGE> 77
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.
67
<PAGE> 78
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."
68
<PAGE> 79
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 March 31, 1998, the Company had
approximately 526 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
----
Second Quarter (Through May 12) . . . . . . $ 20.75 $ 17.06
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 May 12, 1998, the
last reported sale price for the Common Stock on the New York Stock Exchange
was $18.88 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.
69
<PAGE> 80
CAPITALIZATION OF SWIFT ENERGY COMPANY
The following table sets forth as of March 31, 1998 the actual
capitalization of the Company and the capitalization of the Company as adjusted
to give effect to the Acquisitions assuming (i) the 100% Case is consummated for
(a) all cash or (b) cash and 2.5 million shares of Common Stock at an assumed
price of $18 per share and (ii) the 50% Case is consummated for (a) all cash or
(b) 2.3 million shares of Common Stock at an assumed price of $18 per share.
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 MARCH 31, 1998
----------------------------------------------------------------------------
AS ADJUSTED FOR THE AS ADJUSTED FOR THE
ACQUISITIONS 100% CASE ACQUISITIONS 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................ $ 1,915 $ 1,915 $ 1,915 $ 1,915 $ 1,915
-------- -------- -------- -------- --------
Long-Term Debt:
6.25% Convertible Subordinated Notes Due
2006................................... 115,000 115,000 115,000 115,000 115,000
Bank Borrowings.......................... 15,124 76,624 31,624 55,724 15,124
-------- -------- -------- -------- --------
Total Long-Term Debt............... 130,124 191,624 146,624 170,724 130,124
-------- -------- -------- -------- --------
Stockholders' Equity:
Preferred stock, $.01 par value,
5,000,000 shares authorized, none
outstanding............................ -- -- -- -- --
Common stock, $.01 par value, 35,000,000
shares authorized, 16,935,312 shares
issued and 16,515,038 shares
outstanding, respectively, 19,435,312
issued and 19,015,038 shares
outstanding as adjusted for the 100%
Case -- Equity/Cash, 19,190,868 issued
and 18,770,594 shares outstanding as
adjusted for the 50% Case -- All Equity
(a).................................... 169 169 194 169 192
Additional paid-in capital............... 148,380 148,380 193,356 148,380 188,958
Treasury stock held, at cost, 420,274
shares................................. (9,093) (9,093) (9,093) (9,093) (9,093)
Unearned ESOP compensation............... (100) (100) (100) (100) (100)
Retained earnings........................ 23,589 27,309 27,012 27,789 27,521
-------- -------- -------- -------- --------
162,945 166,665 211,369 167,145 207,478
-------- -------- -------- -------- --------
Total Liabilities and Stockholders'
Equity........................... $293,069 $358,289 $357,993 $337,869 $337,602
======== ======== ======== ======== ========
</TABLE>
- ---------------
(a) Excludes 1,822,987 shares issuable upon exercise of employee and director
stock options outstanding as of March 31, 1998.
70
<PAGE> 81
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 three months ended March 31, 1998, and
the unaudited pro forma consolidated balance sheets as of March 31, 1998
(collectively, the "Pro Forma Financial Statements") are based on the historical
consolidated financial statements of the Company and the historical combined
financial statements of all the Partnerships whose oil and gas assets are
proposed to be acquired under the 100% Case and the 50% Case scenarios, adjusted
to give effect to the acquisition alternatives 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 100% Case Pro Forma Financial Statements assume that all 63
Partnerships will approve their respective Proposal. 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 51 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 three months ended March 31, 1998 of all 63
Partnerships.
The Unaudited Pro Forma Consolidated Statements of Income for the year
ended December 31, 1997 and for the three months ended March 31, 1998 give
effect to the Acquisitions as if they had occurred as of January 1, 1997. The
Unaudited Pro Forma Consolidated Balance Sheets give effect to the Acquisitions
as if they had occurred as of March 31, 1998. The Pro Forma Financial Statements
assume (i) the 100% Case is consummated for (a) all cash or (b) cash and 2.5
million shares of Common Stock at an assumed price of $18 per share and (ii) the
50% Case is consummated for (a) all cash or (b) 2.3 million shares of Common
Stock at an assumed price of $18 per share. 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 and
the Combined Financial Statements of the Partnerships and related notes thereto
included elsewhere in this Joint Proxy Statement/Prospectus.
71
<PAGE> 82
UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
(100% CASE -- ALL CASH)
ASSETS
<TABLE>
<CAPTION>
AS OF MARCH 31, 1998
----------------------------------------------------
100% CASE
COMPANY PARTNERSHIPS PRO FORMA ALL CASH
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- ---------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C>
Current Assets:
Cash and cash equivalents............................ $ 1,915 $ 6,270 $ (6,270)(c) $ 1,915
Accounts receivable --
Oil and gas sales.................................. 9,468 7,198 (1,812)(a) 14,854
Associated limited partnerships.................... 5,027 -- (5,027)(h) --
Joint interest owners and other.................... 4,886 3,576 -- 8,462
Other current assets................................. 1,335 149 (149) 1,335
-------- -------- --------- --------
Total Current Assets.......................... 22,631 17,193 (13,258) 26,566
-------- -------- --------- --------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized.................. 356,269 325,897 (56,687)(a) 417,769
61,500(g)
(269,210)(j)
Unproved properties not being amortized............ 46,100 -- -- 46,100
-------- -------- --------- --------
402,369 325,897 (264,397) 463,869
Furniture, fixtures, and other equipment............. 6,333 -- -- 6,333
-------- -------- --------- --------
408,702 325,897 (264,397) 470,202
Less -- Accumulated depreciation, depletion, and
amortization....................................... (77,419) (242,767) 35,516(a) (77,419)
207,251(j)
-------- -------- --------- --------
331,283 83,130 (21,630) 392,783
-------- -------- --------- --------
Other Assets:
Receivables from associated limited partnerships,
net of current portion............................. 70 -- -- 70
Limited partnership formation and marketing costs.... 750 -- -- 750
Deferred charges..................................... 4,097 -- -- 4,097
-------- -------- --------- --------
4,917 -- -- 4,917
-------- -------- --------- --------
Total Assets.................................. $358,831 $100,323 $ (34,888) $424,266
======== ======== ========= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities............. $ 22,367 $ 2,065 $ (511)(a) $ 23,581
(340)(f)
Payable to associated limited partnerships........... 7,434 895 (2,900)(h) 5,429
Undistributed oil and gas revenues................... 6,530 -- -- 6,530
-------- -------- --------- --------
Total Current Liabilities..................... 36,331 2,960 (3,751) 35,540
-------- -------- --------- --------
6.25% Convertible Subordinated Notes................... 115,000 -- -- 115,000
Bank Borrowings........................................ 15,124 -- 61,500(e) 76,624
Deferred Revenues...................................... 2,592 1,247 (241)(a) 3,598
Deferred Income Taxes.................................. 26,839 -- -- 26,839
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding....................... -- -- -- --
Common stock, $.01 par value, 35,000,000 shares
authorized, 16,935,312 shares issued, and
16,515,038 shares outstanding, respectively........ 169 -- -- 169
Additional paid-in capital........................... 148,380 -- -- 148,380
Treasury stock held, at cost, 420,274 shares......... (9,093) -- -- (9,093)
Unearned ESOP compensation........................... (100) -- -- (100)
Retained earnings.................................... 23,589 -- 3,720 27,309
Partners' capital.................................... -- 96,116 (96,116)(j) --
-------- -------- --------- --------
162,945 96,116 (92,396) 166,665
-------- -------- --------- --------
Total Liabilities and Stockholders' Equity.... $358,831 $100,323 $ (34,888) $424,266
======== ======== ========= ========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
72
<PAGE> 83
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(100% CASE -- ALL CASH)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
-------------------------------------------------------
100% CASE
COMPANY PARTNERSHIPS PRO FORMA ALL CASH
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- ---------
(IN THOUSANDS, EXCEPT SHARE DATA AND RATIOS)
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales................................ $ 69,015 $42,228 $(6,748)(a) $ 104,495
Fees from limited partnerships................... 746 -- (204)(b) 542
Supervision fees................................. 5,210 -- -- 5,210
Interest income.................................. 2,395 330 (330)(c) 2,395
Other, net....................................... 2,556 266 (44)(a) 2,778
--------- ------- ------- ---------
79,922 42,824 (7,326) 115,420
--------- ------- ------- ---------
Costs and Expenses:
General and administrative, net of
reimbursement.................................. 6,129 5,206 (843)(a) 10,288
(204)(b)
Depreciation, depletion, and amortization........ 24,247 16,857 (2,150)(a) 33,801
(5,153)(d)
Oil and gas production........................... 11,384 13,774 (2,221)(a) 22,937
Interest expense, net............................ 5,033 21 4,745(e) 9,799
--------- ------- ------- ---------
46,793 35,858 (5,826) 76,825
--------- ------- ------- ---------
Income before Income Taxes......................... 33,129 6,966 (1,500) 38,595
Provision for Income Taxes......................... 10,819 -- 2,303(f) 13,122
--------- ------- ------- ---------
Net Income......................................... $ 22,310 $ 6,966 $(3,803) $ 25,473
========= ======= ======= =========
Per share amounts --
Basic:........................................... $ 1.35 $ 1.54
========= =========
Diluted:......................................... $ 1.26 $ 1.41
========= =========
Weighted Average Shares Outstanding................ 16,493 16,493
========= =========
Ratio of earnings to fixed charges................. 5.2x 4.0x
========= =========
SUPPLEMENTAL CASH FLOW INFORMATION:
Net cash provided by operating activities........ $ 55,256 $ 67,769
Net cash used in investing activities............ (132,788) (197,436)
Net cash provided by financing activities........ 1,784 63,285
--------- ---------
Net decrease in cash and cash equivalents........ $ (75,748) $ (66,382)
========= =========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
73
<PAGE> 84
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(100% CASE -- ALL CASH)
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31, 1998
----------------------------------------------------
100% CASE
COMPANY PARTNERSHIPS PRO FORMA ALL CASH
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- ---------
(IN THOUSANDS, EXCEPT SHARE DATA AND RATIOS)
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales............................. $ 15,802 $ 5,659 $ (922)(a) $ 20,539
Fees from limited partnerships................ 80 -- (32)(b) 48
Supervision fees.............................. 1,286 -- -- 1,286
Interest income............................... 19 95 (95)(c) 19
Other, net.................................... 575 41 (7)(a) 609
-------- ------- ------- --------
17,762 5,795 (1,056) 22,501
-------- ------- ------- --------
Costs and Expenses:
General and administrative, net of
reimbursement.............................. 1,643 1,174 (200)(a) 2,585
(32)(b)
Depreciation, depletion, and amortization..... 6,735 3,723 (395)(a) 8,376
(1,687)(d)
Oil and gas production........................ 3,163 2,496 (418)(a) 5,241
Interest expense, net......................... 1,385 2 1,189(e) 2,576
-------- ------- ------- --------
12,926 7,395 (1,543) 18,778
-------- ------- ------- --------
Income before Income Taxes...................... 4,836 (1,600) 487 3,723
Provision for Income Taxes...................... 1,606 -- (340)(f) 1,266
-------- ------- ------- --------
Net Income...................................... $ 3,230 $(1,600) $ 827 $ 2,457
======== ======= ======= ========
Per share amounts --
Basic:........................................ $ 0.20 $ 0.15
======== ========
Diluted:...................................... $ 0.20 $ 0.15
======== ========
Weighted Average Shares Outstanding............. 16,500 16,500
======== ========
Ratio of earnings to fixed charges.............. 2.9x 1.9x
======== ========
SUPPLEMENTAL CASH FLOW INFORMATION:
Net cash provided by operating activities..... $ 13,020 $ 14,335
Net cash used in investing activities......... (20,647) (82,848)
Net cash provided by financing activities..... 7,495 68,995
-------- --------
Net increase (decrease) in cash and cash
equivalents................................ $ (132) $ 482
======== ========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
74
<PAGE> 85
UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
(100% CASE -- EQUITY/CASH)
ASSETS
<TABLE>
<CAPTION>
AS OF MARCH 31, 1998
------------------------------------------------------
100% CASE
COMPANY PARTNERSHIPS PRO FORMA EQUITY/CASH
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- -----------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C>
Current Assets:
Cash and cash equivalents............................ $ 1,915 $ 6,270 $ (6,270)(c) $ 1,915
Accounts receivable --
Oil and gas sales.................................. 9,468 7,198 (1,812)(a) 14,854
Associated limited partnerships.................... 5,027 -- (5,027)(h) --
Joint interest owners and other.................... 4,886 3,576 -- 8,462
Other current assets................................. 1,335 149 (149) 1,335
-------- --------- --------- --------
Total Current Assets.......................... 22,631 17,193 (13,258) 26,566
-------- --------- --------- --------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized.................. 356,269 325,897 (56,687)(a) 417,769
61,500(g)
(269,210)(j)
Unproved properties not being amortized............ 46,100 -- -- 46,100
-------- --------- --------- --------
402,369 325,897 (264,397) 463,869
Furniture, fixtures, and other equipment............. 6,333 -- -- 6,333
-------- --------- --------- --------
408,702 325,897 (264,397) 470,202
Less -- Accumulated depreciation, depletion, and
amortization....................................... (77,419) (242,767) 35,516(a) (77,419)
207,251(j)
-------- --------- --------- --------
331,283 83,130 (21,630) 392,783
-------- --------- --------- --------
Other Assets:
Receivables from associated limited partnerships, net
of current portion................................. 70 -- -- 70
Limited partnership formation and marketing costs.... 750 -- -- 750
Deferred charges..................................... 4,097 -- -- 4,097
-------- --------- --------- --------
4,917 -- -- 4,917
-------- --------- --------- --------
Total Assets.................................. $358,831 $ 100,323 $ (34,888) $424,266
======== ========= ========= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities............. $ 22,367 $ 2,065 $ (511)(a) $ 23,877
(44)(f)
Payable to associated limited partnerships........... 7,434 895 (2,900)(h) 5,429
Undistributed oil and gas revenues................... 6,530 -- -- 6,530
-------- --------- --------- --------
Total Current Liabilities..................... 36,331 2,960 (3,455) 35,836
-------- --------- --------- --------
6.25% Convertible Subordinated Notes................... 115,000 -- -- 115,000
Bank Borrowings........................................ 15,124 -- 16,500(e) 31,624
Deferred Revenues...................................... 2,592 1,247 (241)(a) 3,598
Deferred Income Taxes.................................. 26,839 -- -- 26,839
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding....................... -- -- -- --
Common stock, $.01 par value, 35,000,000 shares
authorized, 16,935,312 shares issued and 16,515,038
shares outstanding, 19,435,312 issued and
19,015,038 shares outstanding as adjusted for the
100% Case -- Equity/Cash, respectively............. 169 -- 25(i) 194
Additional paid-in capital........................... 148,380 -- 44,976 193,356
Treasury stock held, at cost, 420,274 shares......... (9,093) -- -- (9,093)
Unearned ESOP compensation........................... (100) -- -- (100)
Retained earnings.................................... 23,589 -- 3,423(a) 27,012
Partners' capital.................................... -- 96,116 (96,116)(j) --
-------- --------- --------- --------
162,945 96,116 (47,692) 211,369
-------- --------- --------- --------
Total Liabilities and Stockholders' Equity.... $358,831 $ 100,323 $ (34,888) $424,266
======== ========= ========= ========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
75
<PAGE> 86
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(100% CASE -- EQUITY/CASH)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
------------------------------------------------------
100% CASE
COMPANY PARTNERSHIPS PRO FORMA EQUITY/CASH
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- -----------
(IN THOUSANDS, EXCEPT SHARE DATA AND RATIOS)
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales................................... $ 69,015 $42,228 $(6,748)(a) $ 104,495
Fees from limited partnerships...................... 746 -- (204)(b) 542
Supervision fees.................................... 5,210 -- -- 5,210
Interest income..................................... 2,395 330 (330)(c) 2,395
Other, net.......................................... 2,556 266 (44)(a) 2,778
--------- ------- ------- ---------
79,922 42,824 (7,326) 115,420
--------- ------- ------- ---------
Costs and Expenses:
General and administrative, net of reimbursement.... 6,129 5,206 (843)(a) 10,288
(204)(b)
Depreciation, depletion, and amortization........... 24,247 16,857 (2,150)(a) 33,801
(5,153)(d)
Oil and gas production.............................. 11,384 13,774 (2,221)(a) 22,937
Interest expense, net............................... 5,033 21 1,258(e) 6,312
--------- ------- ------- ---------
46,793 35,858 (9,313) 73,338
--------- ------- ------- ---------
Income before Income Taxes............................ 33,129 6,966 1,987 42,082
Provision for Income Taxes............................ 10,819 -- 3,489(f) 14,308
--------- ------- ------- ---------
Net Income............................................ $ 22,310 $ 6,966 $(1,502) $ 27,774
========= ======= ======= =========
Per share amounts --
Basic:.............................................. $ 1.35 $ 1.46
========= =========
Diluted:............................................ $ 1.26 $ 1.36
========= =========
Weighted Average Shares Outstanding................... 16,493 18,993
========= =========
Ratio of earnings to fixed charges.................... 5.2x 5.5x
========= =========
SUPPLEMENTAL CASH FLOW INFORMATION:
Net cash provided by operating activities........... $ 55,256 $ 70,070
Net cash used in investing activities............... (132,788) (197,436)
Net cash provided by financing activities........... 1,784 63,285
--------- ---------
Net decrease in cash and cash equivalents........... $ (75,748) $ (64,081)
========= =========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
76
<PAGE> 87
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(100% CASE -- EQUITY/CASH)
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31, 1998
------------------------------------------------------
100% CASE
COMPANY PARTNERSHIPS PRO FORMA EQUITY/CASH
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- -----------
(IN THOUSANDS, EXCEPT SHARE DATA AND RATIOS)
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales........................... $ 15,802 $ 5,659 $ (922)(a) $ 20,539
Fees from limited partnerships.............. 80 -- (32)(b) 48
Supervision fees............................ 1,286 -- -- 1,286
Interest income............................. 19 95 (95)(c) 19
Other, net.................................. 575 41 (7)(a) 609
-------- ------- ------- --------
17,762 5,795 (1,056) 22,501
-------- ------- ------- --------
Costs and Expenses:
General and administrative, net of
reimbursement............................ 1,643 1,174 (200)(a) 2,585
(32)(b)
Depreciation, depletion, and amortization... 6,735 3,723 (395)(a) 8,376
(1,687)(d)
Oil and gas production...................... 3,163 2,496 (418)(a) 5,241
Interest expense, net....................... 1,385 2 317(e) 1,704
-------- ------- ------- --------
12,926 7,395 (2,415) 17,906
-------- ------- ------- --------
Income before Income Taxes.................... 4,836 (1,600) 1,359 4,595
Provision for Income Taxes.................... 1,606 -- (44)(f) 1,562
-------- ------- ------- --------
Net Income.................................... $ 3,230 $(1,600) $ 1,403 $ 3,033
======== ======= ======= ========
Per share amounts --
Basic:...................................... $ 0.20 $ 0.16
======== ========
Diluted:.................................... $ 0.20 $ 0.16
======== ========
Weighted Average Shares Outstanding........... 16,500 19,000
======== ========
Ratio of earnings to fixed charges............ 2.9x 2.6x
======== ========
SUPPLEMENTAL CASH FLOW INFORMATION:
Net cash provided by operating activities... $ 13,020 $ 14,911
Net cash used in investing activities....... (20,647) (82,848)
Net cash provided by financing activities... 7,495 68,995
-------- --------
Net increase (decrease) in cash and cash
equivalents.............................. $ (132) $ 1,058
======== ========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
77
<PAGE> 88
UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
(50% CASE -- ALL CASH)
ASSETS
<TABLE>
<CAPTION>
AS OF MARCH 31, 1998
-----------------------------------------------------
50% CASE
COMPANY PARTNERSHIPS PRO FORMA ALL CASH
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- ---------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C>
Current Assets:
Cash and cash equivalents................................. $ 1,915 $ 4,174 $ (4,174)(c) $ 1,915
Accounts receivable --
Oil and gas sales....................................... 9,468 4,659 (1,211)(a) 12,916
Associated limited partnerships......................... 5,027 -- (2,561)(h) 2,466
Joint interest owners and other......................... 4,886 2,411 -- 7,297
Other current assets...................................... 1,335 82 (82) 1,335
-------- --------- --------- --------
Total Current Assets................................ 22,631 11,326 (8,028) 25,929
-------- --------- --------- --------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized....................... 356,269 247,401 (43,823)(a) 396,869
40,600(g)
(203,578)(j)
Unproved properties not being amortized................. 46,100 -- -- 46,100
-------- --------- --------- --------
402,369 247,401 (206,801) 442,969
Furniture, fixtures, and other equipment.................. 6,333 -- -- 6,333
-------- --------- --------- --------
408,702 247,401 (206,801) 449,302
Less-Accumulated depreciation, depletion, and
amortization............................................ (77,419) (189,019) 28,475(a) (77,419)
160,544(j)
-------- --------- --------- --------
331,283 58,382 (17,782) 371,883
-------- --------- --------- --------
Other Assets:
Receivables from associated limited partnerships, net of
current portion......................................... 70 -- -- 70
Limited partnership formation and marketing costs......... 750 -- -- 750
Deferred charges.......................................... 4,097 -- -- 4,097
-------- --------- --------- --------
4,917 -- -- 4,917
-------- --------- --------- --------
Total Assets........................................ $358,831 $ 69,708 $ (25,810) $402,729
======== ========= ========= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities.................. $ 22,367 $ 1,379 $ (326)(a) $ 23,123
(297)(f)
Payable to associated limited partnerships................ 7,434 434 (2,845)(h) 5,023
Undistributed oil and gas revenues........................ 6,530 -- -- 6,530
-------- --------- --------- --------
Total Current Liabilities........................... 36,331 1,813 (3,468) 34,676
-------- --------- --------- --------
6.25% Convertible Subordinated Notes........................ 115,000 -- -- 115,000
Bank Borrowings............................................. 15,124 -- 40,600(e) 55,724
Deferred Revenues........................................... 2,592 951 (198)(a) 3,345
Deferred Income Taxes....................................... 26,839 -- -- 26,839
