SWIFT ENERGY CO, 424B5, 1999-07-14

SWIFT ENERGY CO
424B5, 1999-07-14
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1
Filed pursuant to Rule 424(b)(5)
Registration No. 333-81651

The information in this prospectus supplement relates to an effective
registration statement filed with the Securities and Exchange Commission and is
subject to completion or amendment. This prospectus supplement and the
accompanying prospectus are not an offer to sell these securities and are not
soliciting an offer to buy these securities in any jurisdiction where the offer
or sale is not permitted.

SUBJECT TO COMPLETION, DATED JULY 13, 1999
PROSPECTUS SUPPLEMENT

(TO PROSPECTUS DATED JULY 9, 1999)

4,000,000 SHARES
[SWIFT ENERGY LOGO] SWIFT ENERGY COMPANY

COMMON STOCK
$ PER SHARE
---------------------
Swift Energy Company is selling 4,000,000 shares of its common stock. The
underwriters named in this prospectus supplement may purchase up to 600,000
additional shares of common stock from Swift under certain circumstances.

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 the common
stock on the New York Stock Exchange on July 12, 1999 was $12.0625 per share.

We are concurrently offering $125 million of % Senior Subordinated
Notes Due 2009 in a separate public offering pursuant to a separate prospectus
supplement. This offering of common stock and the concurrent notes offering are
not conditioned upon each other.
---------------------

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

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 is truthful or complete.
Any representation to the contrary is a criminal offense.
---------------------

<TABLE>
<CAPTION>
PER SHARE TOTAL
-------------- --------------
<S> <C> <C>
Public Offering Price $ $
Underwriting Discount $ $
Proceeds to Swift (before expenses) $ $
</TABLE>

The underwriters are offering the shares subject to various conditions. The
underwriters expect to deliver the shares to purchasers on or about ,
1999.
---------------------

SALOMON SMITH BARNEY

CIBC WORLD MARKETS

CREDIT SUISSE FIRST BOSTON

DAIN RAUSCHER WESSELS
A DIVISION OF DAIN RAUSCHER
INCORPORATED

JEFFERIES & COMPANY, INC.

, 1999
<PAGE> 2

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.

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.

TABLE OF CONTENTS

<TABLE>
<S> <C>
PROSPECTUS SUPPLEMENT
Summary..................................................... S-3
Risk Factors................................................ S-10
Use of Proceeds............................................. S-15
Capitalization.............................................. S-16
Common Stock Price Range and Dividend Policy................ S-17
Selected Historical Consolidated Financial Data............. S-18
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. S-20
Business and Properties..................................... S-28
Management.................................................. S-38
Principal Shareholders...................................... S-40
Certain Relationships and Related Transactions.............. S-43
Underwriting................................................ S-44
Legal Opinions.............................................. S-45
Experts..................................................... S-46
Glossary of Terms........................................... S-47
Consolidated Financial Statements........................... F-1

PROSPECTUS

About this Prospectus....................................... 3
Where You Can Find More Information......................... 3
Forward-looking Statements.................................. 4
The Company................................................. 4
Ratio of Earnings to Fixed Charges.......................... 5
Use of Proceeds............................................. 6
Description of Debt Securities.............................. 6
Description of Capital Stock................................ 14
Description of Depositary Shares............................ 18
Description of Warrants..................................... 19
Plan of Distribution........................................ 19
Legal Opinions.............................................. 21
Experts..................................................... 21
</TABLE>

See the "Glossary of Terms" on page S-47 for explanations of abbreviations
and terms used in this prospectus supplement.

S-2
<PAGE> 3

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 specific terms of the offering of our common
stock, information about our business and financial data. We encourage you to
read this prospectus supplement, including the "Risk Factors" section, the
accompanying prospectus and the documents we incorporate by reference before
making an investment decision.

ABOUT SWIFT

Swift Energy Company engages in the development, exploration, acquisition
and operation of oil and gas properties, with a primary focus on U.S. onshore
gas reserves in Texas and Louisiana. As of December 31, 1998, we had interests
in over 1,750 oil and gas wells located in eight states. We operated 836 of
these wells, representing 91% of our proved reserves. At year-end 1998, we had
estimated proved reserves of 436.1 Bcfe, 81% of which was gas. We focus
primarily on drilling and production in four major fields, with 93% of our 1998
year-end proved reserves and 88% of our 1998 production concentrated in these
four fields:

<TABLE>
<CAPTION>
% OF YEAR-END % OF 1998
FIELD LOCATION 1998 PROVED RESERVES PRODUCTION
- ------------- ------------------- -------------------- ----------
<S> <C> <C> <C>
AWP Olmos South Texas 51% 40%
Brookeland East Texas 18% 9%
Giddings South-Central Texas 12% 18%
Masters Creek Western Louisiana 12% 21%
</TABLE>

The AWP Olmos Field is characterized by long-lived reserves, while the
other core fields are characterized by shorter-lived reserves with high initial
rates of production. We have extensive experience in these geological trends,
having operated in the AWP Olmos Field since 1988 and the Giddings Field since
1992. Outside our core fields, we are currently pursuing opportunities in the
Gulf Coast Basin and onshore New Zealand.

In the third quarter of 1998, we purchased interests in the Brookeland and
Masters Creek Fields from Sonat Exploration Company for approximately $85.6
million in cash. The acquisition included approximately 91.1 Bcfe of proved
reserves, a 20% interest in two gas processing plants and interests in
approximately 444,000 net acres. At year-end 1998, the proved reserves of these
fields were estimated to be 130.5 Bcfe, of which approximately 58% was gas and
59% was proved developed. Primarily as a result of the acquisition, our 1998
production increased 54% over 1997 production and the percentage of oil in our
production mix increased from 16% in the first half of 1998 to 37% in the first
half of 1999. We expect to use our operating expertise from similar geological
trends to continue to successfully develop and exploit these fields.

Over the last several years, our growth in reserves, production and cash
flow has resulted primarily from our increased acreage position, producing
property acquisitions and drilling activities in our core fields. Over the
five-year period ended December 31, 1998:

- our estimated proved reserves grew from 90.1 Bcfe to 436.1 Bcfe;

- we replaced 449% of our production at an average cost of $0.88 per
Mcfe; and

- our net cash provided by operating activities grew at a compounded
annual growth rate of 50%.

From 1997 to 1998, revenues grew from $74.7 million to $82.5 million, and
EBITDA increased from $62.4 million to $65.5 million. Revenues increased from
$32.8 million in the first six months of 1998 to $45.4 million in the same
period of 1999 and EBITDA increased from $26.1 million to $34.6 million.

S-3
<PAGE> 4

These net increases in revenue and EBITDA are primarily due to production
increases resulting from our successful development and exploration program
combined with the Sonat acquisition, which offset declines in gas prices.

In response to lower oil and gas prices in 1998, we reduced our budgeted
capital expenditures from $183.8 million in 1998 to $54.2 million in 1999. We
have targeted $36.0 million of this 1999 amount for drilling, of which $31.3
million is for development drilling and $4.7 million is for exploratory
drilling. The remaining $18.2 million is for leasehold, seismic and geological
costs of prospects.

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

BUSINESS STRATEGY

Our strategy is to increase our reserves and production through both
drilling and acquisitions, shifting the balance between the two activities in
response to market conditions. In addition, we seek to enhance the results of
our drilling and production efforts through the implementation of advanced
technologies. The elements of our strategy may be further described as follows:

Development and Exploration Drilling Activities. Our development
strategy is to maximize the value and productivity of our existing
properties through carefully targeted drilling and advanced recovery
methods. We pursue a "controlled" risk approach to exploratory drilling,
focusing on regions in the U.S. in which we have experience with similar
geological or production characteristics and which are in close proximity
to known producing horizons.

Strategic Acquisitions. We continually review acquisition
opportunities, using a disciplined, market-driven approach to acquire
properties which complement our drilling program. We seek to acquire
properties with significant proved producing reserves and the potential to
increase reserves and production through additional development and
exploration efforts.

Use of Advanced Technologies. We have increasingly used advanced
technologies to enhance the results of our drilling and production efforts,
including 2-D and 3-D seismic analysis, amplitude versus offset studies,
horizontal well drilling technology, innovative fracturing methods and
coiled tubing technology. In addition, we utilize computer telemetry to
monitor well performance. As a result of these technologies, we have
enhanced our production yields while controlling our production costs per
Mcfe.

S-4
<PAGE> 5

THE OFFERING

Common stock offered....... 4,000,000 shares

Common stock to be
outstanding after the
offering................. 20,181,179 shares

Use of proceeds............ The net proceeds of this offering are estimated to
be approximately $ million. The net
proceeds of the concurrent notes offering are
estimated to be approximately $ million.
The $ million of net proceeds of the two
offerings will be used to repay the outstanding
indebtedness under our credit facility. We intend
to use any excess net proceeds together with the
funds then made available under our credit facility
for capital expenditures, acquisitions and general
corporate purposes.

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:

- up to 600,000 shares which may be sold to the underwriters upon exercise
of their over-allotment option;

- 2,238,296 shares that may be issued pursuant to stock options outstanding
as of June 30, 1999, or under our other stock compensation or incentive
plans;

- up to 3,646,847 shares reserved for issuance upon conversion of our
convertible notes due 2006; and

- 859,456 shares held as treasury stock.

RISK FACTORS

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

CONCURRENT OFFERING

We are concurrently offering $125.0 million of % Senior Subordinated
Notes Due 2009 in a separate public offering pursuant to a separate prospectus
supplement. This offering of common stock and the concurrent notes offering are
not conditioned upon each other. This prospectus supplement relates only to the
offering of common stock and not to the offering of notes.

S-5
<PAGE> 6

SUMMARY CONSOLIDATED FINANCIAL DATA

The summary consolidated financial data of Swift as of and for each of the
five years ended December 31, 1998 has been derived from our audited
consolidated financial statements. The summary consolidated financial data of
Swift as of and for each of the six months ended June 30, 1999 and 1998 were
derived from our unaudited condensed consolidated financial statements. In the
opinion of our management, the summary consolidated financial data as of and for
each of the six months ended June 30, 1999 and 1998 include all normal recurring
adjustments necessary to present fairly this information. For a discussion of
the significant financial results and conditions during 1998, 1997, 1996 and the
six months ended June 30, 1999 and 1998, SEE "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS." The results of
operations for the six months ended June 30, 1999 should not be regarded as
indicative of expected results for the full year.

<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEAR ENDED DECEMBER 31,
------------------- ----------------------------------------------------
1999 1998 1998 1997 1996 1995 1994
-------- -------- -------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and gas sales..................... $ 44,668 $ 31,483 $ 80,068 $ 69,015 $ 52,771 $ 22,528 $ 19,802
Fees from limited partnerships and
joint ventures...................... 100 205 334 746 937 590 702
Interest income....................... 23 63 107 2,395 433 212 48
Other, net............................ 626 1,065 1,960 2,556 2,157 1,762 1,073
-------- -------- -------- -------- -------- -------- --------
Total Revenues.................... 45,417 32,816 82,469 74,712 56,298 25,092 21,625
-------- -------- -------- -------- -------- -------- --------
Costs and Expenses:
General and administrative, net of
reimbursement....................... 2,294 1,880 3,854 3,524 4,150 3,336 3,323
Depreciation, depletion, and
amortization........................ 21,227 13,985 39,343 24,247 16,526 8,839 7,905
Oil and gas production................ 8,551 4,875 13,139 8,779 6,142 4,907 3,764
Interest expense...................... 6,653 2,970 8,752 5,033 694 1,115 1,795
Write-down of oil and gas
properties(A)....................... -- -- 90,772 -- -- -- --
-------- -------- -------- -------- -------- -------- --------
Total Costs and Expenses.......... 38,725 23,710 155,860 41,583 27,512 18,197 16,787
-------- -------- -------- -------- -------- -------- --------
Income (Loss) before Income Taxes....... 6,692 9,106 (73,391) 33,129 28,786 6,895 4,838
Provision (Benefit) for Income Taxes.... 2,258 2,980 (25,166) 10,819 9,760 1,982 1,112
-------- -------- -------- -------- -------- -------- --------
Income (Loss) before Cumulative Effect
of Change in Accounting Principle..... 4,434 6,126 (48,225) 22,310 19,026 4,913 3,726
Cumulative Effect of Change in
Accounting Principle.................. -- -- -- -- -- -- (16,773)
-------- -------- -------- -------- -------- -------- --------
Net Income (Loss)................. $ 4,434 $ 6,126 $(48,225) $ 22,310 $ 19,026 $ 4,913 $(13,047)
======== ======== ======== ======== ======== ======== ========
Earnings (Loss) Per Share Amounts(B)(C):
Basic............................. $ 0.27 $ 0.37 $ (2.93) $ 1.35 $ 1.27 $ 0.49 $ (1.79)
======== ======== ======== ======== ======== ======== ========
Diluted........................... $ 0.27 $ 0.37 $ (2.93) $ 1.26 $ 1.25 $ 0.49 $ (1.79)
======== ======== ======== ======== ======== ======== ========
Weighted Average Shares
Outstanding(B)........................ 16,154 16,513 16,437 16,493 15,001 10,035 7,309
======== ======== ======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
EBITDA(D)............................... $ 34,572 $ 26,061 $ 65,476 $ 62,410 $ 46,006 $ 16,849 $ 14,538
Net cash provided by operating
activities............................ 28,303 25,491 54,249 55,256 37,103 14,376 10,395
Capital expenditures.................... 23,190 66,968 183,816 131,967 91,487 40,033 34,531
Ratio of earnings to fixed charges(E)... 1.6x 2.6x -- 5.2x 12.8x 3.1x 2.6x
Ratio of EBITDA to cash
interest(D)(F)........................ 4.1x 5.7x 5.1x 8.6x 15.7x 6.3x 4.0x
BALANCE SHEET DATA (AT END OF PERIOD):
Working capital (deficit)............... $ 5,178 $ 10,345 $ 3,831 $ 1,464 $ 68,704 $ 3,247 $(13,137)
Total assets............................ 395,580 404,259 403,645 339,115 310,375 175,253 135,673
Long-term debt:
Bank borrowings....................... 140,000 64,000 146,200 7,915 -- -- --
6.25% Convertible Subordinated
Notes............................... 115,000 115,000 115,000 115,000 115,000 -- --
6.50% Convertible Subordinated
Debentures.......................... -- -- -- -- -- 28,750 28,750
Stockholders' equity.................... 113,309 165,937 109,363 159,401 142,762 93,346 42,127

(Notes on following page)
</TABLE>

S-6
<PAGE> 7

NOTES TO SUMMARY CONSOLIDATED FINANCIAL DATA

(a) In the third quarter of 1998, we took a non-cash write-down of oil and gas
properties. Lower prices for both oil and gas at September 30, 1998,
necessitated a pre-tax domestic full-cost ceiling write-down of $77.2
million, or $50.9 million after-tax. Also in the third quarter, we
re-evaluated the timing of the recovery of our capitalized unproved
properties costs in Russia due to economic and political uncertainty and
impaired our total investment of $10.8 million. In addition, the
international economic uncertainty and currency concerns in Venezuela,
combined with the price volatility and severe tightening of international
credit markets, also caused us to impair our capitalized unproved
properties costs in Venezuela of $2.8 million. The re-evaluation of the
unproved properties costs in these two countries resulted in a separate
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 resulted in a
combined non-cash charge to earnings of $90.8 million pre-tax, or $59.9
million after-tax.

(b) Amounts have been retroactively restated in all periods presented to
reflect two 10% stock dividends, one in September 1994, the other in
October 1997.

(c) On a pro forma basis, assuming the 1994 change in accounting principle is
applied retroactively, basic and diluted earnings per share would have been
$0.51 for 1994.

(d) EBITDA represents income before interest expense, income tax, and
depreciation, depletion and amortization (including the 1998 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 and ability to incur and service debt.
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 and debt
servicing ability 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.

(e) For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expense, capitalized interest, amortization of
debt issuance costs and that portion of non-capitalized rental expense
deemed to be the equivalent of interest. Earnings represents income before
income taxes from continuing operations before fixed charges. Due to the
$90.8 million non-cash charge incurred in 1998 caused by a write-down in
the carrying value of 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 1998.

(f) Cash interest is defined as the total amount of interest paid on our
obligations, prior to any allowed capitalized amount.

S-7
<PAGE> 8

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. We have prepared our estimates of oil and gas
reserves, the future net revenues therefrom and their discounted present value,
or PV-10 Value, and they have been audited by H.J. Gruy and Associates, Inc.,
independent petroleum engineers. SEE, "BUSINESS AND PROPERTIES -- OIL AND GAS
RESERVES" AND "RISK FACTORS."

<TABLE>
<CAPTION>
AS OF OR FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------------------
1998 1997 1996 1995 1994
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
ESTIMATED PROVED OIL AND GAS RESERVES(A):
Net gas reserves (MMcf):
Proved developed................................ 197,106 191,108 135,425 81,532 46,406
Proved undeveloped.............................. 155,295 123,198 90,333 62,036 29,858
-------- -------- -------- -------- --------
Total.................................... 352,401 314,306 225,758 143,568 76,264
======== ======== ======== ======== ========
Net oil reserves (MBbls):
Proved developed................................ 7,143 4,289 3,622 3,313 3,209
Proved undeveloped.............................. 6,815 3,570 1,862 2,109 1,344
-------- -------- -------- -------- --------
Total.................................... 13,958 7,859 5,484 5,422 4,553
======== ======== ======== ======== ========
Total Proved Oil and Gas Reserves (MMcfe)......... 436,148 361,459 258,664 176,099 103,584
======== ======== ======== ======== ========
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.............................. $243,124 $244,365 $310,409 $ 85,537 $ 47,172
Proved undeveloped............................ 97,661 105,980 160,776 61,501 22,223
-------- -------- -------- -------- --------
Total PV-10 Value (before income taxes)(a)........ $340,785 $350,345 $471,185 $147,038 $ 69,395
======== ======== ======== ======== ========
Standardized measure of discounted estimated
future net cash flows after income taxes(A)..... $290,273 $292,838 $367,232 $128,904 $ 66,472
======== ======== ======== ======== ========
PRICES USED IN CALCULATING END OF YEAR PROVED
RESERVES:
Oil (per Bbl)................................... $ 11.23 $ 15.76 $ 23.75 $ 18.07 $ 15.09
Gas (per Mcf)................................... $ 2.23 $ 2.78 $ 4.47 $ 2.41 $ 1.85
OTHER RESERVES DATA:
Reserve replacement cost (per Mcfe)(b)............ $ 0.97 $ 0.73 $ 0.67 $ 0.61 $ 0.79
Reserve replacement rate(c)....................... 422% 590% 562% 588% 397%
Gas as % of total proved reserve quantities....... 81% 87% 87% 82% 74%
Proved developed reserves as % of total proved
reserves........................................ 55% 60% 61% 58% 63%
</TABLE>

<TABLE>
<CAPTION>
SIX
MONTHS
ENDED YEAR ENDED DECEMBER 31,
JUNE 30, ----------------------------------------------
1999 1998 1997 1996 1995 1994
-------- ------- ------- ------- ------- ------
<S> <C> <C> <C> <C> <C> <C>
NET SALES VOLUME:
Oil (MBbls).................................. 1,372 1,801 672 623 545 467
Gas (MMcf)(d)................................ 13,913 28,226 21,359 15,697 7,914 6,799
Total production (MMcfe)(d).................. 22,145 39,030 25,394 19,437 11,187 9,601
WEIGHTED AVERAGE SALES PRICES:
Oil (per Bbl)................................ $ 12.93 $ 11.86 $ 17.59 $ 19.82 $ 15.66 $14.35
Gas (per Mcf)................................ $ 1.94 $ 2.08 $ 2.68 $ 2.57 $ 1.77 $ 1.93
SELECTED DATA PER MCFE:
Production costs............................. $ 0.39 $ 0.34 $ 0.35 $ 0.32 $ 0.44 $ 0.39
Depreciation, depletion, and amortization.... $ 0.96 $ 1.01 $ 0.95 $ 0.85 $ 0.79 $ 0.82
General and administrative, net of
reimbursement.............................. $ 0.10 $ 0.10 $ 0.14 $ 0.21 $ 0.30 $ 0.35

(Notes on following page)
</TABLE>

S-8
<PAGE> 9

NOTES TO SUMMARY RESERVES AND PRODUCTION DATA

(a) Quantity estimates, their PV-10 Value and the standardized measure are
affected by the change in crude oil and gas prices at the end of each year.
While our total proved reserves quantities on an MMcfe basis at year-end
1998 increased by 21% over reserves quantities at the prior year-end, the
PV-10 Value decreased 3% and the standardized measure of those reserves
decreased 1%, from the PV-10 Value and standardized measure at year-end
1997. This decrease was almost entirely due to lower year-end 1998 prices.

(b) 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, including any revisions of those reserves.

(c) 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.

(d) Gas production for the six months ended June 30, 1999 and for the years
ended 1998, 1997, 1996, 1995 and 1994 includes 384, 866, 1,015, 1,156,
1,211 and 1,358 MMcf delivered under the volumetric production payment
agreement pursuant to which we are obligated to deliver certain monthly
quantities of gas to a third party through October 2000. Future volumes
associated with the volumetric production payment are not included in our
estimates of future net reserves.

S-9
<PAGE> 10

RISK FACTORS

An investment in our common stock involves significant risks. You should
carefully consider the following risk factors before you decide to buy the
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 buy the common stock.

LOW OIL AND GAS PRICES HURT OUR FINANCIAL RESULTS AND CONDITION.

Prices for oil and gas have become increasingly volatile and declined
significantly during the second half of 1998 and early 1999. Gas prices affect
us more than oil prices, as gas production was 72% of our 1998 production and
63% of our production in the first half of 1999. In 1998, gas prices we received
were 22% lower than 1997 prices, and oil prices were 33% lower. These lower
prices triggered a ceiling test write down, causing us to incur a net loss for
1998. Prices remaining at lower levels or decreasing further would negatively
affect us in several ways:

- our cash flows 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;

- 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; and

- we could be required to take another ceiling test write down of the
carrying values of our properties.

Consequently, our revenues and profitability would suffer. Most of the factors
which affect price volatility are beyond our control, such as demand, worldwide
economic conditions, weather conditions, supply levels, import prices, political
conditions in major oil producing regions, especially the Middle East, and
actions taken by OPEC.

OUR SUBSTANTIAL DEBT REDUCES OUR FINANCIAL FLEXIBILITY AND OUR DEBT LEVELS MAY
GROW.

After giving effect to this offering and the concurrent offering of notes,
on a pro forma basis at June 30, 1999, our long-term debt would equal
approximately 60% of our capitalization. A high level of debt:

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

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

- limits 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 the
notes being sold in the concurrent offering, we may borrow up to approximately
$150.0 million for capital expenditures. If we add additional debt to our
current debt levels, the risks discussed above would be accentuated.

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
approximately 42% of our reserves at December 31, 1998 are in the Austin Chalk
trend where wells typically have very steep rates of decline. Lower prices
S-10
<PAGE> 11

decrease our cash flow which can be dedicated to finding or purchasing new
producing reserves, and make borrowing and equity sales more difficult. Thus, we
need to spend significant amounts of capital to discover or purchase new
reserves. In response to lower oil and gas prices, our capital expenditures in
1999 are budgeted at $54.2 million, compared to $183.8 million in 1998 and
$132.0 million in 1997. It is likely that capital expenditures in 2000 will be
closer to the levels budgeted for 1999, rather than the levels spent in 1998. At
this level of capital expenditures, it is more difficult to replace our
reserves. Furthermore, for the reasons discussed below, even if capital is spent
on drilling or to make acquisitions, such efforts have a high risk of being
unsuccessful.

WE MAY INCUR ADDITIONAL WRITE DOWNS OF THE CARRYING VALUES OF OUR PROPERTIES.

SEC accounting rules require that on a quarterly basis we review the
carrying value of our oil and gas properties for possible write down or
impairment. Under these rules, capitalized costs of proved reserves may not
exceed 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. Primarily because of weak prices,
in the third quarter of 1998 we recorded a $77.2 million pre-tax ceiling
limitation write down for our domestic properties. Similarly, pricing and
currency factors, together with economic and political uncertainty in Russia and
Venezuela, led to a $13.6 million pre-tax impairment of our foreign investments
in those regions. This resulted in a combined non-cash charge of $90.8 million
before taxes in 1998.

We may be required to write down the carrying value of our oil and gas
properties in the future if oil and gas prices are depressed for even a short
period, are unusually volatile or if we have substantial downward revisions to
our proved reserves quantities. Any such ceiling test write down would result in
a charge to earnings and a reduction of stockholders' equity, but would not
impact our cash flow from operating activities. Once incurred, these write downs
are not reversible at a later date.

