SWIFT ENERGY CO, 424B1, 1995-07-27

SWIFT ENERGY CO
424B1, 1995-07-27
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1

5,000,000 SHARES

(LOGO)
SWIFT ENERGY COMPANY
COMMON STOCK
------------------------------
All of the shares of Common Stock offered hereby are being sold by Swift
Energy Company ("Swift" or the "Company"). The Company's Common Stock is listed
on the New York Stock Exchange and the Pacific Stock Exchange under the symbol
"SFY." On July 25, 1995, the last reported sale price of the Company's Common
Stock on the New York Stock Exchange was $8.625 per share. See "Price Range of
Common Stock and Dividend Policy."

THE COMMON STOCK OFFERED HEREBY INVOLVES A HIGH DEGREE OF RISK.
SEE "RISK FACTORS" ON PAGE 7.
------------------------------
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. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------
PRICE TO UNDERWRITING PROCEEDS TO
PUBLIC DISCOUNT(1) COMPANY(2)
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Per Share......................... $8.50 $0.48 $8.02
Total(3).......................... $42,500,000 $2,400,000 $40,100,000
- -------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------
</TABLE>

(1) See "Underwriting" for information concerning indemnification of the
Underwriters and other information.
(2) Before deducting expenses of the offering payable by the Company estimated
at $500,000.
(3) The Company has granted the Underwriters an option, exercisable within 30
days of the date hereof, to purchase up to 750,000 additional shares of
Common Stock for the purpose of covering over-allotments, if any. If the
Underwriters exercise such option in full, the total Price to Public,
Underwriting Discount and Proceeds to Company will be $48,875,000,
$2,760,000 and $46,115,000, respectively. See "Underwriting."
------------------------------
The shares of Common Stock are offered severally by the Underwriters when,
as and if delivered to and accepted by them, subject to their right to withdraw,
cancel or reject orders in whole or in part and subject to certain other
conditions. It is expected that delivery of the certificates representing the
shares will be made against payment on or about July 31, 1995 at the offices of
Oppenheimer & Co., Inc., Oppenheimer Tower, World Financial Center, New York,
New York 10281.
------------------------------
OPPENHEIMER & CO., INC.
MORGAN KEEGAN & COMPANY, INC.
SOUTHCOAST CAPITAL
CORPORATION

The date of this Prospectus is July 26, 1995.
<PAGE> 2

AVAILABLE INFORMATION

The Company has filed with the Securities and Exchange Commission (the
"SEC") a Registration Statement on Form S-2 (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 SEC. The Registration
Statement, the exhibits thereto, and the Reports, can be inspected and copied at
the public reference facilities maintained by the SEC at 450 5th Street, N.W.,
Room 1024, Washington, D.C. 20549, and at the following regional offices of the
SEC: 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 CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK AT
A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH
TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE, THE PACIFIC STOCK
EXCHANGE OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT
ANY TIME.

DEFINED TERMS

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

"BCF " means billion cubic feet of natural gas.

"BCFE" means billion cubic feet equivalent. See "-- Mcfe."

"BBL" means barrel or barrels of oil.

"MBBL" means thousand barrels of oil.

"MMBBL" means million barrels of oil.

"MMBTU" means a 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 price per MMBtu, the same basis
on which natural gas is contracted for sale.

"MCF " means thousand cubic feet of natural gas.

"MCFE" means thousand cubic feet equivalent which is determined using the ratio
of one barrel of oil, condensate or natural gas liquids to six Mcf of natural
gas.

"MMCF " means million cubic feet of natural gas.

"MMCFE" means million cubic feet equivalent. See "-- Mcfe."

"PV-10 VALUE" means 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. See "Risk
Factors -- Uncertainty of Estimates of Reserves and Future Net Revenues."

"RESERVE REPLACEMENT COST" means, with respect to proved reserves, a three-year
average calculated by dividing total acquisition, exploration and development
costs by net reserves added during the period.

"VOLUMETRIC PRODUCTION PAYMENT" means the 1992 agreement pursuant to which the
Company financed the purchase of certain oil and gas interests and committed to
deliver certain monthly quantities of natural gas. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- General."

2
<PAGE> 3

PROSPECTUS SUMMARY

This summary is qualified in its entirety by the detailed information and
financial data appearing elsewhere in this Prospectus. In September 1994, the
Company distributed a 10% stock dividend. Primary and fully diluted income
(loss) per share has been restated for all periods set forth in this Prospectus
to reflect the effect of the stock dividend. Investors should carefully consider
the information set forth under "Risk Factors." Unless otherwise indicated, the
information contained in this Prospectus assumes that the Underwriters' over-
allotment option will not be exercised. The Company's principal executive
offices are located at 16825 Northchase Drive, Suite 400, Houston, Texas 77060,
and its telephone number is (713) 874-2700. Defined terms used herein to
describe quantities of oil and gas and other matters are explained under
"Defined Terms" above.

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. The Company has interests in approximately 4,100 oil and gas wells
located in 15 states, with over 80% of its proved reserve base concentrated in
Texas, Oklahoma and Louisiana. The Company was formed in 1979 and, since 1985,
has grown primarily through the acquisition of producing properties funded
through limited partnership financing. Commencing in 1991, the Company began to
re-emphasize the addition of reserves through increased exploration and
development drilling activity while significantly reducing its reliance on
limited partnership financing. In 1994, the Company added approximately 24.8
Bcfe of proved reserves through exploration and development drilling, at a cost
of $0.51 per Mcfe, representing approximately 250% of 1994 production.

The Company's proved reserve base, production and cash flow from operations
have increased at annualized compounded rates of 35%, 38% and 30%, respectively,
over the last five years. At May 31, 1995, the Company had estimated proved
reserves of 133.3 Bcf of natural gas and 5.4 MMBbls of oil (totalling
approximately 165.8 Bcfe) with a PV-10 Value of approximately $100.2 million.
The proved reserves at May 31, 1995 represent an increase of 60% over estimated
amounts at December 31, 1994. Approximately 80% of the Company's proved reserve
base at that date was natural gas. The Company's reserve replacement cost over
the last three years has averaged $0.79 per Mcfe, which it believes is better
than industry averages.

At December 31, 1994, the Company operated 750 wells which represented 61%
of its proved reserve base, and managed reserves on behalf of limited
partnerships which, exclusive of the Company's interests, had proved reserves of
approximately 200 Bcfe. Five oil and gas fields accounted for 54% of the
Company's PV-10 Value at December 31, 1994, of which the two largest were the
AWP Olmos Field and the Giddings Field. The AWP Olmos Field, located in McMullen
County, Texas, and the Giddings Field located in Fayette County, Texas,
accounted for 25% and 12%, respectively, of the Company's PV-10 Value as of such
date. The Company believes that the Giddings Field's prolific but short-lived
wells complement the long-lived reserves of the AWP Olmos Field. The application
of advanced technologies and achievement of operating efficiencies have enabled
the Company to reduce costs and enhance reserve recoveries in these fields.

BUSINESS STRATEGY

Key elements of the Company's strategy include the following:

3
<PAGE> 4

$55.0 million on development drilling activities, including approximately
$30.0 million in the AWP Olmos and Giddings fields in Texas. The Company
pursues a "controlled risk" approach to exploration, focusing its
exploration activities in regions where it possesses technological or
geological expertise and which are adjacent to known producing horizons.
The Company also is pursuing opportunities in Russia and Venezuela. Swift
currently anticipates expenditures of approximately $15.0 million on
exploratory drilling through 1996 in the Yegua, Frio, Lobo, Wilcox and
Austin Chalk trends in the Gulf Coast Basin, the Smackover trend in the
North Louisiana Salt Dome Basin, the Red Fork formation in the Anadarko
Basin in Oklahoma and the Minnelusa trend in Wyoming.

- Strategic acquisitions. Through December 31, 1994, the Company had
acquired approximately $460.0 million of producing oil and natural gas
properties on behalf of itself and its co-investors in 120 separate
transactions. Approximately $108.0 million of this amount, representing
approximately 139.7 Bcfe, was acquired for the Company's own account,
including 12.9 Bcfe purchased in 1994. The Company is continuously
reviewing acquisition opportunities, with a particular emphasis on
identifying properties in close proximity to the Company's current
reserves, where such reserves can be increased through development
drilling and improved operating efficiencies can be achieved. Using these
criteria, the Company employs a disciplined, market-driven approach to
acquisitions that can result in varying levels of annual spending on
acquisitions. Through 1996, the Company anticipates spending
approximately $25.0 million for the acquisition of producing property
interests, including the purchase of interests from limited partnerships.

- Application of advanced technologies. To minimize the risks associated
with exploration and development drilling and improve operating results,
the Company has devoted considerable resources to develop advanced
technological expertise. These technologies include 2-D and 3-D seismic
analysis, AVO (amplitude versus offset) studies and detailed formation
depletion studies. The Company has attained substantial expertise in
horizontal well technology, having participated in 17 such wells in the
past two years with a 100% success rate. Additionally, the use of
innovative fracturing methods and coiled tubing technology in the AWP
Olmos Field has enabled the Company to achieve improved production
yields.

THE OFFERING

<TABLE>
<S> <C>
Common Stock Offered by the Company.......... 5,000,000 shares.
Common Stock Outstanding after the
Offering(1)................................ 11,718,742 shares.
Use of Proceeds(2)........................... Net proceeds of this offering will be used to
repay outstanding indebtedness under the
Company's credit facilities, and will be
added to working capital to be available for
exploration and development activities,
acquisitions and general corporate purposes.
New York Stock Exchange and Pacific Stock
Exchange Symbol............................ SFY.
</TABLE>

- ---------------
(1) Calculated as of May 31, 1995, and includes 8,330 shares issued between
March 31, 1995 and May 31, 1995 pursuant to stock benefit plans, but
excludes (a) 1,324,288 shares issuable upon exercise of employee and
director stock options outstanding as of May 31, 1995, (b) 68,750 shares
issuable upon the exercise of stock options outstanding as of May 31, 1995,
granted to other individuals, and (c) 2,343,113 shares issuable upon
conversion of the outstanding $28.75 million of 6 1/2% Convertible
Subordinated Debentures due 2003. See "Management" and the Company's
Consolidated Financial Statements and the Notes thereto.

(2) See "Use of Proceeds."

4
<PAGE> 5

SUMMARY FINANCIAL DATA

The following tables, parts of which have been derived from the Company's
audited financial statements, set forth selected historical financial
information for the Company and should be read in conjunction with the Company's
Consolidated Financial Statements and Notes thereto and "Management's Discussion
and Analysis of Financial Condition and Results of Operations" herein. The
financial data for the three-month periods ended March 31, 1995 and 1994 were
derived from the unaudited financial statements of the Company that, in
management's opinion, include all adjustments (consisting of only normal
recurring adjustments, except as disclosed below) necessary to present fairly
the results for such periods. The operating results for such periods are not
necessarily indicative of the operating results to be expected for a full fiscal
year and none of the data presented below are necessarily indicative of future
results.

<TABLE>
<CAPTION>
YEARS ENDED THREE MONTHS
DECEMBER 31, ENDED MARCH 31,
-------------------------------- ---------------------
1992 1993 1994 1994 1995
------- ------- -------- -------- ------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
SELECTED OPERATING DATA:
Revenues..................................... $19,209 $24,133 $ 25,375 $ 6,139 $6,259
Costs and expenses:
General and administrative (net)........... 4,977 5,065 5,198 1,196 1,307
Depreciation, depletion and amortization... 4,906 7,301 7,905 1,689 2,168
Oil and gas production..................... 3,934 4,540 5,639 1,142 1,629
Interest expense........................... 76 598 1,795 359 478
Other expenses............................. 628 -- -- -- --
------- ------- ------- -------- ------
Income before income taxes................... 4,688 6,629 4,838 1,753 677
Income before cumulative effect of change in
accounting principle....................... 3,170 4,897 3,726 1,211 525
------- ------- ------- -------- ------
Cumulative effect of change in accounting
principle.................................. 915(1) -- (16,773)(2) (16,773)(2) --
------- ------- ------- -------- ------
Net income (loss)............................ $ 4,085 $ 4,897 $(13,047) $(15,562) $ 525
======= ======= ======= ======== ======
Per share data:
Primary:
Income before cumulative effect of change
in accounting principle............... $ 0.52 $ 0.74 $ 0.56 $ 0.18 $ 0.08
Cumulative effect of change in accounting
principle............................. 0.15 -- (2.52) (2.54) --
------- ------- ------- -------- ------
Net income (loss)........................ $ 0.67 $ 0.74 $ (1.96) $ (2.36) $ 0.08
======= ======= ======= ======== ======
Fully diluted:
Income before cumulative effect of change
in accounting principle............... $ 0.52 $ 0.70 $ 0.56 $ 0.17 $ 0.08
Cumulative effect of change in accounting
principle............................. 0.15 -- (2.52) (2.54) --
------- ------- ------- -------- ------
Net income (loss)........................ $ 0.67 $ 0.70 $ (1.96) $ (2.36) $ 0.08
======= ======= ======= ======== ======
Weighted average shares outstanding.......... 6,135 6,588 6,644 6,602 6,689
======= ======= ======= ======== ======
OTHER DATA:
Net cash provided by operating activities.... $ 6,349 $ 7,238 $ 10,395 $ 2,680 $2,964
Capital expenditures......................... 34,401 24,229 34,531 4,043 5,745
</TABLE>

<TABLE>
<CAPTION>
MARCH 31, 1995
DECEMBER 31, -------------------------
1994 ACTUAL AS ADJUSTED(3)
------------ -------- --------------
<S> <C> <C> <C>
BALANCE SHEET DATA:
Working capital..................................................... $(13,137) $(16,729) $ 22,871
Total assets........................................................ 135,673 135,795 144,845
Short-term bank borrowings.......................................... 27,229 30,550 --
Long-term debt...................................................... 28,750 28,750 28,750
Stockholders' equity................................................ 42,127 42,878 82,478
</TABLE>

Footnotes on following page

5
<PAGE> 6

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

(1) Effective January 1, 1992, the Company elected to adopt SFAS No. 109. The
cumulative effect of this change resulted in an increase in net income of
$915,000, reflected in the first quarter of 1992.

(2) In the fourth quarter of 1994, the Company adopted a new method of
accounting for earned interests with respect to the limited partnerships for
which it serves as general partner, effective January 1, 1994, whereby
earned interests are no longer recognized as income. The effect of the
change in 1994 was to increase income before cumulative effect of accounting
principle by approximately $1,047,000 or $.16 per share. The cumulative
effect of this change in accounting principle resulted in an adjustment of
$16,772,698 or $(2.52) per share (after a reduction for income taxes of
$8,640,481) in the first quarter of 1994, to apply the new method
retroactively, thereby reducing net income in 1994. The Company believes the
change in policy results in financial statements that better reflect its
current business focus and that are more comparable to current practices in
the oil and gas exploration and production business. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- General" and Note 2 to the Company's Consolidated Financial
Statements.

(3) As adjusted to give effect to the sale of 5,000,000 shares of the Common
Stock offered hereby at the offering price of $8.50 per share and the
application of the net proceeds therefrom as described in "Use of Proceeds."

SUMMARY OIL AND GAS RESERVE AND OPERATING DATA

The following table sets forth certain summary information as of December
31, 1994 and May 31, 1995, with respect to estimates prepared by the Company,
and audited by H.J. Gruy and Associates, Inc., independent petroleum engineers,
of the Company's proved oil and gas reserves, the future net revenues therefrom,
and their PV-10 Value. Estimates are based upon weighted average prices of $1.85
per Mcf of natural gas and $15.09 per barrel of oil at December 31, 1994, and
$2.03 per Mcf of natural gas and $16.68 per barrel of oil at May 31, 1995, at
each date holding prices constant throughout the life of the properties in
accordance with regulations of the SEC. This information is based upon numerous
assumptions and is subject to change due to numerous factors. See "Business and
Properties '-- Properties' and '-- Oil and Gas Reserves' " and "Risk
Factors -- Uncertainty of Estimates of Reserves and Future Net Revenues."

<TABLE>
<CAPTION>
DECEMBER 31, 1994 MAY 31, 1995
---------------------- ----------------------
PROVED TOTAL PROVED TOTAL
DEVELOPED PROVED DEVELOPED PROVED
--------- -------- --------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
ESTIMATED NET PROVED RESERVES(1)
Natural gas (MMcf)....................................... 46,406 76,264 45,687 133,336
Oil and condensate (MBbl)................................ 3,209 4,553 3,252 5,407
Total (MMcfe)............................................ 65,663 103,584 65,200 165,779
Future net revenues...................................... $81,650 $119,157 $90,226 $202,530
PV-10 Value.............................................. $47,172 $ 69,395 $51,270 $100,196
</TABLE>

<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------------ ---------------------
1992 1993 1994 1994 1995
---------- ---------- ---------- --------- ---------
<S> <C> <C> <C> <C> <C>
PRODUCTION:
Oil (Bbl)...................................... 283,928 324,486 467,056 99,992 134,626
Natural gas (Mcf)(2)........................... 3,975,203 5,421,841 6,798,531 1,643,348 1,702,658
Gas equivalents (Mcfe)......................... 5,678,771 7,368,757 9,600,867 2,243,300 2,510,414
WEIGHTED AVERAGE SALES PRICES:
Oil (per Bbl).................................. $ 17.19 $ 15.10 $ 14.35 $ 11.80 $ 15.61
Natural gas (per Mcf).......................... 1.90 1.96 1.93 2.21 1.63
SELECTED DATA PER MCFE:
Production costs............................... $ 0.69 $ 0.62 $ 0.59 $ 0.51 $ 0.65
Depreciation, depletion and amortization....... 0.86 0.99 0.82 0.75 0.86
General and administrative (net)............... 0.88 0.69 0.54 0.53 0.52
Reserve replacement cost (Mcfe)................ 0.60 0.70 0.79 N/A N/A
WELLS DRILLED (GROSS)............................ 40 34 44 12 9
GAS EQUIVALENTS (MCFE) ADDED BY:
Acquisitions................................... 44,680,418 26,469,487 12,879,408 N/A N/A
Exploration and development.................... 1,365,283 13,502,397 24,803,819 N/A N/A
</TABLE>

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

(1) Proved reserves exclude quantities subject to the Volumetric Production
Payment. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- General."

(2) Natural gas production for 1992, 1993, 1994, and the three-month periods
ended March 31, 1994 and 1995 includes 1,148,862, 1,581,206, 1,358,375,
386,028 and 316,745 Mcf, respectively, delivered under the Volumetric
Production Payment.

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<PAGE> 7

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 Common Stock offered hereby.

VOLATILITY OF OIL AND GAS PRICES AND MARKETS

The Company's profitability is substantially dependent on prevailing prices
for natural gas and oil. 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 -- The Company." 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 so-called "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 Hedging."

FUTURE CAPITAL REQUIREMENTS

The Company will require substantial additional capital to further develop
and explore its properties and to acquire additional properties. Capital
expenditures are currently anticipated to be $100 million through December 31,
1996. Cash flows from operations, to the extent available, will be used to fund
these expenditures. The Company intends to seek additional capital from
traditional reserve base borrowings, equity and debt offerings, joint ventures,
and, to a lesser degree, investment limited partnerships. Furthermore, the
Company may seek to raise capital through production payment financing and
vendor financing. 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 development and exploration of
the Company's properties could be delayed and, accordingly, the implementation
of the Company's business strategy would be adversely affected.

UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET REVENUES

Estimates of the Company's proved developed oil and gas reserves and future
net revenues therefrom appearing elsewhere herein are based on reserve reports
audited by independent petroleum engineers. The estimation of reserves requires
substantial judgment on the part of the petroleum engineers, resulting in
imprecise determinations, particularly with respect to new discoveries.
Estimates of proved undeveloped reserves, which comprise a substantial portion
of the Company's 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 resources may vary
substantially from those assumed in the estimates, may result in revisions to
such estimates and could materially affect the estimated quantities and related
PV-10 Value of reserves set forth in this Prospectus. The estimates of future
net revenues reflect oil and gas prices as of the date of estimation, without
escalation,

7
<PAGE> 8

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 estimates in the reserve reports
could have a material adverse effect on the Company. See "Business and
Properties '-- Properties' and '-- Oil and Gas Reserves.' "

RISKS OF PURCHASING INTERESTS IN PRODUCING PROPERTIES

Although the Company has recently shifted its emphasis to reserve growth
through drilling, it expects to continue to make acquisitions of producing
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."

EXPLORATION AND DEVELOPMENT RISKS

Exploration and development of oil and gas resources 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

In addition to the substantial risk that wells drilled will not be
productive, hazards such as unusual or unexpected geologic formations,
pressures, downhole fires, mechanical failures, blowouts, cratering, explosions,
uncontrollable flows 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.

