Edgar Filing: SWIFT ENERGY CO

FILED PURSUANT TO RULE 424(b)(2)
REGISTRATION NO. 333-64692

PROSPECTUS SUPPLEMENT TO PROSPECTUS DATED JULY 23, 2001

1,500,000 Shares

[SWIFT LOGO]

Common Stock

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

Our common stock is listed on the New York Stock Exchange and Pacific Stock
Exchange under the symbol "SFY." The last reported sale price of our common
stock on the New York Stock Exchange on April 8, 2002 was $19.45 per share.

The underwriter has an option to purchase a maximum of 225,000 additional
shares from us to cover over-allotments of shares.

INVESTING IN OUR COMMON STOCK INVOLVES RISKS. SEE "RISK FACTORS" BEGINNING
ON PAGE S-10 OF THIS PROSPECTUS SUPPLEMENT AND ON PAGE 2 OF THE ACCOMPANYING
PROSPECTUS.

UNDERWRITING PROCEEDS TO
DISCOUNTS AND SWIFT ENERGY
PRICE TO PUBLIC COMMISSIONS COMPANY
---------------- ---------------- ----------------

Per Share....................................... $18.25 $0.50 $17.75
Total........................................... $27,375,000 $750,000 $26,625,000

Delivery of the shares of common stock will be made on or about April 12,
2002.

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved these securities or determined if this
prospectus supplement or the accompanying prospectus to which it relates is
truthful or complete. Any representation to the contrary is a criminal offense.

CREDIT SUISSE FIRST BOSTON

The date of this prospectus supplement is April 9, 2002

This document is in two parts. The first part is this prospectus
supplement, which describes the terms of the offering of common stock. The
second part is the accompanying prospectus, which gives more general
information, some of which may not apply to the common stock. In this prospectus
supplement, "Swift," "we," "us," and "our" refer to Swift Energy Company and its
subsidiaries, unless otherwise indicated.

YOU SHOULD RELY ONLY ON THE INFORMATION WE HAVE INCLUDED OR INCORPORATED BY
REFERENCE IN THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS. WE HAVE
NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH ADDITIONAL OR DIFFERENT INFORMATION.
IF YOU RECEIVE ANY UNAUTHORIZED INFORMATION, YOU MUST NOT RELY ON IT. WE ARE
OFFERING TO SELL THE COMMON STOCK ONLY IN STATES WHERE SALES ARE PERMITTED. YOU
SHOULD NOT ASSUME THAT THE INFORMATION WE HAVE INCLUDED IN THIS PROSPECTUS
SUPPLEMENT OR THE ACCOMPANYING PROSPECTUS IS ACCURATE AS OF ANY DATE OTHER THAN
THE DATE OF THIS PROSPECTUS SUPPLEMENT OR THE ACCOMPANYING PROSPECTUS OR THAT
ANY INFORMATION WE HAVE INCORPORATED BY REFERENCE IS ACCURATE AS OF ANY DATE
OTHER THAN THE DATE OF THE DOCUMENT INCORPORATED BY REFERENCE.

See the "Glossary of Terms" beginning on page S-54 for explanations of
abbreviations and terms used in this prospectus supplement.
------------------

TABLE OF CONTENTS

PROSPECTUS SUPPLEMENT

PAGE
----

SUMMARY............................... S-1
RISK FACTORS.......................... S-10
USE OF PROCEEDS....................... S-14
CAPITALIZATION........................ S-15
COMMON STOCK PRICE RANGE AND DIVIDEND
POLICY.............................. S-16
SELECTED HISTORICAL CONSOLIDATED
FINANCIAL DATA...................... S-17
NOTES TO SELECTED HISTORICAL
CONSOLIDATED FINANCIAL DATA......... S-18
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS....................... S-19

PAGE
----

BUSINESS AND PROPERTIES............... S-28
MANAGEMENT............................ S-45
DESCRIPTION OF EXISTING
INDEBTEDNESS........................ S-48
UNDERWRITING.......................... S-50
NOTICE TO CANADIAN RESIDENTS.......... S-51
LEGAL MATTERS......................... S-52
EXPERTS............................... S-53
OTHER MATTERS......................... S-53
GLOSSARY OF TERMS..................... S-54
CONSOLIDATED FINANCIAL
STATEMENTS.......................... F-1

PROSPECTUS

PAGE
----

ABOUT THIS PROSPECTUS................. 1
WHERE YOU CAN FIND MORE INFORMATION... 1
RISK FACTORS.......................... 2
FORWARD-LOOKING STATEMENTS............ 3
THE COMPANY........................... 4
RATIO OF EARNINGS TO FIXED
CHARGES............................. 4
USE OF PROCEEDS....................... 5

PAGE
----

DESCRIPTION OF DEBT SECURITIES........ 5
DESCRIPTION OF CAPITAL STOCK.......... 13
DESCRIPTION OF DEPOSITARY SHARES...... 17
DESCRIPTION OF WARRANTS............... 18
SELLING SHAREHOLDERS.................. 18
PLAN OF DISTRIBUTION.................. 19
LEGAL OPINIONS........................ 20
EXPERTS............................... 21

INCORPORATION OF ADDITIONAL DOCUMENTS BY REFERENCE

In addition to the documents referred to under "Where You Can Find More
Information" in the accompanying prospectus, this prospectus supplement
incorporates by reference our Annual Report on Form 10-K for the fiscal year
ended December 31, 2001 filed by us with the Securities and Exchange Commission.

SUMMARY

This summary highlights selected information from this prospectus
supplement and the accompanying prospectus, but may not contain all of the
information that is important to you. This prospectus supplement and the
accompanying prospectus include specifics of the offering of our common stock
and information about our business and financial data. Before making an
investment decision, we encourage you to read this prospectus supplement and the
accompanying prospectus, including the "Risk Factors" section in each
prospectus, and the documents we incorporate by reference. When we describe our
year end 2001 proved reserves on a pro forma basis, we are giving effect to our
January 2002 acquisition of an estimated 62.1 Bcfe of proved reserves at year
end 2001 in the TAWN fields in New Zealand and to our March 2002 acquisition of
an estimated 5.7 Bcfe of proved reserves at year end 2001 in the Rimu/Kauri area
in New Zealand from Antrim Oil and Gas Limited. Our actual year end 2001 proved
reserves prior to the above acquisitions were 645.8 Bcfe. Unless otherwise
indicated, this prospectus supplement assumes no exercise of the underwriter's
over-allotment option.

ABOUT SWIFT

Swift Energy Company engages in developing, exploring, acquiring, and
operating oil and gas properties, with a focus on onshore oil and natural gas
reserves in Texas and Louisiana and onshore oil and natural gas reserves in New
Zealand. At year end 2001, on a pro forma basis, we had estimated proved
reserves of 713.6 Bcfe, concentrated 48% in Texas, 25% in Louisiana and 24% in
New Zealand. Approximately 52% of these reserves are natural gas. For the 12
months ended December 31, 2001, we generated EBITDA of $136.8 million.

The following table of pro forma proved reserves highlights our core areas:

PRO FORMA PROVED RESERVES
AS OF YEAR END 2001
-----------------------------------
PROVED PERCENT OF
AREA LOCATION RESERVES (BCFE) PROVED RESERVES
---- -------- ----------------- ---------------

AWP Olmos........................... South Texas 207.5 29%
Masters Creek....................... Central Louisiana 104.8 15%
Brookeland.......................... East Texas 59.1 8%
Lake Washington..................... South Louisiana 72.5 10%
Rimu/Kauri.......................... New Zealand 107.6 15%
TAWN................................ New Zealand 62.1 9%
Other Domestic..................................... 100.0 14%
----- ----
Total......................................... 713.6 100%

We have a well-balanced portfolio of oil and gas properties and prospects.
The AWP Olmos, Lake Washington and New Zealand areas are characterized by
long-lived reserves that we expect to produce steadily over a long period of
time. The Masters Creek and Brookeland areas are characterized by shorter-lived
reserves with high initial rates of production that decline more rapidly. Based
on 2001 year end domestic proved reserves and 2001 production, our domestic
properties had an estimated average reserve life of 12.3 years. An independent
engineering firm's report in late 2001 estimates the Rimu/Kauri development area
to have a 25-30 year life. In addition to our core areas, we have a number of
emerging growth areas that may become additional core operating areas for us.
These growth areas are described in the "Business and Properties" section of
this prospectus supplement.

RECENT DEVELOPMENTS

Effective January 25, 2002, we expanded our core areas of operation by
acquiring interests in the four TAWN fields in New Zealand for approximately
$54.4 million. This acquisition, which also included significant infrastructure,
added proved developed reserves estimated to be 62.1 Bcfe at December 31, 2001,
all of which are proved producing and approximately 75% of which were classified
as natural gas. In March 2002, we purchased an additional 5% interest in our
permit 38719, where the Rimu and Kauri discoveries are located, from Antrim Oil
and Gas Limited for 220,000 shares of Swift common stock and
S-1

an effective date adjustment of approximately $530,000. This acquisition added
estimated reserves at year end 2001 of 5.7 Bcfe and increased our interest in
the permit to 95%. We also acquired Antrim's interest in another New Zealand
permit, which doubled our interest there to 15%. In addition, the construction
of our Rimu production station in New Zealand has been completed, which will
allow us to commence sale of production from our Rimu discovery in April 2002.

Since acquiring the Lake Washington field in March 2001, we have drilled a
total of eight wells in this field. The results of these wells support our
belief that there is additional reserves potential in multiple horizons located
around the salt dome in the center of the field ranging from depths of 1,300 to
18,000 feet. We have increased average monthly production in this field net to
Swift's interests from approximately 652 BOE per day when we acquired the field
to approximately 1,236 BOE per day during February 2002. The field currently
produces oil and natural gas liquids from 26 wells. As a result of our drilling
and remapping of the field and improvement in production levels, we are
currently focusing most of our 2002 domestic drilling budget on 20 development
wells and two exploratory wells in this field. We have 29 proved undeveloped
drilling locations in this field.

Our first quarter 2002 production increased over 17.5% to at least 12.1
Bcfe compared to production of 10.3 Bcfe during the first quarter of 2001. This
is also a 5% increase from 11.5 Bcfe produced during the fourth quarter of 2001.
Approximately 20% of the first quarter 2002 production comes from our new TAWN
core area in New Zealand.

On March 28, 2002, we received $7.5 million for our interest in the Samburg
project located in Western Siberia, Russia as a result of the sale by a third
party of its ownership in a Russian joint stock company, which owned and
operated this field. This cash payment will result in our recognition of a $7.5
million non-recurring pre-tax gain in the first quarter of 2002.

In late March and early April 2002, we entered into hedges covering a
portion of both our oil and natural gas production from May 2002 through
December 2002. These hedges are in the form of participating collars that are a
series of puts and calls, in which we will participate in 60% of the price
received above the cap. The counter party to the gas contracts is a member of
our bank syndicate under our credit facility and another member is the counter
party to the oil contracts. One group of oil collars has a floor of $20.00 per
Bbl and a cap of $27.52 per Bbl and covers 25,000 Bbl per month, and the other
group has a floor of $21.00 per Bbl and a cap of $27.65 and covers 20,000 Bbl
per month. One group of natural gas collars has a floor of $2.50 per MMBtu and a
cap of $4.21 per MMBtu and covers 200,000 MMBtu per month of our domestic
production, and the other group has a floor of $2.75 per MMBtu and a cap of
$4.55 per MMBtu and covers 80,000 MMBtu per month of our domestic production.
All of our New Zealand natural gas production for 2002 is contracted for at
defined prices under two long-term, reserve-based contracts.

We have filed a preliminary prospectus supplement dated April 1, 2002 with
the SEC relating to the offering of $150.0 million of senior subordinated notes
due 2012. These notes will be offered in a separate public offering pursuant to
a separate prospectus supplement. The indenture to be executed in conjunction
with the notes offering will contain substantially the same covenants as in our
existing 10.25% Senior Subordinated Notes Due 2009. See "Description of Existing
Indebtedness -- Senior Subordinated Notes Due 2009." Our notes offering is
expected to close in mid-April 2002, although we can provide no assurance in
this regard. This offering of common stock and the notes offering are not
conditioned upon each other.

On April 8, 2002, Moody's Investors Service announced it had assigned a B3
rating to our proposed $150.0 million senior subordinated notes offering. In
connection with this rating, Moody's announced further that it had changed the
rating of our existing $125.0 million of 10.25% senior subordinated notes due
2009 to B3, down from B2.

S-2

COMPETITIVE STRENGTHS AND BUSINESS STRATEGY

SUCCESSFUL TRACK RECORD

Our growth in reserves and production has resulted primarily from drilling
activities in our core areas combined with producing property acquisitions. Over
the five-year period ended December 31, 2001, our estimated proved reserves grew
from 258.7 Bcfe to 713.6 Bcfe on a pro forma basis. Over the same period, our
net cash provided by operations increased from $37.1 million to $139.9 million.
We believe that our experience in growing our reserves will be beneficial to us
as we continue to pursue our business strategy.

BALANCED APPROACH TO ADDING RESERVES

Over the past five years, we have spent an average of 11% of our capital
expenditure budget on exploration drilling, 51% on development activities, 19%
on proved property acquisitions and 14% on lease acquisitions. Currently our
2002 capital expenditures are focused on developing and producing long-lived
reserves in Lake Washington and New Zealand, which should flatten our overall
production decline curve, strengthen our ongoing production profile and extend
our average reserve life. Our strategy is to grow through drilling on our core
properties and in emerging growth areas when oil and gas prices are strong, with
a shift toward acquisitions when prices weaken. We believe this balanced
approach has resulted in our ability to grow reserves in a relatively low cost
manner, while participating in the upside potential of exploration. Over the
five-year period ended December 31, 2001, we replaced 302% of our production at
an average cost of $1.26 per Mcfe.

CONCENTRATED FOCUS ON CORE AREAS

Our concentration of reserves and our significant acreage positions in our
core areas allow us to realize economies of scale in drilling and production.
Our domestic operations are concentrated in Texas and Louisiana, where 96% of
our domestic reserves are located. All of our international operations are
currently concentrated in New Zealand. We enhance the value of these
concentrations by acting as operator of 95% of our proved reserves at year end
2001. Our focus in our core areas has enabled us to develop and utilize several
innovative technology applications adapted to those areas, which we believe
provide us with an advantage over our competitors.

ABILITY TO BUILD UPON OUR SUCCESSFUL DISCOVERIES AND ACQUISITIONS IN NEW ZEALAND

Our New Zealand activities provide us with long-term growth opportunities
and significant potential reserves in a country with stable political and
economic conditions, existing oil and gas infrastructure and favorable tax and
royalty regimes. In April 2001, we began selling oil from extended production
testing of our New Zealand wells. We expect production and gas processing
facilities will be operational in April 2002, a significantly faster period from
initial discovery to commercial production than similar projects previously
conducted in New Zealand of which we are aware. In January 2002, we acquired the
TAWN fields. From the closing of the TAWN acquisition on January 25, 2002
through March 25, 2002, these fields have generated average daily net production
of approximately 40 MMcfe. In our TAWN acquisition, we also acquired extensive
associated processing facilities and pipelines, which give us a competitive
advantage through infrastructure that complements our existing fields, providing
us with access to export terminals and markets and additional excess processing
capacity for both oil and natural gas. We also have prospective areas in New
Zealand outside of the Rimu/Kauri area that we will evaluate for drilling in the
future.

EXPERIENCED TECHNICAL TEAM

We employ 35 oil and gas professionals, including geophysicists,
petrophysicists, geologists, petroleum engineers and production and reservoir
engineers, who have an average of approximately 25 years of experience in their
technical fields and have been employed by Swift for an average of over 10
years. This level of expertise and experience, coupled with our employees'
longevity with Swift, gives us a unique in-house ability to apply advanced
technologies to our drilling, acquisition and production activities.

S-3

FINANCIAL DISCIPLINE

We practice a disciplined approach to financial management and have
historically maintained a strong capital structure that preserves our ability to
execute our business plan. Key components of our financial discipline include
maintaining a balanced capital budget, establishing leverage ratios that are
appropriate given the volatility of the oil and gas markets and
opportunistically accessing the capital markets. After giving effect to this
offering, as of December 31, 2001, our long-term debt would have comprised
approximately 41% of our total capitalization, or 45% after giving further
effect to the proposed notes offering. As of February 28, 2002, after the TAWN
acquisition in January 2002, and after giving effect to the Antrim acquisition
in March 2002 and this offering, our long-term debt would have comprised
approximately 48% of our total capitalization, which remains the same after
giving further effect to the proposed notes offering. Additionally, after
applying the net proceeds from this offering to reduce amounts outstanding under
our credit facility, based on our February 28, 2002 balance, we expect to have
approximately $81.3 million of available borrowing capacity, or $167.0 million
after giving further effect to the proposed notes offering. By replacing
indebtedness incurred under our revolving credit facility in connection with
acquisition, development and exploitation activity with the net proceeds from
this offering and the proposed notes offering, we will be implementing our
strategy of matching long-lived assets with long-term debt and equity.

S-4

THE OFFERING

Common stock offered.......... 1,500,000 shares

Common stock to be outstanding
after the offering............ 26,612,636 shares

Use of proceeds............... The net proceeds of this offering are estimated
to be approximately $26.5 million. The net
proceeds will be used to reduce the outstanding
indebtedness under our credit facility incurred
in connection with our recent acquisition,
development and exploration activities.

New York Stock Exchange and
Pacific Stock Exchange
Symbol........................ "SFY"

The number of shares shown above to be outstanding after the offering does not
include 2,639,504 shares that may be issued upon exercise of options outstanding
under our stock compensation plans outstanding as of December 31, 2001.

RISK FACTORS

Before making an investment decision, you should consider all of the
information in this prospectus supplement and the accompanying prospectus, and
should carefully evaluate the risks in the "Risk Factors" section beginning on
page S-10 of this prospectus supplement and page 2 of the accompanying
prospectus.

S-5

SUMMARY CONSOLIDATED FINANCIAL DATA

The summary consolidated financial data presented below for each of the
five years in the period ended December 31, 2001 has been derived from our
audited consolidated financial statements. For a discussion of our significant
financial results and conditions during 2001, 2000 and 1999, see "Management's
Discussion and Analysis of Financial Condition and Results of Operations" in
this prospectus supplement.

YEAR ENDED DECEMBER 31,
----------------------------------------------------
2001 2000 1999 1998 1997
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT RATIOS)

INCOME STATEMENT DATA:
Revenues:
Oil and gas sales......................................... $181,185 $189,139 $108,899 $ 80,068 $ 69,015
Fees from limited partnerships and joint ventures......... 427 332 230 334 746
Interest income........................................... 49 1,339 833 107 2,395
Price risk management and other, net...................... 2,146 815 709 1,960 2,556
-------- -------- -------- -------- --------
Total revenues...................................... 183,807 191,625 110,671 82,469 74,712
-------- -------- -------- -------- --------
Costs and expenses:
General and administrative, net of reimbursement.......... 8,187 5,586 4,497 3,854 3,524
Depreciation, depletion, and amortization................. 59,502 47,771 42,349 39,343 24,247
Oil and gas production.................................... 36,720 29,221 19,646 13,139 8,779
Interest expense, net..................................... 12,627 15,968 14,443 8,752 5,033
Other expenses............................................ 2,102 -- -- -- --
Write-down of oil and gas properties(a)................... 98,862 -- -- 90,772 --
-------- -------- -------- -------- --------
Total costs and expenses............................ 218,000 98,546 80,935 155,860 41,583
-------- -------- -------- -------- --------
Income (loss) before income taxes and extraordinary item and
change in accounting principle............................ (34,193) 93,079 29,736 (73,391) 33,129
Provision (benefit) for income taxes........................ (12,238) 33,265 10,450 (25,166) 10,819
-------- -------- -------- -------- --------
Income (loss) before extraordinary item and change in
accounting principle...................................... (21,955) 59,814 19,286 (48,225) 22,310
Extraordinary loss on early extinguishment of debt (net of
taxes)(b)................................................. -- 630 -- -- --
Cumulative effect of change in accounting principle (net of
taxes)(c)................................................. 393 -- -- -- --
-------- -------- -------- -------- --------
Net income (loss)........................................... $(22,348) $ 59,184 $ 19,286 $(48,225) $ 22,310
======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
EBITDA(d)................................................... $136,799 $156,819 $ 86,528 $ 65,476 $ 62,410
Net cash provided by operating activities................... 139,884 128,197 73,603 54,249 55,256
Capital expenditures........................................ 275,126 173,277 78,113 183,816 131,967

BALANCE SHEET DATA (AT END OF PERIOD):
Working capital (deficit)................................... $(36,492) $(22,452) $ 16,535 $ 3,831 $ 1,464
Total assets................................................ 671,685 572,387 454,299 403,645 339,115
Long-term debt:
Bank borrowings........................................... 134,000 10,600 -- 146,200 7,915
6.25% convertible subordinated notes...................... -- -- 115,000 115,000 115,000
10.25% senior subordinated notes.......................... 124,197 124,129 124,068 -- --
Stockholders' equity........................................ 312,653 332,154 170,404 109,363 159,401

(Notes on following page)

S-6

NOTES TO SUMMARY CONSOLIDATED FINANCIAL DATA

(a) In the fourth quarter of 2001, prices for both oil and gas at December 31,
2001, necessitated a pre-tax domestic full cost ceiling write-down of oil
and gas properties of $98.9 million, or $63.5 million after-tax.
Additionally, in the third quarter of 1998, we took a non-cash write-down
of domestic oil and gas properties as lower prices for both oil and gas at
September 30, 1998, necessitated a pre-tax domestic full cost ceiling
write-down in 1998 of $77.2 million, or $50.9 million after-tax. Also in
the third quarter of 1998, we impaired our total investment in Russia of
$10.8 million and impaired our capitalized unproved properties costs in
Venezuela of $2.8 million. The impairment of the unproved properties costs
in these two countries resulted in a separate 1998 non-cash pre-tax charge
to earnings of $13.6 million, or $9.0 million after-tax. The combination of
the non-cash full cost domestic ceiling write-down and the non-cash foreign
impairment charges in 1998 resulted in a combined non-cash charge to
earnings of $90.8 million pre-tax, or $59.9 million after-tax.

(b) In December 2000, we called for redemption of all our 6.25% Convertible
Subordinated Notes due 2006, or Convertible Notes, at 103.75% of their
principal amount. Holders of approximately $100.0 million of the
Convertible Notes elected to convert their notes into 3,164,644 shares of
our common stock. Holders of the approximately $15.0 million remaining
Convertible Notes elected to redeem their notes for cash plus accrued
interest. This cash redemption resulted in our recognizing an extraordinary
loss on the early extinguishment of debt (net of taxes) of $0.6 million.

(c) We adopted SFAS No. 133 effective January 1, 2001. Accordingly, we marked
our open derivative contracts at December 31, 2000 to fair value at that
date resulting in a one-time net of taxes charge of $0.4 million which is
recorded as a cumulative effect of change in accounting principle.

(d) EBITDA represents income before interest expense, income tax, and
depreciation, depletion and amortization (including the write-down of oil
and gas properties). We have reported EBITDA because we believe EBITDA is a
measure commonly reported and widely used by investors as an indicator of a
company's operating performance. We believe EBITDA assists such investors
in comparing a company's performance on a consistent basis without regard
to depreciation, depletion and amortization, which can vary significantly
depending upon accounting methods or nonoperating factors such as
historical cost. EBITDA is not a calculation based on GAAP and should not
be considered an alternative to net income in measuring our performance or
used as an exclusive measure of cash flow because it does not consider the
impact of working capital growth, capital expenditures, debt principal
reductions and other sources and uses of cash which are disclosed in our
Consolidated Statements of Cash Flows. Investors should carefully consider
the specific items included in our computation of EBITDA. While EBITDA has
been disclosed herein to permit a more complete comparative analysis of our
operating performance relative to other companies, investors should be
cautioned that EBITDA as reported by us may not be comparable in all
instances to EBITDA as reported by other companies. EBITDA amounts may not
be fully available for management's discretionary use, due to certain
requirements to conserve funds for capital expenditures, debt service and
other commitments.

S-7

SUMMARY RESERVES AND PRODUCTION DATA

The following tables set forth certain summary information with respect to
estimates of our oil and gas reserves, and data about production and sales of
oil and gas for the periods indicated. Reserves were determined by us and
audited by H.J. Gruy and Associates, Inc., independent petroleum consultants.
The net reserves and cash flows for New Zealand were prepared by us. See
"Business and Properties -- Oil and Gas Reserves" and "Risk Factors."

AS OF AND FOR THE YEAR ENDED DECEMBER 31,
------------------------------------------------------------
2001 2000 1999 1998 1997
---------- ---------- -------- -------- --------

ESTIMATED PROVED OIL AND GAS RESERVES(A):
Net gas reserves (MMcf):
Proved developed...................................... 181,652 215,170 174,046 197,106 191,108
Proved undeveloped.................................... 143,260 203,444 155,914 155,295 123,198
---------- ---------- -------- -------- --------
Total........................................... 324,912 418,614 329,960 352,401 314,306
========== ========== ======== ======== ========
Net oil reserves (MBbls):
Proved developed...................................... 23,760 10,980 8,437 7,143 4,289
Proved undeveloped.................................... 29,723 24,154 12,369 6,815 3,570
---------- ---------- -------- -------- --------
Total........................................... 53,483 35,134 20,806 13,958 7,859
========== ========== ======== ======== ========
TOTAL PROVED OIL AND GAS RESERVES (MMCFE)....... 645,808 629,416 454,797 436,148 361,459
========== ========== ======== ======== ========
ESTIMATED PRESENT VALUE OF PROVED RESERVES (IN
THOUSANDS):
Estimated present value of future net cash flows from
proved reserves discounted at 10% per annum, "PV-10
Value"(a):
Proved developed...................................... $ 344,479 $1,257,571 $301,200 $243,124 $244,365
Proved undeveloped.................................... 258,507 1,055,684 262,855 97,661 105,980
---------- ---------- -------- -------- --------
PV-10 Value(a).......................................... $ 602,986(b) $2,313,255(b) $564,055 $340,785 $350,345
========== ========== ======== ======== ========
Standardized measure of discounted estimated future net
cash flows after income taxes(a)...................... $ 454,558 $1,577,958 $438,944 $290,273 $292,838
========== ========== ======== ======== ========
PRICES USED IN CALCULATING END OF YEAR PROVED RESERVES:
Oil (per Bbl)........................................... $ 18.45 $ 24.62 $ 23.69 $ 11.23 $ 15.76
Gas (per Mcf)........................................... $ 2.51 $ 9.86 $ 2.58 $ 2.23 $ 2.78
OTHER RESERVES DATA:
Three year reserve replacement cost (per Mcfe)(c)....... $ 1.40 $ 1.00 $ 1.09 $ 0.96 $ 0.73
Three year reserve replacement rate(d).................. 263% 319% 287% 422% 590%
Gas as percent of total proved reserve quantities....... 50% 67% 73% 81% 87%
Proved developed reserves as percent of total proved
reserves.............................................. 50% 45% 49% 55% 60%

YEAR ENDED DECEMBER 31,
------------------------------------------------------------
2001 2000 1999 1998 1997
---------- ---------- -------- -------- --------

NET SALES VOLUME:
Oil (MBbls)............................................. 3,055 2,472 2,565 1,801 672
Gas (MMcf)(e)........................................... 26,459 27,525 27,485 28,226 21,359
Total production (MMcfe)(e)............................. 44,791 42,357 42,874 39,030 25,394
WEIGHTED AVERAGE SALES PRICES:
Oil (per Bbl)........................................... $ 22.64 $ 29.35 $ 16.75 $ 11.86 $ 17.59
Gas (per Mcf)........................................... $ 4.23 $ 4.24 $ 2.40 $ 2.08 $ 2.68
SELECTED DATA PER MCFE:
Production costs........................................ $ 0.82 $ 0.69 $ 0.46 $ 0.34 $ 0.35
Depreciation, depletion, and amortization............... $ 1.33 $ 1.13 $ 0.99 $ 1.01 $ 0.95
General and administrative, net of reimbursement........ $ 0.18 $ 0.13 $ 0.10 $ 0.10 $ 0.14

(Notes on following page)

S-8

NOTES TO SUMMARY RESERVES AND PRODUCTION DATA

(a) Quantity estimates, their PV-10 Value and the standardized measure of
future net cash flows are affected by the change in crude oil and gas
prices at the end of each year.

(b) Under SEC guidelines, estimates of the PV-10 Value of proved reserves must
be made using oil and gas sales prices at the date for the valuation, which
prices are held constant throughout the life of the properties. Our year
end 2001 average prices used to calculate PV-10 Value were $2.51 per Mcf
and $18.45 per Bbl. The year end 2001 gas price of $2.51 was significantly
lower than the average gas price of $4.23 we received during 2001. The year
end 2001 oil price of $18.45 was also lower than the average oil price of
$22.64 we received in 2001. Had year end reserves been calculated using the
average 2001 prices we received, $22.64 for oil and $4.23 for gas, the
PV-10 Value would have been approximately $947.8 million compared to the
$603.0 million reported using year end 2001 prices. Conversely, commodity
prices were unusually high at year end 2000, especially gas prices. Our
year end 2000 average prices used to calculate PV-10 Value were $9.86 per
Mcf and $24.62 per Bbl. Had year end 2000 reserves been calculated using
the average 2000 prices we received, $29.35 for oil and $4.24 for gas, the
PV-10 Value would have been approximately $1.1 billion compared to the $2.3
billion reported using year end 2000 prices.

(c) Calculated for a three-year period ending with the year presented by
dividing total acquisition, exploration and development costs, excluding
future development costs, during such period by net reserves added during
the period, excluding any revisions of those reserves.

(d) Calculated for a three-year period ending with the year presented by
dividing the increase in net reserves, including any revisions of those
reserves, by the production quantities for such period.

(e) Natural gas production for the years ended 2000, 1999, 1998 and 1997
includes 405, 728, 866 and 1,015 MMcf, respectively, delivered under the
volumetric production payment agreement pursuant to which we were obligated
to deliver certain monthly quantities of gas to a third party through
October 2000. Remaining obligated volumes associated with the volumetric
production payment were not included in our estimate of net reserves for
the relevant years.

S-9

RISK FACTORS

An investment in our common stock involves significant risks. You should
carefully consider the following risk factors before you decide to purchase our
common stock. You should also carefully read and consider all of the information
we have included, or incorporated by reference, in this prospectus supplement
and the accompanying prospectus before you decide to purchase our common stock.

OIL AND NATURAL GAS PRICES ARE VOLATILE. A SUBSTANTIAL DECREASE IN OIL AND
NATURAL GAS PRICES WOULD ADVERSELY AFFECT OUR FINANCIAL RESULTS.

Our future financial condition, results of operations and the value of our
oil and natural gas properties depend primarily upon market prices for oil and
natural gas. Oil and natural gas prices historically have been volatile and will
likely continue to be volatile in the future. Oil and natural gas prices
received in the second half of 2001 were significantly lower than the average
prices we received during the first half of 2001, and lower than the average
prices received for most of 2000. Both commodity prices continued to drop during
the early part of the first quarter of 2002. The prices for oil and natural gas
are subject to wide fluctuation in response to relatively minor changes in the
supply of and demand for oil and natural gas, market uncertainty, worldwide
economic conditions, weather conditions, import prices, political conditions in
major oil producing regions, especially the Middle East, and actions taken by
OPEC. A significant decrease in price levels for an extended period would
negatively affect us in several ways:

- our cash flow would be reduced, decreasing funds available for capital
expenditures employed to replace reserves or increase production;

- certain reserves would no longer be economic to produce, leading to both
lower proved reserves and cash flow;

- our lenders could reduce the borrowing base under our credit facility
because of lower oil and gas reserve values, reducing our liquidity and
possibly requiring mandatory loan repayments; and

- access to other sources of capital, such as equity or long-term debt
markets, could be severely limited or unavailable in a low price
environment.

Consequently, our revenues and profitability would suffer.

OUR DEBT REDUCES OUR FINANCIAL FLEXIBILITY, AND OUR DEBT LEVELS MAY INCREASE.

As of February 28, 2002, after the TAWN acquisition in January 2002, and
after giving effect to the Antrim acquisition in March 2002, to this offering
and to the proposed notes offering, our long-term debt would have comprised
approximately 48% of our total capitalization. Increased debt:

- would require us to dedicate a significant portion of our cash flow to
the payment of interest;

- would subject us to a higher financial risk in an economic downturn due
to substantial debt service costs;

- would limit our ability to obtain financing or raise equity capital in
the future; and

- may place us at a competitive disadvantage to the extent that we are more
highly leveraged than some of our peers.

Subject to restrictions in our credit facility and the indenture for our
senior subordinated notes due 2009, as of February 28, 2002, we had a $300.0
million credit facility with a borrowing base of $275.0 million of which $54.8
million was available for borrowing. If we increase our debt levels further, the
risks discussed above would become greater.

IF WE CANNOT REPLACE OUR RESERVES, OUR REVENUES AND FINANCIAL CONDITION WILL
SUFFER.

Unless we successfully replace our reserves, our production will decline,
resulting in lower revenues and cash flow. This is accentuated by the fact that
in our Masters Creek area new production added by drilling has not kept up with
the decline in production. When oil and gas prices decrease, our cash flow

S-10

decreases, resulting in less available cash to drill and replace our reserves
and an increased need to draw on our bank line of credit.

DRILLING WELLS IS SPECULATIVE AND CAPITAL INTENSIVE.

Developing and exploring for oil and gas properties requires significant
capital expenditures and involves a high degree of financial risk. The budgeted
costs of drilling, completing and operating wells are often exceeded and can
increase significantly when drilling costs rise. Drilling may be unsuccessful
for many reasons, including title problems, weather, cost overruns, equipment
shortages and mechanical difficulties. Moreover, the successful drilling of an
oil or gas well does not ensure a profit on investment. Exploratory wells bear a
much greater risk of loss than development wells. A variety of factors, both
geological and market-related, can cause a well to become uneconomical or only
marginally economical. In addition to their cost, unsuccessful wells can hurt
our efforts to replace reserves.

ESTIMATES OF PROVED RESERVES ARE UNCERTAIN, AND REVENUES FROM PRODUCTION MAY
VARY FROM EXPECTATIONS SIGNIFICANTLY.

The quantities and values of our proved reserves included in this
prospectus supplement and in our documents we have incorporated by reference are
only estimates and subject to numerous uncertainties. Estimates by other
engineers might differ materially. The accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geological
interpretation. These estimates depend on assumptions regarding quantities and
production rates of recoverable oil and gas reserves, future prices for oil and
gas, timing and amounts of development expenditures and operating expenses, all
of which will vary from those assumed in our estimates. These variances may be
significant. For example, in 2001 the net reduction in our estimate of proved
reserves in New Zealand was approximately 37 Bcfe.