Given that full cost accounting rules are applied on a country-by-country
basis, we are currently exposed to the risk of a possible write down or
impairment of our properties in New Zealand. At June 30, 1999, our investments
in New Zealand totaled $5.4 million. To date, our drilling efforts there have
not been successful in establishing proved reserves. We have commenced drilling
an exploratory well under our New Zealand permit which we expect to conclude
during the second half of 1999. Swift's portion of the currently budgeted
drilling costs of this well are approximately $4.3 million. This exploratory
well is speculative. If this well does not discover economic reserves, in the
second half of 1999 we may be required to write down a large portion of our
drilling and capitalized costs. SEE, "BUSINESS AND PROPERTIES -- FOREIGN
ACTIVITIES."

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 and supply tightens. 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 economic. In addition to their
cost, unsuccessful wells can hurt our efforts to replace reserves.

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.

S-11
<PAGE> 12

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 and Louisiana, we may pursue acquisitions or properties
located in other geographic areas, which would decrease our geographical
concentration, but would also be in areas in which we have no or limited
experience.

ESTIMATES OF OUR PROVED RESERVES ARE UNCERTAIN AND OUR REVENUES FROM PRODUCTION
MAY VARY SIGNIFICANTLY FROM ESTIMATED AMOUNTS.

The quantities and values of our proved reserves included in this
prospectus supplement 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.

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, 1998, approximately 45% 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 DO NOT INSURE AGAINST ALL POTENTIAL LOSSES AND COULD BE SERIOUSLY HARMED BY
UNEXPECTED LIABILITIES.

Exploration for and production of oil and gas can be hazardous, involving
natural disasters and other unforeseen occurrences such as blowouts, cratering,
fires and loss of well control, which can damage or destroy wells or production
facilities, injure or kill people, and damage property and the environment.
Because third party drilling contractors are used to drill our wells, we may not
realize the full benefit of workman's compensation laws in dealing with their
employees. We maintain insurance against many potential losses and liabilities
arising from our operations in accordance with customary industry practices and
in amounts that we believe to be prudent. However, our insurance does not
protect us against all operational risks.

OUR HEDGING ACTIVITIES MAY RESULT IN LOSSES.

From time to time we enter into hedging activities in an effort to mitigate
the potential impact of declines in oil and gas prices. These activities consist
of buying protection price floors for some of our oil and gas production. The
cost of these floors may be lost if prices rise, and thus these arrangements
reduce the benefit of increases in the price of oil or gas while providing only
partial protection against declines in prices. FOR A MORE DETAILED DESCRIPTION
OF OUR HEDGING ACTIVITIES, SEE "BUSINESS AND PROPERTIES -- PRICE RISK
MANAGEMENT," AND NOTE 1 TO THE CONSOLIDATED FINANCIAL STATEMENTS.

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

Our exploration, production and marketing operations are regulated
extensively at the federal, state and local levels, which regulations affect the
costs, manner and feasibility of our operations. As an owner
S-12
<PAGE> 13

and operator of oil and gas properties, we are subject to federal, state and
local regulation of 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 regulations,
which may impose liability on us for the cost of pollution clean-up resulting
from operations, subject us to liability for pollution damages and require
suspension or cessation of operations in affected areas. Changes in or additions
to regulations regarding the protection of the environment could increase our
compliance costs and might hurt our business.

We are subject to state and local regulations that impose permitting,
reclamation, land use, conservation and other restrictions on our ability to
drill and produce. 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.

RELIANCE ON SENIOR OFFICERS AND OTHER KEY EMPLOYEES.

We rely on key employees and their expertise. If we were to lose several of
our key technical employees or executive officers, our operations could suffer
during their successors' transition periods. A. Earl Swift, our chief executive
officer and founder, has indicated a desire to retire during the fourth quarter
of 1999, which could adversely affect our day-to-day operations, although he
intends to remain as chairman of the board of directors. The board of directors
has commenced its search for Mr. Swift's replacement as chief executive officer.

WE ARE EXPOSED TO FINANCIAL AND OTHER LIABILITIES AS THE GENERAL PARTNER IN
NUMEROUS LIMITED PARTNERSHIPS.

We currently serve as the managing general partner of 80 limited
partnerships. 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 from partnership assets or insurance proceeds. At June 30,
1999, the partnerships' only liabilities were to Swift in the amount of
approximately $6.8 million. In the future, we may be exposed to litigation in
connection with partnership activities, or find it necessary to advance funds on
behalf of certain partnerships to protect the value of their oil and gas
properties. FOR MORE DETAILED DESCRIPTION, SEE "BUSINESS AND
PROPERTIES -- PARTNERSHIPS."

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.

WE ARE ENGAGED IN FOREIGN ACTIVITIES THAT EXPOSE US TO LOSSES FROM POLITICAL AND
ECONOMIC CONDITIONS ABROAD.

We are engaged in development and exploration activities in New Zealand,
have an existing net profits agreement in Russia and are pursuing pipeline
ventures in Venezuela. These foreign activities subject us to risks of foreign
currency fluctuations and controls, changes in foreign laws or their enforcement
and political and economic instability. Due to prevailing economic conditions in
the third quarter of 1998 in both Russia and Venezuela, we impaired our
capitalized unproved properties costs in both countries, resulting in a pre-tax
charge to earnings of $13.6 million. SEE, "BUSINESS AND PROPERTIES -- FOREIGN
ACTIVITIES."

S-13
<PAGE> 14

WE AND OUR SUPPLIERS OR PARTNERS MAY NOT BE YEAR 2000 COMPLIANT, WHICH COULD
RESULT IN DISRUPTION OF OUR OPERATIONS.

Actual effects of the Year 2000 issue are subject to uncertainties. Our
Year 2000 program may not completely identify every potential problem which may
arise. Our inability to completely solve all potential problems or address all
potentially affected systems could materially hurt our business. Likewise, our
business suppliers and partners may experience unanticipated Year 2000 problems
which could in turn affect our operations. In addition, we have relied on
representations from third parties that our systems and the systems of third
parties with whom we conduct business are Year 2000 compliant. However, because
of the difficulty in anticipating all effects of the Year 2000 issue, these
representations are not guarantees. If there are Year 2000 related failures in
our critical systems or our business suppliers' and partners' critical systems
that create substantial or prolonged disruptions to our business, the adverse
impact on us could materially affect our financial condition or results of
operations. FOR A MORE DETAILED DESCRIPTION OF OUR YEAR 2000 PROGRAM, SEE
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS -- YEAR 2000."

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 when announcements of adverse events regarding us or the industry are made.
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 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 to 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.

WE MAY NOT FINALIZE OUR PENDING LITIGATION SETTLEMENT.

The tentative agreement we have recently reached with the Lower Colorado
River Authority to settle our pending litigation, involving claims against us
alleged not to exceed $10.0 million exclusive of punitive damages, may not be
consummated and we may have to continue pursuing the matter in court. SEE,
"BUSINESS AND PROPERTIES -- LITIGATION."

S-14
<PAGE> 15

USE OF PROCEEDS

We estimate that the net proceeds from the sale of common stock will be
approximately $ million after deducting underwriting discounts and expenses,
or $ million if the underwriters fully exercise their over-allotment option.
Concurrently with this common stock offering, we are offering $125.0 million of
% Senior Subordinated Notes Due 2009, with estimated net proceeds of
$ . The two offerings are not conditioned upon each other.

We intend to use the net proceeds of the two offerings, which are estimated
to be $ million in the aggregate, to repay the outstanding debt under our
credit facility. We intend to use any excess net proceeds together with funds
then made available under our credit facility for capital expenditures,
acquisitions and general corporate purposes. As of June 30, 1999, the credit
facility had an outstanding balance of $140.0 million, of which $85.6 million
was used for the Sonat acquisition and the remainder was used for working
capital purposes. The weighted average interest rate was 6.64% at June 30, 1999.
Our credit facility matures August 18, 2002. After we apply the net proceeds of
both offerings to reduce our debt, we will have no outstanding balance under the
credit facility, and an anticipated borrowing base of approximately $150.0
million.

S-15
<PAGE> 16

CAPITALIZATION

The following table sets forth as of June 30, 1999:

- our historical capitalization;

- our capitalization as adjusted to show the receipt of the estimated net
proceeds from the sale of:

- the common stock being sold in this offering; and

- the concurrent common stock and notes offerings;

but does not reflect:

- the sale of up to 600,000 shares of common stock to the underwriters
if they exercise their over-allotment option in this offering;

- 2,238,296 shares that may be issued pursuant to stock compensation
plans as of June 30, 1999; or

- 3,646,847 shares of common stock that may be issued upon conversion of
our convertible notes due 2006.

This table should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the consolidated
financial statements and the related notes contained in this prospectus
supplement.

<TABLE>
<CAPTION>
AS OF JUNE 30, 1999
-----------------------------------
AS AS
ADJUSTED ADJUSTED
FOR FOR
COMMON COMMON
STOCK STOCK AND
HISTORICAL ONLY NOTES
---------- -------- ---------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C>
CASH AND CASH EQUIVALENTS.................................. $ 2,361 $ 2,361 $ 28,966
======== ======== ========
LONG-TERM DEBT:
Bank borrowings.......................................... $140,000 $ 94,645 --
% Senior Subordinated Notes Due 2009................. -- -- 125,000
6.25% Convertible Subordinated Notes Due 2006............ 115,000 115,000 115,000
-------- -------- --------
Total Long-Term Debt............................. 255,000 209,645 240,000
-------- -------- --------
STOCKHOLDERS' EQUITY:
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding.......................... -- -- --
Common stock, $.01 par value, 35,000,000 shares
authorized, 17,040,635 and 21,040,635 shares issued
and 16,181,179 and 20,181,179 shares outstanding,
respectively, as adjusted for the common stock
offering.............................................. 170 210 210
Additional paid-in capital............................... 148,897 197,107 197,107
Treasury stock held, at cost, 859,456 shares............. (12,326) (12,326) (12,326)
Retained earnings........................................ (23,432) (23,432) (23,432)
-------- -------- --------
Total Stockholders' Equity....................... 113,309 161,559 161,559
-------- -------- --------
TOTAL CAPITALIZATION............................. $368,309 $371,204 $401,559
======== ======== ========
</TABLE>

S-16
<PAGE> 17

COMMON STOCK PRICE RANGE AND DIVIDEND POLICY

Our common stock is traded on the New York Stock Exchange and the Pacific
Stock Exchange 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 New
York Stock Exchange and the Pacific Stock Exchange on a consolidated basis for
the periods indicated.

<TABLE>
<CAPTION>
HIGH LOW
------ ------
<S> <C> <C>
1997
First Quarter............................................... $34.20 $19.32
Second Quarter.............................................. 26.02 16.93
Third Quarter............................................... 26.48 18.86
Fourth Quarter.............................................. 31.00 19.25

1998
First Quarter............................................... $21.00 $15.88
Second Quarter.............................................. 20.75 15.00
Third Quarter............................................... 16.75 8.81
Fourth Quarter.............................................. 11.19 6.94

1999
First Quarter............................................... $ 9.25 $ 5.13
Second Quarter.............................................. 12.94 8.06
Third Quarter (through July 12, 1999)....................... 12.06 11.13
</TABLE>

We have adjusted the stock prices for the first three quarters of 1997 to
reflect a 10% stock dividend declared in October 1997. The last sale price of
our common stock as reported by the New York Stock Exchange on July 12, 1999 was
$12.0625 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 for the concurrently offered notes limit our
ability to pay dividends. FOR A MORE DETAILED DESCRIPTION, SEE "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS -- LIQUIDITY AND CAPITAL RESOURCES."

S-17
<PAGE> 18

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The selected historical consolidated financial data of Swift as of and for
each of the five years ended December 31, 1998 has been derived from our audited
consolidated financial statements. The selected historical consolidated
financial data of Swift as of and for each of the six months ended June 30, 1999
and 1998 were derived from our unaudited condensed consolidated financial
statements. In the opinion of our management, the selected historical
consolidated financial data as of and for each of the six months ended June 30,
1999 and 1998 include all normal recurring adjustments necessary to present
fairly this information. For a discussion of the significant financial results
and conditions during 1998, 1997, 1996 and the six months ended June 30, 1999
and 1998, SEE "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS." The results of operations for the six months ended June
30, 1999 should not be regarded as indicative of expected results for the full
year.

<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEAR ENDED DECEMBER 31,
------------------- ----------------------------------------------------
1999 1998 1998 1997 1996 1995 1994
-------- -------- -------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and gas sales........................ $ 44,668 $ 31,483 $ 80,068 $ 69,015 $ 52,771 $ 22,528 $ 19,802
Fees from limited partnerships and joint
ventures............................... 100 205 334 746 937 590 702
Interest income.......................... 23 63 107 2,395 433 212 48
Other, net............................... 626 1,065 1,960 2,556 2,157 1,762 1,073
-------- -------- -------- -------- -------- -------- --------
Total Revenues....................... 45,417 32,816 82,469 74,712 56,298 25,092 21,625
-------- -------- -------- -------- -------- -------- --------
Costs and Expenses:
General and administrative, net of
reimbursement.......................... 2,294 1,880 3,854 3,524 4,150 3,336 3,323
Depreciation, depletion, and
amortization........................... 21,227 13,985 39,343 24,247 16,526 8,839 7,905
Oil and gas production................... 8,551 4,875 13,139 8,779 6,142 4,907 3,764
Interest expense......................... 6,653 2,970 8,752 5,033 694 1,115 1,795
Write-down of oil and gas
properties(A).......................... -- -- 90,772 -- -- -- --
-------- -------- -------- -------- -------- -------- --------
Total Costs and Expenses............. 38,725 23,710 155,860 41,583 27,512 18,197 16,787
-------- -------- -------- -------- -------- -------- --------
Income (Loss) before Income Taxes.......... 6,692 9,106 (73,391) 33,129 28,786 6,895 4,838
Provision (Benefit) for Income Taxes....... 2,258 2,980 (25,166) 10,819 9,760 1,982 1,112
-------- -------- -------- -------- -------- -------- --------
Income (Loss) before Cumulative Effect of
Change In Accounting Principle........... 4,434 6,126 (48,225) 22,310 19,026 4,913 3,726
Cumulative Effect of Change in Accounting
Principle................................ -- -- -- -- -- -- (16,773)
-------- -------- -------- -------- -------- -------- --------
Net Income (Loss)...................... $ 4,434 $ 6,126 $(48,225) $ 22,310 $ 19,026 $ 4,913 $(13,047)
======== ======== ======== ======== ======== ======== ========
Earnings (Loss) Per Share Amounts(B)(C):
Basic.................................... $ 0.27 $ 0.37 $ (2.93) $ 1.35 $ 1.27 $ 0.49 $ (1.79)
======== ======== ======== ======== ======== ======== ========
Diluted.................................. $ 0.27 $ 0.37 $ (2.93) $ 1.26 $ 1.25 $ 0.49 $ (1.79)
======== ======== ======== ======== ======== ======== ========
Weighted Average Shares Outstanding(B)..... 16,154 16,513 16,437 16,493 15,001 10,035 7,309
======== ======== ======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
EBITDA(D).................................. $ 34,572 $ 26,061 $ 65,476 $ 62,410 $ 46,006 $ 16,849 $ 14,538
Net cash provided by operating
activities............................... 28,303 25,491 54,249 55,256 37,103 14,376 10,395
Capital expenditures....................... 23,190 66,968 183,816 131,967 91,487 40,033 34,531
Ratio of earnings to fixed charges(E)...... 1.6x 2.6x -- 5.2x 12.8x 3.1x 2.6x
Ratio of EBITDA to cash interest(D)(F)..... 4.1x 5.7x 5.1x 8.6x 15.7x 6.3x 4.0x

BALANCE SHEET DATA (AT END OF PERIOD):
Working capital (deficit).................. $ 5,178 $ 10,345 $ 3,831 $ 1,464 $ 68,704 $ 3,247 $(13,137)
Total assets............................... 395,580 404,259 403,645 339,115 310,375 175,253 135,673
Long-term debt:
Bank borrowings.......................... 140,000 64,000 146,200 7,915 -- -- --
6.25% Convertible Subordinated Notes..... 115,000 115,000 115,000 115,000 115,000 -- --
6.50% Convertible Subordinated
Debentures............................. -- -- -- -- -- 28,750 28,750
Stockholders' equity....................... 113,309 165,937 109,363 159,401 142,762 93,346 42,127

(Notes on following page)
</TABLE>

S-18
<PAGE> 19

NOTES TO SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

(a) In the third quarter of 1998, we took a non-cash write-down of oil and gas
properties. Lower prices for both oil and gas at September 30, 1998,
necessitated a pre-tax domestic full-cost ceiling write-down of $77.2
million, or $50.9 million after tax. Also in the third quarter, we
re-evaluated the timing of the recovery of our capitalized unproved
properties costs in Russia due to economic and political uncertainty and
impaired our total investment of $10.8 million. In addition, the
international economic uncertainty and currency concerns in Venezuela
combined with the price volatility and severe tightening of international
credit markets, also caused us to impair our capitalized unproved
properties costs in Venezuela of $2.8 million. The re-evaluation of the
unproved properties costs in these two countries resulted in a separate
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 resulted in a combined non-cash
charge to earnings of $90.8 million pre-tax, or $59.9 million after tax.

(b) Amounts have been retroactively restated in all periods presented to
reflect two 10% stock dividends, one in September 1994, the other in
October 1997.

(c) On a pro forma basis, assuming the 1994 change in accounting principle is
applied retroactively, basic and diluted earnings per share would have been
$0.51 for 1994.

(d) EBITDA represents income before interest expense, income tax, and
depreciation, depletion and amortization (including the 1998 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 and ability to incur and service debt.
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 and debt
servicing ability 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.

(f) Cash interest is defined as the total amount of interest paid on our
obligations, prior to any allowed capitalized amount.

S-19
<PAGE> 20

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 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 4.

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 lower and other market conditions are
appropriate, as we did in the third quarter of 1998 with the purchase of the
Brookeland and Masters Creek Fields from Sonat Exploration Company. Since 1996,
we have used this flexible strategy of employing both drilling and acquisitions
to add more reserves than we depleted through production. Our revenues are
primarily from oil and gas sales attributable to properties in which we own a
direct or indirect interest.

Proved Oil and Gas Reserves. At year-end 1998, our total proved reserves
were 436.1 Bcfe with a PV-10 Value of $340.8 million. In 1998, we increased our
proved gas reserves by 38.1 Bcf, or 12%, and our proved oil reserves by 6.1
MMBbl or 78%, for a total of 74.7 Bcfe representing a 21% increase. From 1996 to
1997, we increased our proved gas reserves by 88.5 Bcf, or 39%, and our proved
oil reserves by 2.4 MMBbl, or 43%, for a total of 102.8 Bcfe representing a 40%
increase. Through drilling, we added 73.9 Bcfe of proved reserves in 1998, 120.2
Bcfe in 1997 and 118.2 Bcfe in 1996. Through acquisitions we added 97.6 Bcfe of
proved reserves in 1998, 33.8 Bcfe in 1997 and 3.3 Bcfe in 1996. A substantial
portion of these reserves were proved undeveloped. At year-end 1998, 45% of our
total proved reserves were proved undeveloped, compared with 40% at year-end
1997 and 39% at year-end 1996.

While our total proved reserves quantities at year-end 1998 increased by
21% over those at year-end 1997, the PV-10 Value of those reserves decreased 3%
over the same period, almost entirely due to pricing declines during 1998. We
added reserves from 1997 to 1998 through our drilling activity, primarily in the
AWP Olmos and Giddings Fields, and through purchases of minerals in place,
primarily in the Brookeland and Masters Creek Fields. These additions to our
reserves were offset by revisions of previous estimates, the 20% decrease in
year-end 1998 gas prices, and the 29% decrease in year-end 1998 oil prices. Gas
prices were $2.23 per Mcf at year-end 1998 compared to $2.78 per Mcf at year-end
1997. Oil prices were $11.23 per Bbl at year-end 1998 compared to $15.76 a year
earlier. If the 1998 year-end PV-10 Value and 1998 year-end standardized measure
had been calculated using year-end 1997 prices, there would have been an
increase in the PV-10 Value and standardized measure from year-end 1997 to
year-end 1998 comparable to the 21% increase in the total proved reserves
quantities during that same period. FOR A MORE DETAILED DESCRIPTION, SEE
"STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS" IN THE SUPPLEMENTAL
INFORMATION TO THE CONSOLIDATED FINANCIAL STATEMENTS AND "BUSINESS AND
PROPERTIES -- OIL AND GAS RESERVES."

RESULTS OF OPERATIONS -- SIX MONTHS ENDED JUNE 30, 1999 AND JUNE 30, 1998

Revenues. Our revenues increased 38% during the first six months of 1999 as
compared to the same period in 1998. This increase was caused by the growth in
our oil and gas sales, which resulted from the increase in production volumes
and which was offset by lower gas prices.

Oil and Gas Sales. Our oil and gas sales increased 42% to $44.7 million in
the first six months of 1999, compared to $31.5 million for the comparable
period in 1998. Our gas production increased 16% and oil production increased
256% primarily due to production from the Brookeland and Masters Creek Fields,
which were acquired in the third quarter of 1998. Our net sales volume in the
first six months of 1999 increased by 55%, or 7.8 Bcfe, over volumes in the same
period in 1998. A 14% decrease in gas prices between the two periods
significantly offset the increase in volume and 9% increase in oil prices.
S-20
<PAGE> 21

Our $13.2 million increase in oil and gas sales during the first six months
of 1999 resulted from:

- Volume increases which added $16.0 million of sales, with $4.2 million of
the increase coming from the 1.9 Bcf increase in gas sales volumes and
$11.8 million of the increase coming from the 987,000 Bbl increase in oil
sales volumes; and

- Price variances, which had a $2.8 million unfavorable impact on sales due
to the decrease in average gas prices received of $4.2 million offset by
an increase of $1.4 million in average oil prices received.

The following table provides additional information regarding the changes
in the sources of our oil and gas sales and volumes for the first six month
periods of 1999 and 1998.

<TABLE>
<CAPTION>
NET SALES
REVENUES VOLUMES
(IN MILLIONS) (BCFE)
-------------- ------------
FIELD 1999 1998 1999 1998
- ----- ----- ----- ---- ----
<S> <C> <C> <C> <C>
AWP Olmos $13.8 $17.2 6.9 7.8
Brookeland $ 5.8 -- 2.9 --
Giddings $ 3.6 $ 8.9 1.9 3.9
Masters Creek $19.3 -- 9.1 --
</TABLE>

Revenues from oil and gas sales comprised 98% of our total revenues for the
first six months of 1999 as compared to 96% for the first half of 1998. Our
acquisition of interests in the Masters Creek and Brookeland Fields, which have
a higher percentage of production from oil, has decreased the predominance of
gas in our production mix from 84% in the first six months of 1998 to 63% in the
first six months of 1999. Even though we scaled back our 1999 capital
expenditures budget, we expect oil and gas sales volumes to increase in 1999
when compared to 1998, primarily due to the full year of production from the
Masters Creek and Brookeland Fields. However, due to the decrease in our 1999
capital expenditures budget, and the resulting curtailment of new drilling in
the Giddings Field, the natural production decline in this field was not offset
by newly developed production.

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

<TABLE>
<CAPTION>
NET SALES VOLUME AVERAGE SALES PRICE
---------------------- -----------------------------
OIL (BBL) GAS (MCF) OIL (PER BBL) GAS (PER MCF)
--------- ---------- ------------- -------------
<S> <C> <C> <C> <C>
1998
Six months ended June 30............ 385,339 12,017,764 $11.91 $2.24
1999
Six months ended June 30............ 1,372,133 13,912,504 $12.93 $1.94
</TABLE>

Costs and Expenses. Our general and administrative expenses for the first
six months of 1999 increased approximately $0.4 million, when compared to the
same period in 1998. However, our general and administrative expenses per Mcfe
produced decreased by 21% from $0.13 per Mcfe for the first six months of 1998
to $0.10 per Mcfe for the comparable period in 1999. Supervision fees netted
from general and administrative expenses for the first six months of 1999 were
$1.5 million and for the same period of 1998 were $1.4 million.

Depreciation, depletion and amortization of our assets, or DD&A, increased
52% or approximately $7.2 million for the first six months of 1999. This was
primarily due to additions to our reserves and associated costs and to the
related 55% increase in production volumes from the added reserves primarily
resulting from the Sonat acquisition as compared to the same period in 1998. Our
DD&A rate per Mcfe of production has decreased from $0.98 per Mcfe in the first
six months of 1998 to $0.96 per Mcfe in the same 1999 period.

Our production costs per Mcfe increased to $0.39 per Mcfe in the first half
of 1999 from $0.34 per Mcfe in the same 1998 period. In the Brookeland and
Masters Creek Fields, a higher percentage of our
S-21
<PAGE> 22

production is from oil. Production costs for oil typically are higher than those
for gas, resulting in a higher production cost per Mcfe. Primarily due to the
55% increase in our production volumes, oil and gas production costs increased
by 75%, or approximately $3.7 million, in the first six months of 1999 when
compared to the first six months of 1998. Supervision fees netted from
production costs for the first six months of 1999 were $1.5 million and for the
first six months of 1998 were $1.4 million.