REPLACEMENT OF RESERVES

The Company's success will be largely dependent on its ability to replace
and expand its oil and gas reserves through the acquisition of producing
properties and the exploration for and development of oil and gas reserves, both
of which involve substantial risks. Without successful acquisition or drilling
ventures, the Company will be unable to replace the reserves being depleted by
production, and its assets and revenues, including the reserves, will decline.
There can be no assurance that the Company's acquisition and exploration and
development activities will result in the replacement of, or additions to, the
Company's reserves. Successful acquisition of producing properties generally
requires accurate assessments of recoverable reserves, future oil and gas prices
and operating costs, potential environmental and other liabilities and other
factors. Such assessments are necessarily inexact, and as estimates their
accuracy is inherently uncertain.

8
<PAGE> 9

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. None of the limited partnerships in
which the Company owns an interest had achieved payout status at May 31, 1995.
Achievement of payout status is largely dependent on the market prices of oil
and natural gas. See "-- Volatility of Oil and Gas Prices and Markets."

EFFECT OF PRICE RISK HEDGING

To the extent that price floors or caps 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.

FOREIGN ACTIVITIES

The Company has recently entered into an agreement to develop and produce
reserves in two fields in Western Siberia. The Company will receive a minimum 5%
net profits interest in return for an initial budgeted capital expenditure of up
to $5.0 million. This region has experienced and continues to experience social,
political and economic instability. Additionally, Swift is pursuing
opportunities in Venezuela. 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 all of the
Company's investment.

EFFECTS OF GOVERNMENTAL REGULATION

The Company's operations are affected by extensive regulation pursuant to
various federal, state and local laws and regulations relating to the
exploration for and development, production, gathering and marketing of oil and
gas. Operations of the Company are also subject to numerous laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection. Although the Company believes that it is in
material compliance with all such laws and regulations, there is no assurance
that new laws or regulations or new interpretations of existing laws and
regulations will not increase substantially the cost of compliance or otherwise
adversely affect the Company's exploration for and development, production,
gathering and marketing of oil and gas. See "Business and Properties --
Regulations."

DEPENDENCE ON KEY PERSONNEL

The Company depends, and will continue to depend in the foreseeable future,
on the services of A. Earl Swift, its President and Chairman, and certain of its
other 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

The Company serves as the managing general partner of 95 limited
partnerships, which have invested over $440.0 million in oil and gas activities.
Although these limited partnerships had less than $2.5 million of indebtedness
at March 31, 1995, 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 assets.
Conversely, Swift 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 -- Conflicts of Interest Between the
Company and Limited Partnerships."

9
<PAGE> 10

USE OF PROCEEDS

The net proceeds to the Company from the sale of 5,000,000 shares offered
hereby will be approximately $39.6 million ($45.6 million assuming exercise of
the Underwriters' over-allotment option) after deducting estimated underwriting
discounts and expenses of the offering payable by the Company. Approximately $30
million of such net proceeds will be utilized to reduce outstanding indebtedness
under the Company's outstanding credit facilities.

The remaining net proceeds will be added to working capital to fund some or
all of the following: (i) exploration and development projects, (ii) acquisition
of oil and gas properties, including the purchase of outstanding limited
partnership interests and/or general partner's contributions to the Company's
acquisition partnerships (see "Business and Properties -- Partnerships"), and
(iii) other general corporate purposes.

The Company's current capital expenditure budget through December 31, 1996,
anticipates expenditures of approximately $100.0 million (of which approximately
$5.7 million has been spent in the first three months of 1995) allocated as
follows: approximately $70.0 million for exploration and development drilling
projects, approximately $25.0 million for the acquisition of producing
properties, including interests from limited partnerships and approximately $5.0
million for equipment and other capital expenditures. 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 exploration and development drilling and other
activities, the availability and cost of oil and gas properties meeting the
Company's acquisition criteria and other matters beyond the control of the
Company. The Company is continually evaluating and pursuing potential property
acquisitions, however, the Company has no material commitments, contracts,
understanding or arrangements at the present time with respect to any particular
acquisition.

The Company has two credit facilities. The Company has, through a two-bank
group, a revolving line of credit of $35.0 million which bears interest at the
lead bank's base rate plus 0.5% (9.5% at March 31, 1995) with an option to set
interest at the London Interbank Offered Rate ("LIBOR") plus 2.25% (8.49% at
March 31, 1995). The outstanding amount under this facility at March 31, 1995
was $24.6 million, $9.6 million of which was bearing interest under the base
rate option and the remaining $15.0 million of which was bearing interest under
the LIBOR rate option. Such funds were borrowed primarily to finance the
Company's working capital and capital expenditures needs and to finance the
advance purchase of producing properties on behalf of limited partnerships
and/or joint ventures to be subsequently reimbursed. The Company's other credit
facility is a $5.0 million revolving line of credit bearing interest at the
bank's base rate (9% at March 31, 1995). At March 31, 1995, $5.0 million was
outstanding under this facility, which has been used for the same purposes. Both
of these credit facilities extend through May 1, 1996. The $35.0 million credit
facility is secured by substantially all of the Company's oil and gas properties
and the $5.0 million credit facility is secured by certain of the Company's
accounts receivable.

Until net proceeds of this 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.

10
<PAGE> 11

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

The Common Stock trades on the New York and Pacific Stock Exchanges under
the symbol "SFY." At July 24, 1995, the Company had approximately 650
stockholders of record. The following table sets forth the range of high and low
quarterly closing sales prices for the Common Stock as reported by the New York
Stock Exchange for the periods indicated.

<TABLE>
<CAPTION>
LOW HIGH
--- ----
<S> <C> <C>
1995
Third Quarter (through July, 25, 1995).............................. $8 1/2 $ 9 1/8
Second Quarter...................................................... 8 1/2 10 1/8
First Quarter....................................................... 8 9 7/8
1994
Fourth Quarter...................................................... $9 1/2 $11 3/8
Third Quarter....................................................... 9 1/4 10 1/2
Second Quarter...................................................... 9 10 1/8
First Quarter....................................................... 8 1/2 11 1/4
1993
Fourth Quarter...................................................... $8 3/8 $11 7/8
Third Quarter....................................................... 9 1/2 12 3/4
Second Quarter...................................................... 9 1/2 11 1/4
First Quarter....................................................... 7 7/8 10
</TABLE>

The above prices have been revised to reflect the 10% common stock dividend
declared and paid in September 1994. On July 25, 1995, the last reported sale
price for the Common Stock on the New York Stock Exchange was $8.625 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 $424,000 in any fiscal year.

11
<PAGE> 12

CAPITALIZATION

The following table sets forth the capitalization of the Company at March
31, 1995, and as adjusted to give effect to the sale by the Company of the
shares of Common Stock offered hereby and the application of the net proceeds as
described under "Use of Proceeds." This information should be read in
conjunction with the Company's Consolidated Financial Statements and the Notes
thereto and "Management's Discussion and Analysis of Financial Condition and
Results of Operations" presented elsewhere in this Prospectus.

<TABLE>
<CAPTION>
MARCH 31, 1995
-----------------------
ACTUAL AS ADJUSTED
------- -----------
(IN THOUSANDS)
<S> <C> <C>
Short-term bank borrowings(1).......................................... $30,550 $ --
======= =========
Long-term debt
6 1/2% Convertible Subordinated Debentures........................... $28,750 $ 28,750
Stockholders' equity:
Preferred Stock -- $.01 par value; 5,000,000 authorized shares; no
shares issued and outstanding..................................... -- --
Common Stock -- $.01 par value; 35,000,000 authorized shares;
6,710,412 issued and outstanding shares, 11,710,412 as
adjusted(2)....................................................... 67 117
Additional paid-in capital........................................... 25,112 64,662
Retained earnings.................................................... 17,699 17,699
------- ---------
Total stockholders' equity........................................... 42,878 82,478
------- ---------
Total capitalization................................................... $71,628 $ 111,228
======= =========
</TABLE>

- ---------------
(1) See Note 4 to the Company's Consolidated Financial Statements for additional
information concerning the Company's short-term bank borrowings.

(2) Excludes (a) 8,330 shares issued between March 31, 1995 and May 31, 1995
pursuant to stock benefit plans, (b) 1,324,288 shares issuable upon exercise
of employee and director stock options outstanding as of May 31, 1995, (c)
68,750 shares issuable upon the exercise of stock options granted to other
individuals outstanding as of May 31, 1995, and (d) 2,343,113 shares
issuable upon conversion of the outstanding $28.75 million of 6 1/2%
Convertible Subordinated Debentures due 2003. See "Management" and the
Company's Consolidated Financial Statements and the Notes thereto.

12
<PAGE> 13

SELECTED CONSOLIDATED FINANCIAL DATA

The following selected consolidated financial data of the Company for each
of the five years in the period ended December 31, 1994, are derived from the
Company's Consolidated Financial Statements, which have been audited. The
selected consolidated financial data for the three-month periods ended March 31,
1994 and 1995 are unaudited, and, in the opinion of management, include all
adjustments (consisting of only normal recurring adjustments, except as
disclosed below) necessary for a fair presentation of the results for such
interim periods. Results for the interim periods are not necessarily indicative
of results to be expected for the entire year. The selected consolidated
financial data should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the Company's
Consolidated Financial Statements and the Notes thereto included elsewhere
herein.

<TABLE>
<CAPTION>
THREE MONTHS
YEAR ENDED DECEMBER 31, ENDED MARCH 31,
---------------------------------------------------- -------------------
1990 1991 1992 1993 1994 1994 1995
-------- -------- -------- -------- -------- -------- --------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and gas sales............................. $ 7,328 $ 8,362 $ 12,420 $ 15,536 $ 19,802 $ 4,817 $ 4,876
Earned interests and fees(1).................. 9,883 2,232 2,716 4,072 702 109 113
Supervision fees.............................. 2,149 3,363 3,444 3,719 3,751 943 905
Interest income............................... 706 192 113 202 48 19 8
Other, net.................................... 324 541 516 604 1,072 251 357
-------- -------- -------- -------- -------- -------- --------
Total revenues.......................... 20,390 14,690 19,209 24,133 25,375 6,139 6,259
-------- -------- -------- -------- -------- -------- --------
COSTS AND EXPENSES:
General and administrative (net).............. 3,943 4,656 4,977 5,065 5,198 1,196 1,307
Depreciation, depletion and amortization...... 3,556 3,843 4,906 7,301 7,905 1,689 2,168
Oil and gas production........................ 2,080 2,442 3,934 4,540 5,639 1,142 1,629
Interest expense.............................. -- -- 76 598 1,795 359 478
Other expenses................................ -- -- 628 -- -- -- --
-------- -------- -------- -------- -------- -------- --------
Total costs and expenses................ 9,579 10,941 14,521 17,504 20,537 4,386 5,582
-------- -------- -------- -------- -------- -------- --------
Income before income taxes...................... 10,811 3,749 4,688 6,629 4,838 1,753 677
Provision for income taxes...................... 3,640 1,236 1,518 1,732 1,112 542 152
-------- -------- -------- -------- -------- -------- --------
Income before cumulative effect of changes in
accounting principle.......................... 7,171 2,513 3,170 4,897 3,726 1,211 525
Cumulative effect of change in accounting
principle(1).................................. -- -- 915 -- (16,773) (16,773) --
-------- -------- -------- -------- -------- -------- --------
Net income (loss)............................... $ 7,171 $ 2,513 $ 4,085 $ 4,897 $(13,047) $(15,562) $ 525
======== ======== ======== ======== ======== ======== ========
Per share data:
Primary:
Income before cumulative effect of changes in
accounting principle.......................... $ 1.36 $ 0.47 $ 0.52 $ 0.74 $ 0.56 $ 0.18 $ 0.08
Cumulative effect of changes in accounting
principle................................. -- -- 0.15 -- (2.52) (2.54) --
-------- -------- -------- -------- -------- -------- --------
Net income (loss)........................... $ 1.36 $ 0.47 $ 0.67 $ 0.74 $ (1.96) $ (2.36) $ 0.08
======== ======== ======== ======== ======== ======== ========
Fully diluted:
Income before cumulative effect of changes
in accounting principle................... $ 1.36 $ 0.47 $ 0.52 $ 0.70 $ 0.56 $ 0.17 $ 0.08
Cumulative effect of changes in accounting
principle................................. -- -- 0.15 -- (2.52) (2.54) --
-------- -------- -------- -------- -------- -------- --------
Net income (loss)........................... $ 1.36 $ 0.47 $ 0.67 $ 0.70 $ (1.96) $ (2.36) $ 0.08
======== ======== ======== ======== ======== ======== ========
Weighted average shares outstanding............. 5,279 5,363 6,135 6,588 6,644 6,602 6,689
======== ======== ======== ======== ======== ======== ========
CASH FLOW STATEMENT DATA:
Net cash flows provided by operating
activities.................................... $ 4,813 $ 5,912 $ 6,349 $ 7,238 $ 10,395 $ 2,680 $ 2,964
Capital expenditures............................ 8,600 7,985 34,401 24,229 34,531 4,043 5,745
BALANCE SHEET DATA:
Working capital................................. $ 1,023 $ (2,992) $ 2,953 $ 9,742 $(13,137) $ 8,058 $(16,729)
Total assets.................................... 118,227 101,422 100,243 160,893 135,673 147,536 135,795
Short-term bank borrowings...................... 12,985 23,380 -- 2,650 27,229 14,000 30,550
Long-term debt.................................. -- -- -- 28,750 28,750 28,750 28,750
Stockholders' equity............................ 35,668 38,660 49,281 54,466 42,127 55,288 42,878
</TABLE>

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

(1) In the fourth quarter of 1994, the Company adopted a new method of
accounting for earned interests with respect to the limited partnerships for
which it serves as general partner, effective January 1, 1994, whereby
earned interests are no longer recognized as income. The current year effect
of the change was to increase income before cumulative effect of accounting
principle by approximately $1,047,000 or $.16 per share. The cumulative
effect of this change in accounting principle resulted in an adjustment of
$16,772,698 or $(2.52) per share (after reduction for income taxes of
$8,640,481), to apply the new method retroactively, thereby reducing net
income in 1994. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- General." See also Note 2 to the
Company's Consolidated Financial Statements. Additionally, effective January
1, 1992, the Company elected to adopt SFAS No. 109. The cumulative effect of
this change resulted in an increase in net income of $915,000, reflected in
the first quarter of 1992. See Note 3 to the Company's Consolidated
Financial Statements.

13
<PAGE> 14

SELECTED OIL AND GAS RESERVE AND OPERATING DATA

The following selected oil and gas reserve and operating data sets forth
certain data as of December 31, 1994 and May 31, 1995, with respect to estimates
prepared by the Company, and audited by H.J. Gruy and Associates, Inc.,
independent petroleum engineers, of the Company's proved oil and gas reserves,
the future net revenues therefrom, and their PV-10 Value. Estimates are based
upon weighted average prices of $1.85 per Mcf of natural gas and $15.09 per
barrel of oil at December 31, 1994, and $2.03 per Mcf of natural gas and $16.68
per barrel of oil at May 31, 1995, at each date holding prices constant
throughout the life of the properties in accordance with regulations of the SEC.
This information is based upon numerous assumptions and is subject to change due
to numerous factors. See "Business and Properties '-- Properties' and '-- Oil
and Gas Reserves' " and "Risk Factors -- Uncertainty of Estimates of Reserves
and Future Net Revenues."

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

(1) Proved reserves exclude quantities subject to the Volumetric Production
Payment. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- General."

14
<PAGE> 15

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 and the Selected
Consolidated Financial Data included elsewhere in this Prospectus.

GENERAL

The Company intends to continue to increase its reserves, cash flow and
underlying net asset value through a balanced strategy that includes an expanded
exploration and development drilling program, strategic acquisitions and the
application of advanced technologies. The Company's proved reserve base,
production and cash flow from operations have increased at annualized compounded
rates of 35%, 38% and 30%, respectively, over the last five years. The Company
has historically financed most of its growth with capital raised through limited
partnership financing, having raised approximately $440 million from 1979
through 1994. Beginning in 1985, the Company increasingly emphasized this
financing vehicle thereby enabling the Company to accelerate its growth and
purchase larger producing properties. Commencing in 1991, the Company began to
reduce its reliance on limited partnership financing as its reserve base
expanded and its strategy shifted to re-emphasize internally-generated
exploration and development activities. The Company intends to continue to
reduce its dependence on limited partnership financing. As a result of its
limited partnership activities, the Company developed the expertise and
infrastructure to manage oil and gas properties significantly in excess of its
current reserve base. At December 31, 1994, the Company owned proved reserves of
over 103.6 Bcfe and managed approximately 200 Bcfe on behalf of limited
partnerships.

In 1991, the Company began to increase its 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. The Company has recently begun to realize benefits
from its drilling program with 24.8 Bcfe of proved reserves added in 1994
through exploration and development drilling at an approximate cost of $0.51 per
Mcfe. In 1994, the Company's additions to proved reserves from drilling were
almost twice the proved reserves added from producing property acquisitions and
represented approximately 250% of production in that year.

The Company's revenue is primarily comprised of the following components:
oil and gas sales attributable to properties in which the Company owns a direct
or indirect interest and supervision fees generated by the Company's role as
operator of approximately 750 producing and drilling wells. Additionally, prior
to 1994, the Company also recorded earned interests and fees from limited
partnerships and joint ventures. Effective January 1, 1994, the Company changed
its revenue recognition policy for earned interests. The cumulative effect in
1994 of this change in accounting principle resulted in a one-time accounting
adjustment of $16.8 million, or a loss of $2.52 per share (after reduction for
income taxes of $8.6 million), from applying the new method retroactively.
Earned interests represented revenues in the form of interests in proved
developed oil and gas properties conveyed to limited partnerships and joint
ventures formed in connection with the Company's organization and management of
limited partnerships and joint ventures, representing the difference between the
Company's capital contributions to each limited partnership or joint venture and
its earned revenue interest in the limited partnership's or venture's properties
(based upon the expected levels of cash distributions to the limited partners or
joint venturers). Under the Company's newly adopted method of accounting for
earned interests, such amounts will not be recognized as income, thereby
reducing the Company's investment in oil and gas property. On a pro forma basis,
after considering the retroactive application of the Company's change in
accounting for earned interests, revenues would have been reduced by 14%, to
$20.8 million and 9%, to $17.5 million for 1993 and 1992, respectively. The
Company believes the change in policy results in financial statements that
better reflect its current business focus and that are more comparable to
current practices in the oil and gas exploration and production industry.

In May 1992, the Company purchased interests in certain wells from the
Manville Corporation for $13.8 million using funds provided by the Company's
sale of the Volumetric Production Payment in these properties to a subsidiary of
Enron Corp. Net proceeds from the sale of the production were recorded as
deferred

15
<PAGE> 16

revenues. Deliveries under the Volumetric Production Payment are recorded as oil
and gas sales revenues which are offset by a corresponding reduction of deferred
revenues. Under this arrangement, the Company is required to deliver a fixed
quantity of hydrocarbons produced from the properties over a specified period.
Volumes remaining to be delivered under the Volumetric Production Payment are
not included in the Company's proved reserves. Under the Volumetric Production
Payment, hydrocarbons produced in excess of the amount required to be delivered
are sold by the Company for its own account. The amounts delivered under the
Volumetric Production Payment were 1,148,862, 1,581,206 and 1,358,375 Mcf in
1992, 1993 and 1994, respectively, representing oil and gas sales revenues of
$1.7 million, $2.3 million and $2.0 million. These amounts represented the
amortization of deferred revenues in each respective period. At March 31, 1995,
approximately 5.1 Bcf of gas remain to be delivered under this arrangement
through October 2000, when it expires.

RESULTS OF OPERATIONS

COMPARISON OF THREE MONTHS ENDED MARCH 31, 1995 AND 1994

Revenues

The Company's revenues increased 2% during the first quarter of 1995 from
the first quarter of 1994, due primarily to the increase in oil and gas sales.

Oil and Gas Sales

Oil and gas sales increased approximately 1% to $4.9 million in the first
three months of 1995, as compared to $4.8 million for the same period in 1994.
Oil and gas sales comprised approximately 78% of total revenue in both periods.
The Company's net equivalent production volumes increased by 12% to 2.51 Bcfe in
the first quarter of 1995 as compared to the same period in 1994. Oil production
increased 35% and gas production increased 4% in the first quarter of 1995,
primarily as the result of (i) increased production from exploratory and
development wells drilled in late 1994 and in the first quarter of 1995, and
(ii) the acquisition of interests in producing properties by the Company in the
third quarter of 1994. Although net equivalent production volumes grew by 12%
and oil prices increased by 32% during the first quarter of 1995, oil and gas
sales revenue increased only 1% due to a 26% decline in gas prices.

