SWIFT ENERGY CO, 10-K405, 1998-03-24

SWIFT ENERGY CO
10-K405, 1998-03-24
CRUDE PETROLEUM & NATURAL GAS

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<PAGE>

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 1997

Commission File Number 1-8754

SWIFT ENERGY COMPANY
(Exact Name of Registrant as Specified in Its Charter)

Texas 74-2073055
(State of Incorporation) (I.R.S. Employer Identification No.)

16825 Northchase Dr., Suite 400
Houston, Texas 77060
(281) 874-2700
(Address and telephone number of principal executive offices)

Securities registered pursuant to Section 12(b) of the Act:

Title of Class: Exchanges on Which Registered:
Common Stock, par value $.01 per share New York Stock Exchange
Pacific Stock Exchange

Convertible Subordinated Notes Due 2006 New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months and (2) has been subject to such filing requirements for
the past 90 days. Yes x No
---- ----

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]

The aggregate market value of the voting stock held by non-affiliates at March
10, 1998 was approximately $275,948,000.

The number of shares of common stock outstanding as of December 31, 1997 was
16,459,156 shares of common stock, $.01 par value.

Documents Incorporated by Reference

Document Incorporated as to

Notice and Proxy Statement for the Annual Part III, Items 10, 11, 12, and 13
Meeting of Shareholders to be held May 12,
1998.

<PAGE>

Form 10-K
Swift Energy Company and Subsidiaries
<TABLE>
<CAPTION>
10-K Part and Item No. Page
- ---------------------- ------
<S> <C> <C>
Part I
Item 1. Business 3

Item 2. Properties 3

Item 3. Legal Proceedings 12

Item 4. Submission of Matters to a Vote of
Security Holders 12

Part II
Item 5. Market for the Registrant's Common
Equity and Related Stockholder
Matters 12

Item 6. Selected Financial Data 13

Item 7. Management's Discussion and
Analysis of Financial Condition
and Results of Operations 15

Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 19

Item 8. Financial Statements and Supple-
mentary Data 19

Item 9. Changes in and Disagreements with
Accountants on Accounting and
Financial Disclosure 35

Part III
Item 10. Directors and Executive Officers of
the Registrant (1) 35

Item 11. Executive Compensation (1) 35

Item 12. Security Ownership of Certain Bene-
ficial Owners and Management (1) 35

Item 13. Certain Relationships and Related
Transactions (1) 35

Part IV
Item 14. Exhibits, Financial Statement
Schedules and Reports on Form 8-K 36
</TABLE>

The statements contained in this Annual Report on Form 10-K ("Annual
Report") that are not historical facts are forward-looking statements as that
term is defined in Section 21E of the Securities and Exchange Act of 1934, as
amended, and therefore involve a number of risks and uncertainties. Such
forward-looking statements may be or may concern, among other things, capital
expenditures, drilling activity, development activities, cost savings,
production efforts and volumes, hydrocarbon reserves, hydrocarbon prices,
liquidity, regulatory matters, and competition. Such forward-looking statements
generally are accompanied by words such as "plan," "budget," "estimate,"
"expect," "predict," "anticipate," "projected," "should," "believe," or other
words that convey the uncertainty of future events or outcomes. Such
forward-looking information is based upon management's current plans,
expectations, estimates and assumptions and is subject to a number of risks and
uncertainties that could significantly affect current plans, anticipated
actions, the timing of such actions and the Company's financial condition and
results of operations. As a consequence, actual results may differ materially
from expectations, estimates or assumptions expressed in or implied by any
forward-looking statements made by or on behalf of the Company, including those
regarding the Company's financial results, levels of oil and gas production or
revenues, capital expenditures, and capital resource activities. Among the
factors that could cause actual results to differ materially are: fluctuations
of the prices received or demand for the Company's oil and natural gas; the
uncertainty of drilling results and reserve estimates; operating hazards;
requirements for capital; general economic conditions; competition and
government regulations; as well as the risks and uncertainties discussed in this
Annual Report, including, without limitation, the portions referenced above and
the uncertainties set forth from time to time in the Company's other public
reports, filings, and public statements. Also, because of the volatility in oil
and gas prices and other factors, interim results are not necessarily indicative
of those for a full year.
- --------------------------
(1)Incorporated by reference from Notice and Proxy Statement for the Annual
Meeting of Shareholders to be held May 12, 1998.

<PAGE>

PART I

Items 1 and 2. Business and Properties

See pages 11 and 12 for explanations of abbreviations and terms used
herein.