Interest expense on our convertible notes due 2006, including amortization
of debt issuance costs, was the same in the first six months of 1999 and in
1998, totaling $3.8 million. Interest expense on our credit facility, including
commitment fees and amortization of debt issuance costs, totaled $4.9 million in
the first six months of 1999, compared to $1.1 million for our credit facilities
in the same 1998 period. Thus, 1999 total interest charges were $8.7 million, of
which $2.0 million was capitalized. In the first six months of 1998, these
charges totaled $4.8 million, of which $1.8 million was capitalized. We
capitalized that portion of interest related to our exploration, partnership and
foreign business development activities. The increase in interest expense in
1999 is attributable to the increase in amounts outstanding under our credit
facility.

Net Income. Our net income for the first six months of 1999 of $4.4 million
and basic earnings per share, or EPS, of $0.27 were both 27% lower than net
income of $6.1 million and basic EPS of $0.37 for the same period in 1998. This
decrease primarily reflected the effect of lower gas prices, while our costs and
expenses increased 63% in relation to the 55% increase in production volumes
discussed above.

RESULTS OF OPERATIONS -- YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996

Revenues. Our revenues increased by 10% in 1998 over revenues in 1997, and
increased by 32% in 1997 over 1996 revenues, principally due to increases in oil
and gas sales revenues.

Oil and Gas Sales. Our oil and gas sales revenues in 1998 increased by 16%,
or $11.1 million, over those revenues for 1997. In 1997, oil and gas sales
revenues increased by 31%, or $16.2 million, over those revenues in 1996. Our
net sales volumes in 1998, including the volumetric production payment
associated with each year's production, increased by 54%, or 13.6 Bcfe, over net
sales volumes in 1997. In 1997, net sales volumes increased by 31%, or 6.0 Bcfe,
over net sales volumes in 1996. Average prices for oil declined from $19.82 per
Bbl in 1996 to $17.59 per Bbl in 1997 and to $11.86 per Bbl in 1998. Average gas
prices increased slightly from $2.57 per Mcf in 1996 to $2.68 per Mcf in 1997,
and then decreased to $2.08 per Mcf in 1998.

In 1998, our $11.1 million increase in oil and gas sales resulted from:

- Volume increases that added $38.3 million of sales with $18.4 million of
the increase coming from the 6.9 Bcf increase in gas sales volumes and
$19.9 million of the increase coming from the 1.1 MMBbl increase in oil
sales volumes; and

- Price variances that had a $27.2 million unfavorable impact on sales,
$16.9 million of which was attributable to the 22% decrease in average
gas prices received, and $10.3 million of which was attributable to the
33% decrease in average oil prices received.

In 1997, our $16.2 million increase in oil and gas sales resulted from:

- Volume increases that added $15.5 million of sales, with $14.5 million of
the increase coming from the 5.7 Bcf increase in gas sales volumes and
$1.0 million of the increase coming from the 49,000 Bbl increase in oil
sales volumes; and

- Price variances that added $0.7 million to sales, with $2.2 million in
increased sales from the increase in average gas prices received, offset
by a $1.5 million decrease in sales from the decrease in average oil
prices received.

In 1998, the increases in oil and gas sales were primarily the result of
the addition of production from the Brookeland and Masters Creek Fields during
the second half of 1998. The decisions to acquire the Brookeland and Masters
Creek Fields and to defer some drilling were both made in response to market

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<PAGE> 23

conditions. In 1997, the increases in oil and gas sales were primarily the
result of production from our accelerated drilling program, most notably in the
AWP Olmos and Giddings Fields.

The following table provides additional information regarding the changes
in the sources of our oil and gas sales and volumes from 1997 to 1998.

<TABLE>
<CAPTION>
NET SALES
REVENUES VOLUMES
(IN MILLIONS) (BCFE)
-------------- ------------
FIELD 1998 1997 1998 1997
- ----- ----- ----- ---- ----
<S> <C> <C> <C> <C>
AWP Olmos $33.5 $42.2 15.5 15.5
Brookeland $ 6.8 -- 3.5 --
Giddings $14.6 $12.9 7.0 4.9
Masters Creek $17.5 -- 8.2 --
</TABLE>

Revenues from our oil and gas sales comprised 97% of total revenues for
1998, 92% of total revenues for 1997 and 94% of total revenues for 1996. The
Brookeland and Masters Creek Fields which have a higher percentage of production
from oil, with oil making up approximately 56% of these fields' 1998 production,
have altered our predominate gas production mix.

Costs and Expenses. Our general and administrative expenses in 1998
increased $0.3 million, or 9%, from the level of such expenses in 1997, while
1997 general and administrative expenses decreased $0.6 million, or 15%, below
1996 levels. The small variances in these costs over the three-year period
reflect our ability to increase our activities and reserves base without
materially increasing related costs. Our general and administrative expenses per
Mcfe produced have decreased in each of the past three years from $0.21 per Mcfe
in 1996 to $0.14 per Mcfe in 1997 and to $0.10 per Mcfe in 1998. Supervision
fees netted from general and administrative expenses were $2.7 million for 1998,
$2.6 million for 1997 and $2.2 million for 1996.

DD&A increased 62% in 1998 and 47% in 1997, primarily due to additions to
our reserves and associated costs and to the related sale of increased
quantities of oil and gas produced from the added properties, which increased
54% in 1998 and 31% in 1997. Our DD&A rate per Mcfe of production was $0.85 in
1996, $0.95 in 1997 and $1.01 in 1998, reflecting variations in the per unit
cost of reserves additions.

Our production costs in 1998 increased $4.4 million, or 50%, over such
expenses in 1997, while those expenses in 1997 increased $2.6 million, or 43%,
over 1996 costs. The increases in each of the periods primarily relate to the
increases in our oil and gas sales volumes. Our production costs per Mcfe
produced were $0.34 in 1998, $0.35 in 1997 and $0.32 in 1996. Supervision fees
netted from production costs were $2.7 million for 1998, $2.6 million for 1997
and $2.2 million for 1996.

Interest expense in both 1998 and 1997 on our convertible notes due 2006,
including amortization of debt issuance costs, totaled $7.5 million, compared to
$0.7 million on our convertible notes due 2006 and $1.0 million on the 1993
convertible debentures in 1996. Interest expense on our credit facilities,
including commitment fees, totaled $5.6 million in 1998, $0.1 million in 1997
and $1.1 million in 1996. Thus, 1998's interest expense totaled $13.1 million,
of which $4.4 million was capitalized. The 1997 total interest expense was $7.6
million, of which $2.6 million was capitalized. The 1996 total interest expense
was $2.8 million, of which $2.1 million was capitalized. We capitalized that
portion of the interest related to our exploration, partnership and foreign
business development activities. The increase in interest expense in 1998 was
attributable to the increase in amounts outstanding under our credit facilities.
The increase in interest expense in 1997 was attributable to the larger
outstanding principal amount of $115.0 million on the convertible notes due 2006
compared to $28.75 million principal amount of 1993 convertible debentures,
offset to some degree by larger outstanding balances under our credit facilities
in 1996 and by the $2.4 million in interest income earned in 1997 on the portion
of the net proceeds of the convertible notes due 2006 invested pending use.

S-23
<PAGE> 24

In the third quarter of 1998, we took a non-cash write down of oil and gas
properties, as discussed in note 1 to our financial statements. Lower prices for
both oil and gas at September 30, 1998 necessitated a pre-tax domestic full-cost
ceiling write down of $77.2 million, or $50.9 million after tax. Also in the
third quarter, we re-evaluated the timing of the recovery of our capitalized
unproved properties costs in Russia due to economic and political uncertainty
and impaired our total investment of $10.8 million. In addition, the
international economic uncertainty and currency concerns in Venezuela combined
with the price volatility and severe tightening of international credit markets,
also caused us to impair our capitalized unproved properties costs in Venezuela
of $2.8 million. The re-evaluation of the unproved properties costs in these two
countries resulted in a separate non-cash pre-tax charge to earnings of $13.6
million, or $9.0 million after tax. We are currently expensing costs in these
countries. The combination of the non-cash full-cost domestic ceiling write down
and the non-cash foreign impairment charges resulted in a combined non-cash
charge to earnings of $90.8 million pre-tax, or $59.9 million after tax. We
currently have no intention to make any additional investments in Russia.

At December 31, 1998, our full-cost ceiling cushion was approximately $25.0
million. Subsequent to year-end 1998, oil and gas prices have increased,
providing a substantially larger full-cost ceiling cushion.

Net Income. Before the non-cash write down of oil and gas properties in
1998, our net income of $11.7 million was 48% lower, and basic EPS of $0.71 was
47% lower, than net income of $22.3 million and basic EPS of $1.35 in the same
period for 1997. This decrease primarily reflected the effect of the 33%
decrease in oil prices and 22% decrease in gas prices, while costs and expenses
increased in general proportion to the 54% increase in production volumes
discussed above.

Our 1997 net income of $22.3 million was 17% higher and basic EPS of $1.35
was 6% higher than net income of $19.0 million and basic EPS of $1.27 in 1996.
This increase in net income primarily reflected the effect of a 31% increase in
oil and gas sales revenues as a result of a 36% increase in gas production, an
8% increase in crude oil production, and a slight 4% increase in gas prices
received, offset by an 11% decrease in oil prices received. The lower percentage
increase in basic EPS reflects a 10% increase in weighted average shares
outstanding in 1997 as a result of the conversion of the 1993 convertible
debentures into 2.34 million shares of common stock in the third quarter of
1996.

LIQUIDITY AND CAPITAL RESOURCES

During the first six months of 1999, we relied upon internally generated
cash flows of $28.3 million to fund capital expenditures of $23.2 million. We
expect internally generated cash flows, together with limited borrowings under
our credit facility, to provide cash and working capital for the remainder of
1999. During 1998, we used $138.3 million of borrowings under our credit
facilities, along with our internal cash flows of $54.2 million, to fund capital
expenditures of $183.8 million.

Net Cash Provided by Operating Activities. For the first half of 1999, net
cash provided by our operating activities increased by 11% to $28.3 million, as
compared to $25.5 million during the first six months of 1998. The 1999 increase
of $2.8 million was primarily due to $13.2 million of additional oil and gas
sales. However, this increase is substantially offset by the $7.4 million
increases in both oil and gas production costs and in interest expense.

Our operating activities provided net cash of $54.2 million in 1998, $55.3
million in 1997 and $37.1 million in 1996. The slight decrease of $1.1 million
in 1998 was primarily due to the offset of our 54% increase in production
volumes by:

- the 25% decrease in average commodity prices received;

- the associated 50% increase in oil and gas production costs; and

- a decrease in interest income and an increase in interest expense due to
our use of the net proceeds of our convertible notes due 2006, resulting
in increased bank borrowings during 1998.

S-24
<PAGE> 25

The 1997 increase in net cash of $18.2 million was primarily due to $16.5
million more in cash flows from oil and gas sales and interest income.

Credit Facility. At June 30, 1999, we had outstanding borrowings of $140.0
million under our credit facility. At December 31, 1998, we had outstanding
borrowings of $146.2 million under the credit facility. At July 1, 1999, our
credit facility consisted of a $250.0 million revolving line of credit with a
$161.0 million borrowing base. Upon closing of both this offering and the
concurrent notes offering, we anticipate that our borrowing base will be
approximately $150.0 million. Our $250.0 million revolving credit facility
includes, among other restrictions, requirements to maintain certain minimum
financial ratios principally pertaining to working capital, debt and equity
ratios, and limitations on incurring other debt. We are currently in compliance
with the provisions of our credit facility.

Debt Maturities. Our credit facility extends until August 18, 2002. Our
convertible notes mature November 15, 2006.

Working Capital. Our working capital increased from $3.8 million at
December 31, 1998 to $5.2 million at June 30, 1999, as our internally generated
funds exceeded our capital expenditures.

Due to the nature of our business, the individual components of our working
capital fluctuate considerably from period to period. We incur significant
working capital requirements in our role as operator of approximately 836 wells
and in our drilling and acquisition activities. In this capacity, we are
responsible for day-to-day cash management, including the collection and
disbursement of oil and gas revenues and related expenses.

Common Stock Repurchase Program. In March 1997, we commenced a common stock
repurchase program which terminated pursuant to its terms as of June 30, 1999.
We spent $13.3 million through June 30, 1999 to acquire 927,774 shares at an
average cost of $14.34 per share. In March 1999, we used 68,318 shares of
treasury stock to fund our employer matching in the 401(k) program for our
employees. The indenture governing the terms of the notes being sold in the
concurrent notes offering will limit our right to make stock repurchases in the
future.

Capital Expenditures. During the first six months of 1999, we used $23.2
million to fund capital expenditures for property, plant and equipment. These
capital expenditures included:

- $15.7 million spent for drilling costs, both development and exploratory;

- $6.7 million of domestic prospect costs, principally prospect leasehold,
seismic and geological costs of unproved prospects for our account;

- $0.4 million invested in New Zealand; and

- $0.4 million spent primarily for computer equipment, software and
furniture and fixtures.

In the remaining six months of 1999, we expect to spend approximately $31.0
million on capital expenditures, including investments in all areas in which
investments were made during the first six months of the year as described
above. Ten wells were drilled in the first half of 1999, and seven were
completed as successful development wells. For the second half of 1999, we
anticipate drilling an additional ten wells, made up of eight development wells
and two exploratory wells. We estimate capital expenditures for 1999 to be
approximately $54.2 million, which is substantially lower than prior years.
Approximately $36.0 million of the 1999 budget is allocated to drilling,
primarily in our core fields. The remaining $18.2 million is targeted
principally for leasehold, seismic and geological costs of unproved properties.
We believe that 1999's anticipated internally generated cash flows, together
with limited borrowings under our credit facility, will be sufficient to finance
the costs associated with our currently budgeted remaining 1999 capital
expenditures.

Our capital expenditures were approximately $183.8 million for 1998, $132.0
million for 1997 and $91.5 million for 1996. During 1997, we relied upon net
proceeds from the sale in 1996 of $115.0 million of convertible notes due 2006
and on internally generated cash flows, along with $7.9 million of bank
borrowings, to fund capital expenditures. During 1998, we used $138.3 million of
bank borrowings, along
S-25
<PAGE> 26

with internal cash flows of $54.2 million, to fund capital expenditures. Capital
expenditures in 1998 included:

- $59.5 million, or 32%, spent on producing properties acquisitions, almost
all of which was for the Brookeland and Masters Creek Fields acquisition;

- $54.8 million, or 30%, spent on developmental drilling, primarily in the
AWP Olmos and Giddings Fields;

- $12.6 million, or 7%, spent on exploratory drilling;

- $34.7 million, or 19%, spent on domestic prospect costs, principally
leasehold, seismic, and geological costs of unproven prospects for our
account, including $15.2 million for leaseholds in the Brookeland and
Masters Creek Fields acquisition;

- $15.0 million, or 8%, spent for the purchase of a 20% interest in two gas
processing plants in the Brookeland and Masters Creek Fields acquisition;

- $3.9 million, or 2%, invested in foreign business opportunities,
consisting of $2.9 million in New Zealand, $0.4 million in Venezuela and
$0.6 million in Russia, as described in Note 8 to our financial
statements;

- $2.2 million, or 1%, spent on field compression facilities; and

- $1.0 million, or 1%, spent on fixed assets.

In 1998, we participated in drilling 61 development wells and 14
exploratory wells, of which 53 development wells and 5 exploratory wells were
successes. The steady growth in the amount of our unproved property to $56.0
million, which is not being amortized, is indicative of our shift to a focus on
drilling activity in recent years as we acquired prospect acreage in or near our
core fields, such as the acquisition of substantial leasehold positions in the
Masters Creek and Brookeland Fields, and in the pursuit of our New Zealand
activities.

YEAR 2000

The Year 2000 issue arose because many existing computer programs use only
the last two digits to refer to a year. Therefore, these programs cannot
distinguish between the years 1900 and 2000. Errors of this type can result in
systems failures, miscalculations and the disruption of normal business
activities. We formed a task force during 1998 to address the Year 2000 issue
and to prepare our business systems for the Year 2000. This task force developed
our Year 2000 program, which includes testing our in-house business systems and
field operations systems, reviewing Year 2000 compliance certifications and
reports issued by third parties, upgrading or replacing noncompliant systems and
preparing a contingency plan for unforeseen difficulties. We are continuing to
implement this plan in an effort to make our operations capable of addressing
the Year 2000.

Our in-house business systems are almost entirely comprised of
off-the-shelf software. During the first half of 1999, we continued to test any
in-house software which has not been certified by the licensor as Year 2000
compliant. To date, 80% of these systems have been tested, certified as
compliant by the licensor of the software, or categorized as not date specific.
We are continuing to identify any software which experiences difficulties
distinguishing the Year 2000. We solve most of these potential Year 2000
problems by upgrading or replacing this software, which we test as it is
installed. We have not experienced any material system disruption during testing
procedures, and based on testing and remedial activities, we believe that we
will be able to resolve potential Year 2000 problems concerning our financial
and administrative systems. We expect to complete testing during the third
quarter of 1999 and continue remedial actions as needed.

Our core business functions consist of oil and gas exploration. The systems
and equipment which perform these functions are primarily non-information
technology systems which are not date specific.

S-26
<PAGE> 27

Although we cannot predict all effects of the Year 2000 issue, based on our
review, we expect that our field operation systems will continue to perform
normally when faced with the Year 2000.

In the event of unforeseen Year 2000 difficulties, employees can manually
perform most, if not all, in-house functions, although such acts may require
additional time to perform. Our most reasonably likely worst case scenario would
therefore involve a prolonged disruption of external power sources upon which
our core field operations equipment relies.

In our business, we also depend on third parties such as pipeline
operations to whom we sell gas, customers and suppliers, any one of whom could
be prone to Year 2000 problems that we cannot assess or detect. We have
contacted our major purchasers, customers, suppliers, financial institutions and
others with whom we conduct business to assess their Year 2000 program and to
inform them of our Year 2000 review. Approximately 60% have responded that they
are compliant, approximately 30% have confirmed that they are continuing to
address the Year 2000 issue and the remainder have not responded.

Based on these third party representations and results of our testing
phase, we are continuing to develop our contingency plan, such as using on-site
generators and identifying substitute suppliers. We do not believe that costs
incurred to address the Year 2000 issue will have a material effect on our
results of operations or our liquidity and financial condition. We estimate our
total cost to address the Year 2000 issue to be less than $150,000, most of
which will be spent during the testing phase. We have used and will continue to
use both internal and external resources to complete our Year 2000 program and
perform tasks necessary to address the Year 2000 problem.

S-27
<PAGE> 28

BUSINESS AND PROPERTIES

GENERAL

Swift Energy Company, a Texas corporation formed in October 1979, engages
in the development, exploration, acquisition and operation of oil and gas
properties with a primary focus on U.S. onshore gas reserves located in Texas
and Louisiana. As of December 31, 1998, we had interests in over 1,750 oil and
gas wells located in eight states. We operated 836 of these wells representing
91% of our proved reserves. At year-end 1998, we had estimated proved reserves
of 436.1 Bcfe, of which approximately 81% was gas. Our estimated proved reserves
are concentrated 84% in Texas and 13% in Louisiana.

We currently focus primarily on development and exploration in four major
fields:

The AWP Olmos Field is characterized by long-lived reserves, which means we
expect these reserves to be steadily produced over a long period of time. The
Brookeland, Giddings and Masters Creek Fields are characterized by shorter-lived
reserves with high initial rates of production that decline rapidly. We believe
these shorter-lived reserves complement our long-lived reserves in the AWP Olmos
Field. Based on 1998 year-end proved reserves and 1998 production, our average
reserve life was 11.2 years. Approximately 93% of our 1998 year-end proved
reserves and 88% of our 1998 production were concentrated in these four fields.

We purchased interests in the Brookeland and Masters Creek Fields from
Sonat Exploration Company in the third quarter of 1998 for approximately $85.6
million in cash. Of this purchase price, $55.3 million was spent for producing
properties, $15.0 million for 20% interests in two natural gas plants and $15.3
million for leasehold properties. This acquisition extended our holdings in the
Austin Chalk formation. We expect to use our operating expertise in this
geological trend to continue to successfully develop and exploit the new
acreage.

As of December 31, 1998, the Brookeland and Masters Creek Fields consisted
of 162 producing wells, 115 of which were operated by us, the production
facilities associated with these wells, 23 saltwater disposal wells and
approximately 444,000 net acres. Our 1998 production from the Brookeland and
Masters Creek Fields, which began in the third quarter of 1998, was
approximately 11.6 Bcfe and representing approximately 30% of our total 1998
production. Of this production, approximately 56% was oil. The production for
these fields during the first six months of 1999 was approximately 54% of our
total production. At year-end 1998, the Brookeland and Masters Creek Fields
contained 130.5 Bcfe of estimated proved reserves, an increase of 43% from the
91.1 Bcfe at the effective date of the acquisition. Approximately 58% of these
year-end reserves were natural gas and 59% were proved developed reserves.

In addition to our continuing production, development and exploration
activities in the AWP Olmos, Brookeland, Giddings and Masters Creek Fields, we
are currently pursuing development and exploration activities in the Gulf Coast
Basin and onshore New Zealand.

During 1997 and 1996, our growth resulted primarily from the acquisition of
additional acreage and increased drilling activities in the AWP Olmos and
Giddings Fields. Capital expenditures for development and exploration drilling,
primarily in these two fields, were $101.0 million in 1997 and $71.8 million in
1996, while capital expenditures for acquisitions were $8.4 million in 1997 and
$1.5 million in 1996. As a result of lower oil and gas prices during 1998, we
reduced capital expenditures for drilling and redirected a portion of those
expenditures to the acquisition of producing properties, primarily the
Brookeland and Masters Creek Fields. In 1998, development and exploration
drilling expenditures for the year,

S-28
<PAGE> 29

concentrated in the first half of the year, totaled $67.4 million. We spent
$59.5 million for the acquisition of producing properties in 1998, almost all in
the third quarter of 1998.

In further response to lower oil and gas prices in 1998, we budgeted
capital expenditures of $54.2 million for 1999. We allocated $36.0 million for
drilling, of which $31.3 million is for development drilling and $4.7 million is
for exploratory drilling. The remaining $18.2 million of this budget represents
the leasing, seismic survey and geological research costs of prospects. We are
funding this budget primarily through the use of internally generated cash
flows, together with limited borrowings under the credit facility.

BUSINESS STRATEGY

Development and Exploration Drilling Activities. Developmental wells are
those drilled within the presently productive area of an oil or gas reservoir.
Exploratory wells are those drilled either in search of a new oil or gas
reservoir or to greatly extend the known limits of a previously discovered
reservoir. We pursue a controlled risk approach to developmental and exploratory
drilling, focusing our activities on specific U.S. regions in which our
technical staff has considerable experience and which are located close to known
producing horizons. We seek to minimize our exploration risk by investing in
multiple prospects, farming out interests to third parties, using advanced
technologies and drilling in diverse types of geological formations. We use
basin studies to analyze targeted formations based on their potential size, risk
profile and economic characteristics.

We added 118 Bcfe of proved reserves through drilling in 1996 and 120 Bcfe
of proved reserves in 1997. In 1998, we deferred drilling projects scheduled for
the second half of the year in response to lower oil and gas prices.
Accordingly, reserves added by drilling decreased to 74 Bcfe in 1998. The 1998
additions were a result of a success rate of 87% for development wells, or 53
out of 61 drilled, and a success rate of 36% for exploratory wells, or 5 out of
14 drilled.

Our development and exploration activities are conducted by our staff of
professionals, including reservoir engineers, geologists, geophysicists,
petrophysicists, landmen and drilling and production engineers. We believe that
one of the keys to our success has been our team approach, which integrates
multiple disciplines to maximize efficient use of information leading to
drillable projects.

Strategic Acquisitions. We use a disciplined, market-driven approach to
acquisitions. Generally we seek to acquire properties with the potential for
additional reserves and production through development and exploration efforts.
In 133 transactions since 1979, we have acquired approximately $537.5 million of
producing oil and gas properties on behalf of ourselves and our co-investors. We
acquired, for our own account, approximately $181.0 million of producing
properties, with original proved reserves estimated at 279.9 Bcfe. Our producing
property acquisition expenditures in the past three years were $59.5 million in
1998, $8.4 million in 1997 and $1.5 million in 1996. Our acquisition costs have
averaged $0.52 per Mcfe over this three-year period.

Use of Advanced Technologies. We have increasingly used advanced 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. We have a number of computer workstations
from which seismic data is analyzed and enhanced with advanced software
programs, including three Landmark Systems(R) workstations. As a result, we have
developed a significant internal seismic expertise and have compiled an
extensive library of seismic data.

