SWIFT ENERGY CO, S-4, 1998-04-21

SWIFT ENERGY CO
S-4, 1998-04-21
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1
As filed with the Securities and Exchange Commission on April 21, 1998.

Registration Statement No. 333-_______

================================================================================

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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

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

(Address and telephone number of Registrant's executive offices and name,
address and telephone number of agent for service)

Copies to:

DONALD W. BRODSKY
KAREN BRYANT
JENKENS & GILCHRIST,
A PROFESSIONAL CORPORATION
1100 LOUISIANA STREET, SUITE 1800
HOUSTON, TEXAS 77002

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

<TABLE>
<CAPTION>
======================================================================================================================
PROPOSED PROPOSED
TITLE OF EACH AMOUNT MAXIMUM MAXIMUM AMOUNT OF
CLASS OF SECURITIES TO BE OFFERING AGGREGATE REGISTRATION
TO BE REGISTERED REGISTERED PRICE PER SHARE OFFERING PRICE FEE
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Common Stock, $.01 par
value per share 2,500,000 $18.3125 $45,781,250.00 $13,505.47
======================================================================================================================
</TABLE>

(1) Estimated solely for the purpose of calculating the registration fee.

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.

================================================================================
<PAGE> 2

SWIFT ENERGY COMPANY
CROSS REFERENCE SHEET
PURSUANT TO REGULATION S-K ITEM 501(b)

<TABLE>
<CAPTION>
FORM S-4 ITEM NUMBER AND CAPTION LOCATION/CAPTION IN PROSPECTUS
-------------------------------- ------------------------------
<S> <C>
A. INFORMATION ABOUT THE TRANSACTION

1. Forepart of the Registration Statement and Outside Outside Front Cover Page of
Front Cover Page of Prospectus.............................. Prospectus

2. Inside Front and Outside Back Cover Pages of Inside Front and Outside Back
Prospectus.................................................. Cover Pages of Prospectus

3. Risk Factors and Ratio of Earnings to Fixed Charges Prospectus Summary; Risk
and Other Information....................................... Factors

4. Terms of the Transaction.................................... Prospectus Summary; Proxy
Statements forming part of this
S-4

5. Pro Forma Financial Information............................. Unaudited Pro Forma Con-
solidated Financial Statements

6. Material Contracts with Company being Acquired.............. Not Applicable

7. Additional Information Required for Reoffering by
Persons and Parties Deemed to be Underwriters............... Not Applicable

8. Interests of Named Experts and Counsel...................... Not Applicable

9. Disclosure of Commission Position on Indemnification
for Securities Act Liabilities.............................. Not Applicable

B. INFORMATION ABOUT THE REGISTRANT

10. Information with Respect to S-2 Registrants................. Incorporation of Certain
Information by Reference

11. Incorporation of Certain Information by Incorporation of Certain
Reference................................................... Information by Reference;
Description of Capital Stock

12. Information with Respect to S-2 or S-3 Registrants.......... Not Applicable

13. Incorporation of Certain Information by Reference........... Not Applicable
</TABLE>

i
<PAGE> 3

<TABLE>
<S> <C>
14. Information with Respect to Registrants Other Than
S-3 or S-2 Registrants...................................... Not Applicable

C. INFORMATION ABOUT THE COMPANY BEING
ACQUIRED

15. Information with Respect to S-3 Companies................... Not Applicable

16. Information with Respect to S-2 or S-3 Companies............ Not Applicable

17. Information with Respect to Companies Other Than Proxy Statements forming part of
S-3 or S-2 Companies........................................ this S-4

D. VOTING AND MANAGEMENT INFORMATION

18. Information if Proxies, Consents or Authorizations are Proxy Statements forming part of
to be Solicited............................................. this S-4

19. Information if Proxies, Consents or Authorizations are
not to be Solicited or in an Exchange Offer................. Not Applicable
</TABLE>

ii
<PAGE> 4
May __, 1998
Dear Limited Partner:

As your Managing General Partner, Swift Energy Company believes that
the time has come to dissolve and liquidate the Partnership. Enclosed is a
proxy statement and related information pertaining to a proposal for the
ultimate sale of substantially all of the 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 fair market value estimates of three independent appraisers,
consisting of two petroleum engineering firms and one investment banking firm,
plus a premium of 7.5% above Fair Market Value. In order for the sale and
liquidation to take place, Limited Partners holding at least 51% 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 sale and liquidation for a
number of reasons. See "The Proposal--Reasons for the Proposal" and
"--Recommendation of the Managing General Partner."

Swift Energy Managed Pension Assets Partnership 1988-A, Ltd. has been
in existence for almost ten years, and most of the properties underlying its
net profits interest were purchased by February 1989. Limited capital is
available for enhancement or development activities on the properties in which
the Partnership owns non-operating interests. The Partnership's interest in
proved producing reserves at December 31, 1997 was only 342,889 Mcfe. Thus,
even if oil and gas prices were unusually high, there would be limited impact
upon the Partnership's economic performance. See "The Proposal--Partnership
Financial Performance and Condition." To continue operation of the Partnership
means that Partnership direct and administrative expenses (such as costs of
audits, reserve reports, Securities and Exchange Commission filings, and tax
returns), 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 Limited Partners. 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 Limited Partners 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
make this an appropriate time for the Limited Partners to consider the sale of
the Partnership's Property Interests, which also increases the likelihood of
maximizing the value of the Partnership's assets.

If Limited Partners holding at least 51% of the Units of the
Partnership approve this proposal and the limited partners of the Partnership's
companion Operating Partnership approve a similar proposal, the sale of the
Partnership's Property Interests to the Managing General Partner will be made
by the end of the third quarter of 1998.

Included in this package are the most recent financial and other
information prepared regarding the Partnership. If you need any further
material or have questions regarding this proposal, 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 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

<PAGE> 5
THIS TRANSACTION HAS NOT BEEN APPROVED OR DISAPPROVED BY THE
SECURITIES AND EXCHANGE COMMISSION ("COMMISSION") NOR HAS THE COMMISSION PASSED
UPON THE FAIRNESS OR THE MERITS OF SUCH TRANSACTION NOR UPON THE ACCURACY OR
ADEQUACY OF THE INFORMATION CONTAINED IN THIS DOCUMENT. ANY REPRESENTATION TO
THE CONTRARY IS UNLAWFUL.

DOCUMENTS INCLUDED

The Partnership's Annual Report on Form 10-K for the year ended
December 31, 1997 is included with this Proxy Statement and incorporated herein
by reference. See "Incorporation of Certain Information By Reference and
Attachment of Such Information Hereto." Additionally, a reserve report dated
February 10, 1998, prepared as of December 31, 1997, and audited by H.J. Gruy
and Associates, Inc., is attached hereto together with the fair market value
estimates of J.R. Butler and H.J. Gruy dated April 17, 1998, and the fair
market value estimate of CIBC Oppenheimer dated April 20, 1998.

TABLE OF CONTENTS

<TABLE>
<S> <C>
SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Partnership Property Interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Proposed Sale of Partnership Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

SPECIAL FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Partnership Property Interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Vote for Liquidation and Proposed Sale of Partnership Property Interests
to the Managing General Partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Independent Appraisal of the Fair Market Value of Partnership Property Interests . . . . . . . . . . . . . . . 4
Fairness of Proposed Sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Consideration of Alternative Transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Federal Income Tax Consequences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Managing General Partner Benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

VOTING ON THE PROPOSAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Vote Required . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Proxies; Revocation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
No Appraisal or Dissenters' Rights Provided . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Solicitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Conflicts of Interest in Purchase of Property Interests by Managing General Partner . . . . . . . . . . . . 19
Timing of Sale and Price Volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Dependence on Vote of Companion Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Possible Increase in Value of Property Interests Due to Drilling Activity after the Sale . . . . . . . . . . 20
Possible Decrease in Distributions to Limited Partners Due to Interim Production . . . . . . . . . . . . . . 20

<PAGE> 6
<TABLE>
<S> <C>
Reasons for the Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Simultaneous Proposal to Companion Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Steps to Implement the Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Impact on the Managing General Partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Recommendation of the Managing General Partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

FEDERAL INCOME TAX CONSEQUENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Tax Treatment of Tax Exempt Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Taxable Gain or Loss Upon Sale of Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Liquidation of the Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Capital Gains Tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Passive Loss Limitations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

BUSINESS OF THE PARTNERSHIP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
The Managing General Partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Transactions Between the Managing General Partner and the Partnership . . . . . . . . . . . . . . . . . . . 34
No Trading Market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Principal Holders of Limited Partner Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Approvals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

INCORPORATION OF CERTAIN INFORMATION BY REFERENCE
AND ATTACHMENT OF INFORMATION HERETO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

GLOSSARY OF TERMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

OTHER BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

FORM OF PROXY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-1
</TABLE>

ii
<PAGE> 7
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 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 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 sales 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.

A record of limited partners of the Partnership has been taken as of
the close of business on April ___, 1998, and only limited partners of record
on that date will be entitled to notice of and to vote at the meeting, or any
adjournment thereof.

IF YOU DO NOT EXPECT TO BE PRESENT IN PERSON AT THE 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
May ____, 1998
<PAGE> 8
SWIFT ENERGY MANAGED PENSION ASSETS PARTNERSHIP 1988-A, LTD.
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060-9468
(281) 874-2700

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

PROXY STATEMENT

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

SUMMARY

GENERAL

This Proxy Statement is being provided by Swift Energy Company, a
Texas corporation (the "Managing General Partner" or "Swift") in its capacity
as the Managing General Partner of Swift Energy Managed Pension Assets
Partnership 1988-A, Ltd. a Texas limited partnership (the "Partnership"), to
holders of units of limited partnership interests representing an initial
investment of $100 per Unit in the Partnership (the "Units"). This Proxy
Statement and the enclosed proxy are provided for use at a special meeting of
limited partners (the "Limited Partners"), and any adjournment of such meeting
(the "Meeting") to be held at 16825 Northchase Drive, Houston, Texas, at 4:00
p.m. Central Time on June ___, 1998. The Meeting is called for the purpose of
considering and voting upon a proposal to indirectly sell substantially all of
the assets of the Partnership to the Managing General Partner and dissolve,
wind up and terminate the Partnership (the "Proposal"), in accordance with the
terms and provisions of the Partnership's Limited Partnership Agreement dated
June 2, 1988 (the "Partnership Agreement"), and the Texas Revised Limited
Partnership Act (the "Texas Act"). This Proxy Statement and the enclosed proxy
are first being mailed to Limited Partners on or about May ____, 1998.

Under the Partnership Agreement, the affirmative vote of Limited
Partners holding at least 51% of the Units then held by Limited Partners as of
the Record Date (as defined) is required for approval of the Proposal. Each
Limited Partner appearing on the Partnership's records as of April ___, 1998
(the "Record Date"), is entitled to notice of the Meeting and is entitled to
one vote for each Unit held by such Limited Partner. Under the Partnership
Agreement, the General Partners may not vote any Units owned by them for
matters such as the Proposal. VJM Corporation, a California corporation, the
Special General Partner of the Partnership, owns a 1% interest in the
Partnership as a General Partner, but owns no Units. The Managing General
Partner has owned a 9.0% general partner's interest in the Partnership since
its inception, in addition to ownership of 5.26% of all outstanding Units
resulting from its purchase of Units from Limited Partners under their right of
presentment. Therefore, the affirmative vote of holders of at least 51% of the
remaining Units is required to approve the proposed sale.

PARTNERSHIP PROPERTY INTERESTS

The Partnership's assets (the "Property Interests") consist of a net
profits interest that covers multiple working interests. The working interest
in the producing oil and gas properties in which the Partnership owns Property
Interests is held by an affiliated companion partnership, Swift Energy Income
Partners 1988-B, Ltd. (the "Operating Partnership"). The most significant
fields in which the Partnership owns a non-operating interest are summarized
under "Special Factors--Partnership Property Interests" below. During 1997,
approximately 91% of the Partnership's revenue was attributable to natural gas
production.
<PAGE> 9
If the Proposal is approved by Limited Partners, and if a similar
proposal to the limited partners of the Operating Partnership is approved, then
it is anticipated that the Partnership will convey its net profits interest to
the Operating Partnership for cash, and then the underlying properties would be
sold to the Managing General Partner by the Operating Partnership. If
approved, it is anticipated that the sale of the Partnership's Property
Interest will be made by the end of the third quarter of 1998. The sale of
Partnership Property Interests will cause the Partnership to dissolve
automatically under the terms of the Partnership Agreement and the Texas Act
and its affairs would then be wound up and the Partnership terminated.
Currently there are no third party buyers for the Property Interests.

For more information about the Partnership's Property Interests and
recent financial performance, see the attached Annual Report on Form 10-K for
the year ended December 31, 1997.

PROPOSED SALE OF PARTNERSHIP PROPERTIES

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 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, has been
asked to approve the selection of the three independent third party appraisers
(the "Appraisers") chosen to estimate the fair market value of the
Partnership's Property Interests, which is the price, plus a premium of 7.5%
above such fair market value, at which such Property Interests would be sold.
The Special Transactions Committee has 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 methodology used by the Appraisers in estimating the fair market
value is discussed below under "Special Factors--Independent Appraisal of the
Fair Market Value of Partnership Property Interests." The Managing General
Partner believes that using this methodology to estimate the fair market value
at which the Property Interests will be purchased from the Partnership is fair
to Limited Partners, as discussed in detail under "Special Factors--Fairness of
Proposed Sale." Also discussed under "The Proposal--Reasons for the Proposal"
are the reasons for proposing the sale of such Property Interests and
liquidation of the Partnership at this time. A discussion of the alternatives
to such sale and liquidation which were considered is contained under "Special
Factors--Consideration of Alternative Transaction." In addition to the
foregoing, there are certain risks involved in the Proposal. See "Risk
Factors."

In order to allow Limited Partners 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 Managing General Partner will
offer to the Limited Partners and limited partners or interest holders of other
partnerships which approve similar proposals the opportunity to purchase on a
collective basis up to 2.5 million shares of common stock of Swift Energy
Company directly from Swift Energy Company. Such shares of common stock will
be offered at a price based upon the then current market price for Swift common
stock on the New York Stock Exchange once the voting is completed by all of the
investors in multiple partnerships managed by the Managing General Partner.
Limited Partners will have the discretion to choose the amount, if any, of
Swift common stock they desire to purchase, provided that they purchase at
least 100 shares.

2
<PAGE> 10
SPECIAL FACTORS

PARTNERSHIP PROPERTY INTERESTS

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 operator, 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.

<TABLE>
<CAPTION>
North 10
Ulrich Grapeland Reydon Tuttle Other
Field Field Field Field Fields
-------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Harris Houston Roger Canadian AR(1)
County and State County, County, Mills County, LA(1)
Texas Texas County, OK MS(1)
OK OK(5)
TX(2)

Number of Wells 5 6 1 3 185

Marquee Fair Oil Apache Apache Swift and
Corp.; 11 others
Operator(s) Columbus
Energy

% of 12/31/97 PV-10 Value 21% 21% 19% 11% 28%

% of 1997 Production (Volumes) 20% 21% 20% 7% 32%
</TABLE>

VOTE FOR LIQUIDATION AND PROPOSED SALE OF PARTNERSHIP PROPERTY INTERESTS TO THE
MANAGING GENERAL PARTNER

If approved by Limited Partners holding at least 51% of the Units, and
assuming approval by the Partnership's companion Operating Partnership of the
sale of substantially all of that partnership's assets, the Proposal described
above to sell substantially all of the Partnership's assets and subsequently to
dissolve and terminate the Partnership ultimately will result in the sale to
the Managing General Partner of the Partnership's Property Interests for
$373,244, which is comprised of the Fair Market Value plus the 7.5% premium
above such value. This sale of the Partnership's Property Interests is being
proposed for Limited Partner approval in an attempt to realize the highest
value for the Partnership's Property Interests.

The reasons for proposing the sale of the Partnership's Property
Interests at this time are described in detail under "The Proposal--Reasons for
the Proposal." These reasons include: (i) the steadily declining levels of
cash flow from the Partnership's Property Interests due to the inherent decline
in hydrocarbons

3
<PAGE> 11
produced over time and is additionally compounded by the absence of any further
capital expenditures on the properties underlying the Partnership's net profits
interest, which in turn has led to very small cash distributions to Limited
Partners in recent periods, and (ii) the continuation of fairly steady levels
of certain fixed oil field overhead and operating costs ($9,090 in 1997),
without regard to the level of production, and continued direct costs (audits,
reserve reports, Securities and Exchange Commission filings, and tax returns)
incurred each year ($18,591 in 1997).

As of December 31, 1997, approximately 83% of the estimated ultimate
recoverable reserves in which the Partnership has an interest had been
produced, with only 519,529 Mcfe of proved reserves remaining at that date. A
third (33%) of the remaining recoverable reserves 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 existing
producing zone. 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
Partnership 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.

Because of steadily declining levels of production, the Managing
General Partner believes that the Partnership's asset base and future net
revenues no longer justify the continuation of the Partnership's operations.
The Partnership has been in existence for almost ten years. The Managing
General Partner believes that improvements over the last several years in the
level of natural gas prices make this an appropriate time to consider the sale
of the Partnership's Property Interests, which also increases the likelihood of
maximizing the value of the Partnership's assets. By selling its Property
Interests and liquidating the Partnerships, future overhead and direct costs
will be avoided and the receipt of the value of the Partnership's reserves
accelerated so that such funds are received at one time.

INDEPENDENT APPRAISAL OF THE FAIR MARKET VALUE OF PARTNERSHIP PROPERTY
INTERESTS

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 the Partnership. 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 Partnership's Property Interests would protect Limited Partners
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.

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<PAGE> 12
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 Partnership's Property Interests.

The Managing General Partner did not instruct the Appraisers as to
pricing, cost or other economic parameters or methods or the assessment of
reserves characteristics, nor did it limit the scope of their investigation for
purposes of preparing their appraisals. The Managing General Partner provided
the Petroleum Engineering Consultants with basic evaluation data for their use
in determining Partnership 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 Partnership for its Property Interests nor provide any information to the
Appraisers on amounts to be paid to the Limited Partners. 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 Limited Partners, and the Managing General Partner has not acquired a
separate report or opinion regarding the fairness to the Limited Partners of
the price at which the Partnership's Property Interests will be sold to the
Managing General Partner if the Proposal is approved by the Limited Partners.

QUALIFICATIONS OF APPRAISERS

H.J. Gruy and Associates, Inc. is an established independent
petroleum engineering firm in Houston, Texas. H.J. 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. H.J. Gruy has extensive
experience evaluating properties in all of the areas in which the Partnership
owns Property Interests. H.J. 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 Corp., 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

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<PAGE> 13
oil and gas businesses and their securities in connection with mergers and
acquisitions, negotiated underwritings, private placements and other corporate
purposes.

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 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. The valuation estimates of the Appraisers
are attached to this Proxy Statement 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 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 Property Interests. As a
result of their individual and collective work, the Petroleum Engineering
Consultants estimated a fair market valuation for each property in which the
Partnership has a Property Interest, and CIBC Oppenheimer estimated a fair
market valuation for each such property. After presentation of the two
valuation estimates to the Special Transactions Committee, the committee
determined that the Fair Market Value of any given Property Interest was the
higher of the two values estimated by the Petroleum Engineering Consultants
and CIBC Oppenheimer. This necessarily matches the definition of "Fair Market
Value," which is the maximum price that a willing buyer will pay and at which a
willing seller will sell at a given point in time at which the buyer is under
no compulsion to buy and the seller is not compelled to sell, both having
reasonable knowledge of all the material circumstances.

VALUATION BY PETROLEUM ENGINEERING CONSULTANTS

The value estimate from the Petroleum Engineering Consultants uses the
"income approach." The income approach for proved producing properties reduces
the discounted future net cash flows before federal income tax to a fair market
value by multiplying such cash flow by a suitable fraction that accounts for
the risk associated with the purchase of that cash flow stream. For proved
developed non-producing and proved undeveloped reserves, the risk adjustments
are generally more severe for a variety of reasons, including the necessity of
making a capital investment when it is assumed that the capital is invested
with certainty and the resulting operating cash income stream is burdened with
the uncertainty.

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<PAGE> 14
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 Congress(es).

Basic evaluation data used by the Petroleum Engineering Consultants,
including 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:

o Reviewing technical and economic data presented by the
Managing General Partner relative to the Partnership's proved,
probable and possible reserves as of December 31, 1997.

o Examining the Partnership's cash flow forecasts for its
quantified probable and possible reserves.

o Reviewing the Partnership's lease operating costs for
reasonableness.

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<PAGE> 15
o Preparing reserves and future performance estimates for the
audit evaluation 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. 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 the Partnership's Property
Interests, CIBC Oppenheimer first reviewed the PV-10 Value at December 31, 1997
for each property to be purchased in which the Partnership has a Property
Interest (a "Field"). In addition, CIBC Oppenheimer reviewed the valuation
estimates prepared by the Petroleum Engineering Consultants for each Field.
Individual partnerships own Property Interests in a number of different Fields.
Therefore, CIBC Oppenheimer first focused upon valuing the individual Fields
and then subsequently valuing the Property Interests of each Partnership in
various Fields by allocating to each Partnership its relevant share of the
value attributable to different Fields in which it has a property interest.

Working with the Petroleum Engineering Consultants, CIBC Oppenheimer
reviewed the Fields for characteristics which would allow them to be divided
into separate classifications. Of the total of 44 Fields, the reserves of 34
Fields were determined to be comprised primarily of Proved Developed Producing
reserves ("PDP") which have comparable reserve characteristics ("Conventional
Case"). The remaining 10 Fields were determined to have distinguishing or
unique reserve 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 Fields 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 equivalents
on a revenue interest basis ("BOE") (See "Glossary of Terms"); and value as a
multiple of projected earnings before interest, taxes and depreciation,
depletion and amortization ("EBITDA") for 1998.

The Valuation Multiples were, in turn, developed from the application
of multiple quantitative and qualitative factors. The quantitative factors
include a review of relevant valuation criteria from comparable acquisitions of
both oil and gas properties and companies which are predominantly active in the
oil and gas industry, and a review of valuation criteria for relevant publicly
traded oil and gas companies (the "Analysis Factors").

The Valuation Multiples determined for the Fields in the Conventional
Case group and the Non-Conventional Case group were unique, reflecting the
different reserve 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.

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<PAGE> 16
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 Field.
Each Partnership was allotted its respective proportionate share of individual
Fields ("Field Share") based upon the Partnership's Property Interest in such
Field in order to convert the value determined for the Fields into values for
an individual Partnership's Property Interests in each Field. The CIBC
Oppenheimer valuation estimate for each individual Partnership is the
cumulative total of that Partnership's respective Field 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 Partnership owns Property
Interests and included the following: Comstock Resources and Black Stone Oil;
National Energy and Alexander Energy; Alliance Resources and LaTex Resources;
Melrose Petroleum Group and Pentex Energy; PANACO and Goldking Companies;
Alexander Energy and American Natural Resources; Gothic Energy and Buttonwood
Energy; Key Production and Brock Exploration; ONEOK and PSEC; and ONEOK and
Washita Production. These selected transactions are not intended to represent
the complete list of oil and gas transactions which have occurred or been
announced during this period; rather, such transactions represent recent
transactions involving publicly traded oil and gas companies engaged in oil and
gas exploration and production activities that were deemed by CIBC Oppenheimer
to operate in comparable producing basins or have comparable financial and
operating characteristics to the Managing General Partner.

No company or transaction described above was directly comparable to
the Partnerships, their reserves, the Managing General Partner or the proposed
transaction. Accordingly, analysis of the results of the foregoing was not
simply mathematical or necessarily precise; rather, it involved complex
considerations and judgments concerning differences in financial and operating
characteristics of companies and other factors that could affect public trading
values.

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<PAGE> 17
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 Partnership's 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 Fields 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 Field'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 Fields 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 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 Fields
are near the end of their economic lives. The degree of this discount was
reduced, however, by the fact that the Fields 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.

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<PAGE> 18
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 Fields 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 Fields, 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 LETTER OF CIBC OPPENHEIMER

The Special Transactions Committee retained CIBC Oppenheimer to
prepare 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 a letter (the
"Valuation Letter") stating that, as of such 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 was $347,204.

The full text of the Valuation Letter, which sets forth the
assumptions made, matters considered, and qualifications and limitations on the
review undertaken by CIBC Oppenheimer, is attached hereto and is incorporated
herein by reference. The summary of the Valuation Letter set forth in this
Proxy Statement is qualified in its entirety by reference to the full text of
such letter. Limited Partners of the Partnership are urged to read such letter
in its entirety. The Valuation Letter was provided to the Special Transactions
Committee for its information and is directed only to the estimate, from a
financial point of view, of the value of the Partnership's Property Interests
and does not address the merits of the underlying decision by the Managing
General Partner or the Partnership to engage in the sale of the Property
Interests to the Managing General Partner and does not constitute a
recommendation to the Partnership's Limited Partners as to how such Limited
Partners should vote on the approval of the Proposal or any matter related
thereto.

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<PAGE> 19
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 Fields of Property Interests owned by all of 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 Fields. 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 the Partnership's Property Interests was $342,030 on December 31, 1997.
CIBC Oppenheimer's evaluation of the Partnership's Property Interests began
with the PV-10 Value of each Field, as calculated by the Petroleum Engineering
Consultants. CIBC Oppenheimer then divided the Fields into two categories.
Those fields with reserves consisting primarily of proved developed producing
reserves were placed in the "Conventional Case" category. Those Fields with
significant proved developed non-producing or undeveloped reserves were placed
in the "Non-Conventional Case" category. CIBC Oppenheimer then valued each
Field by applying the multiples discussed above to each Field's PV-10 Value,
proved reserves on a BOE basis, and projected 1998 EBIDTA. A separate set of
multiples was used for Fields in the Conventional Case category and the
Non-Conventional Case category, respectively. This provided CIBC Oppenheimer
with three estimated values for each Field. The average of these three values
yielded CIBC Oppenheimer's estimation of the fair market value of each Field.
CIBC Oppenheimer then allocated the appropriate portion of the Field's estimated
fair market value to the Partnership based upon the Partnership's Property
Interest in each Field. The result of this analysis by CIBC Oppenheimer was an
estimation that 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 Swift
Energy 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 Swift 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 Swift, Swift 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.

PRIOR RELATIONSHIPS BETWEEN THE APPRAISERS, THE PARTNERSHIP AND THE MANAGING
GENERAL PARTNER

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<PAGE> 20
owned by seven limited partnerships (not including the Partnership) 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 the Partnership. 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 Partnership, and the Appraisers' compensation is not contingent upon the
results of their fair market value opinions resulting from their review of the
Partnership 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 Partnership's Property Interests is fair to Limited Partners 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 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 ultimately proposed to be paid by the
Managing General Partner for the Partnership's Property
Interest(s) (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 Limited Partners holding at least 51% of the Units, without
the Managing General Partner voting any limited partnership
interests in the Partnership which it owns.

3. The Special Transactions Committee has made the determination
as to the retention of the Appraisers and approved the fair
market value estimates provided by the Appraisers, which the
Special Transactions Committee then recommended for adoption
by the Board of Directors of the Managing General Partner.
The Special Transactions Committee is comprised solely of
independent directors of the Managing General Partner.

13
<PAGE> 21
4. If the Proposal is approved by Limited Partners and the
Property Interests ultimately are purchased by the Managing
General Partner, it is likely that the Managing General
Partner will expend the capital necessary to bring various
nonproducing reserves into production.

In order to allow Limited Partners 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 Managing General Partner will
offer to limited partners or interest holders of partnerships which approve
similar proposals the opportunity to purchase on a collective basis up to 2.5
million shares of common stock of Swift Energy Company directly from Swift
Energy Company. Such shares of common stock will be offered at a price based
upon the then current market price for Swift common stock on the New York Stock
Exchange once the voting is completed by all of the investors in multiple
partnerships managed by the Managing General Partner. Limited Partners will
have the discretion to choose the amount, if any, of Swift common stock they
desire to purchase, provided that they purchase at least 100 shares. There is
no requirement that any such purchase of Swift's common stock be made, and any
such offer is made solely by means of a separate prospectus of Swift Energy
Company included with this proxy statement.

CONSIDERATION OF ALTERNATIVE TRANSACTIONS

The Managing General Partner has given consideration to a number of
different alternatives prior to submitting the Proposal to Limited Partners for
their approval. These alternatives included continued operation of the
properties for a longer period, offering the Partnership's 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 Partnership.( 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 Partnership's 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 interests in the same properties owned by all 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
Partnership owns an interest would remain operated by the
Managing General Partner because it controls other interests
in fields

14
<PAGE> 22
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 Approximately 34% of the proved reserves value attributed to
the Partnership's Property Interests represents 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
Partnership to offer substantially all of its properties and assets to third
parties.

NEGOTIATED SALE

Many of the same factors discussed above affect whether the
Partnership would benefit from attempting to sell its Property Interests in
negotiated transactions.

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 Partnership's interests therein over several years.

o Lastly, sale of properties on a direct basis often involves
substantial periods of time for due diligence, negotiation and
execution of agreements and closings, often with different
purchases for different properties, in addition to the
necessity of taking large amounts of time to create and
supervise data rooms or disseminate data to possible
purchasers, plus the time needed to deal directly with
multiple prospective purchasers. Furthermore, certain issues,
such as environmental and title matters, may come to light in
the late stages of a negotiated sale, which may delay or
preclude the consummation of the sale.

The proposed sale of the Partnership's 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 Partnership's Property Interests will be funded from the
Managing General Partner's working capital and cash flow.

15
<PAGE> 23
Neither the Managing General Partner nor a majority of its independent
directors retained an unaffiliated representative to act on behalf of the
Partnership's Limited Partners 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 consequences of the
sale of substantially all of the Partnership's Property Interests and its
liquidation; see "Federal Income Tax Consequences" herein.