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding............................ -- -- -- --
Common stock, $.01 par value, 35,000,000 shares
authorized, 16,935,312 shares issued, and 16,515,038
shares outstanding, respectively........................ 169 -- -- 169
Additional paid-in capital.................................. 148,380 -- -- 148,380
Treasury stock held, at cost, 420,274 shares................ (9,093) -- -- (9,093)
Unearned ESOP compensation.................................. (100) -- -- (100)
Retained earnings........................................... 23,589 -- 4,200 27,789
Partners' capital........................................... -- 66,944 (66,944)(j) --
-------- --------- --------- --------
162,945 66,944 (62,744) 167,145
-------- --------- --------- --------
Total Liabilities and Stockholders' Equity.......... $358,831 $ 69,708 $ (25,810) $402,729
======== ========= ========= ========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
78
<PAGE> 89
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(50% CASE -- ALL CASH)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
----------------------------------------------------
50% CASE
COMPANY PARTNERSHIPS PRO FORMA ALL CASH
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- ---------
(IN THOUSANDS, EXCEPT SHARE DATA AND RATIOS)
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales............................ $ 69,015 $28,588 $(4,613)(a) $ 92,990
Fees from limited partnerships............... 746 -- (123)(b) 623
Supervision fees............................. 5,210 -- -- 5,210
Interest income.............................. 2,395 216 (216)(c) 2,395
Other, net................................... 2,556 184 (31)(a) 2,709
--------- ------- ------- ---------
79,922 28,988 (4,983) 103,927
--------- ------- ------- ---------
Costs and Expenses:
General and administrative, net of
reimbursement............................. 6,129 3,724 (611)(a) 9,119
(123)(b)
Depreciation, depletion, and amortization.... 24,247 11,857 (1,396)(a) 30,569
(4,139)(d)
Oil and gas production....................... 11,384 9,324 (1,524)(a) 19,184
Interest expense, net........................ 5,033 10 3,136(e) 8,179
--------- ------- ------- ---------
46,793 24,915 (4,657) 67,051
--------- ------- ------- ---------
Income before Income Taxes..................... 33,129 4,073 (326) 36,876
Provision for Income Taxes..................... 10,819 -- 1,719(f) 12,538
--------- ------- ------- ---------
Net Income..................................... $ 22,310 $ 4,073 $(2,045) $ 24,338
========= ======= ======= =========
Per share amounts --
Basic:....................................... $ 1.35 $ 1.48
========= =========
Diluted:..................................... $ 1.26 $ 1.35
========= =========
Weighted Average Shares Outstanding............ 16,493 16,493
========= =========
Ratio of earnings to fixed charges............. 5.2x 4.3x
========= =========
SUPPLEMENTAL CASH FLOW INFORMATION:
Net cash provided by operating activities.... $ 55,256 $ 63,402
Net cash used in investing activities........ (132,788) (176,536)
Net cash provided by financing activities.... 1,784 42,385
--------- ---------
Net decrease in cash and cash equivalents.... $ (75,748) $ (70,749)
========= =========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
79
<PAGE> 90
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(50% CASE -- ALL CASH)
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31, 1998
-------------------------------------------------------
50% CASE
COMPANY PARTNERSHIPS PRO FORMA ALL CASH
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- ---------
(IN THOUSANDS, EXCEPT SHARE DATA AND RATIOS)
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales................................. $ 15,802 $ 3,526 $ (568)(a) $ 18,760
Fees from limited partnerships.................... 80 -- (14)(b) 66
Supervision fees.................................. 1,286 -- -- 1,286
Interest income................................... 19 63 (63)(c) 19
Other, net........................................ 575 28 (5)(a) 598
-------- ------- ------- --------
17,762 3,617 (650) 20,729
-------- ------- ------- --------
Costs and Expenses:
General and administrative, net of
reimbursement................................... 1,643 871 (150)(a) 2,350
(14)(b)
Depreciation, depletion, and amortization......... 6,735 2,561 (255)(a) 7,783
(1,258)(d)
Oil and gas production............................ 3,163 1,698 (285)(a) 4,576
Interest expense, net............................. 1,385 -- 786(e) 2,171
-------- ------- ------- --------
12,926 5,130 (1,176) 16,880
-------- ------- ------- --------
Income before Income Taxes.......................... 4,836 (1,513) 526 3,849
Provision for Income Taxes.......................... 1,606 -- (297)(f) 1,309
-------- ------- ------- --------
Net Income.......................................... $ 3,230 $(1,513) $ 823 $ 2,540
======== ======= ======= ========
Per share amounts --
Basic:............................................ $ 0.20 $ 0.15
======== ========
Diluted:.......................................... $ 0.20 $ 0.15
======== ========
Weighted Average Shares Outstanding................. 16,500 16,500
======== ========
Ratio of earnings to fixed charges.................. 2.9x 2.1x
======== ========
SUPPLEMENTAL CASH FLOW INFORMATION:
Net cash provided by operating activities......... $ 13,020 $ 13,825
Net cash used in investing activities............. (20,647) (61,831)
Net cash provided by financing activities......... 7,495 48,095
-------- --------
Net increase (decrease) in cash and cash
equivalents..................................... $ (132) $ 89
======== ========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
80
<PAGE> 91
UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
(50% CASE -- ALL EQUITY)
ASSETS
<TABLE>
<CAPTION>
AS OF MARCH 31, 1998
----------------------------------------------------
50% CASE
COMPANY PARTNERSHIPS PRO FORMA ALL EQUITY
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- ----------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C>
Current Assets:
Cash and cash equivalents................................. $ 1,915 $ 4,174 $ (4,174)(c) $ 1,915
Accounts receivable --
Oil and gas sales....................................... 9,468 4,659 (1,211)(a) 12,916
Associated limited partnerships......................... 5,027 -- (2,561)(h) 2,466
Joint interest owners and other......................... 4,886 2,411 -- 7,297
Other current assets...................................... 1,335 82 (82) 1,335
-------- --------- ---------- --------
Total Current Assets................................ 22,631 11,326 (8,028) 25,929
-------- --------- ---------- --------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized......................... 356,269 247,401 (43,823)(a) 396,869
40,600(g)
(203,578)(j)
Unproved properties not being amortized..................... 46,100 -- -- 46,100
-------- --------- ---------- --------
402,369 247,401 (206,801) 442,969
Furniture, fixtures, and other equipment.................... 6,333 -- -- 6,333
-------- --------- ---------- --------
408,702 247,401 (206,801) 449,302
Less -- Accumulated depreciation, depletion, and
amortization.............................................. (77,419) (189,019) 28,475(a) (77,419)
160,544(j)
-------- --------- ---------- --------
331,283 58,382 (17,782) 371,883
-------- --------- ---------- --------
Other Assets:
Receivables from associated limited partnerships,
net of current portion.................................... 70 -- -- 70
Limited partnership formation and marketing costs......... 750 -- -- 750
Deferred charges.......................................... 4,097 -- -- 4,097
-------- --------- ---------- --------
4,917 -- -- 4,917
-------- --------- ---------- --------
Total Assets........................................ $358,831 $ 69,708 $ (25,810) $402,729
======== ========= ========== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities.................. $ 22,367 $ 1,379 $ (326)(a) $ 23,390
(30)(f)
Payable to associated limited partnerships................ 7,434 434 (2,845)(h) 5,023
Undistributed oil and gas revenues........................ 6,530 -- -- 6,530
-------- --------- ---------- --------
Total Current Liabilities........................... 36,331 1,813 (3,201) 34,943
-------- --------- ---------- --------
6.25% Convertible Subordinated Notes........................ 115,000 -- -- 115,000
Bank Borrowings............................................. 15,124 -- -- 15,124
Deferred Revenues........................................... 2,592 951 (198)(a) 3,345
Deferred Income Taxes....................................... 26,839 -- -- 26,839
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding............................ -- -- -- --
Common stock, $.01 par value, 35,000,000 shares
authorized, 16,935,312 shares issued and 16,515,038
shares outstanding, 19,190,868 issued and 18,770,594
shares outstanding as adjusted for the All Equity
Case.................................................... 169 -- 23(i) 192
Additional paid-in capital.................................. 148,380 -- 40,578(i) 188,958
Treasury stock held, at cost, 420,274 shares................ (9,093) -- -- (9,093)
Unearned ESOP compensation.................................. (100) -- -- (100)
Retained earnings........................................... 23,589 -- 3,932 27,521
Partners' capital........................................... -- 66,944 (66,944)(j) --
-------- --------- ---------- --------
162,945 66,944 (22,411) 207,478
-------- --------- ---------- --------
Total Liabilities and Stockholders' Equity.......... $358,831 $ 69,708 $ (25,810) $402,729
======== ========= ========== ========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
81
<PAGE> 92
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(50% CASE -- ALL EQUITY)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
-----------------------------------------------------
50% CASE
COMPANY PARTNERSHIPS PRO FORMA ALL EQUITY
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- ----------
(IN THOUSANDS, EXCEPT SHARE DATA AND RATIOS)
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales.................................... $ 69,015 $28,588 $(4,613)(a) $ 92,990
Fees from limited partnerships....................... 746 -- (123)(b) 623
Supervision fees..................................... 5,210 -- -- 5,210
Interest income...................................... 2,395 216 (216)(c) 2,395
Other, net........................................... 2,556 184 (31)(a) 2,709
--------- ------- ------- ---------
79,922... 28,988 (4,983) 103,927
--------- ------- ------- ---------
Costs and Expenses:
General and administrative, net of reimbursement..... 6,129 3,724 (611)(a) 9,119
(123)(b)
Depreciation, depletion, and amortization............ 24,247 11,857 (1,396)(a) 30,569
(4,139)(d)
Oil and gas production............................... 11,384 9,324 (1,524)(a) 19,184
Interest expense, net................................ 5,033 10 (10)(a) 5,033
--------- ------- ------- ---------
46,793 24,915 (7,803) 63,905
--------- ------- ------- ---------
Income before Income Taxes............................. 33,129 4,073 2,820 40,022
Provision for Income Taxes............................. 10,819 -- 2,788(f) 13,607
--------- ------- ------- ---------
Net Income............................................. $ 22,310 $ 4,073 $ 32 $ 26,415
========= ======= ======= =========
Per share amounts --
Basic:............................................... $ 1.35 $ 1.41
========= =========
Diluted:............................................. $ 1.26 $ 1.31
========= =========
Weighted Average Shares Outstanding.................... 16,493 18,748
========= =========
Ratio of earnings to fixed charges..................... 5.2x 6.0x
========= =========
SUPPLEMENTAL CASH FLOW INFORMATION:
Net cash provided by operating activities............ $ 55,256 $ 65,479
Net cash used in investing activities................ (132,788) (176,536)
Net cash provided by financing activities............ 1,784 42,385
--------- ---------
Net decrease in cash and cash equivalents............ $ (75,748) $ (68,672)
========= =========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
82
<PAGE> 93
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(50% CASE -- ALL EQUITY)
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31, 1998
-----------------------------------------------------
50% CASE
COMPANY PARTNERSHIPS PRO FORMA ALL EQUITY
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- ----------
(IN THOUSANDS, EXCEPT SHARE DATA AND RATIOS)
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales............................. $ 15,802 $ 3,526 $ (568)(a) $ 18,760
Fees from limited partnerships................ 80 -- (14)(b) 66
Supervision fees.............................. 1,286 -- -- 1,286
Interest income............................... 19 63 (63)(c) 19
Other, net.................................... 575 28 (5)(a) 598
-------- ------- ------- --------
17,762 3,617 (650) 20,729
-------- ------- ------- --------
Costs and Expenses:
General and administrative, net of
reimbursement.............................. 1,643 871 (150)(a) 2,350
(14)(b)
Depreciation, depletion, and amortization..... 6,735 2,561 (255)(a) 7,783
(1,258)(d)
Oil and gas production........................ 3,163 1,698 (285)(a) 4,576
Interest expense, net......................... 1,385 -- -- 1,385
-------- ------- ------- --------
12,926 5,130 (1,962) 16,094
-------- ------- ------- --------
Income before Income Taxes...................... 4,836 (1,513) 1,312 4,635
Provision for Income Taxes...................... 1,606 -- (30)(f) 1,576
-------- ------- ------- --------
Net Income...................................... $ 3,230 $(1,513) $ 1,342 $ 3,059
======== ======= ======= ========
Per share amounts --
Basic:........................................ $ 0.20 $ 0.16
======== ========
Diluted:...................................... $ 0.20 $ 0.16
======== ========
Weighted Average Shares Outstanding 16,500 18,756
======== ========
Ratio of earnings to fixed charges.............. 2.9x 2.8x
======== ========
SUPPLEMENTAL CASH FLOW INFORMATION:
Net cash provided by operating activities..... $ 13,020 $ 14,344
Net cash used in investing activities......... (20,647) (61,831)
Net cash provided by financing activities..... 7,495 48,095
-------- --------
Net increase (decrease) in cash and cash
equivalents................................ $ (132) $ 608
======== ========
</TABLE>
See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements
83
<PAGE> 94
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 Investor
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 Acquisitions.
(b) Represents a management fee provided in the Partnership agreements, which
had the Acquisitions 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 Acquisitions, all cash in the Partnerships will be
distributed to the Investors.
(d) Represents adjustment to depreciation, depletion, and amortization based on
the Company's and Partnerships' combined historical production, reserves,
and the Company's new cost basis for oil and gas property.
(e) Represents an increase in interest expense for the period presented to
reflect $61,500,000 (100% Case -- All Cash), $16,500,000 (100%
Case -- Equity/Cash) and $40,600,000 (50% Case -- All Cash) of additional
borrowings under the Company's credit facilities (at an assumed annual
interest rate of 7.75% which approximates the Company's effective 1997 and
first quarter 1998 rate under these facilities) that would have been
required to fund the Acquisitions. The effects of fluctuations of 0.125%
and 0.25% in interest rates in respect to the credit facilities on pro
forma interest would have been $76,875 and $153,750, respectively on the
100% Case -- All Cash for 1997 or $20,625 and $41,250, respectively on the
100% Case -- Equity/Cash for 1997 or $50,750 and $101,500, respectively on
the 50% Case -- All Cash for 1997. The effects of fluctuations of 0.125%
and 0.25% in interest rates in respect to the credit facilities on pro
forma interest would have been $19,219 and $38,438, respectively on the
100% Case -- All Cash for the three months ended March 31, 1998 or $5,156
and $10,313, respectively on the 100% Case -- Equity/Cash for the three
months ended March 31, 1998 or $12,688 and $25,275, respectively on the 50%
Case -- All Cash for the three months ended March 31, 1998.
(f) Represents additional income tax expense based on pro forma adjustments
assuming a statutory tax rate of 34.0%.
(g) Represents the recording of the estimated purchase price to proved oil and
gas property costs, as follows (in thousands):
<TABLE>
<CAPTION>
100% CASE 50% CASE
--------- --------
<S> <C> <C>
Estimated gross purchase price................... $70,587 $47,100
Estimated purchase price adjustments*............ (9,237) (6,650)
Estimated acquisition costs...................... 150 150
------- -------
Estimated net purchase price..................... $61,500 $40,600
======= =======
</TABLE>
--------------------------
* Estimated purchase price adjustments represent estimated interim
cash flows to the purchased interests from the period from the
effective date (January 1, 1998) to June 30, 1998.
(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 50% Case -- All Equity, this
reflects the issuance of 2.5 million and 2.3 million shares, respectively
of Common Stock ($0.01 par value) at an assumed price of $18 per share.
(j) Represents the elimination of the Partnerships' historical oil and gas
property balances (excluding the Company's ownership interests) and
Partners' Capital.
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<PAGE> 95
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31, 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............. $ 15,802 $ 18,370 $ 69,015 $ 52,771 $ 22,528 $ 19,802 $ 15,536
Fees and Earned
Interests(b)................ 80 99 746 937 590 702 4,072
Supervision fees.............. 1,286 1,248 5,210 4,470 3,839 3,751 3,719
Interest income............... 19 999 2,395 433 212 48 201
Other, net.................... 575 530 2,556 2,157 1,762 1,073 604
-------- -------- -------- -------- -------- -------- --------
Total Revenues......... 17,762 21,246 79,922 60,768 28,931 25,376 24,132
-------- -------- -------- -------- -------- -------- --------
Costs and Expenses:
General and administrative,
net of reimbursement........ 1,643 1,575 6,129 6,385 5,256 5,198 5,065
Depreciation, depletion, and
amortization................ 6,735 5,397 24,247 16,526 8,839 7,905 7,301
Oil and gas production........ 3,163 2,763 11,384 8,377 6,826 5,640 4,540
Interest expense, net......... 1,385 1,350 5,033 694 1,115 1,795 598
-------- -------- -------- -------- -------- -------- --------
Total Costs and
Expenses............. 12,926 11,085 46,793 31,982 22,036 20,538 17,504
-------- -------- -------- -------- -------- -------- --------
Income before Income Taxes...... 4,836 10,161 33,129 28,786 6,895 4,838 6,628
Provision for Income Taxes...... 1,606 3,392 10,819 9,760 1,982 1,112 1,732
-------- -------- -------- -------- -------- -------- --------
Income Before Cumulative Effect
of Change in Accounting
Principle..................... 3,230 6,769 22,310 19,026 4,913 3,726 4,896
Cumulative Effect of Change in
Accounting Principle.......... -- -- -- -- -- (16,773) --
-------- -------- -------- -------- -------- -------- --------
Net Income (Loss)............... $ 3,230 $ 6,769 $ 22,310 $ 19,026 $ 4,913 $(13,047) $ 4,896
======== ======== ======== ======== ======== ======== ========
Per share amounts (c)--
Basic......................... $ 0.20 $ 0.41 $ 1.35 $ 1.27 $ 0.49 $ (1.79)(d) $ 0.68(d)
======== ======== ======== ======== ======== ======== ========
Diluted....................... $ 0.20 $ 0.37 $ 1.26 $ 1.25 $ 0.49 $ (1.79)(d) $ 0.64(d)
======== ======== ======== ======== ======== ======== ========
Weighted Average Shares
Outstanding(c)................ 16,500 16,703 16,493 15,001 10,035 7,309 7,247
======== ======== ======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
Net cash provided by operating
activities.................... $ 13,020 $ 19,539 $ 55,256 $ 37,103 $ 14,376 $ 10,395 $ 7,238
Capital expenditures............ 27,980 28,409 131,967 91,487 40,033 34,531 24,229
BALANCE SHEET DATA:
Working capital................. $(13,700) $ 52,509 $ 1,464 $ 68,704 $ 3,247 $(13,137) $ 9,742
Total assets.................... 358,831 318,334 339,115 310,375 175,253 135,673 160,893
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
Bank borrowings............... 15,124 -- 7,915 -- -- -- --
Stockholders' equity............ 162,945 146,911 159,401 142,762 93,346 42,127 54,466
</TABLE>
- ---------------
(a) For a discussion of the significant items affecting comparability of 1997,
1996, 1995 and for the three months ended March 31, 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 three months ended March 31, 1998 and 1997 "Fees and Earned Interests"
does 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) 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> 96
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 Notes thereto.
GENERAL
Swift Energy Company's principal corporate objectives are the
accumulation of crude oil and natural gas reserves for current and future
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 reemphasize the
addition of reserves through increased exploration and development drilling
activity. This emphasis on exploration and development drilling has led to
additions of increasing quantities of reserves in each of the years 1995, 1996,
and 1997. 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.
The statements contained in this Prospectus that are not historical
facts are forward-looking statements as that term is defined in Section 21E of
the Securities and Exchange Act of 1934, as amended, and therefore involve a
number of risks and uncertainties. Such forward-looking statements may be or may
concern, among other things, 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" and elsewhere in this Prospectus, 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. Also, because the volatility in oil and gas prices and other
factors, interim results are not necessarily indicative of those for a full
year.
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. 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 exploration and
development 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 or 40% of total proved reserves at year end 1997,
86
<PAGE> 97
101.5 Bcfe or 39% of total proved reserves at year end 1996, and 74.7 Bcfe or
42% of total proved reserves at year end 1995. This reflects the emphasis on
exploration and development 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 financial statements) and in the
Estimated Present Value of Proved Reserves (see page 7--"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 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 a year earlier). While the
Company's total proved reserves quantities 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 almost
totally due to the high product prices at year end 1996 detailed above. If the
PV-10 Value as of year end 1997 had been calculated using the same prices in
effect a year earlier, there would have been an increase in PV-10 Value from
year end 1996 to year end 1997 comparable to the 40% increase in the Company's
total proved reserves quantities during that same period.
Under the Securities and Exchange 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
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. The $2.78 per
Mcf and the $15.76 per barrel were prices in effect as of the year end 1997 and
may not be indicative of future sales prices received.
FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR THE
THREE MONTHS ENDED MARCH 31, 1998 AND 1997
LIQUIDITY AND CAPITAL RESOURCES
During the first three months of 1998, the Company relied upon net
proceeds from its $115.0 million public offering of 6.25% Convertible
Subordinated Notes due 2006 and its internally generated cash flows, along with
$15.1 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 and/or equity
financing.
Net Cash Provided by Operating Activities
For the three month period ended March 31, 1998, net cash provided by
operating activities decreased 33% to $13.0 million, as compared to $19.5
million during the first three months of 1997. The 1998 decrease of $6.5 million
was primarily due to a decrease in cash flows from oil and gas sales, which
decreased $2.5 million (14%), exclusive of the noncash amortization of deferred
revenues associated with the Company's volumetric production payment, along with
the $1.0 million decrease in interest income, a result of having expended all
the net proceeds of the $115.0 million note offering. The decrease in oil and
gas sales was due to substantially lower product prices, somewhat offset by
increased production volumes, as discussed below.