We began our horizontal drilling program in the Austin Chalk trend in 1992.
Our success in the Austin Chalk trend has been due to the use of recent
technological advances that facilitate the drilling of horizontal wells. These
technological advances include the development of a durable down-hole motor that
S-29
<PAGE> 30

is mounted directly behind the drill bit and down-hole
measurement-while-drilling instruments that signal the exact location of the
bit, allowing the operators to ensure that the drilled hole stays within the
targeted interval. We have also introduced underbalanced drilling and the
completion of an increasing number of dual-lateral wells. A successful
horizontal drilling program also requires a knowledge of the location of the
potential hydrocarbon traps, or natural vertical fractures, within the trend.
Our team has expertise in all the disciplines necessary for a successful
program, including years of experience in directional and horizontal drilling.

We use a variety of advanced recovery techniques, including water flooding
and acid treatments, hydraulic fracturing, fracture extension and coiled tubing.
Hydraulic fracture technique stimulates production from wells drilled in tight,
low-permeability sand, as is found in the AWP Olmos Field. The fractures provide
pathways through which oil and gas can flow into the well bore. Fracture
extension, or re-fracing, means that wells that have already been producing, for
months or years, undergo hydraulic fracturing for a second time. When wells
undergo a second fracturing process, the original fractures are extended or new
fractures are created, or both. This allows the wells to access additional
reserves and increase their production rates. As a result of the low commodity
prices of 1998, fracture extensions became a more economic approach for
increasing production. During 1998, our fracture extension program was increased
from 40 wells to 103 wells. The use of small-diameter coiled tubing velocity
strings in older wells speeds the upward flow of the natural gas and prevents
the buildup of liquids that clog the well bore. We believe that the application
of fracturing technology and coiled tubing significantly increases production
and decreases costs in the AWP Olmos Field. Through direct computer access to
the AWP Olmos Field, we monitor both fracturing operations and routine
production from our Houston headquarters. This computer telemetry increases our
efficiency.

During the first half of 1999, we introduced dendritic fracturing
techniques to the Brookeland Field. Dendritic fracturing is the pumping of large
quantities of water and small amounts of hydrochloric acid at high injection
rates down a well bore out into the formation's natural fractures, some of which
have become clogged. The objective is to clean out the fractures to improve
hydrocarbon flow into the well bore.

PRIMARY PROPERTIES

AWP Olmos Field. Our largest contiguous operation is in the AWP Olmos Field
in south Texas. As of December 31, 1998, we owned approximately 37,000 net acres
in the AWP Olmos Field. We have extensive expertise in this area and a long
history of experience with the low-permeability, tight-sand formations typical
of this field, having acquired our first acreage in this field in 1988. The
reserves in this field are over 92% gas. At year-end 1998, we owned interests in
and served as operator of 447 wells in this field producing gas from the Olmos
Sand formation at a depth of approximately 10,000 feet. We or entities we manage
own nearly 100% of the working interests in all wells in which we have an
interest in this field.

In 1998, we drilled 33 development wells in the AWP Olmos Field, 31 of
which were successful. We increased our leasehold position in the field in 1998
by obtaining additional acreage and will, if warranted, acquire more acreage in
the future. At year-end 1998, we had 140 proved undeveloped locations. Our
planned 1999 capital expenditures of $12.0 million in this area are focused on
fracture extensions and further use of coiled tubing velocity strings.

Brookeland Field. As of December 31, 1998, we owned drilling and production
rights in 223,000 gross acres, 163,000 net acres and 15,000 fee mineral acres
containing substantial proved undeveloped reserves. This field was also part of
the Sonat acquisition in 1998. The Brookeland Field is located in southeast
Texas near the border of Louisiana in Jasper and Newton counties. This area
primarily contains horizontal wells producing gas from the Austin Chalk
formation. At year-end 1998, we had 36 proved undeveloped locations. We plan to
drill seven infill development wells in 1999, with three to be operated by us
and four by Union Pacific. Our planned 1999 capital expenditures in this area
are $6.2 million.

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<PAGE> 31

Giddings Field. As of December 31, 1998, we owned drilling and production
rights in approximately 113,000 net acres in the Giddings Field. This field is
located in Washington, Colorado, Fayette and Austin counties in southeast
central Texas, known as the Quad Counties area, where we continue to selectively
acquire acreage. Since 1992, we have participated in 78 horizontal wells in the
Giddings Field with an 87% success rate. The reserves in this field are
approximately 90% gas. In 1998, we drilled 16 successful development wells out
of 19 and drilled two successful exploratory wells out of four. We plan to drill
an additional development well and one exploratory well in the second half of
1999. We attribute our success in the Giddings Field, which primarily produces
from the Austin Chalk formation, to our ability to identify hydrocarbon-bearing
fractures through our expertise in geological and geophysical analyses, and to
our ability to drill and operate horizontal wells through advanced horizontal
drilling techniques. In addition to the Austin Chalk formation, we have targeted
exploration projects in the Edwards Lime formation. At year-end 1998, we had
nine proved undeveloped locations. Our planned 1999 capital expenditures in this
field are $2.7 million.

We have established a number of joint ventures with industry partners to
further develop and explore this field, including:

Chevron USA Production Company. The joint venture encompasses a
development area of 144,000 gross acres in Fayette, Colorado and Austin
counties, with 70,000 net acres currently under lease. Swift and Chevron
each own a 50% working interest, and we serve as operator, with any
additional leased acreage to be shared and operated on the same basis. To
date, we have drilled two exploratory wells, one of which was successful.

Union Pacific Resources.

- We have a 25% working interest in a joint development area covering
approximately 17,000 gross acres in Washington County, Texas. Union
Pacific acts as operator in this venture.

- We own a 50% working interest in another joint development area also
in Washington County covering approximately 6,300 gross acres. Union
Pacific acts as operator in this venture.

- We own a 75% working interest and serve as operator for a joint
venture covering approximately 8,100 gross acres in Washington and
Austin counties.

Masters Creek Field. As of December 31, 1998, we owned drilling and
production rights in 413,000 gross acres, 281,000 net acres and 141,000 fee
mineral acres in this field containing substantial proved undeveloped reserves.
This field was part of the August 1998 Sonat acquisition. It is located near the
Texas-Louisiana border in the two parishes of Vernon and Rapides in Louisiana.
The Masters Creek Field contains horizontal wells producing both oil and gas
from the Austin Chalk formation.

In the first half of 1999, we drilled a successful development well in
which we have an 80% working interest. Because of the success of this well, we
plan to begin drilling an additional well in this field during the third quarter
of 1999. At year-end 1998, we had ten proved undeveloped locations with an
additional proved undeveloped location just west of the field. Our planned 1999
capital expenditures in this area are $7.3 million.

OTHER PROPERTIES

Gulf Coast Basin. This area includes all the Texas counties and Louisiana
parishes along the Gulf Coast extending into Mississippi and Alabama. In 1998,
we drilled three successful development wells out of six and two successful
exploratory wells out of three in this area, following one successful
development well and four successful exploratory wells drilled in 1997. In 1999,
one development well and two exploratory wells are scheduled for drilling in the
Gulf Coast Basin.

During 1997, we acquired 1,920 gross acres in Jim Hogg County, Texas, in
which we own a minimum 75% working interest. Our successful exploratory well
drilled to the Queen City formation in 1997 was

S-31
<PAGE> 32

followed by three successful development wells and a successful exploratory well
in 1998. Further work in the area is awaiting a fracture extension program to be
carried out in 1999 to assess the full potential of the area.

FOREIGN ACTIVITIES

New Zealand. Since October 1995, the New Zealand Minister of Energy has
issued Swift two petroleum exploration permits. The first permit covered
approximately 65,000 acres in the onshore Taranaki Basin of New Zealand's North
Island, and the second covered approximately 69,300 adjacent acres. In March
1998, we surrendered approximately 46,400 acres covered in the first permit, and
the remaining acreage has been included as an extension of the area covered in
the second permit, leaving us with only one expanded permit. Under the terms of
the expanded permit, we must drill one exploratory well prior to August 12,
1999, which we have commenced. We have fulfilled all other obligations under the
permit.

On October 23, 1998, we entered into separate agreements with Marabella
Enterprises Ltd., a subsidiary of Bligh Oil & Minerals N.L., an Australian
company, to obtain from Marabella a 25% working interest in another New Zealand
petroleum exploration permit and provide Marabella a 5% interest in our permit.
During the fourth quarter of 1998, Marabella drilled an unsuccessful exploration
well on its permit. Accordingly, we charged $400,000 against earnings,
representing costs of this well. We also agreed in principle to participate with
Marabella in an additional permit as a 25% working interest owner. Additionally,
Swift obtained a 7.50% working interest in another New Zealand permit from
Antrim Oil and Gas Limited, and Antrim became a 5% participant in our permit. On
this permit, an exploratory well was drilled and temporarily abandoned during
the second quarter of 1999, and we charged our $290,000 portion of the costs on
this well to earnings. As of June 30, 1999, our investment in New Zealand
totaled approximately $5.4 million. We included these costs in the unproved
properties portion of oil and gas properties. We are currently exposed to the
risk of another write down or impairment of our properties in New Zealand. SEE,
"RISK FACTORS."

Russia. Under a participation agreement with Senega, a Russian Federation
joint stock company, in which we have an indirect interest of 1%, we retain a 6%
net profits interest in the Samburg Field, located in western Siberia. Due to
the prevailing economic conditions in Russia, we impaired all of $10.8 million
of costs after tax for our properties in Russia. We currently expense any
amounts spent here as they are incurred and have no intention to make any
additional investments in this country.

Venezuela. We have entered into an agreement with Tecnoconsult, S.A., and
Corporation EDC, S.A.C.A., Venezuelan companies, to jointly formulate and submit
a proposal to Petroleos de Venezuela, S.A. for the construction and operation of
a methane pipeline. Currently, the technical and economic feasibility of the
project is under study. Due to the prevailing economic conditions in Venezuela,
we impaired all $2.8 million of costs after tax for our properties in Venezuela
during the third quarter of 1998, and are now expensing any amounts spent there.

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,
1998, 1997 and 1996 based on proved reserves reports prepared by us and audited
by H. J. Gruy and Associates, Inc., Houston, Texas, independent petroleum
engineers. Gruy based its estimates upon review of production histories and
other geological, economic, ownership and engineering data provided by us. All
calculations of estimated reserves have been made in accordance with SEC
guidelines and, except as otherwise indicated, give no effect to federal or
state income taxes otherwise attributable to estimated future cash flows from
the sale of oil and gas. The PV-10 Value is the estimated future net revenue to
be generated from the production of proved reserves, discounted to present value
using an annual discount rate of 10%. These amounts are calculated net of
estimated production costs and future development costs, using prices and costs
at the time of the estimate, without escalation and without considering
non-property related expenses, such as general and

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<PAGE> 33

administrative expenses, debt service, future income tax expense, or
depreciation, depletion and amortization. We have interests in some tracts
estimated to have additional hydrocarbon reserves that cannot be classified as
proved which are not reflected in the following table. The proved reserves
presented also exclude any reserves attributable to the volumetric production
payment.

Proved reserves are an estimate of oil and gas to be recovered in the
future. Reservoir engineering, the process used to estimate reserves, is a
subjective process involving the estimation of 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. Reserve reports of other
engineers might differ from those we have used. Results of drilling, testing and
production after these estimates may justify revisions of these estimates.
Future prices received for the sale of oil and gas may be different from those
used in preparing these estimates. The amounts and timing of future operating
and development costs may also differ from those used. Therefore, reserve
estimates often differ from the quantities of oil and gas ultimately recovered.
These estimates may not accurately predict 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. As of December 31, 1998, 17 of the 80
limited partnerships managed by us have achieved payout status.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1998 1997 1996
------------ ------------ ------------
<S> <C> <C> <C>
ESTIMATED PROVED OIL AND GAS RESERVES:
Net gas reserves (Mcf):
Proved developed................................. 197,105,963 191,108,214 135,424,880
Proved undeveloped............................... 155,294,872 123,197,455 90,333,321
------------ ------------ ------------
Total.................................... 352,400,835 314,305,669 225,758,201
============ ============ ============
Net oil reserves (Bbl):
Proved developed................................. 7,142,566 4,288,696 3,622,480
Proved undeveloped............................... 6,815,359 3,570,222 1,861,829
------------ ------------ ------------
Total.................................... 13,957,925 7,858,918 5,484,309
============ ============ ============
TOTAL PROVED OIL & AND GAS RESERVES (MCFE)......... 436,148,385 361,459,177 258,664,055
============ ============ ============
ESTIMATED PRESENT VALUE OF PROVED RESERVES:
Estimated present value of future net cash flows
from proved reserves discounted at 10%:
Proved developed................................. $243,124,194 $244,365,044 $310,408,949
Proved undeveloped............................... 97,660,811 105,979,738 160,776,008
------------ ------------ ------------
Total.................................... $340,785,005 $350,344,782 $471,184,957
============ ============ ============
PRICES USED IN CALCULATING END OF YEAR PROVED
RESERVES:
Oil (per Bbl).................................... $ 11.23 $ 15.76 $ 23.75
Gas (per Mcf).................................... 2.23 2.78 4.47
</TABLE>

Changes in crude oil and gas prices at the end of each year affect quantity
estimates and the estimated present value of proved reserves. While our total
proved reserves quantities, on an equivalent Bcfe basis, at year-end 1998
increased by 21% over reserves quantities a year earlier, the PV-10 Value of
those reserves decreased 3% from the PV-10 Value at year-end 1997. This decrease
was due almost entirely to pricing declines at year-end 1998 as compared to
year-end 1997, which more than offset the 21% Bcfe increase in reserves
quantities. Product prices for gas declined 20% during 1998 from year-end 1997,
accompanied by a 29% decrease in the price of oil between the two dates. No
other reports on our reserves have been filed with any federal agency.
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<PAGE> 34

OIL AND GAS WELLS

The following table sets forth the gross and net wells in which we owned an
interest at the following dates. This presentation excludes 36 service wells in
1998, 16 service wells in 1997 and 26 service wells in 1996.

<TABLE>
<CAPTION>
OIL WELLS GAS WELLS TOTAL WELLS
--------- --------- -----------
<S> <C> <C> <C>
December 31, 1998
Gross............................................... 657 1,060 1,717
Net................................................. 89.4 494.5 583.9
December 31, 1997
Gross............................................... 625 926 1,551
Net................................................. 48.1 381.7 429.8
December 31, 1996
Gross............................................... 734 1,068 1,802
Net................................................. 59.5 222.9 282.4
</TABLE>

OIL AND GAS ACREAGE

The following table sets forth the developed and undeveloped domestic
leasehold acreage held by us at December 31, 1998. Fee minerals acquired in the
Sonat acquisition are not included in the following leasehold acreage table. In
that acquisition, we acquired 23,179 developed fee mineral acres and 114,034
undeveloped fee mineral acres for a total of 137,213 fee mineral acres.

<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
----------------- -----------------
GROSS NET GROSS NET
------- ------- ------- -------
<S> <C> <C> <C> <C>
Alabama........................................ 4,495 617 292 73
Arkansas....................................... 3,339 1,736 8,093 5,023
Kansas......................................... -- -- 4,600 1,989
Louisiana...................................... 100,234 50,356 159,556 101,110
Mississippi.................................... 4,186 2,241 3,694 911
Montana........................................ -- -- 4,411 4,411
Oklahoma....................................... 33,241 14,197 3,209 887
Texas.......................................... 260,232 146,577 301,336 161,354
Wyoming........................................ 4,714 1,969 120,253 104,579
All other states............................... -- -- 6,317 1,286
------- ------- ------- -------
Total................................ 410,441 217,693 611,761 381,623
======= ======= ======= =======
</TABLE>

DRILLING ACTIVITIES

The following table sets forth the results of our drilling activities
during each of the three years ended December 31, 1998:

<TABLE>
<CAPTION>
GROSS WELLS NET WELLS
----------------------- -----------------------
YEAR TYPE OF WELL TOTAL PRODUCING DRY TOTAL PRODUCING DRY
- ---- ------------ ----- --------- --- ----- --------- ---
<S> <C> <C> <C> <C> <C> <C> <C>
1998 Exploratory...................... 14 5 9 8.7 2.7 6.0
Development...................... 61 53 8 37.7 32.8 4.9
1997 Exploratory...................... 15 7 8 7.2 2.7 4.5
Development...................... 167 159 8 127.5 123.6 3.9
1996 Exploratory...................... 11 7 4 5.9 3.7 2.2
Development...................... 142 134 8 110.5 106.7 3.8
</TABLE>

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<PAGE> 35

REPLACEMENT OF RESERVES AND PRODUCTION

We increased our proved reserves from 90.1 Bcfe at year-end 1993 to 436.1
Bcfe at year-end 1998, resulting in the replacement of 449% of production during
this period. Due to our geographic concentration and increased production, our
general and administrative expenses decreased from $0.35 per Mcfe in 1994 to
$0.10 per Mcfe in 1998. Production costs decreased from $0.39 per Mcfe in 1994
to $0.34 per Mcfe in 1998. As a result of increased production and decreased
operating costs per Mcfe, net cash provided by operating activities grew at an
annual compounded growth rate of 50% for the five-year period ended December 31,
1998.

In 1998, we increased our proved reserves by 21%, resulting in the
replacement of 296% of 1998 production. Over the five-year period ended December
31, 1998, our average replacement cost was $0.88 per Mcfe. As a result of both
acquisition and drilling activity, 1998 production increased 54% over 1997
production.

OPERATIONS

We generally seek to be the operator for wells in which we have a
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 oilfield 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 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 1998 ranged from $200 to $1,632 per well per month and totaled
approximately $5.5 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 by us or other operators
and delivered to a central point. Gas production is primarily sold in the spot
market on a monthly contract basis, while we sell our oil production at
prevailing market prices at the time of sale. We do not refine any oil we
produce. For the year ended December 31, 1998, two purchasers accounted for
approximately 16% and 10% 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.

We have entered into gas processing and gas transportation agreements for
our gas production in the AWP Olmos Field with Pacific Gas & Electric
Corporation and in the Giddings Field with Aquila Southwest Pipeline
Corporation. We believe that these contracts adequately provide for our gas
purchase and processing needs. The prices we receive are redetermined monthly to
reflect the current gas price.

We sell our oil production from the Brookeland and Masters Creek Fields to
purchasers at prevailing market prices. Our gas production from the Brookeland
and Masters Creek Fields is processed under long-term gas processing contracts
with Duke Energy Field Services, Inc., utilizing the gas processing plants in
which we own a 20% interest.

The following table summarizes sales volumes, sales prices and production
cost information for our net oil and gas production for the first half of 1999
and the years ended December 31, 1998, 1997 and

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<PAGE> 36

1996. Net production includes production owned by Swift, either directly or
indirectly, and produced to our interest after deducting royalty and other
interests.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
SIX MONTHS ENDED ---------------------------------------
JUNE 30, 1999 1998 1997 1996
---------------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
NET SALES VOLUME:
Oil (Bbls).................. 1,372,133 1,800,676 672,385 623,386
Gas (Mcf)................... 13,912,504 28,225,974 21,359,434 15,696,798
Total Production (Mcfe)..... 22,145,302 39,030,030 25,393,744 19,437,114
WEIGHTED AVERAGE SALES PRICES:
Oil (per Bbl)............... $ 12.93 $ 11.86 $ 17.59 $ 19.82
Gas (per Mcf)............... $ 1.94 $ 2.08 $ 2.68 $ 2.57
PRODUCTION COST (PER MCFE):... $ 0.39 $ 0.34 $ 0.35 $ 0.32
</TABLE>

Gas production includes 384,438 Mcf for the six months ended June 30, 1999,
866,232 Mcf for 1998, 1,015,226 Mcf for 1997 and 1,156,361 Mcf for 1996,
delivered under a volumetric production payment agreement pursuant to which we
are obligated to deliver certain monthly quantities of gas until October 2000.
SEE, NOTE 1 TO THE CONSOLIDATED FINANCIAL STATEMENTS.

PRICE RISK MANAGEMENT

Market prices of oil and gas fluctuate and can adversely affect our
operating results. To mitigate some of this risk, we engage periodically in
limited hedging activities, but only to the extent of buying price floors for
portions of our oil and gas production and that of the limited partnerships we
manage. Costs and benefits derived from these price floors are accordingly
recorded as a reduction or increase, as appropriate, in oil and gas sales
revenue and have not been significant in any recent years. We amortize the costs
to purchase these floors over the option period.

During 1998, we entered into various gas price floor contracts throughout
the year that covered between 500,000 and 3,000,000 MMBtu of gas at prices from
$1.80 to $2.10. For the months of January and February 1998, 60,000 Bbls of oil
production were covered each month, providing for a minimum price of $18.00 per
Bbl. Costs related to 1998 price floor activities totaled approximately
$377,000, with benefits of approximately $101,000 being received, resulting in a
cost of approximately $276,000 or $0.007 per Mcfe.

During the first six months of 1999, we have entered into various price
floor contracts that ranged from $1.60 to $2.00 for gas on volumes from
1,000,000 to 2,800,000 MMBtu, and $12.00 to $16.00 per Bbl for oil on volumes
from 100,000 to 300,000 Bbl. The costs related to 1999 hedging activities
through June 30, 1999 totaled approximately $591,600, with benefits of
approximately $348,400 having been received, resulting in a net cash outflow of
approximately $243,200. The costs related to open contracts as of June 30, 1999
totaled approximately $194,000 and had a fair market value of $10,000.

PARTNERSHIPS

For many years, we relied on limited partnerships as our principal vehicle
to fund our operations. We have formed 109 limited partnerships which raised a
total of approximately $509.5 million.

From 1984 to 1995, we formed limited partnerships and joint ventures for
the purpose of acquiring interests in producing oil and gas properties. During
1996 and 1997, the limited partners in 37 partnerships, which had been in
operation for between six and seventeen years and had produced a substantial
majority of their reserves, voted to sell their remaining properties and
liquidate the limited partnerships. Of these partnerships, 10 were the earliest
public income partnerships formed in 1984 through 1986, eight were private
drilling partnerships formed from 1979 to 1985, and 11 were income partnerships,
formed in 1990 and 1991.

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<PAGE> 37

Between 1993 and 1998, we offered private partnerships formed to engage in
drilling for oil and gas reserves. We serve as the managing general partner of
these entities. As of December 31, 1998, thirteen private drilling partnerships
had been formed, with investor contributions totaling approximately $66.1
million.

In October 1998, we notified investors in 63 Swift-managed production
partnerships formed between 1986 and 1994 that we had delayed calling investor
meetings to consider the purchase by us of all of the oil and gas properties
owned by these partnerships, which was proposed in March 1998. This decision
principally reflected significant market changes that had occurred and the aging
of the third-party appraisals of these partnership properties during the
regulatory review period. In the second half of 1998, low oil and gas prices
created concern over the propriety of partnerships selling the properties at
that time. Currently, we are re-evaluating the status and operation of these
partnerships and whether to propose some form of liquidating transactions. No
partnerships have been formed or offered in 1999.

LITIGATION

In 1997, Swift and the Lower Colorado River Authority filed claims against
each other in the District Court of Fayette County, Texas. Swift originally sued
to force the River Authority to assign to Swift leases which the River Authority
had refused to assign, and seeking declaration as to the parties' interests in
the properties involved. The River Authority counterclaimed alleging fraud,
conversion and conspiracy to convert oil and gas. The parties tentatively agreed
to settle this litigation during a mediation held in late May 1999. The
settlement has not been finalized, is subject to negotiation and requisite
approvals of a definitive agreement, and may not be consummated. Swift does not
believe that the ultimate resolution of this case will have a material adverse
impact upon its financial condition or results of operations. SEE, "RISK
FACTORS."

EMPLOYEES

At June 30, 1999, we employed 167 persons. None of our employees are
represented by a union. Relations with employees are considered to be good.

FACILITIES

We occupy approximately 75,000 square feet of office space at 16825
Northchase Drive, Houston, Texas, under a ten year lease expiring in 2005. The
lease requires payments of approximately $95,000 per month. We have field
offices in various locations from which our employees supervise local oil and
gas operations.

S-37
<PAGE> 38

MANAGEMENT

The following table sets forth information about our directors, executive
officers and other officers as of June 30, 1999.