Supervision Fees

Supervision fees decreased 4% in the first three months of 1995 compared to
the same period in 1994 due primarily to a reduction in the number of wells the
Company operated, as it disposed of certain marginal wells between the two
periods.

Costs and Expenses

General and administrative expenses for the first quarter of 1995 increased
9% as compared to the same period in 1994, due primarily to increased staffing
levels required to support the Company's increased reserve base and drilling
activities. The Company's general and administrative expenses declined from
$0.53 per Mcfe for the first quarter of 1994 to $0.52 per Mcfe for the same
period in 1995 as a result of increased production volumes.

Depreciation, depletion and amortization ("DD&A") increased 28%, due
primarily to the increase in the Company's producing properties and the related
sale of increased quantities of oil and gas therefrom. DD&A grew from $0.75 per
Mcfe in the 1994 period to $0.86 per Mcfe in the 1995 period, reflecting
variations in the per unit cost of property additions and changes in the mix of
reserves between oil and gas.

Oil and gas production costs increased 43% in the first quarter of 1995
(such costs increased from $0.51 per Mcfe in 1994 to $0.65 per Mcfe in 1995) due
to the growth in the Company's production volumes, certain one-time remedial
well expenses, and higher well insurance costs and ad valorem taxes.

Interest expense totaled $1.1 million for the first three months of 1995
(of which $671,000 was capitalized) and $686,000 for the first three months of
1994 (of which $327,000 was capitalized). The

16
<PAGE> 17

Company capitalizes that portion of interest related to its exploration,
partnership and foreign business development activities. The increase in
interest expense in 1995 is attributable to an increase in the average balance
under the Company's credit lines necessary to finance the Company's capital
expenditures discussed below.

Net Income (Loss)

Net income decreased 57% in the first quarter of 1995 to $525,000, or $0.08
per share, as compared to income before the cumulative effect of change in
accounting principle of $1.2 million, or $0.18 per share, in the same period of
1994. The decrease in net income primarily reflected the substantially lower gas
prices realized in 1995. The net loss of $15.6 million in the first quarter of
1994 included the cumulative effect of a change in accounting principle of $16.8
million discussed above.

COMPARISON OF YEARS ENDED DECEMBER 31, 1992, 1993 AND 1994

Revenues

Company revenues increased by 5% during 1994 and 26% during 1993,
principally due to increases in oil and gas sales revenues. In addition to the
components of revenues discussed below, 1992 and 1993 revenues included the
recognition of earned interests (excluded in 1994 due to a change in accounting
principle) which amounted to $1.7 and $3.3 million, respectively.

Oil and Gas Sales

Oil and gas sales increased by $4.3 million, or 27%, in 1994 compared to
1993 due to increased production generated from acquired properties and the
Company's expanded exploration and drilling programs. As a percentage of total
revenues, oil and gas sales rose from 65% of total revenues in 1992 to 78% of
total revenues in 1994. Average prices for oil dropped from $17.19 per Bbl in
1992, to $15.10 per Bbl in 1993, to $14.35 per Bbl in 1994, while average gas
prices increased from $1.90 per Mcf in 1992, to $1.96 per Mcf in 1993, and back
down to $1.93 per Mcf in 1994. The Company's net volumes increased by 30% to 9.6
Bcfe in 1994 as compared to 1993. This volume increase was offset by a decrease
in oil and gas prices. Average gas prices declined from $2.21 in the first
quarter of 1994 to $1.63 in the fourth quarter of 1994, which significantly
impacted 1994 revenues and accordingly, net income. In 1993, oil and gas sales
revenues increased by 25% or $3.1 million, over 1992 revenues, primarily due to
increased production volumes.

Cash Fees

The Company receives cash fees in connection with the formation and
continuing management of limited partnerships and, to a lesser extent, fees paid
by joint venture partners. Cash fees received were $764,000, $763,000 and
$702,000 in 1992, 1993 and 1994, respectively. These amounts vary due to
differences in the level of limited partnership subscriptions, ongoing limited
partnership net revenues, and the amount and terms of joint venture fees.

Supervision Fees

Supervision fees increased from $3.4 million in 1992, to $3.7 million in
1993 to $3.8 million in 1994. These increases were due to a higher level of
drilling wells operated by the Company and the annual escalation of producing
well overhead rates.

Costs and Expenses

General and administrative expenses, net of reimbursement to the Company
for the services performed on behalf of limited partnerships, increased 2% and
3% during 1993 and 1994, respectively. These increases were primarily the result
of the Company receiving its general partner share of expenses in a larger
number of limited partnerships. These expenses decreased from $0.88 per Mcfe in
1992 to $0.69 per Mcfe in 1993 to $0.54 per Mcfe in 1994.

17
<PAGE> 18

DD&A has steadily increased due to significant growth in the Company's
interests in production volumes. The Company's DD&A rate per Mcfe has fluctuated
from $0.86 in 1992 to $0.99 in 1993 to $0.82 in 1994, reflecting variations in
the per unit cost of property additions and changes in the mix of reserves
between oil and gas over the years. The 1994 DD&A amount was also favorably
impacted (by approximately $2.3 million) as a result of the change in accounting
principle relating to earned interests as discussed. The accounting principle
change will continue to have a favorable impact on DD&A in the future. See
"-- General."

The Company's oil and gas production costs increased 24% during 1994 and
15% during 1993 due to increased production volumes. The Company's production
costs decreased from $0.69 per Mcfe in 1992 to $0.62 per Mcfe in 1993 to $0.59
per Mcfe in 1994, reflecting higher net equivalent production volumes in each
period.

Total interest expense was $1.4 million, $1.6 million, and $3.7 million for
1992, 1993, and 1994, respectively, of which $1.3 million, $1.0 million, and
$1.9 million related to the Company's exploration, partnership and foreign
business development activities and was capitalized. The increase in interest
expense for 1994 was attributable to payment of a full year's interest on the
Debentures, as opposed to payment of six months' interest on the Debentures in
1993, and no interest on the Debentures in 1992.

Net Income (Loss)

The Company incurred a net loss for 1994 of $13.0 million, which included
the cumulative effect of a change in accounting principle (as discussed above)
of $16.8 million. Income before the cumulative effect of a change in accounting
principle for 1994 was 24% less than net income for 1993, primarily due to the
elimination in 1994 of recording earned interest as an item of revenue ($3.4
million in 1993) and the 1994 increase of $1.2 million in interest expense,
partially offset by a $2.6 million increase in oil and gas income activities
(sales revenues net of the associated increases in production costs and DD&A).

Net income for 1993 increased 20% as compared to 1992, principally due to
increased production volumes. The Company's consolidated effective tax rate was
32.4%, 26.1% and 23.0% in 1992, 1993 and 1994, respectively. During 1992, the
Company also recognized a $915,000 income benefit as a result of the cumulative
effect of adopting Statement No. 109 of the Financial Accounting Standards Board
as described in Note 3 to the Company's Consolidated Financial Statements, which
increased first quarter 1992 income by $0.15 per share.

RECENT DEVELOPMENTS

Oil and gas sales volumes for the second quarter of 1995 are currently
estimated to be comparable to sales volumes during the first quarter of 1995.
Management currently estimates that its weighted average gas sales price has
improved approximately 10% during the second quarter when compared to the $1.63
weighted average sales price for the first quarter of 1995, while its weighted
average oil sales price has declined slightly for the period. Preliminary
estimates indicate that its related costs and expenses for the second quarter of
1995 will increase slightly over the levels in the first quarter of 1995.

In the fourth quarter of 1994, the Company acquired a leasehold position in
8,830 net acres immediately adjacent to its existing AWP Olmos Field. The
Company subsequently extended its geological and engineering studies to cover
this area, and has drilled four new wells on this acreage. As a result of these
efforts, Swift has identified 89 proved undeveloped locations, and currently
plans to drill up to 70 development wells through year-end 1996.

At May 31, 1995, the Company had estimated proved reserves of 133.3 Bcf of
natural gas and 5.4 MMBbls of oil (totalling approximately 165.8 Bcfe) with a
PV-10 Value of approximately $100.2 million. The proved reserves at May 31, 1995
represent an increase of 60% over estimated amounts at December 31, 1994,
reflecting recent reserve additions comprised primarily of proved undeveloped
reserves in newly acquired areas of the AWP Olmos Field, as well as higher oil
and gas prices at May 31, 1995.

18
<PAGE> 19

LIQUIDITY AND CAPITAL RESOURCES

The Company historically has relied on limited partnerships as its
principal financing vehicle to fund its acquisitions. Since 1991, the Company's
strategy has shifted toward increased reliance on exploration and development
activities, and it has significantly expanded reserves added through these
efforts. As a result, the Company has reduced its reliance on cash flow
generated from, and capital raised through, limited partnerships. Supplemental
cash and working capital are provided through internally generated cash flow and
debt and equity financing.

NET CASH FROM OPERATIONS

For the three-month period ended March 31, 1995, cash flows from operating
activities increased to $2.9 million compared to $2.7 million during the first
three months of 1994. This increase was primarily due to increased production
volumes and higher oil prices, offset by lower average gas prices as discussed
above. In 1992, 1993, and 1994, the Company generated net cash from operating
activities of $6.3 million, $7.2 million and $10.4 million, respectively. The
1994 increase was primarily due to increased production volumes, partially
offset by lower oil and gas prices and an increase in interest expense. The 1993
increase of $889,000 in net cash from operations was substantially due to
increased production, offset by lower oil prices and an increase in interest
expense.

WORKING CAPITAL

The Company's working capital has decreased from $9.7 million at December
31, 1993, to working capital deficits of $13.1 million and $16.7 million at
December 31, 1994, and at March 31, 1995, respectively. The working capital
deficits are primarily the result of borrowings under short-term facilities to
fund a portion of the increases in the Company's oil and gas property assets as
described below under "-- Capital Expenditures." At December 31, 1994 and March
31, 1995, the Company's borrowings were $27.2 million and $30.5 million,
respectively.

Due to the nature of the Company's business, the individual components of
working capital fluctuate considerably from period to period. Balance sheet
changes in receivables, producing oil and gas properties held for transfer and
payables related to producing oil and gas property acquisitions principally
arise from the timing of property purchases and payments made by and to the
Company related to the Company's management of limited partnerships.

The Company incurs significant working capital requirements in connection
with its role as operator of approximately 750 producing wells 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. As a result,
significant balances in the Company's receivable and payable accounts exist in
the normal course of its business. The Company receives certain fees in
connection with these activities.

FINANCING ACTIVITIES

The Company raised $34.7 million, $44.1 million and $50.2 million in
limited partnership subscriptions in 1994, 1993, and 1992, respectively,
reflecting the Company's reduced reliance on limited partnership financing.

On June 30, 1993, the Company issued $28.75 million of Debentures in a
public offering. Proceeds of the offering have been used primarily to acquire
producing oil and gas properties and to finance the Company's expanding
exploration and development programs. See Note 5 to the Company's Consolidated
Financial Statements.

In May 1992, the Company received proceeds of $14.0 million from the sale
of certain properties from its oil and gas property account and $6.4 million
from the sale of 990,000 shares of common stock through an institutional
offering, and used the Volumetric Production Payment to acquire $13.8 million of
properties from the Manville Corporation. See "-- General" and Note 8 to the
Company's Consolidated Financial Statements.

19
<PAGE> 20

CREDIT FACILITIES

The Company has established credit facilities which have been used
principally to finance the Company's purchase of producing oil and gas
properties on an interim basis pending transfer of the properties to newly
formed limited partnerships and joint ventures, and to provide working capital.
More recently the Company's credit facilities have been used to fund a portion
of the Company's exploration and development activities. See Note 4 to the
Company's Consolidated Financial Statements.

At March 31, 1995, the Company had $30.5 million outstanding under its
borrowing arrangements. Up to an additional $10.5 million was available under
these lines at March 31, 1995. These facilities included three lines: (i) a
$35.0 million revolving line of credit at the lead bank's base rate plus 0.5%,
with an option to set interest at the London Interbank Offered Rate ("LIBOR")
plus 2.25%; (ii) a $5.0 million accounts receivable line bearing interest at the
bank's base rate; and (iii) a line for the acquisition of producing oil and gas
properties (the "Acquisition Line") at the bank's base rate plus 1.0%. The $35.0
million credit facility is secured by substantially all of the Company's oil and
gas properties and the $5.0 million credit facility is secured by certain of the
Company's accounts receivable. The Company has since terminated the Acquisition
Line, retaining the two lines totalling $40.0 million. See "Use of Proceeds" and
Note 4 to the Company's Consolidated Financial Statements.

CAPITAL EXPENDITURES

Additions to property, plant and equipment during the first three months of
1995 were $5.7 million which include $2.0 million for exploratory and
development drilling costs; $1.8 million of prospect costs (principally prospect
leasehold, seismic and geological costs of unproven prospects); $1.0 million to
fund the Company's general partner capital contribution to the limited
partnerships formed under its SEDV offering (see "Business and
Properties -- Partnerships"); $600,000 invested in foreign business
opportunities ($530,000 in Russia and $70,000 in Venezuela); and $300,000 spent
for furniture and fixtures, primarily computer equipment.

The Company's capital expenditures were $34.4 million $24.2 million and
$34.5 million in 1992, 1993 and 1994, respectively. In 1994 approximately $6.9
million was spent on the purchase of producing oil and gas property interests.
The Company expended approximately $6.6 million for prospect costs;
approximately $5.7 million for the Company's general partner capital
contribution to limited partnerships; $4.1 million in development drilling; and
$4.0 million for exploratory drilling. The Company also purchased $3.5 million
of limited partnership interests in previously formed limited partnerships
through its acceptance, at its option, of the right of presentment provided in
those limited partnerships. In its foreign activities, the Company invested
another $3.0 million and $300,000, in its Russia and Venezuela initiatives,
respectively, and $500,000 on fixed assets consisting primarily of computer
equipment.

The Company anticipates capital expenditures of approximately $100.0
million (of which approximately $5.7 million was spent during the first three
months of 1995) for currently planned projects in 1995 and 1996, including
approximately $70.0 million for exploration and development drilling projects
and approximately $25.0 million for the acquisition of producing properties,
including the purchase of interests from limited partnerships and $5.0 million
for equipment and other capital expenditures. Actual expenditures for planned
exploration and development activities may vary significantly, depending upon
many factors, including drilling results, oil and gas prices, industry
conditions and general economic factors. In addition, the Company's exploration
and development expenditures may be increased as additional prospects or wells
are generated, acquired or developed.

The Company believes that internally-generated cash flows (expected to
increase as the Company's production base increases as a result of its
accelerated drilling program) together with the proceeds of this offering and
its existing credit facilities, will be sufficient to finance the costs
associated with its currently budgeted capital expenditures at least through
1996. Further liquidity needs may also be met by the additional availability
under its credit facilities based upon the value of the Company's proved
reserves, as management continually evaluates future use of debt and/or equity
to finance its capital needs. See "Risk Factors -- Future Capital Requirements."

20
<PAGE> 21

QUARTERLY RESULTS OF OPERATIONS

The following table sets forth certain unaudited quarterly financial
information for each of the Company's last five quarters. The data has been
prepared on a basis consistent with the Company's audited consolidated combined
financial statements included elsewhere in this Prospectus and includes all
necessary adjustments, consisting only of normal recurring accruals that
management considers necessary for a fair presentation. The operating results
for any quarter are not necessarily indicative of results for any future period.

<TABLE>
<CAPTION>
QUARTERS ENDED
--------------------------------------------------------------------
MARCH 31, JUNE 30, SEPT. 30, DEC. 31, MARCH 31,
1994 1994 1994 1994 1995
------------ ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Revenues(1).................... $ 6,138,535 $6,106,954 $6,962,612 $6,167,191 $6,258,588
Depreciation, depletion and
amortization................. 1,688,938 1,802,483 2,143,652 2,269,728 2,168,229
Income before income
taxes(1)..................... 1,753,003 1,462,980 1,439,620 182,226 676,434
Income before cumulative effect
of change in accounting
principle(1)................. 1,210,722 1,076,077 1,130,398 308,474 524,600
Net income (loss) (as
restated)(1)................. $(15,561,976) $1,076,077 $1,130,398 $ 308,474 $ 524,600
Primary:
Income before cumulative
effect of change in
accounting principle...... $ 0.18 $ 0.16 $ 0.17 $ 0.05 $ 0.08
Net income (loss)(1)......... (2.36) 0.16 0.17 0.05 0.08
Fully diluted:
Income before cumulative
effect of change in
accounting principle...... $ 0.17 $ 0.15 $ 0.16 $ 0.05 $ 0.08
Net income (loss)(1)......... (2.36) 0.15 0.16 0.05 0.08
Net cash provided by operating
activities................... $ 2,679,971 $2,256,457 $3,355,621 $1,902,465 $2,964,097
</TABLE>

- ---------------
(1) In the fourth quarter of 1994, the Company changed its revenue recognition
policy for earned interests. See Note 2 to the Company's Consolidated
Financial Statements for further discussion. This change was effective
beginning January 1, 1994, and, accordingly, the cumulative effect of this
change resulted in an adjustment of $16,772,698 or $(2.52) per share, which
has been reflected in the first quarter of 1994, and the first three
quarters of 1994 have been restated to reflect the basis of the newly
adopted accounting principle. Net Income, Primary Income Per Share, and
Fully Diluted Income Per Share were previously reported as $814,325, $0.14,
and $0.14, respectively, for the first quarter of 1994; $1,140,197, $0.19,
and $0.17, respectively, for the second quarter of 1994; and $768,161,
$0.12, and $0.12, respectively, for the third quarter of 1994.

21
<PAGE> 22

BUSINESS AND PROPERTIES

THE COMPANY

The Company's proved reserve base, production and cash flow from operations
have increased at annualized compounded rates of 35%, 38% and 30%, respectively,
over the last five years. At May 31, 1995, the Company had estimated proved
reserves of 133.3 Bcf of natural gas and 5.4 MMBbls of oil (totalling
approximately 165.8 Bcfe) with a PV-10 Value of approximately $100.2 million.
Approximately 80% of the Company's proved reserve base at that date was natural
gas. The proved reserves at May 31, 1995 represent an increase of 60% over
estimated amounts at December 31, 1994. The Company's reserve replacement cost
over the last three years has averaged $0.79 per Mcfe, which it believes is
better than industry averages.

As of December 31, 1994, the Company operated 750 wells which represented
61% of its proved reserve base and managed reserves on behalf of limited
partnerships which, exclusive of the Company's interests, had proved reserves of
approximately 200 Bcfe. Five oil and gas fields accounted for 54% of the
Company's PV-10 Value at December 31, 1994, of which the two largest were the
AWP Olmos Field and the Giddings Field. The AWP Olmos Field, located in McMullen
County, Texas, and the Giddings Field, located in Fayette County, Texas,
accounted for 25% and 12%, respectively, of the Company's PV-10 Value as of such
date. The Company believes that the Giddings Field's prolific but short-lived
wells complement the long-lived reserves of the AWP Olmos Field. The application
of advanced technologies and achievement of operating efficiencies have enabled
the Company to reduce costs and enhance reserve recoveries in these fields.

BUSINESS STRATEGY

Key elements of the Company's strategy include the following:

- Increased exploration and development drilling activities. The Company
believes that its existing properties, including its substantial
inventory of undeveloped acreage, provide significant future exploration
and development potential. The Company anticipates expenditures of
approximately $70.0 million on currently planned drilling activities
during 1995 and 1996 (of which approximately $3.8 million was spent in
the first quarter of 1995). Through December 31, 1996, the Company
currently anticipates expenditures of approximately $55 million on
development drilling activities, including approximately $30.0 million in
the AWP Olmos and Giddings fields in Texas. Swift expects to spend
approximately $15.0 million on exploratory drilling in the Yegua, Frio,
Lobo, Wilcox and Austin Chalk trends in the Gulf Coast Basin, the
Smackover trend in the North Louisiana Salt Dome Basin, the Red Fork
formation in the Anadarko Basin in Oklahoma and the Minnelusa trend in
Wyoming.

22
<PAGE> 23

properties in close proximity to the Company's current reserves, where
reserves can be increased through development drilling and improved
operating efficiencies can be achieved. Using these criteria, the Company
employs a disciplined, market-driven approach to acquisitions that can
result in varying levels of annual spending on acquisitions. Through
1996, the Company anticipates spending approximately $25.0 million for
the acquisition of producing property interests, including the purchase
of interests from limited partnerships.