Any significant variance from the assumptions used could result in the
actual amounts of oil and gas ultimately recovered and future net cash flows
being materially different from the estimates in our reserve reports. In
addition, results of drilling, testing, production and changes in prices after
the date of the estimate may result in substantial downward revisions. These
estimates may not accurately predict the present value of net cash flows from
oil and gas reserves.

At December 31, 2001, approximately 50% of our estimated proved reserves
were undeveloped. Recovery of undeveloped reserves generally requires
significant capital expenditures and successful drilling operations. The reserve
data assumes that we can and will make these expenditures and conduct these
operations successfully, which may not occur.

WE INCURRED A WRITE-DOWN OF THE CARRYING VALUES OF OUR PROPERTIES IN THE FOURTH
QUARTER OF 2001 AND COULD INCUR ADDITIONAL WRITE-DOWNS IN THE FUTURE.

Under the full cost method of accounting, SEC accounting rules require that
on a quarterly basis we review the carrying value of our oil and gas properties
on a country by country basis for possible write-down or impairment. Under these
rules, capitalized costs of proved reserves may not exceed a ceiling calculated
at the present value of estimated future net revenues from those proved
reserves, determined using a 10% per year discount and unescalated prices in
effect as of the end of each fiscal quarter. Capital costs in excess of the
ceiling must be permanently written down.

We recorded an after-tax, non-cash charge during the fourth quarter of 2001
of $63.5 million. This write-down results in a charge to earnings and a
reduction of shareholders' equity, but does not impact our cash flow from
operating activities. Once incurred, write-downs are not reversible at a later
date. If commodity prices continue to decline or if we have downward oil and gas
revisions, we could incur additional write-downs in the future. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Critical Accounting Policies -- Property and Equipment."

S-11

RESERVES ON PROPERTIES WE BUY MAY NOT MEET OUR EXPECTATIONS AND COULD CHANGE THE
NATURE OF OUR BUSINESS.

Property acquisition decisions are based on various assumptions and
subjective judgments that are speculative. Although available geological and
geophysical information can provide information about the potential of a
property, it is impossible to predict accurately a property's production and
profitability. Furthermore, future acquisitions may change the nature of our
operations and business. For example, an acquisition of producing properties
containing primarily oil reserves could change our current emphasis on gas
reserves.

In addition, we may have difficulty integrating future acquisitions into
our operations, and they may not achieve our desired profitability objectives.
Likewise, as is customary in the industry, we generally acquire oil and gas
acreage without any warranty of title except through the transferor. In many
instances, title opinions are not obtained if, in our judgment, it would be
uneconomical or impractical to do so. Losses may result from title defects or
from defects in the assignment of leasehold rights. While our current operations
are primarily in Texas, Louisiana and New Zealand, we may pursue acquisitions of
properties located in other geographic areas, which would decrease our
geographical concentration, and could also be in areas in which we have no or
limited experience.

WE MAY HAVE DIFFICULTY COMPETING FOR OIL AND GAS PROPERTIES OR SUPPLIES.

We operate in a highly competitive environment, competing with major
integrated and independent energy companies for desirable oil and gas
properties, as well as for the equipment, labor and materials required to
develop and operate such properties. Many of these competitors have financial
and technological resources substantially greater than ours. The market for oil
and gas properties is highly competitive and we may lack technological
information or expertise available to other bidders. We may incur higher costs
or be unable to acquire and develop desirable properties at costs we consider
reasonable because of this competition.

GOVERNMENTAL LAWS AND REGULATIONS ARE COSTLY AND COMPLEX, ESPECIALLY THOSE
RELATING TO ENVIRONMENTAL PROTECTION.

Our exploration, production and marketing operations are subject to
extensive laws and regulations at the international, federal, state and local
levels. These laws and regulations affect the costs, manner and feasibility of
our operations. As an owner and operator of oil and gas properties, we are
subject to international, federal, state and local laws and regulations relating
to discharge of materials into, and protection of, the environment. We have made
and will continue to make significant expenditures in our efforts to comply with
the requirements of these environmental laws and regulations, which may impose
liability on us for the cost of pollution clean-up resulting from operations,
subject us to penalties and liabilities for pollution damages and require
suspension or cessation of operations in affected areas. Changes in or additions
to laws and regulations regarding the protection of the environment could
increase our compliance costs and might hurt our business.

We are subject to state and local laws and regulations domestically and are
subject to New Zealand laws and regulations that impose permitting, reclamation,
land use, conservation and other restrictions on our ability to drill and
produce oil and natural gas. These laws and regulations can require well and
facility sites to be closed and reclaimed. We frequently buy and sell interests
in properties that have been operated in the past, and as a result of these
transactions we may retain or assume clean-up or reclamation obligations for our
own operations or those of third parties.

WE MAY BE EXPOSED TO FINANCIAL AND OTHER LIABILITIES AS THE GENERAL PARTNER IN
71 LIMITED PARTNERSHIPS.

We currently serve as the managing general partner of 71 limited
partnerships, all but six of which are in the process of selling their
properties and liquidating. We are contingently liable for our obligations as a
general partner, including responsibility for day-to-day operations and any
liabilities that cannot be repaid

S-12

from partnership assets or insurance proceeds. In the future, we may be exposed
to litigation in connection with the partnerships.

INCREASED VOLATILITY OF OIL AND GAS PRICES CAN CAUSE SUDDEN CHANGES IN THE
MARKET PRICE OF OUR COMMON STOCK.

Our quarterly results of operations may fluctuate significantly as a result
of variations in oil and gas prices and production performance. In recent years,
oil and gas price volatility has become increasingly severe. You can expect the
market price of our common stock to decline when our quarterly results decline
or at any time when events adverse to us or the industry occur. Our common stock
price may decline to a price below the price you paid to purchase your shares of
common stock in this offering.

OUR SHAREHOLDER RIGHTS PLAN, ARTICLES OF INCORPORATION AND BYLAWS DISCOURAGE
UNSOLICITED TAKEOVER PROPOSALS AND COULD PREVENT YOU FROM REALIZING A PREMIUM
FOR YOUR COMMON STOCK.

We have a stockholder rights plan that may have the effect of discouraging
unsolicited takeover proposals. The rights issued under the stockholder rights
plan would cause substantial dilution to a person or group that attempts to
acquire us on terms not approved in advance by our board of directors. In
addition, our articles of incorporation and bylaws contain provisions that may
discourage unsolicited takeover proposals that stockholders may consider to be
in their best interests. These provisions include:

- a classified board of directors;

- the ability of the board of directors to designate the terms of and issue
new series of preferred stock;

- advance notice requirements for nominations for election of the board of
directors; and

- requirements for approval of business combinations with interested
parties.

Together these provisions and the rights plan may discourage transactions that
otherwise could involve payment of a premium over prevailing market prices for
your common stock.

S-13

USE OF PROCEEDS

We estimate that the net proceeds from the sale of common stock in this
offering will be approximately $26.5 million, or $30.5 million if the
underwriter exercises its over-allotment option in full, after deducting
underwriting discounts and commissions and estimated offering expenses.

We intend to use the net proceeds to repay a portion of the outstanding
indebtedness under our credit facility and to use the funds then made available
under our credit facility for capital expenditures, acquisitions, and general
corporate purposes.

In January 2002, upon closing of the New Zealand TAWN acquisition, our
credit facility increased from $250.0 million to $300.0 million and the
borrowing base increased from $200.00 million to $275.0 million. At February 28,
2002, $220.2 million was outstanding under our credit facility at a weighted
average interest rate of 3.53%. The amount available for borrowing is subject to
a borrowing base determination that is recalculated at least every six months,
and is subject to reduction upon the closing of the proposed notes offering. Our
bank credit facility is described in more detail in the "Description of Existing
Indebtedness" section of this prospectus supplement.

S-14

CAPITALIZATION

The following table sets forth as of December 31, 2001:

- our historical capitalization;

- our capitalization as adjusted for the estimated net proceeds of $26.5
million from the sale of our common stock in this offering; and

- our capitalization as further adjusted for the estimated net proceeds of
$145.7 million from the proposed notes offering.

Our proposed notes offering is expected to close in mid-April 2002,
although we can provide no assurance in this regard. This table does not reflect
the issuance of 220,000 shares of our common stock in March 2002 to acquire the
New Zealand assets of Antrim Oil and Gas Limited or 2,639,504 shares that may be
issued pursuant to outstanding stock compensation plans as of December 31, 2001.
This table should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations," the consolidated
financial statements, and the related notes contained in this prospectus
supplement.

AS OF DECEMBER 31, 2001
------------------------------------------
AS ADJUSTED
AS ADJUSTED FOR BOTH
SOLELY FOR COMMON STOCK
COMMON STOCK AND NOTES
HISTORICAL OFFERING OFFERINGS
---------- ------------ --------------
(IN THOUSANDS, EXCEPT SHARE DATA)

Cash and cash equivalents(a)......................... $ 2,149 $ 2,149 $ 40,389
======== ======== ========
Long-Term Debt
Bank Borrowings(a)................................. 134,000 107,500 --
10.25% Senior Subordinated Notes Due 2009.......... 124,197 124,197 124,197
% Senior Subordinated Notes Due 2012.......... -- -- 150,000
-------- -------- --------
Total Long-Term Debt....................... $258,197 $231,697 $274,197
-------- -------- --------
Stockholders' Equity
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding.................... -- -- --
Common stock, $.01 par value, 85,000,000 shares
authorized, 25,634,598 and 27,134,598 shares
issued and 24,795,564 and 26,295,564 shares
outstanding, respectively, as adjusted for the
common stock offering........................... 257 272 272
Additional paid-in capital......................... 296,173 323,658 322,658
Treasury stock held, at cost, 839,034 shares....... (12,033) (12,033) (12,033)
Retained Earnings.................................. 28,256 28,256 28,256
-------- -------- --------
Total stockholders' equity................. 312,653 339,153 339,153
-------- -------- --------
Total Capitalization....................... $570,850 $570,850 $613,350
======== ======== ========

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

(a) As of February 28, 2002, our outstanding bank borrowings were $220.2
million. Accordingly, after repaying a portion of amounts outstanding with
the net proceeds from this offering, our bank borrowings as of February 28,
2002 would have been approximately $193.7 million, and our cash and cash
equivalents would have been approximately $2.1 million. After repaying a
portion of amounts outstanding with the net proceeds expected from the
proposed notes offering, these amounts would have been approximately $48.0
million and $2.1 million, respectively.

S-15

COMMON STOCK PRICE RANGE AND DIVIDEND POLICY

Our common stock is traded on the New York and Pacific Stock Exchanges
under the symbol "SFY." The following table sets forth the range of high and low
sale prices per share of our common stock as reported by the NYSE for the
periods indicated.

HIGH LOW
------ ------

1999
First Quarter............................................. $ 8.63 $ 5.69
Second Quarter............................................ 13.13 8.25
Third Quarter............................................. 13.13 10.25
Fourth Quarter............................................ 13.31 10.31

2000
First Quarter............................................. $17.88 $ 9.75
Second Quarter............................................ 29.56 15.00
Third Quarter............................................. 41.88 20.38
Fourth Quarter............................................ 43.50 28.81

2001
First Quarter............................................. $37.50 $28.91
Second Quarter............................................ 37.70 27.70
Third Quarter............................................. 32.55 19.00
Fourth Quarter............................................ 25.14 16.66

2002
First Quarter............................................. $21.25 $15.39
Second Quarter (through April 9).......................... 20.90 17.95

The last sale price of our common stock as reported by the New York Stock
Exchange on April 9, 2002, was $18.10 per share.

We have not paid cash dividends on our common stock in the past and do not
intend to pay dividends on our common stock in the foreseeable future. Our
credit facility and the indenture governing our outstanding 10.25% notes due
2009 limit our ability to pay dividends.

S-16

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The selected historical consolidated financial data presented below for
each of the five years in the period ended December 31, 2001 has been derived
from our audited consolidated financial statements. For a discussion of our
significant financial results and conditions during 2001, 2000 and 1999, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" in this prospectus supplement.

YEAR ENDED DECEMBER 31,
----------------------------------------------------
2001 2000 1999 1998 1997
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT RATIOS)

(Notes on following page)

S-17

NOTES TO SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

(a) In the fourth quarter of 2001, prices for both oil and gas at December 31,
2001, necessitated a pre-tax domestic full cost ceiling write-down of oil
and gas properties of $98.9 million, or $63.5 million after-tax.
Additionally, in the third quarter of 1998, we took a non-cash write-down
of domestic oil and gas properties as prices for both oil and gas at
September 30, 1998, necessitated a pre-tax domestic full-cost ceiling
write-down in 1998 of $77.2 million, or $50.9 million after-tax. Also in
the third quarter of 1998 we impaired our total investment in Russia of
$10.8 million and impaired our capitalized unproved properties costs in
Venezuela of $2.8 million. The impairment of the unproved properties costs
in these two countries resulted in a separate 1998 non-cash pre-tax charge
to earnings of $13.6 million, or $9.0 million after-tax. The combination of
the non-cash full cost domestic ceiling write-down and the non-cash foreign
impairment charges in 1998 resulted in a combined non-cash charge to
earnings of $90.8 million pre-tax, or $59.9 million after-tax.

(b) In December 2000, we called for redemption of all of our Convertible Notes
at 103.75% of their principal amount. Holders of approximately $100.0
million of the Convertible Notes elected to convert their notes into
3,164,644 shares of our common stock. Holders of the approximately $15.0
million remaining Convertible Notes elected to redeem their notes for cash
plus accrued interest. This cash redemption resulted in our recognizing an
extraordinary loss on the early extinguishment of debt (net of taxes) of
$0.6 million.

S-18

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis in conjunction with
our financial information and our consolidated financial statements and notes
thereto included or incorporated by reference in this prospectus supplement. The
following information contains forward-looking statements. For a discussion of
limitations inherent in forward-looking statements, see "Forward-Looking
Information" in the accompanying prospectus on page 3.

GENERAL

Over the last several years, we have emphasized adding reserves through
drilling activity. We also add reserves through strategic purchases of producing
properties when oil and gas prices are at lower levels and other market
conditions are appropriate. During the past three years, we have used this
flexible strategy of employing both drilling and acquisitions to add more
reserves than we have depleted through production.

CRITICAL ACCOUNTING POLICIES. The following summarizes several of our
critical accounting policies. See a complete list of significant accounting
policies in Note 1 to the Consolidated Financial Statements.

Use of Estimates. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities, if
any, at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from estimates.

Property and Equipment. We follow 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 exploration, development, and
acquisition of oil and gas reserves are capitalized.

The cost of unproved properties not being amortized is assessed quarterly,
on a country-by-country basis, to determine whether such properties have been
impaired. In determining whether such costs should be impaired, our management
evaluates, among other factors, current drilling results, lease expiration
dates, current oil and gas industry conditions, international economic
conditions, capital availability, foreign currency exchange rates, the political
stability in the countries in which we have an investment, and available
geological and geophysical information. Any impairment assessed is added to the
cost of proved properties being amortized. To the extent costs accumulate in
countries where there are no proved reserves, any costs determined by management
to be impaired are charged to income.

Full Cost Ceiling Test. At the end of each quarterly reporting period, the
unamortized cost of oil and gas properties, net of related deferred income
taxes, is limited to the sum of the estimated future net revenues from proved
properties using period-end prices, discounted at 10%, and the lower of cost or
fair value of unproved properties, adjusted for related income tax effects
("Ceiling Test"). This calculation is done on a country-by-country basis for
those countries with proved reserves.

The calculation of the Ceiling Test is based on estimates of proved
reserves. There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production, timing, and
plan of development. The accuracy of any reserves estimate is a function of the
quality of available data and of engineering and geological interpretation and
judgment. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimate. Accordingly, reserves
estimates are often different from the quantities of oil and gas that are
ultimately recovered.

In 2001, as a result of low oil and gas prices at December 31, 2001, we
reported a non-cash write-down on a before-tax basis of $98.9 million ($63.5
million after tax) on our domestic properties. We had no write-down on our New
Zealand properties.

depreciation, depletion, and amortization costs our portion of drilling costs
associated with an unsuccessful exploratory well drilled by another operator in
New Zealand. This charge was $290,000.

Because of the delineation of our 1999 Rimu discovery with two successful
delineation wells drilled in 2000, proved reserves were recognized in New
Zealand as of December 31, 2000.

Given the volatility of oil and gas prices, our estimates of discounted
future net cash flows from proved oil and gas reserves are subject to change. If
oil and gas prices decline significantly, even if only for a short period, it is
possible that additional write-downs of oil and gas properties could occur in
the future.

Price-Risk Management Activities. In June 1998, the Financial Accounting
Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities." The statement establishes accounting and reporting
standards requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded in the balance
sheet as either an asset or a liability measured at its fair value. SFAS No. 133
requires that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. Special accounting
for qualifying hedges allows the gains and losses on derivatives to offset
related results on the hedged item in the income statements and requires that a
company must formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting. SFAS No. 133, as amended by SFAS No.
137 and SFAS No. 138, was adopted by us on January 1, 2001.

We have a policy to use derivative instruments, mainly the buying of
protection price floors, to protect against price declines in oil and gas
prices. We elected not to designate our price floors for special hedge
accounting treatment under SFAS No. 133, as amended. However, we have elected to
use mark-to-market accounting treatment for our derivative contracts. Upon
adoption of SFAS No. 133 on January 1, 2001, we recorded a net of taxes charge
of $392,868, which is recorded as a Cumulative Effect of Change in Accounting
Principle. During 2001 we recognized net gains of $1,173,094 relating to our
derivative activities, with $16,784 in unrealized losses at year end 2001. This
activity is recorded in Price-risk management and other, net on the accompanying
statements of income.

At December 31, 2001, we had open price floor contracts covering notional
volumes of 2.0 million MMBtu of natural gas. These natural gas price floor
contracts relate to the NYMEX contract months of February and March 2002 at an
average price of $2.33 per MMBtu. The fair value of our open price floor
contracts at December 31, 2001, totaled $296,000 and is included in Other
current assets on the accompanying balance sheet.

PROVED OIL AND GAS RESERVES. At year end 2001, our total proved reserves
were 645.8 Bcfe with a PV-10 Value of $603.0 million. In 2001, our proved
natural gas reserves decreased 93.7 Bcf, or 22%, while our proved oil reserves
increased 18.3 MMBbl, or 52%, for a total equivalent increase of 16.4 Bcfe, or
3%. From 1999 to 2000, our proved natural gas reserves increased by 88.7 Bcf, or
27%, while our proved oil reserves increased by 14.3 MMBbl, or 69%, for a total
equivalent increase of 174.6 Bcfe, or 38%. We added reserves from 2000 to 2001
through both our drilling activity and through purchases of minerals in place.
Through drilling we added 105.8 Bcfe (17.4 Bcfe of which came from New Zealand)
of proved reserves in 2001, 184.7 Bcfe (122.5 Bcfe of which came from New
Zealand) in 2000, and 64.9 Bcfe in 1999. Through acquisitions we added 54.6 Bcfe
of proved reserves in 2001, 39.7 Bcfe in 2000, and 20.1 Bcfe in 1999. At year
end 2001, 50% of our total proved reserves were proved developed, compared with
45% at year end 2000 and 49% at year end 1999.

While our total proved reserves quantities increased by 3% during 2001, the
PV-10 Value of those reserves decreased 74%, primarily due to significantly
lower prices at year end 2001 than at year end 2000. Between year end 2000 and
year end 2001, there was a 75% decrease in natural gas prices and a 25% decrease
in oil prices. Gas prices were $2.51 per Mcf at year end 2001, compared to $9.86
per Mcf at year end 2000. Oil prices were $18.45 per Bbl at year end 2001,
compared to $24.62 a year earlier. These decreases in prices resulted in 47.1
Bcfe of the downward reserve revisions. Under SEC guidelines, estimates of
proved reserves must be made using year end oil and gas sales prices and are
held constant throughout the life of the properties. Subsequent changes to such
year end oil and gas prices could have a

S-20

significant impact on the calculated PV-10 Value. The year end 2001 gas price of
$2.51 was significantly lower than the average gas price of $4.23 we received
during 2001. The year end 2001 oil price of $18.45 per barrel was also lower
than the average oil price of $22.64 we received in 2001. Had year end reserves
been calculated using the average 2001 prices we received, $22.64 for oil and
$4.23 for gas, the PV-10 Value would have been approximately $947.8 million
compared to the $603.0 million reported using year end prices.

RECENT EVENTS

TAWN ACQUISITION. Through our subsidiary, Swift Energy New Zealand
Limited, we acquired Southern Petroleum Exploration Limited ("Southern NZ") from
an affiliate of Shell New Zealand in January 2002 for approximately $54.4
million. Through Southern NZ we now own interests in four onshore producing oil
and gas fields, extensive associated hydrocarbon-processing facilities and
pipelines complementing our existing fields by providing us with access to
export terminals and markets and additional excess processing capacity for both
oil and natural gas. As of December 31, 2001, the reserves associated with this
acquisition were estimated to be approximately 62.1 Bcfe, all of which were
proved developed. This acquisition was accounted for using the purchase method
of accounting. Upon the closing of this acquisition, our credit facility was
increased to $300.0 million, and the borrowing base became $275.0 million.

In conjunction with the TAWN acquisition, we granted Shell New Zealand a
short-term option to acquire an undivided 25% interest in our permit 38719,
which includes our Rimu and Kauri areas, as well as a 25% interest in our Rimu
Production Station. We do not know if Shell New Zealand will exercise this
option. Any exercise of the option would be subject to numerous notifications,
governmental approvals and consents. If Shell New Zealand does not exercise its
option, we intend to pursue discussions with several other companies that have
expressed interest in acquiring up to a 25% interest in the permit.

ANTRIM ACQUISITION. We purchased through our subsidiary, Swift Energy New
Zealand Limited, all of the New Zealand assets owned by Antrim Oil and Gas
Limited for 220,000 shares of Swift Energy Company common stock and an effective
date adjustment of approximately $530,000. Antrim owned a 5% interest in permit
38719 and a 7.5% interest in permit 38716. As of December 31, 2001, the reserves
associated with this acquisition were estimated to be approximately 5.7 Bcfe.
This transaction closed in March 2002.

RUSSIA. On March 28, 2002, we received $7.5 million for our interest in
the Samburg project located in Western Siberia, Russia as a result of the sale
by a third party of its ownership in a Russian joint stock company, which owned
and operated this field. This will result in a $7.5 million non-recurring,
pre-tax gain in the first quarter of 2002.

RESULTS OF OPERATIONS

REVENUES. Our revenues in 2001 decreased by 4% compared to revenues in
2000 due primarily to decreases in oil prices.

Oil and gas sales revenues in 2001 decreased by 4%, or $8.0 million, from
the level of those revenues for 2000 even though our net sales volumes in 2001
increased by 6%, or 2.4 Bcfe, over net sales volumes in 2000. Average prices
received for oil decreased to $22.64 per Bbl in 2001 from $29.35 per Bbl in
2000. Average gas prices received decreased slightly to $4.23 per Mcf in 2001
from $4.24 per Mcf in 2000.

In 2001, our $8.0 million decrease in oil and gas sales resulted from:

- Price variances that had a $20.6 million unfavorable impact on sales, of
which $20.5 million was attributable to the 23% decrease in average oil
prices received and $0.1 million was attributable to the slight decrease
in average gas prices received; and

- Volume variances that had a $12.6 million favorable impact on sales, with
$17.1 million of increases coming from the 583,000 Bbl increase in oil
sales volumes, partially offset by a decrease of $4.5 million from the
1.1 Bcf decrease in gas sales volumes.

S-21

Revenues in 2000 increased by 73% compared to 1999 revenues. In 2000, oil
and gas sales revenues increased by 74%, or $80.2 million, over those revenues
in 1999. In 2000, net sales volumes decreased by 1%, or 0.5 Bcfe, compared to
net sales volumes in 1999. Average oil prices received went from $16.75 per Bbl
in 1999 to $29.35 per Bbl in 2000, and average gas prices received increased
from $2.40 per Mcf in 1999 to $4.24 per Mcf in 2000.

In 2000, our $80.2 million increase in oil and gas sales resulted from:

- Price variances that had an $81.7 million favorable impact on sales, of
which $31.1 million was attributable to the 75% increase in average oil
prices received and $50.6 million was attributable to the 77% increase in
average gas prices received; and

- Volume variances that had a $1.5 million unfavorable impact on sales,
with $1.6 million of decreases coming from the 93,000 Bbl decrease in oil
sales volumes, partially offset by an increase of $0.1 million from the
40,000 Mcf increase in gas sales volumes.

The following table provides additional information regarding our oil and
gas sales:

NET SALES VOLUME AVERAGE SALES PRICE
------------------------- ---------------------
OIL GAS COMBINED OIL GAS
(MBBL) (BCF) (BCFE) (PER BBL) (PER MCF)
------ ----- -------- --------- ---------

2001:
First Qtr. .................................... 603 6.7 10.3 $27.63 $6.86
Second Qtr. ................................... 691 7.1 11.3 26.05 4.66
Third Qtr. .................................... 813 6.8 11.7 23.76 2.94
Fourth Qtr. ................................... 948 5.9 11.5 16.02 2.21
----- ---- ----
3,055 26.5 44.8 $22.64 $4.23
2000:
First Qtr. .................................... 653 6.6 10.6 $27.35 $2.93
Second Qtr. ................................... 650 6.9 10.8 27.55 3.99
Third Qtr. .................................... 591 7.0 10.5 30.68 4.39
Fourth Qtr. ................................... 578 7.0 10.5 32.26 5.55
----- ---- ----
2,472 27.5 42.4 $29.35 $4.24
1999:
First Qtr. .................................... 728 7.2 11.6 $10.87 $1.82
Second Qtr. ................................... 644 6.7 10.6 15.25 2.05
Third Qtr. .................................... 612 6.9 10.5 18.46 2.84
Fourth Qtr. ................................... 581 6.7 10.2 23.99 2.91
----- ---- ----
2,565 27.5 42.9 $16.75 $2.40

Revenues from our oil and gas sales comprised 99% of total revenues for
both 2001 and 2000 and 98% of total revenues for 1999. Natural gas production
made up 59% of our production volumes in 2001, 65% in 2000, and 64% in 1999.

COSTS AND EXPENSES. Our general and administrative expenses, net in 2001
increased $2.6 million, or 47%, from the level of such expenses in 2000, while
2000 general and administrative expenses increased $1.1 million, or 24%, over
1999 levels. These increases reflect the increase in our corporate activities
along with a reduction in reimbursement from partnerships we manage as these
continue undergoing planned liquidation as voted upon by their limited partners.
Our general and administrative expenses per Mcfe produced increased to $0.18 per
Mcfe in 2001 from $0.13 per Mcfe in 2000 and $0.10 per Mcfe in 1999. The portion
of supervision fees netted from general and administrative expenses was $3.1
million for 2001, $3.4 million for 2000, and $3.2 million for 1999.

Depreciation, depletion, and amortization of our assets, or DD&A, increased
$11.7 million, or 25%, in 2001 from 2000, while 2000 DD&A increased $5.4
million, or 13%, from 1999 levels. In 2001, the increase was primarily due to
additional dollars spent to add to our reserves and increased associated service
costs

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in an environment where demand for such services had increased compared to 2000,
along with a 6% increase in production. In 2000, the increase was primarily due
to the additional dollars spent to add to our reserves and associated costs in
2000 over 1999. Our DD&A rate per Mcfe of production was $1.33 in 2001, $1.13 in
2000, and $0.99 in 1999, reflecting variations in per unit cost of reserves
additions.

Our production costs in 2001 increased $7.5 million, or 26%, over such
expenses in 2000, while those expenses in 2000 increased $9.6 million, or 49%,
over 1999 costs. Our production costs per Mcfe produced were $0.82 in 2001,
$0.69 in 2000, and $0.46 in 1999. The portion of supervision fees netted from
production costs was $3.1 million for 2001, $3.4 million for 2000, and $3.2
million for 1999. Approximately $1.7 million of the increase in production costs
during 2001 was related to severance taxes. Severance taxes increased primarily
from the expiration of certain specific well severance tax exemptions. The
remainder of the increase reflected costs associated with new wells drilled and
acquired and the related increase in costs in procuring such services in an
environment where demand for such services has increased from the prior year.

While our production costs increased 49% in 2000, our oil and gas sales
increased 74%. That increase in oil and gas sales had a direct impact on the
increase in production costs, as severance taxes have a direct correlation to
sales and were $4.9 million higher in 2000. Also, the increase in commodity
prices brought increased demand and competition for field services that resulted
in an increase in the cost of those services. Remedial well work and workover
costs increased $1.2 million over 1999 levels. In the Masters Creek area,
salt-water disposal charges, which increased $0.4 million over 1999 charges,
increased as the volume of water associated with that production increased. Also
in the Masters Creek area, production chemical costs increased $0.6 million as
we began our scale inhibitor program in that area.

Interest expense on our Senior Notes issued in July 1999, including
amortization of debt issuance costs, totaled $13.1 million in both 2001 and 2000
and $5.3 million in 1999. Interest expense on our Convertible Notes due 2006,
including amortization of debt issuance costs, totaled $7.4 million in 2000 and
$7.5 million in 1999. Interest expense on the credit facility, including
commitment fees and amortization of debt issuance costs, totaled $5.8 million in
2001, $0.7 million in 2000 and $6.1 million in 1999. The total interest expense
in 2001 was $18.9 million, of which $6.3 million was capitalized. The 2000 total
interest expense was $21.2 million, of which $5.2 million was capitalized. The
1999 total interest expense was $18.9 million, of which $4.5 million was
capitalized. We capitalize that portion of interest related to our exploration,
partnership, and foreign business development activities. The decrease in total
interest expense in 2001 was attributed to the conversion and extinguishment of
our Convertible Notes in December 2000 and the increase in capitalized interest,
partially offset by the increase in interest paid on our credit facility. The
increase in interest expense in 2000 was attributed to the replacement of our
bank borrowings in August 1999 with the Senior Notes that carry a higher
interest rate.

In the fourth quarter of 2001, we took a domestic non-cash write-down of
oil and gas properties, as discussed in Note 1 to the Consolidated Financial
Statements. Lower prices for both oil and natural gas at December 31, 2001,
necessitated a pre-tax domestic full cost ceiling write-down of $98.9 million,
or $63.5 million after tax. In addition to this domestic ceiling write-down, we
expensed $2.1 million of non-recurring charges in the fourth quarter of 2001 for
certain delinquent accounts receivable, the majority of which was related to gas
sold to Enron, and a write-off of debt issuance costs for a planned offering
that was cancelled based upon market conditions following the events of
September 11, 2001.

As discussed in Note 1 to the Consolidated Financial Statements, we adopted
SFAS No. 133, amended by SFAS No. 137 and SFAS No. 138, on January 1, 2001. Our
adoption of SFAS No. 133 resulted in a one-time net of taxes charge of $392,868,
which is recorded as a Cumulative Effect of Change in Accounting Principle on
our Consolidated Statement of Income.

In the fourth quarter of 2000, we recorded a $0.6 million non-recurring
loss on the early extinguishment of debt (net of taxes), as discussed in Note 4
to the Consolidated Financial Statements. We called our Convertible Notes for
redemption effective December 26, 2000. Holders of approximately $100.0 million
of the Convertible Notes elected to convert their notes into shares of our
common stock.

S-23

Holders of the remaining $15.0 million of the Convertible Notes elected to
redeem their notes for cash plus accrued interest. This cash redemption resulted
in this non-recurring item.

NET INCOME (LOSS). Our loss before extraordinary item and change in
accounting principle in 2001 of $(22.0) million was 137% lower and Basic loss
per share ("Basic EPS") before extraordinary item and change in accounting
principle of $(0.89) was 132% lower than our 2000 net income of $59.8 million
and Basic EPS of $2.82. These decreases reflected the effect of $101.0 million
in non-recurring charges in 2001 as described above. The lower percentage
decrease in Basic EPS reflects a 16% increase in weighted average shares
outstanding in 2001, primarily due to the conversion of our Convertible Notes
into 3.2 million shares of common stock in December 2000.

Our net loss for 2001 was $(22.3) million with a loss per share of $(0.90)
per diluted share. Our net income for 2001, excluding non-recurring charges of
$101.0 million as described above, totaled $42.5 million with EPS of $1.67 per
diluted share. These amounts are lower than our 2000 net income of $59.8 million
and EPS of $2.53 per diluted share, primarily due to significantly lower oil
prices and overall increased costs.

Our income before extraordinary item in 2000 of $59.8 million was 210%
higher and Basic EPS before extraordinary item of $2.82 was 164% higher than our
1999 net income of $19.3 million and Basic EPS of $1.07. These increases
reflected the effect of the 75% increase in average oil prices received and 77%
increase in average gas prices received. Oil and gas prices rose each quarter
and resulted in quarterly sequential increases in earnings. The lower percentage
increase in Basic EPS reflects an 18% increase in weighted average shares
outstanding in 2000, primarily due to our third-quarter 1999 public sale of 4.6
million shares of common stock.

RELATED-PARTY TRANSACTIONS

We are the operator of a number of properties owned by our affiliated
limited partnerships and joint ventures and, accordingly, charge these entities
and third-party joint interest owners operating fees. The operating fees charged
to the partnerships in 2001, 2000, and 1999 totaled approximately $925,000,
$1,775,000, and $1,970,000, respectively. We are also reimbursed for direct,
administrative, and overhead costs incurred in conducting the business of the
limited partnerships, which totaled approximately $3,140,000, $4,465,000, and
$4,000,000 in 2001, 2000, and 1999, respectively. In partnerships in which the
limited partners have voted to sell their remaining properties and liquidate
their limited partnerships, we are also reimbursed for direct, administrative,
and overhead costs incurred in the disposition of such properties, which costs
totaled approximately $2,360,000, $1,220,000, and $850,000 in 2001, 2000, and
1999, respectively.

CONTRACTUAL COMMITMENTS AND OBLIGATIONS

Our contractual commitments for the next four years and thereafter are as
follows:

2002 2003 2004 2005 THEREAFTER TOTAL
---------- ---------- ---------- ------------ ------------ ------------

Non-cancelable operating lease
commitments....................... $1,393,095 $1,480,092 $1,492,268 $ 248,711 $ -- $ 4,614,166
Senior Subordinated Notes due August
2009.............................. -- -- -- -- 125,000,000 125,000,000
Credit Facility which expires in
October 2005(1)................... -- -- -- 134,000,000 -- 134,000,000
---------- ---------- ---------- ------------ ------------ ------------
$1,393,095 $1,480,092 $1,492,268 $134,248,711 $125,000,000 $263,614,166
========== ========== ========== ============ ============ ============

(1) The repayment of the credit facility is based upon the balance at December
31, 2001. The amount borrowed under this facility has increased from 2001
year end levels. This amount excludes $0.8 million of a standby letter of
credit issued under this facility.