<TABLE>
<CAPTION>
NAME AGE POSITION
- ---- --- --------
<S> <C> <C>
A. Earl Swift........................ 65 Chief Executive Officer and Chairman of the
Board
Terry E. Swift....................... 43 President and Chief Operating Officer
Virgil N. Swift...................... 70 Vice Chairman of the Board and Executive Vice
President -- Business Development
John R. Alden........................ 53 Senior Vice President -- Finance, Chief
Financial Officer and Secretary
Bruce H. Vincent..................... 51 Senior Vice President -- Funds Management
James M. Kitterman................... 55 Senior Vice President -- Operations
Joseph A. D'Amico.................... 51 Senior Vice President -- Exploration and
Development
Alton D. Heckaman, Jr. .............. 42 Vice President and Controller
G. Robert Evans...................... 68 Director
Raymond O. Loen...................... 75 Director
Henry C. Montgomery.................. 63 Director
Clyde W. Smith, Jr. ................. 50 Director
Harold J. Withrow.................... 71 Director
</TABLE>

A. Earl Swift is Chief Executive Officer and Chairman of the Board of
Directors of Swift and has served in such capacities since its founding in 1979.
Mr. Swift has indicated a desire to retire as Chief Executive Officer during the
fourth quarter of 1999. He intends to continue as Chairman of the Board. He
previously served as President from 1979 to November 1997. For the 17 years
prior to 1979, he was employed by affiliates of American Natural Resources
Company. Mr. Swift is a registered professional engineer and holds a degree in
Petroleum Engineering, a degree of Doctor of Jurisprudence and a Master's degree
in Business Administration. He is the father of Terry E. Swift and the brother
of Virgil N. Swift.

Terry E. Swift was appointed President of Swift in November 1997. He served
as Executive Vice President and Chief Operating Officer of Swift from 1991 to
1997, as Senior Vice President -- Exploration and Joint Ventures from 1990 to
1991 and as Vice President -- Exploration and Joint Ventures from 1988 to 1990.
Mr. Swift is a registered professional engineer and holds a degree in Chemical
Engineering and a Master's degree in Business Administration.

Virgil N. Swift has been a director of Swift since 1981 and has acted as
Vice Chairman of the Board and Executive Vice President -- Business Development
since November 1991. He previously served as Executive Vice President and Chief
Operating Officer from 1982 to November 1991. Mr. Swift joined Swift in 1981 as
Vice President -- Drilling and Production. For the preceding 28 years, he held
various production, drilling and engineering positions with Gulf Oil Corporation
and its subsidiaries, last serving as General Manager -- Drilling for Gulf
Canada Resources, Inc. Mr. Swift is a registered professional engineer and holds
a degree in Petroleum Engineering.

John R. Alden was appointed Senior Vice President -- Finance, Chief
Financial Officer and Secretary in 1990. Mr. Alden joined Swift in 1981. Prior
to 1990, he served Swift as its principal financial officer under a variety of
titles. Mr. Alden holds a degree in Accounting and a Master's degree in Business
Administration.

Bruce H. Vincent joined Swift as Senior Vice President -- Funds Management
in 1990. Mr. Vincent acted as Chief Operating Officer of Energy Assets
International Corp. from 1986 to 1988 and as President of Vincent & Company, an
investment banking firm, from 1988 to 1990. Mr. Vincent holds a degree in
Business Administration and a Master's degree in Finance.

James M. Kitterman was appointed Senior Vice President -- Operations in May
1993. He had previously served as Vice President -- Operations since joining
Swift in 1983 with 16 years of prior

S-38
<PAGE> 39

experience in oil and gas exploration, drilling and production. Mr. Kitterman
holds a degree in Petroleum Engineering and a Master's degree in Business
Administration.

Joseph A. D'Amico was appointed Senior Vice President -- Exploration and
Development of Swift in February 1998. He served as Swift's Vice President of
Exploration and Development from 1993 to 1998, Director of Exploration and
Development from 1992 to 1993 and Funds Manager from 1988 to 1992. He served in
the funds management division and as Director of Exploration and Development of
Swift from 1988 to 1993. Mr. D'Amico holds a Bachelor of Science and Master of
Science in Petroleum Engineering and a Master's degree in Business
Administration.

Alton D. Heckaman, Jr. was appointed Vice President and Controller in May
1993. He had previously served as Assistant Vice President -- Finance and
Controller since 1986. Mr. Heckaman joined Swift in 1982. He is a Certified
Public Accountant and holds a degree in Accounting.

G. Robert Evans has served as a director of Swift since 1994. Effective
January 1, 1998, Mr. Evans retired as Chairman of Material Sciences Corporation,
having held that position since 1991. Material Sciences Corporation develops and
commercializes continuously processed, coated materials technologies. He remains
a director of Material Sciences Corporation. He is also currently serving as a
director of Consolidated Freightways, Inc. (transportation). From 1990 until
1991, he served as President, Chief Executive Officer and a Director of
Corporate Finance Associates of Illinois, Inc., a financial intermediary and
consulting firm. From 1987 until 1990, he served as President, Chief Executive
Officer and a Director of Bemrose Group USA, a British holding company engaged
in value-added manufacturing and sale of products to the advertising specialty
industry.

Raymond O. Loen has served as a director of Swift since its founding in
1979. Since 1963, he has been President of R. O. Loen Company, a privately held
management consulting firm headquartered in Lake Oswego, Oregon.

Henry C. Montgomery has served as a director of Swift since 1987. Mr.
Montgomery served as Executive Vice President of SyQuest Technology, Inc., a
public company engaged in the development, manufacture and sale of computer hard
drives from November 1996 through July 1997. He served as President and Chief
Executive Officer of New Media Corporation, a privately held company engaged in
developing, manufacturing and selling PCMCIA cards for the computer industry,
from March 1995 through November 1996. Since 1980, Mr. Montgomery has been the
Chairman of the Board of Montgomery Financial Services Corporation, a management
consulting and financial services firm. Mr. Montgomery also previously served as
director of Catalyst Semiconductor, Inc., a public company engaged in the design
and manufacture of semiconductors (1990 to 1995), and Southwall Technologies,
Inc., a public company engaged in thin film deposition technologies (1982 to
1995).

Clyde W. Smith, Jr. has served as a director of Swift since 1984. He has
served as President of Somerset Properties, Inc., a real estate and investment
company, from 1985 to 1996, as President of AdVision, Inc., which markets video
display merchandising systems, since 1988, as President of H&R Precision, Inc.,
a general contractor, from 1994 to 1997, and President of Millennium Technology
Services, Inc., a White City, Oregon based electronics manufacturer, since
August 1997. On May 5, 1997, Mr. Smith filed a petition under Chapter 7 of the
U.S. Bankruptcy Code.

Harold J. Withrow has served as a director of Swift 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-39
<PAGE> 40

PRINCIPAL SHAREHOLDERS

DIRECTORS AND OFFICERS

The following table sets forth information concerning the shareholdings, as
of June 30, 1999, of the seven current members of the board of directors, each
of Swift's five most highly compensated executive officers and all executive
officers and directors as a group:

<TABLE>
<CAPTION>
SHARES OF COMMON STOCK
BENEFICIALLY OWNED AT
JUNE 30, 1999(1)
---------------------------
PERCENT OF
CLASS
NAME OF PERSON OR GROUP POSITION POSITION NUMBER OUTSTANDING
- -------------------------------- -------- --------- -----------
<S> <C> <C> <C>
A. Earl Swift................... Chairman of the Board, Chief 333,970(2) 2.0%
Executive Officer
Virgil N. Swift................. Vice Chairman of the Board, 350,119(2)(3) 2.2%
Executive Vice
President -- Business
Development
G. Robert Evans................. Director 23,000 (4)
Raymond O. Loen................. Director 157,481(5) (4)
Henry C. Montgomery............. Director 53,866 (4)
Clyde W. Smith, Jr. ............ Director 24,210 (4)
Harold J. Withrow............... Director 35,206 (4)
Terry E. Swift.................. President, Chief Operating 140,704(2) (4)
Officer
John R. Alden................... Senior Vice 122,527(2)(6) (4)
President -- Finance, Chief
Financial Officer, Secretary
James M. Kitterman.............. Senior Vice 110,209(2) (4)
President -- Operations
</TABLE>

<TABLE>
<S> <C> <C> <C>
All executive officers and
directors as a group (13
persons)...................... 1,540,335 8.8%
</TABLE>

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

(1) Unless otherwise indicated in the footnotes below, the percent outstanding
are as of June 30, 1999. Unless otherwise indicated below, the persons named
have sole voting and investment power over the number of shares of Swift's
common stock shown as being owned by them. The table includes the following
shares that were acquirable within 60 days following June 30, 1999 by
exercise of options granted under Swift's stock option plans:

- Mr. A. E. Swift -- 69,938;

- Mr. V. N. Swift -- 58,124;

- Mr. Evans -- 18,600;

- Mr. Loen -- 35,100;

- Mr. Montgomery -- 13,067;

- Mr. Smith -- 24,210;

- Mr. Withrow -- 30,260;

- Mr. T. E. Swift -- 108,900;

- Mr. Alden -- 90,985;

- Mr. Kitterman -- 90,750; and

- All executive officers and directors as a group -- 688,946.

(2) Includes approximately 317 shares held by individual's (each of the five
named executive officers) ESOP account over which individual possesses
voting, but not investment, control.

(3) Includes 121 shares held jointly by Mr. Virgil N. Swift and his wife.

(4) Less than one percent.

(5) Includes 77,000 shares held by Mr. Loen's wife (who holds sole voting and
investment power as to those shares), 4,047 shares held in her IRA, and
2,809 shares held in Mr. Loen's IRA.

(6) Includes 220 shares in an IRA held by Mr. Alden's wife (who holds sole
voting and investment power as to those shares).

S-40
<PAGE> 41

HOLDERS OF MORE THAN 5% OF OUR STOCK

The following table sets forth information concerning the shareholdings, as
reported in their most recent public filings on Schedule 13G, of each person who
beneficially owned more than five percent of our outstanding common stock:

<TABLE>
<CAPTION>
SHARES OF COMMON STOCK
BENEFICIALLY OWNED AT
DECEMBER 31, 1998(1)
--------------------------------
PERCENT OF
NAME NUMBER CLASS OUTSTANDING
---- --------- -----------------
<S> <C> <C>
American Century Investment Management, Inc. .......... 1,353,318(2) 8.2%
4500 Main Street
P. O. Box 418210
Kansas City, MO 64141-9210
American Century Capital Portfolios, Inc. ............. 1,173,701(2) 7.1%
4500 Main Street
P. O. Box 418210
Kansas City, MO 64141-9210
The Equitable Companies, Incorporated.................. 1,085,391(3) 6.7%
Alliance Capital Management, L.P.
Donaldson, Lufkin & Jenrette Securities Corporation
1290 Avenue of the Americas
New York, New York 10104
FMR Corp............................................... 1,653,400(4) 10.1%
Fidelity Management and Research Company
Edward C. Johnson 3d
Abigail P. Johnson
82 Devonshire Street
Boston, Massachusetts 02109
Franklin Resources, Inc. .............................. 1,820,858(5) 10.1%
Franklin Advisers, Inc.
Charles B. Johnson
Rupert H. Johnson, Jr.
777 Mariners Island Blvd
San Mateo, California 94404
Goldman Sachs & Co..................................... 1,022,300(6) 6.3%
The Goldman Sachs Group, L.P.
85 Broad Street
New York, NY 10004
Neuberger Berman, LLC.................................. 850,080(7) 5.2%
Neuberger Berman Management Inc.
605 Third Avenue
New York, NY 10158-3698
Scudder Kemper Investments, Inc. ...................... 1,061,930(8) 6.5%
345 Park Avenue
New York, NY 10154
</TABLE>

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

(1) The percent of class outstanding are as of December 31, 1998.

(2) Based on a Schedule 13G dated February 10, 1999, American Century Investment
Management, Inc. "ACIM," as a registered investment adviser, manages 13
registered investment companies pursuant to management agreements and is
therefore deemed to be the beneficial owner, and possesses sole voting and
disposition power, of 1,353,318 shares of Swift's common stock. In addition,
American Century Capital Portfolios, Inc. "ACCP," one

S-41
<PAGE> 42

of the 13 registered investment companies managed by ACIM, is deemed to be
the beneficial owner of 1,173,701 of the shares of common stock beneficially
owned by ACIM. ACIM, as manager, holds all such stock for ACCP and the other
12 investment companies in institutional investor accounts which ACIM
manages.

(3) Based on a Schedule 13G dated February 10, 1999, Alliance Capital
Management, L.P., "Alliance," a subsidiary of the Equitable Companies,
Incorporated, "Equitable" and an investment advisor registered under Section
203 of the Investment Advisers Act of 1940, is deemed to beneficially own
1,083,600 shares of Swift's common stock. The Schedule 13G also states that
these shares were acquired by Alliance solely for investment purposes on
behalf of client discretionary investment advisory accounts. Of these
shares, Alliance is deemed to have:

- sole power to vote or direct the vote of 897,000 shares;

- shared power to vote or direct the vote of 180,800 shares; and

- sole power to dispose or direct the disposition of all 1,083,600 shares.

Donaldson, Lufkin, Jenrette Securities Corporation, "DLJ," a broker-dealer
registered under Section 15 of the Securities Exchange Act of 1934, an
investment advisor registered under Section 203 of the Investment Advisers
Act of 1940, and a subsidiary of Equitable, holds 1,791 shares for
investment purposes. The Schedule 13G also states that DLJ is deemed to have
shared power to dispose or direct the disposition of these shares. Each
subsidiary of Equitable operates under independent management and makes
independent voting and investment decisions. Also according to this Schedule
13G, the parent companies of Equitable, AXA and the Mutuelles AXA group of
companies, disclaim all beneficial ownership of these shares.

(4) Based on a Schedule 13G dated February 1, 1999, FMR Corp., as a parent
holding company, in accordance with Section 240 of the Investment Advisers
Act of 1940, is deemed to be the beneficial owner, with sole power to
dispose and direct the disposition of 1,653,400 shares of Swift's common
stock. In addition, Fidelity Management and Research Company, "Fidelity", a
wholly owned subsidiary of FMR Corp. and an investment adviser registered
under Section 203 of the Investment Advisers Act of 1940, is deemed the
beneficial owner of 1,652,300 of the shares beneficially owned by FMR Corp.
as a result of acting as investment adviser to various investment companies.
One such investment company, Fidelity Low-Priced Stock Fund, is deemed
beneficial owner of 1,644,700 of the shares beneficially owned by FMR Corp.
Members of the Edward C. Johnson 3d family and trusts for their benefit are
the predominant owners of Class B shares of common stock of FMR Corp.,
representing approximately 49% of the voting power of FMR Corp. Of these,
12% are owned by Mr. Johnson 3d and 24.5% are owned by Abigail Johnson. The
Johnson family group and all other Class B shareholders have entered into a
shareholders voting agreement under which all Class B shares will be voted
in accordance with the majority vote of the Class B shares. Accordingly,
through their ownership of voting common stock and the execution of the
shareholders voting agreement, members of the Johnson family may be deemed
under the Investment Company Act of 1940, to control a controlling group
with respect to FMR Corp. Neither FMR Corp. nor the Edward C. Johnson 3d
family has any power to vote or direct the voting of the shares owned
directly by the investment companies.

(5) Based on a Schedule 13G dated January 8, 1999, Franklin Advisers Inc.,
"Advisers," a wholly owned subsidiary of Franklin Resources, Inc., "FRI,"
and an investment adviser registered under Section 203 of the Investment
Advisers Act of 1940, is deemed to be the beneficial owner of 1,820,858
shares of Swift's common stock as a result of Advisers acting as an
investment adviser to one or more open or closed-end investment companies or
other managed accounts. As the parent holding company of Advisers, FRI is
also deemed beneficial owner of these shares. All of these shares of Swift's
common stock are shares acquirable upon conversion of $57,750,000 principal
amount of convertible subordinated notes due 2006. The advisory contracts
grant all investment and/or voting power over the securities to Advisers. In
addition, Charles B. Johnson and Rupert H. Johnson, Jr., each owning in
excess of 10% of the outstanding common stock of FRI, are considered control
persons of FRI and thus are also deemed beneficial owners of the 1,820,858
shares.

(6) Based on a Schedule 13G dated February 14, 1999, the Goldman Sachs Group,
L.P., "GS Group," the parent holding company of Goldman, Sachs and Company,
"GS," a broker-dealer registered under Section 15 of the Securities Exchange
Act of 1934 and an investment adviser registered under Section 203 of the
Investment Advisers Act of 1940, are each deemed to be the beneficial owner
of 1,022,300 shares of Swift's common stock as a result of client accounts
managed by GS Group and GS for investment purposes. Although GS Group and GS
share voting power and dispositive power with respect to these securities,
both GS Group and GS disclaim beneficial ownership of such securities.

(7) Based on a Schedule 13G dated February 5, 1999, Neuberger Berman, LLC,
"Neuberger," and Neuberger Berman Management Inc., "Management," serve as
sub-advisers and investment managers of various mutual funds and are thus
deemed beneficial owners of 850,080 shares of Swift's common stock, which
shares they hold

S-42
<PAGE> 43

for their clients. Of the shares beneficially owned, both Neuberger and
Management share dispositive power as to all 850,080 shares and share voting
power as to 661,990 shares of Swift's common stock. Neuberger possesses sole
voting power as to the remaining 188,090 shares.

(8) Based on a Schedule 13G dated February 12, 1999, Scudder Kemper Investments,
Inc., an investment adviser registered under Section 203 of the Investment
Advisers Act of 1990, is deemed beneficial owner of 1,061,930 shares of
Swift's common stock as a result of serving as an investment adviser to one
or more investment companies or other managed accounts. Scudder has the sole
power to dispose of and direct the disposition of all 1,061,930 shares and
has sole voting power as to 700,830 of such shares of Swift's common stock.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

In the ordinary course of our business, we acquire interests in
developmental and exploratory oil and gas prospects, and sell portions to
unaffiliated third parties for purposes of diversification. For the past several
years, we have offered interests in certain of these prospects to our executive
officers and other employees. These prospect interests are sold to employees on
terms identical to those at which interests are sold to third party investors in
that prospect. As a result of enhanced drilling activity, the amounts invested
by executive officers in such prospects in 1997 and through mid-1998 increased
significantly over previous years. During 1998, 1997 and 1996, leasehold and
drilling costs incurred by executive officers who invested in these properties
in excess of $60,000 were: A. Earl Swift -- none, $322,261, and $135,957; Terry
E. Swift -- $71,746, $207,426, and $106,621; Virgil N. Swift -- $335,114,
$390,784, and $259,379; John R. Alden -- $183,233, $246,270, and $95,080; Bruce
H. Vincent -- $75,258, $220,458 and none; and only in 1997 for James M.
Kitterman -- $133,068. Some executive officers deferred paying cash for their
investments in such properties, instead assigning the proceeds of production
which over time repay amounts owed, rounded to the nearest $1,000, resulting in
their owing money to Swift from time to time. Prior to 1997, the indebtedness of
any one officer never exceeded $60,000. In late 1997, due to increased levels of
drilling activity, the balances owed to Swift increased, with the greatest
amounts owed Swift in excess of $60,000 occurring in mid-1998 as follows: Virgil
N. Swift -- $174,000; John R. Alden -- $130,000; Bruce H. Vincent -- $124,000;
and James M. Kitterman -- $62,000. At June 30, 1999, no executive officer owed
Swift an amount in excess of $60,000. Individual executive officers are charged
interest on the amount owed Swift at its incremental borrowing rate.

We operate a substantial number of properties owned by our affiliated
limited partnerships and joint ventures for which we charge operating fees. We
are also reimbursed for direct, administrative, and overhead costs incurred in
conducting the business of the limited partnerships, which totaled approximately
$5.0 million in 1998, $6.3 million in 1997, and $6.1 million in 1996. We were
also reimbursed by the limited partnerships and joint ventures for costs
incurred in the screening, evaluation and acquisition of producing oil and gas
properties on their behalf. These costs totaled approximately $490,000 in 1997
and $250,000 in 1996. We have fulfilled our responsibility of acquiring
properties for such partnerships, as those partnerships are fully invested in
properties. In partnerships whose limited partners voted to sell remaining
properties and liquidate their limited partnerships, the partnerships reimbursed
us for direct, administrative and overhead costs in disposing of these
properties totaling approximately $0.6 million in 1998, $0.7 million in 1997 and
$0.8 million in 1996. In the ordinary course of the affiliated partnerships'
business, they have also purchased properties from Swift.

Our Employee Stock Ownership Plan, the "ESOP," can borrow money from us to
buy stock for the purpose of distribution to our employees. In September 1996,
the ESOP borrowed money from Swift to purchase 25,000 shares of common stock
from our chairman for $568,750. This debt was repaid in April 1999.

S-43
<PAGE> 44

UNDERWRITING

Subject to the terms and conditions stated in the underwriting agreement
dated the date of this prospectus supplement, each underwriter named below has
severally agreed to purchase, and we have agreed to sell to such underwriter,
the number of shares set forth opposite the name of such underwriter.

<TABLE>
<CAPTION>
NUMBER
NAME OF SHARES
- ---- ---------
<S> <C>
Salomon Smith Barney Inc....................................
CIBC World Markets Corp.....................................
Credit Suisse First Boston Corporation......................
Dain Rauscher Wessels, a division of Dain Rauscher
Incorporated..............................................
Jefferies & Company, Inc....................................

---------
Total............................................. 4,000,000
=========
</TABLE>

The underwriting agreement provides that the obligations of the several
underwriters to purchase the shares included in this offering are subject to
approval of certain legal matters by counsel and to certain other conditions.
The underwriters are obligated to purchase all the shares, other than those
covered by the over-allotment option described below, if they purchase any of
the shares.

The underwriters, for whom Salomon Smith Barney Inc., CIBC World Markets
Corp., Credit Suisse First Boston Corporation, Dain Rauscher Wessels, a division
of Dain Rauscher Incorporated, and Jefferies & Company, Inc. are acting as
representatives, propose to offer some of the shares directly to the public at
the public offering price set forth on the cover page of this prospectus
supplement and some of the shares to certain dealers at the public offering
price less a concession not in excess of $ per share. The underwriters may
allow, and such dealers may reallow, a concession not in excess of $ per
share on sales to certain other dealers. If all of the shares are not sold at
the initial offering price, the representatives may change the public offering
price and the other selling terms.

We have granted to the underwriters an option, exercisable for 30 days from
the date of this prospectus supplement, to purchase up to 600,000 additional
shares of our common stock at the public offering price less the underwriting
discount. The underwriters may exercise such option solely for the purpose of
covering over-allotments, if any, in connection with this offering. To the
extent such option is exercised, each underwriter will be obligated, subject to
certain conditions, to purchase a number of additional shares approximately
proportionate to such underwriter's initial purchase commitment.

We, for a period of 180 days, and our officers and directors, for a period
of 90 days, have agreed that from the date of this prospectus supplement, we and
they will not, without the prior written consent of Salomon Smith Barney Inc.,
dispose of or hedge any shares of our common stock or any securities convertible
into or exercisable or exchangeable for common stock. Salomon Smith Barney Inc.,
in its sole discretion, may release any of the securities subject to these
lock-up agreements at any time without notice.

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

The following table shows the underwriting discounts and commissions to be
paid to the underwriters by us in connection with this offering. These amounts
are shown assuming both no exercise and full exercise of the underwriters'
over-allotment option to purchase additional shares of our common stock.

<TABLE>
<CAPTION>
PAID BY SWIFT
---------------------------
NO EXERCISE FULL EXERCISE
----------- -------------
<S> <C> <C>
Per share................................................... $ $
Total....................................................... $ $
</TABLE>

S-44
<PAGE> 45

In connection with this offering, Salomon Smith Barney Inc., on behalf of
the underwriters, may purchase and sell shares of common stock in the open
market. These transactions may include over-allotment, syndicate covering
transactions and stabilizing transactions. Over-allotment involves syndicate
sales of common stock in excess of the number of shares to be purchased by the
underwriters in this offering, which creates a syndicate short position.
Syndicate covering transactions involve purchases of the common stock in the
open market after the distribution has been completed in order to cover
syndicate short positions. Stabilizing transactions consist of certain bids or
purchases of common stock made for the purpose of preventing or retarding a
decline in the market price of our common stock while the offering is in
progress.

The underwriters may also impose a penalty bid. Penalty bids permit the
underwriters to reclaim a selling concession from a syndicate member when
Salomon Smith Barney Inc., in covering syndicate short positions or market
stabilizing purchases, repurchases shares originally sold by that syndicate
member.

Any of these activities may cause the price of our common stock to be
higher than the price that would otherwise exist in the open market in the
absence of such transactions. These transactions may be effected on the New York
Stock Exchange or in the over-the-counter market, or otherwise and, if
commenced, may be discontinued at any time.

We estimate that our total expenses for this offering and the concurrent
notes offering will be $900,000.

The representatives have performed certain investment banking and advisory
services for us from time to time for which they have received customary fees
and expenses. The representatives may, from time to time, engage in transactions
with and perform services for us in the ordinary course of their business.
Salomon Smith Barney Inc., CIBC World Markets Corp. and Credit Suisse First
Boston Corporation are also acting as representatives for the underwriters in
the concurrent notes offering.

Certain of the underwriters or their affiliates are lenders under our
credit facility, which is expected to be repaid with the net proceeds from this
offering and the concurrent notes offering.

Under Rule 2710(c)(8) of the Conduct Rules of the NASD, special
considerations apply to a public offering of an issuer's securities where more
than ten percent of the net proceeds thereof will be paid to members of the NASD
that are participating in the offering, or persons affiliated or associated with
such members. Certain of the underwriters or their respective affiliates have
loaned money to us under an existing credit facility. In the event more than ten
percent of the proceeds of this offering will be used to repay such money loaned
by any underwriter or its affiliates, the offering will be conducted in
conformity with Rule 2710(c)(8).