MANAGING GENERAL PARTNER BENEFITS

The Managing General Partner will share the benefits available to
Limited Partners through liquidating its partnership interests and receiving
the current value of those interests as a result of such sales. Additionally,
by purchasing the Partnership's Property Interests itself, the Managing General
Partner will continue to serve as operator of many of the properties in which
the Partnership owns an interest and will continue to receive operating fees.
The sale of the Partnership's Property Interests to the Managing General
Partner will have no effect or an inconsequential effect on the Managing
General Partner's net book value and net earnings. Simultaneously with the
proposal to the Limited Partners of the Partnership, the Managing General
Partner is making a similar proposal to investors in a number of other limited
partnerships organized for the same purposes between the years 1986 and 1994.
If the investors in all of these partnerships were to approve the proposal 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 the total proved reserves on an 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 PROPOSAL INVOLVES CERTAIN RISKS. SEE "RISK FACTORS."

o There is no guarantee that the fair market value estimates of the
independent Appraisers represents the highest possible price that
might be received for the Partnership's Property Interests in all
circumstances. This price 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 would purchase the Partnership's Property
Interests has been 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 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
Limited Partners 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 most
of its oil and gas reserves.

o It is likely that if the Proposal is approved by Limited Partners and
the Partnership's Property Interests are transferred to the Managing
General Partner, the Managing General Partner will further develop
those properties by spending required capital on recovery of
behind-pipe reserves or developing undeveloped reserves. Limited
Partners will not share in any possible improvement of cash flow from
such properties. The Managing General Partner will provide an
opportunity for Limited Partners to

16
<PAGE> 24
purchase stock of Swift Energy Company on a direct basis so that they
might share in any such improvement.

If the Proposal is not approved by Limited Partners holding 51% or
more of the Units then held by Limited Partners and a similar proposal is not
also approved by the required vote of the limited partners or interest holders
of the Partnership's companion Operating Partnership, the Partnership will
continue to exist.

LIMITED PARTNERS ARE URGED TO COMPLETE, SIGN AND DATE THE ENCLOSED
PROXY AND TO RETURN IT TO THE MANAGING GENERAL PARTNER NO LATER
THAN JUNE _____, 1998.

17
<PAGE> 25
VOTING ON THE PROPOSAL

VOTE REQUIRED

According to the terms of the Partnership Agreement, approval of the
Proposal requires the affirmative vote by the holders of at least 51% of the
Units held by Limited Partners. Therefore, an abstention by a Limited Partner
will have the same effect as a vote against the Proposal. This solicitation is
being made for votes in favor of the Proposal (which will result in liquidation
and dissolution). As of the Record Date, 45,180.63 Units were outstanding and
were held of record by 411 Limited Partners (excluding the Managing General
Partner's Units). Each Limited Partner is entitled to one vote for each Unit
held in its name on the Record Date. Accordingly, the affirmative vote of
holders of at least 23,042.12 Units is required to approve the Proposal. The
Managing General Partner holds 2,523 Units, but, in accordance with the
Partnership Agreement, the Managing General Partner may not vote its Units.
The Managing General Partner's non-vote, in contrast to abstention by Limited
Partners, will not affect the outcome, because for purposes of adopting the
Proposal 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 included in this Proxy Statement.
The actual proxy to be used to register your vote on the Proposal is the
separate green sheet of paper included with the Proxy Statement. PLEASE USE
THE GREEN PROXY TO VOTE UPON THE PROPOSAL.

If a proxy is properly signed and is not revoked by a Limited Partner,
the Units it represents will be voted in accordance with the instructions of
the Limited Partner. If no specific instructions are given, the Units will be
voted FOR the Proposal. A Limited Partner may revoke his proxy at any time
before it is voted at the Meeting. Any Limited Partner who attends the Meeting
and wishes to vote in person may revoke his proxy at that time. Otherwise, a
Limited Partner 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 proposal to sell substantially all of the
Partnership's assets and liquidate the Partnership, Limited Partners are not
entitled to any dissenters' or appraisal rights such as would be available to
shareholders in a corporation engaging in a merger. Dissenting Limited
Partners are protected under state law by virtue of the fiduciary duty of
general partners to act with prudence in the business affairs of the
Partnership.

SOLICITATION

The solicitation is being made by the Partnership. The Partnership
will bear the costs of the preparation of this Proxy Statement and of the
solicitation of proxies and such costs will be allocated 90% to the Limited
Partners and 10% to the General Partners with respect to their general
partnership interests pursuant to Article VIII.A(iv) of the Partnership
Agreement. As the Managing General Partner holds approximately 5.26% of the
Units held by all Limited Partners, 5.26% of the costs borne by the Limited
Partners 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

18
<PAGE> 26
temporary employees of the Managing General Partner may, if necessary to ensure
the presence of a quorum, solicit proxies in person or by telephone. The
Managing General Partner also may retain a proxy solicitor to assist in
contacting brokers or Limited Partners to encourage the return of proxies,
although it does not anticipate doing so. The expenses associated with the
sale of the Partnership's Property Interests are expected to be approximately
3% of the Fair Market Value of the Partnership's 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.

RISK FACTORS

A Limited Partner considering whether to vote in favor of the Proposal
should give careful consideration to the risks involved, including those
summarized below:

CONFLICTS OF INTEREST IN PURCHASE OF PROPERTY INTERESTS BY MANAGING GENERAL
PARTNER

If the Proposal is approved by Limited Partners, the Partnership's
Property Interests ultimately would be sold to the Managing General Partner at
the Fair Market Value plus a 7.5% premium, which has been set by the Special
Transactions Committee based on the valuation estimates of the Appraisers.
There is no guarantee that this purchase price represents the highest possible
price that might be received for the Partnership's Property Interest 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 the 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 (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 transactions for the
Partnership's Property Interests, depending upon future prices for either or
both of oil and gas.

DEPENDENCE ON VOTE OF COMPANION PARTNERSHIP

If the Partnership's companion Operating Partnership does not approve
a similar 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 the
Proposal is approved by Limited Partners, 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 Operating Partnership."
Although the Managing General Partner will attempt to provide a different
approach for sale of the Partnerships' Property Interests, it is possible that
the Partnership's assets may not be sold. If the Proposal is approved by the
Partnership and the Operating Partnership, the entire Property Interests owned
by the Partnership will be sold.

19
<PAGE> 27
POSSIBLE INCREASE IN VALUE OF PROPERTY INTERESTS DUE TO DRILLING ACTIVITY AFTER
THE SALE

If the Proposal to sell the Partnership's Property Interests is
approved by Limited Partners 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
Partnership's 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 Partnership owns Property Interests could
increase the values of such Property Interests. The Partnership 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 Partnership was 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 Managing General Partner intends to
offer common stock in Swift Energy Company for sale directly to limited
partners or interest holders of partnerships which approve the proposal as a
method of sharing in any gains which might be realized due to such activity.

POSSIBLE DECREASE IN DISTRIBUTIONS TO LIMITED PARTNERS DUE TO INTERIM
PRODUCTION

The amounts available for distribution to Limited Partners if the
Proposal is approved are estimated under "The Proposal--Estimates of
Liquidating Distribution Amount." The amounts estimated thereon have been
reduced by estimated cash distributions to Limited Partners 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.

THE PROPOSAL

GENERAL

The Managing General Partner has proposed that the Partnership's
Property Interests be sold, the Partnership be dissolved and that the Managing
General Partner, acting as liquidator, wind up the Partnership's affairs and
make final distributions to its partners. The Partnership's assets consist of
a net profits interest in producing oil and gas properties in which the working
interest is owned by an affiliated partnership also managed by the Managing
General Partner and formed at approximately the same time as the Partnership
was organized. The Partnership's non-operating net profits interest exists by
virtue of a Net Profits and Overriding Royalty Interest Agreement ("NP/OR
Agreement") dated July 1, 1988 with Swift Energy Income Partners 1988-B, Ltd.
(the "Operating Partnership"). The NP/OR Agreement gives the Partnership a net
profits interest in a group of producing properties in which the Operating
Partnership owns the working interests, and entitles the Partnership to receive
a portion of the net profits from operation of the group of producing
properties owned by the Operating Partnership which are subject to the NP/OR
Agreement. The net profits percentage to which the Partnership is entitled is
based upon a percentage of the gross proceeds (reduced by certain costs) from
the sale of oil and gas production from these properties.

Pursuant to the terms of the Partnership Agreement, the Partnership,
if not terminated earlier, will continue in being through January 1, 2021, at
which point it will terminate automatically.

The Managing General Partner is an independent oil and gas company
engaged in the exploration, development, acquisition and operation of oil and
gas properties, both directly and through partnership arrangements, and
therefore holds various interests in numerous oil and gas properties.
Furthermore, the Managing General Partner is the managing general partner of a
number of oil and gas partnerships.

20
<PAGE> 28
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 a Property Interest 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.

The Limited Partners have made contributions of $4,770,363, in the
aggregate to the Partnership. The Managing General Partner has made capital
contributions with respect to its general partnership interest of $38,125.
Additionally, pursuant to the presentment right set forth in the Partnership
Agreement, it has purchased 2,523 Units from Limited Partners. From inception
through January 31, 1998, the Partnership has made cash distributions to its
Limited Partners totaling $2,728,500. Through January 31, 1998, the Managing
General Partner has received cash distributions from the Partnership of
$255,406 with respect to its general partnership interest, and $16,188 related
to its limited partnership interests. On a per Unit basis, Limited Partners
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 1989-1993 during which
time the Partnership's oil prices in fact averaged $18.79 per barrel but natural
gas prices 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 oil and 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.

21
<PAGE> 29
[GRAPH: 1 page of gas properties info]

22
<PAGE> 30
Lower prices 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.

ESTIMATES OF LIQUIDATING 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 cash distributions from January 1, 1998
until June 30, 1998, resulting in an estimate of the amount of net
distributions available for Limited Partners as a result of such sales.

ESTIMATE OF LIMITED PARTNERS' SHARE OF DISTRIBUTIONS
FROM PROPERTY INTEREST SALES AND LIQUIDATION

<TABLE>
<S> <C>
Appraisers' Fair Market Value of Partnership Property Interests(1) $ 347,204
(Gross Sales Proceeds) =================

Limited Partners' Share of Sales Proceeds(2) $ 312,484
-----------------

Purchase Premium (7.5% of Fair Market Value)(3) $ 23,436
-----------------
Estimated Selling and Dissolution Expenses(4) $ (9,375)
(3% of the Fair Market Value) -----------------

Net Assets(5) $ 73,736
-----------------
Estimated Interim Cash Distributions(6) $ (50,100)
-----------------

Estimated Net Distributions to Limited Partners $ 350,181
=================

ESTIMATED NET DISTRIBUTIONS PER $100 UNIT $ 7.34
=================
</TABLE>

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

(1) Represents the higher of two values estimated by the Appraisers.

(2) Gross Sales Proceeds amount is allocated 90% to the Limited Partners
pursuant to the Limited Partnership Agreement.

(3) As determined by the Special Transactions Committee.

23
<PAGE> 31
(4) Includes Limited Partners' share of all costs associated with
dissolution and liquidation of the Partnership.

(5) Includes cash and net receivables of the Partnership as of December
31, 1997.

(6) Estimated cash distributions paid to the Limited partners from January
1, 1998 to June 30, 1998.

If, on the other hand, the Partnership were to retain its Property
Interest and continue to benefit from production of its assets until they have
reached their economic limit, the table below estimates the return to Limited
Partners, 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 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 Operating 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 LIMITED PARTNERS'
NET DISTRIBUTIONS FROM CONTINUED OPERATIONS

<TABLE>
<CAPTION>
PROJECTED
CASH FLOWS
----------
<S> <C>
Estimated Future Net Revenues from Net Profits Interest(1) $ 811,554

Estimated Interim Cash Distributions(2) $ (50,100)

Estimated Partnership Direct and Administrative Expenses(3) $ (121,733)

Net Assets(4) $ 73,736
---------------------
Net Distributions to Limited Partners(5) $ 713,457
=====================

NET DISTRIBUTIONS PER $100 UNIT $ 14.96

PRESENT VALUE OF NET DISTRIBUTIONS PER $100 UNIT(6) $ 8.25
</TABLE>

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

(1) Limited Partners' future net revenues are based on the reserve
estimates at December 31, 1997 using the pricing based upon 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 cash distributions paid to the Limited Partners from January
1, 1998 to June 30, 1998.

(3) Includes Limited Partners' share of general and administrative
expenses, and audit, tax, and reserve engineering fees.

24
<PAGE> 32
(4) Includes 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 distribution,
are to be distributed to the Limited Partners 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 Limited Partners for
the reasons discussed in detail under "Special Factors--Fairness of Proposed
Sale."

Based on the above tables, it is estimated that a Limited Partner
could expect to receive $7.34 per $100 Unit upon immediate sale of the
Partnership Property Interests. In comparison, it is estimated that a Limited
Partner 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 Distribution Amount" above show that estimated cash distributions
to Limited Partners (based on net present value) from continued operations
would be approximately 12% higher than estimated 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 distribution in one lump sum currently.
The estimates of 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 subject Limited Partners to the risk
of receiving lower levels of cash distributions if oil and gas prices over this
period are lower on average than those used in preparing the estimates of cash
distributions from continued operations. Continued operations also subject
Limited Partners' potential 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 Limited Partners taking any funds to be received upon liquidation
and redeploying those assets in other investments, rather than continuing to
receive decreasing levels of 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 Partnership
Agreement at which the Managing General Partner can offer to repurchase Units
from Limited Partners. As of January 1, 1997, this "Unit Value" was $10.66 per
$100 Unit. In 1997, the Limited Partners received cash 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 price 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 Limited Partners the Unit Value, and
the Limited Partners have the right to present their Units for purchase by the
Managing General Partner for the Unit Value. The Unit Value amount is
determined by adding the present value of proved oil and gas reserves
(discounted at 10% per annum) calculated on an escalated pricing basis to cash

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<PAGE> 33
and accounts receivable less outstanding debts and obligations of the
Partnership, and then further discounted that result by 30%.

REASONS FOR THE PROPOSAL

The Managing General Partner believes that it is in the best interest
of the Limited Partners 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 oil and gas prices, particularly those for
natural gas, make this an appropriate time to consider the sale of the
Partnership's Property Interests, and increases the likelihood of maximizing
the value of the Partnership's assets, although the future prices and market
volatility cannot be predicted with any accuracy.

Decreasing Cash Flow While Expenses Continue. As of December 31,
1997, approximately 83% of the Partnership's ultimate recoverable reserves had
been produced, and the Limited Partners' 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 the partners 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 8 to
10 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
partners' net commitments for the acquisition of Property

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<PAGE> 34
Interests many years ago, and it no longer has capital to invest in improvement
of the properties through secondary or tertiary recovery. 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 Limited Partner 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 Limited Partners 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, Limited Partners will realize gain or loss, or
a combination of both, under federal income tax laws. Thereafter, Limited
Partners will have no further tax reporting obligations with respect to the
Partnership. The dissolution of the Partnership will also allow Limited
Partners to take a capital loss deduction for syndication costs incurred in
connection with formation of the Partnership. See "Federal Income Tax
Consequences."

SIMULTANEOUS PROPOSAL TO COMPANION PARTNERSHIP

Simultaneously with the Proposal to Limited Partners to ultimately
sell all of the Partnership's Property Interests, a similar proposal is being
made to the limited partners of the companion Operating Partnership which owns
the working interest in the same properties in which the Partnership owns a
non-operating interest. If the Partnership approves the Proposal, but its
companion partnership does not approve a similar proposal to sell its Property
Interests and liquidate, it is likely to affect the ability of the Partnership
to consummate the sale of its Property Interests. Although the Partnership's
Limited Partners may desire to sell the Partnership's 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 nonoperating
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 the Partnership's
companion Operating Partnership does not approve its proposal to liquidate and
sell its Property Interests, and the Managing General Partner continues as the
manager of that partnership, then it is possible but not certain that the
Partnership's Property Interest might be sold under the terms set out in the
Proposal. If one of the two partnerships does not approve its proposal, then
the Managing General Partner will advise the limited partners or interest
holders accordingly.

If the Limited Partners of the Partnership do not vote in favor of the
Proposal, then it is likely that the Partnership will continue operations and
will produce its reserves until depletion with steadily decreasing rates of
cash flow and consequently steadily decreasing amounts of cash distributions to
the Limited Partners.

STEPS TO IMPLEMENT THE PROPOSAL

Following the approval of the Proposal and the companion Operating
Partnership's approval of its similar proposal, the Managing General Partner
intends to take the following steps to implement the Proposal:

1. Pay the purchase price of the Property Interests,
transfer the Partnership's Property Interests to the
companion Operating Partnership, and execute
assignments and other instruments to accomplish such
sale (including documents to be executed together
with the Partnership's companion Operating
Partnership).

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<PAGE> 35
2. Pay or provide for payment of the Partnership's
liabilities and obligations to creditors, if any,
using the Partnership's cash on hand and sales
proceeds;

3. Conduct a final accounting in accordance with the
Partnership Agreement and make a final liquidating
distribution;

4. Cause final Partnership tax returns to be prepared
and filed with the Internal Revenue Service and
appropriate state taxing authorities;

5. Distribute to the Limited Partners final Form K-1 tax
information; and

6. File a Certificate of Cancellation on behalf of the
Partnership with the Secretary of State of the State
of Texas.

Estimated Selling Costs. The expenses associated with the sale of the
Partnership's Property Interests are expected to be approximately 3% of the
Fair Market Value of the Partnership's 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 Proposal and related
transactions will be met through the normal ongoing fee set out in the
Partnership's Limited Partnership Agreement. See "Voting on the
Proposal--Solicitation."

Other. Any sale of the Partnership Property Interests and the
subsequent liquidating distributions to the Limited Partners, if any, pursuant
to the Proposal will be taxable transactions under federal and state income tax
laws, even though Limited Partners may not be required to recognize any taxable
income or loss. See "Federal Income Tax Consequences."

IMPACT ON THE MANAGING GENERAL PARTNER

The Managing General Partner will purchase the Partnership's Property
Interests if the Proposal is approved and a similar proposal is approved by the
Partnership's companion Operating Partnership. To the extent of its ownership
of Units, liquidation will have the same effect on it as on the Limited
Partners. See "The Proposal--Estimates of Liquidating Distribution Amount."
Additionally, by purchasing the Partnership's Property Interests itself, the
Managing General Partner will be able to maintain its position as operator of
many of the properties in which the Partnership owns an interest and for which
it will continue to receive operating fees. The sale of the Partnership's
Property Interests to the Managing General Partner will have no effect or an
inconsequential effect on the Managing General Partner's net book value and net
earnings. However, simultaneously with the Proposal to the Limited Partners of
the Partnership, the Managing General Partner is making a similar proposal to
investors in a number of other limited partnerships organized for the same
purposes between the years 1986 and 1994. If the investors in all of these
partnerships were to 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 the total proved reserves on an
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 Limited Partners,
rather than on the basis of the direct economic impact on the Managing General
Partner.

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<PAGE> 36
RECOMMENDATION OF THE MANAGING GENERAL PARTNER

For the foregoing reasons, the Managing General Partner believes that
it is in the best interests of the Limited Partners to dissolve and liquidate
the Partnership. Liquidation will allow the Limited Partners to receive the
remaining value of Partnership reserves currently, rather than receiving
distributions over the remaining life of the Partnership, 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
Partnership's interest in remaining reserves. The Managing General Partner
believes that general improvements over the last several years in the level of
natural gas prices make this an appropriate time to consider the sale of the
Partnership's Property Interest. If operations continue over many years,
revenues will continue to decline while operating and general and
administrative expenses continue, reducing cash distributions. Continued
operations also mean continuation of the additional costs incurred by the
Limited Partners, including the costs associated with inclusion of information
from the Schedule K-1 relating to the Partnership in their personal income tax
returns, while reserves continue to decline. Termination of the Partnership
will allow preparation of a final tax return, and certain additional deductions
may be generated in connection with this termination.

THE MANAGING GENERAL PARTNER RECOMMENDS THAT THE
LIMITED PARTNERS VOTE FOR THE PROPOSAL.

FEDERAL INCOME TAX CONSEQUENCES

GENERAL

The following summarizes certain federal income tax consequences to
the Limited Partners arising from the Partnership's proposed sale of its oil
and gas properties and liquidation pursuant to the Proposal. This discussion
is not based upon an opinion of counsel and it is possible that different
results than those described may occur. Statements of legal conclusions
regarding tax consequences are based upon relevant provisions of the Internal
Revenue Code of 1986, as amended (the "Code"), and accompanying Treasury
Regulations, as in effect on the date hereof, upon private letter rulings dated
October 6, 1987 and August 22, 1991, 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 Limited Partners.

This summary does not describe all the tax aspects which may affect
Limited Partners because the tax consequences may vary depending upon the
individual circumstances of a Limited Partner. It is generally directed to
Limited Partners that are qualified plans and trusts under Code Section 401(a)
and 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 Partnership as "capital assets" (generally,
property held for investment). Each Limited Partner that is not a Tax Exempt
Plan 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.

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<PAGE> 37
TAX TREATMENT OF TAX EXEMPT PLANS

SALE OF PROPERTY INTEREST AND LIQUIDATION OF PARTNERSHIP

The Managing General Partner is proposing to sell the Partnership's
Property Interests as well as any other royalties and overriding royalties the
Partnership may own. After the sale of the properties, the Partnership's
assets will consist solely of cash, which will be distributed to the partners
in complete liquidation of the partnership.

Tax Exempt Plans are subject to tax on their unrelated business
taxable income ("UBTI"). UBTI is income derived by an organization from the
conduct of a trade or business that is substantially unrelated to its
performance of the function that constitutes the basis of its tax exemption
(aside from the need of such organization for funds). Royalty interests,
dividends, interest and gain from the disposition of capital assets are
generally excluded from classification as UBTI. Notwithstanding these
exclusions, royalties, interest, dividends, and gains will create UBTI if they
are received from debt-financed property, as discussed below.

The Internal Revenue Service has previously ruled that the
Partnership's Property Interest, as structured under the NP/OR, 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 Limited Partners 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 Interest for federal income tax
purposes. The foregoing assumes Limited Partners have not borrowed funds to
acquire 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 a Limited Partner 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. The Managing General Partner has
represented that (i) the Partnership did not borrow money to acquire its
Property Interest, and (ii) that the Property Interest of the Partnership is
not subject to any debt, mortgages or similar liens that will cause the
Partnership's Property Interest 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 Interest is not expected to be considered debt-financed
property.

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<PAGE> 38
TAX TREATMENT OF LIMITED PARTNERS SUBJECT TO FEDERAL INCOME TAX DUE TO
DEBT-FINANCING OR WHO ARE NOT TAX EXEMPT PLANS

All references hereinbelow to Limited Partners refers solely to
Limited Partners 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.
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 Partnership Property Interest and the
liquidation of the Partnership assumes that all of a Limited Partner's income,
gain, loss and deduction from the Partnership is subject to federal taxation.

TAXABLE GAIN OR LOSS UPON SALE OF PROPERTIES

A Limited Partner will realize and recognize gain or loss, or a
combination of both, upon the 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
the Partnership and allocated to the Limited Partner (i.e., cash or
consideration received) over the Limited Partner'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 Limited
Partner's tax basis over the amount realized by the Partnership for such
property and allocated to the Limited Partner. It is projected that taxable
loss will be realized upon the sale of Partnership properties and that such
loss will be allocated among the Limited Partners in accordance with the
Partnership Agreement. The Partnership Agreement includes an allocation
provision that requires 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 Limited Partner will realize and
recognize his allocable share of gains and losses in his tax year within which
the Partnership properties are sold.

LIQUIDATION OF THE PARTNERSHIP

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<PAGE> 39
than such Limited Partner's adjusted tax basis in his Partnership interest, the
Limited Partner will realize and recognize a capital loss to the extent of the
excess. If the amount of cash distributed is greater than such Limited
Partner's adjusted tax basis in his Partnership interest, the Limited Partner
will recognize a capital gain to the extent of the excess. Because each
Limited Partner 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 Limited Partners will be less
than such Limited Partners' 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 ordinarily income, including income from
the recapture of depletion, will be taxed at a maximum rate depending on that
Limited Partner'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 Limited Partner
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

Limited Partners 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.

THE FOREGOING DISCUSSION IS INTENDED TO BE A SUMMARY OF CERTAIN INCOME
TAX CONSIDERATIONS OF THE SALE OF PROPERTIES AND LIQUIDATION. EACH LIMITED
PARTNER SHOULD CONSULT ITS OWN TAX ADVISOR CONCERNING ITS PARTICULAR TAX
CIRCUMSTANCES AND THE FEDERAL, STATE, LOCAL, FOREIGN AND OTHER TAX CONSEQUENCES
TO IT OF THE SALE OF PROPERTIES AND THE LIQUIDATION OF THE PARTNERSHIP.

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.

RESERVES

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<PAGE> 40
contains both estimates for the Partnership as a whole and those solely
attributable to the interest in the Partnership of the Limited Partners. 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
Proxy Statement.

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.

THE MANAGING GENERAL PARTNER

Subject to certain limitations set forth in the Partnership Agreement,
the Managing General Partner has full, exclusive and complete discretion in the
management and control of the business of the Partnership. The Managing
General Partner has general liability for the debts and obligations of the
Partnership.

The Managing General Partner is engaged in the business of oil and gas
exploration, development and production, and the Managing General Partner
serves as the general partner of a number of other oil and gas income and
pension partnerships. The Managing General Partner's common stock is traded on
the New York and Pacific Stock Exchanges.

The principal executive offices of the Managing General Partner are
located at 16825 Northchase Drive, Suite 400, Houston, Texas 77060, telephone
number (281) 874-2700.

TRANSACTIONS BETWEEN THE MANAGING GENERAL PARTNER AND THE PARTNERSHIP

The Managing General Partner receives operating fees for wells in
which the Partnership has a net profits interest 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 net
profits interest. The Managing General Partner believes that it will be
positively affected, on the other hand, by liquidation of the Partnership, on
the basis of its ownership interest in the Partnership. See "The
Proposal--Estimates of Liquidating Distribution Amount," and "The
Proposal--Impact on the Managing General Partner."

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<PAGE> 41
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 partnership interest or limited
partnership interests it has purchased. 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.

o The Managing General Partner receives per-well monthly
operating fees from the Operating Partnership for 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
Limited Partner capital contributions to the Partnership
relative to limited partner or interest holder contributions
of all partnerships for which the Managing General Partner
serves as Managing General Partner. Through December 31,
1997, the Managing General Partner had received $312,053 in
the general and administrative overhead allowance.

o The Managing General Partner has been reimbursed $25,064 in
direct expenses, all of which was billed by, and then paid
directly to, third party vendors.

NO TRADING MARKET

There is no trading market for the Units, and none is expected to
develop. Under the Partnership Agreement, the Limited Partners 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 Limited Partners invested in the Partnership.
Through December 31, 1997, the Managing General Partner has purchased 2,523
Units from Limited Partners pursuant to the right of presentment. As of April
___, 1998, there were 411 Limited Partners (excluding the Managing General
Partner). The Managing General Partner does not have an obligation to
repurchase Limited Partner interests pursuant to this right of presentment but
merely an option to do so when such interests are presented for repurchase.

PRINCIPAL HOLDERS OF LIMITED PARTNER UNITS

The Managing General Partner holds 5.26% of all outstanding Units of
the Partnership resulting from the purchase of Units from Limited Partners
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.

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APPROVALS

No federal or state regulatory requirements must be satisfied or
approvals obtained in connection with the sale of the Partnership's Property
Interests.

LEGAL PROCEEDINGS

The Managing General Partner is not aware of any material pending
legal proceedings to which the Partnership is a party or of which any of its
property is the subject.

INCORPORATION OF CERTAIN INFORMATION BY REFERENCE AND
ATTACHMENT OF INFORMATION HERETO

The Partnership's Annual Report on Form 10-K for the year ended
December 31, 1997, is attached hereto and incorporated herein by reference.
Additionally, a reserve report dated February 10, 1998, prepared as of December
31, 1997, and audited by H.J. Gruy and Associates, Inc., is attached hereto
together with the fair market value estimates of J.R. Butler and H.J. Gruy
dated April 17, 1998, and the fair market value estimate of CIBC Oppenheimer
dated April 20, 1998.

GLOSSARY OF TERMS

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.

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.

EBITDA means earnings before interest, taxes and depreciation, depletion and
amortization.

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.

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.

MMBTU means million British Thermal Units, which is a heating equivalent
measure for natural gas.

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, the 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

35
<PAGE> 43
at the respective dates of acquisition to contain Proved Reserves, to the
extent such depths underlie specified surface acreage.

NP/OR AGREEMENT OR NET PROFITS AGREEMENT means the form of Net Profits and
Overriding Royalty Interest Agreement or Net Profits Agreement entered into
between the Partnership and an Operating Partnership pursuant to which the
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.

PV-10 VALUE means, in accordance with Securities and Exchange 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 future income, ad valorem and severance 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.

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.

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.

36
<PAGE> 44
OTHER BUSINESS

The Managing General Partner does not intend to bring any other
business before the Meeting and has not been informed that any other matters
are to be presented at the Meeting by any other person.

SWIFT ENERGY COMPANY
as Managing General Partner of
SWIFT ENERGY MANAGED PENSION
ASSETS PARTNERSHIP 1988-A, LTD.

---------------------------------
John R. Alden
Secretary

37
<PAGE> 45
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
------------------------------ ---------------------

IF LIMITED PARTNERSHIP UNITS ARE HELD JOINTLY, ALL JOINT TENANTS MUST
SIGN.

<PAGE> 46

May ___, 1998
Dear Limited Partner:

As your Managing General Partner, Swift Energy Company believes that
the time has come to dissolve and liquidate the Partnership. Enclosed is a proxy
statement and related information pertaining to a proposal for the sale of
substantially all of the 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 fair
market value estimates of three independent appraisers, consisting of two
petroleum engineering firms and one investment banking firm, plus a premium of
7.5% above Fair Market Value. In order for the sale and liquidation to take
place, Limited Partners holding at least 51% 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 sale and liquidation for a number of reasons. See "The
Proposal--Reasons for the Proposal" and "--Recommendation of the Managing
General Partner."