S-24

LIQUIDITY AND CAPITAL RESOURCES

During 2001, we relied both upon internally generated cash flows of $139.9
million and $123.4 million of additional borrowings from our bank credit
facility to fund capital expenditures of $275.1 million. During 2000, we
primarily used internally generated cash flows of $128.2 million to fund capital
expenditures of $173.3 million, along with the remaining net proceeds from our
third quarter 1999 issuance of Senior Notes and common stock.

NET CASH PROVIDED BY OPERATING ACTIVITIES. In 2001, net cash provided by
our operating activities increased by 9% to $139.9 million, as compared to
$128.2 million in 2000 and $73.6 million in 1999. The 2001 increase of $11.7
million was primarily due to reductions in working capital as oil and gas sales
receivables decreased in 2001 along with a reduction in interest expense of $3.3
million. These increases in cash flow were offset by an $8.0 million reduction
of oil and gas sales, a $7.5 million increase in oil and gas production costs,
and a $2.6 million increase in general and administrative expense. The 2000
increase of $54.6 million was primarily due to $80.2 million of additional oil
and gas sales, partially offset by $12.2 million of increases in oil and gas
production costs, general and administrative expenses, and interest expense.

EXISTING CREDIT FACILITIES. At December 31, 2001, we had $134.0 million in
outstanding borrowings under our credit facility. Our credit facility at year
end 2001 consisted of a $250.0 million revolving line of credit with a $200.0
million borrowing base. The borrowing base is redetermined at least every six
months. Our revolving credit facility includes, among other restrictions,
requirements as to maintenance of certain minimum financial ratios (principally
pertaining to working capital, debt, and equity ratios) and limitations on
incurring other debt. We are in compliance with the provisions of this
agreement. The credit facility extends until October 2005. At December 31, 2000,
we had $10.6 million in outstanding borrowings under this facility.

Subsequent to December 31, 2001, upon the closing of the New Zealand TAWN
acquisition, the credit facility was increased to $300.0 million and the
borrowing base became $275.0 million. Our bank facility is described in more
detail in "Description of Existing Indebtedness."

WORKING CAPITAL. Our working capital further declined from a deficit of
$22.5 million at December 31, 2000, to a deficit of $36.5 million at December
31, 2001. The decrease was primarily due to reductions in oil and gas sales
receivables, as oil and gas prices were lower at year end 2001, and an increase
in payables to partnerships related to December 2001 oil and gas property sales.

CAPITAL EXPENDITURES IN 2001. Our capital expenditures of approximately
$275.1 million included:

Domestic activities of $224.3 million as follows:

- $120.6 million, or 44%, for developmental drilling;

- $40.5 million, or 15%, for producing properties acquisitions, with
approximately $32.6 million spent on the Lake Washington acquisition and
the remainder for the purchase of property interests from partnerships
managed by us;

- $36.4 million, or 13%, for exploratory drilling;

- $25.3 million, or 9%, for domestic prospect costs, principally leasehold,
seismic, and geological costs;

- $1.1 million, or less than 1%, for fixed assets;

- $0.3 million for field compression facilities; and

- $0.1 million for gas processing plants in the Brookeland and Masters
Creek areas.

S-25

New Zealand activities of $50.8 million as follows:

- $19.0 million, or 7%, for developmental drilling to further delineate the
Rimu and Kauri areas;

- $17.9 million, or 7%, for the Rimu Production Station;

- $7.2 million, or 3%, for exploratory drilling in the Rimu and Kauri
areas;

- $5.5 million, or 2%, for prospect costs, principally seismic and
geological costs;

- $0.8 million, or less than 1%, for producing properties acquisition
evaluation costs related to our TAWN acquisition; and

- $0.4 million for fixed assets, principally computers and office furniture
and fixtures.

In 2001, we participated in drilling 40 development wells and 13
exploratory wells, of which 38 development wells and six exploratory wells were
successes. Four of the development wells were drilled in New Zealand to
delineate the Rimu and Kauri areas, two of which were successful. Two of the
exploratory wells were drilled in New Zealand; one unsuccessful and one was
temporarily abandoned. Of our $95.9 million of unproved property costs, $72.3
million relates to our inventory of developmental and exploratory acreage to
sustain drilling activity for future growth, while the remaining $23.6 million
pertains to the Rimu Production Station which will be reclassified to proved
properties once it comes on-line near the end of the first quarter of 2002.

CAPITAL EXPENDITURES FOR 2002. We estimate we will spend approximately
$132.5 million during 2002. Approximately $39.8 million of the 2002 budget is
allocated to domestic drilling, primarily in the Lake Washington area. In New
Zealand, approximately $11.2 million of the 2002 budget is allocated to
drilling, with another $8.7 million expected to be spent primarily for
production facilities. In 2002, we anticipate drilling 20 development wells and
2 exploratory wells domestically, along with six development wells and one
exploratory well in New Zealand. Approximately $54.6 million is targeted towards
producing property acquisitions, the majority for the TAWN properties in New
Zealand that closed in January 2002. Of the remainder, $13.5 million will be
used primarily for domestic leasehold, seismic, and geological costs, and $4.7
million is budgeted for such costs in New Zealand. This $132.5 million budget
also excludes any producing property acquisitions that may arise in this low
price environment and also excludes any property sales. Although we expect our
2002 total production to increase by 10% to 20% over 2001 due to the focus of
our budget in the Lake Washington area and in New Zealand, we expect production
to decline in our other core areas as no new drilling is currently budgeted to
offset their natural production decline.

We believe that the anticipated internally generated cash flows for 2002,
together with bank borrowings under our credit facility, will be sufficient to
finance the costs associated with our currently budgeted 2002 capital
expenditures. Should other producing property acquisitions activity become
attractive in the current environment, we intend to explore the use of debt and
or equity offerings to fund such activity.

CAPITAL EXPENDITURES IN 2000 AND 1999. Our capital expenditures were
approximately $173.3 million in 2000 and $78.1 million in 1999. During 1999, we
used internally generated cash flows of $73.6 million to fund capital
expenditures of $78.1 million. During 2000, we primarily used internally
generated cash flows of $128.2 million to fund capital expenditures of $173.3
million, along with part of the remaining net proceeds from our third quarter
1999 issuance of Senior Notes and common stock. Our capital expenditures in 2000
included:

Domestic activities of $157.9 million as follows:

- $90.3 million, or 52%, for developmental drilling;

- $33.4 million, or 19%, for producing properties acquisitions,
approximately half of which was for the purchase of property interests
from partnerships managed by us, with the other half purchased from a
third party;

S-26

- $16.3 million, or 9%, for domestic prospect costs, principally leasehold,
seismic, and geological costs;

- $15.5 million, or 9%, for exploratory drilling;

- $1.4 million, or 1%, for fixed assets;

- $0.8 million, or less than 1%, for gas processing plants in the
Brookeland and Masters Creek areas; and

- $0.2 million for field compression facilities.

New Zealand activities of $15.4 million as follows:

- $7.6 million, or 4%, for developmental drilling to further delineate the
Rimu area;

- $4.5 million, or 3%, for prospect costs, principally seismic and
geological costs;

- $2.1 million, or 1%, for exploratory drilling;

- $1.1 million, or 1%, for the initial stages of production facilities; and

- $0.1 million, or less than 1%, for fixed assets, principally a field
office and warehouse.

In 2000, we participated in drilling 61 development wells and nine
exploratory wells, of which 54 development wells and five exploratory wells were
successes. Two of the development wells were drilled in New Zealand to delineate
the Rimu area, both of which were successful.

S-27

BUSINESS AND PROPERTIES

GENERAL

We currently focus our business in the following six core areas:

- AWP Olmos -- South Texas

- Masters Creek -- Central Louisiana

- Brookeland -- East Texas

- Lake Washington -- South Louisiana

- Rimu/Kauri -- New Zealand

- TAWN -- New Zealand

COMPETITIVE STRENGTHS AND BUSINESS STRATEGY

We believe that we have the competitive strengths that together with a
balanced and comprehensive business strategy provide us with the flexibility and
capability to accomplish our goals.

Successful track record

Our growth in reserves and production has resulted primarily from drilling
activities in our core areas combined with producing property acquisitions. In
2001, we increased our proved reserves by 3%, which replaced 136% of our 2001
production. Our net cash provided by operations increased from $37.1 million in
1996 to $139.9 million in 2001. While 2001 production increased 6% in relation
to 2000 production, we have increased our production from 19.4 Bcfe in 1996 to
44.8 Bcfe in 2001. We believe our experience in growing our reserves will be
beneficial to us as we continue to pursue our business strategy.

Balanced Approach to Adding Reserves

Over the past five years, we have spent an average of 11% of our capital
expenditure budget on exploration drilling, 51% on development activities, 19%
on proved property acquisitions and 14% on lease acquisitions. When we believe
the market favors increasing reserves through acquisitions, we apply our
considerable experience in evaluating and negotiating prospective acquisitions.
For example, in 1998, when commodity prices were relatively weak, 32% of our
capital expenditures consisted of property acquisitions, with 37% committed to
our drilling activities. In contrast, in 2001, when commodity prices were
relatively strong in the first half of the year, only 15% of our capital
expenditures were spent on property acquisitions, with our drilling expenditures
increasing to 67% of total capital expended. We believe this balanced approach
has resulted in our ability to grow reserves in a relatively low cost manner,
while participating in the upside potential of exploration. Over the five-year
period ended December 31, 2001, we replaced 302% of our production at an average
cost of $1.26 per Mcfe.

In this current environment of stronger oil prices in relation to gas
prices, our 2002 capital expenditures are focused on developing and producing
long-lived oil reserves in Lake Washington and in the Rimu/Kauri area. Our
current focus on developing and acquiring long-lived reserves with an overall
flatter production decline curve should strengthen our ongoing production
profile and extend our average reserve life.

S-28

Concentrated Focus on Core Areas

Our concentration of reserves and our significant acreage positions in our
core areas allow us to realize economies of scale in drilling and production. We
enhance the value of this concentration by acting as operator of 95% of our
proved reserves at year end 2001. Our operational control allows us to better
manage production, control our expenses, allocate capital and time field
development. We intend to continue to acquire large acreage positions in
under-explored and under-exploited areas where, as operator, we can exploit
successful discoveries to create new core areas or grow production from
developed fields. In executing this strategy:

- We focus our resources on acquiring properties that we can operate, and
in which we can obtain a significant working interest. With operational
control, we can apply our technical and operational expertise to optimize
our exploration and exploitation of the properties that we acquire.

- We acquire and operate domestic properties in a limited number of
geographic areas. Operating in a concentrated area helps us to better
control our overhead by enabling us to manage a greater amount of acreage
with fewer employees, minimizing incremental costs of increased drilling
and production.

- We continue to believe in natural gas prospects and reserves in the
United States. The natural gas market in the United States has a
well-developed infrastructure. Natural gas is viewed by many as the
preferred fuel in North America for several reasons, including
environmental concerns. We have a strong inventory of natural gas that
can be developed in a higher priced environment.

- We seek to operate large acreage positions with high exploration and
development potential. For example, on our original 100,000 acre New
Zealand permit, only two wells had been drilled at the time that we
acquired our interest. The Masters Creek, Brookeland and Lake Washington
areas also had significant additional development potential when we first
acquired our interest in those areas.

Ability to Build Upon our Successful Discoveries and Acquisitions in New
Zealand

During 2001 we produced and sold 84,261 Bbls on an extended production test
basis at an average sales price of $21.64 per Bbl from our Rimu and Kauri wells.
We have several exploration and delineation wells planned in the Rimu/Kauri
area, as well as prospective areas in New Zealand outside of the Rimu/Kauri area
that we will evaluate for drilling in the future.

In January 2002, we acquired the TAWN fields. From the closing of the TAWN
acquisition on January 25, 2002 through March 25, 2002, these fields have
generated an average daily net production of approximately 40 MMcfe. In our TAWN
acquisition, we also acquired extensive associated processing facilities and
pipelines, which give us a competitive advantage through infrastructure that
complements our existing fields, providing us with increased access to export
terminals and markets and additional excess processing capacity for both oil and
natural gas.

Experienced Technical Team

We employ oil and gas professionals, including geophysicists,
petrophysicists, geologists, petroleum engineers and production and reservoir
engineers, who have an average of approximately 25 years of experience in their
technical fields and have been employed by Swift for an average of over 10
years. We

S-29

continually apply our extensive in-house expertise and current advanced
technologies to benefit our drilling and production operations. We have
developed a particular expertise in drilling horizontal wells at vertical depths
below 10,000 feet, often in a high pressure environment, involving single or
dual lateral legs of several thousand feet. This results in an integrated
approach to exploration using multidisciplinary data analysis and interpretation
that has helped us identify a number of exploration prospects.

We use various recovery techniques, including water flooding and acid
treatments, fracturing reservoir rock through the injection of high-pressure
fluid, and inserting coiled tubing velocity strings to enhance and maintain gas
flow. We believe that the application of fracturing technology and coiled tubing
has resulted in significant increases in production and decreases in completion
and operating costs, particularly in our AWP Olmos area.

We have increasingly used seismic technology to enhance the results of our
drilling and production efforts, including 2-D and 3-D seismic analysis,
amplitude versus offset studies and detailed formation depletion studies. As a
result, we have maintained internal seismic expertise and have compiled an
extensive database.

When appropriate, we develop new applications for existing technology. For
example, in New Zealand we acquired seismic data by effectively combining marine
data with the acquisition of land seismic data, an application we have not seen
any other company use in New Zealand.

Financial Discipline

DOMESTIC CORE OPERATING AREAS

AWP Olmos Area

We began drilling and operating wells in the AWP Olmos area in 1988. Since
that time, we have gained extensive expertise with the low-permeability,
tight-sand formations typical of these fields. Our net proved reserves for this
area of 207.5 Bcfe as of December 31, 2001 constituted 32% of our total reserves
at that date. This field is characterized by long-lived reserves, with 74% of
the reserves at year end 2001 comprised of natural gas.

Additionally, AWP Olmos area has yielded a steady production base,
producing an average of approximately 35,700 Mcfe per day in 2001. We have
maintained these rates by performing fracture extensions and installing coiled
tubing velocity strings. During 2001, approximately 76% of our production from
this field was natural gas. As of December 31, 2001, we owned interests in 496
wells and were the operator of 492 wells in this area producing gas from the
Olmos Sand formation at depths from 10,000 to 11,500 feet. We own nearly a 100%
working interest in almost all wells in this area in which we have an

S-30

interest. As of December 31, 2001, we owned drilling and production rights to
approximately 28,562 net acres in this area in South Texas.

Geologically, this region is characterized by a blanket sand with an
extensive fault system. In 2001, all 11 development wells we drilled in the AWP
Olmos area were successful. As of December 31, 2001, we had 122 proved
undeveloped locations in this area. Our planned 2002 capital expenditures in
this area will focus on performing fracture extensions and installing coiled
tubing velocity strings.

Masters Creek Area

We acquired our interest in this area in mid-1998 as part of a larger
property acquisition. Located just east of the Texas-Louisiana border in the
Louisiana parishes of Vernon and Rapides, this area contains our operated fields
of Masters Creek and South Burr Ferry as well as other fields in which we have
interests, but which are operated by others. As of December 31, 2001, we owned
drilling and production rights to 194,212 gross acres, 149,400 net acres, and
141,000 fee mineral acres in this area.

The Masters Creek area contains horizontal wells producing both oil and gas
from the Austin Chalk formation. In 2001, this area produced 15.3 Bcfe. In 2001,
we drilled or participated in drilling nine development wells, all successful.
As of December 31, 2001, we had 18 proved undeveloped drilling locations.

Brookeland Area

This area is located in southeast Texas in Jasper and Newton counties near
the Texas-Louisiana border. This area also was a part of the 1998 property
acquisition in which we acquired our interest in the Masters Creek area and
contains horizontal wells producing both oil and gas from the Austin Chalk
formation. In 2001, we drilled or participated in the drilling of 11 development
wells, all successful. Our reserves in this area are approximately 60% oil and
natural gas liquids.

As of December 31, 2001, we owned drilling and production rights to 127,703
gross acres, 79,874 net acres, and 15,000 fee mineral acres containing
substantial proved undeveloped reserves. As of December 31, 2001, we had 17
proved undeveloped drilling locations in this field.

Lake Washington Field

We acquired interests in Lake Washington Field, located in Plaquemines
Parish, Louisiana, effective March 1, 2001. Lake Washington Field produces oil
from multiple Miocene sands ranging in depth from less than 2,000 feet to
greater than 10,000 feet. This field is located on a salt dome and has produced
over 300 million BOE since its inception. The area around the dome is heavily
faulted, thereby creating a large number of potential traps. Since our
acquisition of this field, we have mapped multiple zones covering all sides of
the salt dome. We see both significant development opportunities and several
distinct exploration plays on the property. Oil and gas from approximately 26
producing wells is gathered from four platforms located in water depths ranging
from six feet to 11 feet, with drilling and workover operations performed with
barge rigs. We have identified a number of under-exploited fault blocks in this
area.

In 2001, we drilled four development wells and one exploratory well, and in
2002 we drilled two additional wells and a salt water disposal well, all of
which were successful. As a result of our drilling and production activities, we
have increased average production in the field net to our interest from
approximately 652 BOE per day in March 2001, when we acquired the field, to
approximately 1,236 BOE per day during February 2002. As of December 31, 2001,
we owned drilling and production rights to 13,595 net acres. Our reserves in
this field are approximately 95% oil and natural gas liquids. As of year end
2001, we had 29 proved undeveloped drilling locations in this field. Our planned
2002 capital expenditures in this field are approximately $25.0 million and
include 20 development wells and two exploratory wells.

S-31

DOMESTIC EMERGING GROWTH AREAS

We are pursuing development and exploration activities in the following
emerging growth areas, including areas where we drilled a number of wells in
2001. The timing and scope of our drilling in these areas depends upon changes
in the relative prices of oil and gas and other market factors.

Frio (Garcia Ranch) Area in South Texas

This area, near the southern tip of Texas in Willacy and Kenedy counties,
features the Frio formation at depths ranging from 10,000 to 16,000 feet. The
traps are structure related and consist of faulted anticlines and three-way
upthrown fault traps. Our prospects are defined by 3-D seismic surveys that were
shot in the mid-1990s. We had two discoveries in the area in 2001, one in the
Rome prospect in Willacy County at a depth of 16,388 feet, and the other in the
Siena prospect in Kenedy County at a depth of 16,300 feet. We have a 65% working
interest in these prospects.

Wilcox Area in Texas Gulf Coast

This area is located along the Texas Gulf Coast in Goliad, Lavaca and
Zapata counties. Our primary objectives are the Austin, Nita, Cameron, Brandon,
Tina, Gracie, and Tyler Upper Wilcox sands. Traps in the Wilcox sand are both
structural and stratigraphic and include upthrown fault traps as well as buried
sand bars and sand channels, with formation depths ranging from 10,000 to 15,000
feet, as defined by both 2-D and 3-D seismic surveys.

Our 2001 exploration activity in this area had three discoveries in the
Wilcox sands, two of which were located in Goliad County, Texas: the Nita
prospect drilled to a depth of approximately 15,000 feet and the Brandon
prospect drilled to a depth of about 13,000 feet. Our working interests in these
two wells are 73% and 60%, respectively. The third well was in the Falcon Ridge
prospect in Zapata County, Texas in which we have a 25% working interest.

Additionally, in Lavaca County we have another Wilcox prospect, the Pearl
prospect. We currently have a 100% working interest in this prospect, but we
have undertaken to market interests in the prospect to potential industry
partners. The Pearl prospect has a projected depth for the test well of 14,500
feet. Additionally, we have other prospects in this area that we are considering
for our future drilling activities.

Woodbine Area in East Texas

The Woodbine formation is located in southeast Texas in San Jacinto, Polk
and Tyler counties. We drilled one well to the Woodbine formation during
2001 -- in the Lion prospect in San Jacinto County, Texas, to a depth of 15,800
feet. Although hydrocarbon-bearing intervals were found, the well was determined
to be noncommercial.

Additionally, we have two other Woodbine prospects for future drilling: the
Jaguar and Bobcat prospects, both located in Polk County, where we would serve
as operator with approximately a 75% working interest.

Miocene Area in South Louisiana

We successfully drilled our first exploratory well in the Miocene sands in
our new Lake Washington Area in Plaquemines Parish, Louisiana -- to a depth of
3,200 feet with a retained interest of 100%. This area has substantial
exploration and development potential, with sands extending from shallow depths
down to 10,000 feet or more. Current plans are to drill another exploratory well
in the area during 2002.

Also in Plaquemines Parish, about 50 miles north of the Lake Washington
Area, is the Delacroix area where we have been developing prospects for both
shallow and deep horizons in the Miocene sands. The first well in this area, in
the Grand Lake prospect, was drilled to a depth of 18,000 feet early in 2002 and
was temporarily abandoned but may become a possible sidetrack well in the
future.

S-32

NEW ZEALAND CORE OPERATING AREAS

Our activity in New Zealand began when we were issued two petroleum
exploration permits in 1995 and 1996, which we combined in 1998 after
surrendering a portion of this acreage. In 1999, we expanded this permit by
adding 12,800 offshore acres. As of December 31, 2001 our permit 38719 included
approximately 50,300 acres in the Taranaki Basin of New Zealand's North Island.
We have a 95% working interest in this permit, and have fulfilled all current
obligations under this permit. The initial five-year term of the permit ended on
August 12, 2001. We have, however, extended our petroleum exploration permit an
additional five years by relinquishing 50% of the acreage within the permit
under the terms of the Crown Minerals Act of 1991. Specifically, we have chosen
to relinquish acreage on the western and eastern portions of our permit that we
feel is not prospective. The approximately 50,300 gross acres that we retain
include all of the acreage that we believe is prospective, and include our Rimu
and Kauri areas as well as our Tawa and Matai prospects.

As of December 31, 2001, our investment in New Zealand totaled
approximately $84.4 million. Approximately $45.6 million of our investment costs
have been included in the proved properties portion of our oil and gas
properties and $38.8 million is included as unproved properties. After giving
effect to our acquisitions in the first quarter of 2002, our total investment in
New Zealand would have been $143.5 million, $54.4 million of which was used to
acquire the TAWN assets, containing all proved producing reserves, and $4.7
million of which was used to acquire the Antrim assets.

At year end 2001, our proved reserves in the Rimu/Kauri area were estimated
at 101.9 Bcfe, with 64% of such reserves classified as oil, natural gas liquids
and condensates. We built production and processing facilities, which are
initially designed to handle 3,500 Bbls of oil per day and 10,000 Mcf of
processed natural gas per day. These facilities will allow us to commence sale
of production from our Rimu discovery in April 2002. We recently entered into an
agreement to sell to Genesis Power Limited approximately 38.0 Bcf of natural gas
over a 10-year period. Natural gas deliveries from our Rimu discovery will begin
under this contract once the Rimu production station is operational.

We expanded our operation in New Zealand in January 2002 with our purchase
of Southern NZ Exploration, Ltd., from Shell New Zealand, through which we
acquired interests in four fields and significant infrastructure assets. We have
estimated the proved reserves associated with the TAWN acquisition at year end
2001 to be approximately 62.1 Bcfe, of which approximately 75% is natural gas.
First quarter 2002 net daily production from the TAWN fields is estimated to be
1,071 Bbl of oil, 30 MMcf of natural gas, and 561 Bbl of natural gas liquids per
day, or a total net daily production of approximately 40 MMcfe of natural gas
per day.

Rimu Area

In 1996 we acquired our interest in permit 38719, which is located in the
eastern onshore portion of the Taranaki Basin in New Zealand. In 1997, we
acquired 2-D seismic data for two key areas in this permit. Based on analysis of
this data, the first exploratory well, Rimu-A1, was drilled onshore in 1999. In
late 1999, we successfully completed and production tested the Rimu-A1. Based
upon additional 2-D seismic data acquired in March 2000, which better identified
the extent of the Rimu structure, we drilled and tested two delineation wells,
the Rimu-B1 and the Rimu-B2. In 2001 we have drilled and tested three more Rimu
delineation wells, the Rimu-A2, Rimu-A3 and Rimu-B3. The Rimu-A3 was successful;
the Rimu-A2 and Rimu-B3 were dry. Early in 2002, the Rimu-A2 was sidetracked and
was successfully completed. The Rimu-B3 was also sidetracked in early 2002 and
again was unsuccessful.

Early in 2002, we were awarded petroleum mining permit 38151 by the New
Zealand Ministry for Economic Development for the development of the Rimu
discovery over a 5,524-acre area for a primary term of 30 years. We plan to add
up to three drilling pads in the permit area, for a total of five pads, with
each able to handle multiple wells. Nine additional wells are currently planned
within the mining permit, one gas injection well and eight development wells
targeting the Upper Tariki and Lower Tariki sandstones and the Upper Rimu
limestone.

S-33

Kauri Area

In 2000, we acquired approximately 45 miles of data from a number of 2-D
transitional zone seismic lines tied to existing marine and land seismic grids
to study the Kauri structure, which is to the south and southeast of our Rimu
discovery. We based our well location on our interpretation of these data. We
drilled our Kauri-A1 well to a total depth of 14,760 feet in the third quarter
of 2001. We encountered significant hydrocarbon-bearing intervals in this well,
and we intend to conduct extensive testing and analysis on these intervals in
the future.

The initial hydrocarbon-bearing zone encountered in the Kauri-A1 well was
found in a shallow section of the Miocene-Pliocene age sandstones, the Manutahi
sand, beginning at a depth of 3,746 feet. Petrophysical analysis of logging
data, along with laboratory analysis of sidewall cores, confirm an oil column of
approximately 39 feet with excellent porosities and permeabilities. Based on
electric log analysis and saturation measurements of the sidewall cores, an
oil/water contact was found at 3,815 feet. Current geologic mapping indicates
that this location is approximately 66 feet low to the top of the structure that
covers approximately 1,000 acres of aerial extent in this fault block. We
commenced drilling the Kauri-A2 development well in September 2001 in order to
further evaluate this prospective interval. This well successfully tested the
Manutahi Sands.

The second significant hydrocarbon-bearing interval encountered in the
Kauri-A1 well was found in the Miocene age sandstones, the Kauri sand, beginning
at a depth of 9,473 feet. This interval largely consists of multiple sections of
sandstones and claystones that yielded oil and gas shows associated with
drilling breaks and appears to be hydrocarbon bearing based on log analysis.
Further petrophysical analysis of this data indicates a hydrocarbon-bearing
sandstone interval of approximately 577 feet with good porosity. This same
interval was also encountered, although not tested, in all of the previously
drilled Rimu wells, with varying degrees of hydrocarbon shows. This interval in
the Kauri-A1 well has greater sand development than in the Rimu wells, with mud
log shows while drilling significantly better than in any of the previous wells
drilled at Rimu.

The third and fourth hydrocarbon-bearing intervals encountered in this well
were found in the Upper Tariki sand beginning at a depth of 11,126 feet and the
Upper Rimu limestone beginning at a depth of 11,270 feet. Both of these
intervals have also been present in all five wells drilled at Rimu, extending
both of these intervals over a distance in excess of five miles. Based upon
analysis of mud logs as well as the logging while drilling tools, the Upper
Tariki appears to have a gross thickness of 30 feet and the Upper Rimu limestone
appears to have a gross thickness of 33 feet.

The Kauri-B1 exploratory well was drilled approximately 1.75 miles to the
southeast of the Kauri-A pad and targeted the Manutahi sands. This well was
plugged and abandoned in late 2001.

TAWN Assets

The TAWN acquisition consisted of a 96.76% working interest in four
petroleum mining licenses, or PML, covering producing oil and gas fields, and
extensive associated hydrocarbon-processing facilities and pipelines, which give
us a competitive advantage through infrastructure that complements our existing
fields, providing us with increased access to export terminals and markets and
additional excess processing capacity for both oil and natural gas. The TAWN
assets are located approximately 17 miles north of the Rimu area.

The properties are collectively identified as the TAWN properties, an
acronym derived from the first letters of the field names -- the Tariki Field
(PML 38138), the Ahuroa Field (PML 38139), the Waihapa Field (PML 38140), and
the Ngaere Field (PML 38141). The Tariki Field and Ahuroa Field both produce
from the Tariki formation, while the Waihapa Field and Ngaere Field produce from
the Tikorangi formation. The four fields include 17 wells where the purchaser of
gas has contracted to take minimum gas quantities and can call for higher
production levels (which has occurred throughout 2002) to meet electrical demand
in New Zealand.

S-34

Solution gas gathered from an oil facility, the Waihapa Production Station,
or WPS, flows to the Tariki Ahuroa gas plant. The current processing capacity of
the WPS facility is over 15,000 bbl of oil and 40 MMcf of natural gas per day. A
32 mile, eight inch diameter oil export line runs from the WPS to the Omata Tank
Farm at New Plymouth, where oil export facilities allow for sales into
international markets. An additional 32 mile, eight inch diameter natural gas
pipeline runs from the WPS to the Taranaki Combined Cycle Electric Generation
Facility near Stratford and on to the New Plymouth Power Station.

We have a service agreement with the owner of the Omata Tank Farm to
utilize the blending, storage, and export capabilities of the facility. The
operator of the facility provides services for a fixed fee per barrel received
and other variable costs as required by the agreement. Under the terms of the
agreement, crude oil produced from the Rimu/Kauri area will also have access to
the Omata Tank Farm.

NEW ZEALAND EMERGING GROWTH AREAS

Tawa Prospect

The Tawa prospect is located on the southeast flank of Kapuni Field and its
main targets are the Tikorangi limestone, the Upper Otaraoa sandstone and the
Tariki sandstone. This is a combination structural and stratigraphic trap. This
prospect was developed based upon our analysis of existing 3-D seismic data as
well as new 2-D seismic surveys we acquired in 1997 and 2000.

Matai Prospect

The Matai prospect is located on the southeast flank of the Tawa prospect
and its main target is the Moki sandstone. This prospect was identified based
upon our analysis of new 2-D seismic data we acquired in 2000. We acquired
additional seismic data in early 2002 to further evaluate this prospect.

Tuihu Prospect

In 2000, we entered into an agreement with Shell New Zealand whereby we
earned a 20% participating interest in petroleum exploration permit 38718
containing approximately 57,400 acres. In January 2001, the operator temporarily
abandoned the Tuihu #1 exploratory well pending further analysis. The permit now
contains approximately 28,700 acres after a scheduled acreage surrender during
December 2000. Additional analysis of the data from the well, as well as
reinterpretation of the seismic data, is underway in order to determine further
development plans.

Huinga Prospect

In 1998, we entered into agreements for a 7.5% working interest held by
Antrim Oil and Gas Limited, a Canadian company, in permit 38716 operated by
Marabella Enterprises Ltd. In turn, Antrim became 5% working interest owners in
our permit 38719. An exploratory well was drilled on the 7.5% working interest
permit and the well has been temporarily abandoned pending further evaluation.
Operations to re-enter and sidetrack this well commenced in April 2002 to target
a location to the west of the initial well. A five year extension was granted on
this permit in 2001 upon the surrender of 50% of the acreage. As part of our
March 2002 acquisition of Antrim's New Zealand assets, we acquired an additional
7.5% working interest in permit 38716, giving us a current 15.0% working
interest in this prospect.

OIL AND GAS RESERVES

The following table presents information regarding proved reserves of oil
and gas attributable to our interests in producing properties as of December 31,
2001, 2000, and 1999. The information set forth in the table regarding reserves
is based on proved reserves reports prepared by us and audited by H. J. Gruy and
Associates, Inc., Houston, Texas, independent petroleum engineers. Gruy's audit
was based upon

S-35

review of production histories and other geological, economic, ownership, and
engineering data provided by us.

In accordance with Securities and Exchange Commission guidelines, estimates
of future net revenues from our proved reserves and the PV-10 Value must be made
using oil and gas sales prices in effect as of the dates of such estimates and
are held constant throughout the life of the properties, except where such
guidelines permit alternate treatment, including, in the case of gas contracts,
the use of fixed and determinable contractual price escalations. Proved reserves
as of December 31, 2001, were estimated based upon prices in effect at year end.
The weighted averages of such year end prices domestically were $2.68 per Mcf of
natural gas and $18.51 per barrel of oil, compared to $11.25 and $25.50 at year
end 2000 and $2.58 and $23.69 at year end 1999. The weighted averages of such
year end 2001 prices for New Zealand were $1.18 per Mcf of natural gas and
$18.25 per barrel of oil, compared to $0.71 and $22.30 in 2000. The weighted
averages of such year end 2001 prices for all our reserves, both domestically
and in New Zealand, were $2.51 per Mcf of natural gas and $18.45 per barrel of
oil, compared to $9.86 and $24.62 in 2000. We have interests in certain tracts
that are estimated to have additional hydrocarbon reserves that cannot be
classified as proved and are not reflected in the following table. The proved
reserves presented for all periods also exclude any reserves attributable to the
volumetric production payment that was in effect in 2000 and 1999.

At year end 2001, 50% of our proved reserves were developed reserves. At
year end 2000, 45% of our proved reserves were developed.

Changes in quantity estimates and the estimated present value of proved
reserves are affected by the change in crude oil and natural gas prices at the
end of each year. While our total proved reserves quantities, on an equivalent
Bcfe basis, at year end 2001 increased by 3% over reserves quantities a year
earlier, the PV-10 Value of those reserves decreased 74% from the PV-10 Value at
year end 2000. The decrease in prices resulted in 47.1 Bcfe of downward reserve
revision, primarily attributed to the decrease in prices used at year end 2001.
Our total proved reserves quantities at year end 2000 increased by 38% over
reserves quantities a year earlier, while the PV-10 Value of those reserves
increased 310% from the PV-10 Value at year end 1999. The PV-10 Value decrease
in 2001 and the PV-10 increase in 2000 were heavily influenced by pricing
decreases at year end 2001 as compared to year end 2000 and by pricing increases
from year end 2000 as compared to year end 1999. Product prices for natural gas
decreased 75% during 2001, from $9.86 per Mcf at December 31, 2000, to $2.51 per
Mcf at year end 2001, while oil prices decreased 25% between the two dates, from
$24.62 to $18.45 per barrel. Product prices for natural gas increased 282%
during 2000, from $2.58 per Mcf at December 31, 1999, to $9.86 per Mcf at year
end 2000, while oil prices increased 4% between the two dates, from $23.69 to
$24.62 per barrel. Product prices for natural gas increased 16% during 1999,
from $2.23 per Mcf at December 31, 1998, to $2.58 per Mcf at year end 1999,
matched by a 111% increase in the price of oil between the two dates, from
$11.23 to $23.69 per barrel.