We have agreed to indemnify the underwriters against certain liabilities,
including liabilities under the Securities Act of 1933, or to contribute to
payments the underwriters may be required to make in respect of any of those
liabilities.

LEGAL OPINIONS

Jenkens & Gilchrist, A Professional Corporation, Houston, Texas, will issue
an opinion for Swift regarding the legality of the common stock offered by this
prospectus supplement and accompanying prospectus. Certain legal matters will be
passed upon for the underwriters by Cravath, Swaine & Moore, New York, New York.

S-45
<PAGE> 46

EXPERTS

The audited financial statements included in this prospectus supplement to
the extent and for the periods indicated in their report have been audited by
Arthur Andersen LLP, independent public accountants, and is included herein in
reliance upon the authority of such firm as experts in giving said report.

Information included or incorporated by reference in this prospectus
supplement and the accompanying 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 & Associates, Inc., independent petroleum engineers.

S-46
<PAGE> 47

GLOSSARY OF TERMS

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

Bbl -- Barrel or barrels of oil.

Bcf -- Billion cubic feet of gas.

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

Development Well -- A well drilled within the presently proved productive
area of an oil or gas reservoir, as indicated by reasonable interpretation of
available data, with the objective of completing that reservoir.

Dry Well -- An exploratory or development well that is not a producing
well.

Exploratory Well -- A well drilled either in search of a new, as yet
undiscovered oil or gas reservoir or to greatly extend the known limits of a
previously discovered reservoir.

Gross Acre -- An acre in which a working interest is owned. The number of
gross acres is the total number of acres in which a working interest is owned.

Gross Well -- A well in which a working interest is owned. The number of
gross wells is the total number of wells in which a working interest is owned.

MBbl -- Thousand barrels of oil.

Mcf -- Thousand cubic feet of gas.

Mcfe -- Thousand cubic feet of gas equivalent, which is determined using
the ratio of one barrel of oil, condensate, or gas liquids to 6 Mcf of gas.

MMBbl -- Million barrels of oil.

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

MMcf -- Million cubic feet of gas.

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

Net Acre -- A net acre is deemed to exist when the sum of fractional
ownership working interests in gross acres equals one. The number of net acres
is the sum of fractional working interests owned in gross acres expressed as
whole numbers and fractions thereof.

Net Well -- A net well is deemed to exist when the sum of fractional
ownership working interests in gross wells equals one. The number of net wells
is the sum of fractional working interests owned in gross wells expressed as
whole numbers and fractions thereof.

Producing Well -- An exploratory or development well found to be capable of
producing either oil or gas in sufficient quantities to justify completion as an
oil or gas well.

Proved Developed Oil and Gas Reserves -- Reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods.

Proved Oil and Gas Reserves -- The estimated quantities of crude oil, gas
and 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.

S-47
<PAGE> 48

Proved Undeveloped Oil and Gas Reserves -- Reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.

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

Working Interest -- 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-48
<PAGE> 49

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<S> <C>
Report of Independent Public Accountants.................... F-2
Consolidated Balance Sheets................................. F-3
Consolidated Statements of Income........................... F-4
Consolidated Statements of Stockholders' Equity............. F-5
Consolidated Statements of Cash Flows....................... F-6
Notes to Consolidated Financial Statements.................. F-7
</TABLE>

F-1
<PAGE> 50

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, 1998
and 1997, and the related consolidated statements of income, stockholders'
equity, and cash flows for each of the three years in the period ended December
31, 1998. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Swift Energy Company and
subsidiaries as of December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.

ARTHUR ANDERSEN LLP

Houston, Texas
February 10, 1999

F-2
<PAGE> 51

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

<TABLE>
<CAPTION>
DECEMBER 31,
JUNE 30, ----------------------------
1999 1998 1997
------------- ------------- ------------
(UNAUDITED)
<S> <C> <C> <C>
Current Assets:
Cash and cash equivalents................................. $ 2,361,331 $ 1,630,649 $ 2,047,332
Accounts receivable
Oil and gas sales....................................... 12,882,248 12,764,568 11,143,033
Associated limited partnerships and joint ventures...... 6,814,544 10,058,239 8,498,702
Joint interest owners................................... 5,265,185 9,767,940 7,357,660
Other current assets...................................... 2,142,828 1,025,035 935,059
------------- ------------- ------------
Total Current Assets................................ 29,466,136 35,246,431 29,981,786
------------- ------------- ------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized....................... 518,037,077 497,296,068 326,836,431
Unproved properties not being amortized................. 55,905,666 56,041,886 41,839,809
------------- ------------- ------------
573,942,743 553,337,954 368,676,240
Furniture, fixtures, and other equipment.................. 7,388,960 7,098,305 6,242,927
------------- ------------- ------------
581,331,703 560,436,259 374,919,167
Less -- Accumulated depreciation, depletion, and
amortization............................................ (221,786,591) (200,713,621) (70,700,240)
------------- ------------- ------------
359,545,112 359,722,638 304,218,927
------------- ------------- ------------
Other Assets:
Receivables from associated limited partnerships, net of
current portion......................................... 926,455 3,170,067 433,444
Limited partnership formation and marketing costs......... 1,565,826 917,189 297,219
Deferred income taxes..................................... -- 254,984 --
Deferred charges.......................................... 4,076,386 4,333,958 4,184,014
------------- ------------- ------------
6,568,667 8,676,198 4,914,677
------------- ------------- ------------
$ 395,579,915 $ 403,645,267 $339,115,390
============= ============= ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities.................. $ 10,302,707 $ 18,639,649 $ 16,518,240
Payable to associated limited partnerships................ 22,016 380,692 3,245,445
Undistributed oil and gas revenues........................ 13,963,366 12,394,713 8,753,979
------------- ------------- ------------
Total Current Liabilities........................... 24,288,089 31,415,054 28,517,664
------------- ------------- ------------
6.25% Convertible Subordinated Notes........................ 115,000,000 115,000,000 115,000,000
Bank Borrowings............................................. 140,000,000 146,200,000 7,915,000
Deferred Revenues........................................... 1,080,472 1,667,574 2,927,656
Deferred Income Taxes....................................... 1,902,834 -- 25,354,150
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none outstanding............................ -- -- --
Common stock, $.01 par value, 35,000,000 shares
authorized, 17,040,635, 16,972,517 and 16,846,956 shares
issued, and 16,181,179, 16,291,242 and 16,459,156 shares
outstanding, respectively............................... 170,406 169,725 168,470
Additional paid-in capital................................ 148,896,472 148,901,270 147,542,977
Treasury stock held, at cost, 859,456, 681,275 and 387,800
shares, respectively.................................... (12,325,668) (11,841,884) (8,519,665)
Unearned ESOP compensation................................ -- -- (150,055)
Retained earnings (deficit)............................... (23,432,690) (27,866,472) 20,359,193
------------- ------------- ------------
113,308,520 109,362,639 159,400,920
------------- ------------- ------------
$ 395,579,915 $ 403,645,267 $339,115,390
============= ============= ============
</TABLE>

See accompanying Notes to Consolidated Financial Statements.

F-3
<PAGE> 52

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

<TABLE>
<CAPTION>
SIX MONTHS
ENDED JUNE 30, YEAR ENDED DECEMBER 31,
------------------------- ----------------------------------------
1999 1998 1998 1997 1996
----------- ----------- ------------ ----------- -----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales........... $44,668,421 $31,482,915 $ 80,067,837 $69,015,189 $52,770,672
Fees from limited
partnerships and joint
ventures................. 99,649 204,879 333,940 745,856 937,238
Interest income............. 23,282 62,875 107,374 2,395,406 433,352
Other, net.................. 625,469 1,065,290 1,960,070 2,555,729 2,156,764
----------- ----------- ------------ ----------- -----------
45,416,821 32,815,959 82,469,221 74,712,180 56,298,026
----------- ----------- ------------ ----------- -----------
Costs and Expenses:
General and administrative,
net of reimbursement..... 2,294,286 1,880,424 3,853,812 3,523,604 4,149,964
Depreciation, depletion, and
amortization............. 21,226,751 13,985,240 39,343,187 24,247,142 16,526,379
Oil and gas production...... 8,550,948 4,874,997 13,138,980 8,778,876 6,141,941
Interest expense............ 6,653,012 2,969,643 8,752,195 5,032,952 693,959
Write-down of oil and gas
properties............... -- -- 90,772,628 -- --
----------- ----------- ------------ ----------- -----------
38,724,997 23,710,304 155,860,802 41,582,574 27,512,243
----------- ----------- ------------ ----------- -----------
Income (Loss) Before Income
Taxes....................... 6,691,824 9,105,655 (73,391,581) 33,129,606 28,785,783
Provision (Benefit) for Income
Taxes....................... 2,258,042 2,979,570 (25,166,377) 10,819,417 9,760,333
----------- ----------- ------------ ----------- -----------
Net Income (Loss)............. $ 4,433,782 $ 6,126,085 $(48,225,204) $22,310,189 $19,025,450
=========== =========== ============ =========== ===========
Per Share Amounts --
Basic....................... $ 0.27 $ 0.37 $ (2.93) $ 1.35 $ 1.27
=========== =========== ============ =========== ===========
Diluted..................... $ 0.27 $ 0.37 $ (2.93) $ 1.26 $ 1.25
=========== =========== ============ =========== ===========
Weighted Average Shares
Outstanding.............. 16,153,982 16,512,562 16,436,972 16,492,856 15,000,901
=========== =========== ============ =========== ===========
</TABLE>

See accompanying Notes to Consolidated Financial Statements.

F-4
<PAGE> 53

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

<TABLE>
<CAPTION>
ADDITIONAL UNEARNED RETAINED
COMMON PAID-IN TREASURY ESOP EARNINGS
STOCK(1) CAPITAL STOCK COMPENSATION (DEFICIT) TOTAL
-------- ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1995........ $125,097 $ 71,133,979 $ -- $ -- $ 22,086,889 $ 93,345,965
Stock issued for benefit plans
(30,015 shares)............... 300 347,345 -- -- -- 347,645
Stock options exercised (257,207
shares)....................... 2,572 2,630,959 -- -- -- 2,633,531
Employee stock purchase plan
(36,387 shares)............... 364 272,178 -- -- -- 272,542
Loan to ESOP for purchase of
shares........................ -- -- -- (568,750) -- (568,750)
Allocation of ESOP shares....... -- 5,382 -- 47,396 -- 52,778
Debenture conversion (2,343,108
shares)....................... 23,431 27,629,018 -- -- -- 27,652,449
Net income...................... -- -- -- -- 19,025,450 19,025,450
-------- ------------ ------------ --------- ------------ ------------
Balance, December 31, 1996........ $151,764 $102,018,861 $ -- $(521,354) $ 41,112,339 $142,761,610
Stock issued for benefit plans
(12,227 shares)............... 122 371,359 -- -- -- 371,481
Stock options exercised (137,155
shares)....................... 1,372 1,613,071 -- -- -- 1,614,443
Employee stock purchase plan
(26,551 shares)............... 266 403,145 -- -- -- 403,411
10% stock dividend (1,494,606
shares)....................... 14,946 43,048,389 -- -- (43,063,335) --
Allocation of ESOP shares....... -- 88,152 -- 371,299 -- 459,451
Purchase of 387,800 shares as
treasury stock................ -- -- (8,519,665) -- -- (8,519,665)
Net income...................... -- -- -- -- 22,310,189 22,310,189
-------- ------------ ------------ --------- ------------ ------------
Balance, December 31, 1997........ $168,470 $147,542,977 $ (8,519,665) $(150,055) $ 20,359,193 $159,400,920
Stock issued for benefit plans
(20,032 shares)............... 200 367,058 -- -- -- 367,258
Stock options exercised (84,757
shares)....................... 847 735,746 -- -- -- 736,593
Employee stock purchase plan
(20,756 shares)............... 208 317,340 -- -- -- 317,548
Stock dividend adjustment (16
shares)....................... -- 461 -- -- (461) --
Allocation of ESOP shares....... -- (62,312) -- 150,055 -- 87,743
Purchase of 293,475 shares as
treasury stocks............... -- -- (3,322,219) -- -- (3,322,219)
Net loss........................ -- -- -- -- (48,225,204) (48,225,204)
-------- ------------ ------------ --------- ------------ ------------
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)(2)............ 224 (366,408) 978,956 -- -- 612,772
Stock options exercised (22,927
shares)(2).................... 229 180,033 -- -- -- 180,262
Employee stock purchase plan
(22,771 shares)(2)............ 228 181,577 -- -- -- 181,805
Purchase of 246,500 shares as
treasury stock(2)............. -- -- $ (1,462,740) -- -- $ (1,462,740)
Net income(2)................... -- -- -- -- 4,433,782 4,433,782
-------- ------------ ------------ --------- ------------ ------------
Balance, June 30, 1999(2)......... $170,406 $148,896,472 $(12,325,668) $ -- $(23,432,690) $113,308,520
======== ============ ============ ========= ============ ============
</TABLE>

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

See accompanying Notes to Consolidated Financial Statements.

F-5
<PAGE> 54

SWIFT ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, YEAR ENDED DECEMBER 31,
--------------------------- --------------------------------------------
1999 1998 1998 1997 1996
------------ ------------ ------------- ------------- ------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash Flows from Operating Activities:
Net income (loss)........................ $ 4,433,782 $ 6,126,085 $ (48,225,204) $ 22,310,189 $ 19,025,450
Adjustments to reconcile net income to
net cash provided by operating
activities --
Depreciation, depletion, and
amortization......................... 21,226,751 13,985,240 39,343,187 24,247,142 16,526,379
Write-down of oil and gas properties... -- -- 90,772,628 -- --
Deferred income taxes.................. 2,157,818 2,728,421 (25,609,134) 10,060,193 8,449,283
Deferred revenue amortization related
to production payment................ (557,616) (647,279) (1,248,800) (1,449,808) (1,670,172)
Other.................................. 257,572 233,297 478,470 786,917 140,047
Change in assets and liabilities --
(Increase) decrease in accounts
receivable........................... 1,373,493 2,864,171 (2,129,360) (204,475) (5,008,592)
Increase (decrease) in accounts payable
and accrued liabilities, excluding
income taxes payable................. (702,149) (20,211) 689,347 (564,323) (444,966)
Increase in income taxes payable....... 113,569 221,223 177,883 70,130 85,149
------------ ------------ ------------- ------------- ------------
Net Cash Provided by Operating
Activities....................... 28,303,220 25,490,947 54,249,017 55,255,965 37,102,578
------------ ------------ ------------- ------------- ------------
Cash Flows from Investing Activities:
Additions to property and equipment...... (23,190,252) (66,968,334) (183,815,927) (131,967,444) (91,487,176)
Proceeds from the sale of property and
equipment.............................. 1,746,559 1,199,061 1,533,112 3,369,982 2,247,799
Net cash distributed as operator of oil
and gas properties..................... (1,354,867) (6,749,156) (5,933,171) (1,829,008) (2,074,104)
Net cash received (distributed) as
operator of partnerships and joint
ventures............................... 3,243,695 575,843 (1,559,537) (2,102,553) 11,284,793
Limited partnership formation and
marketing costs........................ (648,637) (478,048) (619,970) -- --
Other.................................... (183,267) (48,745) (113,716) (259,255) 840
------------ ------------ ------------- ------------- ------------
Net Cash Used in Investing
Activities....................... (20,386,769) (72,469,379) (190,509,209) (132,788,278) (80,027,848)
------------ ------------ ------------- ------------- ------------
Cash Flows from Financing Activities:
Proceeds from 6.25% Convertible
Subordinated Notes..................... -- -- -- -- 115,000,000
Net proceeds from (payments of) bank
borrowings............................. (6,200,000) 56,085,000 138,285,000 7,915,000 --
Net proceeds from issuances of common
stock.................................. 476,971 1,178,846 1,421,399 2,389,336 3,264,482
Purchase of treasury stock............... (1,462,740) (826,846) (3,322,219) (8,519,665) --
Loan to ESOP for purchase of shares...... -- -- -- -- (568,750)
Payments of debt issuance costs.......... -- -- (540,671) -- (4,550,000)
------------ ------------ ------------- ------------- ------------
Net Cash Provided by (Used in)
Financing Activities............. (7,185,769) 56,437,000 135,843,509 1,784,671 113,145,732
------------ ------------ ------------- ------------- ------------
Net Increase (Decrease) in Cash and Cash
Equivalents.............................. $ 730,682 $ 9,458,568 $ (416,683) $ (75,747,642) $ 70,220,462
Cash and Cash Equivalents at Beginning of
Period................................... 1,630,649 2,047,332 2,047,332 77,794,974 7,574,512
------------ ------------ ------------- ------------- ------------
Cash and Cash Equivalents at End of
Period................................... $ 2,361,331 $ 11,505,900 $ 1,630,649 $ 2,047,332 $ 77,794,974
============ ============ ============= ============= ============
Supplemental Disclosures of Cash Flows
Information:
Cash paid during period for interest, net
of amounts capitalized................. $ 6,395,440 $ 2,794,055 $ 8,343,445 $ 4,638,308 $ 831,516
Cash paid during period for income
taxes.................................. $ -- $ 29,926 $ 36,286 $ 381,514 $ 676,920
</TABLE>

See accompanying Notes to Consolidated Financial Statements.

F-6
<PAGE> 55

SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation. The accompanying consolidated financial
statements include the accounts of Swift Energy Company (Swift) and its wholly
owned subsidiaries (collectively referred to as the "Company"), which are
engaged in the exploration, development, acquisition, and operation of oil and
natural gas properties, with particular emphasis on U.S. onshore natural gas
reserves. The Company also has oil and gas activities in New Zealand, Venezuela,
and Russia. The Company's investments in associated oil and gas partnerships and
its joint ventures are accounted for using the proportionate consolidation
method, whereby the Company's proportionate share of each entity's assets,
liabilities, revenues, and expenses is included in the appropriate
classifications in the consolidated financial statements. Intercompany balances
and transactions have been eliminated in preparing the consolidated statements.
In the second quarter of 1998, the Company began netting supervision fees
against general and administrative expenses and oil and gas production costs.
This reclassification has been made for all periods presented. Certain other
reclassifications have been made to prior year amounts to conform to the current
year presentation.

Unaudited Interim Information. The unaudited interim consolidated financial
statements as of June 30, 1999 and for each of the six month periods ended June
30, 1999 and 1998, included herein, have been prepared pursuant to the rules and
regulations of the Securities and Exchange Commission. Accordingly, they do not
include all of the information and footnotes required by generally accepted
accounting principles for complete financial statements. In the opinion of the
Company's management, the unaudited interim consolidated financial statements
include all adjustments (consisting only of normal recurring adjustments) to
present fairly the information set forth herein. The interim financial results
should not be regarded as indicative of operating results for an entire year.

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

Property and Equipment. The Company follows the "full-cost" method of
accounting for oil and gas property and equipment costs. Under this method of
accounting, all productive and nonproductive costs incurred in the acquisition,
exploration, and development of oil and gas reserves are capitalized. 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. The Company's management
believes this capitalization of such costs is appropriate under full-cost
accounting rules. General and administrative costs related to production and
general overhead are expensed as incurred.

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

Future development, site restoration, and dismantlement and abandonment
costs, net of salvage values, are estimated on a property-by-property basis
based on current economic conditions and are amortized to expense as the
Company's capitalized oil and gas property costs are amortized. The

F-7
<PAGE> 56
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Company's properties are all onshore, and historically the salvage value of the
tangible equipment offsets the Company's site restoration and dismantlement and
abandonment costs. The Company expects that this relationship will continue in
the future.

The Company computes the provision for depreciation, depletion, and
amortization of oil and gas properties on the unit-of-production method. Under
this method, the Company computes the provision by multiplying the total
unamortized costs of oil and gas properties -- including future development,
site restoration, and dismantlement and abandonment costs, but excluding costs
of unproved properties -- by an overall rate determined by dividing the physical
units of oil and gas produced during the period by the total estimated units of
proved oil and gas reserves. This calculation is done on a country-by-country
basis for those countries with oil and gas production. The Company currently has
production in the United States only. 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.

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. Domestically, any impairment assessed is added to the cost of proved
properties being amortized. To the extent costs accumulated in the Company's
international initiatives are determined by management to be costs that will not
result in the addition of proved reserves, any impairment is charged to income.
In determining whether such costs should be impaired, the Company's management
evaluates, among other factors, current oil and gas industry conditions,
international economic conditions, capital availability, foreign currency
exchange rates, the political stability in the countries in which the Company
has an investment, and available geological and geophysical information.

Domestic Properties. At the end of each quarterly reporting period, the
unamortized cost of oil and gas properties, net of related deferred income
taxes, is limited to the sum of the estimated future net revenues from proved
properties using current 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. Currently, the Company has proved
reserves in the United States only.

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.

As a result of low oil and gas prices at September 30, 1998, the Company
reported a non-cash write-down on a before-tax basis of $77.2 million ($50.9
million after tax) on its domestic properties.

Foreign Properties. In addition, during the third quarter of 1998, as it
does every reporting period, the Company evaluated all of its foreign
unevaluated properties (a detailed description of which is included in Note 8 to
the Company's financial statements), especially in light of the then increased
volatility in the oil and gas markets, international uncertainty, and turmoil in
the world capital markets.

The increased volatility in the oil and gas markets affected the Company's
cash flows available for further exploration and forced the Company to scale
back its capital expenditures budget. All of this was further accentuated in
Venezuela by the economic crisis there, the results of which were to diminish
the availability of financing in international markets for Venezuelan projects
and to worsen Venezuelan currency problems. Petroleos de Venezuela, S.A.
layoffs, threatened oil worker strikes, reduced OPEC
F-8
<PAGE> 57
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

production allocations, and other third quarter 1998 events highlight the
problems that the oil and gas industry is encountering in Venezuela. As a result
of these and other factors, in the third quarter of 1998, the Company decided to
impair all $2.8 million of costs related to its Venezuelan oil and gas
exploration activities.

In addition, in the third quarter of 1998, the Company impaired all $10.8
million of costs relating to its Russian activities. This impairment is
attributed not only to the volatility in the oil and gas markets and the severe
tightening of international credit markets discussed above, but also to the
increased political instability in Russia and the August 1998 collapse of the
Russian currency. The Company believed that the economic and political situation
would result in the lack of capital to develop these reserves underlying the
Company's net profits interest in the near term. Although the Company continues
to believe that its net profits interest is legally enforceable under
international law, for all these reasons the Company does not believe that
realistically it will be able to recover its investment in Russia in the
foreseeable future. Because of this, the Company determined that it no longer
had a reasonable basis to continue capitalization of the costs in its Russia
cost center.

The combination of the third-quarter domestic full-cost ceiling write-down
and foreign activities impairment charges reduced before-tax earnings by $90.8
million ($59.9 million after tax). Since such impairment, any costs incurred in
Venezuela and Russia have been charged to income.

Also, during the fourth quarter of 1998, the Company's $0.4 million portion
of drilling costs associated with an unsuccessful exploratory well drilled by
another operator in New Zealand was charged to income as depreciation,
depletion, and amortization costs.

Oil and Gas Revenues. Gas revenues are reported using the entitlement
method in which the Company recognizes its ownership interest in natural gas
production as revenue. If the Company's sales exceed its ownership share of
production, the differences are reported as deferred revenue. Natural gas
balancing receivables are reported when the Company's ownership share of
production exceeds sales. As of December 31, 1998, the Company did not have any
material natural gas imbalances.

Deferred Charges. Legal and accounting fees, underwriting fees, printing
costs, and other direct expenses associated with the public offering in November
1996 of the Company's 6.25% Convertible Subordinated Notes (the "Notes") have
been capitalized and are being amortized over the life of the Notes, which
mature on November 15, 2006. The balance of these issuance costs at December 31,
1998 was $3,826,864, net of accumulated amortization of $723,136. The issuance
costs associated with its new $250.0 million revolving credit facility (the "New
Credit Facility"), which closed in August 1998, have been capitalized and are
being amortized over the life of the facility, which will extend until August
2002. The balance of these issuance costs at December 31, 1998, was $507,094,
net of accumulated amortization of $51,600.

Limited Partnerships and Joint Ventures. Between 1984 and 1995, the Company
formed limited partnerships and joint ventures for the purpose of acquiring
interests in producing oil and gas properties and, since 1993, partnerships
engaged in drilling for oil and gas reserves. The Company serves as managing
general partner or manager of these entities.