- Application of advanced technologies. To minimize the risks associated
with exploration and development drilling and improve operating results,
the Company has devoted considerable resources to development of advanced
technological expertise. These technologies include 2-D and 3-D seismic
analysis, AVO studies and detailed formation depletion studies. The
Company has attained substantial expertise in horizontal well technology,
having participated in 17 such wells in the past two years with a 100%
success rate. Additionally, the use of innovative fracturing methods and
coiled tubing technology in the AWP Olmos Field has enabled the Company
to achieve improved production yields.

EXPLORATION AND DEVELOPMENT DRILLING ACTIVITIES

In 1991, the Company began to increase its 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. The Company has recently begun to realize benefits
from its drilling program with 24.8 Bcfe of proved reserves added in 1994
through exploration and development drilling at an approximate cost of $0.51 per
Mcfe. Proved reserves added through exploration and development drilling were
approximately double the amount added through the acquisition of producing
properties in 1994, and represented approximately 250% of that year's annual
production. The Company's success rate for 1994 drilling activity was 43% for
exploratory wells (6 out of 14 drilled) and 87% for development wells (26 out of
30 drilled), which management believes are above industry averages.

The Company pursues a "controlled risk" approach to exploratory drilling.
The Company focuses its exploration activities on specific regions in the U.S.
where its technical staff has considerable experience and near proved productive
properties 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'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 in several of its fields, including the Company's largest single
property, the AWP Olmos Field. See "-- Properties -- AWP Olmos Field."

The Company's exploration and development activities are conducted by its
in-house exploration staff, assisted by professionals from other departments,
including reservoir engineers, geologists, geophysicists, petrophysicists,
landmen, and drilling and operations engineers. The Company believes that one of
the keys to its success has been its team approach which integrates multiple
disciplines to maximize utilization of the information provided by modern
seismic techniques.

The Company has increasingly utilized advanced seismic technology to
enhance the quality of its drilling efforts, including 2-D and 3-D seismic
analysis, AVO studies, and detailed formation depletion studies. Utilizing the
Company's computer workstations, seismic data is analyzed and enhanced with
advanced software programs, many of which are proprietary. As a result, the
Company has developed a significant internal seismic expertise and has compiled
an extensive library of seismic data.

23
<PAGE> 24

AWP Olmos Field. The Company has extensive expertise in the AWP Olmos
Field where it drilled four successful development wells in 1994. The Company
has a long history of experience with low-permeability tight-sand formations
typical of its AWP Olmos Field properties. Since acquiring its first AWP Olmos
Field acreage in 1988, the Company has made detailed studies of drainage
patterns in the formation and has introduced innovations in fracture design and
implementation methods and coiled tubing technology that substantially reduce
drilling costs and improve recoveries.

In the fourth quarter of 1994, the Company acquired a leasehold position in
8,830 net acres immediately adjacent to its existing AWP Olmos Field. The
Company subsequently extended its geological and engineering studies to cover
this area, and to date has drilled and completed four new wells on this acreage.
As a result of these efforts, Swift has identified 89 proved undeveloped
locations in this field, where it currently plans to drill up to 70 development
wells through 1996.

Giddings Field. Wells in the Giddings Field initially have high
deliverability rates, with strong cash flows that decline rapidly. The Company
believes these reserves complement its long-lived reserves in the AWP Olmos
Field. Since 1992, the Company has participated in 17 horizontal wells in the
Giddings Field with a 100% success rate, including six successful development
wells in 1994. 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. In 1994,
the Company acquired a 2-D swath of seismic data covering approximately 6,500
acres. In addition, the Company acquired undeveloped leasehold interests to
provide additional flexibility in designing its development program. The Company
currently plans an additional 12 development wells in the Giddings Field through
December 31, 1996.

Gulf Coast Basin. The Company's drilling program in the Gulf Coast Basin
in 1994 consisted of three successful exploratory wells and five successful
development wells, primarily in the Yegua trend. These locations were selected
utilizing traditional geologic studies combined with analyses of available 2-D
seismic data. To further reduce exploration and development risk in the Gulf
Coast Basin, the Company conducted a 3-D seismic survey in Jackson County, Texas
in 1994. The processing and interpretation has identified a number of potential
drilling locations which have been further refined through AVO analysis. The
Company owns interests in the South Louisiana East Mud Lake and Second Bayou
fields with significant proved undeveloped reserves. The Company plans to
conduct additional 3-D seismic surveys in these fields in 1995. Up to 12
exploratory wells and four development wells are scheduled for drilling in the
Gulf Coast Basin through 1995, principally focusing on the Yegua, Frio, Lobo and
Wilcox trends.

Anadarko Basin. The Company plans to continue exploration and development
activities in the Anadarko Basin in Oklahoma principally focusing on the Red
Fork formation. The Company participated in five successful development wells in
this area in 1994. The Company's geologists and geophysicists search for the Red
Fork formation's narrow channel sands using interactive software to integrate
geologic and seismic data. By correlating the two sets of information, the
presence of potential hydrocarbon accumulations is determined and optimum
drilling sites are selected. For 1995, two exploratory locations and one
development location have been identified.

Wyoming Powder River Basin. In early 1995, the Company drilled a discovery
well in the Minnelusa trend in Campbell County, Wyoming, which tested at an
initial production rate of 415 barrels of oil per day. The Company has a 50%
working interest in the well. Two development wells offsetting the new discovery
and four additional exploratory wells are planned for this area in 1995. The
Minnelusa trend has been the subject of extensive study by the Company's
multidisciplinary teams, in order to identify the location of stratigraphic
hydrocarbon traps. The Company's staff has evaluated over 5,000 wells drilled in
the area, utilizing 2-D and 3-D seismic data, and has conducted petrophysical
studies to determine the hydrocarbon-bearing capacity of the rock. To increase
the production in some areas, the Company has instituted secondary and tertiary
recovery through water or polymer flooding in the Minnelusa fields.

North Louisiana Salt Dome. The North Louisiana Salt Dome covers the
neighboring corners of Arkansas, Louisiana and Texas. The Company has studied
the Smackover trend for several years and has drilled two successful exploratory
wells in southwest Arkansas during 1993 and 1994. The Smackover formation is a
prolific hydrocarbon producer from multiple levels and from a variety of
structures, including

24
<PAGE> 25

fault traps, salt anticlines, basement structures and stratigraphic traps. The
Company currently has access to a 7,000-mile seismic data base in the area, and
plans to conduct two additional 3-D seismic surveys in the Smackover formation
during 1995. The Company plans to drill five exploratory wells and one
development well in the region in 1995 and is currently evaluating the
implementation of a water flood project in Arkansas.

ACQUISITION ACTIVITIES

Since 1979, the Company has acquired approximately $460.0 million of
producing oil and natural gas properties on behalf of itself and its
co-investors in 120 separate transactions. The Company has acquired for its own
account approximately $108.0 million of producing properties, with proved
reserves estimated at 139.7 Bcfe. The Company's acquisition activities have
declined over the past three years, with approximately $27.0 million, $18.5
million and $13.1 million of properties acquired in 1992, 1993 and 1994,
respectively. The Company's acquisition costs have averaged $0.70 per Mcfe over
this three year period, which it believes is better than industry averages.
Through 1996, the Company anticipates spending approximately $25.0 million for
acquisitions of producing property interests, including the purchase of
interests from limited partnerships.

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 through additional development efforts. As the market for acquisitions
has become more competitive in recent years, the Company has taken the
initiative in creating acquisition opportunities by directly soliciting property
owners who have not placed their properties on the market. Properties are
acquired after the Company has analyzed and evaluated available reservoir
engineering, geological, and geophysical data. In evaluating producing
properties prior to purchase, the Company assesses many factors, including
estimated reserves, anticipated cash flow from production, production costs and
various factors affecting the marketing of production. See "Risk
Factors '-- Uncertainty of Estimates of Reserves and Future Net Revenues' and
'-- Risks of Purchasing Interests in Producing Properties.' "

PROPERTIES

The Company's proved reserves have been relatively concentrated, with
approximately 54% of the Company's PV-10 Value at December 31, 1994,
attributable to its five largest properties. The following table presents data
regarding the number of gross producing wells, the estimated quantities of
proved oil and gas reserves and the PV-10 Value attributable to these
properties, as of December 31, 1994.

<TABLE>
<CAPTION>
DECEMBER 31, 1994
---------------------------------------------------------------
ESTIMATED PROVED RESERVES
GROSS --------------------------- PV-10
PRODUCING OIL GAS VALUE PERCENT
PROPERTY STATE WELLS (MBBL) (MMCF) MMCFE (000'S) OF PV-10
- ------------------------------- ----- --------- ------ ------ ------- ------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
AWP Olmos...................... TX 85 1,159 31,068 38,022 $17,651 25.4%
Giddings....................... TX 54 512 5,375 8,447 8,242 11.9
Second Bayou/E. Mud Lake....... LA 43 70 5,518 5,938 4,924 7.1
Weatherford.................... OK 144 92 6,070 6,622 3,637 5.2
West Bernard................... TX 7 32 3,032 3,224 2,952 4.3
Chunchula...................... AL 47 302 3,026 4,838 2,552 3.7
North Creole................... LA 5 54 1,790 2,114 2,369 3.4
West Fouke..................... AK 1 95 2,000 2,570 1,948 2.8
Estes Cove..................... TX 7 211 488 1,754 1,405 2.0
Appalachian.................... WV 287 -- 1,664 1,664 1,241 1.8
Other Fields................... 3,492 2,026 16,233 28,389 22,474 32.4
----- ----- ------ ------- ------- -----
Total................ 4,172 4,553 76,264 103,582 $69,395 100.0%
===== ===== ====== ======= ======= =====
</TABLE>

25
<PAGE> 26

The Company focuses its activities in four main geographical basins: the
Gulf Coast Basin, the Oklahoma Anadarko Basin in Oklahoma, the Wyoming Powder
River Basin and the North Louisiana Salt Dome Basin. The AWP Olmos Field, the
Giddings Field and the East Mud Lake and Second Bayou fields (located in the
Gulf Coast Basin) and the Weatherford Area (located in the Anadarko Basin in
Oklahoma) were the Company's most significant oil and gas properties at December
31, 1994.

AWP Olmos Field

The AWP Olmos Field, including an adjacent 8,830-acre leasehold acquired in
1994, located in McMullen County, Texas, represented approximately 30% of the
Company's production and 25% of its PV-10 Value at December 31, 1994. The
Company owns interests in, and is the operator of, 85 wells producing natural
gas from the Olmos Sand formation at a depth of approximately 10,000 feet.
Working interests owned by the Company and limited partnerships in this field
range from 86.5% to 100%. During 1994, the Company drilled four successful
development wells in this field. 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. In the fourth quarter of 1994, the
Company successfully acquired a leasehold position in 8,830 net acres
immediately adjacent to its existing AWP Olmos Field. The Company subsequently
extended its geological and engineering studies to cover this area, and has
drilled four new wells on this acreage. As a result of these efforts, Swift has
identified 89 proved undeveloped locations, and currently plans to drill up to
70 development wells through 1996.

Giddings Field

The Giddings Field represented approximately 12% of the Company's PV-10
Value at December 31, 1994. Swift owns interests in 54 wells producing from the
Austin Chalk formation, 17 of which are horizontal. The Giddings Field wells are
all horizontally produced natural gas and oil wells that deliver high initial
flow rates and strong initial cash flows which decline rapidly. The Company owns
drilling and production rights to over 12,000 acres and has a substantial amount
of undeveloped proved reserves in this area. Therefore, the Company believes the
Giddings Field will be an increasing area of activity in the future.

South Louisiana East Mud Lake and Second Bayou Fields

The East Mud Lake and Second Bayou fields located adjacently in Cameron
Parish, Louisiana, represented approximately 7% of the Company's PV-10 Value at
December 31, 1994. The Company owns working interests ranging from 4% to 14% in
43 wells which are operated by third parties. This field produces primarily
natural gas from the Planulina and Abbeville Series formations at depths ranging
from 10,000 to 13,000 feet.

The Oklahoma Weatherford Area

The Oklahoma Weatherford Area, located in Caddo, Custer, and Washita
Counties in southwestern Oklahoma, represented approximately 5% of the Company's
PV-10 Value at December 31, 1994. The Company owns interests in 144 wells
producing primarily from the Red Fork and Springer (Britt) formations at average
depths of 12,500 and 15,000 feet, respectively. The Company is the operator of
40 wells which represent approximately 75% of its proved reserves in the field.
The Company also manages a gas gathering system, including pipelines and
compressors and two condensate recovery systems in the field.

OPERATIONS

The Company generally seeks to be named as operator for wells in which it
or limited partnerships and joint ventures have acquired a significant interest,
although this typically occurs only when the Company or limited partnerships and
joint ventures own the major portion of the working interest in a particular
well or field. The Company acts as operator of approximately 750 wells, which
comprise approximately 61% of the Company's total proved reserves.

26
<PAGE> 27

As operator, the Company is able to exercise substantial influence over
development and enhancement of a well, and supervises 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 attempt to improve production rates,
increase reserves and/or lower the cost of operating its oil and gas properties.

Oil and gas properties are customarily operated under the terms of a joint
operating agreement, which provides for reimbursement of the operator's direct
expenses and monthly per-well supervision fees. Per-well supervision fees vary
widely, depending on 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 1994 ranged from $50 to $1,372 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
posted prices. The Company does not refine any oil it produces. No single oil or
gas purchaser accounted for 10% or more of the Company's consolidated revenues
during the three years ended December 31, 1994. The Company does not believe
that the loss of any single oil or gas purchaser or contract would materially
affect its sales.

The following table summarizes sales volume, sales price, and production
cost information for the Company's net oil and gas production for the three-year
period ended December 31, 1994. "Net" production is production that is owned by
the Company either directly or indirectly through limited partnerships or joint
venture interests and produced to its interest after deducting royalty, limited
partner, and other similar interests.

<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------------ -----------------------
1992 1993 1994 1994 1995
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Production
Oil (Bbl).......................... 283,928 324,486 467,056 99,992 134,626
Natural gas (Mcf)(1)............... 3,975,203 5,421,841 6,798,531 1,643,348 1,702,658
Weighted average sales price
Oil (per Bbl)...................... $ 17.19 $ 15.10 $ 14.35 $ 11.80 $ 15.61
Natural gas (per Mcf).............. 1.90 1.96 1.93 2.21 1.63
Average production cost (per Mcfe)... $ 0.69 $ 0.62 $ 0.59 $ 0.51 $ 0.65
</TABLE>

- ---------------
(1) Natural gas production for 1992, 1993, 1994, and for the three-month periods
ended March 31, 1994 and 1995 includes 1,148,862, 1,581,206, 1,358,378,
386,028 and 316,745 Mcf, respectively, delivered under the Volumetric
Production Payment.

Under the Volumetric Production Payment arrangement entered into in 1992,
as of March 31, 1995, the Company has a remaining commitment to deliver
approximately 5.1 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. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- General."

During 1994, the Company entered into three natural gas price hedging
contracts covering a small portion of the Company's and limited partnerships'
natural gas production. Two contracts covered 300,000 MMBtu, one for the first
two months of 1994 and one for the last two months, providing for minimum prices
of $2.25 and $1.58 per MMBtu, respectively. The third contract covered 1,000,000
MMBtu for July, August and September production with a floor price of $1.77. See
"Risk Factors -- Effect of Price Risk Hedging."

27
<PAGE> 28

FOREIGN ACTIVITIES

During 1993, the Company entered into a Participation Agreement (the
"Participation Agreement") with a Russian Federation joint stock company (in
which the Company has an indirect interest of less than 1%) to develop and
produce reserves in two fields in Western Siberia. Under this Participation
Agreement, the Company would receive a minimum 5% net profits interest in return
for an initial budgeted capital expenditure of up to $5.0 million. The Company
also is pursuing opportunities in the oil and gas industry in Venezuela. These
activities are described in greater detail in Note 10 to the Company's
Consolidated Financial Statements. See "Risk Factors -- Foreign Activities."

OIL AND GAS RESERVES

All information set forth in this Prospectus regarding proved reserves,
related future net revenues and PV-10 Value is taken from reports prepared by
the Company and audited by H.J. Gruy and Associates, Inc. ("Gruy"), Houston,
Texas, independent petroleum engineers. Gruy's estimates were based upon review
of production histories and other geological, economic, ownership and
engineering data provided by the Company, and their report is contained as an
exhibit to the Registration Statement of which this Prospectus is a part. In
accordance with SEC guidelines, the Company's estimates of future net revenues
from the Company's proved reserves and the present value thereof (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 at December 31, 1994, were estimated based upon weighted average
prices of $1.85 per Mcf of natural gas and $15.09 per barrel of oil, compared to
$2.50 and $2.45 per Mcf of natural gas and $12.87 and $17.52 per barrel of oil
as of December 31, 1993 and 1992, respectively. Proved reserves at May 31, 1995
were estimated based on weighted average prices of $2.03 per Mcf of natural gas
and $16.68 per barrel of oil. See "Risk Factors -- Uncertainty of Estimates of
Reserves and Future Net Revenues."

The Company's total proved developed and undeveloped reserve volumes have
increased at an annualized compounded rate of approximately 35% over the last
five years. In 1994, the Company's proved natural gas reserves increased over
1993 year-end amounts by 18% or 11.8 Bcf and its proved oil reserves increased
7% or 282,198 Bbl. At May 31, 1995, natural gas reserves had increased over
year-end 1994 amounts by 75% and oil reserves by 19%. The composition of these
reserves has shifted substantially, with proved developed reserves comprising
77% of total proved reserves at year end 1993, 63% at year end 1994 and 39% at
May 31, 1995. This shift reflects the recent reserve additions comprised of
proved undeveloped reserves in newly acquired areas of the AWP Olmos Field.
Additional reserves have also been added due to May 31, 1995 prices being higher
than those at year-end 1994, which has the effect of changing quantities
estimates and the estimated present value of such proved reserves.

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 SEC, and the PV-10 Value. Operating costs and 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 the Notes
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 1994, 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 1995 and thereafter will be made at an
unrestricted level. The Company has interests in certain tracts which are
estimated to have additional hydrocarbon reserves which cannot be classified as
proved and are not reflected in the following table. The proved reserves
presented for all periods also exclude any reserves attributed to the Volumetric
Production Payment. See "Management's Discussion of and Analysis of Financial
Condition and Results of Operations -- General." There can be no assurance that
these estimates are accurate predictions of future net revenues from oil and gas
reserves or their present value.

28
<PAGE> 29

ESTIMATED PROVED OIL AND GAS RESERVES

<TABLE>
<CAPTION>
AT DECEMBER 31,
------------------------------------------- AT MAY 31,
1992 1993 1994 1995
---------- ---------- ----------- -----------
<S> <C> <C> <C> <C>
NET NATURAL GAS RESERVES (MCF):
Proved developed.................. 32,955,080 50,936,942 46,406,448 45,686,959
Proved undeveloped................ 8,683,020 13,525,863 29,857,516 87,648,967
---------- ---------- ----------- -----------
Total proved natural gas
reserves................ 41,638,100 64,462,805 76,263,964 133,335,926
========== ========== =========== ===========
NET OIL RESERVES (BBL):
Proved developed.................. 2,082,885 3,110,505 3,209,387 3,252,151
Proved undeveloped................ 818,736 1,160,564 1,343,880 2,155,055
---------- ---------- ----------- -----------
Total proved oil
reserves................ 2,901,621 4,271,069 4,553,267 5,407,206
========== ========== =========== ===========
TOTAL PROVED RESERVES (MCFE)........ 59,047,826 90,089,219 103,583,566 165,779,162
========== ========== =========== ===========
</TABLE>

ESTIMATED PRESENT VALUE OF PROVED RESERVES

<TABLE>
<CAPTION>
AT DECEMBER 31,
-------------------------------------------- AT MAY 31,
1992 1993 1994 1995
----------- ----------- ----------- ------------
<S> <C> <C> <C> <C>
ESTIMATED PV-10 VALUE:
Proved developed.................. $45,192,000 $66,309,471 $47,172,093 $ 51,269,819
Proved undeveloped................ 10,248,000 17,451,305 22,222,511 48,926,612
----------- ----------- ----------- ------------
Total..................... $55,440,000 $83,760,776 $69,394,604 $100,196,431
=========== =========== =========== ============
</TABLE>

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.
Reserve 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, reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered.

A portion of the Company's proved reserves has been accumulated through the
Company's interests in the limited partnerships for which it serves as general
partner. The estimates of future net cash flows and their present values, based
on period end prices, assume that some of the limited partnerships in which the
Company owns interests will achieve payout status in the future. None of the
limited partnerships had achieved payout status at May 31, 1995.