The table 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 their PV-10 Value. Operating costs, development costs, and certain
production-related taxes were deducted in arriving at the estimated future net
revenues. No provision was made for income taxes. The estimates of future net
revenues and their present value differ in this respect from the standardized
measure of discounted future net cash flows of $454.6 million at year end 2001,
$1,578.0 million at year end 2000 and $438.9 million at year end 1999 set forth
in Supplemental Information to our Consolidated Financial Statements, which is
calculated after provision for future income taxes.

S-36

YEAR ENDED DECEMBER 31, 2001
--------------------------------------------------
TOTAL DOMESTIC NEW ZEALAND
-------------- -------------- ------------

ESTIMATED PROVED OIL AND GAS RESERVES
Net natural gas reserves (Mcf):
Proved developed................................... 181,651,578 167,401,736 14,249,842
Proved undeveloped................................. 143,260,547 121,087,764 22,172,783
-------------- -------------- ------------
Total....................................... 324,912,125 288,489,500 36,422,625
============== ============== ============
Net oil reserves (Bbl):
Proved developed................................... 23,759,574 20,393,142 3,366,432
Proved undeveloped................................. 29,723,062 22,171,591 7,551,471
-------------- -------------- ------------
Total....................................... 53,482,636 42,564,733 10,917,903
============== ============== ============
ESTIMATED PRESENT VALUE OF PROVED RESERVES
Estimated present value of future net cash flows from
proved reserves discounted at 10% per annum:
Proved developed................................... $ 344,478,834 $ 306,095,381 $ 38,383,453
Proved undeveloped................................. 258,507,354 186,012,413 72,494,941
-------------- -------------- ------------
Total....................................... $ 602,986,188 $ 492,107,794 $110,878,394
============== ============== ============

YEAR ENDED DECEMBER 31, 2000
--------------------------------------------------
TOTAL DOMESTIC NEW ZEALAND
-------------- -------------- ------------

ESTIMATED PROVED OIL AND GAS RESERVES
Net natural gas reserves (Mcf):
Proved developed................................... 215,169,833 215,169,833 --
Proved undeveloped................................. 203,444,143 148,130,666 55,313,477
-------------- -------------- ------------
Total....................................... 418,613,976 363,300,499 55,313,477
============== ============== ============
Net oil reserves (Bbl):
Proved developed................................... 10,980,196 10,980,196 --
Proved undeveloped................................. 24,153,400 12,962,513 11,190,887
-------------- -------------- ------------
Total....................................... 35,133,596 23,942,709 11,190,887
============== ============== ============
ESTIMATED PRESENT VALUE OF PROVED RESERVES
Estimated present value of future net cash flows from
proved reserves discounted at 10% per annum:
Proved developed................................... $1,257,570,764 $1,257,570,764 $ --
Proved undeveloped................................. 1,055,684,045 919,388,009 136,296,036
-------------- -------------- ------------
Total....................................... $2,313,254,809 $2,176,958,773 $136,296,036
============== ============== ============

YEAR ENDED DECEMBER 31, 1999
--------------------------------------------------
TOTAL DOMESTIC NEW ZEALAND
-------------- -------------- ------------

ESTIMATED PROVED OIL AND GAS RESERVES
Net natural gas reserves (Mcf):
Proved developed................................... 174,046,096 174,046,096 --
Proved undeveloped................................. 155,913,654 155,913,654 --
-------------- -------------- ------------
Total....................................... 329,959,750 329,959,750 --
============== ============== ============
Net oil reserves (Bbl):
Proved developed................................... 8,437,299 8,437,299 --
Proved undeveloped................................. 12,368,964 12,368,964 --
-------------- -------------- ------------
Total....................................... 20,806,263 20,806,263 --
============== ============== ============
ESTIMATED PRESENT VALUE OF PROVED RESERVES
Estimated present value of future net cash flows from
proved reserves discounted at 10% per annum:
Proved developed................................... $ 301,199,660 $ 301,199,660 $ --
Proved undeveloped................................. 262,854,849 262,854,849 --
-------------- -------------- ------------
Total....................................... $ 564,054,509 $ 564,054,509 $ --
============== ============== ============

S-37

Proved reserves are estimates of hydrocarbons to be recovered in the
future. Reservoir engineering is a subjective process of estimating the sizes of
underground accumulations of oil and gas that cannot be measured in an exact
way. The accuracy of any reserves estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Reserves reports of other engineers might differ from the reports contained
herein. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimate. Future prices received for
the sale of oil and gas may be different from those used in preparing these
reports. The amounts and timing of future operating and development costs may
also differ from those used. Accordingly, reserves estimates are often different
from the quantities of oil and gas that are ultimately recovered. There can be
no assurance that these estimates are accurate predictions of the present value
of future net cash flows from oil and gas reserves.

A portion of our proved reserves has been accumulated through our interests
in the limited partnerships for which we serve 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 we own interests will
achieve payout status in the future. At December 31, 2001, 32 of the limited
partnerships managed by us had achieved payout status.

No other reports on our reserves have been filed with any federal agency.

OIL AND GAS WELLS

As we continue to sell properties on behalf of limited partnerships which
have voted to liquidate, our total well count decreased. Acquisitions such as
Lake Washington, where we own nearly a 100% interest in all operated wells, have
increased well ownership on a net basis. The following table sets forth the
gross and net wells in which we owned an interest at the following dates:

OIL WELLS GAS WELLS TOTAL WELLS(1)
--------- --------- --------------

DECEMBER 31, 2001
Gross.................................................... 396 786 1,182
Net...................................................... 297.0 467.9 764.9
DECEMBER 31, 2000
Gross.................................................... 599 904 1,503
Net...................................................... 165.2 484.7 649.9
DECEMBER 31, 1999
Gross.................................................... 577 947 1,524
Net...................................................... 105.5 449.2 554.7

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

(1) Excludes 48 service wells in 2001, 25 service wells in 2000, and 33 service
wells in 1999. Also excludes 5 wells in 2001 and 3 wells in 2000 in New
Zealand, temporarily shut-in awaiting the commissioning of the Rimu
Production Station.

OIL AND GAS ACREAGE

As is customary in the industry, we generally acquire oil and gas acreage
without any warranty of title except as to claims made by, through, or under the
transferor. Although we have 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 our judgment it would be
uneconomical or impractical to do so.

S-38

The following table sets forth the developed and undeveloped leasehold
acreage held by us at December 31, 2001:

DEVELOPED(1) UNDEVELOPED(1)
----------------- -----------------
GROSS NET GROSS NET
------- ------- ------- -------

Alabama........................................ 10,092 2,862 776 292
Arkansas....................................... 762 558 2,040 679
Kansas......................................... -- -- 4,520 1,909
Louisiana...................................... 135,148 92,489 138,532 89,804
Mississippi.................................... 730 176 -- --
Texas.......................................... 232,258 145,162 96,817 64,807
Wyoming........................................ 522 120 84,212 74,997
All other states............................... -- -- 5,928 981
Offshore Louisiana............................. 4,609 276 25,000 1,536
Offshore Texas................................. 14,400 1,601 450 23
------- ------- ------- -------
Total -- Domestic............................ 398,521 243,244 358,275 235,028
New Zealand(2)................................. 24,901 22,411 135,459 79,552
------- ------- ------- -------
Total..................................... 423,422 265,655 493,734 314,580
======= ======= ======= =======

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

(1) Fee mineral acreage acquired in the Masters Creek and Brookeland areas
acquisition are not included in the above leasehold acreage table. We have
26,345 developed fee mineral acres and 114,655 undeveloped fee mineral acres
in these two areas for a total of 141,000 fee mineral acres.

(2) Excludes 24,602 gross, and 23,805 net acres acquired in the TAWN acquisition
that closed in January 2002, as well as 2,478 net acres acquired in the
Antrim acquisition which closed in March 2002.

DRILLING ACTIVITIES

The following table sets forth the results of our drilling activities
during the three years ended December 31, 2001:

GROSS WELLS NET WELLS
-------------------------------------- -------------------------------------
TEMPORARILY TEMPORARILY
YEAR TYPE OF WELL TOTAL PRODUCING DRY ABANDONED TOTAL PRODUCING DRY ABANDONED
---- ------------ ----- --------- ---- ----------- ----- --------- --- -----------

2001 Exploratory -- Domestic.... 11 6 5 -- 6.2 4.0 2.2 --
Exploratory -- New
Zealand.................... 2 -- 1 1 1.1 -- 0.9 0.2
Development -- Domestic.... 36 36 -- -- 29.5 29.5 -- --
Development -- New
Zealand.................... 4 2 2 -- 3.6 1.8 1.8 --
2000 Exploratory -- Domestic.... 9 5 4 -- 6.2 3.4 2.8 --
Development -- Domestic.... 59 52 7 -- 42.4 37.1 5.3 --
Development -- New
Zealand.................... 2 2 -- -- 1.8 1.8 -- --
1999 Exploratory -- Domestic.... 3 1 2 -- 1.5 0.3 1.2 --
Exploratory -- New
Zealand.................... 2 1 -- 1 1.0 0.9 -- 0.1
Development -- Domestic.... 22 19 3 -- 10.7 9.4 1.3 --

OPERATIONS

We generally seek to be operator in the wells in which we have significant
economic interest. As operator, we design and manage the development of a well
and supervise operation and maintenance activities on a day-to-day basis. We do
not own drilling rigs or other oil field services equipment used for drilling or
maintaining wells on properties we operate. Independent contractors supervised
by us provide all the equipment and personnel. We employ drilling, production
and reservoir engineers, geologists, and other specialists who work to improve
production rates, increase reserves, and lower the cost of operating our oil and
gas properties.

Oil and gas properties are customarily operated under the terms of a joint
operating agreement. These agreements usually provide for reimbursement of the
operator's direct expenses and for payment of

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monthly per-well supervision fees. Supervision fees vary widely depending on the
geographic location and depth of the well and whether the well produces oil or
gas. The fees for these activities paid to us in 2001 ranged from $200 to $2,216
per well per month and totaled $6.2 million.

MARKETING OF PRODUCTION

We typically sell our oil and gas production at market prices near the
wellhead, although in some cases it must be gathered and delivered to a central
point. Gas production is sold in the spot market on a monthly basis, while we
sell our oil production at prevailing market prices. We do not refine any oil we
produce. Two oil or gas purchasers accounted for 10% or more each of our total
revenues during the year ended December 31, 2001. Oil and gas sales to
subsidiaries of Eastex Crude Company were $31.6 million, or 18.1% of oil and gas
sales, while sales to subsidiaries of Enron were $18.2 million, or 10.4% of oil
and gas sales. Our last sale to Enron was for November 2001 production. We
currently have other purchasers for those volumes. For the year ended December
31, 2000, two purchasers accounted for approximately 37% of our total revenues.
However, due to the availability of other purchasers, we do not believe that the
loss of any single oil or gas purchaser or contract would materially affect our
revenues.

In 1998, we entered into gas processing and gas transportation agreements
for our gas production in the AWP Olmos area with PG&E Energy Trading
Corporation, which was assumed in December 2000 by El Paso Hydrocarbon, LP, and
El Paso Industrial, LP, both affiliates of El Paso Merchant Energy, for up to
75,000 Mcf per day, which provides for a ten-year term with automatic one-year
extensions unless earlier terminated. We believe that these arrangements
adequately provide for our gas transportation and processing needs in the AWP
Olmos area for the foreseeable future. Additionally, the gas processed and
transported under these agreements may be sold to El Paso based upon current
natural gas prices.

Our oil production from the Brookeland and Masters Creek areas is sold to
various purchasers at prevailing market prices. Our gas production from these
areas is processed under long-term gas processing contracts with Duke Energy
Field Services, Inc. The processed liquids and residue gas production are sold
in the spot market at prevailing prices.

Our oil production from the Lake Washington area is delivered into
ExxonMobil's crude oil pipeline system for sales to various purchasers at
prevailing market prices. Our gas production from this area is either consumed
on the lease or is delivered into El Paso's Tennessee Gas Pipeline system and
then sold in the spot market at prevailing prices.

Our oil production in New Zealand is sold into the international market at
prices tied to the Asia Petroleum Price Index Tapis posting, less the cost of
storage, trucking, and transportation.

Our gas production from our TAWN fields, which we acquired and closed on in
January 2002, is sold under a long-term contract with Contact Energy. Upon
commissioning of the Rimu Production Station, our gas production from the Rimu
field will be sold to Genesis Power Ltd. under a long-term contract.

Our natural gas liquids production from the TAWN fields is sold to RockGas
under long-term contracts tied to New Zealand's domestic natural gas liquids
market. Upon commissioning of the Rimu Production Station, our natural gas
liquids from the Rimu Field also will be sold to RockGas.

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The following table summarizes sales volumes, sales prices, and production
cost information for our net oil and gas production for the three-year period
ended December 31, 2001. "Net" production is production that is owned by us
either directly or indirectly through partnerships or joint venture interests
and is produced to our interest after deducting royalty, limited partner, and
other similar interests.

YEAR ENDED DECEMBER 31,
---------------------------------------
2001 2000 1999
----------- ----------- -----------

NET SALES VOLUME:
Oil (Bbls).......................................... 3,055,374 2,472,014 2,564,924
Gas (Mcf)........................................... 26,458,958 27,524,621 27,484,759
Gas equivalents (Mcfe).............................. 44,791,202 42,356,705 42,874,303
AVERAGE SALES PRICE:
Oil (Per Bbl)....................................... $ 22.64 $ 29.35 $ 16.75
Gas (Per Mcf)....................................... $ 4.23 $ 4.24 $ 2.40
AVERAGE PRODUCTION COST (PER MCFE).................... $ 0.82 $ 0.69 $ 0.46

Oil production for 2001 includes New Zealand production of 84,261 barrels,
at an average price per barrel of $21.64. Natural gas production for 2000 and
1999 includes 405,130 and 728,235 Mcf, respectively, delivered under the
volumetric production payment agreement pursuant to which we were obligated to
deliver certain monthly quantities of natural gas (see Note 1 to the
Consolidated Financial Statements). Under the volumetric production payment
entered into in 1992, we delivered the last remaining commitment of gas in
October 2000, when such agreement expired.

RISK MANAGEMENT

Our 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 us to substantial liability due to pollution and other
environmental damage. Additionally, as managing general partner of limited
partnerships, we are solely responsible for the day-to-day conduct of the
limited partnerships' affairs and accordingly have liability for expenses and
liabilities of the limited partnerships. We maintain comprehensive insurance
coverage. We believe that our insurance is adequate and customary for companies
of a similar size engaged in comparable operations, but losses could occur for
uninsurable or uninsured risks or in amounts in excess of existing insurance
coverage.

COMPETITION

We operate in a highly competitive environment, competing with major
integrated and independent energy companies for desirable oil and gas
properties, as well as for equipment, labor and materials required to develop
and operate such properties. Many of these competitors have financial and
technological resources substantially greater than ours. We may incur higher
costs or be unable to acquire and develop desirable properties at costs we
consider reasonable because of this competition.

PRICE RISK MANAGEMENT

Our major market risk exposure is the commodity pricing applicable to our
oil and natural gas production. Realized commodity prices received for such
production are primarily driven by the prevailing worldwide price for crude oil
and spot prices applicable to natural gas. The effects of such pricing
volatility are discussed above, and such volatility is expected to continue.

Our price risk program permits the utilization of agreements and financial
instruments, such as futures, forward and options contracts, and swaps, to
mitigate price risk associated with fluctuations in oil and natural gas prices.
In 1998, 1999 and 2000, price floors have been the primary financial instruments

S-41

that we have utilized to hedge our exposure to price risk for the three fiscal
years ended December 31, 2000. During those periods, the costs and any benefits
that we derived from price floors were recorded as a reduction or increase, as
applicable, in oil and gas sales revenues. The costs to purchase put options
were amortized over the option period.

During the fourth quarter of 1999, in addition to the price floor we had in
place, we entered into participating collars to hedge oil production through
June 2000. The participating collars were designated as hedges, and realized
losses were recognized in oil and gas revenues in 2000 when the associated
production occurred. During 1998, 1999 and 2000 we recognized net losses
relating to our price floors and our collars of approximately $276,000, $561,000
and $1,114,000, respectively. This activity is recorded in oil and gas sales on
the accompanying statements of income.

Effective January 1, 2001, we adopted SFAS No. 133. We did not elect to
designate our contracts for special hedge accounting treatment and instead are
using mark-to-market accounting treatment.

During 2001, we have continued our general practice of primarily using
price floors to hedge our exposure to price risk. At December 31, 2001, we had
open price floor contracts covering notional volumes of 2.0 million MMBtu of
natural gas. Natural gas price floor contracts relate to the NYMEX contract
months of February and March 2002, at an average price of $2.33 per MMBtu. The
fair market value of our open price floor contracts at December 31, 2001 totaled
$296,000 and is included under "Other Current Assets" on our December 31, 2001
balance sheet. During 2001 we recognized net gains of $1,173,094 relating to our
derivative activities, with $16,784 of losses unrealized at year end 2001. This
activity is recorded in "Price risk management and other, net" on our statements
of income for 2001.

For recent information on our hedging activities, see "Summary -- Recent
Developments."

PARTNERSHIPS

Prior to 1995, we funded a substantial portion of our operations through
109 limited partnerships which we formed and for which we have served as
managing general partner. These partnerships raised a total of $509.5 million,
with the largest portion (81%) raised to acquire interests in producing
properties. Eight of the earliest partnerships and 13 of the most recently
formed partnerships were created to drill for oil and gas. In all of these
partnerships Swift paid for varying percentages of the capital or front-end
costs and continuing costs of the partnerships and, in return, received
differing percentage ownership interests in the partnerships, along with
reimbursement of costs and/or payment of certain fees. At year end 2001, we
continued to serve as managing general partner of 71 of these various
partnerships, of which 65 are production purchase partnerships that have been in
existence from six to fifteen years and the remainder of which are drilling
partnerships that have been in existence from three to five years.

During 1997 and 1998, eight drilling partnerships formed between 1979 and
1985 and 21 of the production purchase partnerships sold their properties and
were dissolved, in each case following a vote of the investors in the particular
partnerships approving such liquidations. Between 1999 and 2001, the investors
in all but six of the remaining partnerships voted to sell the properties or
their interests in the partnerships and dissolve. During 2001, seven drilling
partnerships and two production purchase partnerships were dissolved. We
anticipate that the liquidation and dissolution of the additional 65
partnerships should be substantially completed by the end of 2002. The remaining
six partnerships will continue to operate.

REGULATIONS

Environmental Regulations

The United States federal government and various state and local
governments have adopted laws and regulations regarding the protection of human
health and the environment. These laws and regulations may require the
acquisition of a permit by operators before drilling commences, prohibit
drilling activities on certain lands lying within wilderness areas, wetlands, or
where pollution might cause serious harm, and impose substantial liabilities for
pollution resulting from drilling operations, particularly with respect to

S-42

operations in onshore and offshore waters or on submerged lands. Failure to
comply with these laws and regulations may result in the imposition of
administrative, civil, or criminal penalties or injunctive relief for failure to
comply. These laws and regulations may increase the costs of drilling and
operating wells. Because these laws and regulations change frequently, the costs
of compliance with existing and future environmental laws and regulations cannot
be predicted with certainty.

We currently own or lease, and have in the past owned or leased, numerous
domestic properties that have been used for the exploration and production of
oil and gas, some for many years. Although we have used operating and disposal
practices that were standard in the industry at the time, hydrocarbons or other
wastes may have been released on or under the properties owned or leased by us
or on or under other locations where such wastes have been taken for disposal.
In addition, many of these properties have been operated by third parties whose
treatment and disposal or release of hydrocarbons or other wastes was not under
our control. These properties and the wastes disposed thereon or away from could
be subject to stringent and costly investigatory or remedial requirements under
applicable laws, some of which are strict liability laws without regard to fault
or the legality of the original conduct, including the federal Comprehensive
Environmental Response, Compensation and Liability Act, the federal Resources
Conservation and Recovery Act, the federal Clean Water Act, the federal Oil
Pollution Act, and analogous state laws. Under such laws, we could be required
to remove or remediate previously disposed wastes (including waste disposed of
or released by prior owners or operators) or property contamination (including
groundwater contamination by prior owners or operators), to perform natural
resource mitigation or restoration practices, or to perform remedial plugging or
closure operations to prevent future contamination.

Our oil and gas operations outside of the United States could also
potentially be subject to similar foreign governmental controls and restrictions
pertaining to protection of human health and the environment. Possible controls
and restrictions may include the need to acquire permits, prohibition on
drilling in certain environmentally sensitive areas, performance of clean-ups
for any release of hydrocarbons or other wastes, and payment of penalties for
any violations of applicable laws. We believe that compliance with existing
requirements of such governmental bodies has not had a material adverse effect
on our results of operations.

United States Federal, State and New Zealand Regulation of Oil and Natural Gas

The transportation and certain sales of natural gas in interstate commerce
are heavily regulated by agencies of the federal government and are affected by
the availability, terms and cost of transportation. The price and terms of
access to pipeline transportation are subject to extensive federal and state
regulation. The FERC is continually proposing and implementing new rules and
regulations affecting the natural gas industry, most notably interstate natural
gas transmission companies that remain subject to the FERC's jurisdiction. The
stated purpose of many of these regulatory changes is to promote competition
among the various sectors of the natural gas industry. Some recent FERC
proposals may, however, adversely affect the availability and reliability of
interruptible transportation service on interstate pipelines.

Our sales of crude oil, condensate and natural gas liquids are not
currently subject to FERC regulation. However, the ability to transport and sell
such products is dependent on certain pipelines whose rates, terms and
conditions of service are subject to FERC regulation.

Production of any oil and gas by us will be affected to some degree by
state regulations. Many states in which we operate 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. Likewise, the government of New Zealand regulates the
exploration, production, sales and transportation of oil and natural gas.

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FEDERAL LEASES

Some of our 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.

LITIGATION

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

EMPLOYEES

At December 31, 2001, we employed 209 persons. In the January 2002 TAWN
acquisition we acquired 22 employees in New Zealand, nine of whom are members of
a union. None of our other employees are represented by a union. Relations with
employees are considered to be good.

FACILITIES

We occupy approximately 91,000 square feet of office space at 16825
Northchase Drive, Houston, Texas, under a ten year lease expiring in 2005. The
lease requires payments of approximately $116,000 per month. We have field
offices in various locations, including New Zealand, from which our employees
supervise local oil and gas operations.

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MANAGEMENT

DIRECTORS AND EXECUTIVE OFFICERS

A. Earl Swift................................ Chairman of the Board
Terry E. Swift............................... President, Chief Executive Officer, Director
Virgil N. Swift.............................. Vice Chairman of the Board
Joseph A. D'Amico............................ Executive Vice President and Chief Operating Officer
Bruce H. Vincent............................. Executive Vice President -- Corporate Development and
Secretary
Alton D. Heckaman, Jr. ...................... Senior Vice President -- Finance and Chief Financial
Officer
James M. Kitterman........................... Senior Vice President -- Operations
Victor R. Moran.............................. Senior Vice President -- Energy Marketing and Business
Development
David W. Wesson.............................. Controller
G. Robert Evans.............................. Director
Henry C. Montgomery.......................... Director
Clyde W. Smith, Jr. ......................... Director
Harold J. Withrow............................ Director

A. Earl Swift, 68, is Chairman of the Board of Directors and has served in
such capacity since Swift's founding in 1979. He previously served as President
from 1979 to November 1997, at which time Terry E. Swift was appointed
President. He also previously served as Chief Executive Officer from 1979 to May
2001, at which time Terry E. Swift was appointed Chief Executive Officer. For
the 17 years prior to 1979, he was employed by affiliates of American Natural
Resources Company. Mr. Swift is a registered professional engineer and holds a
degree in petroleum engineering, Juris Doctor degree and a master's degree in
business administration. He is the father of Terry E. Swift and the brother of
Virgil N. Swift.

Terry E. Swift, 46, has served as a director since the 2000 annual
shareholders meeting. He was appointed President in November 1997 and Chief
Executive Officer in May 2001. He served as Executive Vice President from 1991
to 1997 and was Chief Operating Officer from 1991 to January 2000. He served as
Senior Vice President -- Exploration and Joint Ventures from 1990 to 1991 and as
Vice President -- Exploration and Joint Ventures from 1988 to 1990. Mr. Swift
has a degree in chemical engineering and a master's degree in business
administration. He is the son of A. Earl Swift and the nephew of Virgil N.
Swift.

Virgil N. Swift, 73, has been a director since 1981, and currently serves
as Vice Chairman of the Board. He acted as Executive Vice President -- Business
Development between November 1991 and June 30, 2000. He previously served as
Executive Vice President and Chief Operating Officer from 1982 to late 1991. Mr.
Swift joined us 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. He
is the brother of A. Earl Swift and the uncle of Terry E. Swift.

Joseph A. D'Amico, 53, was appointed Executive Vice President in August
2000 and was appointed Chief Operating Officer in January 2000. He was Senior
Vice President of Exploration and Development from February 1998 to January
2000. He served as Vice President of Exploration and Development from 1993 to
1998, Director of Exploration and Development from 1992 to 1993 and Funds
Manager from 1988 to 1992. Mr. D'Amico holds Bachelor and Master of Science
degrees in petroleum engineering and a master's degree in business
administration.

Bruce H. Vincent, 54, has been Executive Vice President -- Corporate
Development and Secretary since August 2000. Previously he served as Senior Vice
President -- Funds Management since joining Swift in 1990. Mr. Vincent holds a
degree in business administration and a master's degree in finance.

S-45

Alton D. Heckaman, Jr., 45, was appointed Senior Vice President -- Finance
and Chief Financial Officer in August 2000. He had previously served as Vice
President and Controller from May 1993 and Assistant Vice President -- Finance
from March 1986 to May 1993. Mr. Heckaman joined Swift in 1982. He is a
certified public accountant and holds a degree in accounting.

James M. Kitterman, 57, was appointed Senior Vice President -- Operations
in May 1993. He had previously served as Vice President -- Operations since
joining Swift in 1983. Mr. Kitterman holds a degree in petroleum engineering and
a master's degree in business administration.

Victor R. Moran, 46, was appointed Senior Vice President -- Energy
Marketing and Business Development in August 2000. From 1995, he served as Vice
President -- Natural Gas Marketing/Business Development. He had previously
served as Director of Business Development since joining Swift in January 1992.
Mr. Moran holds a degree in government and a Juris Doctor degree.

David W. Wesson, 43, was appointed Controller in January 2001. He
previously served as Assistant Controller -- Reporting from April 1999 to
January 2001, Manager, Reporting/Budget from October 1995 to April 1999 and
Manager, Corporate Accounting/Budget from February 1990. He joined Swift as a
Senior Accountant in 1988. Mr. Wesson is a certified public accountant and holds
a degree in accounting.

G. Robert Evans, 70, has been a director since 1994. Effective January 1,
1998, Mr. Evans retired as Chairman of Material Sciences Corporation, having
held that position since 1991. Material Sciences Corporation develops and
commercializes continuously processed, coated materials technologies. He remains
a director of Material Sciences Corporation. He also serves as a director of
Consolidated Freightways, Inc., a trucking company.

Henry C. Montgomery, 66, has served as a director since 1987. Since 1980,
Mr. Montgomery has been and continues to serve as the Chairman of the Board of
Montgomery Financial Services Corporation, a management consulting and financial
services firm. Mr. Montgomery specializes in services for companies in
transition or that are financially troubled. The following describes some of
those engagements. From January 2000 to early March 2001, Mr. Montgomery served
as Executive Vice President, Financial and Administration, and Chief Finance
Officer of Indus International, Inc., a public company engaged in enterprise
asset management systems. For eight months in 1999 he served as interim
Executive Vice President of Finance and Administration and currently serves on
the board of directors of Spectrian Corporation, a public company engaged in
making cellular base station power amplifiers. From November 1996 through July
1997, Mr. Montgomery served as Executive Vice President of SyQuest Technology,
Inc., a public company engaged in the development, manufacture and sale of
computer hard drives. On November 17, 1998, SyQuest filed a petition under
Chapter 11 of the U.S. Bankruptcy Code. Mr. Montgomery served from March 1995
until mid-November 1996 as President and Chief Executive Officer of New Media
Corporation, a privately held company engaged in developing, manufacturing and
selling PCMCIA cards for the computer industry. On October 14, 1998, New Media
Corporation filed a petition under Chapter 11 of the U.S. Bankruptcy Code. Mr.
Montgomery currently also serves on the boards of directors of Consolidated
Freightways Corporation, a trucking company, and Catalyst Semiconductor, Inc., a
company that designs, develops and markets programmable integrated circuit
products.

Clyde W. Smith, Jr., 53, has served as a director since 1984. Since January
2002, Mr. Smith has served as President of Ascentron, Inc., an electronics
manufacturing services company that acquired the assets of D.W. Manufacturing,
Inc. in January 2002. From May 1998 until January 2002, Mr. Smith served as
General Manager of D.W. Manufacturing, Inc. d/b/a Millennium Technology
Services, an Oregon based electronics manufacturer. From August 1997 to May
1998, when its assets were acquired by D.W. Manufacturing, Mr. Smith served as
President of Millenium Technology, Inc., a debtor-in-possession under the U.S.
Bankruptcy Code. He served as President of Somerset Properties, Inc., a real
estate investment company, from 1985 to 1994 and as President of H&R Precision,
Inc., a general contractor, from 1994 to August 1997. Mr. Smith is a certified
public accountant. On May 7, 1997, Mr. Smith filed a petition under Chapter 7 of
the U.S. Bankruptcy Code.

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Harold J. Withrow, 74, has been a director since 1988. Mr. Withrow worked
as an independent oil and gas consultant from 1988 until he retired at the end
of 1995. From 1975 until 1988, Mr. Withrow served as Senior Vice
President -- Gas Supply for Michigan Wisconsin Pipe Line Company and its
successor, ANR Pipeline Company.

S-47

DESCRIPTION OF EXISTING INDEBTEDNESS

CREDIT FACILITY

Our $300.0 million credit facility with a nine bank syndicate, which is
scheduled to mature on October 1, 2005, is secured by substantially all of our
oil and gas properties. The amount available for borrowing is subject to a
borrowing base determination that is re-calculated at least every six months.
Our current borrowing base is $275.0 million. Our borrowing base will be reduced
by 40% of the amount of the proposed notes offering upon its closing. Our
proposed notes offering is expected to close in mid-April 2002, although we can
provide no assurance in this regard. Without taking this reduction into account,
the bank syndicate reconfirmed this borrowing base effective April 5, 2002. At
December 31, 2001 and February 28, 2002, we had $134.0 million and $220.2
million in outstanding borrowings under our credit facility. After we apply the
net proceeds of this offering to reduce our bank debt, based upon our
outstanding indebtedness at February 28, 2002, we anticipate we would have
approximately $193.7 million outstanding under our credit facility. This amount
will be reduced to approximately $48.0 million after application of the net
proceeds we expect from the proposed notes offering.

Under our current credit facility and depending on the level of outstanding
debt, the interest rate is either the lead bank's base rate, 4.75% at December
31, 2001, or, at our option, LIBOR plus the applicable margin, which was 3.64%
for our outstanding borrowings at December 31, 2001. The weighted average
interest rate was 3.53% for our outstanding borrowings at February 28, 2002.

The terms of the revolving line of credit include, among other
restrictions, a limitation on cash dividends, requirements as to maintenance of
certain minimum financial ratios, including maintaining working capital and debt
and equity ratios, and limitations on incurring other debt. Since inception, no
cash dividends have been declared on our common stock. Our credit facility
limits our repurchase of shares of common stock to $15.0 million from September
28, 2001. In addition, our credit facility contains certain covenants that
limit, among other things, our ability to:

- incur debt;

- dispose of property and assets;

- enter into consolidation or merger transactions;

- enter into certain contracts or leases; and

- expand into other lines of business.

For all periods presented in this prospectus supplement, we were in
compliance with the provisions of our credit facility. For a detailed
description of this credit facility, see the credit agreement which is attached
as Exhibit 10.16 of our Quarterly Report on Form 10-Q for the quarter ended
September 30, 2001.

SENIOR SUBORDINATED NOTES DUE 2009

On August 4, 1999, we issued $125.0 million aggregate principal amount of
10.25% senior subordinated notes due August 1, 2009.

Payments of principal, interest and premium under the senior subordinated
notes due 2009 will be subordinated to payments on our existing and future
senior debt, including our credit facility. On or after August 1, 2004, we may
redeem our senior subordinated notes due 2009 for cash at 105.125% of principal
declining to 100% in 2007. In addition, before August 1, 2002, we may redeem up
to 33.33% of our senior subordinated notes due 2009 with the proceeds of
qualified offerings of our equity at 110.25% of their principal amount, together
with accrued and unpaid interest. If certain changes in control occur, or if our
common stock ceases trading on a national exchange, each holder of the senior
subordinated notes due 2009 will have the right to require us to repurchase
their senior subordinated notes due 2009 at 101% of the note's principal amount,
plus accrued and unpaid interest to the date of repurchase.

S-48

For a detailed description of the senior subordinated notes due 2009 and
their provisions, see the indenture and the supplement filed as an exhibit to
the senior subordinated notes registration statement on July 9, 1999 and to our
Current Report on Form 8-K filed with the SEC on August 4, 1999, respectively.

S-49

UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting
agreement dated April 9, 2002, we have agreed to sell to Credit Suisse First
Boston Corporation ("CSFB") all of the shares of common stock in this offering.

The underwriting agreement provides that CSFB is obligated to purchase all
of the shares of common stock in this offering if any are purchased, other than
those shares covered by the over-allotment option described below.

We have granted to CSFB a 30-day option to purchase up to 225,000
additional shares at the initial public offering price less the underwriting
discounts and commissions. The option may be exercised only to cover any
over-allotments of common stock.

CSFB proposes to offer the shares of common stock initially at the public
offering price on the cover page of this prospectus supplement and to selling
group members at that price less a selling concession of $0.30 per share. CSFB
and selling group members may allow a discount of $0.10 per share on sales to
other broker/dealers. After the initial public offering, CSFB may change the
public offering price and concession and discount to broker/dealers.

The following table summarizes the compensation and estimated expenses we
will pay.