Swift Energy Income Partners 1989-B, Ltd. has been in existence for
almost nine years, and most of the properties underlying its working interest
were purchased by October 1989. The Partnership achieved payout as of January 1,
1998. Limited capital is available for enhancement or development activities on
the properties in which the Partnership owns operating interests. See "The
Proposal--Partnership Financial Performance and Condition." To continue
operation of the Partnership means that Partnership direct and administrative
expenses (such as costs of audits, reserve reports, Securities and Exchange
Commission filings, and tax returns), 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 Limited
Partners. 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 Limited Partners 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 make this an appropriate time for the Limited Partners to consider
the sale of the Partnership's Property Interests, which also increases the
likelihood of maximizing the value of the Partnership's assets.

If Limited Partners holding at least 51% of the Units of the
Partnership approve this proposal and the limited partners of the Partnership's
companion Pension Partnership approve a similar proposal, the sale of the
Partnership's Property Interests to the Managing General Partner will be made by
the end of the third quarter of 1998.

Included in this package are the most recent financial and other
information prepared regarding the Partnership. If you need any further material
or have questions regarding this proposal, please feel free to contact the
Managing General Partner at (800) 777-2750.

SWIFT ENERGY COMPANY,
Managing General Partner

A. Earl Swift
Chairman

<PAGE> 47

THIS TRANSACTION HAS NOT BEEN APPROVED OR DISAPPROVED BY THE
SECURITIES AND EXCHANGE COMMISSION ("COMMISSION") NOR HAS THE COMMISSION PASSED
UPON THE FAIRNESS OR THE MERITS OF SUCH TRANSACTION NOR UPON THE ACCURACY OR
ADEQUACY OF THE INFORMATION CONTAINED IN THIS DOCUMENT. ANY REPRESENTATION TO
THE CONTRARY IS UNLAWFUL.

DOCUMENTS INCLUDED

TABLE OF CONTENTS

<TABLE>
<S> <C>
SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Partnership Property Interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Proposed Sale of Partnership Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

SPECIAL FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Partnership Property Interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Vote for Liquidation and Proposed Sale of Partnership Property Interests
to the Managing General Partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
INDEPENDENT APPRAISAL OF THE FAIR MARKET VALUE OF PARTNERSHIP PROPERTY INTERESTS . . . . . . . . . . . . . . 4
Fairness of Proposed Sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Consideration of Alternative Transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Federal Income Tax Consequences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Managing General Partner Benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

THE PROPOSAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Partnership Financial Performance and Condition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Estimates of Liquidating Distribution Amount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Comparison of Sale Versus Continuing Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Reasons for the Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Simultaneous Proposal to Companion Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Steps to Implement the Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Impact on the Managing General Partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Recommendation of the Managing General Partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

FEDERAL INCOME TAX CONSEQUENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Taxable Gain or Loss Upon Sale of Propertiess . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Liquidation of the Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Capital Gains Tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Passive Loss Limitations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

BUSINESS OF THE PARTNERSHIP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
The Managing General Partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Transactions Between the Managing General Partner and the Partnership. . . . . . . . . . . . . . . . . . . . 33
No Trading Market. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Principal Holders of Limited Partner Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Approvals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

INCORPORATION OF CERTAIN INFORMATION BY REFERENCE
AND ATTACHMENT OF INFORMATION HERETO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

GLOSSARY OF TERMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

OTHER BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

FORM OF PROXY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-1
</TABLE>

i
<PAGE> 48

SWIFT ENERGY INCOME PARTNERS 1989-B, 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 of
Swift Energy Income Partners 1989-B, Ltd. (the "Partnership") will be held at
16825 Northchase Drive, Houston, Texas, on Tuesday, June ___, 1998 at 4:00 p.m.
Central Time to consider and vote upon:

The adoption of a 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
"Termination"). The asset sales 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.

A record of limited partners of the Partnership has been taken as of
the close of business on April ___, 1998, and only limited partners of record on
that date will be entitled to notice of and to vote at the meeting, or any
adjournment thereof.

SWIFT ENERGY COMPANY,
Managing General Partner

JOHN R. ALDEN
Secretary
May ____, 1998

<PAGE> 49

SWIFT ENERGY INCOME PARTNERS 1989-B, LTD.
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060-9468
(281) 874-2700

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

PROXY STATEMENT

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

SUMMARY

GENERAL

This Proxy Statement is being provided by Swift Energy Company, a Texas
corporation (the "Managing General Partner" or "Swift") in its capacity as the
Managing General Partner of Swift Energy Income Partners 1989-B, Ltd. a Texas
limited partnership (the "Partnership"), to holders of units of limited
partnership interests representing an initial investment of $100 per Unit in the
Partnership (the "Units"). This Proxy Statement and the enclosed proxy are
provided for use at a special meeting of limited partners (the "Limited
Partners"), and any adjournment of such meeting (the "Meeting") to be held at
16825 Northchase Drive, Houston, Texas, at 4:00 p.m. Central Time on June ___,
1998. The Meeting is called for the purpose of considering and voting upon a
proposal to sell substantially all of the assets of the Partnership to the
Managing General Partner and dissolve, wind up and terminate the Partnership
(the "Proposal"), in accordance with the terms and provisions of the
Partnership's Limited Partnership Agreement dated June 30, 1989 (the
"Partnership Agreement"), and the Texas Revised Limited Partnership Act (the
"Texas Act"). This Proxy Statement and the enclosed proxy are first being mailed
to Limited Partners on or about May ____, 1998.

Under the Partnership Agreement, the affirmative vote of Limited
Partners holding at least 51% of the Units then held by Limited Partners as of
the Record Date (as defined) is required for approval of the Proposal. Each
Limited Partner appearing on the Partnership's records as of April ___, 1998
(the "Record Date"), is entitled to notice of the Meeting and is entitled to one
vote for each Unit held by such Limited Partner. Under the Partnership
Agreement, the General Partners may not vote any Units owned by them for matters
such as the Proposal. VJM Corporation, a California corporation, the Special
General Partner of the Partnership, owns a 1.50% interest in the Partnership as
a General Partner, but owns no Units. The Managing General Partner has owned a
13.50% general partner's interest in the Partnership since partnership payout
effective January 1, 1998, in addition to ownership of 9.11% of all outstanding
Units resulting from its purchase of Units from Limited Partners under their
right of presentment. Therefore, the affirmative vote of holders of at least 51%
of the remaining Units is required to approve the proposed sale.

PARTNERSHIP PROPERTY INTERESTS

The Partnership's assets consist of working interests in producing oil
and gas properties (the "Property Interests"). The Property Interests are
burdened by a single net profits interest in the producing oil and gas
properties granted to an affiliated companion partnership, Swift Energy Managed
Pension Assets Partnership 1989-B, Ltd. (the "Pension Partnership"). The most
significant fields in which the Partnership owns a working interest are
summarized under "Special Factors--Partnership Property Interests" below. During
1997, approximately 48% of the Partnership's revenue was attributable to natural
gas production.

If the Proposal is approved by Limited Partners, and if a similar
proposal to the limited partners of the Pension Partnership is approved, then
the underlying properties would be sold to the Managing General

<PAGE> 50

Partner by the Operating Partnership. If approved, it is anticipated that the
sale of the Partnership's Property Interest will be made by the end of the third
quarter of 1998. The sale of Partnership Property Interests will cause the
Partnership to dissolve automatically under the terms of the Partnership
Agreement and the Texas Act and its affairs would then be wound up and the
Partnership terminated. Currently there are no third party buyers for the
Property Interests.

For more information about the Partnership's Property Interests and
recent financial performance, see the attached Annual Report on Form 10-K for
the year ended December 31, 1997.

PROPOSED SALE OF PARTNERSHIP PROPERTIES

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 potential
conflict of interest between the Managing General Partner acting in its capacity
as 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, has been asked to approve
the selection of the three independent third party appraisers (the "Appraisers")
chosen to estimate the fair market value of the Partnership's Property
Interests, which is the price, plus a premium of 7.5% above such fair market
value, at which such Property Interests would be sold. The Special Transactions
Committee has 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 methodology used by the Appraisers in estimating the fair market
value is discussed below under "Special Factors--Independent Appraisal of the
Fair Market Value of Partnership Property Interests." The Managing General
Partner believes that using this methodology to estimate the fair market value
at which the Property Interests will be purchased from the Partnership is fair
to Limited Partners, as discussed in detail under "Special Factors--Fairness of
Proposed Sale." Also discussed under "The Proposal--Reasons for the Proposal"
are the reasons for proposing the sale of such Property Interests and
liquidation of the Partnership at this time. A discussion of the alternatives to
such sale and liquidation which were considered is contained under "Special
Factors--Consideration of Alternative Transaction." In addition to the
foregoing, there are certain risks involved in the Proposal. See "Risk Factors."

In order to allow Limited Partners 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 Managing General Partner will
offer to the Limited Partners and limited partners or interest holders of other
partnerships which approve similar proposals the opportunity to purchase on a
collective basis up to 2.5 million shares of common stock of Swift Energy
Company directly from Swift Energy Company. Such shares of common stock will be
offered at a price based upon the then current market price for Swift common
stock on the New York Stock Exchange once the voting is completed by all of the
investors in multiple partnerships managed by the Managing General Partner.
Limited Partners will have the discretion to choose the amount, if any, of Swift
common stock they desire to purchase, provided that they purchase at least 100
shares.

<PAGE> 51

SPECIAL FACTORS

PARTNERSHIP PROPERTY INTERESTS

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 operator, 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.

SHAWNEE 31
AWP TOWNSITE CAPRITO OTHER
FIELD FIELD FIELD FIELDS
--------------- ----------------- --------------- -----------
<S> <C> <C> <C> <C>
McMullen Pottawatomie Ward AL(2)
County and State County, County, County, AR(3)
Texas OK OK LA(5)
OK(10)
TX(7)
WY(4)

Number of Wells 96 34 36 477

Swift Vintage Titan Swift
Petroleum; Resources and 42
Operator(s) Estoril others
Producing

% of 12/31/97 PV-10 Value 40% 14% 8% 38%

% of 1997 Production (Volumes) 25% 18% 10% 47%
</TABLE>

VOTE FOR LIQUIDATION AND PROPOSED SALE OF PARTNERSHIP PROPERTY INTERESTS TO THE
MANAGING GENERAL PARTNER

If approved by Limited Partners holding at least 51% of the Units, and
assuming approval by the Partnership's companion Pension Partnership of the sale
of substantially all of that partnership's assets, the Proposal described above
to sell substantially all of the Partnership's assets and subsequently to
dissolve and terminate the Partnership ultimately will result in the sale to the
Managing General Partner of the Partnership's Property Interests for $3,314,557,
which is comprised of the Fair Market Value plus the 7.5% premium above such
value. This sale of the Partnership's Property Interests is being proposed for
Limited Partner approval in an attempt to realize the highest value for the
Partnership's Property Interests.

The reasons for proposing the sale of the Partnership's Property
Interests at this time are described in detail under "The Proposal--Reasons for
the Proposal." Although Limited Partners already have received

<PAGE> 52

cash distributions in excess of their original capital contributions to the
Partnership, these cash distributions will continue to decrease over time. This
decrease is due to the inherent decline in hydrocarbons produced over time and
is additionally compounded by the absence of any further capital expenditures on
the properties in which the Partnership has a Property Interest. The Partnership
has been in existence for almost nine years. While production and revenues
decrease over time, various costs will continue, including certain fixed oil
field overhead and operating costs ($80,297 in 1997) which are incurred
regardless of the level of production, and continued direct costs (audits,
reserve reports, Securities and Exchange Commission filings, and tax returns)
incurred each year ($30,353 in 1997). The Managing General Partner believes that
improvements over the last several years in the level of natural gas prices make
this an appropriate time to propose the sale of the Partnership's Property
Interests, which also increases the likelihood of maximizing the value of the
Partnership's assets. By selling its Property Interests and liquidating, the
Partnership will avoid future overhead and direct costs and the receipt of the
value of the Partnership's reserves accelerated so that such funds are received
at one time. This in turn avoids the risk of subjecting future revenues and cash
distributions to Limited Partners to volatility of oil and gas prices, as well
as inherent geological, engineering and operational risks, which could affect
future returns.

INDEPENDENT APPRAISAL OF THE FAIR MARKET VALUE OF PARTNERSHIP PROPERTY INTERESTS

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 Limited Partners
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.

One of the three Appraisers, H.J. Gruy, is the independent petroleum
engineering firm most familiar with the properties in which the Partnership has
an interest and has prepared the annual reserves audit and independent reserve
report upon the Partnership's reserves since inception of the Partnership. 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 Partnership's Property Interests.

<PAGE> 53

Interests. The Managing General Partner did not set the amount of consideration
to be paid to the Partnership for its Property Interests nor provide any
information to the Appraisers on amounts to be paid to the Limited Partners. 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 Limited Partners, and the Managing General Partner has not acquired a
separate report or opinion regarding the fairness to the Limited Partners of the
price at which the Partnership's Property Interests will be sold to the Managing
General Partner if the Proposal is approved by the Limited Partners.

QUALIFICATIONS OF APPRAISERS

H.J. Gruy and Associates, Inc. is an established independent petroleum
engineering firm in Houston, Texas. H.J. 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. H.J. Gruy has extensive experience evaluating
properties in all of the areas in which the Partnership owns Property Interests.
H.J. 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 Corp., 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

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. The valuation estimates of the Appraisers are
attached to this Proxy Statement 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

<PAGE> 54

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 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 Property Interests. As a result
of their individual and collective work, the Petroleum Engineering Consultants
estimated a fair market valuation for each property in which the Partnership has
a Property Interest, and CIBC Oppenheimer estimated a fair market valuation for
each such property. After presentation of the two valuation estimates to the
Special Transactions Committee, the committee determined that the Fair Market
Value of any given Property Interest was the higher of the two values estimated
by the Petroleum Engineering Consultants and CIBC Oppenheimer. This necessarily
matches the definition of "Fair Market Value," which is the maximum price that a
willing buyer will pay and at which a willing seller will sell at a given point
in time at which the buyer is under no compulsion to buy and the seller is not
compelled to sell, both having reasonable knowledge of all the material
circumstances.

VALUATION BY PETROLEUM ENGINEERING CONSULTANTS

The value estimate from the Petroleum Engineering Consultants uses the
"income approach." The income approach for proved producing properties reduces
the discounted future net cash flows before federal income tax to a fair market
value by multiplying such cash flow by a suitable fraction that accounts for the
risk associated with the purchase of that cash flow stream. For proved developed
non-producing and proved undeveloped reserves, the risk adjustments are
generally more severe for a variety of reasons, including the necessity of
making a capital investment when it is assumed that the capital is invested with
certainty and the resulting operating cash income stream is burdened with the
uncertainty.

The Petroleum Engineering Consultants audited the estimates of proved,
probable and possible reserves and future net revenues therefrom prepared by the
Managing General Partner utilizing standard petroleum engineering methods. For
properties with sufficient production history, reserves estimates and rate
projections were based primarily on extrapolation of established performance
trends and reconciled, whenever possible, with volumetric and/or material
balance calculations. For the undeveloped locations, reserves were determined by
a combination of volumetric calculations (geologic mapping) and analogy.
Volumetrically determined reserves or those determined by analogy are generally
subject to greater qualifications than reserve estimates supported by
established production decline curves and/or material balance calculations. The
Petroleum Engineering Consultants audited the determination and classification
of proved reserves in accordance with Securities and Exchange Commission
guidelines (with the exception of having employed escalated prices and costs).
The definitions used by the Petroleum Engineering Consultants for the unproved
reserves conform to those promulgated by the Society of Petroleum Engineers,
Inc. (SPE) and the World Petroleum Congress(es).

<PAGE> 55

Basic evaluation data used by the Petroleum Engineering Consultants,
including 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:

o Reviewing technical and economic data presented by the
Managing General Partner relative to the Partnership's proved,
probable and possible reserves as of December 31, 1997.

o Examining the Partnership's cash flow forecasts for its
quantified probable and possible reserves.

o Reviewing the Partnership's lease operating costs for
reasonableness.

o Preparing reserves and future performance estimates for the
audit evaluation 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. For the
non-producing zones and undeveloped locations, reserves were
determined by a combination of volumetric calculations and
analogy.

<PAGE> 56

VALUATION BY CIBC OPPENHEIMER

In performing its analysis of the value of the Partnership's Property
Interests, CIBC Oppenheimer first reviewed the PV-10 Value at December 31, 1997
for each property to be purchased in which the Partnership has a Property
Interest (a "Field"). In addition, CIBC Oppenheimer reviewed the valuation
estimates prepared by the Petroleum Engineering Consultants for each Field.
Individual partnerships own Property Interests in a number of different Fields.
Therefore, CIBC Oppenheimer first focused upon valuing the individual Fields and
then subsequently valuing the Property Interests of each Partnership in various
Fields by allocating to each Partnership its relevant share of the value
attributable to different Fields in which it has a property interest.

Working with the Petroleum Engineering Consultants, CIBC Oppenheimer
reviewed the Fields for characteristics which would allow them to be divided
into separate classifications. Of the total of 44 Fields, the reserves of 34
Fields were determined to be comprised primarily of Proved Developed Producing
reserves ("PDP") which have comparable reserve characteristics ("Conventional
Case"). The remaining 10 Fields were determined to have distinguishing or unique
reserve 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 Fields 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 equivalents 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 determined for the Fields in the Conventional
Case group and the Non-Conventional Case group were unique, reflecting the
different reserve 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 Field. Each
Partnership was allotted its respective proportionate share of individual Fields
("Field Share") based upon the Partnership's Property Interest in such Field, in
order to convert the value determined for the Fields into values for an
individual Partnership's Property Interests in each Field. The CIBC Oppenheimer
valuation estimate for each individual Partnership is the cumulative total of
that Partnership's respective Field Shares.

<PAGE> 57

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 Partnership owns Property Interests and
included the following: Comstock Resources and Black Stone Oil; National Energy
and Alexander Energy; Alliance Resources and LaTex Resources; Melrose Petroleum
Group and Pentex Energy; PANACO and Goldking Companies; Alexander Energy and
American Natural Resources; Gothic Energy and Buttonwood Energy; Key Production
and Brock Exploration; ONEOK and PSEC; and ONEOK and Washita Production. These
selected transactions are not intended to represent the complete list of oil and
gas transactions which have occurred or been announced during this period;
rather, such transactions represent recent transactions involving publicly
traded oil and gas companies engaged in oil and gas exploration and production
activities that were deemed by CIBC Oppenheimer to operate in comparable
producing basins or have comparable financial and operating characteristics to
the Managing General Partner.

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 Partnership's 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.

<PAGE> 58

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 Fields 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 Field'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 Fields
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 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 Fields are near the
end of their economic lives. The degree of this discount was reduced, however,
by the fact that the Fields 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 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 Fields 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

<PAGE> 59

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.

VALUATION LETTER OF CIBC OPPENHEIMER

The Special Transactions Committee retained CIBC Oppenheimer to prepare
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 a letter (the "Valuation
Letter") stating that, as of such 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 was $3,028,036.

The full text of the Valuation Letter, which sets forth the assumptions
made, matters considered, and qualifications and limitations on the review
undertaken by CIBC Oppenheimer, is attached hereto and is incorporated herein by
reference. The summary of the Valuation Letter set forth in this Proxy Statement
is qualified in its entirety by reference to the full text of such letter.
Limited Partners of the Partnership are urged to read such letter in its
entirety. The Valuation Letter was provided to the Special Transactions
Committee for its information and is directed only to the estimate, from a
financial point of view, of the value of the Partnership's Property Interests
and does not address the merits of the underlying decision by the Managing
General Partner or the Partnership to engage in the sale of the Property
Interests to the Managing General Partner and does not constitute a
recommendation to the Partnership's Limited Partners as to how such Limited
Partners should vote on the approval of the Proposal 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
estimate involves 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 an estimate is 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.

<PAGE> 60

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 Fields of Property Interests owned by all of 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 Fields. 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 the
Partnership's Property Interests was $3,083,309 on December 31, 1997. CIBC
Oppenheimer's evaluation of the Partnership's Property Interests began with the
PV-10 Value of each Field, as calculated by the Petroleum Engineering
Consultants. CIBC Oppenheimer then divided the Fields into two categories. Those
fields with reserves consisting primarily of proved developed producing reserves
were placed in the "Conventional Case" category. Those Fields with significant
proved developed non-producing or undeveloped reserves were placed in the
"Non-Conventional Case" category. CIBC Oppenheimer then valued each Field by
applying the multiples discussed above to each Field's PV-10 Value, proved
reserves on a BOE basis, and projected 1998 EBIDTA. A separate set of multiples
was used for Fields in the Conventional Case category and the Non-Conventional
Case category, respectively. This provided CIBC Oppenheimer with three estimated
values for each Field. The average of these three values yielded CIBC
Oppenheimer's estimation of the fair market value of each Field. CIBC
Oppenheimer then allocated the appropriate portion of the Field's estimated fair
market value to the Partnership based upon the Partnership's Property Interest
in each Field. The result of this analysis by CIBC Oppenheimer was an estimation
that 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 Swift Energy
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 Swift 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 Swift, Swift 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.

PRIOR RELATIONSHIPS BETWEEN THE APPRAISERS, THE PARTNERSHIP AND THE MANAGING
GENERAL PARTNER

<PAGE> 61

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 Partnership, and the Appraisers' compensation is not
contingent upon the results of their fair market value opinions resulting from
their review of the Partnership 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 Partnership's Property Interests is fair to Limited Partners 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 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 ultimately proposed to be paid by the Managing General
Partner for the Partnership's Property Interest(s) (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."

3. The Special Transactions Committee has made the determination
as to the retention of the Appraisers and approved the fair
market value estimates provided by the Appraisers, which the
Special Transactions Committee then recommended for adoption
by the Board of Directors of the Managing General Partner. The
Special Transactions Committee is comprised solely of
independent directors of the Managing General Partner.

4. If the Proposal is approved by Limited Partners and the
Property Interests ultimately are purchased by the Managing
General Partner, it is likely that the Managing General
Partner will expend the capital necessary to bring various
nonproducing reserves into production.

<PAGE> 62

Company directly from Swift Energy Company. Such shares of common stock will be
offered at a price based upon the then current market price for Swift common
stock on the New York Stock Exchange once the voting is completed by all of the
investors in multiple partnerships managed by the Managing General Partner.
Limited Partners will have the discretion to choose the amount, if any, of Swift
common stock they desire to purchase, provided that they purchase at least 100
shares. There is no requirement that any such purchase of Swift's common stock
be made, and any such offer is made solely by means of a separate prospectus of
Swift Energy Company included with this proxy statement.

CONSIDERATION OF ALTERNATIVE TRANSACTIONS

The Managing General Partner has given consideration to a number of
different alternatives prior to submitting the Proposal to Limited Partners for
their approval. These alternatives included continued operation of the
properties for a longer period, offering the Partnership's 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 Partnership. 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 Partnership's Property Interests,
as discussed below.

AUCTION

o A substantial portion of the value of the properties in which
the Partnership owns an interest 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 Approximately 17% of the proved reserves value attributed to
the Partnership's Property Interests represents non-producing
reserves. Typically auction buyers base the prices they

<PAGE> 63

pay at auction upon a multiple of cash flow. This methodology
of auction pricing significantly discounts the value of
non-producing reserves.

NEGOTIATED SALE

Many of the same factors discussed above affect whether the Partnership
would benefit from attempting to sell its Property Interests in negotiated
transactions.

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 Partnership's interests therein over several years.

The proposed sale of the Partnership's 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 Partnership's 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
Partnership's Limited Partners 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.

<PAGE> 64

FEDERAL INCOME TAX CONSEQUENCES

For information concerning the Federal income tax consequences of the
sale of substantially all of the Partnership's Property Interests and its
liquidation, see "Federal Income Tax Consequences" herein.

MANAGING GENERAL PARTNER BENEFITS

The Managing General Partner will share the benefits available to
Limited Partners through liquidating its partnership interests and receiving the
current value of those interests as a result of such sales. Additionally, by
purchasing the Partnership's Property Interests itself, the Managing General
Partner will continue to serve as operator of many of the properties in which
the Partnership owns an interest and will continue to receive operating fees.
The sale of the Partnership's Property Interests to the Managing General Partner
will have no effect or an inconsequential effect on the Managing General
Partner's net book value and net earnings. Simultaneously with the proposal to
the Limited Partners of the Partnership, the Managing General Partner is making
a similar proposal to investors in a number of other limited partnerships
organized for the same purposes between the years 1986 and 1994. If the
investors in all of these partnerships were to approve the proposal 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 the total proved reserves on an 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 PROPOSAL INVOLVES CERTAIN RISKS. SEE "RISK FACTORS."

o There is no guarantee that the fair market value estimates of the
independent Appraisers represents the highest possible price that might
be received for the Partnership's Property Interests in all
circumstances. This price 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 would purchase the Partnership's Property
Interests has been 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 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
Limited Partners receiving higher distributions from continued
operations of the Partnership, although inherent geological,
engineering and operational risk would continue.

<PAGE> 65
If the Proposal is not approved by Limited Partners holding 51% or more
of the Units then held by Limited Partners and a similar proposal is not also
approved by the required vote of the limited partners or interest holders of the
Partnership's companion Pension Partnership, the Partnership will continue to
exist.

LIMITED PARTNERS ARE URGED TO COMPLETE, SIGN AND DATE THE ENCLOSED
PROXY AND TO RETURN IT TO THE MANAGING GENERAL PARTNER NO LATER
THAN JUNE _____, 1998.

<PAGE> 66

VOTING ON THE PROPOSAL

VOTE REQUIRED

According to the terms of the Partnership Agreement, approval of the
Proposal requires the affirmative vote by the holders of at least 51% of the
Units held by Limited Partners. Therefore, an abstention by a Limited Partner
will have the same effect as a vote against the Proposal. This solicitation is
being made for votes in favor of the Proposal (which will result in liquidation
and dissolution). As of the Record Date, 75,781.00 Units were outstanding and
were held of record by 626 Limited Partners (excluding the Managing General
Partner's Units). Each Limited Partner is entitled to one vote for each Unit
held in its name on the Record Date. Accordingly, the affirmative vote of
holders of at least 38,648.31 Units is required to approve the Proposal. The
Managing General Partner holds 7,514 Units, but, in accordance with the
Partnership Agreement, the Managing General Partner may not vote its Units. The
Managing General Partner's non-vote, in contrast to abstention by Limited
Partners, will not affect the outcome, because for purposes of adopting the
Proposal 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 included in this Proxy Statement. The
actual proxy to be used to register your vote on the Proposal is the separate
green sheet of paper included with the Proxy Statement. PLEASE USE THE GREEN
PROXY TO VOTE UPON THE PROPOSAL.

If a proxy is properly signed and is not revoked by a Limited Partner,
the Units it represents will be voted in accordance with the instructions of the
Limited Partner. If no specific instructions are given, the Units will be voted
FOR the Proposal. A Limited Partner may revoke his proxy at any time before it
is voted at the Meeting. Any Limited Partner who attends the Meeting and wishes
to vote in person may revoke his proxy at that time. Otherwise, a Limited
Partner 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 proposal to sell substantially all of the
Partnership's assets and liquidate the Partnership, Limited Partners are not
entitled to any dissenters' or appraisal rights such as would be available to
shareholders in a corporation engaging in a merger. Dissenting Limited Partners
are protected under state law by virtue of the fiduciary duty of general
partners to act with prudence in the business affairs of the Partnership.

SOLICITATION

The solicitation is being made by the Partnership. The Partnership will
bear the costs of the preparation of this Proxy Statement and of the
solicitation of proxies and such costs will be allocated 85% to the Limited
Partners and 15% to the General Partners with respect to their general
partnership interests pursuant to Article VIII.A(v) of the Partnership
Agreement. As the Managing General Partner holds approximately 9.11% of the
Units held by all Limited Partners, 9.11% of the costs borne by the Limited
Partners 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

<PAGE> 67

temporary employees of the Managing General Partner may, if necessary to ensure
the presence of a quorum, solicit proxies in person or by telephone. The
Managing General Partner also may retain a proxy solicitor to assist in
contacting brokers or Limited Partners to encourage the return of proxies,
although it does not anticipate doing so. The expenses associated with the sale
of the Partnership's Property Interests are expected to be approximately 3% of
the Fair Market Value of the Partnership's 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.

RISK FACTORS

A Limited Partner considering whether to vote in favor of the Proposal
should give careful consideration to the risks involved, including those
summarized below:

CONFLICTS OF INTEREST IN PURCHASE OF PROPERTY INTERESTS BY MANAGING GENERAL
PARTNER

If the Proposal is approved by Limited Partners, the Partnership's
Property Interests ultimately would be sold to the Managing General Partner at
the Fair Market Value plus a 7.5% premium, which has been set by the Special
Transactions Committee based on the valuation estimates of the Appraisers. There
is no guarantee that this purchase price represents the highest possible price
that might be received for the Partnership's Property Interest 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 the 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 (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 transactions for the Partnership's
Property Interests, depending upon future prices for either or both of oil and
gas.

DEPENDENCE ON VOTE OF COMPANION PARTNERSHIP

If the Partnership's companion Pension Partnership does not approve a
similar 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 the
Proposal is approved by Limited Partners, 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 Operating Partnership."
Although the Managing General Partner will attempt to provide a different
approach for sale of the Partnerships' Property Interests, it is possible that
the Partnership's assets may not be sold. If the Proposal is approved by the
Partnership and the Pension Partnership, the entire Property Interests owned by
the Partnership will be sold.