Credit Facilities
At March 31, 1998, the Company had outstanding borrowings of $15.1
million under its credit facilities. At March 31, 1997, the Company had no
outstanding balances under these borrowing
87
<PAGE> 98
arrangements, since the balance of those borrowings was repaid in November 1996
with proceeds from the Company's public sale of $115.0 million of 6.25%
Convertible Subordinated Notes.
Working Capital
The Company's working capital has decreased over the last three months,
from $1.5 million at December 31, 1997, to a deficit of $13.7 million at March
31, 1998. This decrease is primarily the result of the Company's capital
expenditures as described below.
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 accelerated
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 are
made in the open market. Under this program, through March 31, 1998, the Company
used $9.09 million of working capital to acquire 420,274 shares at an average
cost of $21.64 per share.
Capital Expenditures
Capital expenditures for property, plant, and equipment during the
first three months of 1998 were $28.0 million. These capital expenditures
included: (a) $16.6 million of drilling costs, both exploratory and
developmental (primarily in the AWP Olmos Field and Austin Chalk trend), (b)
$6.8 million of prospect costs (principally prospect leasehold, seismic and
geological costs of unproved prospects for the Company's account), (c) $0.6
million invested in foreign business opportunities in New Zealand (approximately
$302,000), in Venezuela (approximately $133,000), and in Russia (approximately
$209,000), (d) $0.3 million spent on field facilities and production equipment,
(e) $3.5 million on producing property acquisitions, with the remainder spent
primarily for computer equipment and furniture and fixtures. In the remaining
nine months of 1998, the Company expects capital expenditures to be
approximately $147 million, including investments in all areas in which
investments were made during the first three months of the year as described
above, with a particular focus on exploratory and development drilling. The
successful completion of the acquisition of producing properties from the
Partnerships, as described above, could impact the anticipated timing and nature
of the remaining 1998 capital expenditures discussed above. The Company
currently plans to participate in the drilling of 73 gross wells this year,
compared to 182 wells in 1997. Through March 31, 1998, the Company had
participated in drilling 30 wells (5 exploratory and 25 development wells with 3
exploratory successes and 23 development successes). The steady growth in the
Company's unproved property account which is not being amortized is indicative
of the shift to a focus on drilling activity, as the Company acquires prospect
acreage, and due to foreign activities.
The Company believes that 1998's anticipated internally generated cash
flows, together with its existing credit facilities, should be sufficient to
finance the costs associated with its currently budgeted 1998 capital
expenditures and other uses of working capital.
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<PAGE> 99
RESULTS OF OPERATIONS - THREE MONTHS ENDED MARCH 31, 1998 AND 1997
Net income of $3.2 million and earnings per share of $0.20 for the
first three months of 1998 were 53% and 51% lower, respectively, than net income
of $6.8 million, and earnings per share of $0.41 in the same period for 1997.
This decrease in net income primarily reflected the effect of a 14% decrease in
oil and gas sales revenues as a result of a 37% and 26% decrease in oil and gas
prices, respectively, which was partially offset by increased oil and gas
volumes of 17% and 19%, respectively.
Revenues
The Company's revenues decreased 16% during the first three months of
1998 from the comparative period in 1997, due primarily to the decrease in oil
and gas sales.
Oil and Gas Sales. Oil and gas sales decreased 14% to $15.8 million in
the first three months of 1998, compared to $18.4 million for the comparative
period in 1997. The 19% increase in natural gas production and the 17% increase
in oil production were primarily the result of production from recent drilling
activity, most notably from the Company's two primary development areas, the AWP
Olmos Field and the Austin Chalk trend. The Company's net sales volume
(including the volumetric production payment) in the first three months of 1998
increased by 19% or 1.1 Bcfe (billion cubic feet equivalent) over volumes in the
comparable 1997 period. The increases in volume were more than offset by a 37%
decrease in oil prices received between the two periods, and a 26% decrease in
gas prices between the two periods, as highlighted in the table below.
The elements of the Company's $2.6 million decrease in oil and gas
sales during the first three months of 1998 included: (1) volume increases that
added $2.9 million of sales from a 1.0 Bcf increase in gas sales volumes and
$0.6 million of increased sales from the 28,900 barrel increase in oil sales
volumes and (2) price variances that subtracted $4.6 million from sales due to
the decrease in average gas prices received, and $1.5 million decrease in sales
due to the decrease in average oil prices received. The Company's three-month
1998 oil and gas sales from the AWP Olmos Field were $8.3 million ($11.1 million
in 1997) from 4.0 Bcfe of net sales volumes (3.7 Bcfe in 1996) for an increase
of 0.3 Bcfe, while the Austin Chalk trend generated three-month 1998 oil and gas
sales of $4.2 million ($3.0 million in 1997) from 1.8 Bcfe of net sales volume
(1.0 Bcfe in 1997) for an increase of 0.8 Bcfe.
Revenues from oil and gas sales comprised 89% and 86%, respectively, of
total revenues for the first three months of 1998 and 1997. The majority (84%
and 82%, respectively) of these revenues 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.
The following table provides additional information regarding the
Company's oil and gas sales.
<TABLE>
<CAPTION>
Net Sales Volume Average
---------------- --------
Oil (Bbl) Gas (Mcf) Oil (Bbl)
--------- --------- ---------
<S> <C> <C> <C>
1997
3 Mos. Ended 03-31-97 166,240 4,903,206 $20.13
1998
3 Mos. Ended 03-31-98 195,114 5,858,509 $12.61
</TABLE>
89
<PAGE> 100
Supervision Fees. These fees increased 3%, having grown from $1.2
million in the first three months of 1997 to $1.3 million in the first three
months of 1998. This increase is primarily due to the annual escalation in well
overhead rates, and the increase in drilling activity by the Company, which in
turn increases the drilling well overhead portion of such fees paid to the
Company as operator of these wells.
Costs and Expenses
General and administrative expenses for the first three months of 1998
increased by approximately $68,000 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 15% from $0.27 per Mcfe produced for the first three months of 1997
to $0.23 per Mcfe produced for the comparable period in 1998. The majority of
the companies in the oil and gas industry treat supervision fees as a reduction
of their general and administrative expenses. If the Company were to follow this
practice, these expenses net of supervision fees would have decreased from $0.06
per Mcfe produced for the first three months of 1997 to $0.05 per Mcfe produced
for the same period in 1998.
Depreciation, depletion, and amortization ("DD&A") increased 25%
(approximately $1.3 million) for the first three months of 1998, 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 has increased from $0.89 per Mcfe produced in the
1997 period to $0.92 per Mcfe produced in the 1998 period, reflecting variations
in the per unit cost of reserve additions.
Production costs per Mcfe decreased from $0.47 per Mcfe produced in the
1997 period to $0.45 per Mcfe produced in the 1998 period. Primarily due to the
19% increase in production volumes, oil and gas production costs increased 14%
(approximately $400,000) in the first three months of 1998 when compared to the
first three months of 1997. 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 is 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. 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 on certified wells drilled prior to September 1,
1996. This tax exemption has had a positive impact on the Company's production
costs during 1997 and 1998.
Interest expense in the first three months of 1998 on the 6.25% Notes,
including amortization of debt issuance costs, totaled $1,884,000 ($1,874,000 in
the 1997 period), while interest expense on the credit facilities, including
commitment fees, totaled $304,000 ($10,000 in the 1997 period for commitment
fees) for a total interest expense of $2,188,000 (of which $803,000 was
capitalized). In the first three months of 1997, these costs totaled $1,884,000
(of which $535,000 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
facilities.
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
90
<PAGE> 101
also does not anticipate any material disruption in its operations as a result
of any year 2000 compliance issues.
FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR THE YEARS
ENDED DECEMBER 31, 1997, 1996 AND 1995
LIQUIDITY AND CAPITAL RESOURCES
During the first ten months of 1996, the Company relied upon internally
generated cash flows and bank borrowings to fund its capital expenditures, and
thereafter upon net proceeds from its $115.0 million public offering of 6.25%
Convertible Subordinated Notes due 2006 and its internally generated cash flows,
along with $7.9 million of bank borrowings in the closing weeks of 1997, all as
described below. Cash and working capital in 1998 are expected to be provided
through internally generated cash flows, bank borrowings, and debt and/or equity
financing.
Net Cash Provided by Operating Activities
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 increase $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 being affected by product price fluctuations, as
described below.
Sale of Convertible Subordinated Notes
In November 1996, the Company issued $115.0 million of 6.25%
Convertible Subordinated Notes due November 15, 2006, in a public offering.
Proceeds of the offering were used for repayment in full of all the Company's
bank borrowings ($33.1 million on November 25, 1996) and, together with
internally generated cash flows, to fund capital expenditures through 1997 and
working capital needs. The principal terms of these Notes are more fully
described in Note 4 to the Company's financial statements.
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 exploration and development activities. As described in Note 4 to the
Company's financial statements included herein, in August 1996 the $28.75
million of 6.5% Convertible Debentures sold in 1993 were converted by their
holders into 2.34 million shares of the Company's Common Stock following the
Company's July 1996 announcement of their redemption. As a result of this
conversion, the Company's stockholders' equity increased approximately $27.65
million.
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<PAGE> 102
Credit Facilities
In the first ten months of 1996 and in the closing weeks of 1997, the
Company's credit facilities have been used to fund a portion of the Company's
exploration and development activities. Currently, these credit facilities
consist of a $100.0 million unsecured revolving line of credit with a $40.0
million borrowing base and a $7.0 million secured revolving line of credit with
a $5.5 million borrowing base. The principal terms and restrictions of these
credit facilities are described in Note 4 to the Company's financial statements
included herein.
At December 31, 1997, the Company had outstanding borrowings of
$7,915,000 under the credit facilities. At December 31, 1996, and until
mid-December 1997, the Company had no outstanding balances under these borrowing
arrangements, since the balance of those borrowings was repaid in November 1996
with proceeds from the Company's public sale of $115.0 million of 6.25%
Convertible Subordinated Notes.
Partnership Programs
Since late 1993, the Company has offered private partnerships formed to
drill for oil and gas. 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 December 31, 1997, 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 $297,000, a
decrease of $213,000 when compared with the balance at December 31, 1996.
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.
Working Capital
The Company's working capital has decreased from $68.7 million at
December 31, 1996, to $1.5 million at December 31, 1997. This decrease is
primarily the result of the Company's capital expenditures as described below.
Since year end 1996, the Company's receivable account from limited
partnerships and its receivable account from joint interest owners increased
$1.8 million and $4.3 million, respectively, due to the increase in drilling
activity between the periods.
Due to the nature of the Company's business highlighted above, the
individual components of 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 accelerated
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.
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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 are
made in the open market. Under this program, through December 31, 1997, the
Company used $8.52 million of working capital to acquire 387,800 shares at an
average cost of $21.97 per share.
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
$43,063,335, with the Common Stock and additional paid-in capital accounts
increased by the same amount.
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 developmental 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 financial statements, and (f)
$0.9 million (1%) spent on fixed assets. In 1997, the Company participate in
drilling 182 wells (15 exploratory and 167 development wells with 7 exploratory
successes and 159 development 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.
Capital expenditures for 1998 are estimated to be approximately $154.8
million, including investments in all areas in which 1997 capital was spent.
Approximately, $123.9 million of the 1998 budget is allocated to exploration and
development drilling, with approximately 73% of this amount to be spent in the
Company's two primary development areas in Texas. The Company's plan anticipates
drilling 113 development and 21 exploratory wells in 1998.
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 accelerated drilling program), together with the existing credit
facilities, will be sufficient to finance the costs associated with its
currently budgeted 1998 capital expenditures.
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RESULTS OF OPERATIONS - YEARS 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 sales revenues.
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 revenues 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 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 accelerated drilling program, most
notably from the Company's two primary development 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.
Average prices received from oil and gas production can have a
dramatic impact on the Company's oil and gas sales revenues. This is evident
not only in the yearly comparisons as described above but also when comparing
fourth quarter 1997 revenues to those for the fourth quarter of 1996. While
oil and gas production volumes increased 1.0 Bcfe (17%) during the fourth
quarter of 1997 when compared to the fourth quarter of 1996, oil and gas sales
increased only $1.1 million (6%) due to average oil prices received being 25%
lower and average gas prices received being 6% lower than in the fourth quarter
of 1996.
Supervision Fees. These fees continue to increase, having grown from
$3.8 million in 1995 to $4.5 million in 1996 to $5.2 million in 1997, primarily
due to the annual escalation in well overhead rates and the increase in
drilling activity by the Company, which in turn increases the drilling well
overhead portion of such fees paid to the Company as operator of these wells.
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
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Mcfe produced have decreased in each of the past three years from $0.47 per
Mcfe produced in 1995 to $0.33 per Mcfe produced in 1996 to $0.24 per Mcfe
produced in 1997. The majority of the companies in the oil and gas industry
treat supervision fees as a reduction of their general and administrative
expenses. If the Company were to follow this practice, these expenses net of
supervision fees would have decreased to $0.13 per Mcfe produced in 1995, $0.10
per Mcfe produced in 1996, and $0.04 per Mcfe produced in 1997.
Depreciation, depletion, and amortization (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 $0.79 in 1995,
$0.85 in 1996, and $0.95 in 1997, 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 $0.45 in 1997, $0.43 in 1996, and $0.61 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 $0.61 to the 1996 rate of $0.43. 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 on certified wells drilled prior to September 1,
1996. This tax exemption has had a positive 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 $0.02 increase in production costs per Mcfe produced in 1997 when compared
to 1996.
Interest expense in 1997 on the Notes, including amortization of debt
issuance costs, totaled $7.5 million, compared to $0.7 million on the Notes and
$1.0 million on 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 Notes
($115.0 million) compared to the Debentures ($28.75 million), offset to some
degree by larger outstanding balances under the Company's 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 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 paying only six months of
interest on the Debentures as they were converted 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 slight 4% increase in gas prices received, offset somewhat by
an 11% decrease in oil prices received. The lower percentage increase
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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.
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BUSINESS AND PROPERTIES OF SWIFT ENERGY COMPANY
GENERAL
Swift Energy Company (the "Company"), a Texas corporation organized in
October 1979, is engaged in the exploration, development, 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, with 93% of its proved
reserves base concentrated in Texas. At the same date, the Company had
estimated proved reserves of 361.5 Bcfe, approximately 87% of which were
natural gas, and operated 650 wells representing 91% of its proved reserves
base.
The Company's primary focus is exploration and development drilling in
its 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 more 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. The Company has substantially accelerated
its drilling activities during the last several years, drilling 42, 116, and
135 net wells in 1995, 1996, and 1997, respectively, primarily in these areas.
During 1996, the Company doubled its acreage position in the AWP Olmos Field
and quadrupled it in the Austin Chalk trend. In 1997, the Company increased
slightly its acreage position in the AWP Olmos field and increased its acreage
position in the Austin Chalk trend by approximately 50%. The Company has
budgeted capital expenditures of $154.8 million for 1998, of which
approximately 73% is targeted for these two fields. The Company is also
actively pursing exploratory and development drilling opportunities in other
basins in Texas, Arkansas, Louisiana, and Wyoming. As a complement to these
domestic activities, the Company is participating in several high potential
international projects with limited capital exposure to the Company in New
Zealand, Russia, and Venezuela.
The Company has increased its proved reserves from 59.0 Bcfe at the year
end 1992 to 361.5 Bcfe at year end 1997, primarily from additions through the
drill bit, which has resulted in the replacement of 554% of production during
the same five-year period. In 1997, the Company increased its proved reserves
by 40%, resulting in the replacement of 522% of 1997 production. The Company's
five-year average reserves 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 $0.88 and $0.69 per Mcfe in 1992 to $0.24 and $0.45 per Mcfe,
respectively, for 1997. The combination of increased production and decreased
operating costs per Mcfe has resulted in average annual growth in net cash
provided by operating activities of 54% per year from year end 1992 to year end
1997. For 1997, due to these same production and operating cost factors, net
cash provided by operating activities increased to $55.3 million or 49% over
the same period in 1996.
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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 that substantially 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. 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.
Also, by utilizing a system of BJ Services, Inc., the Company 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 Bcfe, with current
production of approximately 2,000 Mcfe per day.
In 1997, the Company drilled 142 (137 successful) development wells 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 continuing its 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. 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 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 in 1997 16 successful development wells out of 17 drilled and
two successful exploratory wells out of five drilled. 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
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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,
beginning 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 that industry partner and the Company 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, a joint development arrangement covering approximately 8,000
acres in Washington County, Texas, in which the Company owns a 25% working
interest, was reached 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 N. Fayetteville Prospect area for which it will serve as
operator. The initial test well was spudded in December 1997.
EXPLORATION AND DEVELOPMENT DRILLING ACTIVITIES
In 1991, the Company began to develop an inventory of exploration and
development 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 47% for exploratory wells (7 out of 15 drilled) and 95%
for development wells (159 out of 167 drilled). These successful drilling
results have led to acquisition 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. The Company focuses its exploration activities on specific U.S.
regions where its technical staff has considerable experience and which are in
close proximity to known producing horizons 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, economic
parameters, and activity in the trend.
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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, which include 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 exploration and development 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 the
Rimu prospect, Swift 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.
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 one successful exploratory well and
two successful development wells drilled in 1996, in 1998, seven exploratory
wells and 18 development 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
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 18
development wells expected to be drilled in the Gulf Coast Basin in 1998, 10
will be drilled on this acreage. Two of those 10 have already been
successfully drilled in the first quarter of 1998, with the third 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.
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In the North Creole prospect in southern Louisiana, the Company has
worked 2-D and 3-D seismic data in conjunction with the Vertical Seismic
Profile it shot in early 1997 to identify development and exploratory locations
of deep high-potential targets to be drilled in the first quarter of 1998.
Additional 3-D seismic grids are being quality checked for eventual licensing
in the area to help in the interpretation of the complex geologic features.
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 test slated for the first quarter of 1998 and has designed a 2-D
seismic cross-swath to be acquired commencing in March 1998 to identify deeper
high-yield structures in the Wilcox trend.
Wyoming Powder River Basin. The Company intends to drill three
exploratory wells and eight development wells 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 exploratory wells and one out of three development 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. This shift is due to the Company's commitment to find larger reserve
accumulations at a lower risk by drilling in areas with multiple producing
zones and larger field sizes. 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 exploratory and one development, with
the development well being successful, following five successful wells drilled
in 1996, four of which were exploratory. The Company plans to drill four
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 slated for testing in the first half of 1998. 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.
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\ 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>
1995 Exploratory 8 4 4 3.5 1.5 2.0
Development 68 65 3 38.7 38.0 0.7
1996 Exploratory 11 7 4 5.9 3.7 2.2
Development 142 134 8 110.5 106.7 3.8
1997 Exploratory 15 7 8 7.2 2.7 4.5
Development 167 159 8 127.5 123.8 3.9
</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 they 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/or 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 it 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 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.
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<PAGE> 113
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 75,000
Mcf 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>
(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 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 October 2000, when such agreement expires. Since entering
into this agreement, these properties have produced in excess of the required
monthly delivery requirements.
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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 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/or 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 cost to purchase put options are amortized over the option
period.
During 1997, the Company entered into oil and natural gas price hedging
contracts covering a portion of the Company's and its affiliated partnerships'
oil and natural gas production. For January, 1,400,000 MMBtu of the natural
gas production was covered, providing for a minimum price of $1.90 per MMBtu.
February was covered for 2,000,000 MMBtu of natural gas, and March and April
were covered for 1,500,000 MMBtu of natural gas, each at a minimum price of
$2.00. For the months of May, June, July, and August, 1,500,000 MMBtu was
covered, providing for a minimum price of $1.80. September, October and
November had two contracts each month with each separate contract covering
1,500,000 MMBtu of natural gas, providing for minimum prices of $1.80 and $1.90
in September, $1.85 and $1.90 in October, and $1.90 and $2.00 in November.
For the months of January, February, and March, 140,000 Bbls of oil
production were covered, with 70,000 Bbls each month providing for a minimum
price of $17.00 and the other 70,000 Bbls each month providing for a minimum
price of $20.00 per Bbl. April, May, and June were covered for 140,000 Bbls of
oil production at a minimum price of $20.00 in April and May, while June
provided for a minimum price of $19.00. July was covered for 60,000 Bbls of
production at a minimum price of $18.00 and for 60,000 Bbls at a minimum price
of $19.00. August was covered for 120,000 Bbls of production, providing for a
minimum price of $19.00. For the months of September through December, 60,000
Bbls of oil production were covered, providing for a minimum price of $18.00.
Costs related to 1997 hedging activities totaled approximately $1,052,000 with
benefits of approximately $439,000 being received, resulting in a net cash
outlay of approximately $613,000 or $0.014 per Mcfe.
The Company had three open contracts at December 31, 1997, covering
1,500,000 MMBtu of the natural gas production for February 1998 at a minimum
price of $2.00, 500,000 MMBtu of gas in March 1998 at a minimum price of $1.90,
and 60,000 Bbls of oil production for February providing for a minimum price of
$18.00 per Bbl. The costs related to the open contracts totaled $95,308 and
had a market value of $121,600 as of December 31, 1997.
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 which 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. 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
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approximately $3.5 million, $1.5 million, and $8.4 million of properties
acquired in 1995, 1996, and 1997, 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.
The Company generally seeks acquisition of properties for its own account that
are in close proximity to its current reserves and provide the potential to add
reserves and production through additional development efforts.
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
and Bligh will obtain a 5% working interest in the Company's permit. 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.
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 providing the
Company with a minimum of 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.
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
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<PAGE> 116
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.
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 and Associates, Inc., Houston, Texas, 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 Securities and Exchange 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 of natural gas and $15.76 per
barrel of oil, compared to $4.47 and $2.41 per Mcf of natural gas and $23.75
and $18.07 per barrel of oil as of December 31, 1996 and 1995, respectively.
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.