PER SHARE TOTAL
--------------------- ---------------------
WITHOUT WITH WITHOUT WITH
OVER- OVER- OVER- OVER-
ALLOTMENT ALLOTMENT ALLOTMENT ALLOTMENT
--------- --------- --------- ---------

Underwriting discounts and commission payable by
us................................................. $0.50 $0.50 $750,000 $862,500
Expenses payable by us............................... $0.08 $0.08 $125,000 $135,000

We have agreed that we will not offer, sell, contract to sell, pledge or
otherwise dispose of, directly or indirectly, or file with the SEC a
registration statement under the Securities Act of 1933 (the "Securities Act")
relating to, any shares of our common stock or securities convertible into or
exchangeable or exercisable for any shares of our common stock, or publicly
disclose the intention to make any such offer, sale, pledge, disposition or
filing, without the prior written consent of CSFB for a period of 90 days after
the date of this prospectus supplement, except issuances pursuant to the
exercise of outstanding options, grants of employee stock options pursuant to
the terms of existing employee benefit plans, and issuances pursuant to the
exercise of such options.

Our executive officers and directors have agreed that they will not offer,
sell, contract to sell, pledge or otherwise dispose of, directly or indirectly,
any shares of our common stock or securities convertible into or exchangeable or
exercisable for any shares of our common stock, enter into a transaction that
would have the same effect, or enter into any swap, hedge or other arrangement
that transfers, in whole or in part, any of the economic consequences of
ownership of our common stock, whether any of these transactions are to be
settled by delivery of our common stock or other securities, in cash or
otherwise, or publicly disclose the intention to make any offer, sale, pledge or
disposition, or to enter into any transaction, swap, hedge or other arrangement,
without, in each case, the prior written consent of CSFB for a period of 90 days
after the date of this prospectus supplement.

We have agreed to indemnify CSFB against liabilities under the Securities
Act or contribute to payments that CSFB may be required to make in that respect.

In connection with the offering CSFB may engage in stabilizing
transactions, over-allotment transactions, syndicate covering transactions and
penalty bids in accordance with Regulation M under the Securities Exchange Act
of 1934.

- Stabilizing transactions permit bids to purchase the underlying security
so long as the stabilizing bids do not exceed a specified maximum.

S-50

- Over-allotment involves sales by CSFB of shares in excess of the number
of shares CSFB is obligated to purchase, which creates a syndicate short
position. The short position may be either a covered short position or a
naked short position. In a covered short position, the number of shares
over-allotted by CSFB is not greater than the number of shares it may
purchase in the over-allotment option. In a naked short position, the
number of shares involved is greater than the number of shares in the
over-allotment option. CSFB may close out any covered short position by
either exercising its over-allotment option and/or purchasing shares in
the open market.

- Syndicate covering transactions involve purchases of common stock in the
open market after the distribution has been completed in order to cover
syndicate short positions. In determining the source of shares to close
out the short position, CSFB will consider, among other things, the price
of shares available for purchase in the open market as compared to the
price at which it may purchase shares through the over-allotment option.
If CSFB sells more shares than could be covered by the over-allotment
option, a naked short position, the position can only be closed out by
buying shares in the open market. A naked short position is more likely
to be created if CSFB is concerned that there could be downward pressure
on the price of the shares in the open market after pricing that could
adversely affect investors who purchase in the offering.

- Penalty bids permit CSFB to reclaim a selling concession from a syndicate
member when the common stock originally sold by the syndicate member is
purchased in a stabilizing transaction or a syndicate covering
transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids
may have the effect of raising or maintaining the market price of our common
stock or preventing or retarding a decline in the market price of our common
stock. As a result, the price of our common stock may be higher than the price
that might otherwise exist in the open market. These transactions, if commenced,
may be discontinued at any time.

A prospectus in electronic format may be made available on the web sites
maintained by CSFB, or selling group members, if any, participating in this
offering. CSFB may agree to allocate a number of shares to itself and selling
group members for sale to their online brokerage account holders. Internet
distributions will be allocated by CSFB and selling group members that will make
internet distributions on the same basis as other allocations.

In the ordinary course of their businesses, CSFB and its affiliates have
engaged, and/or may in the future engage, in investment banking or commercial
banking transactions with us and our affiliates. CSFB will not receive any
benefit from this offering other than the underwriting discount to be provided
by us. CSFB is the lead manager of our proposed notes offering.

NOTICE TO CANADIAN RESIDENTS

RESALE RESTRICTIONS

The distribution of the common stock in Canada is being made only on a
private placement basis exempt from the requirement that we prepare and file a
prospectus with the securities regulatory authorities in each province where
trades of common stock are made. Any resale of the common stock in Canada must
be made under applicable securities laws which will vary depending on the
relevant jurisdiction, and which may require resales to be made under available
statutory exemptions or under a discretionary exemption granted by the
applicable Canadian securities regulatory authority. Purchasers are advised to
seek legal advice prior to any resale of the common stock.

REPRESENTATIONS OF PURCHASERS

By purchasing common stock in Canada and accepting a purchase confirmation
a purchaser is representing to us and the dealer from whom the purchase
confirmation is received that

S-51

- the purchaser is entitled under applicable provincial securities laws to
purchase the common stock without the benefit of a prospectus qualified
under those securities laws;

- where required by law, that the purchaser is purchasing as principal and
not as agent; and

- the purchaser has reviewed the text above under "Resale Restrictions."

RIGHTS OF ACTION -- ONTARIO PURCHASERS ONLY

Under Ontario securities legislation, a purchaser who purchases a security
offered by this prospectus supplement during the period of distribution will
have a statutory right of action for damages, or while still the owner of the
shares, for rescission against us in the event that this prospectus supplement
and/or the accompanying prospectus contains a misrepresentation. A purchaser
will be deemed to have relied on the misrepresentation. The right of action for
damages is exercisable not later than the earlier of 180 days from the date the
purchaser first had knowledge of the facts giving rise to the cause of action
and three years from the date on which payment is made for the shares. The right
of action for rescission is exercisable not later than 180 days from the date on
which payment is made for the shares. If a purchaser elects to exercise the
right of action for rescission, the purchaser will have no right of action for
damages against us. In no case will the amount recoverable in any action exceed
the price at which the shares were offered to the purchaser and if the purchaser
is shown to have purchased the securities with knowledge of the
misrepresentation, we will have no liability. In the case of an action for
damages, we will not be liable for all or any portion of the damages that are
proven to not represent the depreciation in value of the shares as a result of
the misrepresentation relied upon. These rights are in addition to, and without
derogation from, any other rights or remedies available at law to an Ontario
purchaser. The foregoing is a summary of the rights available to an Ontario
purchaser. Ontario purchasers should refer to the complete text of the relevant
statutory provisions.

ENFORCEMENT OF LEGAL RIGHTS

All of our directors and officers as well as the experts named herein may
be located outside of Canada and, as a result, it may not be possible for
Canadian purchasers to effect service of process within Canada upon us or those
persons. All or a substantial portion of our assets and the assets of those
persons may be located outside of Canada and, as a result, it may not be
possible to satisfy a judgment against us or those persons in Canada or to
enforce a judgment obtained in Canadian courts against us or those persons
outside of Canada.

TAXATION AND ELIGIBILITY FOR INVESTMENT

Canadian purchasers of common stock should consult their own legal and tax
advisors with respect to the tax consequences of an investment in the common
stock in their particular circumstances and about the eligibility of the common
stock for investment by the purchaser under relevant Canadian legislation.

LEGAL MATTERS

The validity of the offered common stock will be passed upon for us by
Jenkens & Gilchrist, a Professional Corporation, Houston, Texas. Certain legal
matters will be passed upon for the underwriters by Vinson & Elkins L.L.P.,
Houston, Texas.

S-52

EXPERTS

The audited financial statements included in this prospectus supplement
have been audited by Arthur Andersen LLP, independent public accountants, as
indicated in their report with respect thereto, and are included herein in
reliance upon the authority of said firm as experts in accounting and auditing
in giving said report.

Information set forth in this prospectus supplement regarding our estimated
quantities of oil and gas reserves and the discounted present value of future
net cash flows therefrom is based upon estimates of such reserves and present
values prepared by H.J. Gruy & Associates, Inc., independent petroleum
engineers. All such information has been so included herein in reliance upon the
authority of such firm as experts in such matters.

OTHER MATTERS

On March 14, 2002, our independent public accountant, Arthur Andersen LLP,
was indicted on federal obstruction of justice charges arising from the federal
government's investigation of Enron Corp. Arthur Andersen has pled not guilty
and indicated that it intends to contest the indictment. Given the uncertainty
surrounding the indictment, it may become difficult for purchasers of the common
stock to seek remedies against Arthur Andersen. The SEC has said that it will
continue accepting financial statements audited by Arthur Andersen, and interim
financial statements reviewed by it, so long as Arthur Andersen is able to make
certain representations to its clients concerning audit quality controls, which
representations have been made to us. Our Audit Committee has been monitoring
these developments, and if necessary will take appropriate action regarding the
auditing of our financial statements.

S-53

GLOSSARY OF TERMS

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

BBL means barrel or barrels of oil.

BCF means billion cubic feet of natural gas.

BCFE means billion cubic feet of natural gas equivalent (see Mcfe).

BOE means one revenue interests barrel of oil equivalent using the ratio of
one barrel of crude oil, condensate or natural gas liquids to six Mcf of natural
gas.

BTU means British thermal unit, which is a heating equivalent measure for
natural gas (see MMBtu).

DEVELOPMENT WELL means a well drilled within the presently proved
productive area of an oil or natural gas reservoir, as indicated by reasonable
interpretation of available data, with the objective of completing in that
reservoir.

EXPLORATORY WELL means a well drilled either in search of a new, as yet
undiscovered oil or natural gas reservoir or to greatly extend the known limits
of a previously discovered reservoir.

FAIR MARKET VALUE is defined as the maximum price that a willing buyer will
pay and a willing seller will sell at a given point in time at which the buyer
is under no compulsion to buy and the seller is not compelled to sell, both
having reasonable knowledge of all the material circumstances.

GROSS ACRE means an acre in which a working interest is owned. The number
of gross acres is the total number of acres in which a working interest is
owned.

GROSS WELL means a well in which a working interest is owned. The number of
gross wells is the total number of wells in which a working interest is owned.

MCF means thousand cubic feet of natural gas.

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

MMBOE means million barrels of oil equivalent (see BOE).

MMBTU means Million British thermal units, which is a heating equivalent
measure for natural gas and is an alternate measure of natural gas reserves, as
opposed to Mcf, which is strictly a measure of natural gas volumes. Typically
prices quoted for natural gas are designated as prices per MMBtu, the same basis
on which natural gas is contracted for sale.

MMCF means million cubic feet of natural gas.

MMCFE means million cubic feet of natural gas equivalent (see Mcfe).

NET ACRE means the sum of fractional ownership working interests in gross
acres equals one. The number of net acres is the sum of fractional working
interests owned in gross acres expressed as whole numbers and fractions thereof.

NET 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.

NGL means natural gas liquid.

PRODUCING WELL means an exploratory or development well found to be capable
of producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well.

PROVED DEVELOPED RESERVES means reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
S-54

PROVED UNDEVELOPED RESERVES means proved reserves that are expected to be
recovered from new wells on undrilled acreage.

PROVED OIL AND GAS RESERVES means the estimated quantities of crude oil,
natural gas, and natural gas liquids that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, that is,
prices and costs as of the date the estimate is made.

PV-10 VALUE means, in accordance with SEC guidelines, the estimated future
net cash flow to be generated from the production of proved reserves discounted
to present value using an annual discount rate of 10%. These amounts are
calculated net of estimated production costs and future development costs, using
prices and costs in effect as of a certain date, without escalation and without
giving effect to non-property related expenses such as general and
administrative expenses, debt services, future income tax expenses or
depreciation, depletion and amortization.

PRODUCING PROPERTIES means properties (or interests in properties)
producing oil and gas in commercial quantities. Producing Properties include
associated well machinery and equipment, gathering systems, storage facilities
or processing installations or other equipment and property associated with the
production and field processing of oil or gas. Interests in Producing Properties
may include Working Interests, production payments, Royalty Interests,
Overriding Royalty Interest, Net Profits Interests and other non-operating
interests. Producing Properties may include gas gathering lines or pipelines.
The geographical limits of a Producing Property may be enlarged or contracted on
the basis of subsequently acquired geological data to define the productive
limits of a reservoir, or as a result of action by a regulatory agency employing
such criteria as the regulatory agency may determine.

PROVED RESERVES means those quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geologic and engineering data,
appear with reasonable certainty to be recoverable in the future from known oil
and gas reservoirs under existing economic and operating conditions. Proved
Reserves are limited to those quantities of oil and gas which can be reasonably
expected to be recoverable commercially at current prices and costs, under
existing regulatory practices and with existing conventional equipment and
operating methods.

RESERVE REPLACEMENT COST means, with respect to proved reserves, a
three-year average (unless otherwise indicated) calculated by dividing total
incurred acquisition, exploration and development costs (exclusive of future
development costs) by net reserves added during the period.

ROYALTY INTEREST means a fractional interest in the gross production, or
the gross proceeds therefrom, of oil and gas and other minerals under a lease;
free of any expenses of exploration, development, operation and maintenance.

SFAS means Statement of Financial Accounting Standards.

TAWN refers to New Zealand producing properties acquired by Swift in
January 2002 and is comprised of the Tariki, Ahuroa, Waihapa and Ngaere fields.

WORKING INTEREST means the operating interest under an oil, gas and mineral
lease or other property interest covering a specific tract or tracts of land.
The owner of a Working Interest has the right to explore for, drill and produce
the oil, gas and other minerals covered by such lease or other property interest
and the obligation to bear the costs of exploration, development, operation or
maintenance applicable to that owner's interest.

S-55

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS

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

F-1

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, 2001
and 2000, and the related consolidated statements of income, stockholders'
equity, and cash flows for each of the three years in the period ended December
31, 2001. 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 auditing standards generally
accepted in the United States. 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, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.

ARTHUR ANDERSEN LLP

Houston, Texas
February 18, 2002

F-2

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,
------------------------------
2001 2000
-------------- -------------

ASSETS

Current Assets:
Cash and cash equivalents................................. $ 2,149,086 $ 1,986,932
Accounts receivable --
Oil and gas sales...................................... 14,215,189 26,939,472
Associated limited partnerships and joint ventures..... 6,259,604 2,685,003
Joint interest owners.................................. 11,467,461 7,181,974
Other current assets...................................... 2,661,640 3,079,498
-------------- -------------
Total Current Assets.............................. 36,752,980 41,872,879
-------------- -------------
Property and Equipment:
Oil and gas, using full cost accounting
Proved properties being amortized...................... 974,698,428 753,426,124
Unproved properties not being amortized................ 95,943,163 55,512,872
-------------- -------------
1,070,641,591 808,938,996
Furniture, fixtures, and other equipment.................. 8,706,414 8,873,266
-------------- -------------
1,079,348,005 817,812,262
Less -- Accumulated depreciation, depletion, and
amortization......................................... (448,139,334) (290,725,112)
-------------- -------------
631,208,671 527,087,150
-------------- -------------
Other Assets:
Deferred charges.......................................... 3,723,182 3,426,972
-------------- -------------
3,723,182 3,426,972
-------------- -------------
$ 671,684,833 $ 572,387,001
============== =============

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities:
Accounts payable and accrued liabilities.................. $ 38,884,380 $ 54,977,397
Payable to associated limited partnerships................ 26,573,490 1,291,787
Undistributed oil and gas revenues........................ 7,787,465 8,055,587
-------------- -------------
Total Current Liabilities......................... 73,245,335 64,324,771
-------------- -------------

Long-Term Debt.............................................. 258,197,128 134,729,485
Deferred Income Taxes....................................... 27,589,650 41,178,590

Commitments and Contingencies

Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding........................... -- --
Common stock, $.01 par value, 85,000,000 and 35,000,000
shares authorized, 25,634,598 and 25,452,148 shares
issued, and 24,795,564 and 24,608,344 shares
outstanding, respectively.............................. 256,346 254,521
Additional paid-in capital................................ 296,172,820 293,396,723
Treasury stock held, at cost, 839,034 and 843,804 shares,
respectively........................................... (12,032,791) (12,101,199)
Retained earnings......................................... 28,256,345 50,604,110
-------------- -------------
312,652,720 332,154,155
-------------- -------------
$ 671,684,833 $ 572,387,001
============== =============

See accompanying Notes to Consolidated Financial Statements.
F-3

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

YEAR ENDED DECEMBER 31,
------------------------------------------
2001 2000 1999
------------ ------------ ------------

Revenues:
Oil and gas sales................................ $181,184,635 $189,138,947 $108,898,696
Fees from limited partnerships and joint
ventures...................................... 427,583 331,497 229,749
Interest income.................................. 49,281 1,339,386 833,204
Price risk management and other, net............. 2,145,991 815,116 709,358
------------ ------------ ------------
183,807,490 191,624,946 110,671,007
------------ ------------ ------------
Costs and Expenses:
General and administrative, net of
reimbursement................................. 8,186,654 5,585,487 4,497,400
Depreciation, depletion, and amortization........ 59,502,040 47,771,393 42,348,901
Oil and gas production........................... 36,719,609 29,220,315 19,645,740
Interest expense, net............................ 12,627,022 15,968,405 14,442,815
Other expenses................................... 2,102,251 -- --
Write-down of oil and gas properties............. 98,862,247 -- --
------------ ------------ ------------
217,999,823 98,545,600 80,934,856
------------ ------------ ------------
Income (Loss) Before Income Taxes, Extraordinary
Item and Change in Accounting Principle.......... (34,192,333) 93,079,346 29,736,151
Provision (Benefit) for Income Taxes............... (12,237,436) 33,265,480 10,449,577
------------ ------------ ------------
Income (Loss) Before Extraordinary Item and Change
in Accounting Principle.......................... $(21,954,897) $ 59,813,866 $ 19,286,574
Extraordinary Loss on Early Extinguishment of Debt
(net of taxes)................................... -- 629,858 --
Cumulative Effect of Change in Accounting Principle
(net of taxes)................................... 392,868 -- --
------------ ------------ ------------
Net Income (Loss).................................. $(22,347,765) $ 59,184,008 $ 19,286,574

Per Share Amounts --
Basic: Income (Loss) Before Extraordinary Item
and Change in Accounting Principle............ $ (0.89) $ 2.82 $ 1.07
Extraordinary Loss............................ -- (0.03) --
Change in Accounting Principle................ (0.01) -- --
------------ ------------ ------------
Net Income (Loss)............................. $ (0.90) $ 2.79 $ 1.07
Diluted: Income (Loss) Before Extraordinary Item
and Change in Accounting Principle............ $ (0.89) $ 2.53 $ 1.07
Extraordinary Loss............................ -- (0.02) --
Change in Accounting Principle................ (0.01) -- --
------------ ------------ ------------
Net Income (Loss)............................. $ (0.90) $ 2.51 $ 1.07

Weighted Average Shares Outstanding................ 24,732,099 21,244,684 18,050,106
============ ============ ============

See accompanying Notes to Consolidated Financial Statements.
F-4

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

RETAINED
COMMON ADDITIONAL EARNINGS
STOCK(1) PAID-IN CAPITAL TREASURY STOCK (DEFICIT) TOTAL
-------- --------------- -------------- ------------ ------------

Balance, December 31, 1998... $169,725 $148,901,270 $(11,841,884) $(27,866,472) $109,362,639
Stock issued for benefit
plans
(90,738 shares)............ 224 (366,408) 978,956 -- 612,772
Stock options exercised
(65,477 shares)............ 655 461,102 -- -- 461,757
Employee stock purchase plan
(22,771 shares)............ 228 181,577 -- -- 181,805
Public stock offering
(4,600,000 shares)......... 46,000 41,915,310 -- -- 41,961,310
Purchase of 246,500 shares
as treasury stock.......... -- -- (1,462,740) -- (1,462,740)
Net income................... -- -- -- 19,286,574 19,286,574
-------- ------------ ------------ ------------ ------------
Balance, December 31, 1999... $216,832 $191,092,851 $(12,325,668) $ (8,579,898) $170,404,117
Stock issued for benefit
plans
(46,632 shares)............ 310 297,060 224,469 -- 521,839
Stock options exercised
(543,450 shares)........... 5,434 4,316,446 -- -- 4,321,880
Employee stock purchase plan
(29,889 shares)............ 299 297,414 -- -- 297,713
Subordinated notes conversion
(3,164,644 shares)......... 31,646 97,392,952 -- -- 97,424,598
Net income................... -- -- -- 59,184,008 59,184,008
-------- ------------ ------------ ------------ ------------
Balance, December 31, 2000... $254,521 $293,396,723 $(12,101,199) $ 50,604,110 $332,154,155
Stock issued for benefit
plans
(11,945 shares)............ 72 354,973 68,408 -- 423,453
Stock options exercised
(152,915 shares)........... 1,529 1,942,634 -- -- 1,944,163
Employee stock purchase plan
(22,360 shares)............ 224 478,490 -- -- 478,714
Net loss..................... -- -- -- (22,347,765) (22,347,765)
-------- ------------ ------------ ------------ ------------
Balance, December 31, 2001... $256,346 $296,172,820 $(12,032,791) $ 28,256,345 $312,652,720
======== ============ ============ ============ ============

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

(1) $.01 par value

See accompanying Notes to Consolidated Financial Statements.
F-5

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEAR ENDED DECEMBER 31,
-----------------------------------------------
2001 2000 1999
------------- ------------- -------------

Cash Flows from Operating Activities:
Net income (loss)........................... $ (22,347,765) $ 59,184,008 $ 19,286,574
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities --
Depreciation, depletion, and
amortization........................... 59,502,040 47,771,393 42,348,901
Write-down of oil and gas properties..... 98,862,247 -- --
Deferred income taxes.................... (12,555,618) 33,413,626 10,435,115
Deferred revenue amortization related to
production payment..................... -- (587,629) (1,056,284)
Other.................................... 509,973 1,075,848 628,614
Change in assets and liabilities --
(Increase) decrease in accounts
receivable.......................... 16,207,377 (14,308,274) (2,889,530)
Increase in accounts payable and
accrued liabilities, excluding
income taxes payable................ 12,984 1,601,042 4,850,036
Increase (decrease) in income taxes
payable............................. (306,983) 47,213 --
------------- ------------- -------------
Net Cash Provided by Operating
Activities........................ 139,884,255 128,197,227 73,603,426
------------- ------------- -------------
Cash Flows from Investing Activities:
Additions to property and equipment......... (275,126,333) (173,277,356) (78,112,550)
Proceeds from the sale of property and
equipment................................ 9,274,440 3,844,375 4,531,935
Net cash received as operator of oil and gas
properties............................... 5,927,539 19,769,213 5,995,842
Net cash received (distributed) as operator
of partnerships and joint ventures....... (3,574,601) 2,674,593 (433,114)
Other....................................... (534,898) (1,329) (131,135)
------------- ------------- -------------
Net Cash Used in Investing
Activities........................ (264,033,853) (146,990,504) (68,149,022)
------------- ------------- -------------
Cash Flows from Financing Activities:
Proceeds from (payments of) long-term
debt..................................... -- (15,203,000) 124,045,000
Net proceeds from (payments of) bank
borrowings............................... 123,400,000 10,600,000 (146,200,000)
Net proceeds from issuances of common
stock.................................... 1,633,508 2,697,561 42,719,776
Purchase of treasury stock.................. -- -- (1,462,740)
Payments of debt issuance costs............. (721,756) -- (3,501,441)
------------- ------------- -------------
Net Cash Provided by (Used in)
Financing Activities.............. 124,311,752 (1,905,439) 15,600,595
------------- ------------- -------------
Net Increase (Decrease) in Cash and Cash
Equivalents................................. $ 162,154 $ (20,698,716) $ 21,054,999
Cash and Cash Equivalents at Beginning of
Year........................................ 1,986,932 22,685,648 1,630,649
------------- ------------- -------------
Cash and Cash Equivalents at End of Year...... $ 2,149,086 $ 1,986,932 $ 22,685,648
============= ============= =============
Supplemental Disclosures of Cash Flows
Information:
Cash paid during year for interest, net of
amounts capitalized......................... $ 12,207,205 $ 15,528,280 $ 8,618,020
Cash paid during year for income taxes........ $ 441,926 $ -- $ --
Non-Cash Financing Activity:
Conversion of convertible notes to common
stock....................................... $ -- $ 99,797,000 $ --

See accompanying Notes to Consolidated Financial Statements.
F-6

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION. The accompanying consolidated financial
statements include the accounts of Swift Energy Company (Swift) and our wholly
owned subsidiaries, which are engaged in the exploration, development,
acquisition, and operation of oil and natural gas properties, with a focus on
onshore oil and natural gas reserves in Texas and Louisiana, as well as onshore
oil and natural gas reserves in New Zealand. Our investments in associated oil
and gas partnerships and joint ventures are accounted for using the
proportionate consolidation method, whereby our proportionate share of each
entity's assets, liabilities, revenues, and expenses are included in the
appropriate classifications in the consolidated financial statements.
Intercompany balances and transactions have been eliminated in preparing the
consolidated financial statements. Certain reclassifications have been made to
prior year amounts to conform to current year presentation.

USE OF ESTIMATES. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities, if
any, at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from estimates.

PROPERTY AND EQUIPMENT. We follow 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 exploration, development and
acquisition of oil and gas reserves are capitalized. Under the full cost method
of accounting, such costs may be incurred both prior to or after the acquisition
of a property and include lease acquisitions, geological and geophysical
services, drilling, completion, equipment, and certain general and
administrative costs directly associated with acquisition, exploration, and
development activities. Interest costs related to unproved properties are also
capitalized to unproved oil and gas properties. General and administrative costs
related to production and general overhead are expensed as incurred.

No gains or losses are recognized upon the sale or disposition of oil and
gas properties, except in transactions involving a significant amount of
reserves. The proceeds from the sale of oil and gas properties are generally
treated as a reduction of oil and gas property costs. Fees from associated oil
and gas exploration and development limited partnerships are credited to oil and
gas property costs to the extent they do not represent reimbursement of general
and administrative expenses currently charged to expense.

Future development, site restoration, and dismantlement and abandonment
costs, net of salvage values, are estimated property-by-property based on
current economic conditions, and are amortized to expense as our capitalized oil
and gas property costs are amortized. The vast majority of our properties are
onshore, and historically the salvage value of the tangible equipment offsets
our site restoration and dismantlement and abandonment costs.

We compute the provision for depreciation, depletion, and amortization of
oil and gas properties by the unit-of-production method. Under this method, we
compute the provision by multiplying the total unamortized costs of oil and gas
properties -- including future development, site restoration, and dismantlement
and abandonment costs, but excluding costs of unproved properties -- by an
overall rate determined by dividing the physical units of oil and gas produced
during the period by the total estimated units of proved oil and gas reserves.
This calculation is done on a country-by-country basis. 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.

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

be impaired, we evaluate, among other factors, current drilling results, lease
expiration dates, current oil and gas industry conditions, international
economic conditions, capital availability, foreign currency exchange rates, the
political stability in the countries in which we have an investment, and
available geological and geophysical information. Any impairment assessed is
added to the cost of proved properties being amortized. To the extent costs
accumulate in countries where there are no proved reserves, any costs determined
by management to be impaired are charged to income.

The calculation of the Ceiling Test and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves. There are
numerous uncertainties inherent in estimating quantities of proved reserves and
in projecting the future rates of production, timing, and plan of development.
The accuracy of any reserves estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. Results of
drilling, testing, and production subsequent to the date of the estimate may
justify revision of such estimate. Accordingly, reserves estimates are often
different from the quantities of oil and gas that are ultimately recovered.

In addition, any unsuccessful exploratory well costs in countries in which
there are no proved reserves are charged to expense as incurred. During the
second quarter of 1999, we charged to income as additional depreciation,
depletion, and amortization costs our portion of drilling costs associated with
an unsuccessful exploratory well drilled by another operator in New Zealand.
This charge was $290,000.

Because of the delineation of our 1999 Rimu discovery with two successful
delineation wells drilled in 2000, proved reserves were recognized in New
Zealand as of December 31, 2000.

Given the volatility of oil and gas prices, it is reasonably possible that
our estimate of discounted future net cash flows from proved oil and gas
reserves could change in the near term. If oil and gas prices decline from the
Company's year end prices used in the Ceiling Test, even if only for a short
period, it is possible that additional write-downs of oil and gas properties
could occur in the future.

OIL AND GAS REVENUES. Oil and gas revenues are reported, as the product is
delivered, using the entitlement method in which we recognize our ownership
interest in production as revenue. If our sales exceed our ownership share of
production, the differences are reported as deferred revenues. Natural gas
balancing receivables are reported when our ownership share of production
exceeds sales. As of December 31, 2001, we did not have any material natural gas
imbalances.

DEFERRED CHARGES. Legal and accounting fees, underwriting fees, printing
costs, and other direct expenses associated with the public offering in November
1996 of our 6.25% Convertible Subordinated Notes (the "Convertible Notes"), with
the public offering in August 1999 of our 10.25% Senior Subordinated Notes (the
"Senior Notes"), and with our September 2001 extension of our bank credit
facility were capitalized and are amortized over the life of each of the
respective note offerings and credit facility. The Convertible Notes were called
for redemption effective December 26, 2000, and the balance of their unamortized
issuance costs at that time of $3,046,181 was either transferred to the common
stock equity accounts ($2,643,476) for the portion of the Convertible Notes
converted into common stock at the election of those note holders or was
recorded, net of taxes, as Extraordinary Loss on Early

F-8

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Extinguishment of Debt ($402,705) for the portion of the Convertible Notes
redeemed for cash. The Senior Notes mature on August 1, 2009, and the balance of
their issuance costs at December 31, 2001, was $2,956,306, net of accumulated
amortization of $545,135. The issuance costs associated with our revolving
credit facility, which closed in September 2001, have been capitalized and are
being amortized over the original life of the facility. The balance of revolving
credit facility issuance costs at December 31, 2001, was $766,876, net of
accumulated amortization of $513,573.

LIMITED PARTNERSHIPS AND JOINT VENTURES. We formed 88 limited partnerships
between 1984 and 1995 to acquire interests in producing oil and gas properties
and 13 partnerships between 1993 and 1998 to drill for oil and gas. In all of
these partnerships, Swift paid for varying percentages of the capital or front-
end costs and continuing costs of the partnerships and, in return, received
differing percentage ownership interests in the partnerships, along with
reimbursement of costs and/or payment of certain fees. At year end 2001, we
continue to serve as managing general partner of 71 of these various
partnerships, and during fiscal 2001 approximately 2.9% of our total oil and gas
sales was attributable to our interests in those partnerships.

During 1997 and 1998, eight drilling partnerships formed between 1979 and
1985 and 21 of the production purchase partnerships sold their properties and
were dissolved, in each case following a vote of the investors in the particular
partnerships approving such liquidations. Between 1999 and 2001, the investors
in all but six of the remaining partnerships voted to sell the properties or
their interests in the partnerships and dissolve. During 2001, seven drilling
partnerships and two production purchase partnerships were dissolved. We
anticipate that the liquidation and dissolution of the additional 65
partnerships will be completed by the end of 2002. The remaining six
partnerships will continue to operate until their limited partners vote
otherwise.

PRICE-RISK MANAGEMENT ACTIVITIES. In June 1998, the Financial Accounting
Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities." The statement establishes accounting and reporting
standards requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded in the balance
sheet as either an asset or a liability measured at its fair value. SFAS No. 133
requires that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. Special accounting
for qualifying hedges allows the gains and losses on derivatives to offset
related results on the hedged item in the income statements and requires that a
company must formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting. SFAS No. 133, as amended by SFAS No.
137 and SFAS No. 138, was adopted by us on January 1, 2001.

We have a policy to use derivative instruments, mainly the buying of
protection price floors, to protect against price declines in oil and gas
prices. We elected not to designate our price floors for special hedge
accounting treatment under SFAS No. 133, as amended. However, we have elected to
use mark-to-market accounting treatment for our derivative contracts. Upon
adoption of SFAS No. 133 on January 1, 2001, we recorded a net of taxes charge
of $392,868, which is recorded as a Cumulative Effect of Change in Accounting
Principle. During 2001 we recognized net gains of $1,173,094 relating to our
derivative activities, with $16,784 in unrealized losses at year-end 2001. This
activity is recorded in Price-risk management and other, net on the accompanying
statements of income.

F-9

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

INCOME TAXES. Under SFAS No. 109, "Accounting for Income Taxes," 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.

CASH AND CASH EQUIVALENTS. We consider all highly liquid debt instruments
with an initial maturity of three months or less to be cash equivalents.

CREDIT RISK DUE TO CERTAIN CONCENTRATIONS. We extend credit, primarily in
the form of monthly oil and gas sales and joint interest owners receivables, to
various companies in the oil and gas industry, which results in a concentration
of credit risk. The concentration of credit risk may be affected by changes in
economic or other conditions and may accordingly impact our overall credit risk.
However, we believe that the risk of these unsecured receivables is mitigated by
the size, reputation, and nature of the companies to which we extend credit.
During 2001, oil and gas sales to subsidiaries of Eastex Crude Company were
$31.6 million, or 18.1% of oil and gas sales, while sales to subsidiaries of
Enron were $18.2 million, or 10.4% of oil and gas sales. During 2000, oil and
gas sales to subsidiaries of Eastex Crude Company were $47.4 million, or 25.7%
of our oil and gas sales, while sales to subsidiaries of PG&E Energy Trading
Corporation were $21.2 million, or 11.5% of oil and gas sales. During 1999, oil
and gas sales to subsidiaries of Eastex Crude Company were $21.7 million, or
19.4% of our oil and gas sales. Beginning in December 2000, the subsidiaries of
PG&E Energy Trading Corporation to which we made sales were sold to subsidiaries
of El Paso Corporation. All receivables from PG&E were collected. During the
fourth quarter of 2001, we wrote off $1.4 million due to uncollected receivables
related to gas sold to Enron in November 2001. This amount is included in Other
expenses on the Consolidated Statement of Income. We have discontinued sales of
oil and gas to Enron and are selling that production to other purchasers.

RISK FACTORS. Our revenues, profitability and cash flow are substantially
dependent upon the price of and demand for oil and gas. Prices for oil and gas
are subject to wide fluctuations in response to relatively minor changes in the
supply of and demand for oil and gas, market uncertainty, and a variety of
additional factors beyond our control. We are also dependent upon the continued
success of our domestic and New Zealand exploration and development programs.
Other factors that could affect revenues, profitability, and cash flow include
the inherent uncertainty in reserves estimates, our price-risk management
activities, and the ability to replace reserves and finance our growth.