<PAGE> 68

POSSIBLE INCREASE IN VALUE OF PROPERTY INTERESTS DUE TO DRILLING ACTIVITY AFTER
THE SALE

If the Proposal to sell the Partnership's Property Interests is
approved by Limited Partners 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
Partnership's 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 Partnership owns Property Interests could
increase the values of such Property Interests. The Partnership 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
Partnership was 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 Managing General Partner intends to offer common stock in Swift
Energy Company for sale directly to limited partners or interest holders of
partnerships which approve the proposal as a method of sharing in any gains
which might be realized due to such activity.

POSSIBLE DECREASE IN DISTRIBUTIONS TO LIMITED PARTNERS DUE TO INTERIM PRODUCTION

The amounts available for distribution to Limited Partners if the
Proposal is approved are estimated under "The Proposal--Estimates of Liquidating
Distribution Amount." The amounts estimated thereon have been reduced by
estimated cash distributions to Limited Partners 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.

THE PROPOSAL

GENERAL

The Managing General Partner has proposed that the Partnership's
Property Interests be sold, the Partnership be dissolved and that the Managing
General Partner, acting as liquidator, wind up the Partnership's affairs and
make final distributions to its partners. The Partnership's assets consist of
working interests in producing oil and gas properties burdened by a net profits
interest held by an affiliated partnership also managed by the Managing General
Partner and formed at approximately the same time as the Partnership was
organized. The Partnership's working interests exist by virtue of oil and gas
leases. The Partnership Property Interests are burdened by a net profits
interest held by its companion Pension Partnership. The net profits interest
exists by virtue of a Net Profits and Overriding Royalty Interest Agreement
("NP/OR Agreement") dated June 30, 1989 with Swift Energy Managed Pension Assets
Partnership 1989-B, Ltd. (the "Pension Partnership"). If the Partnership and the
Pension Partnership approve the sale of their Property Interests, the Pension
Partnership will convey its net profits interest to the Partnership, which then
will sell all properties it holds to the Managing General Partner.

Pursuant to the terms of the Partnership Agreement, the Partnership,
if not terminated earlier, will continue in being through January 1, 2021, at
which point it will terminate automatically.

<PAGE> 69

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, using funds advanced by the Managing General Partner to
perform these operations, which amounts have been subsequently repaid.

The Limited Partners have made contributions of $8,329,500 in the
aggregate to the Partnership. The Managing General Partner has made capital
contributions with respect to its general partnership interest of $70,596.
Additionally, pursuant to the presentment right set forth in the Partnership
Agreement, the Managing General Partner has purchased 7,514 Units from Limited
Partners. From inception through January 31, 1998, the Partnership has made cash
distributions to its Limited Partners totaling $8,451,400. Through January 31,
1998, the Managing General Partner has received cash distributions from the
Partnership of $1,106,465 with respect to its general partnership interest, and
$204,707 related to its limited partnership interests. On a per Unit basis,
Limited Partners 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 Partnership's oil prices averaged $17.45 per barrel and natural gas
prices averaged approximately $1.79 per Mcf. A comparison of gas prices as
described in this paragraph appears in the graph presented below.

<PAGE> 70

[GRAPHS: 2 pages of oil and gas properties logo]

<PAGE> 71

23
<PAGE> 72

Lower prices 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.

ESTIMATES OF LIQUIDATING 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 cash distributions from January 1, 1998 until
June 30, 1998, resulting in an estimate of the amount of net distributions
available for Limited Partners as a result of such sales.

ESTIMATE OF LIMITED PARTNERS' SHARE OF DISTRIBUTIONS
FROM PROPERTY INTEREST SALES AND LIQUIDATION

<S> <C>
Appraisers' Fair Market Value of Partnership Property Interests(1) $ 3,083,309
(Gross Sales Proceeds) ===================

Limited Partners' Share of Sales Proceeds(2) $ 2,620,813
--------------------
Purchase Premium (7.5% of Fair Market Value)(3) $ 196,561
--------------------
Estimated Selling and Dissolution Expenses(4) $ (78,624)
(3% of the Fair Market Value) --------------------

Net Assets(5) $ 585,147
--------------------
Estimated Interim Cash Distributions(6) $ (499,800)
--------------------
Estimated Net Distributions to Limited Partners $ 2,824,097
====================

ESTIMATED NET DISTRIBUTIONS PER $100 UNIT $ 33.90
====================
</TABLE>

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

(1) Represents the higher of two values estimated by the Appraisers.

(2) Gross Sales Proceeds amount is allocated 85% to the Limited Partners
pursuant to the Limited Partnership Agreement.

(3) As determined by the Special Transactions Committee.

<PAGE> 73

(4) Includes Limited Partners' share of all costs associated with
dissolution and liquidation of the Partnership.

(5) Includes cash and net receivables of the Partnership as of December 31,
1997.

(6) Estimated Cash Distributions paid to the Limited Partners from January
1, 1998 to June 30, 1998.

If, on the other hand, the Partnership were to retain its Property
Interest and continue to benefit from production of its assets until they have
reached their economic limit, the table below estimates the return to Limited
Partners, 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 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 Pension 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 LIMITED PARTNERS'
NET DISTRIBUTIONS FROM CONTINUED OPERATIONS

PROJECTED
CASH FLOWS
----------
<S> <C>
Estimated Future Net Revenues from Net Profits Interest(1) $ 5,266,181
Estimated Interim Cash Distributions(2) $ (499,800)
Estimated Partnership Direct and Administrative Expenses(3) $ (663,540)
Net Assets(4) $ 585,147
---------------
Net Distributions to Limited Partners(5) $ 4,687,988
===============

NET DISTRIBUTIONS PER $100 UNIT $ 56.28
===============
PRESENT VALUE OF NET DISTRIBUTIONS PER $100 UNIT(6) $ 36.32
===============
</TABLE>

- ----------------------------------
(1) Limited Partners' future net revenues are based on the reserve
estimates at December 31, 1997 using pricing based upon year-end 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 Cash Distributions paid to the Limited Partners from January
1, 1998 to June 30, 1998.

(3) Includes Limited Partners' share of general and administrative
expenses, and audit, tax, and reserve engineering fees.

<PAGE> 74

(4) Includes 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 distribution,
are to be distributed to the Limited Partners 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

Based on the above tables, it is estimated that a Limited Partner could
expect to receive $33.90 per $100 Unit upon immediate sale of the Partnership
Property Interests. In comparison, it is estimated that a Limited Partner 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 Distribution Amount" above show that estimated cash distributions to
Limited Partners (based on net present value) from continued operations would be
approximately 7% higher than estimated 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 distribution in one lump sum currently. The estimates
of 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 subject Limited Partners to the risk of receiving lower levels of
cash distributions if oil and gas prices over this period are lower on average
than those used in preparing the estimates of cash distributions from continued
operations. Continued operations also subject Limited Partners' potential
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 Limited Partners taking any funds to be
received upon liquidation and redeploying those assets in other investments,
rather than continuing to receive decreasing levels of 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 Partnership Agreement at which the
Managing General Partner can offer to repurchase Units from Limited Partners. As
of January 1, 1997, this "Unit Value" was $54.65 per $100 Unit. In 1997, the
Limited Partners received cash 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 price 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 Limited Partners the Unit Value, and the Limited Partners have the
right to present their Units for purchase by the Managing General Partner for
the Unit Value. The Unit Value amount is determined by adding the present value
of proved oil and gas reserves (discounted at 10% per annum) calculated on an
escalated pricing basis to cash

<PAGE> 75

and accounts receivable less outstanding debts and obligations of the
Partnership, and then further discounted that result by 30%.

REASONS FOR THE PROPOSAL

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 oil and gas prices, particularly those for natural gas, make
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 of production.
Likewise, direct costs and general and administrative expenses such as 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 Limited Partner 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 Limited Partners 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 properties and dissolution of the Partnership,
Limited Partners will recognize gain or loss, or a combination of both, under
federal income tax laws. Thereafter, Limited Partners will have no further tax
reporting obligations with respect to the Partnership. The dissolution of the
Partnership will also allow Limited Partners to take a capital loss deduction
for syndication costs incurred in connection with formation of the Partnership.
See "Federal Income Tax Consequences."

SIMULTANEOUS PROPOSAL TO COMPANION PARTNERSHIP

Simultaneously with the Proposal to Limited Partners to sell all of the
Partnership's Property Interests, a similar proposal is being made to the
limited partners of the companion Pension Partnership which owns the net profits
interest in the same properties in which the Partnership owns a working
interest. If the Partnership approves the Proposal, but its companion
partnership does not approve a similar proposal to sell its Property Interests
and liquidate, it is likely to affect the ability of the Partnership to
consummate the sale of its Property Interests. Although the Partnership's
Limited Partners may desire to sell the Partnership's Property Interests,

<PAGE> 76

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
nonoperating 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 the Partnership's
companion Pension Partnership does not approve its proposal to liquidate and
sell its Property Interests, and the Managing General Partner continues as the
manager of that partnership, then it is possible but not certain that the
Partnership's Property Interest might be sold under the terms set out in the
Proposal. If one of the two partnerships does not approve its proposal, then the
Managing General Partner will advise the limited partners or interest holders
accordingly.

If the Limited Partners of the Partnership do not vote in favor of the
Proposal, then it is likely that the Partnership will continue operations and
will produce its reserves until depletion with steadily decreasing rates of cash
flow and consequently steadily decreasing amounts of cash distributions to the
Limited Partners.

STEPS TO IMPLEMENT THE PROPOSAL

Following the approval of the Proposal and the companion Pension
Partnership's approval of its similar proposal, the Managing General Partner
intends to take the following steps to implement the Proposal:

1. Pay the purchase price of the Property Interests, transfer the
Partnership's Property Interests to the companion Pension
Partnership, and execute assignments and other instruments to
accomplish such sale (including documents to be executed together
with the Partnership's companion Pension Partnership).

2. Pay or provide for payment of the Partnership's liabilities and
obligations to creditors, if any, using the Partnership's cash on
hand and sales proceeds;

3. Conduct a final accounting in accordance with the Partnership
Agreement and make a final liquidating distribution;

4. Cause final Partnership tax returns to be prepared and filed with
the Internal Revenue Service and appropriate state taxing
authorities;

5. Distribute to the Limited Partners final Form K-1 tax
information; and

6. File a Certificate of Cancellation on behalf of the Partnership
with the Secretary of State of the State of Texas.

Estimated Selling Costs. The expenses associated with the sale of the
Partnership's Property Interests are expected to be approximately 3% of the Fair
Market Value of the Partnership's 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 Proposal and related transactions will be met
through the normal ongoing fee set out in the Partnership's Limited Partnership
Agreement. See "Voting on the Proposal--Solicitation."

<PAGE> 77

IMPACT ON THE MANAGING GENERAL PARTNER

The Managing General Partner will purchase the Partnership's Property
Interests if the Proposal is approved and a similar proposal is approved by the
Partnership's companion Pension Partnership. To the extent of its ownership of
Units, liquidation will have the same effect on it as on the Limited Partners.
See "The Proposal--Estimates of Liquidating Distribution Amount." Additionally,
by purchasing the Partnership's Property Interests itself, the Managing General
Partner will be able to maintain its position as operator of many of the
properties in which the Partnership owns an interest and for which it will
continue to receive operating fees. The sale of the Partnership's Property
Interests to the Managing General Partner will have no effect or an
inconsequential effect on the Managing General Partner's net book value and net
earnings. However, simultaneously with the Proposal to the Limited Partners of
the Partnership, the Managing General Partner is making a similar proposal to
investors in a number of other limited partnerships organized for the same
purposes between the years 1986 and 1994. If the investors in all of these
partnerships were to 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 the total proved reserves on an
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 Limited Partners, rather
than on the basis of the direct economic impact on the Managing General Partner.

RECOMMENDATION OF THE MANAGING GENERAL PARTNER

For the foregoing reasons, the Managing General Partner believes that
it is in the best interests of the Limited Partners to dissolve and liquidate
the Partnership. Liquidation will allow the Limited Partners to receive the
remaining value of Partnership reserves currently, rather than receiving
distributions over the remaining life of the Partnership, 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
Partnership's interest in remaining reserves. The Managing General Partner
believes that general improvements over the last several years in the level of
natural gas prices make this an appropriate time to consider the sale of the
Partnership's Property Interest. If operations continue over many years,
revenues will continue to decline while operating and general and administrative
expenses continue, reducing cash distributions. Continued operations also mean
continuation of the additional costs incurred by the Limited Partners, including
the costs associated with inclusion of information from the Schedule K-1
relating to the Partnership in their personal income tax returns, while reserves
continue to decline. Termination of the Partnership will allow preparation of a
final tax return, and certain additional deductions may be generated in
connection with this termination.

THE MANAGING GENERAL PARTNER RECOMMENDS THAT THE
LIMITED PARTNERS VOTE FOR THE PROPOSAL.

FEDERAL INCOME TAX CONSEQUENCES

GENERAL

<PAGE> 78

may occur. Statements of legal conclusions regarding tax consequences are based
upon relevant provisions of the Internal Revenue Code of 1986, as amended (the
"Code"), and accompanying Treasury Regulations, as in effect on the date hereof,
upon reported judicial decisions and published positions of the Internal Revenue
Service (the "Service"), and upon further assumptions that the 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 Limited
Partners.

This summary does not describe all the tax aspects which may affect
Limited Partners because the tax consequences may vary depending upon the
individual circumstances of a Limited Partner. It is generally directed to
individual Limited Partners who are original purchasers of the Units and hold
interests in the Partnership as "capital assets" (generally, property held for
investment). Each Limited Partner 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

Limited Partners will realize and recognize gain or loss, or a
combination of both, upon the 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
the Partnership and allocated to the Limited Partner (i.e., cash or
consideration received) over the Limited Partner'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 Limited Partner's
tax basis over the amount realized by the Partnership for such property and
allocated to the Limited Partner. No gain or loss is expected to be realized on
property acquired from the Pension Partnership and immediately sold by the
Partnership to the Managing General Partner. It is projected that taxable gain
will be realized upon the sale of Partnership properties (other than those
acquired from the Pension Partnership) and that such gain will be allocated
among the Limited Partners in accordance with the Partnership Agreement. The
Partnership Agreement includes an allocation provision that requires 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.

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 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 Partnership did not
incur material amounts of intangible drilling and development costs, and
accordingly the recapture of same is not expected to be material.

<PAGE> 79

the net Partnership 1231 gains or losses must be netted with that Limited
Partner's individual section 1231 gains and losses recognized during the year in
order to determine the character of such net gains or net losses under section
1231. Net gains will be treated as capital gains except to the extent
recharacterized as ordinary income due to recapture and net losses will be
treated as ordinary losses.

LIQUIDATION OF THE PARTNERSHIP

After sale of its properties, the Partnership's assets will consist
solely of cash which it will distribute to its partners in complete liquidation.
The Partnership will not realize gain or loss upon such distribution of cash to
its partners in liquidation. If the amount of cash distributed to a Limited
Partner in liquidation is less than such Limited Partner's adjusted tax basis in
his Partnership interest, the Limited Partner will realize and recognize a
capital loss to the extent of the excess. If the amount of cash distributed is
greater than such Limited Partner's adjusted tax basis in his Partnership
interest, the Limited Partner will recognize a capital gain to the extent of the
excess. Because each Limited Partner 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 Limited Partners
will be less than such Limited Partners' bases in their Partnership interests
and thusly 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 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 Limited Partner'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 Limited Partner 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.

PASSIVE LOSS LIMITATIONS

A Limited Partner'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 Limited Partner'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 the Partnership will terminate the Limited
Partner's interest in the passive activity, a Limited Partner's allocable share
of any loss (i) previously realized as a Limited Partner in the Partnership and
suspended because of its passive characterization, (ii) realized on the
liquidating sale of Partnership properties, or (iii) realized by the Limited
Partner upon liquidation of his Partnership interest, will not be characterized
as losses from a passive activity.

<PAGE> 80

CONSEQUENCES TO IT OF THE SALE OF PROPERTIES AND THE LIQUIDATION OF THE
PARTNERSHIP.

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.

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 attached report,
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 the Limited
Partners. 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
Proxy Statement.

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.

THE MANAGING GENERAL PARTNER

Subject to certain limitations set forth in the Partnership Agreement,
the Managing General Partner has full, exclusive and complete discretion in the
management and control of the business of the Partnership. The Managing General
Partner has general liability for the debts and obligations of the Partnership.

<PAGE> 81

income and pension partnerships. The Managing General Partner's common stock is
traded on the New York and Pacific Stock Exchanges.

The principal executive offices of the Managing General Partner are
located at 16825 Northchase Drive, Suite 400, Houston, Texas 77060, telephone
number (281) 874-2700.

TRANSACTIONS BETWEEN THE MANAGING GENERAL PARTNER AND THE PARTNERSHIP

The Managing General Partner receives operating fees for wells in which
the Partnership has a working interest 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 working
interest. The Managing General Partner believes that it will be positively
affected, on the other hand, by liquidation of the Partnership, on the basis of
its ownership interest in the Partnership. See "The Proposal--Estimates of
Liquidating Distribution Amount," and "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 partnership interest or limited partnership
interests it has purchased. 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.

o The Managing General Partner receives per-well monthly
operating fees from the Partnership for 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
Limited Partner capital contributions to the Partnership
relative to limited partner or interest holder contributions
of all partnerships for which the Managing General Partner
serves as Managing General Partner. Through December 31, 1997,
the Managing General Partner had received $1,093,481 in the
general and administrative overhead allowance.

o The Managing General Partner has been reimbursed $42,650 in
direct expenses, all of which was billed by, and then paid
directly to, third party vendors.

NO TRADING MARKET

33
<PAGE> 82

Originally 661 Limited Partners invested in the Partnership. Through December
31, 1997, the Managing General Partner has purchased 7,514 Units from Limited
Partners pursuant to the right of presentment. As of April ___, 1998, there were
626 Limited Partners (excluding the Managing General Partner). The Managing
General Partner does not have an obligation to repurchase Limited Partner
interests pursuant to this right of presentment but merely an option to do so
when such interests are presented for repurchase.

PRINCIPAL HOLDERS OF LIMITED PARTNER UNITS

The Managing General Partner holds 9.11% of all outstanding Units of
the Partnership resulting from the purchase of Units from Limited Partners 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.

INCORPORATION OF CERTAIN INFORMATION BY REFERENCE AND ATTACHMENT OF
INFORMATION HERETO

The Partnership's Annual Report on Form 10-K for the year ended
December 31, 1997, is attached hereto and incorporated herein by reference.
Additionally, a reserve report dated February 10, 1998, prepared as of December
31, 1997, and audited by H.J. Gruy and Associates, Inc., is attached hereto
together with the fair market value estimates of J.R. Butler and H.J. Gruy dated
April 17, 1998, and the fair market value estimate of CIBC Oppenheimer dated
April 20, 1998.

GLOSSARY OF TERMS

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.

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.

EBITDA means earnings before interest, taxes and depreciation, depletion and
amortization.

34
<PAGE> 83

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.

MMBTU means million British Thermal Units, which is a heating equivalent measure
for natural gas.

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, the Partnership receives a Net Profits Interest entitling
it to a specified percentage of the aggregate Gross Proceeds generated by, less
the aggregate operating costs attributable to, those depths of all Producing
Properties acquired pursuant to such agreement that are evaluated at the
respective dates of acquisition to contain Proved Reserves, to the extent such
depths underlie specified surface acreage.

NP/OR AGREEMENT OR NET PROFITS AGREEMENT means the form of Net Profits and
Overriding Royalty Interest Agreement or Net Profits Agreement entered into
between the Partnership, as operator, and a Pension Partnership pursuant to
which the Pension Partnership acquired a Net Profits Interest, or in certain
instances various Overriding Royalty Interests, from the Partnership in a group
of Producing Properties. The Working Interest in such group of properties is
held by the Partnership.

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, or containing shut-in wells capable of such
production, or properties which are acquired as an incidental part of the
acquisition of such properties. 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.

35
<PAGE> 84

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.

OTHER BUSINESS

The Managing General Partner does not intend to bring any other
business before the Meeting and has not been informed that any other matters are
to be presented at the Meeting by any other person.

SWIFT ENERGY COMPANY
as Managing General Partner of
SWIFT ENERGY INCOME PARTNERS
1989-B, LTD.

-------------------------------------
John R. Alden
Secretary

36
<PAGE> 85

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:

<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
--------------------------------- --------------------

IF LIMITED PARTNERSHIP UNITS ARE HELD JOINTLY, ALL JOINT TENANTS MUST SIGN.

<PAGE> 86

May ___, 1998
Dear Interest Holder:

As your Managing General Partner, Swift Energy Company believes that
the time has come to dissolve and liquidate the Partnership. Enclosed is a proxy
statement and related information pertaining to a proposal for the ultimate sale
of substantially all of the 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 fair
market value estimates of three independent appraisers, consisting of two
petroleum engineering firms and one investment banking firm, plus a premium of
7.5% above Fair Market Value. In order for the sale and liquidation to take
place, Interest Holders holding more than 50% of the outstanding SDIs 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 sale and liquidation for a number of reasons. See "The
Proposal--Reasons for the Proposal" and "--Recommendation of the Managing
General Partner."

Swift Energy Pension Partners 1993-B, Ltd. has been in existence for
almost five years, and most of the properties underlying its net profits
interest were purchased by October 1993. Limited capital is available for
enhancement or development activities on the properties in which the Partnership
owns non-operating interests. See "The Proposal--Partnership Financial
Performance and Condition." To continue operation of the Partnership means that
Partnership direct and administrative expenses (such as costs of audits, reserve
reports, Securities Exchange Commission filings, and tax returns), 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 Interest Holders. 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 Interest Holders
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 make this an appropriate time for the Interest
Holders to consider the sale of the Partnership's Property Interests, which also
increases the likelihood of maximizing the value of the Partnership's assets.

If Interest Holders holding more than 50% of the SDIs of the
Partnership approve this proposal and the interest holders of the Partnership's
companion Operating Partnership approve a similar proposal, the sale of the
Partnership's Property Interests to the Managing General Partner will be made by
the end of the third quarter of 1998.

Included in this package are the most recent financial and other
information prepared regarding the Partnership. If you need any further material
or have questions regarding this proposal, please feel free to contact the
Managing General Partner at (800) 777-2750.

SWIFT ENERGY COMPANY,
Managing General Partner

A. Earl Swift
Chairman

<PAGE> 87

THIS TRANSACTION HAS NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION ("COMMISSION") NOR HAS THE COMMISSION PASSED UPON THE
FAIRNESS OR THE MERITS OF SUCH TRANSACTION NOR UPON THE ACCURACY OR ADEQUACY OF
THE INFORMATION CONTAINED IN THIS DOCUMENT. ANY REPRESENTATION TO THE CONTRARY
IS UNLAWFUL.

DOCUMENTS INCLUDED

The Partnership's Annual Report on Form 10-K for the year ended
December 31, 1997 is included with this Proxy Statement and incorporated herein
by reference. See "Incorporation of Certain Information By Reference and
Attachment of Such Information Hereto." Additionally, a reserve report dated
February 10, 1998, prepared as of December 31, 1997, and audited by H.J. Gruy
and Associates, Inc., is attached hereto together with the fair market value
estimates of J.R. Butler and H.J. Gruy dated April 17, 1998, and the fair market
value estimate of CIBC Oppenheimer dated April 20, 1998.

TABLE OF CONTENTS

<S> <C>
SUMMARY .........................................................................................................1
General ................................................................................................1
Partnership Property Interests...........................................................................1
Proposed Sale of Partnership Properties..................................................................2

SPECIAL FACTORS...................................................................................................3
Partnership Property Interests...........................................................................3
Vote for Liquidation and Proposed Sale of Partnership Property Interests
to the Managing General Partner.........................................................................3
Independent Appraisal of the Fair Market Value of Partnership Property Interests.........................4
Fairness of Proposed Sale...............................................................................15
Consideration of Alternative Transactions...............................................................15
Federal Income Tax Consequences.........................................................................17
Managing General Partner Benefits.......................................................................17

VOTING ON THE PROPOSAL...........................................................................................19
Vote Required...........................................................................................19
Proxies; Revocation.....................................................................................19
No Appraisal or Dissenters' Rights Provided.............................................................19
Solicitation............................................................................................19

RISK FACTORS.....................................................................................................20
Conflicts of Interest in Purchase of Property Interests by Managing General Partner.....................20
Timing of Sale and Price Volatility.....................................................................20
Dependence on Vote of Companion Partnership.............................................................20
Possible Increase in Value of Property Interests Due to Drilling Activity after the Sale................21
Possible Decrease in Distributions to Interest Holders Due to Interim Production........................21

THE PROPOSAL.....................................................................................................21
General ...............................................................................................21
Partnership Financial Performance and Condition.........................................................22
Estimates of Liquidating Distribution Amount............................................................25
</TABLE>

<PAGE> 88

<TABLE>

<S> <C>
Comparison of Sale Versus Continuing Operations.........................................................27
Reasons for the Proposal................................................................................28
Simultaneous Proposal to Companion Partnership..........................................................29
Steps to Implement the Proposal.........................................................................29
Impact on the Managing General Partner..................................................................30
Recommendation of the Managing General Partner..........................................................30

FEDERAL INCOME TAX CONSEQUENCES..................................................................................31
General ...............................................................................................31
Tax Treatment of Tax Exempt Plans.......................................................................31
Tax Treatment of Interest Holders Subject to Federal Income Tax Due to Debt-financing...................32
Taxable Gain or Loss Upon Sale of Properties............................................................33
Liquidation of the Partnership..........................................................................33
Capital Gains Tax.......................................................................................34
Passive Loss Limitations................................................................................34

BUSINESS OF THE PARTNERSHIP......................................................................................34
Reserves ...............................................................................................34
The Managing General Partner............................................................................35
Transactions Between the Managing General Partner and the Partnership...................................35
No Trading Market.......................................................................................36
Principal Holders of Interest Holder SDIs...............................................................36
Approvals...............................................................................................37
Legal Proceedings.......................................................................................37

INCORPORATION OF CERTAIN INFORMATION BY REFERENCE
AND ATTACHMENT OF INFORMATION HERETO............................................................................37

GLOSSARY OF TERMS................................................................................................37

OTHER BUSINESS...................................................................................................39

FORM OF PROXY...................................................................................................F-1

</TABLE>

<PAGE> 89

SWIFT ENERGY PENSION PARTNERS 1993-B, LTD.
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060
(281) 874-2700

NOTICE OF SPECIAL MEETING OF INTEREST HOLDERS
TO BE HELD JUNE ___, 1998

Notice is hereby given that a special meeting of interest holders of
Swift Energy Pension Partners 1993-B, Ltd. (the "Partnership") will be held at
16825 Northchase Drive, Houston, Texas, on Tuesday, June ___, 1998 at 4:00 p.m.
Central Time to consider and vote upon:

A record of interest holders of the Partnership has been taken as of
the close of business on April ___, 1998, and only interest holders of record on
that date will be entitled to notice of and to vote at the meeting, or any
adjournment thereof.

SWIFT ENERGY COMPANY,
Managing General Partner

JOHN R. ALDEN
Secretary
May ____, 1998

<PAGE> 90

SWIFT ENERGY PENSION PARTNERS 1993-B, LTD.
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060-9468
(281) 874-2700

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

PROXY STATEMENT

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

SUMMARY

GENERAL

This Proxy Statement is being provided by Swift Energy Company, a Texas
corporation (the "Managing General Partner" or "Swift") in its capacity as the
Managing General Partner of Swift Energy Pension Partners 1993-B, Ltd. a Texas
limited partnership (the "Partnership"), to holders of depositary interests
representing an initial investment of $1.00 per SDI in the Partnership (the
"SDIs"). This Proxy Statement and the enclosed proxy are provided for use at a
special meeting of interest holders (the "Interest Holders"), and any
adjournment of such meeting (the "Meeting") to be held at 16825 Northchase
Drive, Houston, Texas, at 4:00 p.m. Central Time on June ___, 1998. The Meeting
is called for the purpose of considering and voting upon a proposal to
indirectly sell substantially all of the assets of the Partnership to the
Managing General Partner and dissolve, wind up and terminate the Partnership
(the "Proposal"), in accordance with the terms and provisions of the
Partnership's Limited Partnership Agreement dated June 30, 1993 (the
"Partnership Agreement"), and the Texas Revised Limited Partnership Act (the
"Texas Act"). This Proxy Statement and the enclosed proxy are first being mailed
to Interest Holders on or about May ____, 1998.

Under the Partnership Agreement, the affirmative vote of Interest
Holders holding more than 50% of the SDIs then held by Interest Holders as of
the Record Date (as defined) is required for approval of the Proposal. Each
Interest Holder appearing on the Partnership's records as of April ___, 1998
(the "Record Date"), is entitled to notice of the Meeting and is entitled to one
vote for each SDI held by such Interest Holder. Under the Partnership Agreement,
the General Partners may not vote any SDIs owned by them for matters such as the
Proposal. VJM Corporation, a California corporation, the Special General Partner
of the Partnership, owns a 0.75% interest in the Partnership as a General
Partner, but owns no SDIs. The Managing General Partner has owned a 14.25%
general partner's interest in the Partnership since its inception, in addition
to ownership of 2.58% of all outstanding SDIs resulting from its purchase of
SDIs from Interest Holders under their right of presentment. Therefore, the
affirmative vote of holders of more than 50% of the remaining SDIs is required
to approve the proposed sale.

PARTNERSHIP PROPERTY INTERESTS

<PAGE> 91

If the Proposal is approved by Interest Holders, and if a similar
proposal to the interest holders of the Operating Partnership is approved, then
it is anticipated that the Partnership will convey its net profits interest to
the Operating Partnership for cash, and then the underlying properties would be
sold to the Managing General Partner by the Operating Partnership. If approved,
it is anticipated that the sale of the Partnership's Property Interest will be
made by the end of the third quarter of 1998. The sale of Partnership Property
Interests will cause the Partnership to dissolve automatically under the terms
of the Partnership Agreement and the Texas Act and its affairs would then be
wound up and the Partnership terminated. Currently there are no third party
buyers for the Property Interests.