<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>
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<PAGE> 117
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 Securities and Exchange 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
financial statements. A substantial portion (40%) of the reserves are proved
undeveloped reserves. This reflects the increased emphasis on exploration and
development activities. This was consistent with the proportions in 1996 of
39% proved undeveloped and 61% proved developed and reflects the continued
emphasis on exploration and development activities.
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 almost totally due to high
product prices at year end 1996, 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.
If the PV-10 Value as of year end 1997 had been calculated using the same
prices in effect a year earlier, there would have been an increase in the PV-10
Value from year end 1996 to year end 1997 comparable to the 40% increase in the
Company's total proved reserves quantities during that same period.
Proved reserves are estimates of hydrocarbons to be recovered in the
future. Reservoir engineering is a subjective process of estimating the sizes
of underground accumulations of oil and gas that cannot be measured in an exact
way. The accuracy of any reserves estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Reserves reports of other engineers might differ from the reports contained
herein. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimate. Future prices received for
the sale of oil and gas may be different from those used in preparing these
reports. The amounts and timing of future operating and development costs may
also differ from those used. Accordingly, reserves estimates are often
different from the quantities of oil and gas that are ultimately recovered.
There can be no assurance that these estimates are accurate predictions of the
present value of future net cash flows from oil and gas reserves.
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<PAGE> 118
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 interest will achieve payout status in
the future. Four of the limited partnerships had achieved payout status at
December 31, 1997.
No other reports on the Company's reserves have been filed with any
federal agency.
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. 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, there can be no assurance that losses will
not result from title defects or from defects in the assignment of leasehold
rights. In many instances, title opinions may not be obtained if in the
Company's judgment it would be uneconomical or impractical to do so.
The following table sets forth the developed and undeveloped domestic
leasehold acreage held by the Company at December 31, 1997:
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<PAGE> 119
<TABLE>
<CAPTION>
Developed Undeveloped
----------------------------- -----------------------------
Gross (1) Net (2) Gross (1) Net (2)
------------ ------------ ------------ ------------
<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>
PARTNERSHIPS
For many years, the Company relied on limited partnerships as its
principal financing vehicle to fund its activities. The Company has formed 107
limited partnerships which have raised a total of approximately $502.0 million
at December 31, 1997. However, as the Company has increasingly shifted its
emphasis to exploration and development activities and its reserves base has
grown, the Company has significantly reduced its reliance on limited
partnership financing.
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 to be
completed by June 30, 1998. Concurrent with this Offering, Proposals to
liquidate are being submitted by the Company to 63 Partnerships. If all such
Proposals are approved, only four operating and pension partnerships will
remain.
From 1991 to 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. Since 1993, the Company also has offered
private partnerships formed to engage in the drilling for oil and gas reserves.
The company serves as the managing general partner of these entities. As of
December 1, 1997, eleven partnerships had been formed (one formed in each of
1993 and 1994, and three in each of 1995, 1996, and 1997) with aggregate
investor contributions of approximately $58.6 million.
The private drilling partnerships have been offered on a no-load basis
under which the Company pays all selling and offering expenses of the offering.
Amounts paid by the Company are treated as a capital
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<PAGE> 120
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.
RISK MANAGEMENT
The Company's operations are subject to all of the risks normally
incident to the exploration for and the production of oil and gas, including
blowouts, cratering, pipe failure, casing collapse, oil spills, and fires, each
of which could result in severe damage to or destruction of oil and gas wells,
production facilities, or other property, or individual injuries. The oil and
gas exploration business is also subject to environmental hazards, such as oil
spills, gas leaks, and ruptures and discharges of toxic substances or gases
that could expose the Company to substantial liability due to pollution and
other environmental damage. Additionally, as managing general partner of
limited partnerships, the Company is solely responsible for the day-to-day
conduct of the limited partnerships' affairs and accordingly has liability for
expenses and liabilities of the limited partnerships. The Company maintains
comprehensive insurance coverage, including general liability insurance in an
amount not less than $25.0 million, as well as general partner liability
insurance. The Company believes that its insurance is adequate and customary
for companies of a similar size engaged in comparable operations, but losses
could occur for uninsurable or uninsured risks or in amounts in excess of
existing insurance coverage.
COMPETITION
The oil and gas industry is highly competitive in all its phases. The
Company encounters strong competition from many other oil and gas producers,
including many that possess substantial financial resources, in acquiring
economically desirable producing properties and exploratory drilling prospects,
and in obtaining equipment and labor to operate and maintain its properties.
Decreases in gas and especially oil prices since year-end 1997 may have an
effect on the Company's cash flow, capital expenditures, or drilling schedule,
although in light of the extreme volatility of prices, it is impossible to
predict the length of time that prices may remain at such levels or may move to
higher or lower levels.
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REGULATIONS
ENVIRONMENTAL REGULATIONS
The federal government and various state and local governments have
adopted laws and regulations regarding the protection of human health and the
environment. These laws and regulations may require the acquisition of a
permit by operators before drilling commences, prohibit drilling activities on
certain lands lying within wilderness areas, wetlands, or where pollution might
cause serious harm, and impose substantial liabilities for pollution resulting
from drilling operations, particularly with respect to operations in onshore
and offshore waters or on submerged lands. These laws and regulations may
increase the costs of drilling and operating wells. Because these laws and
regulations change frequently, the costs to the Company of compliance with
existing and future environmental regulations cannot be predicted with
certainty.
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 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.
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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,
exploration and development 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 SEMCO 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. For the 17 years prior to 1979, he was employed by affiliates of
American Natural Resources Company. He previously served as President from
1979 to November 1997, at which time Terry E. Swift was appointed President.
Mr. Swift is a registered professional engineer and holds a degree in Petroleum
Engineering, a Juris Doctor degree and a Master's degree in Business
Administration. He is the brother of Virgil N. Swift and the father of Terry
E. Swift.
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 1981 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.
Terry E. Swift, 42, was appointed President of the Company in 1997. He
served as Executive Vice President and Chief Operating Officer 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.
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, 53, 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 D'Amico, 49, 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, 60, 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, 66, 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, 73, 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 Montgomery Financial Services
Corporation, a management consulting and financial services firm. Mr.
Montgomery also
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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). Mr. Montgomery previously served as Chairman of
the Board of each of Private Financial Services Corporation, a management
consulting and financial services firm (1986 to 1989), and Aquanautics
Corporation, a public company involved in the extraction of oxygen from water
and air (1986 to 1991).
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 United States 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 March 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
March 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)
Harold J. Withrow . . . . . . Director 39,134 (3)
Terry E. Swift . . . . . . . President, Chief Operating Officer 130,975 (3)
</TABLE>
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<TABLE>
<CAPTION>
Shares of Common Stock
Beneficially Owned at
March 1, 1998(1)
----------------------------------
Percent of
Class
Name of Person or Group Position Number Outstanding
----------------------- -------- ------ -----------
<S> <C> <C> <C>
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 March 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 March 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 Securities and Exchange Commission,
FMR Corp., as a parent holding company in accordance with Section 240 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
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<PAGE> 127
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 Securities and Exchange 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 6.25% Convertible
Subordinated Notes due 2006. 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 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 1997
occurring at year end as follows: A. Earl Swift - $78,000; John R. Alden -
$62,806; and Bruce H. Vincent - $94,749. Individual executive officers do not
pay any interest to the Company on any such loan balances. It is anticipated
that through the application of production proceeds, these balances will be
reduced below $50,000 by late spring of 1998.
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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
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
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<PAGE> 129
("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.
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.
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<PAGE> 130
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 March 31,
1998. Holders of Common Stock are entitled to one vote for each share held.
Shareholder 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 March 31, 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 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
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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.
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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 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 herein in
reliance upon the authority of said firm as experts in giving said reports: (i)
Swift Energy Company and subsidiaries included in the Company's Annual Report
on Form 10-K for the year ended December 31, 1997, included (incorporated by
reference) herein; (ii) the combined financial statements of the Partnerships
included herein; (iii) Swift Energy Managed Pension Assets Partnership 1988-A,
Ltd.'s Annual Report on Form 10-K for the year ended December 31, 1997; (iv)
Swift Energy Income Partners 1989-B, Ltd.'s Annual Report on Form 10-K for the
year ended December 31, 1997; and (v) Swift Energy Pension Partners 1993-B,
Ltd.'s Annual Report on Form 10-K for the year ended December 31, 1997.
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.
122
<PAGE> 133
GLOSSARY OF TERMS
The following abbreviations and terms have the indicated meanings when
used in this 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 6 Mcf of natural gas.
BTU means British Thermal Unit, which is a heating equivalent measure for
natural gas.
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.
DISCOVERY COST means with respect to proved reserves, a three-year average
(unless otherwise indicated) calculated by dividing total incurred exploration
and development costs (exclusive of future development costs) by net reserves
added during the period through extensions, discoveries, and other additions.
DRY WELL means an exploratory or development well that is not a producing well.
EBITDA means earnings before interest, taxes and depreciation, depletion and
amortization.
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.
123
<PAGE> 134
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.
MMBTU 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 a net acre is deemed to exist when 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.
NET WELL means a net well is deemed to exist when the sum of fractional
ownership working interests in gross wells equals one. The number of net wells
is the sum of fractional working interests owned in gross wells expressed as
whole numbers and fractions thereof.
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.
124
<PAGE> 135
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.
PROVED UNDEVELOPED OIL AND GAS RESERVES means 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.
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.
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.
125
<PAGE> 136
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.
126
<PAGE> 137
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
127
<PAGE> 138
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
Report of Independent Public Accountants.................... F-22
Combined Balance Sheets..................................... F-23
Combined Statements of Income............................... F-24
Combined Statements of Partners' Capital.................... F-25
Combined Statements of Cash Flows........................... F-26
Notes to Combined Financial Statements...................... F-27
</TABLE>
F-1
<PAGE> 139
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 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 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 audit provides 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> 140
SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
MARCH 31, ---------------------------
1998 1997 1996
------------ ------------ ------------
(UNAUDITED)
<S> <C> <C> <C>
Current Assets:
Cash and cash equivalents................................. $ 1,915,585 $ 2,047,332 $ 77,794,974
Accounts receivable
Oil and gas sales....................................... 9,468,013 11,143,033 13,637,390
Associated limited partnerships and joint ventures...... 5,027,044 8,498,702 6,396,149
Joint interest owners................................... 4,885,824 7,357,660 3,079,619
Other current assets...................................... 1,334,870 935,059 711,346
------------ ------------ ------------
Total Current Assets............................... 22,631,336 29,981,786 101,619,478
------------ ------------ ------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized....................... 356,268,527 326,836,431 216,310,033
Unproved properties not being amortized................. 46,100,007 41,839,809 27,620,462
------------ ------------ ------------
402,368,534 368,676,240 243,930,495
Furniture, fixtures, and other equipment.................. 6,333,396 6,242,927 5,729,228
------------ ------------ ------------
408,701,930 374,919,167 249,659,723
Less -- Accumulated depreciation, depletion, and
amortization............................................ (77,419,329) (70,700,240) (46,685,736)
------------ ------------ ------------
331,282,601 304,218,927 202,973,987
------------ ------------ ------------
Other Assets:
Receivables from associated limited partnerships, net of
current portion......................................... 70,392 433,444 759,711
Limited partnership formation and marketing costs......... 750,102 297,219 510,607
Deferred charges.......................................... 4,096,960 4,184,014 4,511,481
------------ ------------ ------------
4,917,454 4,914,677 5,781,799
------------ ------------ ------------
$358,831,391 $339,115,390 $310,375,264
============ ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities.................. $ 22,367,220 $ 16,518,240 $ 20,416,589
Payable to associated limited partnerships................ 7,433,959 3,245,445 1,444,648
Undistributed oil and gas revenues........................ 6,529,989 8,753,979 11,054,379
------------ ------------ ------------
Total Current Liabilities.......................... 36,331,168 28,517,664 32,915,616
------------ ------------ ------------
6.25% Convertible Subordinated Notes........................ 115,000,000 115,000,000 115,000,000
Bank Borrowings............................................. 15,124,000 7,915,000 --
Deferred Revenues........................................... 2,591,760 2,927,656 4,404,081
Deferred Income Taxes....................................... 26,839,133 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, 16,935,512, 16,846,956, and 15,176,417
shares issued, and 16,515,038, 16,459,156, and
15,176,417 shares outstanding, respectively............. 169,353 168,470 151,764
Additional paid-in capital................................ 148,380,851 147,542,977 102,018,861
Treasury stock held, at cost, 420,274 and 387,800 shares,
respectively............................................ (9,093,292) (8,519,665) --
Unearned ESOP compensation................................ (100,390) (150,055) (521,354)
Retained earnings......................................... 23,588,808 20,359,193 41,112,339
------------ ------------ ------------
162,945,330 159,400,920 142,761,610
------------ ------------ ------------
$358,831,391 $339,115,390 $310,375,264
============ ============ ============
</TABLE>
See accompanying notes to Consolidated Financial Statements
F-3
<PAGE> 141
SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31, YEAR ENDED DECEMBER 31,
----------------------------- ---------------------------------------
1998 1997 1997 1996 1995
------------- ------------- ----------- ----------- -----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales........... $15,801,911 $18,369,651 $69,015,189 $52,770,672 $22,527,892
Fees from limited
partnerships and joint
ventures................. 79,931 98,730 745,856 937,238 590,441
Supervision fees............ 1,286,072 1,247,967 5,210,022 4,470,206 3,838,815
Interest income............. 18,499 998,825 2,395,406 433,352 212,329
Other, net.................. 574,888 530,296 2,555,729 2,156,764 1,761,568
----------- ----------- ----------- ----------- -----------
17,761,301 21,245,469 79,922,202 60,768,232 28,931,045
----------- ----------- ----------- ----------- -----------
Costs and Expenses:
General and administrative,
net of reimbursement..... 1,643,515 1,575,154 6,128,615 6,385,067 5,256,184
Depreciation, depletion, and
amortization............. 6,734,722 5,396,947 24,247,142 16,526,379 8,838,657
Oil and gas production...... 3,162,796 2,762,692 11,383,887 8,377,044 6,826,306
Interest expense, net....... 1,384,766 1,349,631 5,032,952 693,959 1,115,361
----------- ----------- ----------- ----------- -----------
12,925,799 11,084,424 46,792,596 31,982,449 22,036,508
----------- ----------- ----------- ----------- -----------
Income Before Income Taxes.... 4,835,502 10,161,045 33,129,606 28,785,783 6,894,537
Provision for Income Taxes.... 1,605,887 3,391,782 10,819,417 9,760,333 1,982,025
----------- ----------- ----------- ----------- -----------
Net Income.................... $ 3,229,615 $ 6,769,263 $22,310,189 $19,025,450 $ 4,912,512
=========== =========== =========== =========== ===========
Per Share Amounts
Basic....................... $ 0.20 $ 0.41 $ 1.35 $ 1.27 $ 0.49
=========== =========== =========== =========== ===========
Diluted..................... $ 0.20 $ 0.37 $ 1.26 $ 1.25 $ 0.49
=========== =========== =========== =========== ===========
Weighted Average Shares
Outstanding................. 16,500,385 16,702,636 16,492,856 15,000,901 10,035,143
=========== =========== =========== =========== ===========
</TABLE>
See accompanying notes to Consolidated Financial Statements
F-4
<PAGE> 142
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 (68,324
shares)(2)............................... 683 491,897 -- -- -- 492,580
Allocation of ESOP shares(2)............... -- (21,081) -- 49,665 -- 28,584
Purchase of 32,474 shares as treasury
stock(2)................................. -- -- (573,627) -- -- (573,627)
Net income(2).............................. -- -- -- -- 3,229,615 3,229,615
-------- ------------ ----------- --------- ------------ ------------
Balance, March 31, 1998(2)................... $169,353 $148,380,851 $(9,093,292) $(100,390) $ 23,588,808 $162,945,330
======== ============ =========== ========= ============ ============
</TABLE>
- ---------------
(1) $.01 par value.
(2) Unaudited
See accompanying notes to Consolidated Financial Statements
F-5
<PAGE> 143
SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31, YEAR ENDED DECEMBER 31,
--------------------------- -------------------------------------------
1998 1997 1997 1996 1995
------------ ------------ ------------- ------------ ------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash Flows from Operating Activities:
Net income............................... $ 3,229,615 $ 6,769,263 $ 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......................... 6,734,722 5,396,947 24,247,142 16,526,379 8,838,657
Deferred income taxes.................. 1,484,983 3,109,279 10,060,193 8,449,283 2,326,162
Deferred revenue amortization related
to production payment................ (335,896) (401,569) (1,449,808) (1,670,172) (1,787,974)
Other.................................. 115,639 457,304 786,917 140,047 112,890
Change in assets and liabilities --
(Increase) decrease in accounts
receivable......................... (51,807) 2,617,292 (204,475) (5,008,592) (488,599)
Increase (decrease) in accounts
payable and accrued liabilities,
excluding income taxes payable..... 1,722,205 1,315,055 (564,323) (444,966) 1,074,532
Increase (decrease) in income taxes
payable............................ 120,404 275,476 70,130 85,149 (611,717)
------------ ------------ ------------- ------------ ------------
Net Cash Provided by Operating
Activities....................... 13,019,865 19,539,047 55,255,965 37,102,578 14,376,463
------------ ------------ ------------- ------------ ------------
Cash Flows from Investing Activities:
Additions to property and equipment...... (27,980,380) (28,408,757) (131,967,444) (91,487,176) (40,032,944)
Proceeds from the sale of property and
equipment.............................. 1,146,100 529,839 3,369,982 2,247,799 230,242
Net cash received (distributed) as
operator of oil and gas properties..... 2,821,264 1,288,099 (1,829,008) (2,074,104) 7,662,419
Net cash received (distributed) as
operator of partnerships and joint
ventures............................... 3,834,710 738,366 (2,102,553) 11,284,793 5,316,693
Other.................................... (468,516) (311,492) (259,255) 840 (41,181)
------------ ------------ ------------- ------------ ------------
Net Cash Used in Investing
Activities....................... (20,646,822) (26,163,945) (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............................. 7,209,000 -- 7,915,000 -- (27,229,000)
Net proceeds from issuances of common
stock.................................. 859,837 759,280 2,389,336 3,264,482 46,306,322
Purchase of treasury stock............... (573,627) (3,759,895) (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............. 7,495,210 (3,000,615) 1,784,671 113,145,732 19,077,322
------------ ------------ ------------- ------------ ------------
Net Increase (Decrease) in Cash and Cash
Equivalents.............................. $ (131,747) $ (9,625,513) $ (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................................... $ 1,915,585 $ 68,169,461 $ 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................. $ -- $ -- $ 4,638,308 $ 831,516 $ 68,097
Cash paid during period for income
taxes.................................. $ 500 $ -- $ 381,514 $ 676,920 $ 277,580
</TABLE>
See accompanying notes to Consolidated Financial Statements
F-6
<PAGE> 144
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.
Certain 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 March 31, 1998 and for each of the three month periods ended
March 31, 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 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
F-7
<PAGE> 145
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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 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.
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.
F-8
<PAGE> 146
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 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.
F-9
<PAGE> 147
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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.
F-10
<PAGE> 148
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 three months ended March 31, 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>
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31,
-------------------------------------------------------------------
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....................... $3,229,615 16,500,385 $0.20 $6,769,263 16,702,636 $0.41
Dilutive Securities:
6.25% Convertible Notes............................ 957,476 3,646,847 952,561 3,646,847
Stock Options...................................... -- 172,043 -- 540,730
---------- ---------- ---------- ----------
Diluted EPS:
Net Income and Assumed Share Conversions........... $4,187,091 20,319,275 $0.20 $7,721,824 20,890,213 $0.37
========== ========== ========== ==========
</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>
F-11
<PAGE> 149
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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>
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.
F-12
<PAGE> 150
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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.
F-13
<PAGE> 151
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 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
F-14
<PAGE> 152
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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
F-15
<PAGE> 153
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 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.
F-16
<PAGE> 154
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 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.
F-17
<PAGE> 155
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 $41,839,809 of net unproved property costs (primarily seismic and
lease acquisition costs) at December 31, 1997, being excluded from the
amortizable base, $20,120,485 was incurred in 1997, $8,990,306 was incurred in
1996, $4,583,249 was incurred in 1995, and $8,145,769 was incurred in prior
years. The Company expects it will complete its evaluation of the properties
representing the majority of these costs within the next two to three years.