FAIR VALUE OF FINANCIAL INSTRUMENTS. Our financial instruments consist of
cash and cash equivalents, accounts receivable, accounts payable, bank
borrowings, and notes. The carrying amounts of cash and cash equivalents,
accounts receivable, and accounts payable approximate fair value due to the
highly liquid nature of these short-term instruments. The fair values of the
bank borrowings approximate the carrying amounts as of December 31, 2001 and
2000, and were determined based upon interest rates currently available to us
for borrowings with similar terms. Based on quoted market prices as of the
respective dates, the fair values of our Senior Notes were $126.5 million and
$115.1 million at December 31, 2001 and 2000, respectively. The carrying value
of our Senior Notes was $124.2 million and $124.1 million at December 31, 2001
and 2000, respectively.

NEW ACCOUNTING PRONOUNCEMENTS. In June 2001, the Financial Accounting
Standards Board issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." The statement requires entities to record the fair value of a
liability for legal obligations associated with the retirement obligations of
tangible long-lived assets in the period in which it is incurred. When the
liability is initially recorded, the entity increases the carrying amount of the
related long-lived asset. Over time, accretion of the liability is recognized
each period, and the capitalized cost is depreciated over the useful life of the
related asset. Upon settlement of the liability, an entity either settles the
obligation for its recorded amount or incurs a gain or loss upon settlement. We
currently do not include dismantlement and abandonment costs in our depletion
calculation as the vast majority of our properties are onshore and the salvage
value of the tangible equipment offsets our dismantlement and abandonment costs.
This standard will require us to
F-10

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

record a liability for the fair value of our dismantlement and abandonment
costs, excluding salvage values. The standard is effective for fiscal years
beginning after June 15, 2002, with earlier application encouraged. The Company
is currently evaluating the effect of adopting Statement No. 143 on its
financial statements and will adopt the statement on January 1, 2003.

2. EARNINGS PER SHARE

Basic earnings per share ("Basic EPS") have been computed using the
weighted average number of common shares outstanding during the respective
periods. The calculation of diluted earnings per share ("Diluted EPS") for 1999
and 2000 assumes conversion of our Convertible Notes as of the beginning of the
respective periods and the elimination of the related after-tax interest
expense. The calculation of diluted earnings per share for all periods assumes,
as of the beginning of the period, exercise of stock options and warrants using
the treasury stock method. The assumed conversion of our Convertible Notes
applies only to the 2000 period since for the 1999 period they would have been
antidilutive and since they were extinguished at year end 2000. Certain of our
stock options that would potentially dilute Basic EPS in the future were also
antidilutive for the 2001 and 1999 periods.

The following is a reconciliation of the numerators and denominators used
in the calculation of Basic and Diluted EPS for the years ended December 31,
2001, 2000, and 1999:

2001 2000 1999
---------------------------------- --------------------------------- ---------------------------------
PER PER PER
SHARE SHARE SHARE
NET LOSS SHARES AMOUNT NET INCOME SHARES AMOUNT NET INCOME SHARES AMOUNT
------------ ---------- ------ ----------- ---------- ------ ----------- ---------- ------

BASIC EPS:
Net Income (Loss) and
Share Amounts...... $(22,347,765) 24,732,099 $(0.90) $59,184,008 21,244,684 $2.79 $19,286,574 18,050,106 $1.07
Dilutive Securities:
6.25% Convertible
Notes............ -- -- 4,772,418 3,546,933 -- --
Stock Options...... -- -- -- 713,112 -- 42,365
------------ ---------- ----------- ---------- ----------- ----------
DILUTED EPS:
Net Income (Loss) and
Assumed Share
Conversions........ $(22,347,765) 24,732,099 $(0.90) $63,956,426 25,504,729 $2.51 $19,286,574 18,092,471 $1.07
============ ========== =========== ========== =========== ==========

3. PROVISION FOR INCOME TAXES

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

YEAR ENDED DECEMBER 31,
----------------------------------------
2001 2000 1999
------------ ----------- -----------

Current...................................... $ 114,611 $ (29,000) $ (11,819)
Deferred..................................... (12,352,047) 33,294,480 10,461,396
------------ ----------- -----------
Total.............................. $(12,237,436) $33,265,480 $10,449,577
============ =========== ===========

There are differences between income taxes computed using the federal
statutory rate (35% for 2001, 2000, and 1999) and our effective income tax rates
(35.8%, 35.7%, and 35.1% for 2001, 2000, and 1999, respectively), primarily as
the result of state income taxes, foreign income taxes and certain tax credits
available to the Company. Foreign net income for Swift Energy New Zealand
Limited for 2001 was

F-11

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

$1,234,919. New Zealand's statutory rate and effective tax rate are 33%.
Reconciliations of income taxes computed using the statutory rate to the
effective income tax rates are as follows:

2001 2000 1999
------------ ----------- -----------

Income taxes computed at U.S. statutory
rate....................................... $(11,967,317) $32,577,772 $10,407,653
State tax provisions, net of federal
benefits................................... (279,875) 775,850 (7,801)
Provision for foreign income tax............. (24,698) -- --
Other, net................................... 34,454 (88,142) 49,725
------------ ----------- -----------
Provision (benefit) for income
taxes............................ $(12,237,436) $33,265,480 $10,449,577
============ =========== ===========

The tax effects of temporary differences representing the net deferred tax
liability (asset) at December 31, 2001 and 2000, were as follows:

2001 2000
------------ ------------

Deferred tax assets:
Alternative minimum tax credits........................ $ (1,979,399) $ (1,979,399)
Net operating loss carry forward....................... (18,877,969) (16,194,060)
------------ ------------
Total deferred tax assets...................... $(20,857,368) $(18,173,459)
Deferred tax liabilities:
Domestic oil and gas properties........................ $ 47,539,564 $ 59,097,793
Foreign oil and gas properties......................... 407,524 --
Other.................................................. 482,513 254,256
------------ ------------
Total deferred tax liabilities................. $ 48,429,601 $ 59,352,049
------------ ------------
Net deferred tax liability..................... $ 27,572,233 $ 41,178,590
============ ============

As of December 31, 2001, we had $52.7 million of net operating loss carry
forwards, which expire as follows: $29.0 million, $20.1 million, $3.0 million
and $0.6 million in 2013, 2014, 2015 and 2016, respectively.

We did not record any valuation allowances against deferred tax assets at
December 31, 2001 and 2000.

At December 31, 2001, we had alternative minimum tax credits of $1,979,399
that carry forward indefinitely and are available to reduce future regular tax
liability to the extent they exceed the related tentative minimum tax otherwise
due.

4. LONG-TERM DEBT

Our long-term debt as of December 31, 2001 and 2000, is as follows:

2001 2000
------------ ------------

Bank Borrowings.......................................... $134,000,000 $ 10,600,000
Senior Notes............................................. 124,197,128 124,129,485
------------ ------------
Long-Term Debt................................. $258,197,128 $134,729,485
============ ============

BANK BORROWINGS. At December 31, 2001, we had outstanding borrowings of
$134.0 million under our $250.0 million credit facility with a syndicate of nine
banks which has a borrowing base of $200 million. At December 31, 2000, we had
borrowings of $10.6 million under our credit facility. The interest rate is
either (a) the lead bank's prime rate (4.75% at December 31, 2001) or (b) the
adjusted
F-12

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

London Interbank Offered Rate ("LIBOR") plus the applicable margin depending on
the level of outstanding debt. The applicable margin is based on the ratio of
the outstanding balance to the last calculated borrowing base. Of the $134.0
million borrowed at December 31, 2001, $130.0 million was borrowed at the LIBOR
rate plus applicable margin, which averaged 3.64%. Of the $10.6 million borrowed
at December 31, 2000, $5.0 million was borrowed at the LIBOR rate plus
applicable margin (which averaged 7.89% at December 31, 2000).

Upon closing of the New Zealand TAWN acquisition in January 2002, our
credit facility increased to $300.0 million and the borrowing base increased to
$275.0 million. For further information on this acquisition, see Footnote 9
"Subsequent Events."

The terms of our credit facility include, among other restrictions, a
limitation on the level of cash dividends (not to exceed $5.0 million 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 our common stock. We are currently in compliance with the
provisions of this agreement. Effective September 28, 2001, the credit facility
was extended until October 1, 2005.

Interest expense on the credit facility, including commitment fees and
amortization of debt issuance costs, totaled $5,833,564 in 2001, $654,936 in
2000, and $6,107,270 in 1999.

CONVERTIBLE NOTES. In November 1996, we sold $115.0 million of 6.25%
Convertible Subordinated Notes due 2006. The Convertible Notes were unsecured
and convertible into Swift common stock at the option of the holders at an
adjusted conversion price of $31.534 per share. Interest on the notes was
payable semiannually, on May 15 and November 15. On December 11, 2000, we called
for the redemption of our Convertible Notes effective December 26, 2000, at
103.75% of their principal amount. Holders of approximately $100.0 million of
the Convertible Notes elected to convert their notes into 3,164,644 shares of
our common stock. Holders of the remaining $15.0 million of the Convertible
Notes elected to redeem their notes for cash plus accrued interest. This cash
redemption resulted in our recognizing an Extraordinary Loss on the Early
Extinguishment of Debt (net of taxes) of $0.6 million, or $1.0 million before
taxes.

Interest expense on the Convertible Notes, including amortization of debt
issuance costs, totaled $7,426,599 in 2000 and $7,569,361 in 1999.

SENIOR NOTES. Our Senior Notes consist of $125.0 million of 10.25% Senior
Subordinated Notes due 2009. The Senior Notes were issued at 99.236% of the
principal amount on August 4, 1999, and will mature on August 1, 2009. The
Senior Notes are unsecured senior subordinated obligations and are subordinated
in right of payment to all our existing and future senior debt, including our
bank debt. Interest on the Senior Notes is payable semiannually, on February 1
and August 1, and commenced with the first payment on February 1, 2000. On or
after August 1, 2004, the Senior Notes are redeemable for cash at the option of
Swift, with certain restrictions, at 105.125% of principal, declining to 100% in
2007. In addition, prior to August 1, 2002, we may redeem up to 33.33% of the
Senior Notes with the proceeds of qualified offerings of our equity at 110.25%
of the principal amount of the Senior Notes, together with accrued and unpaid
interest. Upon certain changes in control of Swift, each holder of Senior Notes
will have the right to require us to repurchase the Senior Notes at a purchase
price in cash equal to 101% of the principal amount, plus accrued and unpaid
interest to the date of purchase.

Interest expense on the Senior Notes, including amortization of debt
issuance costs and discount, totaled $13,123,052 in 2001, $13,092,127 in 2000,
and $5,303,266 in 1999.

DEBT MATURITIES. Our bank borrowings are due in October 2005, and our
Senior Notes are due in August 2009.

F-13

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

5. COMMITMENTS AND CONTINGENCIES

Total rental and lease expenses were $1,322,611 in 2001, $1,255,474 in
2000, and $1,272,497 in 1999. Our remaining minimum annual obligations under
non-cancelable operating lease commitments are $1,393,095 for 2002, $1,480,092
for 2003, $1,492,268 for 2004, and $248,711 for 2005. The rental and lease
expenses and remaining minimum annual obligations under non-cancelable operating
lease commitments primarily relate to the lease of our office space in Houston,
Texas.

As of December 31, 2001, we were the managing general partner of 71 limited
partnerships. Because we serve as the general partner of these entities, under
state partnership law we are 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.

6. STOCKHOLDERS' EQUITY

COMMON STOCK. During the third quarter of 1999, we issued 4.6 million
shares of common stock at a price of $9.75 per share. Gross proceeds from this
offering were $44,850,000 with issuance costs of $2,888,690.

In December 2000, the holders of approximately $100.0 million of our
Convertible Notes converted such notes into 3,164,644 shares of our common
stock, which resulted in an increase in our common stock capital accounts of
approximately $97.4 million.

STOCK-BASED COMPENSATION PLANS. We have two current stock option plans,
the 2001 Omnibus Stock Compensation Plan, which was adopted by our board of
directors in February 2001 and was approved by shareholders at the 2001 Annual
Meeting of Shareholders, and the 1990 non-qualified plan. In addition, we have
an employee stock purchase plan. No further grants will be made under the 1990
stock compensation plan.

Under the 2001 plan, incentive stock options and other options and awards
may be granted to employees to purchase shares of common stock. Under the 1990
non-qualified plan, non-employee members of our board of directors may be
granted options to purchase shares of common stock. Both plans provide that the
exercise prices equal 100% of the fair value of the common stock on the date of
grant. Unless otherwise provided, options become exercisable for 20% of the
shares on the first anniversary of the grant of the option and are exercisable
for an additional 20% per year thereafter. Options granted expire 10 years after
the date of grant or earlier in the event of the optionee's separation from
employment. At the time the stock options are exercised, the option price is
credited to common stock and additional paid-in capital.

F-14

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The employee stock purchase plan provides eligible employees the
opportunity to acquire shares of Swift common stock at a discount through
payroll deductions. The plan year is from June 1 to the following May 31. The
first year of the plan commenced June 1, 1993. To date, employees have been
allowed to authorize payroll deductions of up to 10% of their base salary during
the plan year by making an election to participate prior to the start of a plan
year. The purchase price for stock acquired under the plan is 85% of the lower
of the closing price of our common stock as quoted on the New York Stock
Exchange at the beginning or end of the plan year or a date during the year
chosen by the participant. Under this plan for the last three years, we have
issued 22,360 shares at a price of $21.41 in 2001, 29,889 shares at a price
range of $8.40 to $10.57 in 2000, and 22,771 shares at a price range of $5.21 to
$11.00 in 1999. The estimated weighted average fair value of shares issued under
this plan, as determined using the Black-Scholes option-pricing model, was $8.19
in 2001, $4.25 in 2000, and $4.74 in 1999. As of December 31, 2001, 362,428
shares remained available for issuance under this plan. There are no charges or
credits to income in connection with this plan.

We account for our stock option plans under Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees." As all options were
issued at a price equal to market price, no compensation expense has been
recognized. Had compensation expense for these plans been determined based on
the fair value of the options consistent with SFAS No. 123, "Accounting for
Stock-Based Compensation," our net income (loss) and earnings (loss) per share
would have been adjusted to the following pro forma amounts:

2001 2000 1999
------------ ----------- -----------

Net Income (Loss)
As Reported................................ $(22,347,765) $59,184,008 $19,286,574
Pro Forma.................................. $(26,632,624) $56,531,665 $16,869,122
Basic EPS:
As Reported................................ $ (0.90) $ 2.79 $ 1.07
Pro Forma.................................. $ (1.08) $ 2.66 $ 0.93
Diluted EPS:
As Reported................................ $ (0.90) $ 2.51 $ 1.07
Pro Forma.................................. $ (1.08) $ 2.40 $ 0.93

Pro forma compensation cost reflected above may not be representative of
the cost to be expected in future years.

F-15

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following is a summary of our stock options under these plans as of
December 31, 2001, 2000, and 1999:

2001 2000 1999
--------------------- --------------------- ---------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
---------- -------- ---------- -------- ---------- --------

Options outstanding, beginning of
period................................. 2,076,593 $11.70 2,148,511 $ 9.08 2,266,146 $ 9.03
Options granted.......................... 747,073 $31.51 645,944 $16.88 25,000 $12.50
Options canceled......................... (31,247) $14.09 (174,412) $ 8.71 (77,158) $ 8.95
Options exercised........................ (152,915) $ 8.69 (543,450) $ 8.48 (65,477) $ 8.55
---------- ---------- ----------
Options outstanding, end of period....... 2,639,504 $17.44 2,076,593 $11.70 2,148,511 $ 9.08
========== ========== ==========
Options exercisable, end of period....... 1,181,141 $11.49 897,711 $ 9.35 1,280,156 $ 8.87
========== ========== ==========
Options available for future grant, end
of period.............................. 1,155,057 181,235 950,735
========== ========== ==========
Estimated weighted average fair value per
share of options granted during the
year................................... $ 20.68 $ 10.90 $ 7.10
========== ========== ==========

The fair value of each option grant, as opposed to its exercise price, is
estimated on the date of grant using the Black-Scholes option-pricing model with
the following weighted average assumptions in 2001, 2000, and 1999,
respectively: no dividend yield; expected volatility factors of 46.9%, 46.7%,
and 44.2%; risk-free interest rates of 5.24%, 6.61%, and 5.60%; and expected
lives of 7.3, 6.7, and 7.5 years. The following table summarizes information
about stock options outstanding at December 31, 2001:

OPTIONS OUTSTANDING OPTIONS EXERCISABLE
-------------------------------------------- -------------------------
NUMBER WEIGHTED WEIGHTED NUMBER WEIGHTED
OUTSTANDING AT AVERAGE AVERAGE EXERCISABLE AT AVERAGE
RANGE OF DECEMBER 31, REMAINING EXERCISE DECEMBER 31, EXERCISE
EXERCISE PRICES 2001 CONTRACTUAL LIFE PRICE 2001 PRICE
--------------- -------------- ---------------- -------- -------------- --------

$ 5.00 to $16.99..................... 1,592,597 5.7 $ 9.50 1,012,907 $ 9.20
$17.00 to $28.99..................... 280,439 6.1 $23.25 153,785 $24.23
$29.00 to $41.00..................... 766,468 9.1 $31.84 14,449 $36.69
--------- ---------
$ 5.00 to $41.00..................... 2,639,504 6.8 $17.44 1,181,141 $11.49
========= =========

EMPLOYEE STOCK OWNERSHIP PLAN. In 1996, we established an Employee Stock
Ownership Plan ("ESOP") effective January 1, 1996. All employees over the age of
21 with one year of service are participants. This plan has a five-year cliff
vesting, and service is recognized after the ESOP effective date. The ESOP is
designed to enable our employees to accumulate stock ownership. While there will
be no employee contributions, participants will receive an allocation of stock
that has been contributed by Swift. Compensation expense is reported when such
shares are released to employees. The plan may also acquire Swift common stock
purchased at fair market value. The ESOP can borrow money from Swift to buy
Swift stock. Benefits will be paid in a lump sum or installments, and the
participants generally have the choice of receiving cash or stock. At December
31, 2001, 2000 and 1999, all of the ESOP compensation was earned.

EMPLOYEE SAVINGS PLAN. We have a savings plan under Section 401(k) of the
Internal Revenue Code. Eligible employees may make voluntary contributions into
the 401(k) savings plan with Swift contributing on behalf of the eligible
employee an amount equal to 100% of the first 2% of compensation and 75% of the
next 4% of compensation based on the contributions made by the eligible
employees. Our contribution to the 401(k) savings plan totaled $558,000,
$483,000, and $474,000 for the years ended

F-16

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

December 31, 2001, 2000, and 1999, respectively. The contribution in 2001 was
made all in common stock, while the 2000 and 1999 contributions were made half
in common stock and half in cash. The shares of common stock contributed to the
401(k) savings plan totaled 28,798, 7,175, and 21,810 shares for the 2001, 2000,
and 1999 contributions, respectively.

COMMON STOCK REPURCHASE PROGRAM. In March 1997, our board of directors
approved a common stock repurchase program that terminated as of June 30, 1999.
Under this program, we spent approximately $13.3 million to acquire 927,774
shares in the open market at an average cost of $14.34 per share. At December
31, 2001, 839,034 shares remain in treasury (net of 88,740 shares used to fund
ESOP and 401(k) contributions) with a total cost of $12,032,791 and are included
in "Treasury stock held, at cost" on the balance sheet.

SHAREHOLDER RIGHTS PLAN. In August 1997, the board of directors declared a
dividend of one preferred share purchase right on each outstanding share of
Swift common stock. The rights are not currently exercisable but would become
exercisable if certain events occurred relating to any person or group acquiring
or attempting to acquire 15% or more of our outstanding shares of common stock.
Thereafter, upon certain triggers, each right not owned by an acquirer allows
its holder to purchase Swift securities with a market value of two times the
$150 exercise price.

7. RELATED-PARTY TRANSACTIONS

8. FOREIGN ACTIVITIES

New Zealand

Swift Operated Permits. Our activity in New Zealand began in 1995 with the
issuance of the first of two petroleum exploration permits. After surrendering a
portion of our permit acreage in 1998, combining the two permits and expanding
the permit acreage in 1999, and relinquishing 50% of the acreage in 2001 as we
extended our petroleum exploration permit, our permit 38719 as of year end 2001
covered approximately 50,300 acres in the Taranaki Basin of New Zealand's north
island, with all but 12,800 acres onshore. At December 31, 2001, we had a 90%
working interest in this permit and had fulfilled all current obligations under
this permit.

In late 1999, we completed our first exploratory well on this permit, the
Rimu-A1, and a production test was performed. During the second half of 2000, we
drilled and successfully tested two development wells, the Rimu-B1 and the
Rimu-B2. In 2001 we drilled and tested three more Rimu development wells, the
Rimu-A2, Rimu-A3 and Rimu-B3. The Rimu-A3 was successful; the Rimu-A2 and
Rimu-B3 were dry. Early in 2002, the Rimu-A2 was sidetracked to the Tariki sand
and is currently awaiting completion. The Rimu-B3 was also sidetracked in early
2002 and again was unsuccessful. In 2001, we also drilled the Kauri-A1
exploratory well, the Kauri-A2 development well, and the Kauri-B1 exploratory
well. In the Kauri-A-1 we tested the Upper Tariki sands and still have further
zones to test. The Kauri-A2 well

F-17

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

successfully tested the Manutahi sands. The Kauri-B1 was drilled approximately
1.75 miles to the southeast of the Kauri-A pad and targeted the Manutahi sands.
This well was plugged and abandoned in 2001. Our portion of the drilling,
completion, and testing costs incurred on the wells within our permits during
2001 was approximately $26.0 million. Our portion of prospect costs on our
permits during 2001 was approximately $5.1 million, which included obtaining 2-D
seismic data in the last half of the year for the Rata prospect. We incurred
$22.5 million on the production facilities that we expect to be commissioned
near the end of the first quarter of 2002.

In 2000, we entered into an agreement with Fletcher Challenge Energy
Limited whereby we would earn a 25% participating interest in petroleum
exploration permit 38730 containing approximately 48,900 acres. In May 2001,
Fletcher relinquished their interest in the permit, and we then assumed 100%
working interest in such permit by means of committing to an acceptable work
plan. Such plan required us to acquire a minimum of 30 kilometers of new 2D
seismic data, which we completed in 2001. Rather than commit to drill a new well
in 2002 as the work plan called for, we surrendered this project in February
2002.

Non-Operated Permits. In 1998, we entered into agreements for a 25%
working interest in an exploration permit, permit 38712, held by Marabella
Enterprises Ltd., a subsidiary of Bligh Oil & Minerals, an Australian company,
and a 7.5% working interest held by Antrim Oil and Gas Limited, a Canadian
company, in a second permit, permit 38716, operated by Marabella. In turn, Bligh
and Antrim each became 5% working interest owners in our permit 38719.
Unsuccessful exploratory wells were drilled on these two permits, and we charged
$0.4 million against earnings in 1998 and $0.3 million in 1999. All of the
acreage on the permit 38712 was surrendered in 2000. The exploratory well on
permit 38716 has been temporarily abandoned pending a further evaluation. It is
currently anticipated that this well will be re-entered and sidetracked to
target a location to the west of the initial well. A five-year extension was
granted on permit 38716 in 2001 upon the surrender of 50% of the acreage.

In 2000, we entered into an agreement with Fletcher Challenge Energy
Limited whereby we will earn a 20% participating interest in petroleum
exploration permit 38718 containing approximately 57,400 acres. In January 2001,
the operator temporarily abandoned the Tuihu #1 exploratory well on permit 38718
pending further analysis. The permit now contains approximately 28,700 acres
after a scheduled surrender during December 2000.

Costs Incurred. During 2001, our costs incurred in New Zealand totaled
$54.5 million, including $25.7 million for drilling, $5.5 million for prospect
costs, $22.5 million for production facilities, and $0.8 million in evaluation
costs for the acquisition of the TAWN assets, which closed in January 2002.
These costs also included $0.6 million of costs incurred on permits operated by
others: $0.2 million of drilling costs and $0.4 million of prospect costs. As of
December 31, 2001, our investment in New Zealand totaled approximately $84.4
million. As we have recorded proved undeveloped reserves relating to our
successful drilling activities, $45.5 million of our investment costs has been
included in the proved properties portion of oil and gas properties and $38.8
million has been included as unproved properties at the end of 2001. Our
development strategy includes having Rimu/Kauri production on line for oil and
gas sales in New Zealand near the end of the first quarter of 2002.

Russia

In 1993, we entered into a Participation Agreement with Senega, a Russian
Federation joint stock company, to assist in the development and production of
reserves from two fields in Western Siberia and received a 5% net profits
interest. We also purchased a 1% net profits interest. Our investment in Russia
was fully impaired in the third quarter of 1998. We retain a minimum 6% net
profits interest from the sale of hydrocarbon products from the fields. The
value of our net profits interest depends upon either the successful development
of production from the fields by others or their sale of the fields.
F-18

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

9. SUBSEQUENT EVENTS

SUPPLEMENTAL INFORMATION (UNAUDITED)

CAPITALIZED COSTS. The following table presents our aggregate capitalized
costs relating to oil and gas producing activities and the related depreciation,
depletion, and amortization:

TOTAL DOMESTIC NEW ZEALAND
-------------- ------------- -----------

DECEMBER 31, 2001
Proved oil and gas properties.................... $ 974,698,428 $ 929,172,460 $45,525,968
Unproved oil and gas properties.................. 95,943,163 57,096,694 38,846,469
-------------- ------------- -----------
1,070,641,591 986,269,154 84,372,437
Accumulated depreciation, depletion, and
amortization................................... (442,337,531) (442,166,052) (171,479)
-------------- ------------- -----------
Net capitalized costs.................. $ 628,304,060 $ 544,103,102 $84,200,958
============== ============= ===========
DECEMBER 31, 2000
Proved oil and gas properties.................... $ 753,426,124 $ 732,265,674 $21,160,450
Unproved oil and gas properties.................. 55,512,872 46,833,274 8,679,598
-------------- ------------- -----------
808,938,996 779,098,948 29,840,048
Accumulated depreciation, depletion, and
amortization................................... (284,886,168) (284,886,168) --
-------------- ------------- -----------
Net capitalized costs.................. $ 524,052,828 $ 494,212,780 $29,840,048
============== ============= ===========

F-19

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Of the $57,096,694 of domestic unproved property costs (primarily seismic
and lease acquisition costs) at December 31, 2001, excluded from the amortizable
base, $26,707,313 was incurred in 2001, $9,545,964 was incurred in 2000,
$5,640,587 was incurred in 1999, and $15,202,830 was incurred in prior years.
When we are in an active drilling mode, we evaluate the majority of these
unproved costs within a two to four year time frame. In response to market
conditions in 1998, we decreased our 1999 drilling expenditures when compared to
prior years, which, when coupled with the $15.3 million of leasehold properties
acquired in the Brookeland and Masters Creek areas in 1998, may extend the
evaluation time frame of such costs. Consequently, in response to market
conditions, we have decreased our 2002 drilling expenditures as well.

Of the $38,846,469 of net New Zealand unproved property costs at December
31, 2001, excluded from the amortizable base, $30,383,713 was incurred in 2001,
$5,013,539 was incurred in 2000, $907,972 was incurred in 1999, and $2,541,245
was incurred in prior years. We expect to continue drilling in New Zealand to
delineate our prospects there, with seven wells planned for drilling in 2002. We
expect to complete our evaluation of current unevaluated costs over the next two
to three years. Upon the startup of the Rimu Production Station near the end of
the first quarter of 2002, $23.6 million of these unproved property costs will
be moved to the proved properties classification and will begin being
depreciated.

F-20

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

COSTS INCURRED. The following table sets forth costs incurred related to
our oil and gas operations:

YEAR ENDED DECEMBER 31, 2001
-----------------------------------------
TOTAL DOMESTIC NEW ZEALAND
------------ ------------ -----------

Acquisition of proved properties..................... $ 41,286,539 $ 40,491,203 $ 795,336
Lease acquisitions(1)................................ 31,225,493 25,688,068 5,537,425
Exploration.......................................... 41,981,536 35,944,405 6,037,131
Development.......................................... 132,246,713 112,597,856 19,648,857
------------ ------------ -----------
Total acquisition, exploration, and
development(2)........................... $246,740,281 $214,721,532 $32,018,749
------------ ------------ -----------
Processing plants.................................... $ 23,331,095 $ 817,454 $22,513,641
Field compression facilities......................... 319,703 319,703 --
------------ ------------ -----------
Total plants and facilities................ $ 23,650,798 $ 1,137,157 $22,513,641
------------ ------------ -----------
Total costs incurred................................. $270,391,079 $215,858,689 $54,532,390
============ ============ ===========

YEAR ENDED DECEMBER 31, 2000
-----------------------------------------
TOTAL DOMESTIC NEW ZEALAND
------------ ------------ -----------

Acquisition of proved properties.................... $ 34,191,883 $ 34,191,883 $ --
Lease acquisitions(1)............................... 20,842,103 16,315,749 4,526,354
Exploration......................................... 20,150,834 18,524,883 1,625,951
Development......................................... 104,083,409 93,931,500 10,151,909
------------ ------------ -----------
Total acquisition, exploration, and
development(2).......................... $179,268,229 $162,964,015 $16,304,214
------------ ------------ -----------
Processing plants................................... $ 1,819,464 $ 755,119 $ 1,064,345
Field compression facilities........................ 203,789 203,789 --
------------ ------------ -----------
Total plants and facilities............... $ 2,023,253 $ 958,908 $ 1,064,345
------------ ------------ -----------
Total costs incurred................................ $181,291,482 $163,922,923 $17,368,559
============ ============ ===========

YEAR ENDED DECEMBER 31, 1999
-----------------------------------------
TOTAL DOMESTIC NEW ZEALAND
------------ ------------ -----------

Acquisition of proved properties.................... $ 18,526,939 $ 18,526,939 $ --
Lease acquisitions(1)............................... 10,382,672 9,251,658 1,131,014
Exploration......................................... 11,019,430 5,101,330 5,918,100
Development......................................... 39,891,868 39,891,868 --
------------ ------------ -----------
Total acquisition, exploration, and
development(2).......................... $ 79,820,909 $ 72,771,795 $ 7,049,114
------------ ------------ -----------
Processing plants................................... $ 1,607,559 $ 1,607,559 $ --
Field compression facilities........................ 171,535 171,535 --
------------ ------------ -----------
Total plants and facilities............... $ 1,779,094 $ 1,779,094 $ --
------------ ------------ -----------
Total costs incurred................................ $ 81,600,003 $ 74,550,889 $ 7,049,114
============ ============ ===========

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

(1) These are actual amounts as incurred by year, including both proved and
unproved lease costs. The annual lease acquisition amounts added to proved
oil and gas properties in 2001, 2000, and 1999 were $22,470,263,
$16,791,834, and $14,389,680, respectively.

(2) Includes capitalized general and administrative costs directly associated
with the acquisition, exploration, and development efforts of approximately
$11,600,000, $10,300,000, and $8,500,000 in 2001, 2000, and 1999,
respectively. In addition, total includes $6,256,222, $5,043,206, and
$4,142,098 in 2001, 2000, and 1999, respectively, of capitalized interest on
unproved properties.

F-21

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

RESULTS OF OPERATIONS. New Zealand operations began in 2001 while all our
oil and gas operations in 2000 and 1999 were domestic. The following table sets
forth results of our oil and gas operations:

YEAR ENDED DECEMBER 31, 2001
--------------------------------------------
TOTAL DOMESTIC NEW ZEALAND
------------ ------------ ------------

Oil and gas sales................................ $181,184,635 $179,360,844 $ 1,823,791
Oil and gas production costs..................... (36,719,609) (36,554,418) (165,191)
Depreciation and depletion....................... (58,589,116) (58,417,637) (171,479)
Write-down of oil and gas properties............. (98,862,247) (98,862,247) --
------------ ------------ ------------
(12,986,337) (14,473,458) 1,487,121
Provision (benefit) for income taxes............. (4,647,810) (5,138,560) 490,750
------------ ------------ ------------
Results of producing activities.................. $ (8,338,527) $ (9,334,898) $ 996,371
============ ============ ============
Amortization per physical unit of production
(equivalent Mcf of gas)........................ $ 1.31 $ 1.32 $ 0.34
============ ============ ============

YEAR ENDED DECEMBER 31, 2000
--------------------------------------------
TOTAL DOMESTIC NEW ZEALAND
------------ ------------ ------------

Oil and gas sales................................ $189,138,947 $189,138,947 $ --
Oil and gas production costs..................... (29,220,315) (29,220,315) --
Depreciation and depletion....................... (46,849,819) (46,849,819) --
------------ ------------ ------------
113,068,813 113,068,813 --
Provision for income taxes....................... 40,365,566 40,365,566 --
------------ ------------ ------------
Results of producing activities.................. $ 72,703,247 $ 72,703,247 $ --
============ ============ ============
Amortization per physical unit of production
(equivalent Mcf of gas)........................ $ 1.11 $ 1.11 $ --
============ ============ ============

YEAR ENDED DECEMBER 31, 1999
--------------------------------------------
TOTAL DOMESTIC NEW ZEALAND
------------ ------------ ------------

Oil and gas sales................................ $108,898,696 $108,898,696 $ --
Oil and gas production costs..................... (19,645,740) (19,645,740) --
Depreciation and depletion....................... (41,410,106) (41,410,106) --
------------ ------------ ------------
47,842,850 47,842,850 --
Provision for income taxes....................... 16,792,840 16,792,840 --
------------ ------------ ------------
Results of producing activities.................. $ 31,050,010 $ 31,050,010 $ --
============ ============ ============
Amortization per physical unit of production
(equivalent Mcf of gas)........................ $ 0.97 $ 0.97 $ --
============ ============ ============

F-22

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SUPPLEMENTAL RESERVE INFORMATION. The following information presents
estimates of our proved oil and gas reserves. Reserves were determined by us and
audited by H. J. Gruy and Associates, Inc. ("Gruy"), independent petroleum
consultants. Gruy's summary report dated February 14, 2002, is set forth as an
exhibit to the Form 10-K Report for the year ended December 31, 2001, and
includes definitions and assumptions that served as the basis for the audit of
proved reserves and future net cash flows. Such definitions and assumptions
should be referred to in connection with the following information:

Estimates of Proved Reserves

TOTAL DOMESTIC NEW ZEALAND
------------------------- ------------------------- ------------------------
OIL, NGL, OIL, NGL, OIL, NGL,
AND AND AND
NATURAL GAS CONDENSATE NATURAL GAS CONDENSATE NATURAL GAS CONDENSATE
(MCF) (BBLS) (MCF) (BBLS) (MCF) (BBLS)
------------ ---------- ------------ ---------- ----------- ----------

Proved reserves as of December 31,
1998(1)................................ 352,400,835 13,957,925 352,400,835 13,957,925 -- --
Revisions of previous estimates(2)..... (31,189,450) 2,058,725 (31,189,450) 2,058,725 -- --
Purchases of minerals in place......... 9,159,780 1,822,858 9,159,780 1,822,858 -- --
Sales of minerals in place............. (3,762,799) (260,287) (3,762,799) (260,287) -- --
Extensions, discoveries, and other
additions............................ 30,107,908 5,791,966 30,107,908 5,791,966 -- --
Production(3).......................... (26,756,524) (2,564,924) (26,756,524) (2,564,924) -- --
------------ ---------- ------------ ---------- ----------- ----------
Proved reserves as of December 31,
1999(1)................................ 329,959,750 20,806,263 329,959,750 20,806,263 -- --
Revisions of previous estimates(2)..... (4,300,787) (455,606) (4,300,787) (455,606) -- --
Purchases of minerals in place......... 26,567,925 2,196,547 26,567,925 2,196,547 -- --
Sales of minerals in place............. (363,262) (76,288) (363,262) (76,288) -- --
Extensions, discoveries, and other
additions............................ 93,869,841 15,134,694 38,556,364 3,943,807 55,313,477 11,190,887
Production(3).......................... (27,119,491) (2,472,014) (27,119,491) (2,472,014) -- --
------------ ---------- ------------ ---------- ----------- ----------
Proved reserves as of December 31,
2000................................... 418,613,976 35,133,596 363,300,499 23,942,709 55,313,477 11,190,887
Revisions of previous estimates(2)..... (122,127,541) 5,621,556 (101,693,477) 8,460,690 (20,434,064) (2,839,134)
Purchases of minerals in place......... 10,038,803 7,430,591 10,038,803 7,430,591 -- --
Sales of minerals in place............. (7,508,064) (555,586) (7,508,064) (555,586) -- --
Extensions, discoveries, and other
additions............................ 52,353,909 8,907,852 50,810,697 6,257,441 1,543,212 2,650,411
Production............................. (26,458,958) (3,055,373) (26,458,958) (2,971,112) -- (84,261)
------------ ---------- ------------ ---------- ----------- ----------
Proved reserves as of December 31,
2001(4)................................ 324,912,125 53,482,636 288,489,500 42,564,733 36,422,625 10,917,903
============ ========== ============ ========== =========== ==========
Proved developed reserves:
December 31, 1998...................... 197,105,963 7,142,566 197,105,963 7,142,566 -- --
December 31, 1999...................... 174,046,096 8,437,299 174,046,096 8,437,299 -- --
December 31, 2000...................... 215,169,833 10,980,196 215,169,833 10,980,196 -- --
December 31, 2001(4)................... 181,651,578 23,759,574 167,401,736 20,393,142 14,249,842 3,366,432

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

(1) Proved reserves exclude quantities subject to our volumetric production
payment agreement, which expired with the last required delivery of volumes
in October 2000.