For more information about the Partnership's Property Interests and
recent financial performance, see the attached Annual Report on Form 10-K for
the year ended December 31, 1997.

PROPOSED SALE OF PARTNERSHIP PROPERTIES

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 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, has been asked to approve
the selection of the three independent third party appraisers (the "Appraisers")
chosen to estimate the fair market value of the Partnership's Property
Interests, which is the price, plus a premium of 7.5% above such fair market
value, at which such Property Interests would be sold. The Special Transactions
Committee has 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 methodology used by the Appraisers in estimating the fair market
value is discussed below under "Special Factors--Independent Appraisal of the
Fair Market Value of Partnership Property Interests." The Managing General
Partner believes that using this methodology to estimate the fair market value
at which the Property Interests will be purchased from the Partnership is fair
to Interest Holders, as discussed in detail under "Special Factors--Fairness of
Proposed Sale." Also discussed under "The Proposal--Reasons for the Proposal"
are the reasons for proposing the sale of such Property Interests and
liquidation of the Partnership at this time. A discussion of the alternatives to
such sale and liquidation which were considered is contained under "Special
Factors--Consideration of Alternative Transaction." In addition to the
foregoing, there are certain risks involved in the Proposal. See "Risk Factors."

In order to allow Interest Holders 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 Managing General Partner will
offer to Interest Holders and limited partners or interest holders of other
partnerships which approve similar proposals the opportunity to purchase on a
collective basis up to 2.5 million shares of common stock of Swift Energy
Company directly from Swift Energy Company. Such shares of common stock will be
offered at a price based upon the then current market price for Swift common
stock on the New York Stock Exchange once the voting is completed by all of the
investors in multiple partnerships managed by the Managing General Partner.
Interest Holders will have the discretion to choose the amount, if any, of Swift
common stock they desire to purchase, provided that they purchase at least 100
shares.

<PAGE> 92

SPECIAL FACTORS

PARTNERSHIP PROPERTY INTERESTS

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 operator, 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, 13 of such fields each comprise less than 1% of the Partnership's
PV-10 Value at December 31, 1997, and the PV-10 Value of each of the other ten
fields average less than 3% of the Partnership's PV-10 Value at the same date.

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

43% 26% 31%
% of 12/31/97 PV-10 Value

% of 1997 Production (Volumes) 23% 45% 32%
</TABLE>

VOTE FOR LIQUIDATION AND PROPOSED SALE OF PARTNERSHIP PROPERTY INTERESTS TO THE
MANAGING GENERAL PARTNER

If approved by Interest Holders holding a majority of the SDIs, and
assuming approval by the Partnership's companion Operating Partnership of the
sale of substantially all of that partnership's assets, the Proposal described
above to sell substantially all of the Partnership's assets and subsequently to
dissolve and terminate the Partnership ultimately will result in the sale to the
Managing General Partner, of the Partnership's Property Interests for
$1,427,367, which is comprised of the Fair Market Value plus the 7.5% premium
above such value. This sale of the Partnership's Property Interests is being
proposed for Interest Holder approval in an attempt to realize the highest value
for its Property Interests.

The reasons for proposing the sale of the Partnership's Property
Interests at this time are described in detail under "The Proposal--Reasons for
the Proposal." In summary, these reasons include: (i) the steadily declining
levels of revenues from the Partnership's Property Interests and matching lower
levels

<PAGE> 93

of cash distributions to Interest Holders; (ii) the inherent decline in
production from proved producing reserves in combination with the absence of any
further capital expenditures on the properties in which the Partnership has a
Property Interest; (iii) the continuation of fairly steady levels of certain
fixed oil field overhead and operating costs ($47,299 in 1997), without regard
to the level of production and continued direct costs (audits, reserve reports,
Securities and Exchange Commission filings, and tax returns) incurred each year
($22,838 in 1997).

Although at December 31, 1997, it was estimated that approximately 44%
of the estimated ultimate recoverable reserves in which the Partnership has an
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 by the working interest owners for the drilling
of new wells to recover such reserves. 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. The levels of cash flow from these
properties from sale of production, 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. Because of the large quantity of nonproducing
reserves, the purchase price an unrelated third party is willing to pay for
these Property Interests is likely to be discounted heavily. Lastly, additional
capital to drill wells to produce undeveloped reserves is not available from the
Partnership or the other third party owners of interests in the same wells. The
Partnership expended its funds within the first or second year after its
organization, as did its companion Operating Partnership.

The Managing General Partner believes that improvements over the last
several years in the level of natural gas prices make this an appropriate time
to consider the sale of the Partnership's Property Interests, because it
increases the likelihood of maximizing the value of the Partnership's assets. By
selling its Property Interests and liquidating the Partnership, future overhead
and direct and general and administrative costs will be avoided and revenues can
be accelerated. Future revenues and cash distributions to Interest Holders will
not be subjected 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.

INDEPENDENT APPRAISAL OF THE FAIR MARKET VALUE OF PARTNERSHIP PROPERTY INTERESTS

The Special Transactions Committee determined that having three
independent appraisers collectively determine the fair market value for a
purchase of the Partnership's Property Interests would protect Interest Holders
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.

<PAGE> 94

The Managing General Partner did not instruct the Appraisers as to
pricing, cost or other economic parameters or methods or the assessment of
reserves characteristics, nor did it limit the scope of their investigation for
purposes of preparing their appraisals. The Managing General Partner provided
the Petroleum Engineering Consultants with basic evaluation data for their use
in determining Partnership 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 Partnership for its Property Interests nor provide any information to the
Appraisers on amounts to be paid to the Interest Holders. 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 Interest Holders, and the Managing General Partner has not acquired a
separate report or opinion regarding the fairness to the Interest Holders of the
price at which the Partnership's Property Interests will be sold to the Managing
General Partner if the Proposal is approved by the Interest Holders.

QUALIFICATIONS OF APPRAISERS

H.J. Gruy and Associates, Inc. is an established independent petroleum
engineering firm in Houston, Texas. H.J. 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. H.J. Gruy has extensive experience evaluating
properties in all of the areas in which the Partnership owns Property Interests.
H.J. 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 Corp., a CIBC World Markets Company, is an
internationally recognized investment banking firm with 31 offices worldwide and
over 8,000 employees. CIBC Oppenheimer was

<PAGE> 95

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

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. The valuation estimates of the Appraisers are
attached to this Proxy Statement 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 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
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 Property Interests. As a result
of their individual and collective work, the Petroleum Engineering Consultants
estimated a fair market valuation for each property in which the Partnership has
a Property Interest, and CIBC Oppenheimer estimated a fair market valuation for
each such property. After presentation of the two valuation estimates to the
Special Transactions Committee, the committee determined that the Fair Market
Value of any given Property Interest 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

<PAGE> 96

for the risk associated with the purchase of that cash flow stream. For proved
developed non-producing and proved undeveloped reserves, the risk adjustments
are generally more severe for a variety of reasons, including the necessity of
making a capital investment when it is assumed that the capital is invested with
certainty and the resulting operating cash income stream is burdened with the
uncertainty.

Basic evaluation data used by the Petroleum Engineering Consultants,
including 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.

<PAGE> 97

EVALUATION PROCEDURES

In summary, the evaluation procedures used by the Petroleum Engineering
Consultants included:

o Reviewing technical and economic data presented by the
Managing General Partner relative to the Partnership's proved,
probable and possible reserves as of December 31, 1997.

o Examining the Partnership's cash flow forecasts for its
quantified probable and possible reserves.

o Reviewing the Partnership's lease operating costs for
reasonableness.

VALUATION BY CIBC OPPENHEIMER

In performing its analysis of the value of the Partnership's Property
Interests, CIBC Oppenheimer first reviewed the PV-10 Value at December 31, 1997
for each property to be purchased in which the Partnership has a Property
Interest (a "Field"). In addition, CIBC Oppenheimer reviewed the valuation
estimates prepared by the Petroleum Engineering Consultants for each Field.
Individual partnerships own Property Interests in a number of different Fields.
Therefore, CIBC Oppenheimer first focused upon valuing the individual Fields and
then subsequently valuing the Property Interests of each Partnership in various
Fields by allocating to each Partnership its relevant share of the value
attributable to different Fields in which it has a property interest.

Working with the Petroleum Engineering Consultants, CIBC Oppenheimer
reviewed the Fields for characteristics which would allow them to be divided
into separate classifications. Of the total of 44 Fields, the reserves of 34
Fields were determined to be comprised primarily of Proved Developed Producing
reserves ("PDP") which have comparable reserve characteristics ("Conventional
Case"). The remaining 10 Fields were determined to have distinguishing or unique
reserve 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 Fields 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 equivalents 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.

<PAGE> 98

The Valuation Multiples determined for the Fields in the Conventional
Case group and the Non-Conventional Case group were unique, reflecting the
different reserve 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 Field. Each
Partnership was allotted its respective proportionate share of individual Fields
("Field Share") based upon the Partnership's Property Interest in such Field, in
order to convert the value determined for the Fields into values for an
individual Partnership's Property Interest in each Field. The CIBC Oppenheimer
valuation estimate for each individual Partnership is the cumulative total of
that Partnership's respective Field 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 Partnership owns 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

<PAGE> 99

involving publicly traded oil and gas companies engaged in oil and gas
exploration and production activities that were deemed by CIBC Oppenheimer to
operate in comparable producing basins or have comparable financial and
operating characteristics to the Managing General Partner.

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 Partnership's 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 Fields 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 Field's PV-10 Value. This reference value reflects a slight
discount to the average adjusted 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 Fields
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

<PAGE> 100

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 Fields are near the
end of their economic lives. The degree of this discount was reduced, however,
by the fact that the Fields 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 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 Fields 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.

VALUATION LETTER OF CIBC OPPENHEIMER

The Special Transactions Committee retained CIBC Oppenheimer to prepare
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 a letter (the "Valuation
Letter") stating that, as of such 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 was $1,327,783.

The full text of the Valuation Letter, which sets forth the assumptions
made, matters considered, and qualifications and limitations on the review
undertaken by CIBC Oppenheimer, is attached hereto and is incorporated herein by
reference. The summary of the Valuation Letter set forth in this Proxy Statement
is qualified in its entirety by reference to the full text of such letter.
Interest Holders of the Partnership are urged to read such letter in its
entirety. The Valuation Letter was provided to the Special Transactions
Committee for its information and is directed only to the estimate, from a
financial point of view, of the value of the Partnership's Property Interests
and does not address the merits of the underlying decision by the Managing
General Partner or the Partnership to engage in the sale of the Property
Interests to the Managing General Partner and does not constitute a
recommendation to the Partnership's Interest Holders as to how such Interest
Holders should vote on the approval of the Proposal or any matter related
thereto.

<PAGE> 101

COLLECTIVE ANALYSIS OF PURCHASE PRICE; PREMIUM OVER FAIR MARKET VALUE

<PAGE> 102

Engineering Consultants. CIBC Oppenheimer then divided the Fields into two
categories. Those fields with reserves consisting primarily of proved developed
producing reserves were placed in the "Conventional Case" category. Those Fields
with significant proved developed non-producing or undeveloped reserves were
placed in the "Non-Conventional Case" category. CIBC Oppenheimer then valued
each Field by applying the multiples discussed above to each Field's PV-10
Value, proved reserves on a BOE basis, and projected 1998 EBIDTA. A separate set
of multiples was used for Fields in the Conventional Case category and the
Non-Conventional Case category, respectively. This provided CIBC Oppenheimer
with three estimated values for each Field. The average of these three values
yielded CIBC Oppenheimer's estimation of the fair market value of each Field.
CIBC Oppenheimer then allocated the appropriate portion of the Field's estimated
fair market value to the Partnership based upon the Partnership's Property
Interest in each Field. The result of this analysis by CIBC Oppenheimer was an
estimation that fair market value of the Partnership's Property Interests was
$1,327,783 on December 31, 1997. The Special Transactions Committee has
determined that, in keeping with the definition of Fair Market Value, the higher
of these two estimations of fair market value, or $1,327,783, represents the
Fair Market Value of the Partnership's Property Interests. In the judgment of
Swift Energy 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
Swift 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 Swift,
Swift 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.

PRIOR RELATIONSHIPS BETWEEN THE APPRAISERS, THE PARTNERSHIP AND THE MANAGING
GENERAL PARTNER

H.J. Gruy has audited the reserve evaluations for both the Partnership,
other partnerships managed by the Managing General Partner, and the Managing
General Partner itself since their respective inceptions. H.J. Gruy has been
paid less than $700 over the most recent two fiscal years by the Partnership,
and approximately $72,300 over the past two years by the Managing General
Partner and its affiliates. 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 Partnership) 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 the Partnership. 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 Partnership, and the Appraisers' compensation is not contingent upon the
results of their fair market value opinions resulting from their review of the
Partnership properties.

In preparing their 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.

<PAGE> 103

FAIRNESS OF PROPOSED SALE

The Managing General Partner believes that this proposed method of sale
of the Partnership's Property Interests is fair to Interest Holders 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 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 ultimately proposed to be paid by the Managing General
Partner for the Partnership's Property Interest(s) (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 Interest Holders holding more than 50% of the SDIs, without
the Managing General Partner voting any limited partnership
interests in the Partnership which it owns.

3. The Special Transactions Committee has made the determination
as to the retention of the Appraisers and approved the fair
market value estimates provided by the Appraisers, which the
Special Transactions Committee then recommended for adoption
by the Board of Directors of the Managing General Partner. The
Special Transactions Committee is comprised solely of
independent directors of the Managing General Partner.

4. If the Proposal is approved by Interest Holders and the
Property Interests ultimately are purchased by the Managing
General Partner, it is likely that the Managing General
Partner will expend the capital necessary to bring various
nonproducing reserves into production.

In order to allow Interest Holders 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 Managing General Partner will
offer to limited partners or interest holders of partnerships which approve
similar proposals the opportunity to purchase on a collective basis up to 2.5
million shares of common stock of Swift Energy Company directly from Swift
Energy Company. Such shares of common stock will be offered at a price based
upon the then current market price for Swift common stock on the New York Stock
Exchange once the voting is completed by all of the investors in multiple
partnerships managed by the Managing General Partner. Interest Holders will have
the discretion to choose the amount, if any, of Swift common stock they desire
to purchase, provided that they purchase at least 100 shares. There is no
requirement that any such purchase of Swift's common stock be made, and any such
offer is made solely by means of a separate prospectus of Swift Energy Company
included with this proxy statement.

CONSIDERATION OF ALTERNATIVE TRANSACTIONS

The Managing General Partner has given consideration to a number of
different alternatives prior to submitting the Proposal to Interest Holders for
their approval. These alternatives included continued operation of the
properties for a longer period, offering the Partnership's remaining property
interests at

<PAGE> 104

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 Partnership. 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 Partnership's Property Interests, as discussed
below.

AUCTION

o Approximately 59% of the proved reserves value attributed to
the Partnership's Property Interests represents 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.

<PAGE> 105

NEGOTIATED SALE

Many of the same factors discussed above affect whether the Partnership
would benefit from attempting to sell its Property Interests in negotiated
transactions.

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 Partnership's interests therein over several years.

The proposed sale of the Partnership's 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 Partnership's 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
Partnership's Interest Holders 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

MANAGING GENERAL PARTNER BENEFITS

The Managing General Partner will share the benefits available to
Interest Holders through liquidating its partnership interests and receiving the
current value of those interests as a result of such sales. Additionally, by
purchasing the Partnership's Property Interests itself, the Managing General
Partner will continue to serve as operator of many of the properties in which
the Partnership owns an interest and will continue to receive operating fees.
The sale of the Partnership's Property Interests to the Managing General Partner
will have no effect or an inconsequential effect on the Managing General
Partner's net book value and net earnings. Simultaneously with the proposal to
the Interest Holders of the Partnership,

<PAGE> 106

the Managing General Partner is making a similar proposal to investors in a
number of other limited partnerships organized for the same purposes between the
years 1986 and 1994. If the investors in all of these partnerships were to
approve the proposal 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 the total proved reserves on an
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 PROPOSAL INVOLVES CERTAIN RISKS. SEE "RISK FACTORS."

o There is no guarantee that the fair market value estimates of the
independent Appraisers represents the highest possible price that might
be received for the Partnership's Property Interests in all
circumstances. This price 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 would purchase the Partnership's Property
Interests has been 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 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
Interest Holders receiving higher distributions from continued
operations of the Partnership, although inherent geological,
engineering, and operational risks would continue.

o It is likely that if the Proposal is approved by Interest Holders and
the Partnership's Property Interests are transferred to the Managing
General Partner, the Managing General Partner will further develop
those properties by spending required capital on recovery of
behind-pipe reserves or developing undeveloped reserves. Interest
Holders will not share in any possible improvement of cash flow from
such properties. The Managing General Partner will provide an
opportunity for Interest Holders to purchase stock of Swift Energy
Company on a direct basis so that they might share in any such
improvement.

If the Proposal is not approved by Interest Holders holding more than
50% of the SDIs then held by Interest Holders and a similar proposal is not also
approved by the required vote of the limited partners or interest holders of the
Partnership's companion Operating Partnership, the Partnership will continue to
exist.

INTEREST HOLDERS ARE URGED TO COMPLETE, SIGN AND DATE THE ENCLOSED
PROXY AND TO RETURN IT TO THE MANAGING GENERAL PARTNER NO LATER
THAN JUNE _____, 1998.

<PAGE> 107

VOTING ON THE PROPOSAL

VOTE REQUIRED

According to the terms of the Partnership Agreement, approval of the
Proposal requires the affirmative vote by the holders of more than 50% of the
SDIs held by Interest Holders. Therefore, an abstention by an Interest Holder
will have the same effect as a vote against the Proposal. This solicitation is
being made for votes in favor of the Proposal (which will result in liquidation
and dissolution). As of the Record Date, 6,076,102.00 SDIs were outstanding and
were held of record by 559 Interest Holders (excluding the Managing General
Partner's SDIs). Each Interest Holder is entitled to one vote for each SDI held
in its name on the Record Date. Accordingly, the affirmative vote of holders of
at least 3,038,052 SDIs is required to approve the Proposal. The Managing
General Partner holds 161,000 SDIs, but, in accordance with the Partnership
Agreement, the Managing General Partner may not vote its SDIs. The Managing
General Partner's non-vote, in contrast to abstention by Interest Holders, will
not affect the outcome, because for purposes of adopting the Proposal its SDIs
are excluded from the total number of voting SDIs.

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 included in this Proxy Statement. The
actual proxy to be used to register your vote on the Proposal is the separate
green sheet of paper included with the Proxy Statement. PLEASE USE THE GREEN
PROXY TO VOTE UPON THE PROPOSAL.

If a proxy is properly signed and is not revoked by an Interest Holder,
the SDIs it represents will be voted in accordance with the instructions of the
Interest Holder. If no specific instructions are given, the SDIs will be voted
FOR the Proposal. An Interest Holder may revoke his proxy at any time before it
is voted at the Meeting. Any Interest Holder who attends the Meeting and wishes
to vote in person may revoke his proxy at that time. Otherwise, an Interest
Holder 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 proposal to sell substantially all of the
Partnership's assets and liquidate the Partnership, Interest Holders are not
entitled to any dissenters' or appraisal rights such as would be available to
shareholders in a corporation engaging in a merger. Dissenting Interest Holders
are protected under state law by virtue of the fiduciary duty of general
partners to act with prudence in the business affairs of the Partnership.

SOLICITATION

The solicitation is being made by the Partnership. The Partnership will
bear the costs of the preparation of this Proxy Statement and of the
solicitation of proxies and such costs will be allocated 85% to the Interest
Holders and 15% to the General Partners with respect to their general
partnership interests pursuant to Article IX, Section 9.01 of the Partnership
Agreement. As the Managing General Partner holds approximately 2.58% of the SDIs
held by all Interest Holders, 2.58% of the costs borne by the Interest

<PAGE> 108

Holders 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, if necessary to ensure the
presence of a quorum, solicit proxies in person or by telephone. The Managing
General Partner also may retain a proxy solicitor to assist in contacting
brokers or Interest Holders to encourage the return of proxies, although it does
not anticipate doing so. The expenses associated with the sale of the
Partnership's Property Interests are expected to be approximately 3% of the Fair
Market Value of the Partnership's 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.

RISK FACTORS

An Interest Holder considering whether to vote in favor of the Proposal
should give careful consideration to the risks involved, including those
summarized below:

CONFLICTS OF INTEREST IN PURCHASE OF PROPERTY INTERESTS BY MANAGING GENERAL
PARTNER

If the Proposal is approved by Interest Holders, the Partnership's
Property Interests ultimately would be sold to the Managing General Partner at
the Fair Market Value plus a 7.5% premium, which has been set by the Special
Transactions Committee based on the valuation estimates of the Appraisers. There
is no guarantee that this purchase price represents the highest possible price
that might be received for the Partnership's Property Interest 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 the 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, (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 transactions for the Partnership's
Property Interests, depending upon future prices for either or both of oil and
gas.

DEPENDENCE ON VOTE OF COMPANION PARTNERSHIP

If the Partnership's companion Operating Partnership, does not approve
a similar 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 the
Proposal is approved by Interest Holders, 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 Operating Partnership."
Although the Managing General Partner will attempt to provide a different
approach for sale of the Partnerships' Property Interests, it is possible that
the Partnership's assets may not be sold. If the Proposal is approved by the
Partnership and the Operating Partnership, the entire Property Interests owned
by the Partnership will be sold.

<PAGE> 109

POSSIBLE INCREASE IN VALUE OF PROPERTY INTERESTS DUE TO DRILLING ACTIVITY AFTER
THE SALE

If the Proposal to sell the Partnership's Property Interests is
approved by Interest Holders 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
Partnership's 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 Partnership owns Property Interests could
increase the values of such Property Interests. The Partnership 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
Partnership was 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 Managing General Partner intends to offer common stock in Swift
Energy Company for sale directly to limited partners or interest holders of
partnerships which approve the proposal as a method of sharing in any gains
which might be realized due to such activity.

POSSIBLE DECREASE IN DISTRIBUTIONS TO INTEREST HOLDERS DUE TO INTERIM PRODUCTION

The amounts available for distribution to Interest Holders if the
Proposal is approved are estimated under "The Proposal--Estimates of Liquidating
Distribution Amount." The amounts estimated thereon have been reduced by
estimated cash distributions to Interest Holders 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.

THE PROPOSAL

GENERAL

The Managing General Partner has proposed that the Partnership's
Property Interests be sold, the Partnership be dissolved and that the Managing
General Partner, acting as liquidator, wind up the Partnership's affairs and
make final distributions to its partners. The Partnership's assets consist of a
net profits interest in producing oil and gas properties in which the working
interest is owned by an affiliated partnership also managed by the Managing
General Partner and formed at approximately the same time as the Partnership was
organized. The Partnership's non-operating net profits interest exists by virtue
of a Net Profits Agreement ("Net Profits Agreement") dated June 30, 1993 with
Swift Energy Operating Partners 1993-B, Ltd. (the "Operating Partnership"). The
Net Profits Agreement gives the Partnership a net profits interest in a group of
producing properties in which the Operating Partnership owns the working
interests, and entitles the Partnership to receive a portion of the net profits
from operation of the group of producing properties owned by the Operating
Partnership which are subject to the Net Profits Agreement. The net profits
percentage to which the Partnership is entitled is based upon a percentage of
the gross proceeds (reduced by certain costs) from the sale of oil and gas
production from these properties.

Pursuant to the terms of the Partnership Agreement, the Partnership,
if not terminated earlier, will continue in being through December 31, 2021, at
which point it will terminate automatically.

<PAGE> 110

PARTNERSHIP FINANCIAL PERFORMANCE AND CONDITION

Interest Holders made contributions of $6,237,102, in the aggregate to
the Partnership. The Managing General Partner has made capital contributions
with respect to its general partnership interest of $810,823. Additionally,
pursuant to the presentment right set forth in the Partnership Agreement, it has
purchased 161,000 SDIs from Interest Holders. From inception through January 31,
1998, the Partnership has made cash distributions to its Interest Holders
totaling $2,588,600. Through January 31, 1998, the Managing General Partner has
received cash distributions from the Partnership of $443,409 with respect to its
general partnership interest, and distributions of $31,295 related to the
limited number of SDIs it purchased from Interest Holders. On a per SDI basis,
Interest Holders 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 Partnership's Property Interest was
acquired during the third quarter of 1993 when 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
1993-1997 during which time the Partnership's oil prices in fact averaged $16.48
per barrel and natural gas prices averaged approximately $2.14 per Mcf. A
comparison of gas prices as described in this paragraph appears in the graph
presented below.

<PAGE> 111

[GRAPHS: 2 pages of oil and gas properties info]

22
<PAGE> 112

[GRAPHS: 2 pages of oil and gas properties info]

23
<PAGE> 113

ESTIMATES OF LIQUIDATING 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 cash distributions from January 1, 1998 until
June 30, 1998, resulting in an estimate of the amount of net distributions
available for Interest Holders as a result of such sales.

ESTIMATE OF INTEREST HOLDERS' SHARE OF DISTRIBUTIONS
FROM PROPERTY INTEREST SALES AND LIQUIDATION

<S> <C>
Appraisers' Fair Market Value of Partnership Property Interests(1) $ 1,327,783
(Gross Sales Proceeds) ===================

Interest Holders' Share of Sales Proceeds(2) $ 1,128,616
--------------------
Purchase Premium (7.5% of Fair Market Value)(3) $ 84,646
--------------------
Estimated Selling and Dissolution Expenses(4) $ (33,858)
(3% of the Fair Market Value) --------------------

Net Assets(5) $ 346,260
--------------------
Estimated Interim Cash Distributions(6) $ (202,700)
--------------------
Estimated Net Distributions to Interest Holders $ 1,322,964
====================

ESTIMATED NET DISTRIBUTIONS PER $1.00 SDI $ 0.21
====================
</TABLE>

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

(1) Represents the higher of two values estimated by the Appraisers.

(2) Gross Sales Proceeds amount is allocated 85% to the Interest Holders
pursuant to the Limited Partnership Agreement.

(3) As determined by the Special Transactions Committee.

24
<PAGE> 114

(4) Includes Interest Holders' share of all costs associated with
dissolution and liquidation of the Partnership.

(5) Includes cash and net receivables of the Partnership as of December 31,
1997.

(6) Estimated cash distributions paid to the Interest Holders from January
1, 1998 to June 30, 1998.

If, on the other hand, the Partnership were to retain its Property
Interest and continue to benefit from production of its assets until they have
reached their economic limit, the table below estimates the return to Interest
Holders, 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 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 Operating 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 INTEREST HOLDERS'
NET DISTRIBUTIONS FROM CONTINUED OPERATIONS

PROJECTED
CASH FLOWS
----------
<S> <C>
Estimated Future Net Revenues from Net Profits Interest(1) $ 2,689,779
Estimated Interim Cash Distributions(2) $ (202,700)
Estimated Partnership Direct and Administrative Expenses(3) $ (338,912)
Net Assets(4) $ 346,260
-------------------
Net Distributions to Interest Holders(5) $ 2,494,427
===================

NET DISTRIBUTIONS PER $1.00 SDI $ 0.40
===================
PRESENT VALUE OF NET DISTRIBUTIONS PER $1.00 SDI(6) $ 0.27
===================
</TABLE>

(1) Interest Holders' future net revenues are based on the reserve
estimates at December 31, 1997 using pricing based upon 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 cash distributions paid to the Interest Holders from January
1, 1998 to June 30, 1998.

(3) Includes Interest Holders' share of general and administrative
expenses, and audit, tax, and reserve engineering fees.

25
<PAGE> 115

(4) Includes 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 distribution,
are to be distributed to the Interest Holders 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 Interest Holders for
the reasons discussed in detail under "Special Factors--Fairness of Proposed
Sale."

Based on the above tables, it is estimated that a Interest Holder could
expect to receive $0.21 per $1.00 SDI upon immediate sale of the Partnership
Property Interests. In comparison, it is estimated that an Interest Holder 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 Distribution Amount" above show that estimated cash distributions to
Interest Holders (based on net present value) from continued operations would be
approximately 29% higher than estimated 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 distribution in one lump sum currently. The estimates
of 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 subject Interest Holders to the risk of receiving lower levels of
cash distributions if oil and gas prices over this period are lower on average
than those used in preparing the estimates of cash distributions from continued
operations. Continued operations also subject Interest Holders' potential
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 Interest Holders taking any funds to be
received upon liquidation and redeploying those assets in other investments,
rather than continuing to receive decreasing levels of 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 Partnership Agreement at which the
Managing General Partner can offer to repurchase SDIs from Interest Holders. As
of January 1, 1997, this "SDI Value" was $0.37 per $1.00 SDI. In 1997, the
Interest Holders received cash distributions of $0.08 per $1.00 SDI, and are
estimated to receive another $.03 per $1.00 SDI before June 30, 1998, which
converts to a comparable price of $.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 Interest Holders the SDI Value, and the Interest Holders have the
right to present their SDIs for purchase by the Managing General Partner for the
SDI Value. The SDI Value amount is determined by adding the present value of
proved oil and gas reserves (discounted at 10% per annum) calculated on an
escalated pricing basis

26
<PAGE> 116

to cash and accounts receivable less outstanding debts and obligations of the
Partnership, and then further discounted that result by 30%.

REASONS FOR THE PROPOSAL

The Managing General Partner believes that it is in the best interest
of the Interest Holders for the Partnership to sell its Partnership's 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 oil and gas prices, particularly those for natural
gas, make this an appropriate time to consider the sale of the Partnership's
Property Interests, and increases the likelihood of maximizing the value of the
Partnership's assets, although the future prices and market volatility cannot be
predicted with any accuracy.