29
<PAGE> 30

DRILLING ACTIVITY

The following table sets forth the results of the Company's drilling
activities during the three fiscal years ended December 31, 1994:

<TABLE>
<CAPTION>
GROSS WELLS NET WELLS(1)
--------------------------------- ---------------------------------
YEAR TYPE OF WELL(2) TOTAL PRODUCING(3) DRY(4) TOTAL PRODUCING(3) DRY(4)
- ---- --------------- ----- ------------ ------ ----- ------------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
1992 Exploratory 7 2 5 2.2 0.7 1.5
Development 33 32 1 5.5 5.4 0.1

1993 Exploratory 12 5 7 5.6 2.5 3.1
Development 22 21 1 3.8 3.4 0.4

1994 Exploratory 14 6 8 9.2 4.7 4.5
Development 30 26 4 6.9 5.0 1.9
</TABLE>

- ---------------
(1) Represents the aggregate of the Company's direct or indirect fractional
working interests in the gross wells drilled.

(2) An exploratory well is a well drilled either in search of a new, as-yet
undiscovered oil or gas reservoir or to greatly extend the known limits of a
previously discovered reservoir. A development well is a well drilled within
the presently proved productive area of an oil or gas reservoir, as
indicated by reasonable interpretation of available data, with the objective
of completing in that reservoir.

(3) A producing well is an exploratory or development well found to be capable
of producing either oil or gas in sufficient quantities to justify
completion as an oil or gas well.

(4) A dry well is an exploratory or development well that is not a producing
well.

OIL AND GAS WELLS

The following table sets forth the number of oil and gas wells in which the
Company had a working interest at December 31, 1994. All of these wells are
located within the U.S.

<TABLE>
<CAPTION>
OIL WELLS GAS WELLS TOTAL WELLS(1)
--------- --------- --------------
<S> <C> <C> <C>
Gross(2)......................................... 3,141.0 1,000.0 4,141.0
Net(3)........................................... 79.3 109.1 188.4
</TABLE>

- ---------------
(1) Excludes 31 service wells in 1994.

(2) A gross well is 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.

(3) 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.

30
<PAGE> 31

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. See "Risk
Factors -- Risks of Purchasing Interests in Producing Properties." The following
table sets forth the developed and undeveloped leasehold acreage held by the
Company at December 31, 1994:

<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
------------------------- ------------------------
GROSS(1) NET(2) GROSS(1) NET(2)
---------- ---------- ---------- ---------
<S> <C> <C> <C> <C>
Alabama.................................... 7,075.72 820.82 372.00 61.17
Arkansas................................... 8,359.45 2,786.80 4,212.60 2,607.63
Kansas..................................... 1,750.00 691.67 5,450.00 2,268.55
Louisiana.................................. 33,364.35 13,841.90 4,943.64 4,401.75
Mississippi................................ 11,153.82 4,260.69 5,476.34 1,011.74
Nebraska................................... -- -- 1,867.04 1,169.53
New Mexico................................. 2,574.47 655.36 422.46 124.60
North Dakota............................... 1,276.19 147.25 9,157.23 957.30
Oklahoma................................... 56,018.81 21,792.40 5,842.08 2,757.14
Texas...................................... 108,368.32 44,662.46 35,651.07 24,622.95
West Virginia.............................. 16,048.20 10,484.50 -- --
Wyoming.................................... 9,306.64 2,780.34 23,085.01 7,111.05
All other states........................... 477.64 128.66 4,690.44 272.81
---------- ---------- ---------- ---------
TOTAL............................ 255,773.61 103,052.85 101,169.91 47,366.22
========== ========== ========== =========
</TABLE>

- ---------------
(1) A gross acre is 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.

(2) 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. A material portion of the Company's acreage is owned
by virtue of its interests derived from limited partnerships. The net
acreage reflected on this table shows the Company's interests assuming that
an after payout status is achieved in these limited partnerships. At May 31,
1995, none of the limited partnerships had achieved payout status.

PARTNERSHIPS

The Company has historically relied on limited partnerships as its
principal financing vehicle to fund its activities. The Company has formed 95
limited partnerships which have raised a total of approximately $440.0 million
at March 31, 1995. However, as the Company has increasingly shifted its emphasis
to exploration and development activities and its reserve base has grown, the
Company has significantly reduced its reliance on limited partnership financing.
The Company intends to continue to reduce its reliance on limited partnerships
in the future.

Approximately 20 of the limited partnerships formed and managed by the
Company have been in operation for nine years or more, and have produced a
substantial majority of their reserves. Given the age of these limited
partnerships, the Company currently intends to propose that the limited partners
in these limited partnerships vote to sell their remaining properties and
liquidate the limited partnerships. The Company may acquire some or all of the
remaining property interests owned by these limited partnerships. At this time,
the Company intends to propose to purchase such properties only after third
party industry members are solicited to purchase such properties, and then only
at prices based upon prices offered for the properties by such third parties.

The Company currently offers two primary types of limited partnerships:
Swift Depositary Interests ("SDI"), a publicly offered partnership program under
which partnerships are formed to acquire interests in

31
<PAGE> 32

producing oil and gas properties, and Swift Energy Drilling Ventures ("SEDV"),
privately offered partnerships formed to engage in the drilling of development
and exploratory wells. The Company does not intend to extend the SDI Program
past its current offering period, which ends April 30, 1996, and will continue
to evaluate the market for the SDI Program in the interim period.

Under the SDI program, partnerships are formed on a sequential basis,
typically at quarterly intervals. In 1994, the Company raised approximately
$32.1 million under the SDI program. The SDI partnerships acquire, manage, and
ultimately sell interests in properties that are producing oil and gas in
commercial quantities or which contain shut-in wells capable of such production.
The SDI partnerships seek to profit primarily from the sale of oil and gas
produced from the properties in which they own interests, and from the proceeds
of the eventual sale of their interests.

In September of 1993, the Company began offering interests in SEDV. As of
March 15, 1995, three partnerships (one in each of 1993, 1994 and 1995) with
aggregate investor contributions of approximately $9.0 million had been formed
under this program. The Company anticipates formation of at least one additional
private drilling partnership in 1995.

Both the SDI and SEDV partnerships are 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 does not bear any of the costs incurred in acquiring or
drilling properties. In the SDI partnerships, the Company bears 14.25% of all
other continuing costs (approximately 24.25% after payout) and in exchange, the
Company is entitled to receive net revenues in the same percentages. In the SEDV
partnerships, 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 SEDV partnership
prior to payout, 30% distributed after payout, and 35% distributed after 200%
payout. In both the SDI and SEDV partnerships, the Company is also entitled to a
general and administrative overhead allowance and an incentive amount.

CONFLICTS OF INTEREST BETWEEN THE COMPANY AND LIMITED PARTNERSHIPS

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
through other limited partnerships and joint ventures and 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, including (i) sales of
properties by the Company to the limited partnerships, (ii) operation of limited
partnership properties by the Company, (iii) rendering of oil field or drilling
services by the Company to an limited partnership, (iv) handling of limited
partnership funds by the Company, and (v) loans between the Company and an
limited partnership. 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 $20.0 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.

32
<PAGE> 33

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. In
marketing its partnership programs, the Company competes with other oil and gas
companies sponsoring similar programs and with numerous other investment
opportunities.

REGULATIONS

ENVIRONMENTAL REGULATIONS

The federal government and various state and local governments have adopted
laws and regulations regarding the control of contamination of the environment.
These laws and regulations may require the acquisition of a permit by operators
before drilling commences, prohibit drilling activities on certain lands lying
within wilderness areas or where pollution arises, and impose substantial
liabilities for pollution resulting from drilling operations particularly
operations in offshore waters or on submerged lands. These laws and regulations
may also increase the costs of drilling and operation of wells. However, the
Company does not believe that it is affected in a significantly different manner
by these regulations than are its competitors in the oil and gas industry. See
"Risk Factors -- Effects of Governmental Regulation."

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 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. See "Risk Factors -- Volatility of
Oil and Gas Prices and Markets."

PRICE CONTROLS

Prior to January 1, 1993, the sale of natural gas production was subject to
regulation under the Natural Gas Act and the Natural Gas Policy Act of 1978
("NGPA"). However, under the Natural Gas Wellhead Decontrol Act of 1989 all
price regulation under the NGPA and Natural Gas Act of rate, certificate and
abandonment requirements were phased out effective as of January 1, 1993.

FERC ORDERS

Several major regulatory changes have been implemented by the Federal
Energy Regulatory Commission ("FERC") from 1985 to the present 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,

33
<PAGE> 34

"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 regulatory
authorities also regulate the amount of oil and gas produced by assigning
allowable rates of production to each well or proration unit.

FEDERAL LEASES

Some of the Company's properties are located on federal oil and gas leases
administered by various federal agencies, including the Bureau of Land
Management. Various regulations and orders affect the terms of leases,
exploration and development plans, methods of operation, and related matters.

EMPLOYEES

At December 31, 1994, the Company employed 209 persons, including 28
engineers, 14 geologists and 11 landmen. None of the Company's employees are
represented by a union. Relations with employees are considered to be good.

FACILITIES

The Company occupies approximately 73,000 square feet of office space at
16825 Northchase Drive, Houston, Texas, under a ten-year lease expiring in 2005
which provides for various expansion options. The payment obligations under the
lease range from $12.50 per square foot in the first two years up to $18.50 per
square foot in the last two years. 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 legal proceedings are pending other than ordinary routine litigation
incidental to the Company's business.

34
<PAGE> 35

MANAGEMENT

EXECUTIVES AND CERTAIN OTHER OFFICERS AND DIRECTORS

<TABLE>
<CAPTION>
NAME TITLE
- --------------------------------------------- ---------------------------------------------
<S> <C>
A. Earl Swift................................ Chairman of the Board, President and Chief
Executive Officer
Virgil N. Swift.............................. Vice Chairman of the Board and Executive Vice
President -- Business Development
Terry E. Swift............................... Executive Vice President and Chief Operating
Officer
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
James R. Stewart............................. Vice President -- Drilling and Production
Alton D. Heckaman, Jr........................ Vice President and Controller
Joseph A. D'Amico............................ Vice President -- Exploration and Development
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, 61, is President, 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, serving his last three years as Vice
President of Exploration and Production for Michigan-Wisconsin Pipe Line Company
and American Natural Gas Production Company. 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, 66, has been a director of the Company since 1981, and has
acted as Vice Chairman of the Board and Executive Vice President -- Business
Development since November 1991. He previously served as Executive Vice
President and Chief Operating Officer from 1982 to November 1991. Mr. Swift
joined the Company in 1981 as Vice President -- Drilling and Production. For the
preceding 28 years he held various production, drilling and engineering
positions with Gulf Oil Corporation and its subsidiaries, last serving as
General Manager -- Drilling for Gulf Canada Resources, Inc. Mr. Swift is a
registered professional engineer and holds a degree in Petroleum Engineering.

Terry E. Swift, 39, was appointed Executive Vice President and Chief
Operating Officer of the Company in November 1991. He served as Senior Vice
President -- Exploration and Joint Ventures from 1990 to November 1991, as Vice
President -- Exploration and Joint Ventures from 1988 to 1990 and as Assistant
Vice President -- Engineering from 1986 to 1988. 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, 49, 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.

Bruce H. Vincent, 47, 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.

35
<PAGE> 36

James M. Kitterman, 51, 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.

James R. Stewart, 59, 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., 38, 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.

Joseph A. D'Amico, 47, has been Vice President -- Exploration and
Development of the Company since August 1993. 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.

G. Robert Evans, 64, has been a director of the Company since 1994. Since
1991, he has been Chairman and Chief Executive Officer of Material Sciences
Corporation of Elk Grove Village, a corporation that develops and commercializes
continuously processed, coated materials technologies. He is also currently
serving as a director of three other public companies: Consolidated Freightways,
Inc. (transportation), Fibreboard Corporation (wood products, insulation and
resort operations) and Elco Industries (manufacturing). 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, 71, 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, 59, has served as a director of the Company since
1987. 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 currently serves as a director of Catalyst
Semiconductor, Inc., a public company engaged in the design and manufacture of
semiconductors. 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., 46, 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 and as President of H&R
Precision, Inc., a general contractor, since 1994. Mr. Smith formerly acted as
Chief Executive Officer of California Video Sales, Inc. from 1987 to 1990.

Harold J. Withrow, 67, has been a director of the Company since 1988. Mr.
Withrow is an independent oil and gas consultant. 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.

COMPENSATION TO DIRECTORS

STANDARD ARRANGEMENTS

During 1995, nonemployee members of the board of directors will receive
$1,750 per board meeting attended, an annual fee of $5,000 for serving on
committees of the board, and an additional annual fee of

36
<PAGE> 37

$5,000 for services as a director. Board members are reimbursed for travel
expenses they incur in attending board of directors meetings. Employees of the
Company are not compensated for serving as directors.

STOCK OPTIONS GRANTED TO NONEMPLOYEE DIRECTORS

Under the Company's 1990 Nonqualified Stock Option Plan, as amended (the
"Nonqualified Plan"), each nonemployee director is granted options to purchase
10,000 shares of the Common Stock on the date he first becomes a nonemployee
director. Additionally, on the day after each annual meeting of the Company's
shareholders, each individual who is a nonemployee director on that date is
granted, subject to an option maximum, options to purchase 5,000 shares of the
Common Stock. A grant of options to a nonemployee director is reduced to the
extent that it would cause him to hold unexercised options to purchase more than
60,000 shares of the Common Stock. Options granted under the Nonqualified Plan
(i) have an exercise price equal to the highest closing price of the Common
Stock on any established national exchange on the date of grant, (ii) are for a
term of 10 years from the date of grant, and (iii) become exercisable for 20% of
the shares covered thereby on each of the first five anniversaries of the date
of grant. None of the nonemployee directors exercised options during the year
ended December 31, 1994.

EXECUTIVE COMPENSATION

SUMMARY OF CASH AND CERTAIN OTHER COMPENSATION

The following table sets forth certain summary information regarding
compensation paid or accrued by the Company to or on behalf of the Company's
Chief Executive Officer and each of the other four most highly compensated
executive officers of the Company (determined as of the end of the last fiscal
year) for the fiscal years ended December 31, 1992, 1993 and 1994.

SUMMARY COMPENSATION TABLE(1)

<TABLE>
<CAPTION>
LONG TERM
COMPENSATION
------------
AWARDS
ANNUAL COMPENSATION ------------
--------------------------------- SECURITIES ALL OTHER COMPENSATION
BONUS UNDERLYING ------------------------
NAME AND ------------------- OPTIONS/SARS LIFE 401(K)
PRINCIPAL POSITION YEAR SALARY CASH STOCK (2) INSURANCE (3) (4)
- ----------------------------------- ---- ---------- -------- ------- ------------ --------------- ------
<S> <C> <C> <C> <C> <C> <C> <C>
A. EARL SWIFT...................... 1994 $278,400 $128,000 $32,000 12,100(5) $102,240 $7,500
Chief Executive Officer, 1993 260,180 136,000 34,000 23,980(6) 47,941 7,925
President 1992 240,000 120,000 30,000 19,800 39,905 7,530
VIRGIL N. SWIFT.................... 1994 190,600 23,898 5,975 12,100(5) 29,019 7,500
Executive Vice 1993 178,180 31,350 7,839 21,340(6) 22,369 7,816
President -- Business Development 1992 168,000 20,164 5,041 16,500 17,072 6,280
TERRY E. SWIFT..................... 1994 158,300 21,117 5,279 52,756 6,138 7,500
Chief Operating Officer, 1993 145,180 27,100 6,775 16,390 5,573 7,580
Executive Vice President 1992 125,000 16,172 4,043 13,750 1,464 4,871
JOHN R. ALDEN...................... 1994 142,500 17,296 4,324 37,730 11,419 7,500
Chief Financial Officer, 1993 133,180 23,430 5,859 13,640 8,781 7,512
Senior Vice President -- Finance 1992 123,000 15,092 3,773 11,000 4,374 4,727
JAMES M. KITTERMAN................. 1994 138,400 17,353 4,338 46,750 12,328 7,500
Senior Vice President -- Operations 1993 128,180 22,720 5,682 11,000 10,294 7,350
1992 118,000 13,848 3,462 8,800 5,000 4,571
</TABLE>

- ---------------
(1) Full executive compensation disclosure is set forth in the Company's
definitive proxy statement mailed to shareholders in connection with the
Company's May 9, 1995 annual meeting, incorporated herein by reference. See
"Incorporation of Certain Information by Reference."
(2) The numbers of securities underlying options granted in 1992, 1993 and 1994
reflect the 10% stock dividend that occurred in September 1994.
(3) Represents insurance premiums paid by the Company during the covered fiscal
year with respect to life insurance for the benefit of the named executive
officer.
(4) Contributions by the Company (one-half in cash and one-half in Company
stock) for the account of the named executive officer to the Swift Energy
Company Employee Savings Plan.
(5) Includes for each of Messrs. A. E. Swift and V. N. Swift, respectively,
previously granted options for 12,100 shares that were extended and repriced
in 1994.
(6) Includes for each of Messrs. A. E. Swift and V. N. Swift, respectively,
previously granted options for 3,300 shares that were extended and repriced
in 1993.

37
<PAGE> 38

PRINCIPAL SHAREHOLDERS

The following table sets forth information concerning the shareholdings, as
of May 31, 1995, 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 owns more
than five percent of the Company's outstanding common stock.

<TABLE>
<CAPTION>
SHARES OF COMMON STOCK
BENEFICIALLY OWNED AT
MAY 31, 1995(1)
-------------------------
PERCENT OF
CLASS
NAME OF PERSON OR GROUP POSITION NUMBER OUTSTANDING
- -------------------------- ----------------------------------------------- --------- -----------
<S> <C> <C> <C>
A. Earl Swift............. Chairman of the Board, President, Chief 4.1%
Executive Officer 304,437(2)
Virgil N. Swift........... Vice Chairman of the Board, Executive Vice 4.1%
President -- Business Development 302,909
G. Robert Evans........... Director 2,000 (3)
Raymond O. Loen........... Director 141,356(4) 1.9%
Henry C. Montgomery....... Director 29,370 (3)
Clyde W. Smith, Jr. ...... Director 24,125 (3)
Harold J. Withrow......... Director 27,720 (3)
Terry E. Swift............ Executive Vice President, Chief Operating (3)
Officer 55,987
John R. Alden............. Senior Vice President -- Finance, Chief (3)
Financial Officer, Secretary 44,401(5)
James M. Kitterman........ Senior Vice President -- Operations 35,041 (3)
All executive officers & directors as a group (12 persons)................. 1,014,917 13.7%
Foreign & Colonial Management Limited...................................... 417,216(6) 6.2%
Hypo Foreign & Colonial Management (Holdings) Limited
Exchange House, Primrose Street
London EC2A 2NY England
FMR Corp................................................................... 367,158(7) 5.5%
82 Devonshire Street
Boston, Massachusetts 02109
Dimensional Fund Advisors Inc. ............................................ 344,560(8) 5.1%
1299 Ocean Avenue, 11th Floor
Santa Monica, California 90401
</TABLE>

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

(1) 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 May 31, 1995 by exercise of options
granted under the Company's stock option plans: Mr. A. E. Swift -- 36,256;
Mr. V. N. Swift -- 34,408; Mr. Loen -- 22,000; Mr. Smith -- 19,800; Mr.
Montgomery -- 25,960; Mr. Withrow -- 25,520; Mr. T. E. Swift -- 34,575; Mr.
Alden -- 30,932; Mr. Kitterman -- 21,230; and all executive officers and
directors as a group -- 293,920.

(2) Includes 4,858 shares held by Mr. Swift's wife.

(3) Less than one percent.

(4) Includes 14,300 shares as to which Mr. Loen, as co-trustee for an HR-10
Retirement Plan, shares voting and investment power with his wife; 70,000
shares held by his wife (who holds sole voting and investment power as to
those shares and 3,680 shares held in her IRA), and 4,554 shares held in Mr.
Loen's IRA.

(5) Includes 100 shares held by Mr. Alden's mother of which he could be deemed
to be the beneficial owner.

(6) Based on a Schedule 13D dated April 26, 1993 filed with the SEC.

(7) Based on a Schedule 13G dated February 13, 1995 filed with the SEC, 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 367,158 shares
of the Company's shares 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"). Edward C. Johnson 3d and Abigail P.
Johnson each own 24.9% of the outstanding voting common stock of FMR Corp.,
and various Johnson family members and trusts for the benefit of Johnson
family members own FMR Corp. voting common stock. Edward C. Johnson 3d, FMR
Corp. (through its control of Fidelity) and the Funds each have sole power
to dispose of the 367,158 shares owned by the Funds, but 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.