(2) Revisions of previous 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, 2001, were based upon
prices in effect at year end. The weighted average of such year end prices
for total, domestic, and New Zealand were $2.51, $2.68, and $1.18 per Mcf of
natural gas and $18.45, $18.51, and $18.25 per barrel of oil, respectively.
This compares to $9.86, $11.25, and $0.71 per Mcf and $24.62, $25.50, and
$22.30 per barrel as of December 31, 2000, for total, domestic, and New
Zealand, respectively.

(3) Natural gas production for 1999 and 2000 excludes 728,235 and 405,130 Mcf,
respectively, delivered under our volumetric production payment agreement.

(4) We acquired 62.1 Bcfe and 5.7 Bcfe from the TAWN and Antrim acquisitions,
respectively, in New Zealand. These reserves estimates at December 31, 2001,
are not included in the above table. The TAWN reserves were all proved
developed while the Antrim reserves were 34% proved developed.

F-23

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS. The standardized
measure of discounted future net cash flows relating to proved oil and gas
reserves is as follows:

YEAR ENDED DECEMBER 31, 2001
----------------------------------------------
TOTAL DOMESTIC NEW ZEALAND
-------------- -------------- ------------

Future gross revenues........................... $1,706,475,138 $1,485,480,927 $220,994,211
Future production costs......................... (483,588,857) (436,141,429) (47,447,428)
Future development costs........................ (198,172,628) (185,347,628) (12,825,000)
-------------- -------------- ------------
Future net cash flows before income taxes....... 1,024,713,653 863,991,870 160,721,783
Future income taxes............................. (261,635,331) (208,726,729) (52,908,602)
-------------- -------------- ------------
Future net cash flows after income taxes........ 763,078,322 655,265,141 107,813,181
Discount at 10% per annum....................... (308,520,417) (274,882,174) (33,638,243)
-------------- -------------- ------------
Standardized measure of discounted future net
cash flows relating to proved oil and gas
reserves...................................... $ 454,557,905 $ 380,382,967 $ 74,174,938
============== ============== ============

YEAR ENDED DECEMBER 31, 2000
----------------------------------------------
TOTAL DOMESTIC NEW ZEALAND
-------------- -------------- ------------

Future gross revenues........................... $4,995,951,799 $4,737,560,630 $258,391,169
Future production costs......................... (817,127,348) (807,436,139) (9,691,209)
Future development costs........................ (204,620,116) (180,320,116) (24,300,000)
-------------- -------------- ------------
Future net cash flows before income taxes....... 3,974,204,335 3,749,804,375 224,399,960
Future income taxes............................. (1,321,061,952) (1,243,731,594) (77,330,358)
-------------- -------------- ------------
Future net cash flows after income taxes........ 2,653,142,383 2,506,072,781 147,069,602
Discount at 10% per annum....................... (1,075,183,917) (1,017,995,158) (57,188,759)
-------------- -------------- ------------
Standardized measure of discounted future net
cash flows relating to proved oil and gas
reserves...................................... $1,577,958,466 $1,488,077,623 $ 89,880,843
============== ============== ============

YEAR ENDED DECEMBER 31, 1999
----------------------------------------------
TOTAL DOMESTIC NEW ZEALAND
-------------- -------------- ------------

Future gross revenues........................... $1,371,541,850 $1,371,541,850 $ --
Future production costs......................... (353,594,258) (353,594,258) --
Future development costs........................ (156,738,446) (156,738,446) --
-------------- -------------- ------------
Future net cash flows before income taxes....... 861,209,146 861,209,146 --
Future income taxes............................. (226,725,033) (226,725,033) --
-------------- -------------- ------------
Future net cash flows after income taxes........ 634,484,113 634,484,113 --
Discount at 10% per annum....................... (195,540,279) (195,540,279) --
-------------- -------------- ------------
Standardized measure of discounted future net
cash flows relating to proved oil and gas
reserves...................................... $ 438,943,834 $ 438,943,834 $ --
============== ============== ============

F-24

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 we reasonably expect to receive.

3. The future gross revenue streams are reduced by estimated future
costs to develop and to produce the proved reserves, as well as certain
abandonment costs based on year end cost estimates and the estimated effect
of future income taxes.

4. Future income taxes are computed by applying the statutory tax rate
to future net cash flows reduced by the tax basis of the properties, the
estimated permanent differences applicable to future oil and gas producing
activities, and tax carry forwards.

The estimates of cash flows and reserves quantities shown above are based
on year end oil and gas prices for each period. Subsequent changes to such year
end oil and gas prices could have a significant impact on discounted future net
cash flows. 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 to the Consolidated Financial Statements). 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 our 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-25

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

YEAR ENDED DECEMBER 31,
------------------------------------------------
2001 2000 1999
--------------- --------------- ------------

Beginning balance.............................. $ 1,577,958,466 $ 438,943,834 $290,273,103
--------------- --------------- ------------
Revisions to reserves proved in prior years --
Net changes in prices, production costs, and
future development costs.................. (1,692,627,074) 1,523,487,598 123,447,890
Net changes due to revisions in quantity
estimates................................. (93,669,181) (36,102,814) (23,746,974)
Accretion of discount........................ 231,325,481 56,405,451 34,078,501
Other........................................ (204,768,815) (220,119,873) 2,032,696
--------------- --------------- ------------
Total revisions.............................. (1,759,739,589) 1,323,670,362 135,812,113
New field discoveries and extensions, net of
future production and development costs...... 110,213,160 359,265,150 102,582,467
Purchases of minerals in place................. 39,544,163 160,240,785 39,282,292
Sales of minerals in place..................... (50,131,970) (598,021) (5,360,428)
Sales of oil and gas produced, net of
production costs............................. (144,262,145) (159,331,003) (88,196,672)
Previously estimated development costs
incurred..................................... 94,107,760 65,953,028 39,149,732
Net change in income taxes..................... 586,868,060 (610,185,669) (74,598,773)
--------------- --------------- ------------
Net change in standardized measure of
discounted future net cash flows............. (1,123,400,561) 1,139,014,632 148,670,731
--------------- --------------- ------------
Ending balance................................. $ 454,557,905 $ 1,577,958,466 $438,943,834
=============== =============== ============

QUARTERLY RESULTS. The following table presents summarized quarterly
financial information for the years ended December 31, 2000 and 2001:

DILUTED
BASIC EPS EPS
INCOME/ INCOME/ INCOME/
(LOSS) (LOSS) (LOSS)
BEFORE BEFORE BEFORE
EXTRA- EXTRA- EXTRA-
INCOME/ ORDINARY ORDINARY ORDINARY
(LOSS) ITEM AND ITEM AND ITEM AND BASIC DILUTED
BEFORE CHANGE IN NET CHANGE IN CHANGE IN EPS NET EPS NET
INCOME ACCOUNTING INCOME/ ACCOUNTING ACCOUNTING INCOME/ INCOME/
REVENUES TAXES PRINCIPLE (LOSS) PRINCIPLE PRINCIPLE (LOSS) (LOSS)
------------ ------------- ------------- ------------ ---------- ---------- ------- -------

2000
First Quarter......... $ 37,747,645 $ 14,919,044 $ 9,589,828 $ 9,589,828 $ 0.46 $ 0.43 0.46 0.43
Second Quarter........ 46,127,375 22,218,358 14,213,274 14,213,274 0.68 0.61 0.68 0.61
Third Quarter......... 49,525,166 24,748,163 15,832,348 15,832,348 0.74 0.66 0.74 0.66
Fourth Quarter........ 58,224,760 31,193,781 20,178,416 19,548,558 0.93 0.82 0.90 0.80
------------ ------------- ------------ ------------
Total......... $191,624,946 $ 93,079,346 $ 59,813,866 $ 59,184,008 $ 2.82 $ 2.53 $ 2.79 $ 2.51
============ ============= ============ ============
2001
First Quarter......... $ 62,392,014 $ 35,513,130 $ 22,719,653 $ 22,326,785 $ 0.92 $ 0.89 $ 0.91 $ 0.88
Second Quarter........ 52,303,265 23,408,900 14,972,946 14,972,946 0.61 0.59 0.61 0.59
Third Quarter......... 41,244,583 11,607,563 7,420,090 7,420,090 0.30 0.29 0.30 0.29
Fourth Quarter........ 27,867,628 (104,721,926) (67,067,586) (67,067,586) (2.71) (2.71) (2.71) (2.71)
------------ ------------- ------------ ------------
Total......... $183,807,490 $ (34,192,333) $(21,954,897) $(22,347,765) $(0.89) $(0.89) $(0.90) $(0.90)
============ ============= ============ ============

F-26

PROSPECTUS

$350,000,000

[SWIFT ENERGY COMPANY LOGO] SWIFT ENERGY COMPANY

DEBT SECURITIES
COMMON STOCK
PREFERRED STOCK
DEPOSITARY SHARES
WARRANTS

Swift Energy Company may offer and sell from time to time debt securities,
common stock, preferred stock, depositary shares or warrants. We will provide
specific terms of the offering and sale of these securities in supplements to
this prospectus. These terms will include the initial offering price, aggregate
amount of the offering, listing on any securities exchange or quotation system,
risk factors and the agents, dealers or underwriters, if any, to be used in
connection with the sale of these securities. Certain selling shareholders may
also from time to time offer and sell common stock under this prospectus. You
should read this prospectus and any supplement carefully before you invest.

Our common stock is traded on the New York Stock Exchange and the Pacific
Stock Exchange under the symbol "SFY."

This prospectus may not be used to sell securities unless accompanied by a
supplement to this prospectus.

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES, OR DETERMINED IF
THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.

The date of this prospectus is July 23, 2001

YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN OR INCORPORATED BY
REFERENCE IN THIS PROSPECTUS AND IN ANY PROSPECTUS SUPPLEMENT. WE HAVE NOT
AUTHORIZED ANYONE TO PROVIDE YOU WITH DIFFERENT INFORMATION. WE ARE NOT MAKING
AN OFFER OF THESE SECURITIES IN ANY STATE WHERE THE OFFER IS NOT PERMITTED. YOU
SHOULD NOT ASSUME THAT THE INFORMATION CONTAINED IN OR INCORPORATED BY REFERENCE
IN THIS PROSPECTUS IS ACCURATE AS OF ANY DATE OTHER THAN THE DATE ON THE FRONT
OF THIS PROSPECTUS OR THE APPLICABLE PROSPECTUS SUPPLEMENT.

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

TABLE OF CONTENTS

PAGE
----

ABOUT THIS PROSPECTUS....................................... 1
WHERE YOU CAN FIND MORE INFORMATION......................... 1
RISK FACTORS................................................ 2
FORWARD-LOOKING STATEMENTS.................................. 3
THE COMPANY................................................. 4
RATIO OF EARNINGS TO FIXED CHARGES.......................... 4
USE OF PROCEEDS............................................. 5
DESCRIPTION OF DEBT SECURITIES.............................. 5
General................................................... 6
Non U.S. Currency......................................... 7
Original Issue Discount Securities........................ 7
Covenants................................................. 7
Registration, Transfer, Payment and Paying Agent.......... 7
Ranking of Debt Securities................................ 8
Global Securities......................................... 9
Outstanding Debt Securities............................... 9
Redemption and Repurchase................................. 9
Conversion and Exchange................................... 9
Consolidation, Merger and Sale of Assets.................. 9
Events of Default......................................... 10
Modification and Waivers.................................. 11
Discharge, Termination and Covenant Termination........... 12
Governing Law............................................. 13
Regarding the Trustees.................................... 13
DESCRIPTION OF CAPITAL STOCK................................ 13
General................................................... 13
Common Stock.............................................. 14
Preferred Stock........................................... 14
Anti-takeover Provisions.................................. 15
DESCRIPTION OF DEPOSITARY SHARES............................ 17
DESCRIPTION OF WARRANTS..................................... 18
SELLING SHAREHOLDERS........................................ 18
PLAN OF DISTRIBUTION........................................ 19
LEGAL OPINIONS.............................................. 20
EXPERTS..................................................... 21

ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement that we filed with the
Securities and Exchange Commission using a "shelf" registration process. Under
the shelf process, we may sell any combination of the securities described in
this prospectus in one or more offerings up to a total dollar amount of
$350,000,000. In addition, under this shelf process, one or more selling
shareholders may sell our common stock in one or more offerings, which will
reduce the aggregate dollar amount we may sell. This prospectus provides you
with a general description of the securities we may offer. Each time we sell
securities, we will provide a prospectus supplement that will contain specific
information about the terms of that offering. The prospectus supplement may also
add, update or change information contained in this prospectus. You should read
both this prospectus and any prospectus supplement, together with additional
information described under the heading "WHERE YOU CAN FIND MORE INFORMATION."

As used in this prospectus, "Swift," "we," "us," and "our" refer to Swift
Energy Company and its subsidiaries.

WHERE YOU CAN FIND MORE INFORMATION

We are subject to the informational requirements of the Securities Exchange
Act of 1934, which requires us to file annual, quarterly and special reports,
proxy statements and other information with the Securities and Exchange
Commission, or the "SEC." You may read and copy any document that we file at the
Public Reference Room of the SEC at 450 Fifth Street, N.W., Washington, D.C.
20549. Please call the SEC at 1-800-SEC-0330 for further information on the
operation of its public reference room. You may also inspect our filings at the
regional offices of the SEC located at Citicorp Center, 500 West Madison Street,
Suite 1400, Chicago, Illinois 60661 and 7 World Trade Center, New York, New York
10048 or over the Internet at the SEC's web site at http://www.sec.gov, or at
our own website at http://www.swiftenergy.com.

This prospectus constitutes part of a Registration Statement on Form S-3
filed with the SEC under the Securities Act of 1933. It omits some of the
information contained in the Registration Statement, and reference is made to
the Registration Statement for further information with respect to us and the
securities we are offering. Any statement contained in this prospectus
concerning the provisions of any document filed as an exhibit to the
Registration Statement or otherwise filed with the SEC is not necessarily
complete, and in each instance reference is made to the copy of the filed
document.

The SEC allows us to "incorporate by reference" the information we file
with them, which means that we can disclose important information to you by
referring you to those documents. The information incorporated by reference is
considered to be part of this prospectus, and later information that we file
with the SEC will automatically update and supersede this information and the
information in the prospectus. We incorporate by reference the documents listed
below and any future filings made with the SEC under Sections 13(a), 13(c), 14
or 15(d) of the Securities Exchange Act of 1934 until we sell all the securities
covered by this prospectus:

1. Our Annual Report on Form 10-K for the year ended December 31,
2000;

2. Our Quarterly Report on Form 10-Q for the fiscal quarter ended
March 31, 2001;

3. The description of our common stock contained in our registration
statement on Form 8-A filed on July 24, 1981, as amended, including any
amendment or report filed before or after the date of this prospectus for
the purpose of updating the description; and

4. The description of our preferred share purchase rights contained in
our registration statement on Form 8-A filed on August 11, 1997, as amended
on April 7, 1999, including any amendment or report filed before or after
the date of this prospectus for the purpose of updating the description.

You may request a copy of these filings at no cost, by writing or
telephoning Bruce H. Vincent, Executive Vice President -- Corporate Development,
Swift Energy Company, Suite 400, 16825 Northchase Drive, Houston, Texas 77060,
phone: (281) 874-2700.
1

RISK FACTORS

There are a number of risks associated with investing in Swift and in our
industry. You should carefully review the more detailed description of risk
factors contained in the supplement to this prospectus.

- Our revenue, profitability and cash flow depend upon the prices and
demand for oil and gas. The markets for these commodities are very
volatile and steep or prolonged drops in prices can harm us financially
and hurt our ability to grow.

- Our drilling activities are subject to many risks, including the risk
that we will not discover commercially productive reservoirs. Operating
and developing oil and natural gas properties involves a number of
inherent risks, including the risk of personal injury, environmental
contamination or loss of wells. We may not be able to insure against all
of these risks.

- Our significant growth in recent years is attributable in significant
part to our acquiring producing properties. Our ability to continue to
make successful acquisitions is influenced by many factors beyond our
control. A failure to acquire producing properties on a profitable basis
in the future may significantly affect our profitability and growth.

- Estimates of our proved developed oil and natural gas reserves and the
resulting future net revenues contained in this prospectus and elsewhere
are based on a number of uncertainties. A failure to realize our
estimated prices or estimated production volumes could materially
adversely affect our revenues, profitability and financial health.

- Our ability to conduct operations in a timely and cost effective manner
depends on the availability of supplies, equipment and personnel. The oil
and gas industry is cyclical and experiences periodic shortages of
drilling rigs and other equipment, tubular goods, supplies and
experienced personnel. Shortages can delay operations and materially
increase operating and capital costs.

- We make, and will continue to make, substantial capital expenditures to
acquire, develop, produce, explore and abandon our oil and natural gas
reserves. Any decrease in our revenues, as a result of lower oil or gas
prices or otherwise, could limit our ability to replace reserves or
maintain production at current levels. If our cash flow from operations
drops significantly, we may be unable to find additional debt or equity
financing.

- Our future success depends on our ability to find, develop or acquire
additional oil and natural gas reserves that are economically
recoverable. Failure to do so will result in lower production and cash
flow.

FORWARD-LOOKING STATEMENTS

Some of the information included in this prospectus, any prospectus
supplement and the documents we have incorporated by reference contain
forward-looking statements. Forward-looking statements use forward-looking terms
such as "believe," "expect," "may," "intend," "will," "project," "budget,"
"should" or "anticipate" or other similar words. These statements discuss
"forward-looking" information such as:

- anticipated capital expenditures and budgets;

- future cash flows and borrowings;

- pursuit of potential future acquisition or drilling opportunities; and

- sources of funding for exploration and development.

These forward-looking statements are based on assumptions that we believe
are reasonable, but they are open to a wide range of uncertainties and business
risks, including the following:

- fluctuations of the prices received or demand for oil and natural gas;

- uncertainty of drilling results, reserve estimates and reserve
replacement;

- operating hazards;

- acquisition risks;

- unexpected substantial variances in capital requirements;

- environmental matters; and

- general economic conditions.

Other factors that could cause actual results to differ materially from
those anticipated are discussed in our periodic filings with the SEC, including
our Annual Report on Form 10-K for the year ended December 31, 2000.

When considering these forward-looking statements, you should keep in mind
the risk factors and other cautionary statements in this prospectus, any
prospectus supplement and the documents we have incorporated by reference. We
will not update these forward-looking statements unless the securities laws
require us to do so.

THE COMPANY

Swift Energy Company, a Texas corporation, is engaged in the exploration,
development, acquisition and operation of oil and gas properties. Historically,
our primary focus has been on U.S. onshore natural gas reserves, although we are
now also focusing on our operations in New Zealand and have interests offshore
in the Gulf of Mexico. As of December 31, 2000, we had interests in 1,528 oil
and gas wells located in eight states, offshore in the Gulf of Mexico and in New
Zealand. We operated 817 of these wells, representing 91% of our proved
reserves. At such date, our estimated proved reserves were 629.4 Bcfe, of which
approximately 67% was natural gas, with 54% of our reserves located in Texas,
22% in Louisiana and 20% in New Zealand.

Our core domestic areas for development and exploration drilling are the
AWP Olmos Area located in South Texas and the Brookeland Area, the Giddings Area
and the Masters Creek Area in the Austin Chalk trend in Texas and Louisiana. We
expect our reserves in the AWP Olmos Field to be steadily produced over a long
period. This offsets the Austin Chalk trend reserves, which have a high initial
production but decline rapidly. The AWP Olmos Field accounted for approximately
37% of our proved reserves as of December 31, 2000 and approximately 32% of our
2000 production, while the Austin Chalk trend accounted for approximately 35% of
our proved reserves as of December 31, 2000 and generated approximately 62% of
our 2000 production. New Zealand accounted for approximately 20% of our proved
reserves as of December 31, 2000 and had not yet produced as of December 31,
2000. Subsequent to year-end 2000, we acquired interests in Lake Washington
Field in Louisiana for $30.5 million.

We have increased our proved reserves from 176.1 Bcfe at year-end 1995 to
629.4 Bcfe at year-end 2000, which represents the replacement of 375% of our
production during the same period. Our five-year average reserves replacement
costs were $0.94 per Mcfe. A combination of increased production and decreased
operating costs per Mcfe resulted in average annual growth in net cash provided
by operating activities of 55% per year from year-end 1995 to year-end 2000.

Swift's philosophy is to pursue a balanced growth strategy that includes an
active drilling program, strategic acquisitions, and the utilization of advanced
technologies. We seek to increase our reserves through both drilling and
acquisitions, shifting the balance between the two activities in response to
market conditions. For example, when oil and gas prices are low, we focus upon
acquiring producing properties. When oil and gas prices are high, we shift our
focus to drilling wells.

Following the fall in oil and gas prices during mid-1998, we grew primarily
by increasing our acreage position, mainly through the Toledo Bend properties
acquisition in Texas and Louisiana purchased from Sonat Exploration Company.
Capital expenditures for development and exploration drilling were $67.4 million
in 1998 and $44 million in 1999, while the amounts spent for acquisitions were
$59.5 million in 1998 and $20.6 million in 1999. In 2000 drilling expenditures
totaled $115.5 million, while $33.4 million was spent to acquire producing
properties, primarily in the third quarter. Most of our drilling activities were
in the AWP Olmos Field, the Austin Chalk trend and New Zealand.

Our principal executive offices are located at 16825 Northchase Drive,
Suite 400, Houston, Texas 77060 and our telephone number is (281) 874-2700.

RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our ratio of earnings to fixed charges:

THREE MONTHS
ENDED
YEARS ENDED DECEMBER 31, MARCH 31,
--------------------------------- -------------
1996 1997 1998 1999 2000 2000 2001
----- ---- ---- ---- ---- ----- -----

Ratio of earnings to fixed charges..... 12.8x 5.2x -- 2.4x 5.2x 3.6x 9.1x

Due to the $90.8 million non-cash charge incurred in the year ended
December 31, 1998 caused by a write down in the carrying value of natural gas
and oil properties, 1998 earnings were insufficient by

$76.9 million to cover fixed charges in 1998. If the $90.8 million non-cash
charge is excluded, the ratio of earnings to fixed charges would have been 2.1x.

For the purpose of computing the ratio of earnings to fixed charges,
earnings are defined as:

- income from continuing operations before income taxes;

- plus fixed charges; and

- less capitalized interest.

Fixed charges are defined as the sum of the following:

- interest, including capitalized interest, on all indebtedness;

- amortization of debt issuance cost; and

- that portion of rental expense which we believe to be representative of
an interest factor.

USE OF PROCEEDS

Unless we specify otherwise in an accompanying prospectus supplement, we
intend to use the net proceeds we receive from the sale of securities offered by
this prospectus and the accompanying prospectus supplement for the repayment of
debt under our credit lines and for general corporate purposes. General
corporate purposes may include additions to working capital, development and
exploration expenditures or the financing of possible acquisitions. We will not
receive any proceeds from any sale of common stock by selling shareholders.

The net proceeds may be invested temporarily until they are used for their
stated purpose.

DESCRIPTION OF DEBT SECURITIES

This section describes the general terms and provisions of the debt
securities which may be offered by us from time to time. The applicable
prospectus supplement will describe the specific terms of the debt securities
offered by that prospectus supplement.

We may issue debt securities either separately or together with, or upon
the conversion of, or in exchange for, other securities. The debt securities are
to be either senior obligations of ours issued in one or more series and
referred to herein as the "Senior Debt Securities," or subordinated obligations
of ours issued in one or more series and referred to herein as the "Subordinated
Debt Securities." The Senior Debt Securities and the Subordinated Debt
Securities are collectively referred to as the "Debt Securities." The Debt
Securities will be general obligations of the Company. Each series of Debt
Securities will be issued under an agreement, or "Indenture," between Swift and
an independent third party, usually a bank or trust company, known as a
"Trustee," who will be legally obligated to carry out the terms of the
Indenture. The name(s) of the Trustee(s) will be set forth in the applicable
prospectus supplement. We may issue all the Debt Securities under the same
Indenture, as one or as separate series, as specified in the applicable
prospectus supplement(s).

This summary of certain terms and provisions of the Debt Securities and
Indentures is not complete. If we refer to particular provisions of an
Indenture, the provisions, including definitions of certain terms, are
incorporated by reference as a part of this summary. The Indentures are or will
be filed as an exhibit to the registration statement of which this prospectus is
a part, or as exhibits to documents filed under the Securities Exchange Act of
1934 which are incorporated by reference into this prospectus. The Indentures
are subject to and governed by the Trust Indenture Act of 1939, as amended. You
should refer to the applicable Indenture for the provisions which may be
important to you.

GENERAL

The Indentures will not limit the amount of Debt Securities which we may
issue. We may issue Debt Securities up to an aggregate principal amount as we
may authorize from time to time. The applicable prospectus supplement will
describe the terms of any Debt Securities being offered, including:

- the title and aggregate principal amount;

- the date(s) when principal is payable;

- the interest rate, if any, and the method for calculating the interest
rate;

- the interest payment dates and the record dates for the interest
payments;

- the places where the principal and interest will be payable;

- any mandatory or optional redemption or repurchase terms or prepayment,
conversion, sinking fund or exchangeability or convertibility provisions;

- whether such Debt Securities will be Senior Debt Securities or
Subordinated Debt Securities and, if Subordinated Debt Securities, the
subordination provisions and the applicable definition of "Senior
Indebtedness";

- additional provisions, if any, relating to the defeasance and covenant
defeasance of the Debt Securities;

- if other than denominations of $1,000 or multiples of $1,000, the
denominations the Debt Securities will be issued in;

- whether the Debt Securities will be issued in the form of Global
Securities, as defined below, or certificates;

- whether the Debt Securities will be issuable in registered form, referred
to as "Registered Securities," or in bearer form, referred to as "Bearer
Securities" or both and, if Bearer Securities are issuable, any
restrictions applicable to the exchange of one form for another and the
offer, sale and delivery of Bearer Securities;

- any applicable material federal tax consequences;

- the dates on which premiums, if any, will be payable;

- our right, if any, to defer payment of interest and the maximum length of
such deferral period;

- any paying agents, transfer agents, registrars or trustees;

- any listing on a securities exchange;

- if convertible into common stock or preferred stock, the terms on which
such Debt Securities are convertible;

- the terms, if any, of the transfer, mortgage, pledge, or assignment as
security for any series of Debt Securities of any properties, assets,
proceeds, securities or other collateral, including whether certain
provisions of the Trust Indenture Act are applicable, and any
corresponding changes to provisions of the Indenture as currently in
effect;

- the initial offering price; and

- other specific terms, including covenants and any additions or changes to
the events of default provided for with respect to the Debt Securities.

The terms of the Debt Securities of any series may differ and, without the
consent of the holders of the Debt Securities of any series, we may reopen a
previous series of Debt Securities and issue additional

Debt Securities of such series or establish additional terms of such series,
unless otherwise indicated in the applicable prospectus supplement.

NON U.S. CURRENCY

If the purchase price of any Debt Securities is payable in a currency other
than U.S. dollars or if principal of, or premium, if any, or interest, if any,
on any of the Debt Securities is payable in any currency other than U.S.
dollars, the specific terms with respect to such Debt Securities and such
foreign currency will be specified in the applicable prospectus supplement.

ORIGINAL ISSUE DISCOUNT SECURITIES

Debt Securities may be issued as "Original Issue Discount Securities" to be
sold at a substantial discount below their principal amount. Original Issue
Discount Securities may include "zero coupon" securities that do not pay any
cash interest for the entire term of the securities. In the event of an
acceleration of the maturity of any Original Issue Discount Security, the amount
payable to the holder thereof upon such acceleration will be determined in the
manner described in the applicable prospectus supplement. Conditions pursuant to
which payment of the principal of the Subordinated Debt Securities may be
accelerated will be set forth in the applicable prospectus supplement. Material
federal income tax and other considerations applicable to Original Issue
Discount Securities will be described in the applicable prospectus supplement.

COVENANTS

Under the Indentures, we will be required to:

- pay the principal, interest and any premium on the Debt Securities when
due;

- maintain a place of payment;

- deliver a report to the Trustee at the end of each fiscal year reviewing
our obligations under the Indentures; and

- deposit sufficient funds with any paying agent on or before the due date
for any principal, interest or any premium.

Any additional covenants will be described in the applicable prospectus
supplement.

REGISTRATION, TRANSFER, PAYMENT AND PAYING AGENT

Unless otherwise indicated in a prospectus supplement, each series of Debt
Securities will be issued in registered form only, without coupons. The
Indentures, however, provide that we may also issue Debt Securities in bearer
form only, or in both registered and bearer form. Bearer Securities shall not be
offered, sold, resold or delivered in connection with their original issuance in
the United States or to any United States person other than offices located
outside the United States of certain United States financial institutions.
"United States person" means any citizen or resident of the United States, any
corporation, partnership or other entity created or organized in or under the
laws of the United States, any estate the income of which is subject to United
States federal income taxation regardless of its source, or any trust whose
administration is subject to the primary supervision of a United States court
and which has one or more United States fiduciaries who have the authority to
control all substantial decisions of the trust. "United States" means the United
States of America (including the states thereof and the District of Columbia),
its territories, its possessions and other areas subject to its jurisdiction.
Purchasers of Bearer Securities will be subject to certification procedures and
may be affected by certain limitations under United States tax laws. Such
procedures and limitations will be described in the prospectus supplement
relating to the offering of the Bearer Securities.

Unless otherwise indicated in a prospectus supplement, Registered
Securities will be issued in denominations of $1,000 or any integral multiple
thereof, and Bearer Securities will be issued in denominations of $5,000.

Unless otherwise indicated in a prospectus supplement, the principal,
premium, if any, and interest, if any, of or on the Debt Securities will be
payable, and Debt Securities may be surrendered for registration of transfer or
exchange, at an office or agency to be maintained by us in the Borough of
Manhattan, The City of New York, provided that payments of interest with respect
to any Registered Security may be made at our option by check mailed to the
address of the person entitled to payment or by transfer to an account
maintained by the payee with a bank located in the United States. No service
charge shall be made for any registration of transfer or exchange of Debt
Securities, but we may require payment of a sum sufficient to cover any tax or
other governmental charge and any other expenses that may be imposed in
connection with the exchange or transfer.

Unless otherwise indicated in a prospectus supplement, payment of principal
of, premium, if any, and interest, if any, on Bearer Securities will be made,
subject to any applicable laws and regulations, at such office or agency outside
the United States as specified in the prospectus supplement and as we may
designate from time to time. Unless otherwise indicated in a prospectus
supplement, payment of interest due on Bearer Securities on any interest payment
date will be made only against surrender of the coupon relating to such interest
payment date. Unless otherwise indicated in a prospectus supplement, no payment
of principal, premium or interest with respect to any Bearer Security will be
made at any office or agency in the United States or by check mailed to any
address in the United States or by transfer to an account maintained with a bank
located in the United States; except that if amounts owing with respect to any
Bearer Securities shall be payable in U.S. dollars, payment may be made at the
Corporate Trust Office of the applicable Trustee or at any office or agency
designated by us in the Borough of Manhattan, The City of New York, if (but only
if) payment of the full amount of such principal, premium or interest at all
offices outside of the United States maintained for such purpose by us is
illegal or effectively precluded by exchange controls or similar restrictions.

Unless otherwise indicated in the applicable prospectus supplement, we will
not be required to:

- issue, register the transfer of or exchange Debt Securities of any series
during a period beginning at the opening of business 15 days before any
selection of Debt Securities of that series of like tenor to be redeemed
and ending at the close of business on the day of that selection;

- register the transfer of or exchange any Registered Security, or portion
thereof, called for redemption, except the unredeemed portion of any
Registered Security being redeemed in part;

- exchange any Bearer Security called for redemption, except to exchange
such Bearer Security for a Registered Security of that series and like
tenor that is simultaneously surrendered for redemption; or

- issue, register the transfer of or exchange any Debt Security which has
been surrendered for repayment at the option of the holder, except the
portion, if any, of the Debt Security not to be so repaid.