Decreasing Cash Flow While Expenses Continue. The Partnership's
underlying interests in oil and gas reserves are expected to continue to decline
as remaining reserves are produced. Declines in well production are based
principally upon the maturity of the wells, not on market factors. These
declines will 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
general and administrative expenses such as 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. Interest Holders will continue to
have a partnership income tax reporting obligation with respect to their SDIs as
long as the Partnership continues to exist. There is no

27
<PAGE> 117

trading market for the SDIs, so Interest Holders 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 properties and dissolution of
the Partnership, Interest Holders will realize gain or loss under federal income
tax laws. Thereafter, Interest Holders will have no further tax reporting
obligations with respect to the Partnership. See "Federal Income Tax
Consequences."

SIMULTANEOUS PROPOSAL TO COMPANION PARTNERSHIP

Simultaneously with the Proposal to Interest Holders to ultimately sell
all of the Partnership's Property Interests, a similar proposal is being made to
the interest holders of the companion Operating Partnership which owns the
working interest in the same properties in which the Partnership owns a
non-operating interest. If the Partnership approves the Proposal, but its
companion partnership does not approve a similar proposal to sell its Property
Interests and liquidate, it is likely to affect the ability of the Partnership
to consummate the sale of its Property Interests. Although the Partnership's
Interest Holders may desire to sell the Partnership's 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 nonoperating
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 the Partnership's
companion Operating Partnership does not approve its proposal to liquidate and
sell its Property Interests, and the Managing General Partner continues as the
manager of that partnership, then it is possible but not certain that the
Partnership's Property Interest might be sold under the terms set out in the
Proposal. If one of the two partnerships does not approve its proposal, then the
Managing General Partner will advise the limited partners or interest holders
accordingly.

If the Interest Holders of the Partnership do not vote in favor of the
Proposal, then it is likely that the Partnership will continue operations and
will produce its reserves until depletion with steadily decreasing rates of cash
flow and consequently steadily decreasing amounts of cash distributions to the
Interest Holders.

STEPS TO IMPLEMENT THE PROPOSAL

1. Pay the purchase price of the Property Interests, transfer the
Partnership's Property Interests to the companion Operating
Partnership, and execute assignments and other instruments to
accomplish such sale (including documents to be executed
together with the Partnership's companion Operating
Partnership).

2. Pay or provide for payment of the Partnership's liabilities
and obligations to creditors, if any, using the Partnership's
cash on hand and sales proceeds;

28
<PAGE> 118

3. Conduct a final accounting in accordance with the Partnership
Agreement and make a final liquidating distribution;

4. Cause final Partnership tax returns to be prepared and filed
with the Internal Revenue Service and appropriate state taxing
authorities;

5. Distribute to the Interest Holders final Form K-1 tax
information; and

6. File a Certificate of Cancellation on behalf of the
Partnership with the Secretary of State of the State of Texas.

Estimated Selling Costs. The expenses associated with the sale of the
Partnership's Property Interests are expected to be approximately 3% of the Fair
Market Value of the Partnership's 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 Proposal and related transactions will be met
through the normal ongoing fee set out in the Partnership's Limited Partnership
Agreement. See "Voting on the Proposal--Solicitation."

Other. Any sale of the Partnership Property Interests and the
subsequent liquidating distributions to the Interest Holders, if any, pursuant
to the Proposal will be taxable transactions under federal and state income tax
laws, even though Interest Holders may not be required to recognize any taxable
income or loss. See "Federal Income Tax Consequences."

IMPACT ON THE MANAGING GENERAL PARTNER

The Managing General Partner will purchase the Partnership's Property
Interests if the Proposal is approved and a similar proposal is approved by the
Partnership's companion Operating Partnership. To the extent of its ownership of
SDIs, liquidation will have the same effect on it as on the Interest Holders.
See "The Proposal--Estimates of Liquidating Distribution Amount." Additionally,
by purchasing the Partnership's Property Interests itself, the Managing General
Partner will be able to maintain its position as operator of many of the
properties in which the Partnership owns an interest and for which it will
continue to receive operating fees. The sale of the Partnership's Property
Interests to the Managing General Partner will have no effect or an
inconsequential effect on the Managing General Partner's net book value and net
earnings. However, simultaneously with the Proposal to the Interest Holders of
the Partnership, the Managing General Partner is making a similar proposal to
investors in a number of other limited partnerships organized for the same
purposes between the years 1986 and 1994. If the investors in all of these
partnerships were to 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 the total proved reserves on an
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 Interest Holders, rather
than on the basis of the direct economic impact on the Managing General Partner.

RECOMMENDATION OF THE MANAGING GENERAL PARTNER

For the foregoing reasons, the Managing General Partner believes that
it is in the best interests of the Interest Holders to dissolve and liquidate
the Partnership. Liquidation will allow the Interest Holders to receive the
remaining value of Partnership reserves currently, rather than receiving
distributions over

29
<PAGE> 119

the remaining life of the Partnership, 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 Partnership's interest in
remaining reserves. The Managing General Partner believes that general
improvements over the last several years in the level of natural gas prices make
this an appropriate time to consider the sale of the Partnership's Property
Interest. If operations continue over many years, revenues will continue to
decline while operating and general and administrative expenses continue,
reducing cash distributions. Continued operations also mean continuation of the
additional costs incurred by the Interest Holders, including the costs
associated with inclusion of information from the Schedule K-1 relating to the
Partnership in their personal income tax returns, while reserves continue to
decline. Termination of the Partnership will allow preparation of a final tax
return.

THE MANAGING GENERAL PARTNER RECOMMENDS THAT THE
INTEREST HOLDERS VOTE FOR THE PROPOSAL.

FEDERAL INCOME TAX CONSEQUENCES

GENERAL

The following summarizes certain federal income tax consequences to the
Interest Holders arising from the Partnership's proposed sale of its oil and gas
properties and liquidation pursuant to the Proposal. This discussion is not
based upon an opinion of counsel and it is possible that results different from
those described may occur. Statements of legal conclusions regarding tax
consequences are based upon relevant provisions of the Internal Revenue Code of
1986, as amended (the "Code"), and accompanying Treasury Regulations, as in
effect on the date hereof, upon a private letter ruling dated February 6, 1991,
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 Interest
Holders.

This summary does not describe all the tax aspects which may affect
Interest Holders because the tax consequences may vary depending upon the
individual circumstances of an Interest Holder. It is directed to Interest
Holders that are qualified plans and trusts under Code Section 401(a) and
individual retirement accounts ("IRAs") under Code Section 408 (collectively
"Tax Exempt Plans") and that are the original purchasers of the SDIs and hold
interests in the Partnership as "capital assets" (generally, property held for
investment). Interest Holders were not admitted to the Partnership as limited
partners but are treated as partners of the Partnership for federal income tax
purposes. 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

The Managing General Partner is proposing to sell the Partnership's
Property Interest as well as any other royalties and overriding royalties the
Partnership may own. After the sale of the properties, the

30
<PAGE> 120

Partnership's assets will consist solely of cash, which will be distributed to
the Interest Holders in complete liquidation of the partnership.

Tax Exempt Plans are subject to tax on their unrelated business taxable
income ("UBTI"). UBTI is income derived by an organization from the conduct of a
trade or business that is substantially unrelated to its performance of the
function that constitutes the basis of its tax exemption (aside from the need of
such organization for funds). Royalty interests, dividends, interest and gain
from the disposition of capital assets are generally excluded from
classification as UBTI. Notwithstanding these exclusions, royalties, interest,
dividends, and gains will create UBTI if they are received from debt-financed
property, as discussed below.

The Internal Revenue Service has previously ruled that the
Partnership's Property Interest, as structured under the NP/OR, 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 Interest Holders 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 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. 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 Interest Holder borrowed to acquire its Partnership Interest or
had borrowed funds either before or after it acquired its Partnership Interest
(i.e., SDIs), its pro rata share of Partnership gain on the sale of the Property
Interest may be UBTI. The Managing General Partner has represented that (i) the
Partnership did not borrowed money to acquire its Property Interest, and (ii)
that the Property Interest of the Partnership is not subject to any debt,
mortgages or similar liens that will cause the Partnership's Property Interest
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 Interest is not
expected to be considered debt-financed property.

<PAGE> 121

TAX TREATMENT OF INTEREST HOLDERS SUBJECT TO FEDERAL INCOME TAX DUE TO
DEBT-FINANCING

All references hereinbelow to Interest Holders refers solely to
Interest Holders 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").

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 Interest Holder's income,
gain, loss and deduction from the Partnership is subject to federal taxation.

TAXABLE GAIN OR LOSS UPON SALE OF PROPERTIES

An Interest Holder will realize and recognize gain or loss upon the
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 the Partnership and allocated to
the Interest Holder (i.e., cash or consideration received) over the Interest
Holder'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 Interest Holder's tax basis over the amount realized by the
Partnership for such property and allocated to the Interest Holder. It is
projected that taxable loss will be realized upon the sale of Partnership
properties and that such loss will be allocated among the Interest Holders in
accordance with the Partnership Agreement. The Partnership Agreement includes an
allocation provision that requires allocations pursuant to a liquidation be made
among Partners (i.e., the Interest Holders and the Managing General Partner) 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 Interest Holder will realize and
recognize his allocable share of gains and losses in his tax year within which
the Partnership properties are sold.

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 (including Interest
Holders) 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

<PAGE> 122

distributed to an Interest Holder in liquidation is less than such Interest
Holder's adjusted tax basis in his Partnership interest, the Interest Holder
will realize and recognize a capital loss to the extent of the excess. If the
amount of cash distributed is greater than such Interest Holder's adjusted tax
basis in his Partnership interest, the Interest Holder will recognize a capital
gain to the extent of the excess.

CAPITAL GAINS 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 depletion, will be taxed at a maximum rate depending on that
Interest Holder'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 Interest Holder 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

Interest Holders 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 Interest Holder'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 Interest Holder's allocable share of any gain or loss realized on sale of the
Partnership's net profit interests is expected to be characterized as portfolio
and may not be offset, or be offset by, passive activity gains or losses.

THE FOREGOING DISCUSSION IS INTENDED TO BE A SUMMARY OF CERTAIN INCOME
TAX CONSIDERATIONS OF THE SALE OF PROPERTIES AND LIQUIDATION. EACH INTEREST
HOLDER SHOULD CONSULT ITS OWN TAX ADVISOR CONCERNING ITS PARTICULAR TAX
CIRCUMSTANCES AND THE FEDERAL, STATE, LOCAL, FOREIGN AND OTHER TAX CONSEQUENCES
TO IT OF THE SALE OF PROPERTIES AND THE LIQUIDATION OF THE PARTNERSHIP.

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.

RESERVES

<PAGE> 123

and which contain both estimates for the Partnership as a whole and those solely
attributable to the interest in the Partnership of the Interest Holders. 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
Proxy Statement.

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.

THE MANAGING GENERAL PARTNER

Subject to certain limitations set forth in the Partnership Agreement,
the Managing General Partner has full, exclusive and complete discretion in the
management and control of the business of the Partnership. The Managing General
Partner has general liability for the debts and obligations of the Partnership.

The Managing General Partner is engaged in the business of oil and gas
exploration, development and production, and the Managing General Partner serves
as the general partner of a number of other oil and gas income and pension
partnerships. The Managing General Partner's common stock is traded on the New
York and Pacific Stock Exchanges.

The principal executive offices of the Managing General Partner are
located at 16825 Northchase Drive, Suite 400, Houston, Texas 77060, telephone
number (281) 874-2700.

TRANSACTIONS BETWEEN THE MANAGING GENERAL PARTNER AND THE PARTNERSHIP

The Managing General Partner receives operating fees for wells in which
the Partnership has a net profits interest 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 net profits
interest. The Managing General Partner believes that it will be positively
affected, on the other hand, by liquidation of the

<PAGE> 124

Partnership, on the basis of its ownership interest in the Partnership. See "The
Proposal--Estimates of Liquidating Distribution Amount," and "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 in addition to revenues
distributable to the Managing General Partner with respect to its general
partnership interest or SDIs it has purchased. 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.

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
Interest Holder capital contributions to the Partnership
relative to limited partner or interest holder contributions
of all partnerships for which the Managing General Partner
serves as Managing General Partner. Through December 31, 1997,
the Managing General Partner had received $458,444 in the
general and administrative overhead allowance.

o The Managing General Partner has been reimbursed $12,908 in
direct expenses, all of which was billed by, and then paid
directly to, third party vendors.

o The Managing General Partner has received a nonaccountable
incentive amount of $123,405 for services rendered from
inception through December 31, 1997.

NO TRADING MARKET

There is no trading market for the SDIs, and none is expected to
develop. Under the Partnership Agreement, the Interest Holders 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 Interest Holders invested in the Partnership. Through
December 31, 1997, the Managing General Partner has purchased 161,000 SDIs from
Interest Holders pursuant to the right of presentment. As of April ___, 1998,
there were 559 Interest Holders (excluding the Managing General Partner). The
Managing General Partner does not have an obligation to repurchase Interest
Holder interests pursuant to this right of presentment but merely an option to
do so when such interests are presented for repurchase.

PRINCIPAL HOLDERS OF INTEREST HOLDER SDIS

The Managing General Partner holds 2.58% of all outstanding SDIs of the
Partnership resulting from the purchase of SDIs from Interest Holders 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.

<PAGE> 125

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.

INCORPORATION OF CERTAIN INFORMATION BY REFERENCE AND ATTACHMENT
OF INFORMATION HERETO

The Partnership's Annual Report on Form 10-K for the year ended
December 31, 1997, is attached hereto and incorporated herein by reference.
Additionally, a reserve report dated February 10, 1998, prepared as of December
31, 1997, and audited by H.J. Gruy and Associates, Inc., is attached hereto
together with the fair market value estimates of J.R. Butler and H.J. Gruy dated
April 17, 1998, and the fair market value estimate of CIBC Oppenheimer dated
April 20, 1998.

GLOSSARY OF TERMS

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.

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.

EBITDA means earnings before interest, taxes and depreciation, depletion and
amortization.

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.

MMBTU means million British Thermal Units, which is a heating equivalent measure
for natural gas.

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, the 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

<PAGE> 126

agreement that are evaluated at the respective dates of acquisition to contain
Proved Reserves, to the extent such depths underlie specified surface acreage.

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.

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.

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.

<PAGE> 127

OTHER BUSINESS

The Managing General Partner does not intend to bring any other
business before the Meeting and has not been informed that any other matters are
to be presented at the Meeting by any other person.

SWIFT ENERGY COMPANY
as Managing General Partner of
SWIFT ENERGY PENSION
PARTNERS 1993-B, LTD.

-------------------------------
John R. Alden
Secretary

<PAGE> 128

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

IF INTEREST HOLDER SDIS ARE HELD JOINTLY, ALL JOINT TENANTS MUST SIGN.

<PAGE> 129
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.

Subject to Completion
Dated April ____, 1998
[GRAPHIC OMITTED]

Prospectus
2,500,000 SHARES
SWIFT ENERGY COMPANY [LOGO]
COMMON STOCK

This Prospectus relates to an aggregate of 2,500,000 shares (the "Shares") of
common stock, par value $.01 per share (the "Common Stock"), of Swift Energy
Company (the "Company") being offered to limited partners (the "Limited
Partners") of those certain partnerships in which the company serves as managing
general partner (the "Partnerships") that approve the proposals being submitted
to the Limited Partners by the Company for sale of substantially all of the
assets of the Partnerships to the Company and the subsequent termination of such
Partnerships (the "Proposals" or singularly for each Partnership, the
"Proposal"). Upon approval of the Proposals and sale of the Partnerships'
properties, the Partnerships' assets will consist solely of cash which each
Limited Partner of such Partnerships will be entitled to receive as a
distribution. This offering is made solely to those Limited Partners of
Partnerships in which the Proposals are approved by it and its companion
partnership ("Eligible Purchasers"). 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 Eligible Purchaser will be entitled to
receive. 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 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.

The purchase price of the Common Stock offered hereby will be the average price
of the Common Stock as reported by the New York Stock Exchange for the period
________________ and _____________________, 1998.

The Company's Common Stock is listed on the New York Stock Exchange and the
Pacific Stock Exchange under the symbol "SFY." On April 17, 1998 the last
reported sale price of the Company's Common Stock on the New York Stock Exchange
was $20.13 per share. Application will be made to list the Shares on the New
York Stock Exchange.

SEE "RISK FACTORS" COMMENCING ON PAGE 12 OF THIS PROSPECTUS FOR A DESCRIPTION OF
CERTAIN FACTORS THAT SHOULD BE CONSIDERED IN CONNECTION WITH AN INVESTMENT IN
THE SHARES.

THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS TO WHICH IT RELATES. ANY REPRESENTATION
TO THE CONTRARY IS A CRIMINAL OFFENSE.

<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
PRICE TO PROCEEDS TO
PUBLIC (1) COMPANY (1)(2)
<S> <C> <C>
Per Share .................................... $ $
Total(3)...................................... $ $
- --------------------------------------------------------------------------------
</TABLE>

(1)
(2)
(3)

The date of this Prospectus is _______________________, 1998.

<PAGE> 130

AVAILABLE INFORMATION

The Company has filed with the Securities and Exchange Commission (the
"Commission") a Registration Statement on Form S-4 (of which this Prospectus is
a part) under the Securities Act of 1933, as amended, with respect to the
securities offered hereby. This Prospectus does not contain all the information
set forth in the Registration Statement or the exhibits thereto, to which
reference is made concerning the contents of such exhibits. Reference to each
such exhibit qualifies all information related thereto.

The Company is subject to the informational requirements of the
Securities Exchange Act of 1934, as amended, and accordingly files 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 Stock Exchange
Incorporated, 115 Sansome Street, 8th Floor, San Francisco, California 94104. In
addition, such materials filed electronically by the Company with the Commission
are available at the Commission's World Wide Web site at http://www.sec.gov.

DEFINED TERMS

The following abbreviations and terms have the indicated meanings when
used in this Prospectus:

BBL - Barrel or barrels of oil.

BCF - Billion cubic feet of natural gas.

BCFE - Billion cubic feet of natural gas equivalent (see Mcfe).

DEVELOPMENT WELL - 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 - 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 - An exploratory or development well that is not a producing well.

EXPLORATORY WELL - 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.

GROSS ACRE - 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.

<PAGE> 131

GROSS WELL - 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 - Thousand barrels of oil.

MCF - Thousand cubic feet of natural gas.

MCFE - 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 - 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 - Million cubic feet of natural gas.

MMCFE - Million cubic feet of natural gas equivalent (see Mcfe).

NET ACRE - 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 WELL - 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.

PRODUCING WELL - 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 - Reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.

PROVED OIL AND GAS RESERVES - 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 - 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 - The estimated future net revenue 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 service, future income tax expense or
depreciation, depletion, and amortization.

<PAGE> 132

RESERVE REPLACEMENT COST - 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.

VOLUMETRIC PRODUCTION PAYMENT - 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.

<PAGE> 133

PROSPECTUS SUMMARY

The following summary is qualified in its entirety by the more detailed
information and Consolidated Financial Statements, including the notes thereto,
and other financial information included or incorporated by reference, appearing
elsewhere in this Prospectus. Prospective investors should carefully consider
the factors set forth under "Risk Factors." Unless the context otherwise
requires, references to the "Company" or "Swift" refer to Swift Energy Company
and its consolidated subsidiaries. Defined terms used herein to describe
quantities of oil and gas and other matters are explained under "Defined Terms"
on page 2 above. The Company's principal executive offices are located at 16825
Northchase Drive, Suite 400, Houston, Texas 77060, and its telephone number is
(281) 874-2700.

The 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. 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. 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. 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 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.

The Company has increased its proved reserves from 59.0 Bcfe at 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.

<PAGE> 134
The Offering

Securities Offered.................... 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 "Proposals" or
singularly for each Partnership, the
"Proposal"), the Company is offering up
to 2,500,000 shares of the Company's
Common Stock to certain Limited Partners
of such Partnerships (the "Offering").
Upon approval of the Proposals and sale
of the Partnerships' properties, the
Partnerships' assets will consist solely
of cash which each Limited Partner of
such Partnerships will be entitled to
receive as a distribution. The Company
hereby offers to each such Limited
Partner who becomes an Eligible
Purchaser (as defined below) the
opportunity to purchase shares of Common
Stock with all or any portion of the
cash distribution such Limited Partner
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. See "Oversubscription"
below. No fractional shares will be
sold.

16,515,038 shares of Common Stock were
issued and outstanding on March 31,
1998. The Common Stock is traded on the
New York Stock Exchange and the Pacific
Stock Exchange under the symbol "SFY."

Minimum Purchase...................... The minimum number of shares of Common
Stock which must be purchased is a round
lot of 100 shares.

Listing............................... Application to list the shares of Common
Stock offered hereby on the New York
Stock Exchange will be made.

Eligible Purchasers................... This Offering is made solely to those
Limited Partners of Partnerships in
which the Proposals are approved by it
and its companion partnership ("Eligible
Purchasers").

Purchase Price........................ The purchase price of the Common Stock
offered hereby will be the average price
of the Common Stock as reported by the
New York Stock Exchange for the period
between ________ and __________, 1998.

Closing Date.......................... The Company will issue checks
representing full or partial
distributions and/or stock certificates
representing shares of Common Stock
subscribed for hereunder approximately
forty-five (45) days after the date of
the Supplement (as defined below) to
this Prospectus (the "Closing Date"),
unless earlier terminated or extended by
the Company.

<PAGE> 135

Due Date.............................. All Subscription Agreements, revocations
of prior subscriptions or additional
required consideration must be received
no later than thirty (30) days after the
date of the Supplement (the "Due Date"),
unless extended by the Company.

Method of Purchase.................... In addition to this Prospectus, Limited
Partners of the Partnerships are being
provided with (i) the relevant proxy
statement relating to the Proposal
before their Partnership, (ii) a proxy
upon which to vote regarding the
Proposal, and (iii) a Subscription
Agreement by which Limited Partners 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, a Limited
Partner will receive the cash
distribution. Provided their cash
distribution is in excess of the amount
required to purchase the minimum number
of shares, Limited Partners 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 a supplement
to this Prospectus (the "Supplement")
advising as to which Partnerships
approved the Proposals. Eligible
Purchasers may subscribe, or revoke
their previous subscription, to purchase
shares of the Common Stock offered
hereby from the date of this Prospectus
until the Due Date, unless earlier
terminated or extended by the Company.

In the event Eligible Purchasers chose
to apply all of their cash distribution
to purchase shares of Common Stock and
such distribution is more than the
purchase price required to purchase a
round lot of 100 shares, such Eligible
Purchasers will receive that number of
shares of Common Stock rounded down to
the nearest whole share as can be
purchased for such amount. If such
Eligible Purchaser elects to purchase
shares of Common Stock in addition to
the number he can purchase with his 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

<PAGE> 136
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.

Oversubscription...................... In the event this Offering is
oversubscribed, all subscribers 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 copy of a previously
submitted Subscription Agreement marked
"REVOKED" and 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.

Use of Proceeds....................... The Company intends to apply the net
proceeds from this Offering towards the
purchase of the assets of the
Partnerships. See "Use of Proceeds."

<PAGE> 137

SUMMARY HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA
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 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 of all the Partnerships (the "Acquisitions") for
(a) cash ("All Cash Case") or (b) 2.5 million shares of the Company's common
stock and cash ("Equity/Cash Case"). 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 December 31,
1997. 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 Prospectus.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------
1997 PRO FORMA
-----------------------
ALL CASH EQUITY/CASH
CASE CASE 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....................... $104,495 $104,495 $ 69,015 $ 52,771 $ 22,528 $ 19,802 $ 15,536
Fees and Earned Interests(b)............ 542 542 746 937 590 702 4,072
Supervision fees........................ 5,210 5,210 5,210 4,470 3,839 3,751 3,719
Interest income......................... 2,395 2,395 2,395 433 212 48 201
Other, net.............................. 2,778 2,778 2,556 2,157 1,762 1,073 604
-------- -------- -------- -------- -------- -------- --------
Total Revenues.................... 115,420 115,420 79,922 60,768 28,931 25,376 24,132
-------- -------- -------- -------- -------- -------- --------
Costs and Expenses:
General and administrative, net of
reimbursement......................... 10,288 10,288 6,129 6,385 5,256 5,198 5,065
Depreciation, depletion, and
amortization.......................... 33,801 33,801 24,247 16,526 8,839 7,905 7,301
Oil and gas production.................. 22,937 22,937 11,384 8,377 6,826 5,640 4,540
Interest expense, net................... 9,799 6,312 5,033 694 1,115 1,795 598
-------- -------- -------- -------- -------- -------- --------
Total Costs and Expenses.......... 76,825 73,338 46,793 31,982 22,036 20,538 17,504
-------- -------- -------- -------- -------- -------- --------
Income before Income Taxes................ 38,595 42,082 33,129 28,786 6,895 4,838 6,628
Provision for Income Taxes................ 13,122 14,308 10,819 9,760 1,982 1,112 1,732
-------- -------- -------- -------- -------- -------- --------
Income Before Cumulative Effect of Change
in Accounting Principle................. $ 25,473 $ 27,774 $ 22,310 $ 19,026 $ 4,913 $ 3,726 $ 4,896
======== ======== ======== ======== ======== ======== ========
Per share amounts (c)--
Basic................................... $ 1.54 $ 1.46 $ 1.35 $ 1.27 $ 0.49 $ 0.51 $ 0.68
======== ======== ======== ======== ======== ======== ========
Diluted................................. $ 1.41 $ 1.36 $ 1.26 $ 1.25 $ 0.49 $ 0.51 $ 0.64
======== ======== ======== ======== ======== ======== ========
Weighted Average Shares Outstanding(c).... 16,493 18,993 16,493 15,001 10,035 7,309 7,247
======== ======== ======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
EBITDA(d)................................. $ 82,195 $ 82,195 $ 62,410 $ 46,006 $ 16,849 $ 14,538 $ 14,527
Net cash provided by operating
activities.............................. 67,769 70,070 55,256 37,103 14,376 10,395 7,238
Capital expenditures...................... 196,615 196,615 131,967 91,487 40,033 34,531 24,229
Ratio of earnings to fixed charges(e)..... 4.0x 5.5x 5.0x 12.6x 3.1x 2.6x 6.8x
BALANCE SHEET DATA:
Working capital........................... $ 1,498 $ 312 $ 1,464 $ 68,704 $ 3,247 $(13,137) $ 9,742
Total assets.............................. 403,319 403,319 339,115 310,375 175,253 135,673 160,893
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......................... 69,415 24,415 7,915 -- -- -- --
Stockholders' equity...................... 158,429 202,243 159,401 142,762 93,346 42,127 54,466
</TABLE>

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

(a) For a discussion of the significant items affecting comparability of 1997,
1996 and 1995, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations" included elsewhere in this Prospectus.
(b) As of January 1, 1994, the Company changed its revenue recognition policy
for earned interests. Accordingly, 1997, 1996, 1995, and 1994 "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) 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.
9
<PAGE> 138

SUMMARY RESERVES AND PRODUCTION DATA

The following table sets forth certain summary information with respect to
estimates prepared by the Company, and audited by H.J. Gruy and Associates,
Inc., independent petroleum engineers ("Gruy"), of the Company's oil and gas
reserves, the future net revenues therefrom and their PV-10 Value. This
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,
1997 PRO --------------------------------------------------
FORMA(a) 1997 1996 1995 1994 1993
-------- -------- -------- -------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
ESTIMATED PROVED OIL AND GAS RESERVES:
Net natural gas reserves (MMcf):
Proved developed........................ 245,543 191,108 135,425 81,532 46,406 50,937
Proved undeveloped...................... 136,523 123,198 90,333 62,036 29,858 13,526
-------- -------- -------- -------- ------- -------
Total............................ 382,066 314,306 225,758 143,568 76,264 64,463
======== ======== ======== ======== ======= =======
Net oil reserves (MBbl):
Proved developed........................ 7,421 4,289 3,622 3,313 3,209 3,110
Proved undeveloped...................... 4,723 3,570 1,862 2,109 1,344 1,161
-------- -------- -------- -------- ------- -------
Total............................ 12,144 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 $244,365 $310,409 $ 85,537 $47,172 $66,310
Proved undeveloped...................... 125,303 105,980 160,776 61,501 22,223 17,451
-------- -------- -------- -------- ------- -------
Total(b)......................... $440,247 $350,345 $471,185 $147,038 $69,395 $83,761
======== ======== ======== ======== ======= =======
Prices used in calculating end of year
proved reserves:
Oil (Per Bbl)........................... $ 15.76 $ 15.76 $ 23.75 $ 18.07 $ 15.09 $ 12.87
======== ======== ======== ======== ======= =======
Gas (Per Mcf)........................... $ 2.78 $ 2.78 $ 4.47 $ 2.41 $ 1.85 $ 2.50
======== ======== ======== ======== ======= =======
OTHER RESERVES DATA:
Reserve replacement cost(c)............... N/A $ 0.73 $ 0.67 $ 0.61 $ 0.79 $ 0.70
Exploration and development reserves added
(MMcfe)................................. N/A 120,150 118,235 72,425 24,804 13,502
Acquisition reserves added (MMcfe)........ 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 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 of those reserves decreased 26% from the PV-10 Value at year end
1996. This decrease was almost totally due to the higher year end 1996
prices. If year end 1997 PV-10 Value used year end 1996 prices, 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 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)

10
<PAGE> 139

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,
1997 PRO -------------------------------------------------
FORMA(a) 1997 1996 1995 1994 1993
-------- ------- ------- ------- ------ ------
<S> <C> <C> <C> <C> <C> <C>
PRODUCTION:
Net Sales Volume:
Oil (MBbls).................... 1,303 672 623 545 467 324
Gas (MMcf)(b).................. 29,930 21,359 15,697 7,914 6,799 5,422
Gas equivalents (MMcfe)........ 37,747 25,394 19,437 11,187 9,601 7,369
WEIGHTED AVERAGE SALES PRICES:
Oil (Per Bbl).................... $ 17.49 $ 17.59 $ 19.82 $ 15.66 $14.35 $15.10
Gas (Per Mcf).................... $ 2.73 $ 2.68 $ 2.57 $ 1.77 $ 1.93 $ 1.96
SELECTED DATA PER MCFE:
Production Costs................. $ 0.61 $ 0.45 $ 0.43 $ 0.61 $ 0.59 $ 0.62
Depreciation, depletion, and
amortization................... $ 0.90 $ 0.95 $ 0.85 $ 0.79 $ 0.82 $ 0.99
General and administrative, net
of reimbursement............... $ 0.27 $ 0.24 $ 0.33 $ 0.47 $ 0.54 $ 0.69
WELLS DRILLED:
Gross............................ N/A 182 153 76 44 34
Net.............................. 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.