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-18
<PAGE> 156
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.......................... (11,383,887) (8,377,044) (6,826,306)
Depreciation, depletion, and
amortization............................ (23,443,273) (15,812,134) (8,349,324)
------------ ------------ -----------
34,188,029 28,581,494 7,352,262
Income taxes.............................. (11,165,058) (9,689,126) (2,110,099)
------------ ------------ -----------
Results of producing activities........... $ 23,022,971 $ 18,892,368 $ 5,242,163
============ ============ ===========
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-19
<PAGE> 157
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-20
<PAGE> 158
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
three months ended March 31, 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.................. $11,188,847 $ 4,561,523 $ 3,082,381 $ .22 $ .20
Second Quarter................. 12,557,891 5,480,944 3,678,316 .26 .24
Third Quarter.................. 15,432,193 7,178,573 4,641,953 .30 .29
Fourth Quarter................. 21,589,301 11,564,743 7,622,800 .46 .46
----------- ----------- ----------- ----- -----
Total................ $60,768,232 $28,785,783 $19,025,450 $1.27 $1.25
=========== =========== =========== ===== =====
1997
First Quarter.................. $21,245,469 $10,161,045 $ 6,769,263 $ .41 $ .37
Second Quarter................. 16,925,842 6,007,474 4,113,689 .25 .24
Third Quarter.................. 19,225,453 7,024,524 4,685,689 .29 .27
Fourth Quarter................. 22,525,438 9,936,563 6,741,548 .41 .37
----------- ----------- ----------- ----- -----
Total................ $79,922,202 $33,129,606 $22,310,189 $1.35 $1.26
=========== =========== =========== ===== =====
1998
First Quarter.................. $17,761,301 $ 4,835,502 $ 3,229,615 $ .20 $ .20
=========== =========== =========== ===== =====
</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-21
<PAGE> 159
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-22
<PAGE> 160
PARTNERSHIPS COMBINED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
MARCH 31, DECEMBER 31,
1998 1997
------------ ------------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C>
Current Assets:
Cash and cash equivalents................................. $ 6,270 $ 7,429
Accounts receivable --
Oil and gas sales...................................... 7,198 9,965
Other.................................................. 3,576 1,782
Other current assets...................................... 149 92
-------- --------
Total Current Assets.............................. 17,193 19,268
-------- --------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized...................... 325,897 328,373
Less-Accumulated depreciation, depletion, and
amortization........................................... (242,767) (239,044)
-------- --------
83,130 89,329
-------- --------
Total Assets...................................... $100,323 $108,597
======== ========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities:
Accounts payable.......................................... $ 2,065 $ 2,718
Other..................................................... 895 711
-------- --------
Total Current Liabilities......................... 2,960 3,429
-------- --------
Deferred Revenues........................................... 1,247 1,251
Limited Partners' Capital................................... 94,569 101,783
General Partners' Capital................................... 1,547 2,134
-------- --------
Total Liabilities and Partners' Capital........... $100,323 $108,597
======== ========
</TABLE>
See accompanying notes to Combined Financial Statements
F-23
<PAGE> 161
PARTNERSHIPS COMBINED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31, YEAR ENDED
------------------ DECEMBER 31,
1998 1997 1997
------- ------- ------------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C>
Revenues:
Oil and gas sales......................................... $ 5,659 $13,856 $42,228
Interest income........................................... 95 75 330
Other..................................................... 41 89 266
------- ------- -------
5,795 14,020 42,824
------- ------- -------
Costs and Expenses:
General and administrative................................ 1,174 1,400 5,206
Depreciation, depletion, and amortization --
Normal provision....................................... 2,449 3,962 13,012
Additional provision................................... 1,274 2,958 3,845
Oil and gas production.................................... 2,496 3,807 13,774
Interest expense.......................................... 2 4 21
------- ------- -------
7,395 12,131 35,858
------- ------- -------
Net Income (Loss)................................. $(1,600) $ 1,889 $ 6,966
======= ======= =======
</TABLE>
See accompanying notes to Combined Financial Statements
F-24
<PAGE> 162
PARTNERSHIPS COMBINED STATEMENTS OF PARTNERS' CAPITAL
<TABLE>
<CAPTION>
LIMITED GENERAL COMBINING
PARTNERS 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)............................. (1,928) 328 -- (1,600)
Cash Distributions(1)............................ (5,286) (915) -- (6,201)
-------- ------- ------- --------
Balance, March 31, 1998(1)......................... $ 85,668 $ 1,547 $ 8,901 $ 96,116
======== ======= ======= ========
</TABLE>
- ---------------
(1) Unaudited
See accompanying notes to Combined Financial Statements
F-25
<PAGE> 163
PARTNERSHIPS COMBINED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31, YEAR ENDED
------------------ DECEMBER 31,
1998 1997 1997
------- ------- ------------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C>
Cash Flows From Operating Activities:
Net Income (Loss)......................................... $(1,600) $ 1,889 $ 6,966
Adjustments to reconcile income to net cash provided by
operations:
Depreciation, depletion, and amortization.............. 3,723 6,920 16,857
Change in gas imbalance receivable and deferred
revenues............................................. (3) (191) 123
Change in assets and liabilities:
(Increase) Decrease in oil and gas sales
receivable........................................ 954 (244) 774
(Increase) Decrease in other current assets.......... (57) 736 (64)
Decrease in accounts payable......................... (451) (1,036) (914)
------- ------- --------
Net Cash Provided by Operating Activities......... 2,566 8,074 23,742
------- ------- --------
Cash Flows From Investing Activities:
Additions to oil and gas properties....................... (779) (1,172) (3,503)
Proceeds from sales of oil and gas properties............. 3,255 14 4,491
Decrease in receivable due to property dispositions....... -- 230 1,015
------- ------- --------
Net Cash (Used in) Provided by Investing
Activities...................................... 2,476 (928) 2,003
------- ------- --------
Cash Flows From Financing Activities:
Cash distributions to partners............................ (6,201) (6,925) (25,485)
------- ------- --------
Net Cash Used in Financing Activities............. (6,201) (6,925) (25,485)
------- ------- --------
Net Increase (Decrease) In Cash and Cash Equivalents........ $(1,159) $ 221 $ 260
------- ------- --------
Cash and Cash Equivalents At Beginning of Period............ 7,429 7,169 7,169
------- ------- --------
Cash and Cash Equivalents at End of Period.................. $ 6,270 $ 7,390 $ 7,429
======= ======= ========
Supplemental disclosure of cash flow information:
Cash paid during the period for interest.................. $ 2 $ 4 $ 11
======= ======= ========
</TABLE>
See accompanying notes to Combined Financial Statements
F-26
<PAGE> 164
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 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 will be entitled to
receive as a distribution. The Company is offering each Limited Partner in the
Partnerships the opportunity to purchase shares of common stock of the Company
with all or part of the cash distribution such Limited Partner 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 partnership and limited partner
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.
(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
F-27
<PAGE> 165
NOTES TO COMBINED FINANCIAL STATEMENTS OF THE PARTNERSHIPS -- (CONTINUED)
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 March 31, 1998
and for each of the three month periods ended March 31, 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.
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, limited partners, 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 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.
F-28
<PAGE> 166
NOTES TO COMBINED FINANCIAL STATEMENTS OF THE PARTNERSHIPS -- (CONTINUED)
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 limited partners' 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 limited partners shown in the statement of partners' capital
together with "combining adjustments" for the differences between the limited
partners' 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 limited partners.
(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 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
F-29
<PAGE> 167
NOTES TO COMBINED FINANCIAL STATEMENTS OF THE PARTNERSHIPS -- (CONTINUED)
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.
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 limited partner
share of proved reserves were 16,227,735 Mcf and 981,541 Bbls.
F-30
<PAGE> 168
NOTES TO COMBINED FINANCIAL STATEMENTS OF THE PARTNERSHIPS -- (CONTINUED)
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 limited partner 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, 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.
F-31
<PAGE> 169
NOTES TO COMBINED FINANCIAL STATEMENTS OF THE PARTNERSHIPS -- (CONTINUED)
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-32
<PAGE> 170
<TABLE>
<CAPTION>
Petroleum
Engineering
CIBC Oppenheimer Firms
Fair Fair Fair
Market Value Market Value Market Purchase
Partnerships Estimate ($) Estimate ($) Value ($)(1) Price ($)(2)
- ---------------------------------------------------------------- ---------------- -------------- ------------ ---------------
<S> <C> <C> <C> <C>
Swift Energy Income Partners 1986-D, Ltd. 1,369,233 1,567,013 1,567,013 1,684,539
Swift Energy Income Partners 1987-A, Ltd. 1,633,293 1,891,557 1,891,557 2,033,424
Swift Energy Income Partners 1987-B, Ltd. 2,300,789 2,487,048 2,487,048 2,673,577
Swift Energy Income Partners 1987-C, Ltd. 1,509,772 1,648,082 1,648,082 1,771,688
Swift Energy Income Partners 1987-D, Ltd. 1,133,246 1,139,378 1,139,378 1,224,831
Swift Energy Income Partners 1988-A, Ltd. 973,233 991,898 991,898 1,066,290
Swift Energy Income Partners 1988-B, Ltd. 647,934 654,752 654,752 703,858
Swift Energy Income Partners 1988-C, Ltd. 715,596 715,415 715,596 769,266
Swift Energy Income Partners 1988-D, Ltd. 912,565 964,529 964,529 1,036,869
Swift Energy Income Partners 1989-A, Ltd. 1,926,262 1,924,455 1,926,262 2,070,732
Swift Energy Income Partners 1989-B, Ltd. 3,028,036 3,083,309 3,083,309 3,314,557
Swift Energy Income Partners 1989-C, Ltd. 700,816 707,621 707,621 760,693
Swift Energy Income Partners 1989-D, Ltd. 1,011,026 1,077,886 1,077,886 1,158,727
Swift Energy Income Partners 1990-A, Ltd. 1,770,035 1,930,359 1,930,359 2,075,136
Swift Energy Income Partners 1990-B, Ltd. 1,124,167 1,232,438 1,232,438 1,324,871
Swift Energy Income Partners 1988-1, Ltd. 146,639 145,331 146,639 157,637
Swift Energy Income Partners 1988-2, Ltd. 321,722 344,363 344,363 370,190
Swift Energy Income Partners 1988-3, Ltd. 473,711 503,103 503,103 540,836
Swift Energy Income Partners 1989-1, Ltd. 604,515 610,895 610,895 656,712
Swift Energy Income Partners 1989-2, Ltd. 1,338,435 1,366,070 1,366,070 1,468,525
Swift Energy Income Partners 1989-3, Ltd. 377,256 388,917 388,917 418,086
Swift Energy Income Partners 1989-4, Ltd. 367,510 391,776 391,776 421,159
Swift Energy Income Partners 1990-1, Ltd. 456,496 497,826 497,826 535,163
Swift Energy Income Partners 1990-2, Ltd. 326,379 357,814 357,814 384,650
Swift Energy Managed Pension Assets Partnership 1988-A, Ltd. 347,204 342,030 347,204 373,244
Swift Energy Managed Pension Assets Partnership 1988-B, Ltd. 436,930 428,888 436,930 469,700
Swift Energy Managed Pension Assets Partnership 1988-C, Ltd. 290,891 297,515 297,515 319,829
Swift Energy Managed Pension Assets Partnership 1989-A, Ltd. 758,786 763,835 763,835 821,123
Swift Energy Managed Pension Assets Partnership 1989-B, Ltd. 1,382,913 1,419,895 1,419,895 1,526,387
Swift Energy Managed Pension Assets Partnership 1989-C, Ltd. 420,342 428,967 428,967 461,140
Swift Energy Managed Pension Assets Partnership 1989-D, Ltd. 558,871 596,024 596,024 640,726
Swift Energy Managed Pension Assets Partnership 1990-A, Ltd. 1,260,871 1,375,076 1,375,076 1,478,207
Swift Energy Managed Pension Assets Partnership 1990-B, Ltd. 965,293 1,058,264 1,058,264 1,137,634
Swift Energy Managed Pension Assets Partnership 1988-1, Ltd. 137,862 137,089 137,862 148,202
Swift Energy Managed Pension Assets Partnership 1988-2, Ltd. 387,188 413,823 413,823 444,860
Swift Energy Managed Pension Assets Partnership 1989-1, Ltd. 1,149,841 1,180,670 1,180,670 1,269,220
Swift Energy Managed Pension Assets Partnership 1989-2, Ltd. 265,714 276,138 276,138 296,848
Swift Energy Operating Partners 1991-C, Ltd. 1,508,176 1,617,489 1,617,489 1,738,801
Swift Energy Operating Partners 1992-A, Ltd. 908,932 961,599 961,599 1,033,719
Swift Energy Operating Partners 1992-B, Ltd. 2,118,171 2,257,441 2,257,441 2,426,749
Swift Energy Operating Partners 1992-C, Ltd. 3,025,691 3,097,269 3,097,269 3,329,564
Swift Energy Operating Partners 1992-D, Ltd. 993,575 1,025,173 1,025,173 1,102,061
Swift Energy Operating Partners 1993-A, Ltd. 1,470,188 1,456,092 1,470,188 1,580,452
Swift Energy Operating Partners 1993-B, Ltd. 2,049,580 1,905,857 2,049,580 2,203,299
Swift Energy Operating Partners 1993-C, Ltd. 1,447,987 1,389,251 1,447,987 1,556,586
Swift Energy Operating Partners 1993-D, Ltd. 1,467,493 1,421,415 1,467,493 1,577,555
Swift Energy Operating Partners 1994-A, Ltd. 1,725,946 1,541,759 1,725,946 1,855,392
Swift Energy Operating Partners 1994-B, Ltd. 2,287,464 2,040,891 2,287,464 2,459,024
Swift Energy Operating Partners 1994-C, Ltd. 2,246,106 2,103,263 2,246,106 2,414,564
Swift Energy Operating Partners 1994-D, Ltd. 2,158,881 2,080,309 2,158,881 2,320,797
Swift Energy Pension Partners 1991-C, Ltd. 1,240,975 1,330,920 1,330,920 1,430,739
Swift Energy Pension Partners 1992-A, Ltd. 817,439 864,804 864,804 929,664
Swift Energy Pension Partners 1992-B, Ltd. 1,242,278 1,323,959 1,323,959 1,423,256
Swift Energy Pension Partners 1992-C, Ltd. 1,650,715 1,689,383 1,689,383 1,816,087
Swift Energy Pension Partners 1992-D, Ltd. 1,239,909 1,279,339 1,279,339 1,375,289
Swift Energy Pension Partners 1993-A, Ltd. 1,309,553 1,296,994 1,309,553 1,407,769
Swift Energy Pension Partners 1993-B, Ltd. 1,327,783 1,234,678 1,327,783 1,427,367
Swift Energy Pension Partners 1993-C, Ltd. 1,024,096 982,556 1,024,096 1,100,903
Swift Energy Pension Partners 1993-D, Ltd. 908,440 880,083 908,440 976,573
Swift Energy Pension Partners 1994-A, Ltd. 1,021,927 912,886 1,021,927 1,098,572
Swift Energy Pension Partners 1994-B, Ltd. 1,450,877 1,294,482 1,450,877 1,559,693
Swift Energy Pension Partners 1994-C, Ltd. 1,219,922 1,142,352 1,219,922 1,311,416
Swift Energy Pension Partners 1994-D, Ltd. 1,370,541 1,320,652 1,370,541 1,473,332
----------- ----------- ----------- -----------
$72,764,025 $73,790,943 $75,291,493 $80,938,359
=========== =========== =========== ===========
</TABLE>
(1) Higher of the two Fair Market Value estimates.
(2) Includes 7.5% premium.
<PAGE> 171
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)
[ ] 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.
[ ] 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.
[ ] 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.
[ ] 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 stock to be held jointly, all joint tenants
must sign)
Date:
---------------- -----------------------------------------------
(Signature)
Social Security or Tax Identification No.:
-----------------------------------------------
<PAGE> 172
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> 173
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.
-----------------
SPECIAL MEETINGS
OF INVESTORS
OF THE PARTNERSHIPS
====================
OFFERING OF
2,500,000 SHARES OF COMMON STOCK
OF SWIFT ENERGY COMPANY
[SWIFT ENERGY LOGO]
JOINT PROXY STATEMENT/PROSPECTUS
DATED ________, 1998
<PAGE> 174
SWIFT ENERGY MANAGED PENSION ASSETS PARTNERSHIP 1988-A, LTD.
(THE "PARTNERSHIP")
SUPPLEMENT
TO
JOINT PROXY STATEMENT/PROSPECTUS
DATED JUNE _____, 1998
OF THE PARTNERSHIPS AND 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") formed between 1986 and 1994 to invest in producing oil and gas
properties, including the Partnership. Swift is asking Investors in the
Partnership (and the other 62 Partnerships) to approve a Proposal to ultimately
sell substantially all of the Partnership's oil and gas assets to the Managing
General Partner (the "Proposal") for $373,244, which is a price based upon the
higher of two fair market value estimates of those assets determined by three
independent Appraisers, plus a 7.5% premium above fair market value estimates.
If the Proposal is approved by Investors in the Partnership and its
Companion Partnership, after the ultimate sale of substantially all of its
properties the Partnership will dissolve, wind up and terminate. The Partnership
will receive cash for its oil and gas assets, which the Investors in the
Partnership will be entitled to receive as net cash distributions in accordance
with their respective percentage ownership interests in the Partnership. If
Investors in the Partnership approve the Proposal, they 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 (without payment of any Broker commissions).
The effects of the adoption 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 risks, effects and fairness
of the Proposal to the Investors in the Partnership and to provide information
on the Partnership to its Investors.
<PAGE> 175
RISK FACTORS
o There is no guarantee that the fair market value estimates of the
Appraisers represent the highest possible prices that might be received
for the Partnership's 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, although
such prices likely would be offset by any additional general and
administrative costs, production costs or sales costs incurred during
the period necessary to close any such sales.
o The fair market value (excluding the 7.5% premium) at which the
Managing General Partner will purchase 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 Partnership's 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, despite the desire of Investors in the
Partnership to sell their Property Interests, this may not be
accomplishable without a similar approval of the Proposal by the
Investors in the companion Partnership. If either Partnership did 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 Partnership.
o It is likely that if the Proposal is approved by Investors and the
Partnership's Property Interests are ultimately sold to the Managing
General Partner, the Managing General Partner will further develop the
Property Interests by spending required capital on recovery of
behind-pipe reserves or developing undeveloped reserves. As such,
Investors would not directly share in any possible improvement of cash
flow from such Property Interests upon consummation of the Proposal.
However, the Managing General Partner is hereby providing an
opportunity for Investors to purchase Common Stock of the Company on a
direct basis so that they might share indirectly in any such
improvement.
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. See "Federal Income Tax Consequences of Adoption of
the Proposal--Tax Treatment of Tax Exempt Plans--Debt-Financed
Property."
o 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 Partnership. The character of the gain or loss
depends on certain factors specific
2
<PAGE> 176
to the Partnership and to the Investors. For a broader discussion of
the tax consequences, Investors should read "Federal Income Tax
Consequences of Adoption of the Proposal."
o As currently proposed, Investors that subscribe for Company stock
pursuant to this offering may 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 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 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 distribution from the
Partnership.
See "Summary--Risks" in the Joint Proxy Statement/Prospectus.
CONFLICTS OF INTEREST
A number of conflicts of interest are inherent in the relationships
among the Partnership, the Company and its directors and officers. Certain of
these conflicts of interest (to the extent not otherwise highlighted above) are
summarized 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 unaffiliated 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 such
transaction.
o Benefits accruing to the Company, including the following:
o 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.
3
<PAGE> 177
o If Investors of all of the Partnerships approve the Proposals,
the Company anticipates that its total proved reserves on an
equivalent basis would increase by approximately 26% and would
increase the Company's cash flow and total assets by
approximately 25% and 19%, respectively.
The Proposal to ultimately sell substantially all of the Partnership's
Property Interests to the Managing General Partner is discussed in detail under
"The Proposal" and "Special Factors" herein. The Proposal presents a potential
conflict of interest between the Managing General Partner acting in its capacity
as managing general partner of the Partnership and its actions in its corporate
capacity as the proposed purchaser of the Partnership's Property Interests. The
Special Transactions Committee of the Board of Directors of Swift Energy Company
(the "Special Transactions Committee"), which consists solely of four of the
five outside independent directors of Swift Energy Company, approved the
selection of the three independent third party appraisers (the "Appraisers")
chosen to estimate the fair market value of the Partnership's Property
Interests. The Special Transactions Committee determined that this conflict of
interest is best addressed by asking three different Appraisers, consisting of
two independent petroleum engineering firms and one investment banking firm, to
estimate the fair market value of the Partnership's Property Interests, rather
than proposing that the Managing General Partner set such fair market value
itself and ask for an opinion on the fairness thereof from an independent third
party.
The Special Transactions Committee determined that having three
independent appraisers collectively determine the fair market value for a cash
purchase of the Partnership's Property Interests would protect Investors by
mitigating the potential conflict 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 three appraisers working
collectively provides the distinct professional expertise of each firm, and
gives the Partnership 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.
See "Summary--Conflicts of Interest" in the Joint Proxy Statement/Prospectus.
THE PROPOSAL
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 almost ten years. As discussed above, 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 Proposal, without the risk
of such distributions being negatively affected by oil and gas price decreases.
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.
4
<PAGE> 178
Decreasing Cash Flow While Expenses Continue. As of December 31, 1997,
approximately 83% of the Partnership's ultimate recoverable reserves had been
produced, and the Investors' share of the Partnership's interest in reserves is
estimated to be less than 467,575 Mcfe. As a result of the 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 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 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.
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 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 Partnership's companion Operating Partnership
on the properties in which the Partnership has an interest.
Limited Partners' Tax Reporting. Each Investor will continue to have a
partnership 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 "Business of the
Partnership--No Trading Market." Following the approval of the Proposal and 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. 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 "Federal Income
Tax Consequences."
See "Summary--Background and Reasons for the Proposals; Managing General
Partner's Recommendations" in the Joint Proxy Statement/Prospectus.
5
<PAGE> 179
FAIRNESS OF PROPOSED SALE
The Managing General Partner believes that this proposed method of sale
of the Partnership's Property Interests is fair to Investors for a variety of
reasons including, without giving weight to the order, the following:
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 based on
the estimations of such value by third party independent
Appraisers. Instead of the Managing General Partner attempting
to set the Fair Market Value of the Property Interests, the
price proposed to be paid by the Managing General Partner for
the Partnership's Property Interests (not including the 7.5%
premium above Fair Market Value) was based on the valuation
estimates of three qualified independent Appraisers, two of
which are petroleum engineering firms and one of which is an
investment banking firm. Using three different firms from two
different disciplines has been designed to provide a
comprehensive analysis of valuation factors. 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 Partnership Property Interests."
2. No transaction will take place unless the Proposal is approved
by Investors holding a majority of the interests in the
Partnership, without the Managing General Partner voting any
limited partnership interests in the Partnership which it
owns, 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 Proposal is approved by Investors, it is likely that
the Managing General Partner will expend the capital necessary
to bring various nonproducing reserves into production on the
Property Interests purchased by the Managing General Partner.
If all of the Property Interests which are the subject of the
Proposal are acquired by the Company, such Property Interests
in the aggregate will constitute less than 20% of the
Company's total assets. In order to allow Investors to benefit
from any increase in value of the Property Interests realized
from the Managing General Partner's investment of capital in
such properties, the Company is hereby offering to Eligible
Purchasers the opportunity to purchase on a collective basis
up to 2,500,000 shares of Common Stock. There is no
requirement that any purchase of Swift's Common Stock be made.