The Company acquired producing oil and gas properties and transferred those
properties to the partnership entities which invested in producing oil and gas
properties. These transfers were at cost, including interest, other carrying
costs, closing costs, and screening and evaluation costs of properties not
acquired, or, in certain instances, at fair market value based upon the opinion
of an independent expert. These costs were reduced by net operating revenues
from the effective date of the acquisition to the date of transfer to these
entities. Such net operating revenue amounts totaled approximately $100,000 and
$300,000 in 1997 and 1996, respectively. With the acquisitions made in 1997, the
Company fulfilled its

F-9
<PAGE> 58
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

responsibility of acquiring properties for such partnerships, as these
partnerships are fully invested in properties.

Commencing in September 1993, the Company began offering, on a private
placement basis, general and limited partnership interests in limited
partnerships to be formed to drill for oil and gas. As managing general partner,
the Company pays for all front-end costs incurred in connection with these
offerings, for which the Company receives an interest in the partnerships.
Through December 31, 1998, approximately $66.1 million had been raised in
thirteen partnerships, one each formed in 1993 and 1994; three each in 1995,
1996, and 1997; and two in 1998. In June and October 1998, the Company closed
the twelfth and thirteenth partnerships with total subscriptions of
approximately $3.2 million and $4.3 million, respectively. Costs of syndication
and qualification of these limited partnerships incurred by the Company have
been deferred. Under the current private limited partnership offerings, selling
and formation costs borne by the Company serve as the Company's general partner
contribution to such partnerships.

During 1996, the limited partners in 18 partnerships, which had been in
operation over nine years and had produced a substantial majority of their
reserves, voted to sell their remaining properties and liquidate the limited
partnerships. Of these partnerships, 10 were the earliest public income
partnerships formed between 1984 and 1986. In early 1997, eight private drilling
partnerships formed between 1979 and 1985 were liquidated. During 1997, the
limited partners in an additional 11 partnerships, formed in 1990 and 1991,
voted to sell their properties and liquidate the limited partnerships, which
occurred in June 1998.

In October 1998, the Company notified investors in 63 Company-managed
partnerships, formed between 1986 and 1994, that it had delayed calling investor
meetings to consider its purchase of all of the oil and gas properties owned by
these partnerships, which was proposed in March 1998. This decision principally
reflected significant market changes that had occurred during the long period
necessary for regulatory review of soliciting materials, the age of the
third-party appraisals of these partnership properties, and the much publicized
weakness in both the equity and debt markets for energy companies. During the
last six months, the weakness in oil and natural gas prices has deepened,
creating concern over the appropriateness of selling properties at this time.
The Company expects to continue to re-evaluate the status and operation of these
partnerships, whether to propose some form of liquidating transaction and, if
so, when and in what form.

Hedging Activities. The Company's revenues are primarily the result of
sales of its oil and natural gas production. Market prices of oil and natural
gas may fluctuate and adversely affect operating results. To mitigate some of
this risk, the Company engages periodically in certain limited hedging
activities, but only to the extent of buying protection price floors for
portions of its and the limited partnership oil and natural gas production.
Costs and any benefits derived from these price floors are accordingly recorded
asa reduction or an increase, as applicable, in oil and gas sales revenue and
were not significant for any year presented. The costs to purchase put options
are amortized over the option period. The costs related to 1998 hedging
activities totaled approximately $377,000 with benefits of approximately
$101,000 being received, resulting in a net cash outlay of approximately
$276,000 or $0.007 per Mcfe. The costs related to the open contracts as of
December 31, 1998, totaled approximately $252,000 and had a fair market value of
$267,000.

Income Taxes. The Company accounts for income taxes using the liability
method, and deferred taxes are determined based on the estimated future tax
effects of differences between the financial statement and tax bases of assets
and liabilities given the provisions of the enacted tax laws.

Deferred Revenues. In May 1992, the Company purchased interests in certain
wells using funds provided by the Company's sale of a volumetric production
payment in these properties to Enron. Under the production payment agreement,
the Company is required to deliver to Enron approximately 9.5 Bcf over an
eight-year period, or for such longer period as is necessary to deliver a
specified heating equivalent

F-10
<PAGE> 59
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

quantity at an average price of $1.115 per MMBtu. The Company receives all
proceeds from sale of excess gas at current market prices plus the proceeds from
sale of oil or condensate. Volumes remaining to be delivered through October
2000 under the volumetric production payment were approximately 1.1 Bcf at
December 31, 1998, and were not included in the Company's proved reserves. Net
proceeds from the sale of the production payment were recorded as deferred
revenues. Deliveries under the production payment agreement are recorded as oil
and gas sales revenues and a corresponding reduction of deferred revenues.

Cash and Cash Equivalents. The Company considers all highly liquid debt
instruments with an initial maturity of three months or less to be cash
equivalents.

Credit Risk Due to Certain Concentrations. The Company extends credit,
primarily in the form of monthly oil and gas sales and joint interest owners
receivables, to various companies in the oil and gas industry, which results in
a concentration of credit risk. The concentration of credit risk may be affected
by changes in economic or other conditions and may accordingly impact the
Company's overall credit risk. However, the Company believes that the risk of
these unsecured receivables is mitigated by the size, reputation, and nature of
the companies to which the Company extends credit. During 1998, oil and gas
sales to subsidiaries of PG&E Energy Trading Corporation and Aquila Southwest
Pipeline Corporation were $13.0 million (16.2% of oil and gas sales) and $8.0
million (10.0%), respectively. In 1997, oil and gas sales to PG&E Energy Trading
Corporation, Aquila Southwest Pipeline Corporation, and Koch Oil Company were
$13.5 million (19.5%), $8.1 million (11.7%), and $7.1 million (10.3%),
respectively. In 1996, oil and gas sales to TECO Gas Marketing Company were $6.9
million (13.0%).

Fair Value of Financial Instruments. The Company's financial instruments
consist of cash and cash equivalents, accounts receivable, accounts payable,
bank borrowings, and convertible 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, 1998
and 1997 and were determined based upon interest rates currently available to
the Company for borrowings with similar terms. The fair values of the
convertible notes were $81.4 million and $113.6 million at December 31, 1998 and
1997, respectively, and were based on quoted markets prices as of the respective
dates.

New Accounting Pronouncements. In the first quarter of 1998, the Company
adopted the Statement of Financial Accounting Standards ("SFAS") No. 130,
"Reporting Comprehensive Income," which requires the display of comprehensive
income and its components in the financial statements. Comprehensive income
represents all changes in equity during the reporting period, including net
income and charges directly to equity, which are excluded from net income. The
adoption of this statement does not have a material impact on the Company or its
financial disclosures, as the Company has not historically and currently does
not enter into transactions that result in charges (or credits) directly to
equity (such as additional minimum pension liability changes, currency
translation adjustments, and unrealized gains and losses on available-for-sale
securities).

In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." The Statement
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
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, is effective for
fiscal years beginning after June 15, 2000. The Company is currently evaluating
the new standard, but has not yet determined the impact it will have on its
financial position and results of operations.
F-11
<PAGE> 60
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

2. EARNINGS PER SHARE

Basic earnings per share ("Basic EPS") has been computed using the weighted
average number of common shares outstanding during the respective periods. Basic
EPS has been retroactively restated in all periods presented to give recognition
to the 10% stock dividend declared in October 1997 that resulted in an
additional 1,494,622 shares being issued.

The calculation of diluted earnings per share ("Diluted EPS") assumes
conversion of the Company's Convertible Notes as of the beginning of the
respective periods and the elimination of the related after-tax interest expense
and assumes, as of the beginning of the period, exercise of stock options and
warrants (using the treasury stock method). Certain of the Company's stock
options that would potentially dilute Basic EPS in the future were not included
in the computation of Diluted EPS because to do so would have been antidilutive
for the 1998 period and for the six months ended June 30, 1999 and 1998. Diluted
EPS has also been retroactively restated for all periods presented to give
effect to the 10% stock dividend. The original conversion price of the
Convertible Notes of $34.6875 was revised to $31.534 to reflect the October 1997
stock dividend declared.

The following is a reconciliation of the numerators and denominators used
in the calculation of Basic and Diluted EPS for the years ended December 31,
1998, 1997, and 1996:
<TABLE>
<CAPTION>
1998 1997 1996
---------------------------------- ------------------------------------ -----------
NET PER NET PER SHARE NET
LOSS SHARES AMOUNT INCOME SHARES AMOUNT INCOME
------------ ---------- ------ ----------- ---------- --------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Basic EPS:
Net Income (Loss) and Share
Amounts......................... $(48,225,204) 16,436,972 $(2.93) $22,310,189 16,492,856 $1.35 $19,025,450
Dilutive Securities:
6.25% Convertible Notes........... -- -- 3,525,808 3,646,847 788,710
Stock Options..................... -- -- -- 428,036 --
------------ ---------- ----------- ---------- -----------
Diluted EPS:
Net Income (Loss) and Assumed
Share Conversions............... $(48,225,204) 16,436,972 $(2.93) $25,835,997 20,567,739 $1.26 $19,814,160
------------ ---------- ----------- ---------- -----------

<CAPTION>
1996
-------------------
PER
SHARES AMOUNT
---------- ------
<S> <C> <C>
Basic EPS:
Net Income (Loss) and Share
Amounts......................... 15,000,901 $1.27
Dilutive Securities:
6.25% Convertible Notes........... 419,637
Stock Options..................... 407,108
----------
Diluted EPS:
Net Income (Loss) and Assumed
Share Conversions............... 15,827,646 $1.25
----------
</TABLE>

3. PROVISION FOR INCOME TAXES

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

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1998 1997 1996
------------ ----------- ----------
<S> <C> <C> <C>
Current..................................................... $ 214,169 $ 77,402 $ 759,253
Deferred.................................................... (25,380,546) 10,742,015 9,001,080
------------ ----------- ----------
Total................................................ $(25,166,377) $10,819,417 $9,760,333
============ =========== ==========
</TABLE>

F-12
<PAGE> 61
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

There are differences between income taxes computed using the statutory
rate (34% for 1998, 1997, and 1996) and the Company's effective income tax rates
(34.3%, 32.7%, and 33.9% for 1998, 1997, and 1996, respectively), primarily as
the result of certain tax credits available to the Company. Reconciliations of
income taxes computed using the statutory rate to the effective income tax rates
are as follows:

<TABLE>
<CAPTION>
1998 1997 1996
------------ ----------- ----------
<S> <C> <C> <C>
Income taxes computed at federal
statutory rate........................ $(24,953,138) $11,264,066 $9,787,166
State tax provisions, net of federal
benefits.............................. 23,949 48,058 75,936
Nonconventional fuel source credit...... (287,000) (294,000) (306,000)
Depletion deductions in excess of
basis................................. (42,500) (51,000) (26,520)
Other, net.............................. 92,312 (147,707) 229,751
------------ ----------- ----------
Provision (benefit) for income taxes.... $(25,166,377) $10,819,417 $9,760,333
============ =========== ==========
</TABLE>

The tax effects of significant temporary differences representing the net
deferred tax liability (asset) at December 31, 1998 and 1997, were as follows:

<TABLE>
<CAPTION>
1998 1997
----------- -----------
<S> <C> <C>
Deferred tax assets:
Alternative minimum tax credits.......................... $(1,979,399) $(1,831,299)
Other.................................................... (237,587) (237,587)
----------- -----------
Total deferred tax assets........................ $(2,216,986) $(2,068,886)
Deferred tax liabilities:
Oil and gas properties................................... $ 1,531,651 $26,785,212
Other.................................................... 430,351 637,824
----------- -----------
Total deferred tax liabilities................... $ 1,962,002 $27,423,036
----------- -----------
Net deferred tax liability (asset)......................... $ (254,984) $25,354,150
=========== ===========
</TABLE>

The Company did not record any valuation allowances against deferred tax
assets at December 31, 1998 or 1997.

At December 31, 1998, the Company 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

Convertible Notes. The Company's convertible notes at December 31, 1998 and
1997, consist of $115,000,000 of 6.25% Convertible Subordinated Notes due 2006.
The following description of the Convertible Notes is qualified in its entirety
by reference to the indenture for the Convertible Notes, a form of which has
been filed with the SEC.

Payments of principal, interest and premiums, under the Convertible Notes
will be subordinated to payments on the notes and are subordinate to all other
senior debt of Swift, including its credit facilities. Holders of the
Convertible Notes may convert them into common stock at any time before maturity
at a price of $31.534 per share. This price is subject to adjustment if certain
events occur. On or after November 15, 1999, Swift may redeem the convertible
notes for cash at 104.375% of principal. This conversion is subject to
restrictions and the conversion rate declines overtime to 100.625% in 2005. If
certain Changes in Control occur, or if our common stock ceases trading on a
national exchange or automated quotation system, holders of Convertible Notes
will have the right to require us to repurchase

F-13
<PAGE> 62
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the Convertible Notes at 101% of the note's principal amount, plus accrued and
unpaid interest to the date of repurchase.

Interest expense on the Notes, including amortization of debt issuance
costs, totaled $7,544,650 and $7,514,967 in 1998 and 1997, respectively.

Bank Borrowings. In August 1998, the Company closed its new $250.0 million
revolving credit facility with a syndicate of ten banks (the "New Credit
Facility"). At December 31, 1998, the Company had outstanding borrowings of
$146.2 million under its New Credit Facility. At December 31, 1997, the Company
had outstanding borrowings of $7.9 million under its borrowing arrangements. At
December 31, 1998, the New Credit Facility consisted of a $250.0 million
revolving line of credit with a $170.0 million borrowing base. The interest rate
is either (a) the lead bank's prime rate (7.75% at December 31, 1998) or (b) the
adjusted London Interbank Offered Rate ("LIBOR") plus the applicable margin
depending on the level of outstanding debt (a weighted average of 6.34% at
December 31, 1998). The applicable margin is based on the Company's ratio of
outstanding balance on the New Credit Facility to the last calculated borrowing
base. Of the $146.2 million borrowed at December 31, 1998, $145.0 million was
borrowed at the LIBOR rate.

The terms of the New Credit Facility include, among other restrictions, a
limitation on the level of cash dividends (not to exceed $2.0 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 the Company's common stock. The Company is currently in
compliance with the provisions of this agreement, as amended in mid-March 1999
to modify the cash flow-to-debt covenant. The New Credit Facility will extend
until August 2002.

Previously, the Company's credit facilities consisted of a $100.0 million
revolving line of credit with an $80.0 million borrowing base and a $7.0 million
revolving line of credit with a $5.1 million borrowing base. These facilities
were with a two-bank group. Depending on the level of outstanding debt, the
interest rate on the $100.0 million revolving line of credit was (a) either the
bank's base rate or the bank's base rate plus 0.25% or (b) the LIBOR rate plus
1% to 1.5%. The interest rate on the $7.0 million revolving line of credit was
the bank's base rate less 0.25%.

In addition to interest on these credit facilities, the Company pays a
commitment fee to compensate the banks for making funds available. The fee on
the revolving line of credit is calculated on the average daily remainder, if
any, of the commitment amount less the aggregate principal amounts outstanding,
plus the amount of all letters of credit outstanding during the period. The
aggregate amounts of commitment fees paid by the Company were $114,000 in 1998
and $31,000 in 1997.

5. COMMITMENTS AND CONTINGENCIES

Total rental and lease expenses were $1,117,351 in 1998, $1,039,210 in
1997, and $957,797 in 1996. The Company's remaining minimum annual obligations
under non-cancelable operating lease commitments are $1,146,229 for 1999,
$1,151,249 for 2000, $1,151,249 for 2001, $1,273,007 for 2002, and $1,358,238
for 2003.

As of December 31, 1998, the Company is the managing general partner of 80
limited partnerships. Because the Company serves as the general partner of these
entities, under state partnership law it is contingently liable for the
liabilities of these partnerships, which liabilities are not material for any of
the periods presented in relation to the partnerships' respective assets.

F-14
<PAGE> 63
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

6. STOCKHOLDERS' EQUITY

Common Stock. In October 1997, the Company declared a 10% stock dividend to
stockholders of record. The transaction was valued based on the closing price
($28.8125) of the Company's common stock on the New York Stock Exchange on
October 1, 1997. As a result of the issuance of 1,494,622 shares of the
Company's common stock as a dividend, retained earnings were reduced by
$43,063,796, with the common stock and additional paid-in capital accounts
increased by the same amount. Basic and Diluted EPS were restated for all
periods presented to reflect the effect of the stock dividend.

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

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

On December 9, 1998, the Company canceled certain previously issued options
under the 1990 stock compensation plan and reissued them at an option price that
reflected current market value of the Company's common stock as of that date. No
compensation expense was recognized in 1998 as a result of this transaction.

The employee stock purchase plan provides eligible employees the
opportunity to acquire shares of Company 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 will be 85% of the
lower of the closing price of the Company's common stock as quoted on the New
York Stock Exchange at the beginning or end of the plan year or a date during
the year chosen by the participant. Under this plan, the Company issued 20,756
shares at a price range of $13.65 to $18.06 in 1998, 26,551 shares at a price of
$15.19 in 1997, and 36,387 shares at a price range of $6.59 to $7.97 in 1996.
The estimated weighted average fair value of shares issued under this plan was
$6.86 in 1998, $4.39 in 1997, and $2.13 in 1996. As of December 31, 1998, there
remained 437,448 shares available for issuance under this plan. There are no
charges or credits to income in connection with this plan.

F-15
<PAGE> 64
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

<TABLE>
<CAPTION>
1998 1997 1996
------------ ----------- -----------
<S> <C> <C> <C> <C>
Net Income (Loss): As Reported $(48,225,204) $22,310,189 $19,025,450
Pro Forma $(49,985,171) $21,362,722 $18,750,064
Basic EPS: As Reported $ (2.93) $ 1.35 $ 1.27
Pro Forma $ (3.04) $ 1.30 $ 1.25
Diluted EPS: As Reported $ (2.93) $ 1.26 $ 1.25
Pro Forma $ (3.04) $ 1.21 $ 1.23
</TABLE>

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

The following is a summary of the Company's stock options under these plans
as of December 31, 1998, 1997, and 1996:

<TABLE>
<CAPTION>
1998 1997 1996
------------------------ ------------------------ ------------------------
WTD. AVG. WTD. AVG. WTD. AVG.
SHARES EXER. PRICE SHARES EXER. PRICE SHARES EXER. PRICE
---------- ----------- ---------- ----------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C>
Options outstanding, beginning
of period................... 1,761,512 $14.71 1,399,769 $12.09 1,308,391 $ 8.83
Options granted............... 1,319,881 $ 9.72 401,390 $26.23 302,281 $23.78
Options cancelled............. (730,490) $24.15 (31,404) $12.99 (11,251) $ 8.81
Options exercised............. (84,757) $ 7.54 (137,155) $ 8.54 (199,652) $ 8.65
Options adjusted for 10% stock
dividend.................... -- 128,912 --
---------- ---------- ----------
Options outstanding, end of
period...................... 2,266,146 $ 9.03 1,761,512 $14.71 1,399,769 $12.09
========== ========== ==========
Options exercisable, end of
period...................... 888,695 $ 8.64 869,484 $ 9.05 700,271 $ 8.82
========== ========== ==========
Options available for future
grant, end of period........ 915,236 1,501,622 38,546
========== ========== ==========
Estimated weighted average
fair value per share of
options granted during the
year........................ $ 3.82 $ 13.98 $ 15.17
========== ========== ==========
</TABLE>

F-16
<PAGE> 65
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 1998, 1997, and 1996,
respectively: no dividend yield, expected volatility factors of 42.3%, 38.7%,
and 40.4%, risk-free interest rates of 4.69%, 6.02%, and 6.42%, and expected
lives of 7.0, 7.5, and 10.0 years. The following table summarizes information
about stock options outstanding at December 31, 1998:

<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------- -----------------------
RANGE OF NUMBER WTD. AVG. WTD. AVG. NUMBER WTD. AVG.
EXERCISE OUTSTANDING REMAINING EXERCISE EXERCISABLE EXERCISE
PRICES AT 12/31/98 CONTRACTUAL PRICE AT 12/31/98 PRICE
-------- ----------- ----------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C>
$ 4.00 to $8.99 1,147,917 6.3 $ 7.87 598,490 $ 7.75
$9.00 to $17.99 1,057,251 7.5 $ 9.57 279,687 $ 9.96
$18.00 to $27.00 60,978 8.3 $21.47 10,518 $23.72
--------- -------
$4.00 to $27.00 2,266,146 7.0 $ 9.03 888,695 $ 8.64
========= =======
</TABLE>

Employee Stock Ownership Plan. In 1996, the Company established an Employee
Stock Ownership Plan ("ESOP") effective January 1, 1996. All employees over the
age of 21 with one year of service are participants. The Plan has a five-year
cliff vesting, and service is recognized after the Plan effective date. The ESOP
is designed to enable employees of the Company to accumulate stock ownership.
While there will be no employee contributions, participants will receive an
allocation of stock that has been contributed by the Company. Compensation
expense is reported when such shares are released to employees. The Plan may
also acquire common stock of the Company purchased at fair market value. The
ESOP can borrow money from the Company to buy Company stock. This was done in
September 1996 to purchase 25,000 shares (adjusted to 27,500 shares after the
October 1, 1997, 10% stock dividend) from the Company's chairman. Benefits will
be paid in a lump sum or installments, and the participants generally have the
choice of receiving cash or stock. At December 31, 1998, all of the ESOP
compensation was earned. At December 31, 1997 and 1996, the unearned portions of
the ESOP, $150,055 and $521,354, respectively, were recorded as a contra-equity
account entitled "Unearned ESOP Compensation."

Common Stock Repurchase Program. In March 1997, the Company's Board of
Directors approved a common stock repurchase program for up to $20.0 million of
the Company's common stock and subsequently extended this program through June
30, 1998. Under this program, the Company used approximately $9.3 million of
working capital to acquire 435,274 shares in the open market at an average cost
of $21.47 per share. On July 23, 1998, the Board of Directors approved a new
repurchase program for up to $10.0 million of the Company's common stock through
the end of 1998. Subsequently, the Company used approximately $2.5 million of
working capital to acquire another 246,001 shares for an average cost of $10.14
per share. Through December 31, 1998, 681,275 shares have been acquired at a
total cost of $11,841,884 and are included in "Treasury stock held, at cost" on
the balance sheet.

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

7. RELATED-PARTY TRANSACTIONS

The Company is the operator of a substantial number of properties owned by
its affiliated limited partnerships and joint ventures and accordingly, charges
these entities and third-party joint interest owners operating fees. The Company
is also reimbursed for direct, administrative, and overhead costs incurred in
conducting the business of the limited partnerships, which totaled approximately
$5,000,000, $6,300,000,

F-17
<PAGE> 66
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

and $6,100,000 in 1998, 1997, and 1996, respectively. The Company was also
reimbursed by the limited partnerships and joint ventures for costs incurred in
the screening, evaluation, and acquisition of producing oil and gas properties
on their behalf. Such costs totaled approximately $490,000 and $250,000 in 1997
and 1996, respectively. The Company, with the acquisitions made in 1997, has
fulfilled its responsibility of acquiring properties for such partnerships, as
those partnerships are fully invested in properties. In the case where the
limited partners voted to sell their remaining properties and liquidate their
limited partnerships, the Company was also reimbursed for direct,
administrative, and overhead costs incurred in the disposition of such
properties, which costs totaled approximately $580,000, $675,000, and $805,000
in 1998, 1997, and 1996, respectively.

The ESOP can borrow money from the Company to buy Company stock. This was
done in September 1996 to purchase 25,000 shares (adjusted to 27,500 shares
after the October 1, 1997 10% stock dividend) from the Company's chairman.
Benefits will be paid in a lump sum or installments, and the participants
generally have the choice of receiving cash or stock.

8. FOREIGN ACTIVITIES

New Zealand. Since October 1995, the Company has been issued two Petroleum
Exploration Permits by the New Zealand Minister of Energy. The first permit
covered approximately 65,000 acres in the Onshore Taranaki Basin of New
Zealand's North Island, and the second covered approximately 69,300 adjacent
acres. A wholly owned subsidiary, Swift Energy New Zealand Limited, formed in
late 1997, conducts the Company's New Zealand activities and owns the interest
in the permits. In March 1998, the Company surrendered approximately 46,400
acres covered in the first permit, and the remaining acreage has been included
as an extension of the area covered in the second permit. Under the terms of the
expanded permit, the Company is obligated to drill one exploratory well prior to
August 12, 1999. All other obligations under the permit have been fulfilled,
including the reinterpretation of existing seismic data and the acquisition and
processing of new seismic data.

On October 23, 1998, the Company entered into separate agreements with
Marabella Enterprises Ltd. ("Marabella"), a subsidiary of Bligh Oil & Minerals
N.L., an Australian company, to obtain from Marabella a 25% working interest in
another New Zealand Petroleum Exploration Permit and for Marabella to become a
5% participant in the Company's permit. An exploration well on the Marabella
permit commenced drilling on October 16, 1998, the results of which were
unsuccessful. Accordingly, the $0.4 million costs of such well were charged
against earnings. The Company has also agreed in principle to participate with
Marabella in an additional permit as a 17.5% working interest owner.