11
<PAGE> 140

RISK FACTORS

In addition to the other information contained in this 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 Securities 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 forwardlooking 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
the volatility in oil and gas prices and other factors, interim results are not
necessarily indicative of those for a full year.

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."

<PAGE> 141

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 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 remaining nine 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

<PAGE> 142

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."

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."

<PAGE> 143

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."

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,

<PAGE> 144

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."

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."

LIABILITY AS GENERAL PARTNER; CONFLICTS OF INTEREST

Over the past decade, the Company has formed 107 limited partnerships,
which had invested approximately $502.0 million in oil and gas activities at
March 31, 1998. These limited partnerships had less than $4 million of
indebtedness at March 31, 1998, virtually all of which is owed to the Company.
However, the Company remains contingently liable for their obligations as
general partner, including responsibility for their day-to-day operations, and
liabilities which cannot be repaid from partnership assets or insurance
proceeds. In the future, the Company might be exposed to litigation in
connection with partnership activities, or find it necessary to advance funds on
behalf of certain partnerships to protect the value of their oil and gas
properties. Conversely, the Company might be prohibited from acquiring certain
property interests if to do so would conflict with the interests of limited
partnerships which it manages. See "Business and Properties -Partnerships."

USE OF PROCEEDS

The net proceeds to the Company from the sale of the Shares offered
hereby will be approximately $_____ million, after deducting estimated expenses
of the Offering payable by the Company. From these proceeds, the Company intends
to apply the net proceeds from this Offering towards the purchase of the assets
of the Partnerships. The allocation of the Company's net proceeds from this
Offering, together with other available capital, among these categories of
anticipated expenditures is discretionary and will depend upon future events
that cannot be predicted, including the actual results and costs of future
exploratory and development drilling and other activities, the availability and
cost of oil and gas properties meeting the

<PAGE> 145

Company's acquisition criteria, the Company's net cash flows from operating
activities and other matters beyond the control of the Company.

Until net proceeds of the Offering are utilized for purposes described
above, they will be invested in interest bearing bank accounts, U.S. government
securities, other investment grade debt securities and other short-term
investments.

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 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 Prospectus.

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

The Common Stock trades on the New York Stock Exchange and the Pacific
Stock Exchange 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 closing sales prices for the Common Stock of the
Company as reported by the New York Stock Exchange for the periods indicated.

High Low
--------- ---------
<S> <C> <C>
1998
Second Quarter (Through April 17)................ $ 20.31 $ 17.38
First Quarter.................................... 21.00 15.88

1997
Fourth Quarter................................... 31.00 19.25
Third Quarter.................................... 26.48 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 April 17, 1998, the
last reported sale price for the Common Stock on the New York Stock Exchange was
$20.13 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.

<PAGE> 146

CAPITALIZATION

The following table sets forth as of December 31, 1997 the actual
capitalization of the Company and the capitalization of the Company as adjusted
to give effect to the Acquisitions. 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.

<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1997
------------------------------------------
AS ADJUSTED AS ADJUSTED
FOR THE FOR THE
ACQUISITIONS ACQUISITIONS
COMPANY ALL CASH EQUITY/CASH
HISTORICAL CASE(a) CASE(b)
---------- ------------ ------------
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
<S> <C> <C> <C>
Current Assets:
Cash and cash equivalents.............................. $ 2,047 $ 2,047 $ 2,047
======== ======== ========
Long-Term Debt:
6.25% Convertible Subordinated Notes Due 2006.......... 115,000 115,000 115,000
Bank Borrowings........................................ 7,915 69,415 24,415
-------- -------- --------
Total Long-Term Debt........................... 122,915 184,415 139,415
-------- -------- --------
Stockholders' Equity:
Preferred stock, $.01 par value 5,000,000 shares
authorized, none outstanding........................ -- -- --
Common stock, $.01 par value, 35,000,000 shares
authorized, 16,846,956 shares issued and 16,459,156
shares outstanding, respectively, 19,346,956 shares
issued and 18,959,156 shares outstanding as adjusted
for the Equity/Cash Case (b) (c).................... 169 169 194
Additional paid-in capital............................. 147,543 147,543 192,518
Treasury stock held, at cost, 387,800 shares........... (8,520) (8,520) (8,520)
Unearned ESOP compensation............................. (150) (150) (150)
Retained earnings...................................... 20,359 19,387 18,201
-------- -------- --------
159,401 158,429 202,243
-------- -------- --------
Total Liabilities and Stockholders' Equity..... $282,316 $342,844 $341,658
======== ======== ========
</TABLE>

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

(a) All Cash Case assumes Acquisitions funded all in cash with the Limited
Partners of all Partnerships voting to sell substantially all their assets
and to liquidate their Partnerships. See "Unaudited Pro Forma Consolidated
Financial Statements."

(b) Equity/Cash Case assumes Acquisitions funded with 2.5 million shares of
Common Stock at an assumed price of $18 per share with remaining purchase
amount funded in cash with the Limited Partners of all Partnerships voting
to sell substantially all their assets and to liquidate their Partnerships.
See "Unaudited Pro Forma Consolidated Financial Statements."

(c) Excludes 1,761,512 shares issuable upon exercise of employee and director
stock options outstanding as of December 31, 1997.

18
<PAGE> 147

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

The following unaudited pro forma consolidated statements of income for the
year ended December 31, 1997 and the unaudited pro forma consolidated balance
sheets as of December 31, 1997 (collectively, the "Pro Forma Financial
Statements") are based on the historical consolidated financial statements of
the Company and the historical combined financial statements of the Partnerships
proposed to be acquired, adjusted to give effect to the Acquisitions.

The Unaudited Pro Forma Consolidated Statements of Income for the year
ended December 31, 1997 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 December 31, 1997. The
Pro Forma Financial Statements assume the Acquisitions are consummated for (i)
all cash and (ii) cash and 2.5 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
result of operations of 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" and
the Consolidated Financial Statements.

19
<PAGE> 148

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
(ALL CASH CASE)

ASSETS

<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1997
---------------------------------------------------------
COMPANY PARTNERSHIPS PRO FORMA ALL CASH CASE
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- -------------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C>
Current Assets:
Cash and cash equivalents.......................... $ 2,047 $ 7,429 $ (7,429)(c) $ 2,047
Accounts receivable --
Oil and gas sales................................ 11,143 9,965 (1,974)(a) 19,134
Associated limited partnerships and joint
ventures....................................... 8,499 -- (7,069)(h) 1,430
Joint interest owners and other.................. 7,358 1,782 -- 9,140
Other current assets............................... 935 92 (92) 935
-------- --------- --------- --------
Total Current Assets........................ 29,982 19,268 (16,564) 32,686
-------- --------- --------- --------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized................ 326,836 328,373 (55,906)(a) 388,336
61,500(g)
(272,467)(j)
Unproved properties not being amortized.......... 41,840 -- -- 41,840
-------- --------- --------- --------
368,676 328,373 (266,873) 430,176
Furniture, fixtures, and other equipment........... 6,243 -- -- 6,243
-------- --------- --------- --------
374,919 328,373 (266,873) 436,419
Less -- Accumulated depreciation, depletion, and
amortization..................................... (70,700) (239,044) 34,336(a) (70,700)
204,708(j)
-------- --------- --------- --------
304,219 89,329 (27,829) 365,719
-------- --------- --------- --------
Other Assets:
Receivables from associated limited partnerships,
net of current portion........................... 433 -- -- 433
Limited partnership formation and marketing
costs............................................ 297 -- -- 297
Deferred charges................................... 4,184 -- -- 4,184
-------- --------- --------- --------
4,914 -- -- 4,914
-------- --------- --------- --------
Total Assets................................ $339,115 $ 108,597 $ (44,393) $403,319
======== ========= ========= ========

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities:
Accounts payable and accrued liabilities........... $ 16,518 $ 2,718 $ (569)(a) $ 20,970
2,303(f)
Payable to associated limited partnerships......... 3,245 711 (2,492)(h) 1,464
Undistributed oil and gas revenues................. 8,754 -- -- 8,754
-------- --------- --------- --------
Total Current Liabilities................... 28,517 3,429 (758) 31,188
-------- --------- --------- --------
6.25% Convertible Subordinated Notes................. 115,000 -- -- 115,000
Bank Borrowings...................................... 7,915 -- 61,500(e) 69,415
Deferred Revenues.................................... 2,928 1,251 (246)(a) 3,933
Deferred Income Taxes................................ 25,354 -- -- 25,354
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding..................... -- -- -- --
Common stock, $.01 par value, 35,000,000 shares
authorized, 16,846,956 shares issued, and
16,459,156 shares outstanding, respectively...... 169 -- -- 169
Additional paid-in capital......................... 147,543 -- -- 147,543
Treasury stock held, at cost, 387,800 shares....... (8,520) -- -- (8,520)
Unearned ESOP compensation......................... (150) -- -- (150)
Retained earnings.................................. 20,359 -- (972)(a) 19,387
Partners' Capital.................................. -- 103,917 (103,917)(j) --
-------- --------- --------- --------
159,401 103,917 (104,890) 158,429
-------- --------- --------- --------
Total Liabilities and Stockholders'
Equity.................................... $339,115 $ 108,597 $ (44,393) $403,319
======== ========= ========= ========
</TABLE>

See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements

20
<PAGE> 149

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(ALL CASH CASE)

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
-------------------------------------------------------
ALL CASH
COMPANY PARTNERSHIPS PRO FORMA CASE
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales................................. $69,015 $42,228 $(6,748)(a) $104,495
Fees from limited partnerships and joint
ventures........................................ 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 (3,518)(a) 33,801
(3,785)(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
======= ========
</TABLE>

See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements

21
<PAGE> 150

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
(EQUITY/CASH CASE)

ASSETS

<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1997
--------------------------------------------------------
EQUITY/CASH
COMPANY PARTNERSHIPS PRO FORMA CASE
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- -----------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C>
Current Assets:
Cash and cash equivalents........................ $ 2,047 $ 7,429 $ (7,429)(c) $ 2,047
Accounts receivable --
Oil and gas sales.............................. 11,143 9,965 (1,974)(a) 19,134
Associated limited partnerships and joint
ventures..................................... 8,499 -- (7,069)(h) 1,430
Joint interest owners and other................ 7,358 1,782 -- 9,140
Other current assets............................. 935 92 (92) 935
-------- --------- --------- --------
Total Current Assets...................... 29,982 19,268 (16,564) 32,686
-------- --------- --------- --------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized.............. 326,836 328,373 (55,906)(a) 388,336
61,500(g)
(272,467)(j)
Unproved properties not being amortized........ 41,840 -- -- 41,840
-------- --------- --------- --------
368,676 328,373 (266,873) 430,176
Furniture, fixtures, and other equipment......... 6,243 -- -- 6,243
-------- --------- --------- --------
374,919 328,373 (266,873) 436,419
Less -- Accumulated depreciation, depletion, and
amortization................................... (70,700) (239,044) 34,336(a) (70,700)
204,708(j)
-------- --------- --------- --------
304,219 89,329 (27,829) 365,719
-------- --------- --------- --------
Other Assets:
Receivables from associated limited partnerships,
net of current portion......................... 433 -- -- 433
Limited partnership formation and marketing
costs.......................................... 297 -- -- 297
Deferred charges................................. 4,184 -- -- 4,184
-------- --------- --------- --------
4,914 -- -- 4,914
-------- --------- --------- --------
Total Assets.............................. $339,115 $ 108,597 $ (44,393) $403,319
======== ========= ========= ========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities......... $ 16,518 $ 2,718 $ (569)(a) $ 22,156
3,489(f)
Payable to associated limited partnerships....... 3,245 711 (2,492)(h) 1,464
Undistributed oil and gas revenues............... 8,754 -- -- 8,754
-------- --------- --------- --------
Total Current Liabilities................. 28,517 3,429 428 32,374
-------- --------- --------- --------
6.25% Convertible Subordinated Notes............... 115,000 -- -- 115,000
Bank Borrowings.................................... 7,915 -- 16,500(e) 24,415
Deferred Revenues.................................. 2,928 1,251 (246)(a) 3,933
Deferred Income Taxes.............................. 25,354 -- -- 25,354
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding................... -- -- -- --
Common stock, $.01 par value, 35,000,000 shares
authorized, 16,846,956 shares issued and
16,459,156 shares outstanding, 19,346,956
issued and 18,959,156 shares outstanding as
adjusted for the Equity/Cash Case.............. 169 -- 25(i) 194
Additional paid-in capital....................... 147,543 -- 44,975(i) 192,518
Treasury stock held, at cost, 387,800 shares..... (8,520) -- -- (8,520)
Unearned ESOP compensation....................... (150) -- -- (150)
Retained earnings................................ 20,359 -- (2,158)(a) 18,201
Partners' Capital................................ -- 103,917 (103,917)(j) --
-------- --------- --------- --------
159,401 103,917 (61,075) 202,243
-------- --------- --------- --------
Total Liabilities and Stockholders'
Equity.................................. $339,115 $ 108,597 $ (44,393) $403,319
======== ========= ========= ========
</TABLE>

See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements

22
<PAGE> 151

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
(EQUITY/CASH CASE)

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
------------------------------------------------------
EQUITY/CASH
COMPANY PARTNERSHIPS PRO FORMA CASE
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ------------ ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales.................................... $69,015 $42,228 $(6,748)(a) $104,495
Fees from limited partnerships and joint ventures.... 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 (3,518)(a) 33,801
(3,785)(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
======= ========
</TABLE>

See accompanying notes to Unaudited Pro Forma Consolidated Financial Statements

23
<PAGE> 152

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 from its
Managing General Partner interests and the purchase of Limited Partner
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.

(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 (All Cash Case) or $16,500,000 (Equity/Cash Case) 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 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 All Cash Case or $20,625 and
$41,250, respectively on the Equity/Cash Case.

(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 of $61,500,000 to
proved oil and gas property costs, as follows (in thousands):

<TABLE>
<S> <C>
Estimated gross purchase price............................. $70,587
Estimated purchase price adjustments*...................... (9,237)
Estimated acquisition costs................................ 150
-------
Estimated net purchase price............................... $61,500
=======
</TABLE>

--------------------------
* Estimated purchase price adjustments represent estimated interim
cash flows to the purchased interests from the period from the
effective date to the closing date of the Acquisitions.

(h) Represents the elimination of intercompany accounts receivables due from
the Partnerships and payables due to the Partnerships.

(i) Under the Equity/Cash Case, this reflects the issuance of 2.5 million
shares of the Company's 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.

24
<PAGE> 153

SELECTED CONSOLIDATED HISTORICAL FINANCIAL DATA

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------
1997(a) 1996(a) 1995(a) 1994 1993
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and gas sales............................. $ 69,015 $ 52,771 $ 22,528 $ 19,802 $ 15,536
Fees and Earned Interests(b).................. 746 937 590 702 4,072
Supervision fees.............................. 5,210 4,470 3,839 3,751 3,719
Interest income............................... 2,395 433 212 48 201
Other, net.................................... 2,556 2,157 1,762 1,073 604
-------- -------- -------- -------- --------
Total Revenues......................... 79,922 60,768 28,931 25,376 24,132
-------- -------- -------- -------- --------
Costs and Expenses:
General and administrative, net of
reimbursement............................... 6,129 6,385 5,256 5,198 5,065
Depreciation, depletion, and amortization..... 24,247 16,526 8,839 7,905 7,301
Oil and gas production........................ 11,384 8,377 6,826 5,640 4,540
Interest expense, net......................... 5,033 694 1,115 1,795 598
-------- -------- -------- -------- --------
Total Costs and Expenses............... 46,793 31,982 22,036 20,538 17,504
-------- -------- -------- -------- --------
Income before Income Taxes...................... 33,129 28,786 6,895 4,838 6,628
Provision for Income Taxes...................... 10,819 9,760 1,982 1,112 1,732
-------- -------- -------- -------- --------
Income Before Cumulative Effect of Change in
Accounting Principle.......................... 22,310 19,026 4,913 3,726 4,896
Cumulative Effect of Change in Accounting
Principle..................................... -- -- -- (16,773) --
-------- -------- -------- -------- --------
Net Income (Loss)............................... $ 22,310 $ 19,026 $ 4,913 $(13,047) $ 4,896
======== ======== ======== ======== ========
Per share amounts (c)--
Basic......................................... $ 1.35 $ 1.27 $ 0.49 $ (1.79)(d) $ 0.68(d)
======== ======== ======== ======== ========
Diluted....................................... $ 1.26 $ 1.25 $ 0.49 $ (1.79)(d) $ 0.64(d)
======== ======== ======== ======== ========
Weighted Average Shares Outstanding(c).......... 16,493 15,001 10,035 7,309 7,247
======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
Net cash provided by operating activities....... $ 55,256 $ 37,103 $ 14,376 $ 10,395 $ 7,238
Capital expenditures............................ 131,967 91,487 40,033 34,531 24,229
BALANCE SHEET DATA:
Working capital................................. $ 1,464 $ 68,704 $ 3,247 $(13,137) $ 9,742
Total assets.................................... 339,115 310,375 175,253 135,673 160,893
Long-term debt:
6.25% Convertible Subordinated Notes.......... 115,000 115,000 -- -- --
6.5% Convertible Subordinated Debentures...... -- -- 28,750 28,750 28,750
Bank borrowings............................... 7,915 -- -- -- --
Stockholders' equity............................ 159,401 142,762 93,346 42,127 54,466
</TABLE>

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

(b) As of January 1, 1994, the Company changed its revenue recognition policy
for earned interests. Accordingly, 1997, 1996, 1995, and 1994 "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.

25
<PAGE> 154
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, 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.

26
<PAGE> 155
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 produce 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 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.

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

27
<PAGE> 156
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.

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.

28
<PAGE> 157
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.

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

29
<PAGE> 158
the existing credit facilities, will be sufficient to finance the costs
associated with its currently budgeted 1998 capital expenditures.

RESULTS OF OPERATIONS

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 consequent 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

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<PAGE> 159
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 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

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<PAGE> 160
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 in earnings per share reflects a 10% increase in weighted average
shares outstanding in 1997 as a result of the conversion of the Debentures into
2.34 million shares of Common Stock in the third quarter of 1996. The
Company's consolidated effective tax rate was 32.7%, 33.9%, and 28.7% in 1997,
1996, and 1995, respectively.

Net income of $19.0 million and earnings per share of $1.27 for 1996
were 287% and 159% higher, respectively, than net income of $4.9 million and
earnings per share of $0.49 in 1995. This increase in net income primarily
reflected the effect of a 134% increase in oil and gas sales revenues as a
result of a 98% increase in natural gas production, a 14% increase in crude oil
production, and product price improvements. The lower percentage increase in
earnings per share reflects a 49% increase in weighted average shares
outstanding for 1996 as a result of the sale of 5.75 million shares of Common
Stock in the third quarter of 1995 and the conversion of the Debentures into
2.34 million shares of Common Stock in the third quarter of 1996.

YEAR 2000. A comprehensive assessment of the year 2000 issue has been
conducted and a compliance plan is currently underway. The Company is in the
process of receiving verification of year 2000 compliance from all hardware and
software vendors. The Company does not expect that the cost to modify its
information technology infrastructure will be material to its financial
condition or results of operations. The Company also does not anticipate any
material disruption in its operations as a result of any year 2000 compliance
issues.

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<PAGE> 161
BUSINESS AND PROPERTIES

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.

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

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<PAGE> 162
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 horizontally
produced wells, 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 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

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<PAGE> 163
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.

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

35
<PAGE> 164
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.

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

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<PAGE> 165
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.

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.

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<PAGE> 166
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.

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
</TABLE>

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<PAGE> 167
<TABLE>
<S> <C> <C> <C>
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.

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.

39
<PAGE> 168
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 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

40
<PAGE> 169
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 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
============= ============= =============
</TABLE>

41
<PAGE> 170
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------------------------
1997 1996 1995
-------------------- -------------------- -------------------
<S> <C> <C> <C>
Net oil reserves (Bbl):
Proved developed 4,288,696 3,622,480 3,313,226

Proved undeveloped 3,570,222 1,861,829 2,108,755
------------- ------------- -------------
Total 7,858,918 5,484,309 5,421,981
============= ============= =============

ESTIMATED PRESENT VALUE OF PROVED RESERVES
Estimated present value of future net cash
flows from proved reserves discounted at
10% per annum:
Proved developed $ 244,365,044 $ 310,408,949 $ 85,536,873

Proved undeveloped 105,979,738 160,776,008 61,501,536
------------- ------------- -------------
Total $ 350,344,782 $ 471,184,957 $ 147,038,409
============= ============= =============
</TABLE>

The table also sets forth estimates of future net revenues presented
on the basis of unescalated prices and costs in accordance with criteria
prescribed by the 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.

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<PAGE> 171
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.

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.

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<PAGE> 172
The following table sets forth the developed and undeveloped domestic
leasehold acreage held by the Company at December 31, 1997:
<TABLE>
<CAPTION>
Developed Undeveloped
---------------------------- -----------------------------
Gross (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 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

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<PAGE> 173
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.

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

45
<PAGE> 174
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.

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

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<PAGE> 175
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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<PAGE> 176
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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<PAGE> 177
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 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

<PAGE> 178
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>
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)

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>

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

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<PAGE> 179

(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 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

51
<PAGE> 180
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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<PAGE> 181
DESCRIPTION OF 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 ("Right Certificates") will be mailed to holders of
record of the Common

53
<PAGE> 182
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.

54
<PAGE> 183
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 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.

55
<PAGE> 184
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.

MATERIAL FEDERAL INCOME TAX CONSIDERATIONS

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 Limited Partners 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 Internal Revenue Code of 1986,
as amended (the "Code"), Treasury Regulations, judicial authority, published
positions of the United States Internal Revenue Service (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, Limited Partners 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

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<PAGE> 185
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, Limited Partners 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 Limited Partners 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. Limited Partners should refer to the attached proxy
statement 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 Limited Partner on the
Partnership liquidation, to the extent that Limited Partners 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 Limited Partners
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 a Limited Partner,
Limited Partners that are either individuals or Tax Exempt Plans, as defined in
the proxy statements relating to pension partnerships, 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

Limited Partners that are Tax Exempt Plans, as defined in the proxy
statement, 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, "Tax Treatment of Tax Exempt Plans" in the proxy statements
relating to pension partnerships.

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 "Material Federal Income Tax
Considerations" will be passed upon for the Company 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 Partnership Property Interests is made in reliance
upon the authority of such firms as experts with respect to such matters.

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<PAGE> 186
INCORPORATION OF CERTAIN INFORMATION BY REFERENCE

The Company's Form 10-K as of December 31, 1997, and its definitive
proxy statement mailed to shareholders in connection with the May 12, 1998
annual shareholders' meeting are incorporated herein by reference. All
documents filed by the Company pursuant to Section 13(a), 13(c) 14 or 15(d) of
the Exchange Act subsequent to the date of this Prospectus and prior to the
termination of the offering of the Shares shall be deemed to be incorporated by
reference into this Prospectus and to be a part hereof from the date of filing
of such documents. Any statement contained in a document incorporated or
deemed to be incorporated by reference herein shall be deemed to be modified or
superseded for purposes of this Prospectus to the extent that a statement
contained herein or in any other subsequently filed document which also is or
is deemed to be incorporated by reference herein modifies or supersedes such
statement. Any such statement so modified or superseded shall not be deemed,
except as so modified or superseded, to constitute a part of this Prospectus.
The Company will furnish without charge to each person to whom this Prospectus
is delivered, upon written or oral request of such person, a copy of the
documents referred to above, excluding exhibits thereto. Requests should be
made to: John R. Alden, Secretary, Swift Energy Company, 16825 Northchase
Drive, Suite 400, Houston, Texas 77060-9968.

58
<PAGE> 187

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 Sheet...................................... F-23
Combined Statement of Income................................ F-24
Combined Statement of Partners' Capital..................... F-25
Combined Statement of Cash Flows............................ F-26
Notes to Combined Financial Statements...................... F-27
</TABLE>

F-1
<PAGE> 188

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> 189

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS
<TABLE>
<CAPTION>

DECEMBER 31,
----------------------------
1997 1996
------------ ------------
<S> <C> <C>
Current Assets:
Cash and cash equivalents................................. $ 2,047,332 $ 77,794,974
Accounts receivable
Oil and gas sales...................................... 11,143,033 13,637,390
Associated limited partnerships and joint ventures..... 8,498,702 6,396,149
Joint interest owners.................................. 7,357,660 3,079,619
Other current assets...................................... 935,059 711,346
------------ ------------
Total Current Assets.............................. 29,981,786 101,619,478
------------ ------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized...................... 326,836,431 216,310,033
Unproved properties not being amortized................ 41,839,809 27,620,462
------------ ------------
368,676,240 243,930,495
Furniture, fixtures, and other equipment.................. 6,242,927 5,729,228
------------ ------------
374,919,167 249,659,723
Less -- Accumulated depreciation, depletion, and
amortization........................................... (70,700,240) (46,685,736)
------------ ------------
304,218,927 202,973,987
------------ ------------
Other Assets:
Receivables from associated limited partnerships, net of
current portion........................................ 433,444 759,711
Limited partnership formation and marketing costs......... 297,219 510,607
Deferred charges.......................................... 4,184,014 4,511,481
------------ ------------
4,914,677 5,781,799
------------ ------------
$339,115,390 $310,375,264
============ ============
</TABLE>

LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<S> <C> <C>
Current Liabilities:
Accounts payable and accrued liabilities.................. $ 16,518,240 $ 20,416,589
Payable to associated limited partnerships................ 3,245,445 1,444,648
Undistributed oil and gas revenues........................ 8,753,979 11,054,379
------------ ------------
Total Current Liabilities......................... 28,517,664 32,915,616
------------ ------------
Long-Term Debt.............................................. 115,000,000 115,000,000
Bank Borrowings............................................. 7,915,000 --
Deferred Revenues........................................... 2,927,656 4,404,081
Deferred Income Taxes....................................... 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, 16,846,956 and 15,176,417 shares issued,
and 16,459,156 and 15,176,417 shares outstanding,
respectively........................................... 168,470 151,764
Additional paid-in capital................................ 147,542,977 102,018,861
Treasury stock held, at cost, 387,800 shares.............. (8,519,665) --
Unearned ESOP compensation................................ (150,055) (521,354)
Retained earnings......................................... 20,359,193 41,112,339
------------ ------------
159,400,920 142,761,610
------------ ------------
$339,115,390 $310,375,264
============ ============
</TABLE>

See accompanying notes to Consolidated Financial Statements

F-3
<PAGE> 190

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
Revenues:
Oil and gas sales................................. $69,015,189 $52,770,672 $22,527,892
Fees from limited partnerships and joint
ventures....................................... 745,856 937,238 590,441
Supervision fees.................................. 5,210,022 4,470,206 3,838,815
Interest income................................... 2,395,406 433,352 212,329
Other, net........................................ 2,555,729 2,156,764 1,761,568
----------- ----------- -----------
79,922,202 60,768,232 28,931,045
----------- ----------- -----------
Costs and Expenses:
General and administrative, net of
reimbursement.................................. 6,128,615 6,385,067 5,256,184
Depreciation, depletion, and amortization......... 24,247,142 16,526,379 8,838,657
Oil and gas production............................ 11,383,887 8,377,044 6,826,306
Interest expense, net............................. 5,032,952 693,959 1,115,361
----------- ----------- -----------
46,792,596 31,982,449 22,036,508
----------- ----------- -----------
Income Before Income Taxes.......................... 33,129,606 28,785,783 6,894,537
Provision for Income Taxes.......................... 10,819,417 9,760,333 1,982,025
----------- ----------- -----------
Net Income.......................................... $22,310,189 $19,025,450 $ 4,912,512
=========== =========== ===========
Per Share Amounts
Basic............................................. $ 1.35 $ 1.27 $ 0.49
=========== =========== ===========
Diluted........................................... $ 1.26 $ 1.25 $ 0.49
=========== =========== ===========
Weighted Average Shares Outstanding................. 16,492,856 15,000,901 10,035,143
=========== =========== ===========
</TABLE>

See accompanying notes to Consolidated Financial Statements

F-4
<PAGE> 191

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
======== ============ =========== ========= ============ ============
</TABLE>

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

(1) $.01 par value.