See "Offer to Eligible Purchaser" below.
See "Summary--Fairness of Proposed Sale" in the Joint Proxy
Statement/Prospectus.
COLLECTIVE ANALYSIS OF PURCHASE PRICE; PREMIUM OVER FAIR MARKET VALUE
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
6
<PAGE> 180
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 $80.94 million. The valuation estimates of the Appraisers are
attached to this Supplement and incorporated herein by reference. The PV-10
Value prepared on an annual basis by H.J. Gruy of the same Property Interests as
of the same date is $484,519. 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 below 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.
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 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.
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 attached to
this Supplement to the Joint Proxy Statement/Prospectus. CIBC Oppenheimer then
divided the property groups ("Property") 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 under "Regarding the
Proposals to Sell the Partnerships' Oil and Gas Assets--Independent Appraisal of
the Fair Market Value of Property Interests of the Partnerships--Valuation of
CIBC Oppenheimer" 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
7
<PAGE> 181
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. 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. Because these
benefits are particular to the Company, the Company believes that it is fair to
pay a premium of 7.5% over the Fair Market Value of the Property Interests to
purchase those interests.
See "Summary--Determination of Fair Market Value of Partnerships'
Property Interests" in the Joint Proxy Statement/Prospectus.
ESTIMATES OF LIQUIDATING NET CASH DISTRIBUTION AMOUNT
Set forth in the table below are estimated net proceeds that the
Partnership may realize from sales 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 June 30, 1998, resulting in an estimate of the amount of net cash
distributions available for Investors as a result of such sales.
8
<PAGE> 182
ESTIMATE OF NET CASH DISTRIBUTIONS
FROM PROPERTY INTEREST SALES AND LIQUIDATION
<TABLE>
<CAPTION>
<S> <C>
Appraisers' 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) $ (56,283)
---------
Estimated Net Distributions to Partners(6) $ 388,140
=========
</TABLE>
<TABLE>
<CAPTION>
<S> <C>
Amount Distributable
to Investors(6) $350,181
Amount Distributable
to General Partners(6)(7) $ 37,959
--------
$388,140
========
</TABLE>
<TABLE>
<CAPTION>
<S> <C>
ESTIMATED NET CASH DISTRIBUTIONS TO INVESTORS PER $100 UNIT $ 7.34
=======
MINIMUM NUMBER OF UNITS NECESSARY TO PURCHASE 100 SHARES
OF SWIFT ENERGY COMMON STOCK WITH CASH DISTRIBUTIONS(8) 246
=======
</TABLE>
- --------------------------------
<TABLE>
<S> <C>
(1) Represents the higher of two values estimated 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
June 30, 1998.
(6) Gross Sales Proceeds amount is allocated 90% to the Investors and 10% to
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, then the
minimum number
</TABLE>
9
<PAGE> 183
of shares which can be purchased by an Eligible Purchaser is a round
lot of 100 shares. Based upon estimated net cash distribution of $7.34
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.
ESTIMATES OF NET CASH DISTRIBUTIONS AVAILABLE FROM CONTINUED OPERATIONS
If, on the other hand, the Partnership were to retain its Property
Interests and continue to benefit from production of its oil and gas assets
until they have reached their economic limit, the table below estimates the
return to Investors, discounted to present value, based upon the year end
pricing without escalation and discount assumptions used above. The estimates of
the present value of future net cash distributions have been further reduced by
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>
<CAPTION>
PROJECTED
CASH FLOWS
-----------
<S> <C>
Estimated Future Net Revenues from Continued Operations Until $ 811,554
Depletion(1)
Estimated Interim Net Cash Distributions(2) $ (50,100)
Estimated Partnership Direct and Administrative Expenses(3) $ (121,733)
Net Assets(4) $ 73,736
------------
Net Cash Distributions to Investors(5) $ 713,457
============
NET CASH DISTRIBUTIONS PER $100 UNIT $ 14.96
PRESENT VALUE OF NET CASH DISTRIBUTIONS PER $100 UNIT(5)(6) $ 8.25
</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 "The Proposal--Reasons for the Proposal." The actual prices
that will be received and the associated costs may be more or less than
those projected. See "The Proposal--Partnership Financial Condition and
Performance."
10
<PAGE> 184
(2) Estimated net cash distributions paid to Investors from January 1, 1998
to June 30, 1998 in order to present this information on a comparative
basis as of June 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 Investors and the General Partners in
accordance with the Partnership Agreement. The amounts finally distributed will
depend on the actual sales prices received for the Partnership assets, results
of operations until such sales and other contingencies and circumstances.
COMPARISON OF SALE VERSUS CONTINUING OPERATIONS
The Managing General Partner believes that the Proposal to sell the
Partnership's Property Interests and liquidate is fair to Investors for the
reasons discussed in detail under "Special Factors--Fairness of Proposed Sale."
Based on the above tables, it is estimated that an Investor could
expect to receive $7.34 per $100 Unit upon immediate sale of the Partnership's
Property Interests. In comparison, it is estimated that an Investor could expect
to receive $8.25 per $100 Unit, discounted to present value at 10% per annum
($14.96 per $100 Unit on an undiscounted basis) if the Partnership continued
operations.
Although the estimates contained under "The Proposal--Estimates of
Liquidating Net Cash Distribution Amount" above show that estimated net cash
distributions to Investors (based on net present value) from continued
operations would be approximately 12% higher than estimated net cash
distributions from selling the Partnership's Property Interests and liquidating
the Partnership at this time, the Managing General Partner believes there is a
substantial advantage in receiving the liquidating net cash distribution in one
lump sum currently. The estimates of net cash distributions from continued
operations are based upon current prices. 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 subjects
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 price volatility and to 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 is the
amount calculated under the terms of the original 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
11
<PAGE> 185
distributions of $1.50 per $100 Unit, and are estimated to receive another $1.05
per $100 Unit before June 30, 1998, which converts to a comparable value of
$8.11 per $100 Unit. Under the terms set out in the 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 determination of fair market value.
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 adding the present value of proved oil and gas reserves (discounted
at 10% per annum) calculated on an escalated pricing basis to cash and accounts
receivable less outstanding debts and obligations of the Partnership, and then
further discounting that result by 30%.
TRANSACTIONS BETWEEN THE MANAGING GENERAL PARTNER AND THE PARTNERSHIP
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. 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 "The Proposal--Impact on the Managing General Partner."
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
to Investor 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 three years ended
December 31, 1997.
o The Managing General Partner receives per-well monthly
operating fees on certain producing wells in which the
Partnership owns Property Interests and for which the Managing
General Partner serves as operator in accordance with the
joint operating agreements for each of such wells. The fees
that are set in the joint operating agreements are negotiated
with the other working interest owners of the properties.
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
12
<PAGE> 186
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 $42,904 has been reimbursed
during the three years ended December 31, 1997.
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
$5,745 has been reimbursed during the three years ended
December 31, 1997.
BUSINESS OF THE PARTNERSHIP
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. In addition to the following information about the
business of the Partnership, see the attached Annual Report on Form 10-K for the
year ended December 31, 1997.
The following tabulation 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 (See "Glossary of
Terms"). The information below 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 ($484,519) 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 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 average less than 5% of the Partnership's PV-10 Value at the same date.
13
<PAGE> 187
<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
Operator(s) Marquee Fair Oil Apache Apache Swift and
Corp.; 11 others
Columbus
Energy
% of 12/31/97 PV-10 Value 21% 21% 19% 11% 28%
% of 1997 Production (Volumes) 20% 21% 20% 7% 32%
</TABLE>
RESERVES
For information about 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, see the report dated
February 10, 1998 attached hereto, which was audited by H.J. Gruy and
Associates, Inc., independent petroleum consultants, and which contains both
estimates for the Partnership as a whole and those solely attributable to the
interest in the Partnership of Investors. This report has not been updated to
include the effect of production since year-end 1997.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates and timing of production,
future costs and future development plans. Oil and gas reserve engineering must
be recognized as a subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact way, and estimates of other
engineers might differ from those in the attached report. 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, and, as a general rule, reserves estimates based upon
volumetric analysis are inherently less reliable than those based on lengthy
production history. Accordingly, reserve estimates are often different from the
quantities of oil and gas that are ultimately recovered.
In estimating the Partnership's interest in oil and natural gas
reserves, the Managing General Partner, in accordance with criteria prescribed
by the Securities and Exchange Commission, has used pricing based upon 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 does not believe that any favorable or adverse event causing a
significant
14
<PAGE> 188
change in the estimated quantity of proved reserves set forth in the attached
report has occurred between December 31, 1997 and the date of this Supplement.
Future prices received for the sale of production from properties in
which the Partnership has an interest may be higher or lower than the prices
used in the Partnership's estimates of oil and gas reserves; the operating costs
relating to such production may also increase or decrease from existing levels.
NO TRADING MARKET
There is no trading market for the Units, and none is expected to
develop, as described above under "Comparison of Sale Versus 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. Through
December 31, 1997, the Managing General Partner has purchased 2,523 Units from
Investors pursuant to the right of presentment. As of June ___, 1998, there were
411 Investors (excluding the Managing General Partner). 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 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.
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.
PARTNERSHIP FINANCIAL PERFORMANCE AND CONDITION
The Partnership owns non-operating Property Interests in producing oil
and gas properties within the continental United States in which the Operating
Partnership 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. The Operating Partnership has, from
time to time, performed workovers and recompletions of 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.
15
<PAGE> 189
Investors have made contributions of $4,770,363, 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 $38,125. Additionally, pursuant to the presentment right set
forth in the Partnership Agreement, it has purchased 2,523 Units from Investors.
From inception through January 31, 1998, the Partnership has made net cash
distributions to its Investors totaling $2,728,500. For details of the amounts
of cash distributions made to Investors, see "Item 6. Selected Financial Data"
in the attached Form 10-K Report for the year ended December 31, 1997. Through
January 31, 1998, the Managing General Partner has received net cash
distributions from the Partnership of $255,406 with respect to its general
partner interest, and $16,188 related to its limited partner interests. On a per
Unit basis, Investors had received, as of January 31, 1998, $57.20 per $100
Unit, or approximately 57.20% 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 during the fourth quarter of 1988 and the first quarter
of 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. The bulk 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 to date has been natural
gas.
16
<PAGE> 190
[GRAPH: 1 page of gas properties info]
17
<PAGE> 191
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.
SUMMARY OF FEDERAL INCOME TAX CONSEQUENCES
GENERAL
The following briefly describes certain federal income tax consequences
to the Investors arising from the Partnership's proposed sale of its Property
Interests, including its net profits interest and liquidation pursuant to the
Proposal. Statements of legal conclusions herein 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"), 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 CERTAIN FEDERAL INCOME TAX CONSEQUENCES TO
INVESTORS MAY BE FOUND IN THE REGISTRATION STATEMENT IN "FEDERAL INCOME TAX
CONSEQUENCES OF ADOPTION OF THE PROPOSAL." 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
18
<PAGE> 192
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 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.
19
<PAGE> 193
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 that the Partnership will realize 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. 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 will be
taxed at a maximum rate of 20%, while ordinarily 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 FOR GENERAL INFORMATION ONLY AND IS
INTENDED TO BE A SUMMARY OF CERTAIN INCOME TAX CONSIDERATIONS OF THE SALE OF
PROPERTIES AND LIQUIDATION. IT IS NOT INTENDED AS AN ALTERNATIVE FOR INDIVIDUAL
TAX PLANNING. EACH INVESTOR SHOULD CONSULT HIS OR ITS OWN TAX ADVISOR CONCERNING
THE FEDERAL, STATE, LOCAL, FOREIGN AND OTHER TAX CONSEQUENCES TO HIM OR IT OF
THE SALE OF PROPERTIES AND THE LIQUIDATION OF THE PARTNERSHIP.
20
<PAGE> 194
SELECTED FINANCIAL INFORMATION AND
PROFORMA FINANCIAL STATEMENTS
For selected financial information and financial statements of the
Partnership, see the Form 10-K Annual Report for the year ended December 31,
1997 and the Form 10-Q Quarterly Report for the quarter ended March 31, 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) are contained in the Joint Proxy Statement/Prospectus
under "Unaudited Proforma Consolidated Financial Statements".
21
<PAGE> 195
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> 196
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> 197
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> 198
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.
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(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> 199
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> 200
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> 201
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> 202
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> 203
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> 204
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> 205
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> 206
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> 207
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> 208
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> 209
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> 210
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 JUNE ____, 1998
The undersigned hereby constitutes and appoints A. Earl Swift, Bruce
H. Vincent, Terry E. Swift or John R. Alden, as duly authorized officers of
Swift Energy Company, acting in its capacity as Managing General Partner of the
Partnership, or any of them, with full power of substitution and revocation to
each, the true and lawful attorneys and proxies of 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 June ___,
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 with all powers the undersigned would possess
if personally present at the Meeting:
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:
THIS PROXY WILL BE VOTED IN ACCORDANCE WITH THE SPECIFICATIONS MADE
HEREON. IF NO CONTRARY SPECIFICATION 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 May___, 1998 is acknowledged.
PLEASE SIGN AND RETURN THE PROXY IN THE ENCLOSED, POSTAGE-PAID,
PRE-ADDRESSED ENVELOPE BY JUNE ___, 1998.
SIGNATURE DATE
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SIGNATURE DATE
------------------------------ ---------------------
SIGNATURE DATE
------------------------------ ---------------------
IF LIMITED PARTNERSHIP UNITS ARE HELD JOINTLY, ALL JOINT TENANTS MUST
SIGN.
<PAGE> 211
SWIFT ENERGY INCOME PARTNERS 1989-B, LTD.
(THE "PARTNERSHIP")
SUPPLEMENT
TO
JOINT PROXY STATEMENT/PROSPECTUS
DATED JUNE _____, 1998
OF THE PARTNERSHIPS AND 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") formed between 1986 and 1994 to invest in producing oil and gas
properties, including the Partnership. Swift is asking approval of a Proposal
being submitted to Investors in the Partnership (and the other 62 Partnerships)
to sell substantially all of the Partnership's oil and gas assets to the
Managing General Partner (the "Proposal") for $3,314,557, which is a price based
upon the higher of two fair market value estimates of those assets determined by
three independent Appraisers, plus a 7.5% premium above fair market value
estimates.
If the Proposal is approved by Investors in the Partnership and its
companion Partnership, after the sale of substantially all of its properties the
Partnership will dissolve, wind up and terminate. The Partnership will receive
cash for its oil and gas assets, which the Investors in the Partnership will be
entitled to receive as net cash distributions in accordance with their
respective percentage ownership interests in the Partnership. If Investors in
the Partnership approve the Proposal, they 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 (without payment of any Broker commissions).
The effects of the adoption 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 risks, effects and fairness
of the Proposal to the Investors in the Partnership and to provide information
on the Partnership to its Investors.
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<PAGE> 212
RISK FACTORS
o There is no guarantee that the fair market value estimates of the
Appraisers represent the highest possible prices that might be received
for the Partnership's 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, although
such prices likely would be offset by any additional general and
administrative costs, production costs or sales costs incurred during
the period necessary to close any such sales.
o The fair market value (excluding the 7.5% premium) at which the
Managing General Partner will purchase 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 Partnership's 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, despite the desire of Investors in the
Partnership to sell their Property Interests, this may not be
accomplishable without a similar approval of the Proposal by the
Investors in the companion Partnership. If either Partnership did 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 Partnership.
o It is likely that if the Proposal is approved by Investors and the
Partnership's Property Interests are sold to the Managing General
Partner, the Managing General Partner will further develop the Property
Interests by spending required capital on recovery of behind-pipe
reserves or developing undeveloped reserves. As such, Investors would
not directly share in any possible improvement of cash flow from such
Property Interests upon consummation of the Proposal. However, the
Managing General Partner is hereby providing an opportunity for
Investors to purchase Common Stock of the Company on a direct basis so
that they might share indirectly in any such improvement.
o Investors 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 Partnership. The
character of the gain or loss depends on certain factors specific to
the Partnership and to the Investors. For a broader discussion of the
tax consequences, Investors should read "Federal Income Tax
Consequences of Adoption of the Proposal."
o As currently proposed, Investors that subscribe for Company stock
pursuant to this offering may 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
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pursuant to the terms of this offering. For federal 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 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 distribution from the
Partnership.
See "Summary--Risks" in the Joint Proxy Statement/Prospectus.
CONFLICTS OF INTEREST
A number of conflicts of interest are inherent in the relationships
among the Partnership, the Company and its directors and officers. Certain of
these conflicts of interest (to the extent not otherwise highlighted above) are
summarized 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 unaffiliated 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 such
transaction.
o Benefits accruing to the Company, including the following:
o 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.
o If Investors of all of the Partnerships approve the Proposals,
the Company anticipates that its total proved reserves on an
equivalent basis would increase by approximately 26% and would
increase the Company's cash flow and total assets by
approximately 25% and 19%, respectively.
The Proposal to sell substantially all of the Partnership's Property
Interests to the Managing General Partner is discussed in detail under "The
Proposal" and "Special Factors" herein. The Proposal presents a
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potential conflict of interest between the Managing General Partner acting in
its capacity as managing general partner of the Partnership and its actions in
its corporate capacity as the proposed purchaser of the Partnership's Property
Interests. The Special Transactions Committee of the Board of Directors of Swift
Energy Company (the "Special Transactions Committee"), which consists solely of
four of the five outside independent directors of Swift Energy Company, approved
the selection of the three independent third party appraisers (the "Appraisers")
chosen to estimate the fair market value of the Partnership's Property
Interests. The Special Transactions Committee determined that this conflict of
interest is best addressed by asking three different Appraisers, consisting of
two independent petroleum engineering firms and one investment banking firm, to
estimate the fair market value of the Partnership's Property Interests, rather
than proposing that the Managing General Partner set such fair market value
itself and ask for an opinion on the fairness thereof from an independent third
party.
The Special Transactions Committee determined that having three
independent appraisers collectively determine the fair market value for a cash
purchase of the Partnership's Property Interests would protect Investors by
mitigating the potential conflict 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 three appraisers working
collectively provides the distinct professional expertise of each firm, and
gives the Partnership 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.
See "Summary--Conflicts of Interest" in the Joint Proxy Statement/Prospectus.
THE PROPOSAL
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
Limited Partners 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 almost
nine years. As discussed above, 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 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 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
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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 a
partnership 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 "Business of the
Partnership--No Trading Market." Following the approval of the Proposal and 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. 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 "Federal Income
Tax Consequences."
See "Summary--Background and Reasons for the Proposals; Managing General
Partner's Recommendations" in the Joint Proxy Statement/Prospectus.
FAIRNESS OF PROPOSED SALE
The Managing General Partner believes that this proposed method of sale
of the Partnership's Property Interests is fair to Investors for a variety of
reasons including, without giving weight to the order, the following:
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 based on
the estimations of such value by third party independent
Appraisers. Instead of the Managing General Partner attempting
to set the Fair Market Value of the Property Interests, the
proposed price to be paid by the Managing General Partner for
the Partnership's Property Interests (not including the 7.5%
premium above Fair Market Value) was based on the valuation
estimates of three qualified independent Appraisers, two of
which are petroleum engineering firms and one of which is an
investment banking firm. Using three different firms from two
different disciplines has been designed to provide a
comprehensive analysis of valuation factors. 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 Partnership Property Interests."
2. No transaction will take place unless the Proposal is approved
by Investors holding a majority of the interests in the
Partnership, without the Managing General Partner voting any
limited partnership interests in the Partnership which it
owns, 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.
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4. If the Proposal is approved by Investors, it is likely that
the Managing General Partner will expend the capital necessary
to bring various nonproducing reserves into production on the
Property Interests purchased by the Managing General Partner.
If all of the Property Interests which are the subject of the
Proposal are acquired by the Company, such Property Interests
in the aggregate will constitute less than 20% of the
Company's total assets. In order to allow Investors to benefit
from any increase in value of the Property Interests realized
from the Managing General Partner's investment of capital in
such properties, the Company is hereby offering to Eligible
Purchasers the opportunity to purchase on a collective basis
up to 2,500,000 shares of Common Stock. There is no
requirement that any purchase of Swift's Common Stock be made.
See "Offer to Eligible Purchaser" below.
See "Summary--Fairness of Proposed Sale" in the Joint Proxy
Statement/Prospectus.
COLLECTIVE ANALYSIS OF PURCHASE PRICE; PREMIUM OVER FAIR MARKET VALUE
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 $80.94 million.
The valuation estimates of the Appraisers are attached to this Supplement and
incorporated herein by reference. 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. 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 below 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.
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 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
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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 $3,083,309 as of December 31,
1997.
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 attached to
this Supplement to the Joint Proxy Statement/Prospectus. CIBC Oppenheimer then
divided the property groups ("Property") 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 under "Regarding the
Proposals to Sell the Partnerships' Oil and Gas Assets--Independent Appraisal of
the Fair Market Value of Property Interests of the Partnerships--Valuation of
CIBC Oppenheimer" 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. 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. Because these
benefits are particular to the Company, the Company believes that it is fair to
pay a premium of 7.5% over the Fair Market Value of the Property Interests to
purchase those interests.
See "Summary--Determination of Fair Market Value of Partnerships'
Property Interests" in the Joint Proxy Statement/Prospectus.
ESTIMATES OF LIQUIDATING NET CASH DISTRIBUTION AMOUNT
Set forth in the table below are estimated net proceeds that the
Partnership may realize from sales 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 June 30, 1998, resulting in an estimate of the amount of net cash
distributions available for Investors as a result of such sales.