(8) Based on a Schedule 13G dated January 31, 1995 filed with the SEC.
Dimensional Fund Advisors Inc. ("Dimensional") is deemed to have beneficial
ownership of 344,560 shares of the Company's stock as of December 31, 1994,
all of which shares are held in portfolios of DFA Investment Dimensions
Group Inc., a registered open-end investment company, or in series of the
DFA Investment Trust Company, a Delaware business trust, or the DFA Group
Trust and DFA Participation Group Trust, investment vehicles for qualified
employee benefit plans, for all of which Dimensional serves as investment
manager. Dimensional disclaims beneficial ownership of all such shares.
Dimensional has sole voting power as to 257,950 shares and sole dispositive
power as to all 344,560 shares.

38
<PAGE> 39

DESCRIPTION OF CAPITAL STOCK
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 limitations 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.

COMMON STOCK

The Company is authorized to issue 35,000,000 shares of Common Stock, par
value $.01, of which 6,718,742 were issued and outstanding at May 31, 1995.
Holders of Common Stock are entitled to one vote for each share held.
Shareholders do not have preemptive rights or the right to cumulate votes for
the election of directors. Shares are not subject to redemption nor to any
liability for further calls. All shares of Common Stock issued and outstanding
are, and all the shares 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 May 31,
1995, there were 2,418,697 shares, in the aggregate, reserved for issuance under
the Company's stock option plans, of which 1,324,288, in the aggregate, were
subject to outstanding options. In addition, 68,750 shares were reserved for
issuance upon the exercise of outstanding options granted outside the Company's
option plans, and 2,343,113 shares were reserved for issuance upon conversion of
the outstanding $28.75 million of 6 1/2% Convertible Subordinated Debentures due
2003, based upon a conversion price of $12.27 per share. 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 Nonqualified Plan, and
its Employee Stock Purchase Plan.

TRANSFER AGENT

American Stock Transfer & Trust Company, New York, New York is the transfer
agent and registrar for the Common Stock.

BYLAW AMENDMENTS

Under Texas law, the board of directors may amend the Company's bylaws to
authorize a classified board, among other things, without shareholder approval.
A proposal may be brought before the board of directors in the near future to
amend the bylaws to include a classified board and other measures that could
have an effect of delaying, deferring or preventing a change in control of the
Company.

39
<PAGE> 40

UNDERWRITING

Subject to the terms and conditions set forth in the Underwriting Agreement
among the Company and the Underwriters named below, for whom Oppenheimer & Co.,
Inc., Morgan Keegan & Company, Inc. and Southcoast Capital Corporation are
acting as representatives (the "Representatives"), the Underwriters named below
have severally agreed to purchase from the Company, and the Company has agreed
to sell to the Underwriters, the number of shares of Common Stock set forth
opposite their respective names:

<TABLE>
<CAPTION>
NUMBER
UNDERWRITER(S) OF SHARES
------------------------------------------------------------------------ -----------
<S> <C>
Oppenheimer & Co., Inc. ................................................ 900,000
Morgan Keegan & Company, Inc. .......................................... 895,000
Southcoast Capital Corporation.......................................... 895,000
Bear, Stearns & Co. Inc. ............................................... 100,000
Dean Witter Reynolds Inc................................................ 100,000
Dillon, Read & Co. Inc. ................................................ 100,000
A.G. Edwards & Sons, Inc. .............................................. 100,000
Goldman, Sachs & Co. ................................................... 100,000
Howard, Weil, Labouisse, Friedrichs Incorporated........................ 100,000
Kemper Securities, Inc. ................................................ 100,000
Lehman Brothers Inc. ................................................... 100,000
Morgan Stanley & Co. Incorporated....................................... 100,000
Prudential Securities Incorporated...................................... 100,000
Salomon Brothers Inc ................................................... 100,000
First Albany Corporation................................................ 100,000
Advest, Inc. ........................................................... 50,000
Robert W. Baird & Co. Incorporated...................................... 50,000
J.C. Bradford & Co. .................................................... 50,000
Crowell, Weedon & Co. .................................................. 50,000
Fahnestock & Co. Inc. .................................................. 50,000
Gerard Klauer Mattison & Co. ........................................... 50,000
Janney Montgomery Scott Inc. ........................................... 50,000
Jefferies & Company, Inc. .............................................. 50,000
Ladenburg, Thalmann & Co. Inc. ......................................... 50,000
Legg Mason Wood Walker, Incorporated.................................... 50,000
McDonald & Company Securities, Inc. .................................... 50,000
Nesbitt Burns Securities Inc. .......................................... 50,000
Neuberger & Berman...................................................... 50,000
Petrie Parkman & Co. ................................................... 50,000
Principal Financial Securities, Inc. ................................... 50,000
Rauscher Pierce Refsnes, Inc. .......................................... 50,000
The Robinson-Humphrey Company, Inc. .................................... 50,000
Stephens Inc. .......................................................... 50,000
First Colonial Securities Group, Inc. .................................. 30,000
Hanifen, Imhoff Inc. ................................................... 30,000
C.L. King & Associates, Inc. ........................................... 30,000
Parker/Hunter Incorporated.............................................. 30,000
Scott & Stringfellow, Inc. ............................................. 30,000
Starr Securities, Inc. ................................................. 30,000
Wellington (H.G.) & Co. Inc. ........................................... 30,000
-------
Total......................................................... 5,000,000
=======
</TABLE>

The Underwriting Agreement provides that the obligations of the
Underwriters thereunder are subject to approval of certain legal matters by
counsel and to various other conditions. The nature of the Underwriters'

40
<PAGE> 41

obligations is such that they are committed to purchase all of the above shares
of Common Stock if any are purchased.

The Underwriters propose to offer the shares of Common Stock directly to
the public at the offering price set forth on the cover page of this Prospectus
and at such price less a concession not in excess of $0.30 per share of Common
Stock to certain securities dealers, of which a concession not in excess of
$0.10 per share of Common Stock may be reallowed to certain other securities
dealers. After this public offering, the public offering price, allowances,
concessions and other selling terms may be changed by the Representatives.

The Company has granted to the Underwriters an option, exercisable within
30 days after the date of this Prospectus, to purchase from the Company up to an
aggregate of 750,000 additional shares of Common Stock to cover over-allotments,
if any, at the public offering price less the underwriting discount set forth on
the cover page of this Prospectus. If the Underwriters exercise their
over-allotment option to purchase any of the 750,000 additional shares of Common
Stock, the Underwriters have severally agreed, subject to certain conditions, to
purchase approximately the same percentage thereof as the number of shares of
Common Stock as may be purchased by each of them bears to the 5,000,000 shares
of Common Stock offered hereby. The Company will be obligated, pursuant to the
over-allotment option, to sell shares to the Underwriters to the extent such
over-allotment option is exercised. The Underwriters may exercise such option
only to cover over-allotments made in connection with the sale of the shares of
Common Stock offered hereby.

All executive officers and directors of the Company, as a group, holding
1,014,917 shares in the aggregate have agreed, pursuant to lock-up agreements
executed in connection with this offering, that until 120 days from the date of
this Prospectus, they will not sell, make any short sale of, loan, grant any
option for the purchase or otherwise dispose of any shares or any securities
convertible into or exchangeable or exercisable for shares without the consent
of Oppenheimer & Co., Inc. The Company has agreed that it will not, without the
consent of Oppenheimer & Co., Inc., offer, sell, or dispose of any shares of
Common Stock, options or warrants to acquire shares of Common Stock or
securities exchangeable for or convertible into shares of Common Stock until 120
days after this offering (except for (i) shares issued pursuant to stock options
outstanding on the date hereof and (ii) stock options issued pursuant to
employee benefit or incentive compensation plans in effect on the date hereof).

The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act, and to contribute
to certain payments that the Underwriters may be required to make in respect
thereof.

An affiliate of a member of the National Association of Securities Dealers,
Inc. ("NASD") that is participating in the offering will receive greater than
10% of the net proceeds of the offering. Accordingly, the offering is being
conducted pursuant to the provisions of Article III, Section 44(c)(8) of the
NASD's Rules of Fair Practice.

The Underwriters do not intend to confirm sales of the Common Stock offered
hereby to any account over which they exercise discretionary authority.

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.
Certain legal matters will be passed upon for the Underwriters by Akin, Gump,
Strauss, Hauer & Feld, L.L.P., Houston, Texas.

EXPERTS

The consolidated financial statements included 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 accounting and auditing in giving said
reports.

41
<PAGE> 42

The reference to the reports of H.J. Gruy and Associates, Inc., independent
petroleum consultants, contained herein with respect to the proved reserves, the
estimated future net revenues from such proved reserves, and the discounted
present values of such estimated future net revenues, is made in reliance upon
the authority of such firm as experts with respect to such matters.

INCORPORATION OF CERTAIN INFORMATION BY REFERENCE

The Company's Form 10-K as of December 31, 1994, its definitive proxy
statement mailed to shareholders in connection with the May 9, 1995, annual
shareholders' meeting and its Form 10-Q for the quarterly period ended March 31,
1995, are incorporated herein by reference. 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.

42
<PAGE> 43

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
</TABLE>

F-1
<PAGE> 44

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, 1994
and 1993, and the related consolidated statements of income, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1994. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, 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, 1994 and 1993, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1994, in conformity with generally accepted accounting principles.

As discussed in Note 2 to the consolidated financial statements, effective
January 1, 1994, the Company changed its method of accounting for earned
interests. As discussed in Note 3 to the consolidated financial statements,
effective January 1, 1992, the Company changed its method of accounting for
income taxes.

ARTHUR ANDERSEN LLP

Houston, Texas
February 17, 1995

F-2
<PAGE> 45

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------- MARCH 31,
1993 1994 1995
------------ ------------ ------------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents............................................ $ 636,349 $ 985,498 $ 1,531,762
Accounts receivable --
Oil and gas sales.................................................. 13,938,932 12,394,636 12,532,029
Associated limited partnerships and joint ventures................. 28,507,948 17,899,150 13,904,695
Joint interest owners.............................................. 2,923,797 4,335,283 4,240,136
Producing oil and gas properties held for transfer................... 15,436,853 3,525,841 3,005,520
Limited partnership formation and marketing costs.................... 2,227,100 -- --
Other current assets................................................. 1,636,141 68,010 128,255
------------ ------------ ------------
Total Current Assets........................................... 65,307,120 39,208,418 35,342,397
------------ ------------ ------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized.................................. 106,251,713 93,368,795 97,257,030
Unproved properties not being amortized............................ 7,932,557 14,805,479 16,318,934
------------ ------------ ------------
114,184,270 108,174,274 113,575,964
Furniture, fixtures and other equipment.............................. 2,969,389 3,476,695 3,819,581
------------ ------------ ------------
117,153,659 111,650,969 117,395,545
Less -- Accumulated depreciation, depletion and amortization........... (25,847,271) (21,364,949) (23,533,177)
------------ ------------ ------------
91,306,388 90,286,020 93,862,368
------------ ------------ ------------
Other Assets:
Receivables from associated limited partnerships, net of current
portion............................................................ -- 1,916,477 2,185,975
Limited partnership formation and marketing costs, net of current
portion............................................................ 2,904,274 2,991,873 3,162,422
Deferred charges..................................................... 1,375,135 1,269,955 1,242,232
------------ ------------ ------------
4,279,409 6,178,305 6,590,629
------------ ------------ ------------
$160,892,917 $135,672,743 $135,795,394
============ ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Short-term bank borrowings........................................... $ 2,650,000 $ 27,229,000 $ 30,550,000
Accounts payable and accrued liabilities............................. 7,518,577 9,516,005 6,634,006
Payable to associated limited partnerships........................... 769,373 637,991 35,184
Payable related to producing oil and gas property acquisitions....... 27,118,706 -- --
Undistributed oil and gas revenues................................... 17,508,781 14,962,863 14,852,256
------------ ------------ ------------
Total Current Liabilities...................................... 55,565,437 52,345,859 52,071,446
------------ ------------ ------------
Long-Term Debt......................................................... 28,750,000 28,750,000 28,750,000
Deferred Revenues...................................................... 9,819,530 7,827,562 7,346,764
Deferred Income Taxes.................................................. 12,292,236 4,622,191 4,748,684
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,
6,001,075, 6,685,137, and 6,710,412 shares issued and outstanding,
respectively....................................................... 60,011 66,851 67,104
Additional paid-in capital........................................... 17,515,417 24,885,903 25,112,419
Retained earnings.................................................... 36,890,286 17,174,377 17,698,977
------------ ------------ ------------
54,465,714 42,127,131 42,878,500
------------ ------------ ------------
$160,892,917 $135,672,743 $135,795,394
============ ============ ============
</TABLE>

See accompanying notes to Consolidated Financial Statements.

F-3
<PAGE> 46

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------------------ --------------------------
1992 1993 1994 1994 1995
----------- ----------- ------------ ------------ ----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales.................. $12,420,222 $15,535,671 $ 19,802,188 $ 4,817,270 $4,876,041
Earned interests from limited
partnerships and joint
ventures......................... 1,692,331 3,308,623 -- -- --
Fees from limited partnerships and
joint ventures................... 1,023,946 763,347 701,528 108,682 113,430
Supervision fees................... 3,443,777 3,718,829 3,751,061 943,148 904,539
Interest income.................... 113,387 201,584 47,980 18,644 7,484
Other, net......................... 515,931 604,599 1,072,535 250,791 357,094
----------- ----------- ----------- ---------- ----------
19,209,594 24,132,653 25,375,292 6,138,535 6,258,588
----------- ----------- ----------- ---------- ----------
Costs and Expenses:
General and administrative, net of
reimbursement.................... 4,977,440 5,065,323 5,197,899 1,195,331 1,306,765
Depreciation, depletion and
amortization..................... 4,906,029 7,300,967 7,904,801 1,688,938 2,168,229
Oil and gas production............. 3,934,294 4,540,290 5,639,630 1,142,288 1,629,379
Interest expense................... 76,477 597,465 1,795,133 358,975 477,781
Impairment of investment in
drilling tool subsidiary......... 627,835 -- -- -- --
----------- ----------- ----------- ---------- ----------
14,522,075 17,504,045 20,537,463 4,385,532 5,582,154
----------- ----------- ----------- ---------- ----------
Income Before Income Taxes........... 4,687,519 6,628,608 4,837,829 1,753,003 676,434
Provision for Income Taxes........... 1,517,759 1,732,355 1,112,158 542,281 151,834
----------- ----------- ----------- ---------- ----------
Income Before Cumulative Effect of
Change in Accounting Principle..... 3,169,760 4,896,253 3,725,671 1,210,722 524,600
Cumulative Effect of Change in
Accounting Principle............... 915,000 -- (16,772,698) (16,772,698) --
----------- ----------- ----------- ---------- ----------
Net Income (Loss).................... $ 4,084,760 $ 4,896,253 $(13,047,027) $(15,561,976) $ 524,600
=========== =========== =========== ========== ==========
Per Share Amounts --
Primary:
Income Before Cumulative Effect of
Change in Accounting Principle... $ 0.52 $ 0.74 $ 0.56 $ 0.18 $ 0.08
=========== =========== =========== ========== ==========
Cumulative Effect of Change in
Accounting Principle............. $ 0.15 $ -- $ (2.52) $ (2.54) $ --
=========== =========== =========== ========== ==========
Net Income (Loss).................. $ 0.67 $ 0.74 $ (1.96) $ (2.36) $ 0.08
=========== =========== =========== ========== ==========
Fully Diluted:
Income Before Cumulative Effect of
Change in Accounting Principle... $ 0.52 $ 0.70 $ 0.56 $ 0.17 $ 0.08
=========== =========== =========== ========== ==========
Cumulative Effect of Change in
Accounting Principle............. $ 0.15 $ -- $ (2.52) $ (2.54) $ --
=========== =========== =========== ========== ==========
Net Income (Loss).................. $ 0.67 $ 0.70 $ (1.96) $ (2.36) $ 0.08
=========== =========== =========== ========== ==========
Weighted Average Shares
Outstanding........................ 6,135,044 6,588,076 6,644,248 6,601,733 6,689,350
=========== =========== =========== ========== ==========
Pro forma amounts assuming change in
accounting for earned interests is
applied retroactively (see Note
2) --
Net Income......................... $ 3,729,851 $ 4,322,478 $ 3,725,671 $ 1,210,722 $ 524,600
Per Share Amounts --
Primary.......................... $ 0.61 $ 0.66 $ 0.56 $ 0.18 $ 0.08
Fully Diluted.................... $ 0.61 $ 0.63 $ 0.56 $ 0.17 $ 0.08
</TABLE>

See accompanying notes to Consolidated Financial Statements.

F-4
<PAGE> 47

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

<TABLE>
<CAPTION>
ADDITIONAL
COMMON PAID-IN RETAINED
STOCK(1) CAPITAL EARNINGS TOTAL
------- ----------- ------------ ------------
<S> <C> <C> <C> <C>
Balance, December 31, 1991............. $49,551 $10,701,532 $ 27,909,273 $ 38,660,356
Stock issued for benefit plans
(23,445 shares)................... 235 138,059 -- 138,294
Stock issued in institutional
placement (990,000 shares)........ 9,900 6,387,976 -- 6,397,876
Net Income........................... -- -- 4,084,760 4,084,760
------- ----------- ------------ ------------
Balance, December 31, 1992............. $59,686 $17,227,567 $ 31,994,033 $ 49,281,286
Stock issued for benefit plans
(19,096 shares)................... 191 170,059 -- 170,250
Stock options exercised (13,400
shares)........................... 134 117,791 -- 117,925
Net Income........................... -- -- 4,896,253 4,896,253
------- ----------- ------------ ------------
Balance, December 31, 1993............. $60,011 $17,515,417 $ 36,890,286 $ 54,465,714
Stock issued for benefit plans
(26,488 shares)................... 265 271,176 -- 271,441
Stock options exercised (21,472
shares)........................... 214 176,808 -- 177,022
Employee stock purchase plan (29,840
shares)........................... 298 259,683 -- 259,981
10% stock dividend (606,262
shares)........................... 6,063 6,662,819 (6,668,882) --
Net Loss............................. -- -- (13,047,027) (13,047,027)
------- ----------- ------------ ------------
Balance, December 31, 1994............. $66,851 $24,885,903 $ 17,174,377 $ 42,127,131
Stock issued for benefit plans
(22,782 shares)................... 228 207,587 -- 207,815
Stock options exercised (2,493
shares)........................... 25 18,929 -- 18,954
Net Income........................... -- -- 524,600 524,600
------- ----------- ------------ ------------
Balance, March 31, 1995................ $67,104 $25,112,419 $ 17,698,977 $ 42,878,500
======= =========== ============ ============
</TABLE>

- ---------------
(1) $.01 par value.

See accompanying notes to Consolidated Financial Statements.