See accompanying notes to Consolidated Financial Statements

F-5
<PAGE> 192

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1997 1996 1995
------------- ------------ ------------
<S> <C> <C> <C>
Cash Flows from Operating Activities:
Net income.................................... $ 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............................. 24,247,142 16,526,379 8,838,657
Deferred income taxes...................... 10,060,193 8,449,283 2,326,162
Deferred revenue amortization related to
production payment....................... (1,449,808) (1,670,172) (1,787,974)
Other...................................... 786,917 140,047 112,890
Change in assets and liabilities --
Increase in accounts receivable.......... (204,475) (5,008,592) (488,599)
Increase (decrease) in accounts payable
and accrued liabilities, excluding
income taxes payable.................. (564,323) (444,966) 1,074,532
Increase (decrease) in income taxes
payable............................... 70,130 85,149 (611,717)
------------- ------------ ------------
Net Cash Provided by Operating
Activities.......................... 55,255,965 37,102,578 14,376,463
------------- ------------ ------------
Cash Flows from Investing Activities:
Additions to property and equipment........... (131,967,444) (91,487,176) (40,032,944)
Proceeds from the sale of property and
equipment.................................. 3,369,982 2,247,799 230,242
Net cash received (distributed) as operator of
oil and gas properties..................... (1,829,008) (2,074,104) 7,662,419
Net cash received (distributed) as operator of
partnerships and joint ventures............ (2,102,553) 11,284,793 5,316,693
Other......................................... (259,255) 840 (41,181)
------------- ------------ ------------
Net Cash Used in Investing
Activities.......................... (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................................. 7,915,000 -- (27,229,000)
Net proceeds from issuances of common stock... 2,389,336 3,264,482 46,306,322
Purchase of treasury stock.................... (8,519,665) -- --
Loan to ESOP for purchase of shares........... -- (568,750) --
Payments of debt issuance costs............... -- (4,550,000) --
------------- ------------ ------------
Net Cash Provided by Financing
Activities.......................... 1,784,671 113,145,732 19,077,322
------------- ------------ ------------
Net Increase (Decrease) in Cash and Cash
Equivalents................................... $ (75,747,642) $ 70,220,462 $ 6,589,014
Cash and Cash Equivalents at Beginning of
Year.......................................... 77,794,974 7,574,512 985,498
------------- ------------ ------------
Cash and Cash Equivalents at End of Year........ $ 2,047,332 $ 77,794,974 $ 7,574,512
============= ============ ============
Supplemental Disclosures of Cash Flows
Information:
Cash paid during year for interest, net of
amounts capitalized........................ $ 4,638,308 $ 831,516 $ 68,097
Cash paid during year for income taxes........ $ 381,514 $ 676,920 $ 277,580
</TABLE>

See accompanying notes to Consolidated Financial Statements

F-6
<PAGE> 193

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.

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 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,

F-7
<PAGE> 194
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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

F-8
<PAGE> 195
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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.

F-9
<PAGE> 196
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 Standard. In June 1997, the FASB issued SFAS No. 130,
"Reporting Comprehensive Income," which established standards for reporting and
displaying comprehensive income and its components in the financial statements.
SFAS No. 130 is effective for fiscal years beginning after December 15, 1997.
The adoption of this statement requires incremental financial statement
disclosure only, and thus will have no 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.

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, and 1995:

<TABLE>
<CAPTION>
1997 1996 1995
--------------------------------- --------------------------------- --------------------------------
PER PER PER
NET SHARE NET SHARE NET SHARE
INCOME SHARES AMOUNT INCOME SHARES AMOUNT INCOME SHARES AMOUNT
----------- ---------- ------ ----------- ---------- ------ ---------- ---------- ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Basic EPS:
Net Income and
Share Amounts.... $22,310,189 16,492,856 $1.35 $19,025,450 15,000,901 $1.27 $4,912,512 10,035,143 $0.49
Dilutive Securities:
6.25% Convertible
Notes............ 3,525,808 3,646,847 788,710 419,637 -- --
Stock Options...... -- 428,036 -- 407,108 -- --
----------- ---------- ----------- ---------- ---------- ----------
Diluted EPS:
Net Income and
Assumed Share
Conversions...... $25,835,997 20,567,739 $1.26 $19,814,160 15,827,646 $1.25 $4,912,512 10,035,143 $0.49
=========== ========== =========== ========== ========== ==========
</TABLE>

F-10
<PAGE> 197
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

3. PROVISION FOR INCOME TAXES

The following is an analysis of the consolidated income tax provision:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------
1997 1996 1995
----------- ---------- ----------
<S> <C> <C> <C>
Current....................................... $ 77,402 $ 759,253 $ (344,137)
Deferred...................................... 10,742,015 9,001,080 2,326,162
----------- ---------- ----------
Total............................... $10,819,417 $9,760,333 $1,982,025
=========== ========== ==========
</TABLE>

There are differences between income taxes computed using the statutory
rate (34% for 1997, 1996, and 1995) and the Company's effective income tax rates
(32.7%, 33.9%, and 28.7% for 1997, 1996, and 1995, respectively), primarily as
the result of certain tax credits available to the Company. Reconciliations of
income taxes computed using the statutory rate to the effective income tax rates
are as follows:

<TABLE>
<CAPTION>
1997 1996 1995
----------- ---------- ----------
<S> <C> <C> <C>
Income taxes computed at federal statutory
rate........................................ $11,264,066 $9,787,166 $2,344,143
State tax provisions, net of federal
benefits.................................... 48,058 75,936 84,202
Nonconventional fuel source credit............ (294,000) (306,000) (370,000)
Depletion deductions in excess of basis....... (51,000) (26,520) (34,000)
Other, net.................................... (147,707) 229,751 (42,320)
----------- ---------- ----------
Provision for income taxes.................... $10,819,417 $9,760,333 $1,982,025
=========== ========== ==========
</TABLE>

The tax effects of significant temporary differences representing the net
deferred tax liability at December 31, 1997 and 1996, were as follows:

<TABLE>
<CAPTION>
1997 1996
----------- -----------
<S> <C> <C>
Deferred tax assets:
Alternative minimum tax credits......................... $ 1,831,299 $ 1,517,470
Other................................................... 237,587 --
----------- -----------
Total deferred tax assets....................... $ 2,068,886 $ 1,517,470
Deferred tax liabilities:
Oil and gas properties.................................. $26,785,212 $15,935,855
Other................................................... 637,824 875,572
----------- -----------
Total deferred tax liabilities.................. $27,423,036 $16,811,427
----------- -----------
Net deferred tax liability................................ $25,354,150 $15,293,957
=========== ===========
</TABLE>

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

F-11
<PAGE> 198
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

$31.534 per share, subject to adjustment upon the occurrence of certain events.
The original conversion price of $34.6875 was adjusted downward to reflect the
October 1997 10% stock dividend. Interest on the Notes is payable semiannually
on May 15 and November 15, commencing with the first payment on May 15, 1997. On
or after November 15, 1999, the Notes are redeemable for cash at the option of
the Company, with certain restrictions, at 104.375% of principal, declining to
100.625% in 2005. Upon certain changes in control of the Company, if the price
of the Company's common stock is not above certain levels, each holder of Notes
will have the right to require the Company to repurchase the Notes at the
principal amount thereof, together with accrued and unpaid interest to the date
of repurchase but after the repayment of any Senior indebtedness, as defined.

The Company's long-term debt previously consisted of $28,750,000 of 6.5%
Convertible Subordinated Debentures due 2003 ("Debentures") issued on June 30,
1993, which were convertible into common stock of the Company at an adjusted
conversion price of $12.27 per share. On July 1, 1996, the Company called all of
the Debentures for redemption on August 5, 1996, at 104.55% of their face
amount. Prior to the redemption date, the holders of all of the outstanding
Debentures elected to convert their Debentures into shares of common stock,
resulting in the issuance of 2.34 million shares of common stock in August 1996.
Upon conversion of the Debentures into common stock, the approximate $27,650,000
net carrying amount of the debt (the face amount less unamortized deferred
charges) was transferred to the Company's appropriate capital accounts during
the third quarter of 1996.

Interest expense on the Notes, including amortization of debt issuance
costs, totaled $7,514,967 in 1997, while interest expense on both the Notes and
Debentures, including amortization of debt issuance costs, totaled $1,731,194 in
1996.

Bank Borrowings. At the end of 1996, the Company had available, through a
two bank-group, a $100,000,000 unsecured revolving line of credit. The available
borrowing base at December 31, 1996, was $5,000,000. Prior to December 1, 1996,
the borrowing base was $30,000,000. At the Company's request, it was reduced to
the $5,000,000 amount effective December 1, 1996. This was requested in order to
reduce the amount of commitment fees paid on this facility, the calculation of
which is described below. Depending on the level of outstanding debt, the
interest rate is either the bank's base rate (8.25% at December 31, 1996) or the
bank's base rate plus 0.25%. This facility also allows, at the Company's option,
draws which bear interest for specific periods at the London Interbank Offered
Rate ("LIBOR"). The LIBOR option will now vary from LIBOR plus 1% to plus 1.5%.
There was no outstanding balance under this line of credit at December 31, 1996.

Effective December 1, 1997, the available borrowing base was increased to
$40,000,000 and will be redetermined periodically. The interest rate was 8.5% at
December 31, 1997, with an outstanding balance at that date of $2,431,000. The
revolving line of credit extends through September 30, 1999.

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.

F-12
<PAGE> 199
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In addition to interest on these credit facilities, the Company pays a
commitment fee to compensate the banks for making funds available. The fee on
the revolving line of credit is calculated on the average daily remainder, if
any, of the commitment amount less the aggregate principal amounts outstanding,
plus the amount of all letters of credit outstanding during the period. The
aggregate amounts of commitment fees paid by the Company were $31,000 in 1997
and $120,000 in 1996.

5. COMMITMENTS AND CONTINGENCIES

Total rental and lease expenses were $1,039,210 in 1997, $957,797 in 1996,
and $998,714 in 1995. The Company's remaining minimum annual obligations under
non-cancelable operating lease commitments are $1,136,523 for 1998, $1,175,546
for 1999, $1,181,455 for 2000, $1,181,455 for 2001, and $1,303,130 for 2002.

As of December 31, 1997, the Company is the managing general partner of 89
limited partnerships. Because the Company serves as the general partner of these
entities, under state partnership law it is contingently liable for the
liabilities of these partnerships, which liabilities are not material for any of
the periods presented in relation to the partnerships' respective assets.

In the ordinary course of business, the Company has been party to various
legal actions, which arise primarily from its activities as operator of oil and
gas wells. In management's opinion, the outcome of any such currently pending
legal actions will not have a material adverse effect on the financial position
or results of operations of the Company.

6. STOCKHOLDERS' EQUITY

Common Stock. In October 1997, the Company declared a 10% stock dividend to
shareholders of record. The transaction was valued based on the closing price
($28.8125) of the Company's common stock on the New York Stock Exchange on
October 1, 1997. As a result of the issuance of 1,494,606 shares of the
Company's common stock as a dividend, retained earnings were reduced by
$43,063,335, with the common stock and additional paid-in capital accounts
increased by the same amount. Basic and diluted income per share was restated
for all periods presented to reflect the effect of the stock dividend.

In August 1996, the holders of the Company's Debentures converted such
Debentures into 2,343,108 shares of the Company's common stock, which resulted
in a third quarter 1996 increase in the Company's capital accounts of
approximately $27,650,000.

Stock-Based Compensation Plans. The Company has two stock option plans, the
1990 stock compensation plan and the 1990 nonqualified plan, as well as an
employee stock purchase plan.

Under the 1990 compensation plan, incentive stock options and other options
and awards may be granted to employees to purchase shares of common stock. Under
the 1990 non-qualified plan, non-employee 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

F-13
<PAGE> 200
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

commenced June 1, 1993. Employees may authorize payroll deductions of up to 10%
of their base salary during the plan year by making an election to participate
prior to the start of a plan year. The purchase price for stock acquired under
the plan will be 85% of the lower of the closing price of the Company's common
stock as quoted on the New York Stock Exchange at the beginning or end of the
plan year or a date during the year chosen by the participant. Under this plan
the Company issued 26,551 shares at a price of $15.19 in 1997, 36,387 shares at
a price range of $6.59 to $7.97 in 1996, and 37,689 shares at a price range of
$6.80 to $7.92 in 1995. The estimated weighted average fair value of shares
issued under this plan was $4.39 in 1997, $2.13 in 1996, and $2.59 in 1995. As
of December 31, 1997, there remained 458,204 shares available for issuance under
this plan. There are no charges or credits to income in connection with this
plan.

The Company accounts for the two stock option plans under APB Opinion No.
25, under which no compensation cost has been recognized. Had compensation cost
for these plans been determined consistent with SFAS No. 123, "Accounting for
Stock-Based Compensation," the Company's net income and earnings per share would
have been reduced to the following pro forma amounts (1996 and 1995 amounts have
been restated to reflect the October 1997 10% stock dividend):

<TABLE>
<CAPTION>
1997 1996 1995
----------- ----------- ----------
<S> <C> <C> <C> <C>
Net Income: As Reported.................. $22,310,189 $19,025,450 $4,912,512
Pro Forma.................... $21,362,722 $18,750,064 $4,628,678
Basic EPS: As Reported.................. $ 1.35 $ 1.27 $ 0.49
Pro Forma.................... $ 1.30 $ 1.25 $ 0.46
Diluted EPS: As Reported.................. $ 1.26 $ 1.25 $ 0.49
Pro Forma.................... $ 1.21 $ 1.23 $ 0.46
</TABLE>

Because the SFAS No. 123 method of accounting has not been applied to
options granted prior to January 1, 1995, the resulting pro forma compensation
cost may not be representative of that to be expected in future years.

F-14
<PAGE> 201
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following is a summary of the Company's stock options under these plans
as of December 31, 1997, 1996, and 1995:

<TABLE>
<CAPTION>
1997 1996 1995
----------------------- ----------------------- -----------------------
WTD. AVG. WTD. AVG. WTD. AVG.
SHARES EXER. PRICE SHARES EXER. PRICE SHARES EXER. PRICE
--------- ----------- --------- ----------- --------- -----------
<S> <C> <C> <C> <C> <C> <C>
Options outstanding,
beginning of period... 1,399,769 $12.09 1,308,391 $ 8.83 1,166,920 $8.86
Options granted......... 401,390 $26.23 302,281 $23.78 227,502 $8.63
Options terminated...... (31,404) $12.99 (11,251) $ 8.81 (80,270) $8.78
Options exercised....... (137,155) $ 8.54 (199,652) $ 8.65 (5,761) $7.59
Options adjusted for 10%
stock dividend........ 128,912 -- --
--------- --------- ---------
Options outstanding, end
of period............. 1,761,512 $14.71 1,399,769 $12.09 1,308,391 $8.83
========= ========= =========
Options exercisable, end
of period............. 869,484 $ 9.05 700,271 $ 8.82 722,627 $8.81
========= ========= =========
Options available for
future grant, end of
period................ 1,501,622 38,546 343,344
========= ========= =========
Estimated weighted
average fair value per
share of options
granted during the
year.................. $ 13.98 $ 15.17 $ 4.76
========= ========= =========
</TABLE>

The fair value of each option grant, as opposed to its exercise price, is
estimated on the date of grant using the Black-Scholes option-pricing model with
the following weighted average assumptions in 1997, 1996, and 1995,
respectively: no dividend yield, expected volatility factors of 38.7%, 40.4%,
and 39.7%, risk-free interest rates of 6.02%, 6.42%, and 6.98%, and expected
lives of 7.5, 10.0, and 7.7 years. The following table summarizes information
about stock options outstanding at December 31, 1997:

<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------------- ------------------------
WTD. AVG. NUMBER
NUMBER REMAINING WTD. AVG. EXERCISABLE WTD. AVG.
OUTSTANDING CONTRACTUAL EXERCISE AT EXERCISE
RANGE OF EXERCISE PRICES AT 12/31/97 LIFE PRICE 12/13/97 PRICE
------------------------ ----------- ----------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C>
$4 to $9................. 787,384 4.8 $ 7.73 606,413 $ 7.63
$9 to $18................ 358,900 6.2 $10.67 220,631 $ 9.68
$18 to $27................ 615,228 9.5 $26.00 42,440 $25.91
--------- -------
$4 to $27................ 1,761,512 6.7 $14.71 869,484 $ 9.05
========= =======
</TABLE>

Employee Stock Ownership Plan. In 1996, the Company established an Employee
Stock Ownership Plan ("ESOP") effective January 1, 1996. All employees over the
age of 21 with one year of service are participants. The Plan has a five year
cliff vesting, and service is recognized after the Plan effective date. The ESOP
is designed to enable employees of the Company to accumulate stock ownership.
While there will be no employee contributions, participants will receive an
allocation of stock which has been contributed by the Company. Compensation
costs are reported when such shares are released to employees. The Plan may also
acquire Swift Energy Company common stock purchased at fair market value. The
ESOP can borrow money from the Company to buy Company stock. This was done in
September 1996 to purchase 25,000 shares (adjusted to 27,500 shares after the
October 1, 1997 10% stock dividend) from the Company's chairman. Benefits will
be paid in a lump sum or installments, and the participants generally have the
choice of receiving

F-15
<PAGE> 202
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

cash or stock. At December 31, 1997 and 1996, the unearned portion of the ESOP
($150,055) and ($521,354), respectively, was recorded as a contra-equity account
entitled "Unearned ESOP Compensation."

Common Stock Repurchase Program. In March 1997, the Company's Board of
Directors approved a common stock repurchase program for up to $20.0 million of
the Company's common stock and subsequently extended this program through June
30, 1998. Purchases of shares are made in the open market. Under the program,
through December 31, 1997, 387,800 shares have been acquired at a total cost of
$8,519,665 and are included in "Treasury stock held, at cost" on the balance
sheet.

Shareholder Rights Plan. In August 1997, the Board of Directors declared a
dividend of one preferred share purchase right on each outstanding share of the
Company's common stock. The rights are not currently exercisable, but would
become exercisable if certain events occurred relating to any person or group
acquiring or attempting to acquire 15% or more of the Company's outstanding
shares of common stock. Thereafter, upon certain triggers, each right not owned
by an acquiror allows its holder to purchase Company securities with a market
value of two times the $150 exercise price.

7. RELATED-PARTY TRANSACTIONS

The Company is the operator of a substantial number of properties owned by
its affiliated limited partnerships and joint ventures and accordingly charges
these entities and third party joint interest owners operating fees. The Company
is also reimbursed for direct, administrative, and overhead costs incurred in
conducting the business of the limited partnerships, which totaled approximately
$6,300,000, $6,100,000, and $4,800,000 in 1997, 1996, and 1995, respectively.
The Company was also reimbursed by the limited partnerships and joint ventures
for costs incurred in the screening, evaluation, and acquisition of producing
oil and gas properties on their behalf. Such costs totaled approximately
$490,000, $250,000, and $600,000 in 1997, 1996, and 1995, respectively. In the
case where the limited partners voted to sell their remaining properties and
liquidate the limited partnerships, the Company was also reimbursed for direct,
administrative, and overhead costs incurred in the disposition of such
properties, which costs totaled approximately $675,000, $805,000, and $80,000 in
1997, 1996, and 1995, respectively.

8. FOREIGN ACTIVITIES

On September 3, 1993, the Company signed a Participation Agreement with
Senega, a Russian Federation joint stock company (in which the Company has an
indirect interest of less than 1%), to assist in the development and production
of reserves from two fields in Western Siberia providing the Company with a
minimum 5% net profits interest from the sale of hydrocarbon products from the
fields for providing managerial, technical, and financial support to Senega.
Additionally, the Company purchased a 1% net profits interest from Senega for
$300,000. In May 1995, the Company executed a Management Agreement with Senega,
under which, in return for undertaking to obtain financing for development of
these fields, Swift would be entitled to receive a 49% interest in production
income derived by Senega from this project after repayment of costs.

On December 10, 1997, the Company agreed to terminate the Management
Agreement with Senega and to amend and restate the Participation Agreement.
Under the amended and restated Participation Agreement, the Company retains its
6% net profits interest in the Samburg Field and has agreed to assist Senega in
obtaining investments necessary to develop the field. Senega is charged with the
management and control of the field development. At December 31, 1997, the
Company's investment in Russia was approximately $10,190,000 and is included in
the unproved properties portion of oil and gas properties.

The Company formed a wholly-owned subsidiary, Swift Energy de Venezuela, C.
A., for the purpose of submitting a bid on August 5, 1993, under the Venezuelan
Marginal Oil Field Reactivation Program. Although the Company did not win the
bid, it has continued to pursue cooperative ventures involving other

F-16
<PAGE> 203
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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.

F-17
<PAGE> 204
SWIFT ENERGY COMPANY AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION (UNAUDITED) -- (CONTINUED)

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.

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>

F-18
<PAGE> 205
SWIFT ENERGY COMPANY AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION (UNAUDITED) -- (CONTINUED)

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.

(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.

F-19
<PAGE> 206
SWIFT ENERGY COMPANY AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION (UNAUDITED) -- (CONTINUED)

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> 207
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 and 1997:

<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
=========== =========== =========== ===== =====
</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> 208

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> 209

PARTNERSHIPS COMBINED BALANCE SHEET

ASSETS

<TABLE>
<CAPTION>
DECEMBER 31,
1997
--------------
(IN THOUSANDS)
<S> <C>
Current Assets:
Cash and cash equivalents................................. $ 7,429
Accounts receivable --
Oil and gas sales...................................... 9,965
Other.................................................. 1,782
Other current assets...................................... 92
--------
Total Current Assets.............................. 19,268
--------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized...................... 328,373
Less-Accumulated depreciation, depletion, and
amortization........................................... (239,044)
--------
89,329
--------
Total Assets...................................... $108,597
========

LIABILITIES AND PARTNERS' CAPITAL

Current Liabilities:
Accounts payable.......................................... $ 2,718
Other..................................................... 711
--------
Total Current Liabilities......................... 3,429
--------
Deferred Revenues........................................... 1,251
Limited Partners' Capital................................... 101,783
General Partners' Capital................................... 2,134
--------
Total Liabilities and Partners' Capital........... $108,597
========
</TABLE>

See accompanying notes to Combined Financial Statements

F-23
<PAGE> 210

PARTNERSHIPS COMBINED STATEMENT OF INCOME

<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
1997
--------------
(IN THOUSANDS)
<S> <C>
Revenues:
Oil and gas sales......................................... $42,228
Interest income........................................... 330
Other..................................................... 266
-------
42,824
-------
Costs and Expenses:
General and administrative................................ 5,206
Depreciation, depletion, and amortization --
Normal provision....................................... 13,012
Additional provision................................... 3,845
Oil and gas production.................................... 13,774
Interest expense.......................................... 21
-------
35,858
=======
Net Income........................................ $ 6,966
=======
</TABLE>

See accompanying notes to Combined Financial Statements

F-24
<PAGE> 211

PARTNERSHIPS COMBINED STATEMENT 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
======== ======= ======= ========
</TABLE>

See accompanying notes to Combined Financial Statements

F-25
<PAGE> 212

PARTNERSHIPS COMBINED STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
1997
--------------
(IN THOUSANDS)
<S> <C>
Cash Flows From Operating Activities:
Net Income................................................ $ 6,966
Adjustments to reconcile income to net cash provided by
operations:
Depreciation, depletion, and amortization.............. 16,857
Change in gas imbalance receivable and deferred
revenues.............................................. 123
Change in assets and liabilities:
Decrease in oil and gas sales receivable............. 774
Increase in other current assets..................... (64)
Decrease in accounts payable......................... (914)
--------
Net cash provided by operating activities......... 23,742
--------
Cash Flows From Investing Activities:
Additions to oil and gas properties....................... (3,503)
Proceeds from sales of oil and gas properties............. 4,491
Decrease in receivable due to property dispositions....... 1,015
--------
Net cash provided by investing activities......... 2,003
--------
Cash Flows From Financing Activities:
Cash distributions to partners............................ (25,485)
--------
Net cash used in financing activities............. (25,485)
--------
Net Increase In Cash and Cash Equivalents................... $ 260
--------
Cash and Cash Equivalents At Beginning of Year.............. 7,169
--------
Cash and Cash Equivalents at End of Year.................... $ 7,429
========
Supplemental disclosure of cash flow information:
Cash paid during the year for interest.................... $ 11
========
</TABLE>

See accompanying notes to Combined Financial Statements

F-26
<PAGE> 213

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> 214
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.

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.

Cash and Cash Equivalents --

Highly liquid debt instruments with an initial maturity of three months or
less are considered to be cash equivalents.

F-28
<PAGE> 215
NOTES TO COMBINED FINANCIAL STATEMENTS OF THE PARTNERSHIPS -- (CONTINUED)

(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 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.

F-29
<PAGE> 216
NOTES TO COMBINED FINANCIAL STATEMENTS OF THE PARTNERSHIPS -- (CONTINUED)

(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> 217
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> 218
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> 219
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> 220

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> 221
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 PROSPECTUS, AND, IF GIVEN OR MADE, SUCH
INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED
BY THE COMPANY OR ANY UNDERWRITERS. NEITHER THE DELIVERY OF THIS 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 PROSPECTUS IS NOT AN OFFER TO SELL OR A SOLICITATION OF AN
OFFER TO BUY ANY SECURITY IN ANY JURISDICTION TO ANY PERSON TO WHOM IT IS
UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION.

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

TABLE OF CONTENTS

<TABLE>
<CAPTION>
Page
----
<S> <C>
Available Information..............................................................2
Defined Terms......................................................................2
Prospectus Summary.................................................................5
Risk Factors......................................................................12
Use of Proceeds...................................................................16
Price Range of Common Stock and
Dividend Policy................................................................17
Capitalization....................................................................18
Unaudited Pro Forma Consolidated
Financial Statements...........................................................19
Selected Consolidated Historical
Financial Data.................................................................25
Management's Discussion and Analysis of
Financial Condition and Results of
Operations.....................................................................26
Business and Properties...........................................................33
Management........................................................................48
Principal Shareholders............................................................50
Certain Relationships and Related
Transactions...................................................................52
Description of Capital Stock......................................................53
Material Federal Income Tax
Considerations.................................................................56
Legal Matters.....................................................................57
Experts...........................................................................57
Incorporation of Certain Information by
Reference......................................................................58
Index to Consolidated Financial Statements.......................................F-1
</TABLE>

2,500,000 Shares

SWIFT
ENERGY
COMPANY

Common Stock

[SWIFT ENERGY LOGO]

PROSPECTUS

DATED ________, 1998

<PAGE> 222

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> 223
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> 224
<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> 225
<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> 226
<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 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 (included on signature page of this Registration Statement)

27 Financial Data Schedule (included in electronic filing only)

*99.1 Reserve Letter Report of H. J. Gruy and Associates, Inc. for Swift Energy Managed
Pension Assets 1988-A, Ltd.

*99.2 Reserve Letter Report of H. J. Gruy and Associates, Inc. for Swift Energy Income
Partners 1989-B, Ltd.

*99.3 Reserve Letter Report of H. J. Gruy and Associates, Inc. for Swift Energy Pension
Partners 1993-B, Ltd.

*99.4 Valuation Estimate of J. R. Butler and Company for Swift Energy Managed Pension
Assets 1988-A, Ltd.

*99.5 Valuation Estimate of J. R. Butler and Company for Swift Energy Income Partners
1989-B, Ltd.

*99.6 Valuation Estimate of J. R. Butler and Company for Swift Energy Pension Partners
1993-B, Ltd.

*99.7 Valuation Estimate of H. J. Gruy and Associates, Inc. for Swift Energy Managed
Pension Assets 1988-A, Ltd.

*99.8 Valuation Estimate of H. J. Gruy and Associates, Inc. for Swift Energy Income
Partners 1989-B, Ltd.

*99.9 Valuation Estimate of H. J. Gruy and Associates, Inc. for Swift Energy Income
Partners 1993-B, Ltd.

*99.10 Valuation Estimate of CIBC Oppenheimer Corp. for Swift Energy Managed Pension
Assets 1988-A, Ltd.

*99.11 Valuation Estimate of CIBC Oppenheimer Corp. for Swift Energy Income Partners
1989-B, Ltd.

*99.12 Valuation Estimate of CIBC Oppenheimer Corp. for Swift Energy Pension Partners
1993-B, Ltd.

</TABLE>

II-5
<PAGE> 227

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

* Filed herewith.

** To be filed by amendment

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> 228

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the
registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Houston,
State of Texas, on April 21, 1998.

SWIFT ENERGY COMPANY

By: /s/ A. EARL SWIFT
-----------------------------------------
A. Earl Swift,
Chairman of the Board and Chief Executive
Officer, Swift Energy Company

Each person whose signature appears below hereby constitutes and appoints
A. Earl Swift, John R. Alden and Alton D. Heckaman, Jr., and each of them, each
with full power to act without the other, his true and lawful attorneys-in-fact
and agents, each with full power of substitution and resubstitution for him and
in his name, place and stead, in any and all capacities, to sign any or all
amendments to this Registration Statement (including post-effective amendments),
and to file the same with all exhibits thereto and other documents in connection
therewith, with the Securities and Exchange Commission, granting unto each of
said attorneys-in-fact and agents full power and authority to do and perform
each and every act and thing requisite and necessary to be done in connection
therewith, as fully to all intents and purposes as he might or could do in
person hereby ratifying and confirming that each of said attorneys-in-fact and
agents or his substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended,
this Registration Statement has been signed below in multiple counterparts with
the effect of one original by the following persons in the capacities and on the
dates indicated.

<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
/s/ A. EARL SWIFT Chairman of the Board April 21, 1998
- ------------------------------------ and Chief Executive Officer,
A. EARL SWIFT Swift Energy Company

/s/ JOHN R. ALDEN Senior Vice President-- Finance, April 21, 1998
- ------------------------------------ Chief Financial Officer, Swift
JOHN R. ALDEN Energy Company

/s/ ALTON D. HECKAMAN, JR. Vice President -- April 21, 1998
- ------------------------------------ Finance and Controller,
ALTON D. HECKAMAN, JR. Principal Accounting Officer,
Swift Energy Company

/s/ G. ROBERT EVANS Director, Swift Energy Company April 21, 1998
- ------------------------------------
G. ROBERT EVANS
</TABLE>

II-7
<PAGE> 229

<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
/s/ RAYMOND O. LOEN Director, Swift Energy Company April 21, 1998
- ------------------------------------
RAYMOND O. LOEN

Director, Swift Energy Company April 21, 1998
- ------------------------------------
HENRY C. MONTGOMERY

Director, Swift Energy Company April 21, 1998
- ------------------------------------
CLYDE W. SMITH, JR.

/s/ HAROLD J. WITHROW Director, Swift Energy Company April 21, 1998
- ------------------------------------
HAROLD J. WITHROW
</TABLE>

II-8
<PAGE> 230
EXHIBIT INDEX

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)

**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

<PAGE> 231
<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)

<PAGE> 232
<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)

10.14 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)

<PAGE> 233
<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)