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ESTIMATE OF NET CASH DISTRIBUTIONS
FROM PROPERTY INTEREST SALES AND LIQUIDATION
Appraisers' 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) $ (547,692)
-----------
Estimated Net Distributions to Partners(6) $ 3,362,774
===========
Amount Distributable
to Investors(6) $ 2,824,097
Amount Distributable
to General Partners(6)(7) $ 538,677
-----------
$ 3,362,774
===========
ESTIMATED NET CASH DISTRIBUTIONS TO
INVESTORS PER $100 UNIT $ 33.90
===========
MINIMUM NUMBER OF UNITS NECESSARY TO
PURCHASE 100 SHARES OF SWIFT ENERGY COMMON
STOCK WITH CASH DISTRIBUTIONS(8) 54
===========
- ---------------------------------
<TABLE>
<S> <C>
(1) Represents the higher of two values estimated 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 June 30, 1998.
(6) Gross Sales Proceeds amount is allocated 85% to the Investors and 15% to 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,
then the minimum number
</TABLE>
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<TABLE>
<S> <C>
of shares which can be purchased by an Eligible Purchaser is a round lot of 100 shares. Based
upon estimated net cash distribution of $33.90 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.
</TABLE>
ESTIMATES OF NET CASH DISTRIBUTIONS AVAILABLE FROM CONTINUED OPERATIONS
If, on the other hand, the Partnership were to retain its Property
Interests and continue to benefit from production of its oil and gas assets
until they have reached their economic limit, the table below estimates the
return to Investors, discounted to present value, based upon the year end
pricing without escalation and discount assumptions used above. The estimates of
the present value of future net cash distributions have been further reduced by
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 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
PROJECTED
CASH FLOWS
-----------
Estimated Future Net Revenues from Continued
Operations Until Depletion(1) $ 5,266,181
Estimated Interim Net Cash Distributions(2) $ (499,800)
Estimated Partnership Direct and
Administrative Expenses(3) $ (663,540)
Net Assets(4) $ 585,147
-----------
Net Cash Distributions to Investors(5) $ 4,687,988
===========
NET CASH DISTRIBUTIONS PER $100 UNIT $ 56.28
PRESENT VALUE OF NET CASH DISTRIBUTIONS
PER $100 UNIT(5)(6) $ 36.32
- --------------------------
<TABLE>
<S> <C>
(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 "The Proposal--Reasons for the Proposal." The actual prices that will be received and
the associated costs may be more or less than those projected. See "The Proposal--Partnership
Financial Condition and Performance."
</TABLE>
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<TABLE>
<S> <C>
(2) Estimated net cash distributions paid to Investors from January 1, 1998 to June 30, 1998 in order
to present this information on a comparative basis as of June 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.
</TABLE>
The proceeds of all sales, to the extent available for net cash
distribution, are to be distributed to Investors and the General Partners in
accordance with the Partnership Agreement. The amounts finally distributed will
depend on the actual sales prices received for the Partnership assets, results
of operations until such sales and other contingencies and circumstances.
COMPARISON OF SALE VERSUS CONTINUING OPERATIONS
The Managing General Partner believes that the Proposal to sell the
Partnership's Property Interests and liquidate is fair to Investors for the
reasons discussed in detail under "Special Factors--Fairness of Proposed Sale."
Based on the above tables, it is estimated that an Investor could
expect to receive $33.90 per $100 Unit upon immediate sale of the Partnership's
Property Interests. In comparison, it is estimated that an Investor could expect
to receive $36.32 per $100 Unit, discounted to present value at 10% per annum
($56.28 per $100 Unit on an undiscounted basis) if the Partnership continued
operations.
Although the estimates contained under "The Proposal--Estimates of
Liquidating Net Cash Distribution Amount" above show that estimated net cash
distributions to Investors (based on net present value) from continued
operations would be approximately 7% higher than estimated net cash
distributions from selling the Partnership's Property Interests and liquidating
the Partnership at this time, the Managing General Partner believes there is a
substantial advantage in receiving the liquidating net cash distribution in one
lump sum currently. The estimates of net cash distributions from continued
operations are based upon current prices. 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 subjects
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 price volatility and to 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 is the
amount calculated under the terms of the original 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
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distributions of $12.63 per $100 Unit, and are estimated to receive another
$6.00 per $100 Unit before June 30, 1998, which converts to a comparable value
of $36.02 per $100 Unit. Under the terms set out in the 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 determination of fair market
value. 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 adding the present value of proved oil and gas reserves
(discounted at 10% per annum) calculated on an escalated pricing basis to cash
and accounts receivable less outstanding debts and obligations of the
Partnership, and then further discounting that result by 30%.
TRANSACTIONS BETWEEN THE MANAGING GENERAL PARTNER AND THE PARTNERSHIP
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. 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 "The Proposal--Impact on the Managing General Partner."
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 to Investor 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 three years ended
December 31, 1997.
o The Managing General Partner receives per-well monthly
operating fees on certain producing wells in which the
Partnership owns Property Interests and for which it serves as
operator in accordance with the joint operating agreements for
each of such wells. The fees that are set in the joint
operating agreements are negotiated with the other working
interest owners of the properties.
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
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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 $388,586 has been
reimbursed during the three years ended December 31, 1997.
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
$9,962 has been reimbursed during the three years ended
December 31, 1997.
BUSINESS OF THE PARTNERSHIP
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. In addition to the following 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 first
quarter ended March 31, 1998.
The following tabulation presents information on those fields in which
the Partnership has Property Interests which constitute 8% 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 (See "Glossary of
Terms"). The information below 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 ($4,009,417) 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 fields in which the Partnership owns a Property
Interest, twenty-one 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 average less than 3% of the Partnership's PV-10 Value at
the same date.
12
<PAGE> 223
<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
Operator(s) Swift Vintage Titan Swift
Petroleum; Resources and 42
Estoril others
Producing
% of 12/31/97 PV-10 Value 40% 14% 8% 38%
% of 1997 Production (Volumes) 25% 18% 10% 47%
</TABLE>
RESERVES
For information about 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, see the report dated
February 10, 1998 attached hereto, which was audited by H.J. Gruy and
Associates, Inc., independent petroleum consultants, and which contains both
estimates for the Partnership as a whole and those solely attributable to the
interest in the Partnership of Investors. This report has not been updated to
include the effect of production since year-end 1997.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates and timing of production,
future costs and future development plans. Oil and gas reserve engineering must
be recognized as a subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact way, and estimates of other
engineers might differ from those in the attached report. 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, and, as a general rule, reserves estimates based upon
volumetric analysis are inherently less reliable than those based on lengthy
production history. Accordingly, reserve estimates are often different from the
quantities of oil and gas that are ultimately recovered.
In estimating the Partnership's interest in oil and natural gas
reserves, the Managing General Partner, in accordance with criteria prescribed
by the Securities and Exchange Commission, has used pricing based upon 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 does not believe that any favorable or adverse event causing a
significant
13
<PAGE> 224
change in the estimated quantity of proved reserves set forth in the
attached report has occurred between December 31, 1997 and the date of this
Supplement.
Future prices received for the sale of production from properties in
which the Partnership has an interest may be higher or lower than the prices
used in the Partnership's estimates of oil and gas reserves; the operating costs
relating to such production may also increase or decrease from existing levels.
NO TRADING MARKET
There is no trading market for the Units, and none is expected to
develop, as described above under "Comparison of Sale Versus 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. Through
December 31, 1997, the Managing General Partner has purchased 7,514 Units from
Investors pursuant to the right of presentment. As of June ___, 1998, there were
626 Investors (excluding the Managing General Partner). 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
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.
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.
PARTNERSHIP FINANCIAL PERFORMANCE AND CONDITION
The Partnership owns Property Interests in producing oil and gas
properties within the continental United States. 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 of 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.
14
<PAGE> 225
Investors have 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 January 31, 1998, the Partnership has made net cash
distributions to its Investors totaling $8,451,400. For details of the amounts
of cash distributions made to Investors, see "Item 6. Selected Financial Data"
in the attached Form 10-K Report for the year ended December 31, 1997. Through
January 31, 1998, the Managing General Partner has received net cash
distributions from the Partnership of $1,106,465 with respect to its general
partner interest, and $204,707 related to its limited partner interests. On a
per Unit basis, Investors had received, as of January 31, 1998, $101.46 per $100
Unit, or approximately 101.46% 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 during the third quarter of 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. The
bulk 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 but the prices for the Partnership's principal asset,
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.
15
<PAGE> 226
[GRAPHS: 2 pages of oil and gas properties info]
16
<PAGE> 227
17
<PAGE> 228
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.
SUMMARY OF FEDERAL INCOME TAX CONSEQUENCES
GENERAL
The following briefly describes certain federal income tax consequences
to the Investors arising from the Partnership's proposed sale of its oil and gas
properties and liquidation pursuant to the Proposal. Statements of legal
conclusions herein 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 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 CERTAIN FEDERAL INCOME TAX CONSEQUENCES TO
INVESTORS MAY BE FOUND IN THE REGISTRATION STATEMENT IN "FEDERAL INCOME TAX
CONSEQUENCES OF ADOPTION OF THE PROPOSAL." 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.
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
18
<PAGE> 229
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 Investors in complete
liquidation. The Partnership will not realize gain or loss upon such
distribution of cash to its Investors 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 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 FOR GENERAL INFORMATION ONLY AND IS
INTENDED TO BE A SUMMARY OF CERTAIN INCOME TAX CONSIDERATIONS OF THE SALE OF
PROPERTIES AND LIQUIDATION. IT IS NOT INTENDED AS AN ALTERNATIVE FOR INDIVIDUAL
TAX PLANNING. EACH INVESTOR SHOULD CONSULT HIS OR ITS OWN TAX ADVISOR CONCERNING
THE FEDERAL, STATE, LOCAL, FOREIGN AND OTHER TAX CONSEQUENCES TO HIM OR IT OF
THE SALE OF PROPERTIES AND THE LIQUIDATION OF THE PARTNERSHIP.
19
<PAGE> 230
SELECTED FINANCIAL INFORMATION AND
PROFORMA FINANCIAL STATEMENTS
For selected financial information and financial statements of the
Partnership, see the Form 10-K Annual Report for the year ended December 31,
1997 and the Form 10-Q Quarterly Report for the quarter ended March 31, 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) are contained in the Joint Proxy Statement/Prospectus
under "Unaudited Proforma Consolidated Financial Statements".
20
<PAGE> 231
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> 232
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> 233
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 1,644,430 $ 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> 234
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> 235
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> 236
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> 237
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> 238
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> 239
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> 240
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> 241
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> 242
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> 243
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> 244
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> 245
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> 246
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 JUNE ____, 1998
The undersigned hereby constitutes and appoints A. Earl Swift, Bruce H.
Vincent, Terry E. Swift or John R. Alden, as duly authorized officers of Swift
Energy Company, acting in its capacity as Managing General Partner of the
Partnership, or any of them, with full power of substitution and revocation to
each, the true and lawful attorneys and proxies of 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 June ___, 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 with all powers the undersigned would possess if personally
present at the Meeting:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
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>
THIS PROXY WILL BE VOTED IN ACCORDANCE WITH THE SPECIFICATIONS MADE
HEREON. IF NO CONTRARY SPECIFICATION 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 May ___, 1998 is acknowledged.
PLEASE SIGN AND RETURN THE PROXY IN THE ENCLOSED, POSTAGE-PAID,
PRE-ADDRESSED ENVELOPE BY JUNE ___, 1998.
SIGNATURE DATE
--------------------------------- --------------------
SIGNATURE DATE
--------------------------------- --------------------
SIGNATURE DATE
--------------------------------- --------------------
IF LIMITED PARTNERSHIP UNITS ARE HELD JOINTLY, ALL JOINT TENANTS MUST SIGN.
<PAGE> 247
SWIFT ENERGY PENSION PARTNERS 1993-B, LTD.
(THE "PARTNERSHIP")
SUPPLEMENT
TO
JOINT PROXY STATEMENT/PROSPECTUS
DATED JUNE _____, 1998
OF THE PARTNERSHIPS AND 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") formed between 1986 and 1994 to invest in producing oil and gas
properties, including the Partnership. Swift is asking Investors in the
Partnership (and the other 62 Partnerships) to approve a Proposal to ultimately
sell substantially all of the Partnership's oil and gas assets to the Managing
General Partner (the "Proposal") for $1,427,367, which is a price based upon the
higher of two fair market value estimates of those assets determined by three
independent Appraisers, plus a 7.5% premium above fair market value estimates.
If the Proposal is approved by Investors in the Partnership and its
companion Partnership, after the ultimate sale of substantially all of its
properties the Partnership will dissolve, wind up and terminate. The Partnership
will receive cash for its oil and gas assets, which the Investors in the
Partnership will be entitled to receive as net cash distributions in accordance
with their respective percentage ownership interests in the Partnership. If
Investors in the Partnership approve the Proposal, they 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 (without payment of any Broker commissions).
The effects of the adoption 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 risks, effects and fairness
of the Proposal to the Investors in the Partnership and to provide information
on the Partnership to its Investors.
<PAGE> 248
RISK FACTORS
o There is no guarantee that the fair market value estimates of the
Appraisers represent the highest possible prices that might be received
for the Partnership's 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, although
such prices likely would be offset by any additional general and
administrative costs, production costs or sales costs incurred during
the period necessary to close any such sales.
o The fair market value (excluding the 7.5% premium) at which the
Managing General Partner will purchase 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 Partnership's 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, despite the desire of Investors in the
Partnership to sell their Property Interests, this may not be
accomplishable without a similar approval of the Proposal by the
Investors in the companion Partnership. If either Partnership did 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 Partnership.
o It is likely that if the Proposal is approved by Investors and the
Partnership's Property Interests are ultimately sold to the Managing
General Partner, the Managing General Partner will further develop the
Property Interests by spending required capital on recovery of
behind-pipe reserves or developing undeveloped reserves. As such,
Investors would not directly share in any possible improvement of cash
flow from such Property Interests upon consummation of the Proposal.
However, the Managing General Partner is hereby providing an
opportunity for Investors to purchase Common Stock of the Company on a
direct basis so that they might share indirectly in any such
improvement.
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. See "Federal Income Tax Consequences of Adoption of
the Proposal--Tax Treatment of Tax Exempt Plans--Debt-Financed
Property."
o 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 Partnership. The character of the gain or loss
depends on certain factors specific
2
<PAGE> 249
to the Partnership and to the Investors. For a broader discussion of
the tax consequences, Investors should read "Federal Income Tax
Consequences of Adoption of the Proposal."
o As currently proposed, Investors that subscribe for Company stock
pursuant to this offering may 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 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 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 distribution from the
Partnership.
See "Summary--Risks" in the Joint Proxy Statement/Prospectus.
CONFLICTS OF INTEREST
A number of conflicts of interest are inherent in the relationships
among the Partnership, the Company and its directors and officers. Certain of
these conflicts of interest (to the extent not otherwise highlighted above) are
summarized 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 unaffiliated 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 such transaction.
o Benefits accruing to the Company, including the following:
o 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.
3
<PAGE> 250
o If Investors of all of the Partnerships approve the Proposals,
the Company anticipates that its total proved reserves on an
equivalent basis would increase by approximately 26% and would
increase the Company's cash flow and total assets by
approximately 25% and 19%, respectively.
The Proposal to ultimately sell substantially all of the Partnership's
Property Interests to the Managing General Partner is discussed in detail under
"The Proposal" and "Special Factors" herein. The Proposal presents a potential
conflict of interest between the Managing General Partner acting in its capacity
as managing general partner of the Partnership and its actions in its corporate
capacity as the proposed purchaser of the Partnership's Property Interests. The
Special Transactions Committee of the Board of Directors of Swift Energy Company
(the "Special Transactions Committee"), which consists solely of four of the
five outside independent directors of Swift Energy Company, approved the
selection of the three independent third party appraisers (the "Appraisers")
chosen to estimate the fair market value of the Partnership's Property
Interests. The Special Transactions Committee determined that this conflict of
interest is best addressed by asking three different Appraisers, consisting of
two independent petroleum engineering firms and one investment banking firm, to
estimate the fair market value of the Partnership's Property Interests, rather
than proposing that the Managing General Partner set such fair market value
itself and ask for an opinion on the fairness thereof from an independent third
party.
The Special Transactions Committee determined that having three
independent appraisers collectively determine the fair market value for a cash
purchase of the Partnership's Property Interests would protect Investors by
mitigating the potential conflict 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 three appraisers working
collectively provides the distinct professional expertise of each firm, and
gives the Partnership 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.
See "Summary--Conflicts of Interest" in the Joint Proxy Statement/Prospectus.
THE PROPOSAL
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 almost five years. As discussed above, 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 Proposal, without the risk
of such distributions being negatively affected by oil and gas price decreases.
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.
4
<PAGE> 251
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. 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 Partnership.
Undeveloped 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. Reduced cash flow affected the ability of the companion
Operating 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 can only occur with the investment of new capital.
As provided in the Partnership Agreement, the Partnership expended all of the
Interest Holders' 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 Operating 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 a
partnership 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 "Business of the
Partnership--No Trading Market." Following the approval of the Proposal and the
sale of the Partnership's Property Interests and dissolution of the Partnership,
Investors will realize gain or loss under federal income tax laws. Thereafter,
Investors will have no further tax reporting obligations with respect to the
Partnership. See "Federal Income Tax Consequences."
See "Summary--Background and Reasons for the Proposals; Managing General
Partner's Recommendations" in the Joint Proxy Statement/Prospectus.
FAIRNESS OF PROPOSED SALE
The Managing General Partner believes that this proposed method of sale
of the Partnership's Property Interests is fair to Investors for a variety of
reasons including, without giving weight to the order, the following:
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 based on
5
<PAGE> 252
the estimations of such value by third party independent
Appraisers. Instead of the Managing General Partner attempting
to set the Fair Market Value of the Property Interests, the
proposed price to be paid by the Managing General Partner for
the Partnership's Property Interests (not including the 7.5%
premium above Fair Market Value) was based on the valuation
estimates of three qualified independent Appraisers, two of
which are petroleum engineering firms and one of which is an
investment banking firm. Using three different firms from two
different disciplines has been designed to provide a
comprehensive analysis of valuation factors. 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 Partnership Property Interests."
2. No transaction will take place unless the Proposal is approved
by Investors holding a majority of the interests in the
Partnership, without the Managing General Partner voting any
limited partnership interests in the Partnership which it
owns, 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 Proposal is approved by Investors, it is likely that
the Managing General Partner will expend the capital necessary
to bring various nonproducing reserves into production on the
Property Interests purchased by the Managing General Partner.
If all of the Property Interests which are the subject of the
Proposal are acquired by the Company, such Property Interests
in the aggregate will constitute less than 20% of the
Company's total assets. In order to allow Investors to benefit
from any increase in value of the Property Interests realized
from the Managing General Partner's investment of capital in
such properties, the Company is hereby offering to Eligible
Purchasers the opportunity to purchase on a collective basis
up to 2,500,000 shares of Common Stock. There is no
requirement that any purchase of Swift's Common Stock be made.
See "Offer to Eligible Purchaser" below.
See "Summary--Fairness of Proposed Sale" in the Joint Proxy
Statement/Prospectus.
COLLECTIVE ANALYSIS OF PURCHASE PRICE; PREMIUM OVER FAIR MARKET VALUE
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 $80.94 million.
The valuation estimates of the Appraisers are attached to this Supplement and
incorporated herein by reference. 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. The
valuations of the Appraisers do not in any manner address the underlying
business decision to sell these Property Interests. Moreover, the
6
<PAGE> 253
valuation estimates of the Appraisers are necessarily based upon the market,
economic and other conditions as they existed on the dates specified below 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.
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 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.
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 attached to
this Supplement to the Joint Proxy Statement/Prospectus. CIBC Oppenheimer then
divided the property groups ("Property") 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 under "Regarding the
Proposals to Sell the Partnerships' Oil and Gas Assets--Independent Appraisal of
the Fair Market Value of Property Interests of the Partnerships--Valuation of
CIBC Oppenheimer" 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 $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
7
<PAGE> 254
Value of the Partnership's Property Interests. 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. Because these benefits are particular to the Company, the Company
believes that it is fair to pay a premium of 7.5% over the Fair Market Value of
the Property Interests to purchase those interests.
See "Summary--Determination of Fair Market Value of Partnerships'
Property Interests" in the Joint Proxy Statement/Prospectus.
ESTIMATES OF LIQUIDATING NET CASH DISTRIBUTION AMOUNT
Set forth in the table below are estimated net proceeds that the
Partnership may realize from sales 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 June 30, 1998, resulting in an estimate of the amount of net cash
distributions available for Investors as a result of such sales.
ESTIMATE OF NET CASH DISTRIBUTIONS
FROM PROPERTY INTEREST SALES AND LIQUIDATION
<TABLE>
<CAPTION>
<S> <C>
Appraisers' Fair Market Value of Partnership Property Interests(1) $ 1,327,783
(Gross Sales Proceeds)
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) $ (225,873)
-----------
Estimated Net Distributions to Partners(6) $ 1,569,026
===========
</TABLE>
<TABLE>
<CAPTION>
<S> <C>
Amount Distributable
to Investors(6) $1,322,964
Amount Distributable
to General Partners(6)(7) $ 246,062
----------
$1,569,026
==========
</TABLE>
<TABLE>
<CAPTION>
<S> <C>
ESTIMATED NET CASH DISTRIBUTIONS TO INVESTORS PER $1.00 SDI $ 0.21
=========
MINIMUM NUMBER OF SDIs NECESSARY TO PURCHASE 100 SHARES OF SWIFT
ENERGY COMMON STOCK WITH CASH DISTRIBUTIONS(8) 8,572
=========
</TABLE>
8
<PAGE> 255
- --------------------------
(1) Represents the higher of two values estimated 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
June 30, 1998.
(6) Gross Sales Proceeds amount is allocated 85% to the Investors and 15% to
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, then 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 $0.21 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.