RANKING OF DEBT SECURITIES

The Senior Debt Securities will be unsubordinated obligations of ours and
will rank equally in right of payment with all other unsubordinated indebtedness
of ours. The Subordinated Debt Securities will be obligations of ours and will
be subordinated in right of payment to all existing and future Senior
Indebtedness. The prospectus supplement will describe the subordination
provisions and set forth the definition of "Senior Indebtedness" applicable to
the Subordinated Debt Securities, and will set forth the approximate amount of
such Senior Indebtedness outstanding as of a recent date.

GLOBAL SECURITIES

The Debt Securities of a series may be issued in whole or in part in the
form of one or more global securities that will be deposited with, or on behalf
of, a "Depositary" identified in the prospectus supplement relating to such
series. Global Debt Securities may be issued in either registered or bearer form
and in either temporary or permanent form. Unless and until it is exchanged in
whole or in part for individual certificates evidencing Debt Securities, a
Global Debt Security may not be transferred except as a whole:

- by the Depositary to a nominee of such Depositary;

- by a nominee of such Depositary to such Depositary or another nominee of
such Depositary; or

- by such Depositary or any such nominee to a successor of such Depositary
or a nominee of such successor.

The specific terms of the depositary arrangement with respect to a series
of Global Debt Securities and certain limitations and restrictions relating to a
series of Global Bearer Securities will be described in the applicable
prospectus supplement.

OUTSTANDING DEBT SECURITIES

In determining whether the holders of the requisite principal amount of
outstanding Debt Securities have given any authorization, demand, direction,
notice, consent or waiver under the relevant Indenture, the amount of
outstanding Debt Securities will be calculated based on the following:

- the portion of the principal amount of an Original Issue Discount
Security that shall be deemed to be outstanding for such purposes shall
be that portion of the principal amount thereof that could be declared to
be due and payable upon a declaration of acceleration pursuant to the
terms of such Original Issue Discount Security as of the date of such
determination;

- the principal amount of a Debt Security denominated in a currency other
than U.S. dollars shall be the U.S. dollar equivalent, determined on the
date of original issue of such Debt Security, of the principal amount of
such Debt Security; and

- any Debt Security owned by us or any obligor on such Debt Security or any
affiliate of us or such other obligor shall be deemed not to be
outstanding.

REDEMPTION AND REPURCHASE

The Debt Securities may be redeemable at our option, may be subject to
mandatory redemption pursuant to a sinking fund or otherwise, or may be subject
to repurchase by Swift at the option of the holders, in each case upon the
terms, at the times and at the prices set forth in the applicable prospectus
supplement.

CONVERSION AND EXCHANGE

The terms, if any, on which Debt Securities of any series are convertible
into or exchangeable for common stock, preferred stock, or other Debt Securities
will be set forth in the applicable prospectus supplement. Such terms of
conversion or exchange may be either mandatory, at the option of the holders, or
at our option.

CONSOLIDATION, MERGER AND SALE OF ASSETS

Each Indenture generally will permit a consolidation or merger, subject to
certain limitations and conditions, between us and another corporation. They
also will permit the sale by us of all or substantially all of our property and
assets. If this happens, the remaining or acquiring corporation shall assume all
of

our responsibilities and liabilities under the Indentures including the payment
of all amounts due on the Debt Securities and performance of the covenants in
the Indentures.

We are only permitted to consolidate or merge with or into any other
corporation or sell all or substantially all of our assets according to the
terms and conditions of the Indentures, as indicated in the applicable
prospectus supplement. The remaining or acquiring corporation will be
substituted for us in the Indentures with the same effect as if it had been an
original party to the Indenture. Thereafter, the successor corporation may
exercise our rights and powers under any Indenture, in our name or in its own
name. Any act or proceeding required or permitted to be done by our board of
directors or any of our officers may be done by the board or officers of the
successor corporation.

EVENTS OF DEFAULT

Unless otherwise specified in the applicable prospectus supplement, an
Event of Default, as defined in the Indentures and applicable to Debt Securities
issued under such Indentures, typically will occur with respect to the Debt
Securities of any series under the Indenture upon:

- default for a period to be specified in the applicable prospectus
supplement in payment of any interest with respect to any Debt Security
of such series;

- default in payment of principal or any premium with respect to any Debt
Security of such series when due upon maturity, redemption, repurchase at
the option of the holder or otherwise;

- default in deposit of any sinking fund payment when due with respect to
any Debt Security of such series;

- default by us in the performance, or breach, of any other covenant or
warranty in such Indenture, which shall not have been remedied for a
period to be specified in the applicable prospectus supplement after
notice to us by the applicable Trustee or the holders of not less than a
fixed percentage in aggregate principal amount of the Debt Securities of
all series issued under the applicable Indenture;

- certain events of bankruptcy, insolvency or reorganization of Swift; or

- any other Event of Default that may be set forth in the applicable
prospectus supplement, including an Event of Default based on other debt
being accelerated, known as a "cross-acceleration."

No Event of Default with respect to any particular series of Debt
Securities necessarily constitutes an Event of Default with respect to any other
series of Debt Securities. If the Trustee considers it in the interest of the
holders to do so, the Trustee under an Indenture may withhold notice of the
occurrence of a default with respect to the Debt Securities to the holders of
any series outstanding, except a default in payment of principal, premium, if
any, interest, if any.

Each Indenture will provide that if an Event of Default with respect to any
series of Debt Securities issued thereunder shall have occurred and be
continuing, either the relevant Trustee or the holders of at least a fixed
percentage in principal amount of the Debt Securities of such series then
outstanding may declare the principal amount of all the Debt Securities of such
series to be due and payable immediately. In the case of Original Issue Discount
Securities, the Trustee may declare as due and payable such lesser amount as may
be specified in the applicable prospectus supplement. However, upon certain
conditions, such declaration and its consequences may be rescinded and annulled
by the holders of at least a fixed percentage in principal amount of the Debt
Securities of all series issued under the applicable Indenture.

The applicable prospectus supplement will provide the terms pursuant to
which an Event of Default shall result in acceleration of the payment of
principal of Subordinated Debt Securities.

In the case of a default in the payment of principal of, or premium, if
any, or interest, if any, on any Subordinated Debt Securities of any series, the
applicable Trustee, subject to certain limitations and conditions, may institute
a judicial proceeding for the collection thereof.

No holder of any of the Debt Securities of any series will have any right
to institute any proceeding with respect to the Indenture or any remedy
thereunder, unless the holders of at least a fixed percentage in principal
amount of the outstanding Debt Securities of such series:

- have made written request to the Trustee to institute such proceeding as
Trustee, and offered reasonable indemnity to the Trustee,

- the Trustee has failed to institute such proceeding within the time
period specified in the applicable prospectus supplement after receipt of
such notice, and

- the Trustee has not within such period received directions inconsistent
with such written request by holders of a majority in principal amount of
the outstanding Debt Securities of such series. Such limitations do not
apply, however, to a suit instituted by a holder of a Debt Security for
the enforcement of the payment of the principal of, premium, if any, or
any accrued and unpaid interest on, the Debt Security on or after the
respective due dates expressed in the Debt Security.

During the existence of an Event of Default under an Indenture, the Trustee
is required to exercise such rights and powers vested in it under the Indenture
and use the same degree of care and skill in its exercise thereof as a prudent
person would exercise under the circumstances in the conduct of such person's
own affairs. Subject to the provisions of the Indenture relating to the duties
of the Trustee, if an Event of Default shall occur and be continuing, the
Trustee is under no obligation to exercise any of its rights or powers under the
Indenture at the request or direction of any of the holders, unless such holders
shall have offered to the Trustee reasonable security or indemnity. Subject to
certain provisions concerning the rights of the Trustee, the holders of at least
a fixed percentage in principal amount of the outstanding Debt Securities of any
series have the right to direct the time, method and place of conducting any
proceeding for any remedy available to the Trustee, or exercising any power
conferred on the Trustee with respect to such series.

The Indentures provide that the Trustee will, within the time period
specified in the applicable prospectus supplement after the occurrence of any
default, give to the holders of the Debt Securities of such series notice of
such default known to it, unless such default shall have been cured or waived;
provided that the Trustee shall be protected in withholding such notice if it
determines in good faith that the withholding of such notice is in the interest
of such holders, except in the case of a default in payment of principal of or
premium, if any, on any Debt Security of such series when due or in the case of
any default in the payment of any interest on the Debt Securities of such
series.

Swift is required to furnish to the Trustee annually a statement as to
compliance with all conditions and covenants under the Indentures.

MODIFICATION AND WAIVERS

From time to time, when authorized by resolutions of our board of directors
and by the Trustee, without the consent of the holders of Debt Securities of any
series, we may amend, waive or supplement the Indentures and the Debt Securities
of such series for certain specified purposes, including, among other things:

- to cure ambiguities, defects or inconsistencies;

- to provide for the assumption of our obligations to holders of the Debt
Securities of such series in the case of a merger or consolidation;

- to add to our Events of Default or our covenants or to make any change
that would provide any additional rights or benefits to the holders of
the Debt Securities of such series;

- to add or change any provisions of such Indenture to facilitate the
issuance of Bearer Securities;

- to establish the form or terms of Debt Securities of any series and any
related coupons;

- to add guarantors with respect to the Debt Securities of such series;
11

- to secure the Debt Securities of such series;

- to maintain the qualification of the Indenture under the Trust Indenture
Act; or

- to make any change that does not adversely affect the rights of any
holder.

Other amendments and modifications of the Indentures or the Debt Securities
issued thereunder may be made by Swift and the Trustee with the consent of the
holders of not less than a fixed percentage of the aggregate principal amount of
the outstanding Debt Securities of each series affected, with each series voting
as a separate class; provided that, without the consent of the holder of each
outstanding Debt Security affected, no such modification or amendment may:

- reduce the principal amount of, or extend the fixed maturity of the Debt
Securities, or alter or waive any redemption, repurchase or sinking fund
provisions of the Debt Securities;

- reduce the amount of principal of any Original Issue Discount Securities
that would be due and payable upon an acceleration of the maturity
thereof;

- change the currency in which any Debt Securities or any premium or the
accrued interest thereon is payable;

- reduce the percentage in principal amount outstanding of Debt Securities
of any series which must consent to an amendment, supplement or waiver or
consent to take any action under the Indenture or the Debt Securities of
such series;

- impair the right to institute suit for the enforcement of any payment on
or with respect to the Debt Securities;

- waive a default in payment with respect to the Debt Securities or any
guarantee;

- reduce the rate or extend the time for payment of interest on the Debt
Securities;

- adversely affect the ranking of the Debt Securities of any series;

- release any guarantor from any of its obligations under its guarantee or
the Indenture, except in compliance with the terms of the Indenture; or

- solely in the case of a series of Subordinated Debt Securities, modify
any of the applicable subordination provisions or the applicable
definition of Senior Indebtedness in a manner adverse to any holders.

The holders of a fixed percentage in aggregate principal amount of the
outstanding Debt Securities of any series may waive compliance by us with
certain restrictive provisions of the relevant Indenture, including any set
forth in the applicable prospectus supplement. The holders of a fixed percentage
in aggregate principal amount of the outstanding Debt Securities of any series
may, on behalf of the holders of that series, waive any past default under the
applicable Indenture with respect to that series and its consequences, except a
default in the payment of the principal of, or premium, if any, or interest, if
any, on any Debt Securities of such series, or in respect of a covenant or
provision which cannot be modified or amended without the consent of a larger
fixed percentage of holders or by the holder of each outstanding Debt Securities
of the series affected.

DISCHARGE, TERMINATION AND COVENANT TERMINATION

When we establish a series of Debt Securities, we may provide that such
series is subject to the termination and discharge provisions of the applicable
Indenture. If those provisions are made applicable, we may elect either:

- to terminate and be discharged from all of our obligations with respect
to those Debt Securities subject to some limitations; or

- to be released from our obligations to comply with specified covenants
relating to those Debt Securities, as described in the applicable
prospectus supplement.

To effect that termination or covenant termination, we must irrevocably
deposit in trust with the relevant Trustee an amount which, through the payment
of principal and interest in accordance with their terms, will provide money
sufficient to make payments on those Debt Securities and any mandatory sinking
fund or similar payments on those Debt Securities. This deposit may be made in
any combination of funds or government obligations. On such a termination, we
will not be released from certain of our obligations that will be specified in
the applicable prospectus supplement.

To establish such a trust we must deliver to the relevant Trustee an
opinion of counsel to the effect that the holders of those Debt Securities:

- will not recognize income, gain or loss for U.S. federal income tax
purposes as a result of the termination or covenant termination; and

- will be subject to U.S. federal income tax on the same amounts, in the
same manner and at the same times as would have been the case if the
termination or covenant termination had not occurred.

If we effect covenant termination with respect to any Debt Securities, the
amount of deposit with the relevant Trustee must be sufficient to pay amounts
due on the Debt Securities at the time of their stated maturity. However, those
Debt Securities may become due and payable prior to their stated maturity if
there is an Event of Default with respect to a covenant from which we have not
been released. In that event, the amount on deposit may not be sufficient to pay
all amounts due on the Debt Securities at the time of the acceleration.

The applicable prospectus supplement may further describe the provisions,
if any, permitting termination or covenant termination, including any
modifications to the provisions described above.

GOVERNING LAW

The Indentures and the Debt Securities will be governed by, and construed
in accordance with, the laws of the State of New York.

REGARDING THE TRUSTEES

The Trust Indenture Act contains limitations on the rights of a trustee,
should it become a creditor of ours, to obtain payment of claims in certain
cases or to realize on certain property received by it in respect of any such
claims, as security or otherwise. Each Trustee is permitted to engage in other
transactions with us from time to time, provided that if such Trustee acquires
any conflicting interest, it must eliminate such conflict upon the occurrence of
an Event of Default under the relevant Indenture, or else resign.

DESCRIPTION OF CAPITAL STOCK

GENERAL

As of the date of this prospectus, we are authorized to issue up to
90,000,000 shares of stock, including up to 85,000,000 shares of common stock
and up to 5,000,000 shares of preferred stock. As of March 31, 2001, we had
24,709,565 shares of common stock and no shares of preferred stock outstanding.
As of that date, we also had approximately 2,153,865 shares of common stock
subject to issuance upon exercise of outstanding options.

The following is a summary of the key terms and provisions of our equity
securities. You should refer to the applicable provisions of our articles of
incorporation, bylaws, the Texas Business Corporation Act

and the documents we have incorporated by reference for a complete statement of
the terms and rights of our capital stock.

COMMON STOCK

Voting Rights. Each holder of common stock is entitled to one vote per
share. Subject to the rights, if any, of the holders of any series of preferred
stock pursuant to applicable law or the provision of the certificate of
designation creating that series, all voting rights are vested in the holders of
shares of common stock. Holders of shares of common stock have noncumulative
voting rights, which means that the holders of more than 50% of the shares
voting for the election of directors can elect 100% of the directors, and the
holders of the remaining shares voting for the election of directors will not be
able to elect any directors.

Dividends. Dividends may be paid to the holders of common stock when, as
and if declared by the board of directors out of funds legally available for
their payment, subject to the rights of holders of any preferred stock. Swift
has never declared a cash dividend and intends to continue its policy of using
retained earnings for expansion of its business.

Rights upon Liquidation. In the event of our voluntary or involuntary
liquidation, dissolution or winding up, the holders of common stock will be
entitled to share equally, in proportion to the number of shares of common stock
held by them, in any of our assets available for distribution after the payment
in full of all debts and distributions and after the holders of all series of
outstanding preferred stock, if any, have received their liquidation preferences
in full.

Non-Assessable. All outstanding shares of common stock are fully paid and
non-assessable. Any additional common stock we offer and issue under this
Prospectus will also be fully paid and non-assessable.

No Preemptive Rights. Holders of common stock are not entitled to
preemptive purchase rights in future offerings of our common stock.

Listing. Our outstanding shares of common stock are listed on the New York
Stock Exchange and the Pacific Stock Exchange under the symbol "SFY." Any
additional common stock we issue will also be listed on the NYSE and the PSE.

PREFERRED STOCK

Our board of directors can, without approval of our shareholders, issue one
or more series of preferred stock and determine the number of shares of each
series and the rights, preferences and limitations of each series. The following
description of the terms of the preferred stock sets forth certain general terms
and provisions of our authorized preferred stock. If we offer preferred stock, a
description will be filed with the SEC and the specific designations and rights
will be described in a prospectus supplement, including the following terms:

- the series, the number of shares offered and the liquidation value of the
preferred stock;

- the price at which the preferred stock will be issued;

- the dividend rate, the dates on which the dividends will be payable and
other terms relating to the payment of dividends on the preferred stock;

- the liquidation preference of the preferred stock;

- the voting rights of the preferred stock;

- whether the preferred stock is redeemable or subject to a sinking fund,
and the terms of any such redemption or sinking fund;

- whether the preferred stock is convertible or exchangeable for any other
securities, and the terms of any such conversion; and

- any additional rights, preferences, qualifications, limitations and
restrictions of the preferred stock.

The description of the terms of the preferred stock to be set forth in an
applicable prospectus supplement will not be complete and will be subject to and
qualified in its entirety by reference to the certificate of designation
relating to the applicable series of preferred stock. The registration statement
of which this prospectus forms a part will include the certificate of
designation as an exhibit or incorporate it by reference.

Undesignated preferred stock may enable our board of directors to render
more difficult or to discourage an attempt to obtain control of us by means of a
tender offer, proxy contest, merger or otherwise, and to thereby protect the
continuity of our management. The issuance of shares of preferred stock may
adversely affect the rights of the holders of our common stock. For example, any
preferred stock issued may rank prior to our common stock as to dividend rights,
liquidation preference or both, may have full or limited voting rights and may
be convertible into shares of common stock. As a result, the issuance of shares
of preferred stock may discourage bids for our common stock or may otherwise
adversely affect the market price of our common stock or any existing preferred
stock.

Any preferred stock will, when issued, be fully paid and non-assessable.

ANTI-TAKEOVER PROVISIONS

Certain provisions in our articles of incorporation, bylaws and our
shareholders' rights plan may encourage persons considering unsolicited tender
offers or other unilateral takeover proposals to negotiate with our board of
directors rather than pursue non-negotiated takeover attempts.

Our Classified Board of Directors. Our bylaws provide that our board of
directors is divided into three classes as nearly equal in number as possible.
The directors of each class are elected for three-year terms, and the terms of
the three classes are staggered so that directors from a single class are
elected at each annual meeting of stockholders. A staggered board makes it more
difficult for shareholders to change the majority of the directors and instead
promotes continuity of existing management.

Our Ability to Issue Preferred Stock. As discussed above, our board of
directors can set the voting rights, redemption rights, conversion rights and
other rights relating to authorized but unissued shares of preferred stock and
could issue that stock in either private or public transactions. Preferred stock
could be issued for the purpose of preventing a merger, tender offer or other
takeover attempt which the board of directors opposes.

Our Rights Plan. Our board of directors has adopted a stockholders' rights
plan. The rights attach to all common stock certificates representing
outstanding shares. One right is issued for each share of common stock
outstanding. Each right entitles the registered holder, under the circumstances
described below, to purchase from us one one-thousandth of a share of our Series
A Junior Participating Preferred Stock, a "Series A" share, at a price of
$150.00 per one one-thousandth of a Series A share, subject to adjustment. The
dividend and liquidation rights and the non-redemption feature of the Series A
shares are designed so that the value of one one-thousandth of a Series A share
purchasable upon exercise of each right will approximate the value of one share
of common stock. The following is a summary of the terms of the rights plan. You
should refer to the applicable provisions of the rights plan which we have
incorporated by reference as an exhibit to the registration statement of which
this prospectus is a part.

The rights will separate from the common stock and right certificates will
be distributed to the holders of common stock as of the earlier of:

- 10 business days following a public announcement that a person or group
of affiliated persons has acquired beneficial ownership of 15% or more of
our outstanding voting shares, or

- 10 business days following the commencement or announcement of an
intention to commence a tender offer or exchange offer which would result
in a person or group beneficially owning 15% or more of our outstanding
voting shares.

The rights are not exercisable until rights certificates are distributed.
The rights will expire on July 31, 2007 unless that date is extended or the
rights are earlier redeemed or exchanged.

If a person or group (with certain exceptions for investment advisers)
acquires 15% or more of our voting shares, each right then outstanding, other
than rights beneficially owned by such person or group, becomes a right to buy
that number of shares of common stock or other securities or assets having a
market value of two times the exercise price of the right. The rights belonging
to the acquiring person or group become null and void.

If Swift is acquired in a merger or other business combination, or 50% of
its consolidated assets or assets producing more than 50% of its earning power
or cash flow are sold, each holder of a right will have the right to receive
that number of shares of common stock of the acquiring company which at the time
of such transaction has a market value of two times the purchase price of the
right.

At any time after a person or group acquires beneficial ownership of 15% or
more of our outstanding voting shares and before the earlier of the two events
described in the prior paragraph or acquisition by a person or group of
beneficial ownership of 50% or more of our outstanding voting shares, our board
of directors may, at its option, exchange the rights, other than those owned by
such person or group, in whole or in part, at an exchange ratio of one share of
common stock or a fractional share of Series A stock or other preferred stock
equivalent in value thereto, per right.

The Series A shares issuable upon exercise of the rights will be
non-redeemable and rank junior to all other series of our preferred stock. Each
whole Series A share will be entitled to receive a quarterly preferential
dividend in an amount per share equal to the greater of $1.00 in cash, or in the
aggregate, 1,000 times the dividend declared on the common stock, subject to
adjustment. In the event of liquidation, the holders of Series A share may
receive a preferential liquidation payment equal to the greater of $1,000 per
share, or in the aggregate, 1,000 times the payment made on the shares of common
stock. In the event of any merger, consolidation or other transaction in which
the shares of common stock are exchanged for or changed into other stock or
securities, cash or other property, each whole Series A share will be entitled
to receive 1,000 times the amount received per share of common stock. Each whole
Series A share will be entitled to 1,000 votes on all matters submitted to a
vote of our stockholders and Series A shares will generally vote together as one
class with the common stock and any other capital stock on all matters submitted
to a vote of our stockholders.

Prior to the earlier of the date it is determined that right certificates
are to be distributed or the expiration date of the rights, our board of
directors may redeem all, but not less than all, of the then outstanding rights
at a price of $0.01 per right. Our board of directors in its sole discretion may
establish the effective date and other terms and conditions of the redemption.
Upon redemption, the ability to exercise the rights will terminate and the
holders of rights will only be entitled to receive the redemption price.

As long as the rights are redeemable, we may amend the rights agreement in
any manner except to change the redemption price. After the rights are no longer
redeemable, we may, except with respect to the redemption price, amend the
rights agreement in any manner that does not adversely affect the interests of
holders of the rights.

Business Combinations Under Texas Law. Swift is a Texas corporation
subject to Part Thirteen of the Texas Business Corporation Act known as the
"Business Combination Law." In general, the Business Combination Law prevents an
affiliated shareholder, or its affiliates or associates, from entering into a

business combination with an issuing public corporation during the three-year
period immediately following the date on which the affiliated shareholder became
an affiliated shareholder, unless:

- before the date such person became an affiliated shareholder, the board
of directors of the issuing public corporation approves the business
combination or the acquisition of shares that caused the affiliated
shareholder to become an affiliated shareholder; or

- not less than six months after the date such person became an affiliated
shareholder, the business combination is approved by the affirmative vote
of holders of at least two-thirds of the issuing public corporation's
outstanding voting shares not beneficially owned by the affiliated
shareholder, or its affiliates or associates.

An affiliated shareholder is a person that is or was within the preceding
three-year period the beneficial owner of 20% or more of a corporation's
outstanding voting shares. An issuing public corporation includes most publicly
held Texas corporations, including Swift. The term business combination
includes:

- mergers, share exchanges or conversions involving the affiliated
shareholder;

- dispositions of assets involving the affiliated shareholder having an
aggregate value of 10% or more of the market value of the assets or of
the outstanding common stock or representing 10% or more of the earning
power or net income of the corporation;

- issuances or transfers of securities by the corporation to the affiliated
shareholder other than on a pro rata basis;

- plans or agreements relating to a liquidation or dissolution of the
corporation involving an affiliated shareholder;

- reclassifications, recapitalizations, distributions or other transactions
that would have the effect of increasing the affiliated shareholder's
percentage ownership of the corporation; and

- the receipt of tax, guarantee, loan or other financial benefits by an
affiliated shareholder other than proportionately as a shareholder of the
corporation.

DESCRIPTION OF DEPOSITARY SHARES

We may offer preferred stock represented by depositary shares and issue
depositary receipts evidencing the depositary shares. Each depositary share will
represent a fraction of a share of preferred stock. Shares of preferred stock of
each class or series represented by depositary shares will be deposited under a
separate deposit agreement among us, a bank or trust company acting as the
"Depositary" and the holders of the depositary receipts. Subject to the terms of
the deposit agreement, each owner of a depositary receipt will be entitled, in
proportion to the fraction of a share of preferred stock represented by the
depositary shares evidenced by the depositary receipt, to all the rights and
preferences of the preferred stock represented by such depositary shares. Those
rights include any dividend, voting, conversion, redemption and liquidation
rights. Immediately following the issuance and delivery of the preferred stock
to the Depositary, we will cause the Depositary to issue the depositary receipts
on our behalf.

If depositary shares are offered, the applicable prospectus supplement will
describe the terms of such depositary shares, the deposit agreement and, if
applicable, the depositary receipts, including the following, where applicable:

- the payment of dividends or other cash distributions to the holders of
depositary receipts when such dividends or other cash distributions are
made with respect to the preferred stock;

- the voting by a holder of depositary shares of the preferred stock
underlying such depositary shares at any meeting called for such purpose;

- if applicable, the redemption of depositary shares upon a redemption by
us of shares of preferred stock held by the Depositary;
17

- if applicable, the exchange of depositary shares upon an exchange by us
of shares of preferred stock held by the Depositary for debt securities
or common stock;

- if applicable, the conversion of the shares of preferred stock underlying
the depositary shares into shares of our common stock, other shares of
our preferred stock or our debt securities;

- the terms upon which the deposit agreement may be amended and terminated;

- a summary of the fees to be paid by us to the Depositary;

- the terms upon which a Depositary may resign or be removed by us; and

- any other terms of the depositary shares, the deposit agreement and the
depositary receipts.

If a holder of depositary receipts surrenders the depositary receipts at
the corporate trust office of the Depositary, unless the related depositary
shares have previously been called for redemption, converted or exchanged into
other securities of Swift, the holder will be entitled to receive at this office
the number of shares of preferred stock and any money or other property
represented by such depositary shares. Holders of depositary receipts will be
entitled to receive whole and, to the extent provided by the applicable
prospectus supplement, fractional shares of the preferred stock on the basis of
the proportion of preferred stock represented by each depositary share as
specified in the applicable prospectus supplement. Holders of shares of
preferred stock received in exchange for depositary shares will no longer be
entitled to receive depositary shares in exchange for shares of preferred stock.
If the holder delivers depositary receipts evidencing a number of depositary
shares that is more than the number of depositary shares representing the number
of shares of preferred stock to be withdrawn, the Depositary will issue the
holder a new depositary receipt evidencing such excess number of depositary
shares at the same time.

Prospective purchasers of depositary shares should be aware that special
tax, accounting and other considerations may be applicable to instruments such
as depositary shares.

DESCRIPTION OF WARRANTS

We may issue warrants for the purchase of preferred or common stock, either
independently or together with other securities. Each series of warrants will be
issued under a warrant agreement to be entered into between Swift and a bank or
trust company. You should refer to the warrant agreement relating to the
specific warrants being offered for the complete terms of such warrant agreement
and the warrants.

Each warrant will entitle the holder to purchase the number of shares of
preferred or common stock at the exercise price set forth in, or calculable as
set forth in any applicable prospectus supplement. The exercise price may be
subject to adjustment upon the occurrence of certain events, as set forth in any
applicable prospectus supplement. After the close of business on the expiration
date of the warrant, unexercised warrants will become void. The place or places
where, and the manner in which, warrants may be exercised shall be specified in
any applicable prospectus supplement.

SELLING SHAREHOLDERS

The selling shareholders may be our directors, executive officers,
employees or other holders of common stock. The selling shareholders may from
time to time transfer shares to a donee, successor or other person, other than
for value, and such transfers will not be made pursuant to this prospectus. Such
donees, successors and other transferees also may effect sales of the shares
donated, distributed or transferred pursuant to this prospectus (as supplemented
or amended to reflect such transaction and donee,

distributee or transferee). The prospectus supplement for any offering of the
common stock by selling shareholders will include the following information:

- the names of the selling shareholders;

- the number of shares of common stock held by each of the selling
shareholders;

- the percentage of the outstanding common stock held by each of the
selling shareholders; and

- the number of shares of common stock offered by each of the selling
shareholders.

PLAN OF DISTRIBUTION

We and any selling shareholders may sell the securities offered by this
prospectus and applicable prospectus supplements:

- through underwriters or dealers;

- through agents;

- directly to purchasers; or

- through a combination of any such methods of sale.

Any such underwriter, dealer or agent may be deemed to be an underwriter
within the meaning of the Securities Act of 1933.

The applicable prospectus supplement relating to the securities will set
forth:

- their offering terms, including the name or names of any underwriters,
dealers or agents;

- the purchase price of the securities and the proceeds to us from such
sale;

- any underwriting discounts, commissions and other items constituting
compensation to underwriters, dealers or agents;

- any initial public offering price;

- any discounts or concessions allowed or reallowed or paid by underwriters
or dealers to other dealers;

- in the case of debt securities, the interest rate, maturity and
redemption provisions; and

- any securities exchanges on which the securities may be listed.

If underwriters or dealers are used in the sale, the securities will be
acquired by the underwriters or dealers for their own account and may be resold
from time to time in one or more transactions in accordance with the rules of
the New York Stock Exchange and the Pacific Stock Exchange:

- at a fixed price or prices which may be changed;

- at market prices prevailing at the time of sale;

- at prices related to such prevailing market prices; or

- at negotiated prices.

The securities may be offered to the public either through underwriting
syndicates represented by one or more managing underwriters or directly by one
or more of such firms. Unless otherwise set forth in an applicable prospectus
supplement, the obligations of underwriters or dealers to purchase the
securities will be subject to certain conditions precedent and the underwriters
or dealers will be obligated to purchase all the securities if any are
purchased. Any public offering price and any discounts or concessions allowed or
reallowed or paid by underwriters or dealers to other dealers may be changed
from time to time.
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Securities may be sold directly by us or through agents designated by us
from time to time. Any agent involved in the offer or sale of the securities in
respect of which this prospectus and a prospectus supplement is delivered will
be named, and any commissions payable by us to such agent will be set forth, in
the prospectus supplement. Unless otherwise indicated in the prospectus
supplement, any such agent will be acting on a best efforts basis for the period
of its appointment.

If so indicated in the prospectus supplement, we will authorize
underwriters, dealers or agents to solicit offers from certain specified
institutions to purchase securities from us at the public offering price set
forth in the prospectus supplement pursuant to delayed delivery contracts
providing for payment and delivery on a specified date in the future. Such
contracts will be subject to any conditions set forth in the prospectus
supplement and the prospectus supplement will set forth the commission payable
for solicitation of such contracts. The underwriters and other persons
soliciting such contracts will have no responsibility for the validity or
performance of any such contracts.

Underwriters, dealers and agents may be entitled under agreements entered
into with us to be indemnified by us against certain civil liabilities,
including liabilities under the Securities Act of 1933, or to contribution by
Swift to payments which they may be required to make. The terms and conditions
of such indemnification will be described in an applicable prospectus
supplement. Underwriters, dealers and agents may be customers of, engage in
transactions with, or perform services for, us in the ordinary course of
business.

Each class or series of securities will be a new issue of securities with
no established trading market, other than the common stock, which is listed on
the New York Stock Exchange and the Pacific Stock Exchange. We may elect to list
any other class or series of securities on any exchange, other than the common
stock, but we are not obligated to do so. Any underwriters to whom securities
are sold by us for public offering and sale may make a market in such
securities, but such underwriters will not be obligated to do so and may
discontinue any market making at any time without notice. No assurance can be
given as to the liquidity of the trading market for any securities.

Certain persons participating in any offering of securities may engage in
transactions that stabilize, maintain or otherwise affect the price of the
securities offered. In connection with any such offering, the underwriters or
agents, as the case may be, may purchase and sell securities in the open market.
These transactions may include overallotment and stabilizing transactions and
purchases to cover syndicate short positions created in connection with the
offering. Stabilizing transactions consist of certain bids or purchases for the
purpose of preventing or retarding a decline in the market price of the
securities; and syndicate short positions involve the sale by the underwriters
or agents, as the case may be, of a greater number of securities than they are
required to purchase from us, as the case may be, in the offering. The
underwriters may also impose a penalty bid, whereby selling concessions allowed
to syndicate members or other broker-dealers for the securities sold for their
account may be reclaimed by the syndicate if such securities are repurchased by
the syndicate in stabilizing or covering transactions. These activities may
stabilize, maintain or otherwise affect the market price of the securities,
which may be higher than the price that might otherwise prevail in the open
market, and if commenced, may be discontinued at any time. These transactions
may be effected on the New York Stock Exchange, the Pacific Stock Exchange, in
the over-the-counter market or otherwise. These activities will be described in
more detail in the sections entitled "Plan of Distribution" or "Underwriting" in
the applicable prospectus supplement.

LEGAL OPINIONS

Jenkens & Gilchrist, A Professional Corporation, Houston, Texas, will issue
an opinion for Swift regarding the legality of the securities offered by this
prospectus and applicable prospectus supplement. If the securities are being
distributed in an underwritten offering, certain legal matters will be passed
upon for the underwriters by counsel identified in the applicable prospectus
supplement.

EXPERTS

The audited financial statements incorporated by reference in this
prospectus and elsewhere in the registration statement have been audited by
Arthur Andersen LLP, independent public accountants, as indicated in their
report with respect thereto, and is incorporated herein in reliance upon the
authority of said firm as experts in giving said report.

Information referenced or incorporated by reference in this prospectus
regarding our estimated quantities of oil and gas reserves and the discounted
present value of future net cash flows therefrom is based upon estimates of such
reserves and present values audited by H.J. Gruy and Associates, Inc.,
independent petroleum engineers.

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