At December 31, 1998, the Company's investment in New Zealand was
approximately $5.0 million and is included in the unproved properties portion of
oil and gas properties. Approximately $0.4 million of such costs have been
impaired.

Russia. On September 3, 1993, the Company signed a Participation Agreement
with Senega, a Russian Federation joint stock company (in which the Company has
an indirect interest of less than 1%), to assist in the development and
production of reserves from two fields in Western Siberia, providing the Company
with a minimum 5% net profits interest from the sale of hydrocarbon products
from the fields for providing managerial, technical, and financial support to
Senega. Additionally, the Company purchased a 1% net profits interest from
Senega for $0.3 million.

On December 10, 1997, the Company amended and restated the Participation
Agreement. Under the amended and restated Participation Agreement, the Company
retains its 6% net profits interest in the Samburg Field and agreed to assist
Senega in obtaining investments necessary to develop the field. Senega is
charged with the management and control of the field development. The Company's
investment in Russia, prior to its impairment in the third quarter of 1998, was
approximately $10.8 million and was

F-18
<PAGE> 67
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

previously included in the unproved properties portion of oil and gas
properties. However, the economic and political uncertainty and currency
concerns that arose during the third quarter of 1998 in Russia, combined with
the price volatility and severe tightening of international capital markets,
caused the Company to re-evaluate the timing of the recovery of its capitalized
costs in that country. See Note 1 to the Company's financial statements for a
more detailed discussion of the impairment. Subsequent to such impairment, any
costs incurred in Russia have been reported as a charge to earnings.

Venezuela. The Company formed a wholly owned subsidiary, Swift Energy de
Venezuela, C. A., for the purpose of submitting a bid on August 5, 1993, under
the Venezuelan Marginal Oil Field Reactivation Program. Although the Company did
not win the bid, it has continued to gather information relating to reserves and
geological and geophysical data in Venezuela, and continued to pursue
cooperative ventures involving other fields and opportunities in Venezuela. The
Company evaluated a number of blocks being offered by Petroleos de Venezuela, S.
A. under the Third Operating Agreement Round in 1997, but decided against
submitting any bid on these blocks. The Company has entered into an agreement
with Tecnoconsult, S. A., and Corporation EDC, S.A.C.A., Venezuelan companies,
to jointly formulate and submit a proposal to Petroleos de Venezuela, S. A. for
the construction and operation of a methane pipeline. Currently, the technical
and economic feasibility of the project is under study. The Company's investment
in Venezuela, prior to its impairment in the third quarter of 1998, was
approximately $2.8 million and was previously included in the unproved
properties portion of oil and gas properties. However, the economic uncertainty
and currency concerns in Venezuela, combined with the price volatility and
severe tightening of international capital markets, caused the Company to
re-evaluate its prospects of participating in further Venezuelan exploration
activities in the near-term and the prospects for recovery of its capitalized
costs in that country. See Note 1 to the Company's financial statements for a
more detailed discussion of the impairment. Subsequent to such impairment, any
costs incurred in Venezuela have been reported as a charge to earnings.

9. ACQUISITION OF PROPERTIES

In the third quarter of 1998, the Company purchased from Sonat Exploration
Company ("Sonat"), a subsidiary of Sonat Inc., the Toledo Bend Properties
located in Texas and Louisiana in the vicinity of Toledo Bend Lake for
approximately $87.0 million in cash, with approximately $56.8 million of the
total spent for producing properties, approximately $15.0 million to purchase an
interest in two gas processing plants, and approximately $15.2 million to
acquire leasehold properties. Post-closing purchase price adjustments are still
being determined, but management does not expect that these adjustments will be
material to the Company's financial statements.

As of December 31, 1998, estimated proved reserves for the Toledo Bend
Properties were 130.5 Bcfe, of which approximately 58% was natural gas, and 59%
was proved undeveloped. At such date the properties include 162 producing oil
and natural gas wells in the Brookeland Field in Southeast Texas and the Masters
Creek Field in Western Louisiana, 23 saltwater disposal wells, a 20% interest in
two natural gas plants, associated production facilities, working interests in
approximately 200,875 gross undeveloped (125,378 net undeveloped) acres, and
approximately 114,000 undeveloped fee mineral acres. The Company has become
operator of 115 of the 162 wells. The two gas plants are operated by a third
party and have combined capacity of 250 MMcfe per day.

The Toledo Bend Properties extend one of the Company's core areas by adding
producing reserves that the Company believes will significantly increase its
production on a short-term basis. The Company's production on these properties
amounted to approximately 11.6 Bcfe, of which 44% was natural gas. Furthermore,
as a result of the Company's extensive experience in other parts of the Austin
Chalk trend, the Company believes that it can successfully exploit incremental
drilling opportunities in the future.

F-19
<PAGE> 68
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

This acquisition was accounted for by the purchase method and was
incorporated into the Company's results of operations in the third quarter of
1998. The following unaudited pro forma supplemental information presents
consolidated results of operations as if this acquisition had occurred on
January 1, 1997:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1998 1997
---------- ----------
(THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED)
<S> <C> <C>
Revenue..................................................... $115,394 $139,584
Net Income Before Non-Cash Charge........................... $ 19,098 $ 38,528
Net Income (Loss)........................................... $(40,812) $ 38,528
Net Income (Loss) Per Share Amounts --
Basic..................................................... $ (2.48) $ 2.34
Diluted................................................... $ (2.48) $ 2.04
</TABLE>

SUPPLEMENTAL INFORMATION (UNAUDITED)

Capitalized Costs. The following table presents the Company's aggregate
capitalized costs relating to oil and gas producing activities and the related
depreciation, depletion, and amortization:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1998 1997
------------ ------------
<S> <C> <C>
Oil and Gas Properties:
Proved................................................. $497,296,068 $326,836,431
Unproved (not being amortized) Domestic................ 51,040,378 26,735,460
Unproved (not being amortized) Foreign................. 5,001,508 15,104,349
------------ ------------
553,337,954 368,676,240
Accumulated Depreciation, Depletion, and Amortization.... (196,626,243) (67,363,393)
------------ ------------
$356,711,711 $301,312,847
============ ============
</TABLE>

Of the $51,040,378 of domestic unproved property costs (primarily seismic
and lease acquisition costs) at December 31, 1998, excluded from the amortizable
base, $33,360,518 was incurred in 1998, $11,966,626 was incurred in 1997,
$3,260,112 was incurred in 1996, and $2,953,122 was incurred in prior years.
When the Company is in an active drilling mode, it has evaluated the majority of
these unproved costs within a two to three year time frame. In response to
current market conditions, the Company has decreased its planned 1999 drilling
expenditures when compared to recent years, which when coupled with the $15.2
million of leasehold properties acquired in the Toledo Bend Properties
acquisition may extend the evaluation timeframe of such costs.

Of the $5,001,508 of net foreign unproved property costs at December 31,
1998, being excluded from the amortizable base, $2,521,761 was incurred in 1998,
$1,731,561 was incurred in 1997, $545,980 was incurred in 1996, and $202,206 was
incurred in 1995. All of these costs are costs incurred in New Zealand, as the
costs incurred in Russia and Venezuela were impaired in the third quarter of
1998 (see Note 1 to the Company's financial statements). The Company expects it
will complete its evaluation of the New Zealand properties as wells are drilled
over the next two to three years.

F-20
<PAGE> 69
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1998 1997 1996
------------ ------------ -----------
<S> <C> <C> <C>
Acquisition of proved properties............ $ 59,487,524 $ 8,417,318 $ 1,529,611
Lease acquisitions(1,2)..................... 38,658,047 21,603,732 16,426,327
Exploration................................. 12,578,124 10,705,115 2,704,281
Development................................. 54,821,131 82,885,549 69,067,024
------------ ------------ -----------
Total acquisition, exploration,
and development(3).............. $165,544,826 $123,611,714 $89,727,243
------------ ------------ -----------
Processing plants........................... $ 15,000,000 $ -- $ --
Field compression facilities................ 2,228,101 7,444,070 --
------------ ------------ -----------
Total plants and facilities....... $ 17,228,101 $ 7,444,070 $ --
------------ ------------ -----------
Total capital expenditures.................. $182,772,927 $131,055,784 $89,727,243
============ ============ ===========
</TABLE>

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

(1) Lease acquisitions for 1998, 1997, and 1996 include expenditures of:
$2,521,761, $1,731,561, and $545,980, respectively, relating to the
Company's initiatives in New Zealand; $421,602, $828,133, and $487,597,
respectively, relating to initiatives in Venezuela; and $592,841, $658,145,
and $2,712,278, respectively, relating to initiatives in Russia.

(2) These are actual amounts as incurred by year, including both proved and
unproved lease costs. The annual lease acquisition amounts added to proved
oil and gas properties (being amortized) for 1998, 1997, and 1996, were
$13,853,129, $7,384,385, and $9,458,016, respectively.

(3) Includes capitalized general and administrative costs directly associated
with the acquisition, exploration, and development efforts of approximately
$12,300,000, $11,700,000, and $7,400,000 in 1998, 1997, and 1996,
respectively. In addition, total includes $3,849,665, $2,326,691, and
$1,549,575 in 1998, 1997, and 1996, respectively, of capitalized interest on
unproved properties.

Results of Operations. The following table sets forth results of the
Company's oil and gas operations:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1998 1997 1996
------------ ------------ ------------
<S> <C> <C> <C>
Oil and gas sales.......................... $ 80,067,837 $ 69,015,189 $ 52,770,672
Oil and gas production costs............... (13,138,980) (8,778,876) (6,141,941)
Depreciation, depletion, and
amortization............................. (38,069,355) (23,443,273) (15,812,134)
Write-down of oil and gas properties....... (90,772,628) -- --
------------ ------------ ------------
(61,913,126) 36,793,040 30,816,597
Provision (benefit) for income taxes....... (21,236,202) 12,015,816 10,448,917
------------ ------------ ------------
Results of producing activities............ $(40,676,924) $ 24,777,224 $ 20,367,680
============ ============ ============
Amortization per physical unit of
production (equivalent Mcf of gas)....... $ 0.98 $ 0.92 $ 0.81
============ ============ ============
</TABLE>

Supplemental Reserve Information. The following information presents
estimates of the Company's proved oil and gas reserves, which are all located
onshore in the United States. All of the Company's reserves were determined by
the Company and audited by H. J. Gruy and Associates, Inc. ("Gruy"), independent
petroleum consultants. Gruy's summary report dated January 27, 1999, is set
forth as an exhibit to the Form 10-K Report for the year ended December 31,
1998, and includes definitions and

F-21
<PAGE> 70
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

assumptions that served as the basis for the estimates of proved reserves and
future net cash flows. Such definitions and assumptions should be referred to in
connection with the following information:

Estimates of Proved Reserves

<TABLE>
<CAPTION>
OIL AND
NATURAL GAS CONDENSATE
(MCF) (BBLS)
----------- ----------
<S> <C> <C>
Proved reserves as of December 31, 1995(1).................. 143,567,520 5,421,981
Revisions of previous estimates(2)........................ (9,544,391) (816,065)
Purchases of minerals in place............................ 2,676,393 97,178
Sales of minerals in place................................ (4,163,770) (340,706)
Extensions, discoveries, and other additions.............. 107,762,886 1,745,307
Production(3)............................................. (14,540,437) (623,386)
----------- ----------
Proved reserves as of December 31, 1996(1).................. 225,758,201 5,484,309
Revisions of previous estimates(2)........................ (22,774,899) (427,412)
Purchases of minerals in place............................ 30,342,398 580,278
Sales of minerals in place................................ (1,155,706) (50,909)
Extensions, discoveries, and other additions.............. 102,479,883 2,945,037
Production(3)............................................. (20,344,208) (672,385)
----------- ----------
Proved reserves as of December 31, 1997(1).................. 314,305,669 7,858,918
Revisions of previous estimates(2)........................ (42,958,447) (2,291,223)
Purchases of minerals in place............................ 54,189,901 7,237,298
Sales of minerals in place................................ (1,727,878) (39,932)
Extensions, discoveries, and other additions.............. 55,951,332 2,993,540
Production(3)............................................. (27,359,742) (1,800,676)
----------- ----------
Proved reserves as of December 31, 1998(1).................. 352,400,835 13,957,925
=========== ==========
Proved developed reserves,
December 31, 1995......................................... 81,532,025 3,313,226
December 31, 1996......................................... 135,424,880 3,622,480
December 31, 1997......................................... 191,108,214 4,288,696
December 31, 1998......................................... 197,105,963 7,142,566
</TABLE>

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

(1) Proved reserves exclude quantities subject to the Company's volumetric
production payment agreement.

(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, 1998, were based upon
prices of $2.23 per Mcf of natural gas and $11.23 per barrel of oil,
compared to $2.78 per Mcf and $15.76 per barrel as of December 31, 1997.

(3) Natural gas production for 1996, 1997, and 1998 excludes 1,156,361,
1,015,226, and 866,232 Mcf, respectively, delivered under the Company's
volumetric production payment agreement.

F-22
<PAGE> 71
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:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------
1998 1997 1996
------------- ------------- --------------
<S> <C> <C> <C>
Future gross revenues.......................... $ 972,852,038 $ 994,828,072 $1,141,831,786
Future production costs........................ (294,307,549) (273,475,056) (228,626,881)
Future development costs....................... (118,420,782) (92,946,811) (59,988,855)
------------- ------------- --------------
Future net cash flows before income taxes...... 560,123,707 628,406,205 853,216,050
Future income taxes............................ (123,875,660) (135,587,216) (211,375,632)
------------- ------------- --------------
Future net cash flows after income taxes....... 436,248,047 492,818,989 641,840,418
Discount at 10% per annum...................... (145,974,944) (199,980,649) (274,608,116)
------------- ------------- --------------
Standardized measure of discounted future net
cash flows relating to proved oil and gas
reserves..................................... $ 290,273,103 $ 292,838,340 $ 367,232,302
============= ============= ==============
</TABLE>

The standardized measure of discounted future net cash flows from
production of proved reserves was developed as follows:

1. Estimates are made of quantities of proved reserves and the future
periods during which they are expected to be produced based on year-end
economic conditions.

2. The estimated future gross revenues of proved reserves are priced
on the basis of year-end prices, except in those instances where fixed and
determinable gas price escalations are covered by contracts limited to the
price the Company reasonably expects to receive.

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

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

The estimates of cash flows and reserves quantities shown above are based
on year-end oil and gas prices for each period. Under Securities and Exchange
Commission rules, companies that follow the full-cost accounting method are
required to make quarterly Ceiling Test calculations, using prices in effect as
of the period end date presented (see Note 1). Application of these rules during
periods of relatively low oil and gas prices, even if of short-term seasonal
duration, may result in write-downs.

The standardized measure of discounted future net cash flows is not
intended to present the fair market value of the Company's oil and gas property
reserves. An estimate of fair value would also take into account, among other
things, the recovery of reserves in excess of proved reserves, anticipated
future changes in prices and costs, an allowance for return on investment, and
the risks inherent in reserve estimates.

F-23
<PAGE> 72
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:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1998 1997 1996
------------- ------------- ------------
<S> <C> <C> <C>
Beginning balance........................ $ 292,838,340 $ 367,232,302 $128,904,084
------------- ------------- ------------
Revisions to reserves proved in prior
years --
Net changes in prices, production
costs, and future development
costs............................... (107,301,930) (237,149,170) 145,661,994
Net changes due to revisions in
quantity estimates.................. (47,924,995) (27,188,512) (25,755,091)
Accretion of discount.................. 35,034,478 47,068,172 14,703,841
Other.................................. (34,966,058) (37,336,420) 7,609,227
------------- ------------- ------------
Total revisions.......................... (155,158,505) (254,605,930) 142,219,971
New field discoveries and extensions, net
of future production and development
costs.................................. 73,956,430 110,396,029 208,250,909
Purchases of minerals in place........... 87,628,829 29,290,334 6,835,362
Sales of minerals in place............... (1,928,900) (2,373,547) (8,084,581)
Sales of oil and gas produced, net of
production costs....................... (65,680,050) (58,786,505) (44,958,559)
Previously estimated development costs
incurred............................... 51,622,419 55,742,684 19,883,446
Net change in income taxes............... 6,994,540 45,942,973 (85,818,330)
------------- ------------- ------------
Net change in standardized measure of
discounted future net cash flows....... (2,565,237) (74,393,962) 238,328,218
------------- ------------- ------------
Ending balance........................... $ 290,273,103 $ 292,838,340 $367,232,302
============= ============= ============
</TABLE>

F-24
<PAGE> 73
SWIFT ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Quarterly Results. The following table presents summarized quarterly
financial information for the years ended December 31, 1997 and 1998:

<TABLE>
<CAPTION>
INCOME (LOSS) BASIC EARNINGS DILUTED EARNINGS
BEFORE INCOME NET INCOME (LOSS) (LOSS)
REVENUES TAXES (LOSS) PER SHARE(1) PER SHARE(1)
----------- ------------- ------------ -------------- ----------------
<S> <C> <C> <C> <C> <C>
1997
First Quarter........... $19,997,502 $ 10,161,045 $ 6,769,263 $ .41 $ .37
Second Quarter.......... 15,653,078 6,007,474 4,113,689 .25 .24
Third Quarter........... 17,895,979 7,024,524 4,685,689 .29 .27
Fourth Quarter.......... 21,165,621 9,936,563 6,741,548 .41 .37
----------- ------------ ------------
Total......... $74,712,180 $ 33,129,606 $ 22,310,189 $ 1.35 $ 1.26
=========== ============ ============
1998
First Quarter........... $16,475,229 $ 4,835,502 $ 3,229,615 $ .20 $ .20
Second Quarter.......... 16,340,730 4,270,153 2,896,470 .18 .18
Third Quarter(2)........ 24,557,553 (87,052,299) (57,431,015) (3.50) (3.50)
Fourth Quarter.......... 25,095,709 4,555,063 3,079,726 .19 .19
----------- ------------ ------------
Total......... $82,469,221 $(73,391,581) $(48,225,204) $(2.93) $(2.93)
=========== ============ ============
1999
First Quarter........... $21,488,087 $ 1,905,419 $ 1,281,755 $ .08 $ .08
Second Quarter.......... 23,928,734 4,786,405 3,152,027 .20 .20
----------- ------------ ------------
Total......... $45,416,821 $ 6,691,824 $ 4,433,782 $ .27 $ .27
=========== ============ ============
</TABLE>

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

(1) Amounts prior to the fourth quarter of 1997 have been retroactively restated
to give recognition to: (a) an equivalent change in capital structure as a
result of a 10% stock dividend in October 1997 (see Note 2 to the Company's
financial statements); and (b) the adoption of Statement of Financial
Accounting Standards No. 128, "Earnings per Share." See Note 2 to the
Company's financial statements.

(2) The loss in the third quarter of 1998 was the result of a pre-tax write-down
of oil and gas properties of $90.8 million ($59.9 million after tax). See
Note 1 to the Company's financial statements.

F-25
<PAGE> 74

PROSPECTUS
$275,000,000

[SWIFT ENERGY 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 these securities in supplements to this prospectus. The terms
of the securities 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. 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 9, 1999
<PAGE> 75

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

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
ABOUT THIS PROSPECTUS....................................... 3
WHERE YOU CAN FIND MORE INFORMATION......................... 3
FORWARD-LOOKING STATEMENTS.................................. 4
THE COMPANY................................................. 4
RATIO OF EARNINGS TO FIXED CHARGES.......................... 5
USE OF PROCEEDS............................................. 6
DESCRIPTION OF DEBT SECURITIES.............................. 6
General................................................... 6
Non U.S. Currency......................................... 7
Original Issue Discount Securities........................ 7
Covenants................................................. 8
Registration, Transfer, Payment and Paying Agent.......... 8
Ranking of Debt Securities................................ 9
Global Securities......................................... 9
Outstanding Debt Securities............................... 10
Redemption and Repurchase................................. 10
Conversion and Exchange................................... 10
Consolidation, Merger and Sale of Assets.................. 10
Events of Default......................................... 10
Modification and Waivers.................................. 12
Discharge, Termination and Covenant Termination........... 13
Governing Law............................................. 14
Regarding the Trustees.................................... 14
DESCRIPTION OF CAPITAL STOCK................................ 14
General................................................... 14
Common Stock.............................................. 14
Preferred Stock........................................... 15
Anti-takeover Provisions.................................. 16
DESCRIPTION OF DEPOSITARY SHARES............................ 18
DESCRIPTION OF WARRANTS..................................... 19
PLAN OF DISTRIBUTION........................................ 19
LEGAL OPINIONS.............................................. 21
EXPERTS..................................................... 21
</TABLE>

2
<PAGE> 76

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
$275,000,000. 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 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.

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,
1998;

2. Our Quarterly Report on Form 10-Q for the fiscal quarter ended
March 31, 1999;

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 John Alden, Senior Vice President, Swift Energy Company, Suite 400,
16825 Northchase Drive, Houston, Texas 77060, phone: (281) 874-2700.

3
<PAGE> 77

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;

- our year 2000 compliance program; 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, 1998.

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. Our primary
focus is on U.S. onshore natural gas reserves. As of December 31, 1998, we had
interests in over 1,750 oil and gas wells located in eight states. We operated
836 of these wells, representing 91% of our proved reserves base. At such date,
our estimated proved reserves were 436.1 Bcfe, of which approximately 81% was
natural gas, with 84% of our reserves located in Texas and 13% in Louisiana.

Our core areas for development and exploration drilling are the AWP Olmos
Field located in South Texas and the Austin Chalk trend in Texas and Louisiana.
We expect the reserves on 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 51% of our proved reserves as of December 31, 1998 and
approximately 40% of our 1998 production, while the Austin Chalk trend accounted
for approximately 42% of our proved reserves as of December 31, 1998 and
generated approximately 48% of our 1998 production.

4
<PAGE> 78

We have increased our proved reserves from 90.1 Bcfe at year-end 1993 to
436.1 Bcfe at year-end 1998, which represents the replacement of 449% of the
production during the same period. Our five-year average reserves replacement
costs were $0.88 per Mcfe. The combination of increased production and decreased
operating costs per Mcfe resulted in average annual growth in net cash provided
by operating activities of 50% per year from 1993 to 1998.

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.

Over the last several years, we have grown primarily by increasing our
acreage position and through drilling activities in the AWP Olmos Field and the
Austin Chalk trend. Capital expenditures for development and exploration
drilling were $71.8 million in 1996 and $101.0 million in 1997, while the
amounts spent for acquisitions were $1.5 million in 1996 and $8.4 million in
1997. Following the fall in oil and gas prices during mid-1998, we decreased
amounts spent for drilling and increased funds spent to acquire producing
properties, primarily the Toledo Bend Properties in Texas and Louisiana
purchased from Sonat Exploration Company. Consequently, in 1998 drilling
expenditures were concentrated in the first half of 1998, totaling $67.4
million, while $59.5 million was spent to acquire producing properties,
primarily in the third quarter.

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:

<TABLE>
<CAPTION>
THREE MONTHS
ENDED
YEARS ENDED DECEMBER 31, MARCH 31,
--------------------------------- -------------
1994 1995 1996 1997 1998 1998 1999
---- ---- ----- ---- ---- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C>
Ratio of earnings to fixed charges............. 2.6x 3.1x 12.8x 5.2x -- 2.9x 1.3x
</TABLE>

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.

5
<PAGE> 79

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.

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";

6
<PAGE> 80

- 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.

7
<PAGE> 81

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

8
<PAGE> 82

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.

9
<PAGE> 83

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;

10
<PAGE> 84

- 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.

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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;

- 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;

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- 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.

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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
40,000,000 shares of stock, including up to 35,000,000 shares of common stock
and up to 5,000,000 shares of preferred stock. As of June 15, 1999, we had
16,176,699 shares of common stock and no shares of preferred stock outstanding.
As of that date, we also had approximately 3,168,697 shares of common stock
reserved for issuance upon exercise of options or in connection with other
awards outstanding under various employee or director incentive, compensation
and option plans. There are an additional 3,646,847 shares of common stock
reserved for issuance upon conversion of our 6.25% Convertible Subordinated
Notes due November 15, 2006.

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

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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

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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 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
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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.

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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;

- 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.
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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.

PLAN OF DISTRIBUTION

We 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;
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- 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.

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
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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 included in this prospectus have been
audited by Arthur Andersen LLP, independent public accountants, as indicated in
their report with respect thereto, is included 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 & Associates, Inc., independent
petroleum engineers.

21
<PAGE> 95

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4,000,000 SHARES

SWIFT ENERGY COMPANY

COMMON STOCK
[SWIFT ENERGY LOGO]

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PROSPECTUS SUPPLEMENT

, 1999

(INCLUDING PROSPECTUS DATED JULY 9, 1999)

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SALOMON SMITH BARNEY

CIBC WORLD MARKETS

CREDIT SUISSE FIRST BOSTON

DAIN RAUSCHER WESSELS
A DIVISION OF DAIN RAUSCHER INCORPORATED

JEFFERIES & COMPANY, INC.
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