ESTIMATES OF NET CASH DISTRIBUTIONS AVAILABLE FROM CONTINUED OPERATIONS
If, on the other hand, the Partnership were to retain its Property
Interests and continue to benefit from production of its oil and gas assets
until they have reached their economic limit, the table below estimates the
return to Investors, discounted to present value, based upon the year end
pricing without escalation and discount assumptions used above. The estimates of
the present value of future net cash distributions have been further reduced by
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.
9
<PAGE> 256
ESTIMATED SHARE OF INVESTORS'
NET CASH DISTRIBUTIONS FROM CONTINUED OPERATIONS
<TABLE>
<CAPTION>
PROJECTED
CASH FLOWS
-----------
<S> <C>
Estimated Future Net Revenues from Continued Operations Until $ 2,689,779
Depletion(1)
Estimated Interim Net Cash Distributions(2) $ (202,700)
Estimated Partnership Direct and Administrative Expenses(3) $ (338,912)
Net Assets(4) $ 346,260
-----------
Net Cash Distributions to Investors(5) $ 2,494,427
===========
NET CASH DISTRIBUTIONS PER $1.00 SDI $ 0.40
PRESENT VALUE OF NET CASH DISTRIBUTIONS PER $1.00 SDI(5)(6) $ 0.27
</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
"The Proposal--Reasons for the Proposal." The actual prices that will be
received and the associated costs may be more or less than those projected.
See "The Proposal--Partnership Financial Condition and Performance."
(2) Estimated net cash distributions paid to Investors from January 1, 1998 to
June 30, 1998 in order to present this information on a comparative basis
as of June 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 Investors and the General Partners in
accordance with the Partnership Agreement. The amounts finally distributed will
depend on the actual sales prices received for the Partnership assets, results
of operations until such sales and other contingencies and circumstances.
COMPARISON OF SALE VERSUS CONTINUING OPERATIONS
The Managing General Partner believes that the Proposal to sell the
Partnership's Property Interests and liquidate is fair to Investors for the
reasons discussed in detail under "Special Factors--Fairness of Proposed Sale."
10
<PAGE> 257
Based on the above tables, it is estimated that an Investor could
expect to receive $0.21 per $1.00 SDI upon immediate sale of the Partnership's
Property Interests. In comparison, it is estimated that an Investor could expect
to receive $0.27 per $1.00 SDI, discounted to present value at 10% per annum
($0.40 per $1.00 SDI on an undiscounted basis) if the Partnership continued
operations.
Although the estimates contained under "The Proposal--Estimates of
Liquidating Net Cash Distribution Amount" above show that estimated net cash
distributions to Investors (based on net present value) from continued
operations would be approximately 29% higher than estimated net cash
distributions from selling the Partnership's Property Interests and liquidating
the Partnership at this time, the Managing General Partner believes there is a
substantial advantage in receiving the liquidating net cash distribution in one
lump sum currently. The estimates of net cash distributions from continued
operations are based upon current prices. 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 subjects
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 price volatility and to 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 is the
amount calculated under the terms of the original 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 $0.03 per $1.00 SDI before June 30, 1998, which
converts to a comparable value of $0.26 per $1.00 SDI. 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
determination of fair market value. 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 adding the present value of proved
oil and gas reserves (discounted at 10% per annum) calculated on an escalated
pricing basis to cash and accounts receivable less outstanding debts and
obligations of the Partnership, and then further discounting that result by 30%.
TRANSACTIONS BETWEEN THE MANAGING GENERAL PARTNER AND THE PARTNERSHIP
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. 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
11
<PAGE> 258
basis of its ownership interest in the Partnership and for other reasons set out
under "The Proposal--Impact on the Managing General Partner."
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 to Investor 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, of which $219 has been
received during the three years ended December 31, 1997.
o The Managing General Partner receives per-well monthly
operating fees on certain producing wells in which the
Partnership owns Property Interests and for which it serves as
operator in accordance with the joint operating agreements for
each of such wells. The fees that are set in the joint
operating agreements are negotiated with the other working
interest owners of the properties.
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 $361,184 has been reimbursed
during the three years ended December 31, 1997.
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
$7,525 has been reimbursed during the three years ended
December 31, 1997.
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 $23,814 has been
received in the three years ended December 31, 1997.
12
<PAGE> 259
BUSINESS OF THE PARTNERSHIP
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. In addition to the following information about the
business of the Partnership, see the attached Annual Report on Form 10-K for the
year ended December 31, 1997.
The following tabulation 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 (See "Glossary of
Terms"). The information below 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 ($2,048,682) 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 fields in which the Partnership owns a Property
Interest, thirteen 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 average less than 3% of the Partnership's PV-10 Value at
the same date.
<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>
RESERVES
For information about 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, see the report dated
February 10, 1998 attached hereto, which was audited by H.J. Gruy and
Associates, Inc., independent petroleum consultants, and which contains both
estimates for the Partnership as a whole and those solely
13
<PAGE> 260
attributable to the interest in the Partnership of Investors. This report has
not been updated to include the effect of production since year-end 1997.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates and timing of production,
future costs and future development plans. Oil and gas reserve engineering must
be recognized as a subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact way, and estimates of other
engineers might differ from those in the attached report. 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, and, as a general rule, reserves estimates based upon
volumetric analysis are inherently less reliable than those based on lengthy
production history. Accordingly, reserve estimates are often different from the
quantities of oil and gas that are ultimately recovered.
In estimating the Partnership's interest in oil and natural gas
reserves, the Managing General Partner, in accordance with criteria prescribed
by the Securities and Exchange Commission, has used pricing based upon 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 does not believe that any favorable or adverse event causing a
significant change in the estimated quantity of proved reserves set forth in the
attached report has occurred between December 31, 1997 and the date of this
Supplement.
Future prices received for the sale of production from properties in
which the Partnership has an interest may be higher or lower than the prices
used in the Partnership's estimates of oil and gas reserves; the operating costs
relating to such production may also increase or decrease from existing levels.
NO TRADING MARKET
There is no trading market for the SDIs, and none is expected to
develop, as described above under "Comparison of Sale Versus 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. Through
December 31, 1997, the Managing General Partner has purchased 161,000 SDIs from
Investors pursuant to the right of presentment. As of June ___, 1998, there were
559 Investors (excluding the Managing General Partner). 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
other holder of SDIs that holds more than 5% of the SDIs.
14
<PAGE> 261
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.
PARTNERSHIP FINANCIAL PERFORMANCE AND CONDITION
The Partnership owns non-operating Property Interests in producing oil
and gas properties within the continental United States in which the Operating
Partnership 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.
Investors have 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 presentment right
set forth in the Partnership Agreement, it has purchased 161,000 SDIs from
Investors. From inception through January 31, 1998, the Partnership has made net
cash distributions to its Investors totaling $2,588,600. For details of the
amounts of cash distributions made to Investors, see "Item 6. Selected Financial
Data" in the attached Form 10-K Report for the year ended December 31, 1997."
Through January 31, 1998, the Managing General Partner has received net cash
distributions from the Partnership of $443,409 with respect to its general
partner interest, and $31,295 related to the number of SDIs it purchased from
Investors. On a per SDI basis, Investors had received, as of January 31, 1998,
$0.42 per $1.00 SDI, or approximately 41.5% 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 $19.70 per barrel of
oil and $2.06 per Mcf of natural gas. The majority of the Partnership's Property
Interests were acquired during the third quarter of 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. The bulk 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.
15
<PAGE> 262
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.
16
<PAGE> 263
[GRAPHS: 2 pages of oil and gas properties info]
17
<PAGE> 264
18
<PAGE> 265
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.
SUMMARY OF FEDERAL INCOME TAX CONSEQUENCES
GENERAL
The following briefly describes certain federal income tax consequences
to the Investors arising from the Partnership's proposed sale of its Property
Interests, including its net profits interest and liquidation pursuant to the
Proposal. Statements of legal conclusions herein 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"), 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 CERTAIN FEDERAL INCOME TAX CONSEQUENCES TO
INVESTORS MAY BE FOUND IN THE REGISTRATION STATEMENT IN "FEDERAL INCOME TAX
CONSEQUENCES OF ADOPTION OF THE PROPOSAL." 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.
19
<PAGE> 266
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 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.
20
<PAGE> 267
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 that the Partnerships will realize taxable loss upon the sale of
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 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 FOR GENERAL INFORMATION ONLY AND IS
INTENDED TO BE A SUMMARY OF CERTAIN INCOME TAX CONSIDERATIONS OF THE SALE OF
PROPERTIES AND LIQUIDATION. IT IS NOT INTENDED AS AN ALTERNATIVE FOR INDIVIDUAL
TAX PLANNING. EACH INVESTOR SHOULD CONSULT HIS OWN TAX ADVISOR CONCERNING THE
FEDERAL, STATE, LOCAL, FOREIGN AND OTHER TAX CONSEQUENCES TO IT OF THE SALE OF
PROPERTIES AND THE LIQUIDATION OF THE PARTNERSHIP.
21
<PAGE> 268
SELECTED FINANCIAL INFORMATION AND
PROFORMA FINANCIAL STATEMENTS
For selected financial information and financial statements of the
Partnership, see the Form 10-K Annual Report for the year ended December 31,
1997 and the Form 10-Q Quarterly Report for the quarter ended March 31, 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), in the Joint Proxy Statement/Prospectus under
"Unaudited Proforma Consolidated Financial Statements".
22
<PAGE> 269
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> 270
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> 271
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> 272
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> 273
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> 274
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> 275
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> 276
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> 277
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> 278
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> 279
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> 280
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> 281
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> 282
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> 283
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> 284
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 JUNE ____, 1998
The undersigned hereby constitutes and appoints A. Earl Swift, Bruce H.
Vincent, Terry E. Swift or John R. Alden, as duly authorized officers of Swift
Energy Company, acting in its capacity as Managing General Partner of the
Partnership, or any of them, with full power of substitution and revocation to
each, the true and lawful attorneys and proxies of 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 June ___, 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 with all powers the undersigned would possess if personally
present at the Meeting:
<TABLE>
<S> <C> <C> <C>
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>
THIS PROXY WILL BE VOTED IN ACCORDANCE WITH THE SPECIFICATIONS MADE
HEREON. IF NO CONTRARY SPECIFICATION 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 May ___, 1998 is acknowledged.
PLEASE SIGN AND RETURN THE PROXY IN THE ENCLOSED, POSTAGE-PAID,
PRE-ADDRESSED ENVELOPE BY JUNE ___, 1998.
SIGNATURE DATE
-------------------------------- ------------------------
SIGNATURE DATE
-------------------------------- ------------------------
SIGNATURE DATE
-------------------------------- ------------------------
IF INTEREST HOLDER SDIS ARE HELD JOINTLY, ALL JOINT TENANTS MUST SIGN.
<PAGE> 285
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> 286
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
EXHIBIT INDEX
<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 Opinion of Jenkens & Gilchrist, A Professional Corporation, as to the
validity of the Securities being registered hereunder
**8 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)
</TABLE>
II-2
<PAGE> 287
<TABLE>
<CAPTION>
EXHIBIT DOCUMENT DESCRIPTION
NO. --------------------
---
<S> <C>
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)
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)
</TABLE>
II-3
<PAGE> 288
<TABLE>
<CAPTION>
EXHIBIT DOCUMENT DESCRIPTION
NO. --------------------
---
<S> <C>
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)
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)
</TABLE>
II-4
<PAGE> 289
<TABLE>
<CAPTION>
EXHIBIT DOCUMENT DESCRIPTION
NO. --------------------
---
<S> <C>
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)
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)
*12 Swift Energy Company Ratio of Earnings to Fixed Charges
*12.1 Partnerships Combined Ratio of Earnings to Fixed Charges
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 C.I.B.C. Oppenheimer
*23.4 Consent of Arthur Andersen LLP
**23.5 Consent of Jenkens & Gilchrist, A Professional Corporation (included in
Exhibit 5)
**23.6 Consent of Hoops & Levy, L.L.P. (included in Exhibit 5)
***24 Power of Attorney
27 Financial Data Schedule (included in electronic filing only)
</TABLE>
II-5
<PAGE> 290
- --------------------------------
* Filed herewith
** To be filed by amendment
*** Previously filed
ITEM 22. UNDERTAKINGS.
A. 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.
B. The undersigned registrant hereby undertakes to deliver or
cause to be delivered with the prospectus, to each person to
whom the prospectus is sent or given, the latest annual report
to security holders that is incorporated by reference in the
prospectus and furnished pursuant to and meeting the
requirements of Rule 14a-3 or Rule 14c-3 under the Securities
Exchange Act of 1934; and, where interim financial information
required to be presented by Article 3 of Regulation S-X are
not set forth in the prospectus, to deliver, or cause to be
delivered to each person to whom the prospectus is sent or
given, the latest quarterly report that is specifically
incorporated by reference in the prospectus to provide such
interim financial information.
C. The undersigned registrant hereby undertakes to respond to
requests for information that is incorporated by reference
into the prospectus pursuant to Items 4, 10(b), 11, or 13 of
this Form, within one business day of receipt of such request,
and to send the incorporated documents by first class mail or
other equally prompt means. This includes information
contained in documents filed subsequent to the effective date
of the registration statement through the date of responding
to the request.
D. The undersigned registrant hereby undertakes to supply by
means of a post-effective amendment all information concerning
a transaction, and the company being acquired involved
therein, that was not the subject of and included in the
Registration Statement when it became effective.
II-6
<PAGE> 291
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
registrant has duly caused this Amendment No. 2 to Registration Statement to be
signed on its behalf by the undersigned, thereunto duly authorized, in the City
of Houston, State of Texas, on June 3, 1998.
SWIFT ENERGY COMPANY
By: /s/ A. EARL SWIFT
-----------------------------------------
A. Earl Swift,
Chairman of the Board and Chief Executive
Officer, Swift Energy Company
II-7
<PAGE> 292
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 Opinion of Jenkens & Gilchrist, A Professional Corporation, as to the
validity of the Securities being registered hereunder
**8 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)
</TABLE>
<PAGE> 293
<TABLE>
<CAPTION>
EXHIBIT DOCUMENT DESCRIPTION
NO. --------------------
---
<S> <C>
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)
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)
</TABLE>
<PAGE> 294
<TABLE>
<CAPTION>
EXHIBIT DOCUMENT DESCRIPTION
NO. --------------------
---
<S> <C>
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)
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)
</TABLE>
<PAGE> 295
<TABLE>
<CAPTION>
EXHIBIT DOCUMENT DESCRIPTION
NO. --------------------
---
<S> <C>
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)
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)
*12 Swift Energy Company Ratio of Earnings to Fixed Charges
*12.1 Partnerships Combined Ratio of Earnings to Fixed Charges
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 C.I.B.C. Oppenheimer
*23.4 Consent of Arthur Andersen LLP
**23.5 Consent of Jenkens & Gilchrist, A Professional Corporation (included in
Exhibit 5)
**23.6 Consent of Hoops & Levy, L.L.P. (included in Exhibit 5)
***24 Power of Attorney
27 Financial Data Schedule (included in electronic filing only)
</TABLE>
<PAGE> 296
- --------------------------------
* Filed herewith
** To be filed by amendment
*** Previously filed
<PAGE> 1
EXHIBIT 12
SWIFT ENERGY COMPANY
RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
HISTORICAL 3 MONTHS 3 MONTHS
ACTUAL DATA 1997 1996 1995 1994 1993 1998 1997
----------- ---------- ---------- ---------- ---------- ---------- --------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
1) Gross G&A............................ 20,098,383 18,215,744 16,603,884 16,773,066 15,655,093 5,381,397 5,046,373
2) Net G&A.............................. 6,128,615 6,385,067 5,256,184 5,197,899 5,065,323 1,643,515 1,575,154
3) Interest Expense..................... 5,032,952 693,959 1,115,361 1,795,133 597,465 1,384,766 1,349,631
4) Rent Expense......................... 1,039,210 957,797 869,191 965,389 961,280 271,888 246,831
5) Net Income Before Taxes.............. 33,129,606 28,785,783 6,894,537 4,837,829 6,628,608 4,835,502 10,161,045
6) Capitalized Interest................. 2,326,691 1,549,575 1,442,022 766,572 389,352 762,447 439,101
7) Depleted Capital Interest............ 201,169 168,375 95,496 87,588 64,454 58,403 49,058
CALCULATED DATA
- ----------------------------------------
8)=(2/1) Unallocated G&A(%)............. 30.49% 35.05% 31.66% 30.99% 32.36% 30.54% 31.21%
9)=(4X8) Non-Capital Rent Expense....... 316,887 335,731 275,154 299,170 311,029 83,036 77,045
10)=(9X.333) 1/3 Non-Capital Rent
Expense............................... 105,629 111,910 91,718 99,723 103,676 27,679 25,682
11)=(3+6+10) Fixed Charges.............. 7,465,272 2,355,444 2,649,101 2,661,428 1,090,493 2,174,892 1,814,414
12)=(3+5+7+10) Earnings................. 38,469,356 29,760,027 8,197,112 6,820,273 7,394,203 6,306,350 11,585,416
Ratio Of Earnings To Fixed Costs
(12/11)............................... 5.15 12.63 3.09 2.56 6.78 2.90 6.39
========== ========== ========== ========== ========== ========= ==========
</TABLE>
<TABLE>
<CAPTION>
100% CASE 100% CASE 50% CASE 50% CASE
ALL CASH EQUITY/CASH ALL CASH ALL EQUITY
100% CASE 100% CASE 50% CASE 50% CASE PRO FORMA PRO FORMA PRO FORMA PRO FORMA
ALL CASH EQUITY/CASH ALL CASH ALL EQUITY 3 MONTHS 3 MONTHS 3 MONTHS 3 MONTHS
PRO FORMA PRO FORMA PRO FORMA PRO FORMA PRO FORMA ENDED ENDED ENDED ENDED
ACTUAL DATA 1997 1997 1997 1997 1998 1998 1998 1998
----------- --------- ----------- --------- ---------- --------- ----------- --------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1) Gross G&A.............. 20,098,383 20,098,383 20,098,383 20,098,383 5,381,397 5,381,397 5,381,397 5,381,397
2) Net G&A................ 10,287,794 10,287,794 9,119,411 9,119,411 2,585,049 2,585,049 2,349,940 2,349,940
3) Interest Expense....... 9,799,202 6,311,702 8,179,452 5,032,952 2,576,329 1,704,454 2,171,391 1,384,766
4) Rent Expense........... 1,039,210 1,039,210 1,039,210 1,039,210 271,888 271,888 271,888 271,888
5) Net Income Before
Taxes................. 38,595,402 42,082,902 36,875,433 40,021,933 3,723,205 4,595,080 3,849,171 4,635,796
6) Capitalized Interest... 2,326,691 2,326,691 2,326,691 2,326,691 762,447 762,447 762,447 762,447
7) Depleted Capital
Interest.............. 201,169 201,169 201,169 201,169 58,403 58,403 58,403 58,403
CALCULATED DATA
- --------------------------
8)=(2/1) Unallocated G&A
(%)..................... 51.19% 51.19% 45.37% 45.37% 48.04% 48.04% 43.67% 43.67%
9)=(4X8) Non-Capital Rent
Expense................. 531,942 531,942 471,530 471,530 130,606 130,606 118,728 118,728
10)=(9X.333) 1/3
Non-Capital Rent
Expense................. 177,314 177,314 157,177 157,177 43,535 43,535 39,576 39,576
11)=(3+6+10) Fixed
Charges................. 12,303,207 8,815,707 10,663,320 7,516,820 3,382,311 2,510,436 2,973,414 2,186,789
12)=(3+5+7+10) Earnings... 48,773,087 48,773,087 45,413,231 45,413,231 6,401,472 6,401,472 6,118,541 6,118,541
Ratio Of Earnings To Fixed
Costs (12/11)........... 3.96 5.53 4.26 6.04 1.89 2.55 2.06 2.80
========== ========== ========== ========== ========= ========= ========= =========
</TABLE>
2
<PAGE> 1
EXHIBIT 12.1
PARTNERSHIPS COMBINED
RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31, YEAR ENDED DECEMBER 31,
------------------------ -------------------------------------------------------------------
1998 1997 1997 1996 1995 1994 1993
----------- ---------- ---------- ----------- ----------- ------------ -----------
<S> <C> <C> <C> <C> <C> <C> <C>
1) Interest Expense............ $ 1,891 $ 4,096 $ 21,460 $ 204,850 $ 463,260 $ 236,827 $ 329,198
2) Net Income (Loss)........... $(1,600,046) $1,888,796 $6,965,141 $11,938,017 $(8,345,952) $(14,094,423) $13,573,358
3) Fixed Charges = (1)......... $ 1,891 $ 4,096 $ 21,460 $ 204,850 $ 463,260 $ 236,827 $ 329,198
4) Earnings = (1+2)............ $(1,598,155) $1,892,892 $6,986,601 $12,142,867 $(7,882,692) $(13,857,596) $13,902,556
Ratio of earnings to fixed
charges (4/3)................ NM 462.13 325.56 59.28 NM NM 42.23
=========== ========== ========== =========== =========== ============ ===========
Fixed Charges in excess of
Earnings..................... $ 1,600,046 N/A N/A N/A $ 8,345,952 $ 14,094,423 N/A
=========== ========== ========== =========== =========== ============ ===========
</TABLE>
<PAGE> 1
EXHIBIT 23.4
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the use of our
reports included in this Registration Statement and to the incorporation by
reference in this Registration Statement of our reports dated February 10, 1998
included in the Annual Reports on Form 10-K listed below, and to all references
to our Firm included in this Registration Statement.
Swift Energy Company's Annual Report on Form 10-K for the year ended December
31, 1997;
Swift Energy Managed Pension Assets Partnership 1988-A, Ltd.'s Annual Report on
Form 10-K for the year ended December 31, 1997;
Swift Energy Income Partners 1989-B, Ltd.'s Annual Report on Form 10-K for the
year ended December 31, 1997; and
Swift Energy Pension Partners 1993-B, Ltd.'s Annual Report on Form 10-K for the
year ended December 31, 1997.
ARTHUR ANDERSEN LLP
Houston, Texas
June 2, 1998