F-5
<PAGE> 48

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------------------ --------------------------
1992 1993 1994 1994 1995
------------ ------------ ------------ ------------ -----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash Flows from Operating Activities:
Net income (loss)............................... $ 4,084,760 $ 4,896,253 $(13,047,027) $(15,561,976) $ 524,600
Adjustments to reconcile net income to net cash
provided by operating activities --
Depreciation, depletion and amortization...... 4,906,029 7,300,967 7,904,801 1,688,938 2,168,229
Deferred income taxes......................... 468,097 1,199,057 963,324 398,935 126,493
Earned interests from limited partnerships and
joint ventures.............................. (1,692,331) (3,308,623) -- -- --
Deferred revenue amortization related to
production payment.......................... (1,666,390) (2,304,080) (1,993,863) (570,629) (464,731)
Impairment of investment in drilling tool
subsidiary.................................. 627,835 -- -- -- --
Cumulative effect of change in accounting
principle................................... (915,000) -- 16,772,698 16,772,698 --
Other......................................... 530,492 49,865 105,180 25,830 27,723
Change in assets and liabilities -- (Increase)
decrease in accounts receivable............. (398,676) (412,960) (762,789) (625,829) 27,181
Increase in accounts payable and accrued
liabilities, excluding income taxes
payable..................................... 204,602 110,324 142,883 457,909 522,280
Increase (decrease) in income taxes payable... 199,662 (292,463) 309,307 94,095 32,322
------------ ------------ ------------ ------------ -----------
Net Cash Provided by Operating
Activities.............................. 6,349,080 7,238,340 10,394,514 2,679,971 2,964,097
------------ ------------ ------------ ------------ -----------
Cash Flows from Investing Activities:
Additions to property and equipment............. (34,401,410) (24,229,103) (34,531,180) (4,042,728) (5,744,576)
Proceeds from the sale of property and
equipment..................................... 14,303,800 157,972 861,073 -- --
Proceeds from volumetric production payment..... 13,790,000 -- -- -- --
Net cash received (distributed) as operator of
oil and gas properties........................ 2,836,149 (2,556,483) (229,351) 1,264,268 (4,219,442)
Property acquisition costs (incurred on behalf
of) reimbursed by partnerships and joint
ventures...................................... 14,726,897 (10,252,142) (1,408,031) (11,310,786) 4,245,278
Limited partnership formation and marketing
costs......................................... (1,089,614) (103,871) -- (381,779) (170,549)
Prepaid drilling costs.......................... -- (1,100,076) -- 780,217 (60,245)
Other........................................... (35,117) (98,437) (25,320) (7,263) (16,068)
------------ ------------ ------------ ------------ -----------
Net Cash Provided by (Used in) Investing
Activities.............................. 10,130,705 (38,182,140) (35,332,809) (13,698,071) (5,965,602)
------------ ------------ ------------ ------------ -----------
Cash Flows from Financing Activities:
Proceeds from long-term debt.................... -- 28,750,000 -- -- --
Net proceeds from (payments of) short-term bank
borrowings.................................... (23,380,000) 2,650,000 24,579,000 11,350,000 3,321,000
Net proceeds from issuances of common stock..... 6,536,170 288,175 708,444 7,750 226,769
Payment of debt issuance costs.................. -- (1,425,000) -- -- --
------------ ------------ ------------ ------------ -----------
Net Cash Provided by (Used in) Financing
Activities.............................. (16,843,830) 30,263,175 25,287,444 11,357,750 3,547,769
------------ ------------ ------------ ------------ -----------
Net Increase (Decrease) in Cash and Cash
Equivalents..................................... $ (364,045) $ (680,625) $ 349,149 $ 339,650 $ 546,264
------------ ------------ ------------ ------------ -----------
Cash and Cash Equivalents at Beginning of
Period.......................................... 1,681,019 1,316,974 636,349 636,349 985,498
------------ ------------ ------------ ------------ -----------
Cash and Cash Equivalents at End of Period........ $ 1,316,974 $ 636,349 $ 985,498 $ 975,999 $ 1,531,762
============ ============ ============ ============ ===========
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for interest, net of
amounts capitalized............................. $ 93,869 $ 605,063 $ 1,691,400 $ 111 $ --
Cash paid during period for income taxes.......... $ 850,000 $ 756,761 $ 97,200 $ 11,951 $ 3,019
</TABLE>

See accompanying notes to Consolidated Financial Statements.

F-6
<PAGE> 49

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

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"). The Company's investments in associated oil and
gas partnerships and its joint ventures are accounted for using the
proportionate consolidation method, whereby the Company's proportionate share of
each entity's assets, liabilities, revenues, and expenses is included in the
appropriate classifications in the consolidated financial statements.
Intercompany balances and transactions have been eliminated in preparing the
consolidated statements. Certain reclassifications have been made to prior year
amounts to conform to the current year presentation.

UNAUDITED INTERIM CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

The interim consolidated financial statements as of March 31, 1995 and for
the three months ended March 31, 1995 and 1994 and notes thereto are unaudited.
In the opinion of management, these interim financial statements include all
adjustments necessary for a fair presentation and all such adjustments are of a
normal recurring nature. Results of the interim periods are not necessarily
indicative of the results for the entire year.

PROPERTY AND EQUIPMENT

For financial reporting purposes, 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 extraordinary
transactions. Instead, the proceeds from the sale of oil and gas properties are
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, 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, 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. 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.

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

F-7
<PAGE> 50

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

properties using current prices, discounted at 10%, and the lower of cost or
fair value of unproved properties, adjusted for related income tax effects.

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 Convertible
Subordinated Debentures in June 1993 have been capitalized and are being
amortized over the life of the Debentures, which mature on June 30, 2003. The
balance at March 31, 1995, is net of accumulated amortization of $182,768.

LIMITED PARTNERSHIPS AND JOINT VENTURES

The Company forms 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.

Under the Swift Depositary Interests limited partnership offering ("SDI
Offering") which commenced in March 1991, the Company receives a reimbursement
of certain costs and a fee, both payable out of revenues. The Company bears all
front-end costs of the offering and partnership formations for which it receives
an interest in the partnerships. Prior to 1994, the Company recognized as
revenue fees (earned interests) received in the form of additional interests in
producing oil and gas properties acquired by these entities. As described in
Note 2, effective January 1, 1994, the Company changed its revenue recognition
policy for earned interests and under its newly adopted policy, will no longer
recognize earned interests as revenue.

The Company acquires and transfers producing oil and gas properties to the
entities 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 are reduced by net operating revenues from the effective date of the
acquisition to the date of transfer to the entities. Such net operating revenue
amounts totaled approximately $4,100,000, $3,200,000, and $2,600,000 in 1994,
1993, and 1992, respectively.

Certain designated oil and gas properties acquired in advance of formation
of partnerships or joint ventures and held by the Company pending resale to
those partnerships or joint ventures are classified as "Producing oil and gas
properties held for transfer."

Commencing September 15, 1993, the Company began offering, on a private
placement basis, general and limited partnership interests in Swift Energy
Drilling Ventures ("SEDV Offering"), a series of limited partnerships to be
formed, and under which approximately $9,000,000 had been raised through March
31, 1995. As managing general partner, the Company pays for all front-end costs
incurred in connection with this offering, for which the Company receives an
interest in the partnerships. The proceeds are to be invested in development
drilling (approximately 50%) and exploratory drilling (approximately 25%), with
the remaining 25% dependent upon the results of the initial drilling activities.
The first three partnerships closed December 8, 1993, July 18, 1994, and March
15, 1995. The Company anticipates formation of at least one additional SEDV
partnership in 1995.

Costs of syndication, registration, and qualification of the SDI and SEDV
limited partnerships incurred by the Company have been deferred. Under the
current SDI and SEDV limited partnership offering, selling

F-8
<PAGE> 51

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

and formation costs borne by the Company serve as the Company's general partner
contribution to such partnerships.

HEDGING ACTIVITIES

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 in
oil and gas sales revenue and is not significant for any year presented.

INCOME (LOSS) PER SHARE

Primary income (loss) per share has been computed using the weighted
average number of common shares outstanding during the respective periods. Stock
options and warrants outstanding do not have an effect on primary income (loss)
per share. The Company's Convertible Subordinated Debentures are not common
stock equivalents for the purpose of computing primary income (loss) per share.

Primary income (loss) per share has been retroactively restated in all
periods presented to give recognition to an equivalent change in capital
structure as a result of a 10% stock dividend. On September 6, 1994, the Company
declared a 10% stock dividend to shareholders of record on September 19, 1994,
which was distributed on September 29, 1994, resulting in an additional 606,262
shares being issued.

The calculation of fully diluted income (loss) per share assumes conversion
of the Company's Convertible Subordinated Debentures as of the beginning of the
period 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. The conversion price of the Convertible
Subordinated Debentures was revised to reflect the 10% stock dividend declared
September 6, 1994. The original conversion price was $13.50 per common share and
the revised conversion price per common share is $12.27. Fully diluted income
(loss) per share has also been retroactively restated for all periods presented
to give effect to the resulting conversion price revision stemming from the 10%
stock dividend. The weighted average number of shares used in the computation of
fully diluted per share amounts were 9,053,736, 7,797,660, and 6,135,044 for the
respective years ended December 31, 1994, 1993, and 1992, and 8,981,799 for the
three-month period ended March 31, 1994. For the three-month period ended March
31, 1995, such amounts were antidilutive.

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. Prior to the adoption of SFAS No. 109, the Company accounted for income
taxes using Accounting Principles Board Opinion No. 11.

Income taxes for the interim periods have been provided using the estimated
annualized effective tax rate.

DEFERRED REVENUES

In May 1992, as discussed in Note 10 "Oil and Gas Producing Activities,"
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
terms of the production payment agreement, the Company continues to own the
properties purchased but is required to deliver a minimum quantity of
hydrocarbons produced from the properties (meeting certain quality and heating
equivalent requirements) over a specified period. Since

F-9
<PAGE> 52

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

entering into this agreement, the Company has met all scheduled deliveries. 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.

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. Noncash investing
activities for the year ended December 31, 1993, included approximately
$27,100,000 associated with producing oil and gas acquisitions that were paid
for in early 1994. Of this amount, approximately $5,100,000 related to property
acquisitions made for the Company's own account. See Note 10 "Oil and Gas
Producing Activities" for further discussion.

2. CHANGE IN ACCOUNTING PRINCIPLE

In the fourth quarter of 1994, the Company changed its revenue recognition
policy for earned interests, effective January 1, 1994. Under the Company's
newly adopted method of accounting for earned interests, such amounts will not
be recognized as income, thereby reducing the Company's investment in oil and
gas property. This change was made as the result of a transition in the
Company's current business activities and changes in the oil and gas limited
partnership syndication markets. The Company feels the change in policy results
in more comparable financial statements in relation to its current business
focus and in comparison to its current peers and competitors in the oil and gas
exploration and production industry.

The current year effect of the change was to increase income before
cumulative effect of change in accounting principle by approximately $1,047,000
or $.16 per share. This current year increase was a result of the decrease in
current year depletion expense more than offsetting the decrease in revenues as
a result of not recognizing earned interests. The cumulative effect of this
change in accounting principle resulted in an adjustment of $16,772,698 or
$(2.52) per share (after reduction for income taxes of $8,640,481), to
retroactively apply the new method, thereby reducing net income in 1994. See
Note 10 to the Company's Consolidated Financial Statements for the effect this
change had on oil and gas properties and accumulated depreciation, depletion and
amortization. The pro forma amounts shown on the income statement have been
adjusted for the effect of retroactive application, had the new method been in
effect during the periods presented.

3. PROVISION FOR INCOME TAXES

In the fourth quarter of 1992, the Company elected to adopt SFAS No. 109,
"Accounting for Income Taxes." The adoption was effective beginning January 1,
1992, and accordingly the cumulative effect of this change resulted in an
increase in net income for 1992 of $915,000 or $.15 per share.

The Omnibus Budget Reconciliation Act of 1993 (the "Act") was enacted on
August 10, 1993. The Act contains several changes to federal income tax
provisions, including an increase in the highest corporate tax rate from 34% to
35%, for companies with taxable income in excess of $10,000,000. The effect of
the Act on income tax expense for the year ended December 31, 1993, and the
Company's net deferred tax liability was not material.

F-10
<PAGE> 53

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

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

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1992 1993 1994
----------- ----------- ----------
<S> <C> <C> <C>
Current...................................... $ 1,049,662 $ 533,298 $ 148,834
Deferred..................................... 468,097 1,199,057 963,324
----------- ----------- ----------
Total........................................ $ 1,517,759 $ 1,732,355 $1,112,158
=========== =========== ==========
</TABLE>

There are differences between income taxes computed using the statutory
rate (34% for 1994, 1993, and 1992) and the Company's effective income tax rates
(23%, 26.1%, and 32.4% for 1994, 1993, and 1992, 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>
1992 1993 1994
----------- ----------- ----------
<S> <C> <C> <C>
Income taxes computed at Federal statutory
rate....................................... $ 1,593,756 $ 2,253,727 $1,644,862
State tax provisions, net of Federal
benefits................................... 44,880 149,002 46,525
Nonconventional fuel source credit........... (211,066) (553,651) (435,016)
Depletion deductions in excess of basis...... (14,014) (98,596) (30,895)
Other, net................................... 104,203 (18,127) (113,318)
----------- ----------- ----------
Provision for income taxes................... $ 1,517,759 $ 1,732,355 $1,112,158
=========== =========== ==========
</TABLE>

The tax effects of significant temporary differences representing the net
deferred tax liability at December 31, 1994, 1993, and 1992 were as follows:

<TABLE>
<CAPTION>
1992 1993 1994
----------- ----------- ----------
<S> <C> <C> <C>
Deferred tax assets:
Alternative minimum tax credits............ $ 654,697 $ 786,774 $ 900,562
Other...................................... 76,736 231,292 7,112
----------- ----------- ----------
Total deferred tax assets.......... $ 731,433 $ 1,018,066 $ 907,674
Deferred tax liabilities:
Oil and gas properties..................... $11,217,376 $12,576,208 $4,811,886
Other...................................... 510,669 637,527 614,300
----------- ----------- ----------
Total deferred tax liabilities..... $11,728,045 $13,213,735 $5,426,186
----------- ----------- ----------
Net deferred tax liability(1)................ $10,996,612 $12,195,669 $4,518,512
=========== =========== ==========
</TABLE>

- ---------------
(1) This amount includes a current deferred tax liability amount of $34,726 for
1992 and current deferred tax asset amounts of $96,567 and $103,679 for 1993
and 1994.

The Company did not record any valuation allowances against deferred tax
assets at December 31, 1994, 1993, and 1992.

At December 31, 1994, the Company had an alternative minimum tax
carryforward of $900,562 indefinitely available to reduce future regular tax
liability to the extent it exceeds the related tentative minimum tax otherwise
due.

F-11
<PAGE> 54

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

4. SHORT-TERM BANK BORROWINGS

The Company had available, through a two-bank group, a revolving line of
credit of $35,000,000 at March 31, 1995, $29,000,000 at the end of 1994, and
$20,000,000 at the end of 1993 bearing interest at the bank's base rate plus
0.5% (9.5% at March 31, 1995, 9% at December 31, 1994, and 6.5% at December 31,
1993), secured by the Company's interests in certain oil and gas properties and
general partner interests. This facility also allows, at the Company's option,
draws which bear interest for specific periods at the London Interbank Offered
Rate ("LIBOR") plus 2.25%. Of the $24,600,000 balance outstanding at March 31,
1995, $15,000,000 was at the LIBOR plus 2.25% rate (8.49%). At December 31,
1994, $14,000,000 of the $18,600,000 outstanding was at the LIBOR plus 2.25%
rates (7.875% on $3,000,000), (8.1875% on $6,000,000), and (8.5% on $5,000,000).
The outstanding amounts under this facility at March 31, 1995 ($24,600,000) and
at December 31, 1994 ($18,600,000) were borrowed primarily to fund the advance
purchase of producing properties on behalf of limited partnerships and/or joint
ventures to be subsequently reimbursed and to fund the Company's working capital
and capital expenditures needs. The $2,650,000 outstanding amount under this
facility at December 31, 1993, was primarily borrowed for the same purposes.

The terms of the revolving line of credit include, among other
restrictions, a limitation on the level of cash dividends (not to exceed
$424,000 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. The Company
presently intends to continue a policy of using retained earnings for expansion
of its business. As of March 31, 1995, the Company was in compliance with the
provisions of these agreements. The revolving line of credit extends through May
1, 1996.

During 1993, the Company also had available with the same two-bank group a
line of credit for producing oil and gas property acquisitions, to be secured by
producing oil and gas properties acquired and held for transfer. There were no
outstanding amounts under this facility at December 31, 1993. This facility was
terminated on January 18, 1994 at the request of the Company.

On June 21, 1994, the Company entered into a new Acquisition Advance
Agreement with the same two-bank group, bearing interest at the greater of (a)
the bank's base rate plus 1% (10% at March 31, 1995 and 9.5% at December 31,
1994) or (b) the Federal Funds rate plus 1.5%, to be secured by producing oil
and gas properties acquired and held for transfer. The outstanding amounts under
this facility at March 31, 1995 ($950,000) and at December 31, 1994 ($3,629,000)
had been borrowed under this agreement to fund the advance purchase of producing
properties on behalf of limited partnerships and/or joint ventures to be
subsequently reimbursed. This credit agreement expired June 15, 1995.

The Company's third credit facility is an amended and restated revolving
line of credit with the lead bank for $5,000,000, bearing interest at the bank's
base rate (9% at March 31, 1995, 8.5% at December 31, 1994, and 6% at December
31, 1993), secured by certain Company receivables. There were no outstanding
amounts under this facility at December 31, 1993. At both March 31, 1995 and
December 31, 1994, $5,000,000 was outstanding under this facility. This credit
facility extends through May 1, 1996.

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 fee
on the Acquisition Advance Agreement is .5% of the amount of the advance. The
aggregate amounts of commitment fees paid by the Company were $23,000 for the
first three months of 1995, $150,000 in 1994, and $112,000 in 1993.

F-12
<PAGE> 55

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

5. LONG-TERM DEBT

The Company's long-term debt consists of $28,750,000 of 6.5% Convertible
Subordinated Debentures ("Debentures"). The Debentures were issued on June 30,
1993, and will mature on June 30, 2003. The Debentures are convertible into
common stock of the Company by the holders at any time prior to maturity at a
conversion price of $12.27 per share, subject to adjustment upon the occurrence
of certain events. The conversion price reflects an adjustment of the original
conversion price of $13.50 per share to reflect the 10% stock dividend declared
September 6, 1994, and distributed September 29, 1994. Interest on the
Debentures is payable semi-annually on June 30 and December 31, commencing with
the payment made at December 31, 1993. After June 30, 1997 (or in certain
circumstances after June 30, 1996), the Debentures are redeemable for cash at
the option of the Company, with certain restrictions, at 104.55% of principal,
declining to 100.65% in 2002. 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 Debentures will have the right to require the Company to repurchase the
Debentures 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.

Interest expense on the Debentures, including amortization of debt issuance
costs, totaled $494,910 for the three-month period ending March 31, 1995.
Interest expense on the Debentures, including amortization of debt issuance
costs, totaled $1,973,931 for 1994. Interest expense on the Debentures,
including amortization of debt issuance costs, totaled $984,239 for the
six-month period ending December 31, 1993.

6. COMMITMENTS AND CONTINGENCIES

Total rental and lease expenses charged to earnings before reimbursements
were $1,159,673 in 1994, $1,155,564 in 1993, and $1,005,276 in 1992. The
Company's remaining minimum annual obligations under non-cancellable operating
lease commitments are $375,917 for 1995, $66,825 for 1996, $41,136 for 1997,
$37,555 for 1998, and $6,259 thereafter.

As of March 31, 1995, the Company is the managing general partner of 95
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. These
partnerships' liabilities generally consist of third party borrowings from time
to time to fund capital expenditures for development of oil and gas properties,
and will be repaid from oil and gas sales proceeds of the partnerships in future
periods.

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
actions will not have a material adverse effect on the financial position or
results of operations of the Company.

The Company extends credit 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 Company's overall credit risk. However, management
believes that the risk is mitigated by the size, reputation, and nature of the
companies to which they extend credit. In addition, the Company generally does
not require collateral or other security to support customer receivables.

7. STOCKHOLDERS' EQUITY

COMMON STOCK

On September 6, 1994, the Company declared a 10% stock dividend to
shareholders of record on September 19, 1994, which was distributed on September
29, 1994. The transaction was valued based on the

F-13
<PAGE> 56

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

closing price ($11.00) of the Company's common stock on the New York Stock
Exchange on September 6, 1994. As a result of the issuance of 606,262 shares of
the Company's common stock as a dividend, retained earnings were reduced by
$6,668,882, with the common stock and additional paid-in capital accounts
increased by the same amount. Primary and fully diluted income (loss) per share
has been restated for all periods to reflect the effect of the stock dividend.

STOCK OPTIONS AND WARRANTS

The Company has an employee option plan under which incentive stock options
and other options and awards may be granted to employees to purchase shares of
common stock and a nonqualified stock option plan under which non-employee
members of the Company's Board of Directors may be granted options to purchase
shares of common stock. The 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. No accounting entries are required until
the stock options are exercised, at which time the option price is credited to
the common stock and additional paid-in capital accounts. The effect of the 10%
stock dividend increased the number of shares and decreased the price according
to the respective agreements.

The following is a summary of stock options under these plans:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------
1993 1994
---------------- ----------------
<S> <C> <C>
Options outstanding, beginning of period.......... 698,525 899,650
Options granted................................... 216,400 202,760
Options terminated................................ (1,875) (20,658)
Options exercised................................. (13,400) (21,472)
Options adjusted for stock dividend............... -- 106,640
------- ---------
Options outstanding, end of period................ 899,650 1,166,920
======= =========
Options exercisable, end of period................ 375,270 546,172
======= =========
Options available for future grant, end of
period.......................................... 152,281 498,909
======= =========
Option price range:
Options granted................................. $ 10.50 - $11.625 $ 9.091 - $ 10.25
Options terminated.............................. $ 7.75 - $10.75 $ 7.045 - $ 12.386
Options exercised............................... $ 6.75 - $10.75 $ 7.045 - $ 9.773
Options outstanding, end of period.............. $ 6.00 - $13.625 $ 5.455 - $ 12.386
</TABLE>

The Company also has granted certain stock options to individuals who are
neither employees, officers, nor directors, for specific services rendered to
the Company. At December 31, 1994, options granted in 1991 covering 68,750
shares at $9.773 (after adjustment for the September 1994 stock dividend) remain
outstanding. During the three years ended December 31, 1994, the only other
activity has been the cancellation of 5,350 option shares in 1993.