General

Swift Energy Company (the "Company"), a Texas corporation organized in
October 1979, is engaged in the exploration, development, acquisition, and
operation of oil and gas properties, with a primary focus on U.S. onshore
natural gas reserves. As of December 31, 1997, the Company had interests in over
1,500 oil and gas wells located in 10 states, with 93% of its proved reserves
base concentrated in Texas. At the same date, the Company had estimated proved
reserves of 361.5 Bcfe, approximately 87% of which were natural gas, and
operated 650 wells representing 91% of its proved reserves base.

The Company's primary focus is exploration and development drilling in its
core areas, the AWP Olmos Field located in South Texas and the Texas Austin
Chalk trend. The AWP Olmos Field is characterized by long-lived reserves, while
the Austin Chalk trend is characterized by more short-lived reserves with high
initial production and rapid decline rates. These fields accounted for
approximately 74% and 15%, respectively, of the Company's proved reserves as of
December 31, 1997, and approximately 61% and 19%, respectively, of the Company's
production during 1997. The Company has substantially accelerated its drilling
activities during the last several years, drilling 42, 116, and 135 net wells in
1995, 1996, and 1997, respectively, primarily in these areas. During 1996, the
Company doubled its acreage position in the AWP Olmos Field and quadrupled it in
the Austin Chalk trend. In 1997, the Company increased slightly its acreage
position in the AWP Olmos Field and increased its acreage position in the Austin
Chalk trend by approximately 50%. The Company has budgeted capital expenditures
of $154.8 million for 1998, of which approximately 73% is targeted for these two
fields. The Company is also actively pursuing exploratory and development
drilling opportunities in other basins in Texas, Arkansas, Louisiana, and
Wyoming. As a complement to these domestic activities, the Company is
participating in several high potential international projects with limited
capital exposure to the Company in New Zealand, Russia, and Venezuela.

The Company has increased its proved reserves from 59.0 Bcfe at year end
1992 to 361.5 Bcfe at year end 1997, primarily from additions through the
drillbit, which has resulted in the replacement of 554% of production during the
same five-year period. In 1997, the Company increased its proved reserves by
40%, resulting in the replacement of 522% of 1997 production. The Company's
five-year average reserves replacement costs were $0.76 per Mcfe. As a result of
increased drilling activity, 1997 production increased 31% over 1996 production.
Due to economies of scale, geographic concentration, and increased production,
general and administrative expenses and production costs have fallen from $0.88
and $0.69 per Mcfe in 1992 to $0.24 and $0.45 per Mcfe, respectively, for 1997.
The combination of increased production and decreased operating costs per Mcfe
has resulted in average annual growth in net cash provided by operating
activities of 54% per year from year end 1992 to year end 1997. For 1997, due to
these same production and operating cost factors, net cash provided by operating
activities increased to $55.3 million or 49% over the same period in 1996.

Properties

The Company's proved reserves are geographically concentrated, with
approximately 89% of the Company's proved reserves at December 31, 1997,
attributable to its two largest properties, the AWP Olmos Field and the Austin
Chalk trend.

AWP Olmos Field. The Company's most significant property is located in the
AWP Olmos Field in South Texas. The Company has extensive expertise in the AWP
Olmos Field and a long history of experience with low-permeability tight-sand
formations typical of this field. Since acquiring its first AWP Olmos Field
acreage in 1988, the Company has made detailed studies of drainage patterns in
the formation and has introduced innovations in fracture design and
implementation methods and coiled tubing technology that substantially reduce
overall costs and improve recoveries.

The AWP Olmos Field represented approximately 74% of the Company's proved
reserves at December 31, 1997, and approximately 61% of the Company's 1997
production. At December 31, 1997, the Company owned interests in and was the
operator of approximately 400 wells producing natural gas from the Olmos Sand
Formation at a depth of approximately 10,000 feet. The Company has engaged in
extensive fracturing operations to increase the permeability of the formation
and flow of gas from the wells. In addition, the Company has used coiled tubing
velocity strings in several wells to improve production rates. Also, by
utilizing a system of BJ Services, Inc., the Company is able to monitor
fracturing operations from its Houston headquarters through direct computer
access to the field.

During 1997, the Company purchased, for approximately $3.8 million, Olmos
producing properties strategically located in the heart of its existing
leasehold in the AWP Olmos Field. The purchase included 35 producing wells, 35
new development drilling locations, and a related 20-mile pipeline. Net proved
reserves attributable to the purchase are approximately 25 Bcfe, with current
production of approximately 2,000 Mcfe per day.

In 1997, the Company drilled 142 (137 successful) development wells in this
field and one unsuccessful exploratory well northwest of the field. The Company
or entities managed by the Company own 100% of the working interest in this
field. During 1997, the Company maintained its leasehold position in this area.
The Company anticipates continuing its acquisition of acreage in this area in
the future, if warranted. The Company plans to drill approximately 57 additional
development wells and four exploratory wells to the Olmos formation in 1998.