The Company also has a plan which 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, with the first
year of the plan commencing 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

F-14
<PAGE> 57

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

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. During 1994, the Company issued 29,840 shares under this plan at a
price of $8.71. As of December 31, 1994, there were 517,176 shares available for
issuance under this plan. There are no charges or credits to income in
connection with this plan.

8. RELATED-PARTY TRANSACTIONS

In 1991, Swift purchased all of the capital stock of a marketing company
from a former significant stockholder and director of Swift and a separate
minority interest owner ("sellers"). This acquired company has marketing
responsibilities for the current and future Swift limited partnership offerings.
The sellers entered into a management agreement to manage and supervise the
sales activities of the Swift marketing entity under which they provided
services and for which they were reimbursed certain fixed expenses and
compensated on a sliding scale basis, dependent upon the number of partnership
units sold. Management fees paid under this management agreement totaled
approximately $21,000, $240,000, and $335,000 in 1994, 1993, and 1992,
respectively. This arrangement was terminated in January 1994, whereby Swift
will now assume all such management responsibilities.

The Company is the operator of a substantial number of properties owned by
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
$4,400,000, $4,200,000, and $3,900,000, in 1994, 1993, and 1992, 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
$1,400,000, $2,500,000, and $900,000 in 1994, 1993, and 1992, respectively.

During 1992, the Company sold certain oil and gas properties, previously
held in "producing oil and gas properties held for transfer" and the Company's
oil and gas property accounts, to partnerships formed under the SDI offering.
The properties were sold to the limited partnerships for proceeds equal to the
properties' fair market value, $30,500,000, as determined by an independent
petroleum engineer. Approximately $14,000,000 of the total proceeds from the
sale were attributed to properties held in the Company's oil and gas property
accounts with the remainder attributable to "producing oil and gas properties
held for transfer." The $14,000,000 of proceeds attributable to properties held
in the Company's oil and gas property account were treated as a reduction of the
Company's proved oil and gas properties with no gain or loss recognized in
accordance with the full-cost accounting method.

9. INVESTMENT IN PET-TECH TOOLS, INC.

The Company, together with another 50% co-venturer, owned Pet-Tech Tools,
Inc. ("Pet-Tech"), a company formed in 1982 to manufacture and lease a drilling
safety tool. In the fourth quarter of 1992, as a result of the continuing
depressed state of the domestic oil and gas drilling services industry, the
Company decided to impair its entire 50% investment in Pet-Tech. The $627,835
effect of that impairment has been reflected in the statements of income for
1992 included herein. The Company's investment in Pet-Tech consisted primarily
of advances and Debentures.

F-15
<PAGE> 58

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

10. OIL AND GAS PRODUCING ACTIVITIES

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>
DECEMBER 31,
-----------------------------
1993 1994
------------ ------------
<S> <C> <C>
Oil and Gas Properties:
Proved................................................ $106,251,713 $ 93,368,795(1)
Unproved (not being amortized)........................ 7,932,557 14,805,479
------------ ------------
114,184,270 108,174,274
Accumulated Depreciation, Depletion and Amortization.... (24,527,693) (19,758,662)(1)
------------ ------------
$ 89,656,577 $ 88,415,612
============ ============
</TABLE>

- ---------------
(1) The effect of the 1994 change in accounting principle (see Note 2) was to
decrease proved property costs by $37,773,087 and accumulated depreciation,
depletion and amortization by $12,359,908.

Of the $14,805,479 of net unproved property costs (primarily seismic and
lease acquisition costs) at December 31, 1994, being excluded from the
amortizable base, $8,232,207 was incurred in 1994, $3,293,351 was incurred in
1993, $911,060 was incurred in 1992, and $2,368,861 was incurred in prior years.
The Company expects it will complete its evaluation of the properties
representing the majority of these costs within the next two to three years.

CAPITAL EXPENDITURES

The following table sets forth capital expenditures related to the
Company's oil and gas operations:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1992 1993 1994
----------- ----------- -----------
<S> <C> <C> <C>
Acquisition of proved properties, including
earned interests in limited partnerships
and joint ventures(1)..................... $28,686,874 $21,832,157 $13,078,242
Lease acquisitions(2),(3)................... 2,886,024 5,388,243 9,905,237
Exploration................................. 527,761 2,195,473 4,003,400
Development................................. 3,034,513 3,164,803 5,637,285
----------- ----------- -----------
Total(4).......................... $35,135,172 $32,580,676 $32,624,164
=========== =========== ===========
</TABLE>

- ---------------
(1) Earned interests amounts included in 1992 and 1993, respectively, are
$1,692,331 and $3,308,623. There are no earned interests in 1994.

(2) Lease acquisitions for 1993 and 1994 include expenditures of $1,032,656 and
$2,973,971, respectively, relating to the Company's initiatives in Russia
and include 1993 and 1994 expenditures of $456,681 and $356,136,
respectively, relating to initiatives in Venezuela.

(3) These amounts are actuals 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 1992, 1993, and 1994,
respectively, were $2,155,526, $4,198,429, and $3,032,315, respectively.

F-16
<PAGE> 59

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

(4) Includes capitalized general and administrative costs directly associated
with the acquisition, development, and exploration efforts of approximately
$1,800,000, $8,300,000, and $5,800,000 in 1992, 1993, and 1994. In addition,
total includes $466,460, $389,352, and $766,572 in 1992, 1993, and 1994,
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,
-------------------------------------------
1992 1993 1994
----------- ----------- -----------
<S> <C> <C> <C>
Oil and gas sales........................... $12,420,222 $15,535,671 $19,802,188
Production costs............................ (3,934,294) (4,540,290) (5,639,630)
Depreciation, depletion and amortization.... (4,685,780) (7,067,636) (7,590,877)
----------- ----------- -----------
3,800,148 3,927,745 6,571,681
Income taxes................................ (1,230,439) (1,025,141) (1,511,487)
----------- ----------- -----------
Results of producing activities............. $ 2,569,709 $ 2,902,604 $ 5,060,194
=========== =========== ===========
Amortization per physical unit of production
(equivalent Mcf of gas)................... $ 0.83 $ 0.96 $ 0.79
=========== =========== ===========
</TABLE>

PROPERTY PURCHASE AND PRODUCTION PAYMENT AGREEMENT

In May 1992, the Company purchased from a subsidiary of Manville
Corporation ("Manville") additional interests in certain wells in McMullen
County, Texas, in which the Company had owned interests for over three years.
The funds for this purchase were provided by the Company's sale of a volumetric
production payment in the Manville properties to Enron Reserve Acquisition Corp.
("Enron") for net proceeds of $13,790,000. These proceeds were recorded as
deferred revenues and are amortized as the required deliveries are made. Under
the production payment agreement, the Company continues to own the properties
purchased from Manville, but 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 in 1994, 1993 and 1992), the Company receives all proceeds from
sale of such excess gas at current market prices, plus the proceeds from sale of
oil or condensate. During 1992, 1993, 1994, and the three-month period ended
March 31, 1995, the Company met all scheduled deliveries to Enron under this
production payment agreement.

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. The Company will receive a
minimum 5% net profits interest from the sale of hydrocarbon products from the
fields for providing managerial, technical and financial support to Senega
limited to an initial budgeted capital expenditure of less than $5,000,000. At
December 31, 1994 and March 31, 1995, respectively, the Company's investment in
Russia was approximately $4,010,000 and $4,540,000 and is included in the
unproved properties portion of oil and gas properties.

F-17
<PAGE> 60

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

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 on the Quiriquire Unit
located in Northeastern Venezuela. Swift (together with a minority interest
holder) was one of six bidders on the Quiriquire Unit. The Company did not win
the bid for the Quiriquire Unit; however, other fields and opportunities are
continuing to be evaluated in Venezuela. At December 31, 1994 and March 31,
1995, respectively, the Company's investment in Venezuela was approximately
$810,000 and $880,000 and is included in the unproved properties portion of oil
and gas properties net of impairments of $45,668.

ACQUISITION OF PROPERTIES BY SWIFT

During the fourth quarter of 1993, the Company acquired approximately
$43,300,000 of producing oil and gas properties in five separate acquisitions.
Approximately $32,700,000 of the properties were transferred to limited
partnerships formed under the Company's SDI offering, and approximately
$10,600,000 of the properties were retained by the Company for its own account.

During the second quarter of 1994, the Company acquired approximately
$18,100,000 of producing oil and gas properties in a single acquisition
transaction. Approximately $12,700,000 of the properties were transferred to
limited partnerships formed under the Company's SDI offering, approximately
$1,900,000 of the properties were retained by the Company for its own account
and the remaining amount of approximately $3,500,000 is included as a current
asset in "producing oil and gas properties held for transfer" at December 31,
1994.

SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)

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 17, 1995, is set forth as an exhibit to the Form
10-K Report for the year ended December 31, 1994, 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:

F-18
<PAGE> 61

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

Estimates of Proved Reserves

<TABLE>
<CAPTION>
OIL AND
NATURAL GAS CONDENSATE
(MCF) (BBLS)
----------- ----------
<S> <C> <C>
Proved reserves as of December 31, 1991..................... 36,685,881 1,950,209
Revisions of previous estimates(1)........................ 2,702,911 88,141
Purchases of minerals in place............................ 35,042,474 1,606,324
Sales of minerals in place................................ (31,083,750) (500,518)
Extensions, discoveries and other additions............... 1,116,925 41,393
Production(2)............................................. (2,826,341) (283,928)
----------- ---------
Proved reserves as of December 31, 1992(3).................. 41,638,100 2,901,621
Revisions of previous estimates(1)........................ (1,800,178) (200,906)
Purchases of minerals in place............................ 17,892,709 1,429,463
Sales of minerals in place................................ (61,996) (12,555)
Extensions, discoveries and other additions............... 10,634,805 477,932
Production(2)............................................. (3,840,635) (324,486)
----------- ---------
Proved reserves as of December 31, 1993(3).................. 64,462,805 4,271,069
Revisions of previous estimates(1)........................ (10,570,138) (714,246)
Purchases of minerals in place............................ 8,136,270 790,523
Sales of minerals in place................................ (881,770) (34,834)
Extensions, discoveries and other additions............... 20,556,953 707,811
Production(2)............................................. (5,440,156) (467,056)
----------- ---------
Proved reserves as of December 31, 1994(3).................. 76,263,964 4,553,267
=========== =========
Proved developed reserves,
December 31, 1991......................................... 26,712,921 1,512,264
December 31, 1992......................................... 32,955,080 2,082,885
December 31, 1993......................................... 50,936,942 3,110,505
December 31, 1994......................................... 46,406,448 3,209,387
</TABLE>

- ---------------
(1) 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, 1994, were
based upon $1.85 per Mcf and $15.09 per barrel of oil, compared to $2.50 per
Mcf and $12.87 per barrel of oil as of December 31, 1993.

(2) Natural gas production for 1992, 1993, and 1994 excludes 1,148,862,
1,581,206, and 1,358,375 Mcf, respectively, delivered under the Company's
volumetric production payment agreement.

(3) Proved reserves for these periods exclude quantities subject to the
Company's volumetric production payment agreement.

F-19
<PAGE> 62

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

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,
----------------------------------------------
1992 1993 1994
------------ ------------ ------------
<S> <C> <C> <C>
Future gross revenues.................... $155,111,299 $218,321,639 $211,210,430
Future production and development
costs.................................. (59,871,337) (75,769,590) (92,053,163)
------------ ------------ ------------
Future net cash flows before income
taxes.................................. 95,239,962 142,552,049 119,157,267
Future income taxes...................... (20,955,655) (26,303,502) (14,143,796)
------------ ------------ ------------
Future net cash flows after income
taxes.................................. 74,284,307 116,248,547 105,013,471
Discount at 10% per annum................ (27,701,313) (41,280,376) (38,541,504)
------------ ------------ ------------
Standardized measure of discounted future
net cash flows relating to proved oil
and gas reserves....................... $ 46,582,994 $ 74,968,171 $ 66,471,967
============ ============ ============
</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 carryforwards.

The estimates of cash flows and reserve 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 test" 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> 63

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

The following are the principal sources of change in the standardized
measure of discounted future net cash flows:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1992 1993 1994
------------ ----------- ------------
<S> <C> <C> <C>
Beginning balance........................... $ 37,174,904 $46,582,994 $ 74,968,171
------------ ----------- ------------
Revisions to reserves proved in prior
years --
Net changes in prices, production costs
and future development costs........... 431,415 (4,140,177) (21,326,677)
Net changes due to revisions in quantity
estimates.............................. 3,634,778 (2,860,642) (11,644,586)
Accretion of discount..................... 4,925,028 5,543,984 8,376,078
Other..................................... (2,965,631) (4,485,723) (5,631,646)
------------ ----------- ------------
Total revisions................... 6,025,590 (5,942,558) (30,226,831)

New field discoveries and extensions, net of
future production and development costs... 1,265,681 13,972,435 15,585,767
Purchases of minerals in place.............. 49,583,438 27,074,564 7,964,821
Sales of minerals in place.................. (44,346,750) (85,174) (574,651)
Sales of oil and gas produced, net of
production costs.......................... (6,819,538) (8,691,301) (12,168,695)
Previously estimated development costs
incurred.................................. 481,141 1,992,967 5,053,417
Net change in income taxes.................. 3,218,528 64,244 5,869,968
------------ ----------- ------------
Net change in standardized measure of
discounted future net cash flows.......... 9,408,090 28,385,177 (8,496,204)
------------ ----------- ------------
Ending balance.................... $ 46,582,994 $74,968,171 $ 66,471,967
============ =========== ============
</TABLE>

F-21
<PAGE> 64

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

11. QUARTERLY RESULTS (UNAUDITED)

The following table presents summarized quarterly financial information for
the years ended December 31, 1992, 1993, and 1994, and the three months ended
March 31, 1995:

<TABLE>
<CAPTION>
FULLY DILUTED
NET INCOME PRIMARY INCOME
INCOME BEFORE (LOSS) INCOME (LOSS) (LOSS)
REVENUES INCOME TAXES (AS RESTATED) PER SHARE(3) PER SHARE(3)
----------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
1992
First Quarter....... $ 3,452,071 $ 873,902 $ 1,491,775(2) $ 0.27 $ 0.27
Second Quarter...... 4,948,329 1,550,423 1,023,279 0.17 0.17
Third Quarter....... 5,760,656 2,039,670 1,346,182 0.21 0.21
Fourth Quarter...... 5,048,538 223,524 223,524 0.03 0.03
----------- ----------- ------------- ------- -------
Total....... $19,209,594 $ 4,687,519 $ 4,084,760 $ 0.67 $ 0.67
=========== =========== ============= ======= =======

1993
First Quarter....... $ 5,325,054 $ 1,411,809 $ 988,266 $ 0.15 $ 0.15
Second Quarter...... 6,012,174 1,743,606 1,220,524 0.19 0.19
Third Quarter....... 6,603,605 1,905,880 1,441,549 0.22 0.19
Fourth Quarter...... 6,191,820 1,567,313 1,245,914 0.19 0.17
----------- ----------- ------------- ------- -------
Total....... $24,132,653 $ 6,628,608 $ 4,896,253 $ 0.74 $ 0.70
=========== =========== ============= ======= =======

1994
First Quarter....... $ 6,138,535 $ 1,753,003(1) $ (15,561,976)(1) $ (2.36)(1) $ (2.36)(1)
Second Quarter...... 6,106,954(1) 1,462,980(1) 1,076,077(1) 0.16(1) 0.15(1)
Third Quarter....... 6,962,612 1,439,620(1) 1,130,398(1) 0.17(1) 0.16(1)
Fourth Quarter...... 6,167,191 182,226 308,474 0.05 0.05
----------- ----------- ------------- ------- -------
Total....... $25,375,292 $ 4,837,829 $ (13,047,027) $ (1.96) $ (1.96)
=========== =========== ============= ======= =======

1995
First Quarter....... $ 6,258,588 $ 676,434 $ 524,600 $ 0.08 $ 0.08
=========== =========== ============= ======= =======
</TABLE>

- ---------------
(1) In the fourth quarter of 1994, the Company changed its revenue recognition
policy for earned interests. See Note 2 "Change in Accounting Principle" for
further discussion. This change was effective beginning January 1, 1994,
and, accordingly, the cumulative effect of this change ($(16,772,698) or
$(2.52) per share) has been reflected in the first quarter of 1994, and the
first three quarters have been restated to reflect the basis of the newly
adopted accounting principle. Net Income, Primary Income Per Share, and
Fully Diluted Income Per Share were previously reported as $814,325, $0.14,
and $0.14, respectively, for the first quarter of 1994; $1,140,197, $0.19,
and $0.17, respectively, for the second quarter of 1994; and $768,161,
$0.12, and $0.12, respectively, for the third quarter of 1994.

(2) In the fourth quarter of 1992, the Company elected to adopt SFAS No. 109
which changed the accounting for deferred income taxes. The adoption is
effective beginning January 1, 1992, and, accordingly, the cumulative effect
of this change has been reflected in the first quarter of 1992. Net Income
and Primary Income Per Share, previously reported as $576,775 and $0.11,
respectively, have been restated. See Note 3, "Provision for Income Taxes"
for further discussion.

F-22
<PAGE> 65

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)

(3) Amounts prior to the fourth quarter of 1994 have been retroactively restated
to give recognition to an equivalent change in capital structure as a result
of the 10% stock dividend. See Note 1, "Summary of Significant Accounting
Policies-Income (Loss) Per Share" for further discussion.

Pro forma amounts assuming the new earned interest recognition policy is
applied retroactively:

<TABLE>
<CAPTION>
PRIMARY FULLY DILUTED
INCOME INCOME
NET INCOME PER SHARE PER SHARE
---------- --------- -------------
<S> <C> <C> <C>
1992
First Quarter.................................. $ 886,401 $0.16 $0.16
Second Quarter................................. 978,411 0.16 0.16
Third Quarter.................................. 1,401,953 0.21 0.21
Fourth Quarter................................. 463,086 0.07 0.07
---------- ----- -----
Total.................................. $3,729,851 $0.61 $0.61
========== ===== =====
1993
First Quarter.................................. $ 917,895 $0.14 $0.14
Second Quarter................................. 1,247,263 0.19 0.19
Third Quarter.................................. 1,113,049 0.17 0.15
Fourth Quarter................................. 1,044,271 0.16 0.15
---------- ----- -----
Total.................................. $4,322,478 $0.66 $0.63
========== ===== =====
1994
First Quarter.................................. $1,210,722 $0.18 $0.17
Second Quarter................................. 1,076,077 0.16 0.15
Third Quarter.................................. 1,130,398 0.17 0.16
Fourth Quarter................................. 308,474 0.05 0.05
---------- ----- -----
Total.................................. $3,725,671 $0.56 $0.56
========== ===== =====
1995
First Quarter.................................. $ 524,600 $0.08 $0.08
========== ===== =====
</TABLE>

F-23
<PAGE> 66

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

NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION IN CONNECTION WITH THIS OFFERING OTHER
THAN THOSE CONTAINED IN THIS PROSPECTUS AND, IF GIVEN OR MADE, SUCH INFORMATION
OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE
COMPANY OR THE UNDERWRITERS. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO
SELL OR A SOLICITATION OF AN OFFER TO BUY ANY OF THE SECURITIES OFFERED HEREBY
IN ANY JURISDICTION TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER IN
SUCH JURISDICTION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE
HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THE
INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE
HEREOF OR THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE SUCH
DATE.

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

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Available Information....................... 2
Defined Terms............................... 2
Prospectus Summary.......................... 3
Risk Factors................................ 7
Use of Proceeds............................. 10
Price Range of Common Stock and Dividend
Policy.................................... 11
Capitalization.............................. 12
Selected Consolidated Financial Data........ 13
Selected Oil and Gas Reserve and Operating
Data...................................... 14
Management's Discussion and Analysis of
Financial Condition and Results of
Operations................................ 15
Business and Properties..................... 22
Management.................................. 35
Principal Shareholders...................... 38
Description of Capital Stock................ 39
Underwriting................................ 40
Legal Matters............................... 41
Experts..................................... 41
Incorporation of Certain Information by
Reference................................. 42
Index to Consolidated Financial
Statements................................ F-1
</TABLE>

- ------------------------------------------------------------
- ------------------------------------------------------------
- ------------------------------------------------------------
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5,000,000 SHARES

(LOGO)

SWIFT ENERGY COMPANY

COMMON STOCK
--------------------

PROSPECTUS
--------------------
OPPENHEIMER & CO., INC.

MORGAN KEEGAN
& COMPANY, INC.

SOUTHCOAST CAPITAL
CORPORATION
JULY 26, 1995

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