Austin Chalk Trend. At December 31, 1997, the Company owned drilling and
production rights in 175,022 gross acres and 112,918 net acres in the Austin
Chalk trend containing substantial proved undeveloped reserves. The Austin Chalk
trend represented approximately 15% of the Company's proved reserves at December
31, 1997. Production from this field constituted 19% of oil and gas production
in 1997. The wells in this trend are all horizontally produced wells, primarily
natural gas, that deliver high initial flow rates and strong initial cash flows
which decline rapidly. The Company believes these reserves complement its
long-lived reserves in the AWP Olmos Field. Since 1992, the Company has
participated in 55 horizontal wells in the trend with a 91% success rate,
including in 1997 16 successful development wells out of 17 drilled and two
successful exploratory

<PAGE>

wells out of five drilled. The Company believes its success is attributable to
its ability to identify hydrocarbon-bearing fractures, relying on its expertise
in seismic data analysis, and its ability to drill and operate horizontal wells.
The Company anticipates drilling 30 development wells and three exploratory
wells in the Austin Chalk during 1998. The acquisition of seismic data in the
Cougar Run and Nimitz areas in Fayette County has helped in upgrading locations
to drill numerous horizontal wells targeting the Austin Chalk formation
determined from previous seismic data acquisitions and subsequent successful
drilling in the Rocky Creek and North Fayetteville prospects.

Substantial portions of its property interests in the Austin Chalk trend
have been acquired through joint development arrangements with industry partners
who are active participants in exploration of the Austin Chalk trend, beginning
in 1993 in an arrangement that covered approximately 8,800 acres in which the
Company currently has an average working interest of 25%. In September 1995, the
Company entered into another joint development agreement providing for an area
of mutual interest covering 19,500 gross acres and pursuant to which that
industry partner and the Company alternate serving as operator of any wells
drilled on the acreage. During 1996, the Company purchased its partner's
interest in 9,500 of these gross acres, and the joint development arrangement
now covers a 10,000 gross acre block in which the Company expects to have an
average working interest of 30% to 35% based on certain assumptions relating to
elections with respect to the drilling of various wells. The Company has a 100%
working interest in the 9,500 acres.

In 1996, a joint development arrangement covering approximately 8,000 acres
in Washington County, Texas, in which the Company owns a 25% working interest,
was reached with an industry partner. This joint development area has been
further expanded to encompass approximately 17,000 gross acres. Simultaneously,
the Company entered into two additional joint development agreements covering an
approximate 6,300 gross acre area, in which the Company owns a 50% working
interest, and an approximate 8,100 gross acre area, in which the Company owns a
75% working interest and serves as operator.

Also in 1997, the Company acquired a 50% working interest in 20,000 net
acres adjoining the N. Fayetteville Prospect area for which it will serve as
operator. The initial test well was spudded in December 1997.

Exploration and Development Drilling Activities

In 1991, the Company began to develop an inventory of exploration and
development drilling prospects. Drilling locations were selected through
intensive geological and geophysical studies of the Company's undeveloped
acreage and other prospects. During 1995, the Company added 72 Bcfe of proved
reserves through drilling, and in 1996, reserves added by drilling increased to
118 Bcfe. In 1997, reserves added by drilling increased to 120 Bcfe, with the
Company's success rate 47% for exploratory wells (7 out of 15 drilled) and 95%
for development wells (159 out of 167 drilled). These successful drilling
results have led to acquisition of additional acreage during 1997 in the area of
its two core properties, the AWP Olmos Field in South Texas and the Austin Chalk
trend in Austin, Colorado, Fayette, Walker, and Washington counties in central
and eastern Texas.

The Company pursues a "controlled risk" approach to exploratory drilling.
The Company focuses its exploration activities on specific U.S. regions where
its technical staff has considerable experience and which are in close proximity
to known producing horizons where the potential for significant reserves exists.
The Company seeks to minimize its exploration risk by investing in multiple
prospects, farming out interests to industry partners and drilling funds,
utilizing advanced technologies, and drilling in different types of geological
formations. The Company utilizes basin studies to analyze targeted formations
based on their potential size, risk profile, economic parameters, and activity
in the trend.

The Company's development strategy is designed to maximize the value and
productivity of its existing properties through development drilling and
recovery methods, enhancing production results through improved field production
techniques, lowering production costs, and applying the Company's technical
expertise and resources to exploit producing properties efficiently. The Company
employs various recovery techniques, which include water flooding, fracturing
reservoir rock through the injection of high-pressure fluid, inserting coiled
tubing velocity strings to speed gas flow, and acid treatments. The Company
believes that the application of fracturing technology and coiled tubing has
resulted in significant increases in production and decreases in drilling and
operating costs, particularly in the Company's largest single property, the AWP
Olmos Field.

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

The Company has increasingly utilized advanced seismic technology to
enhance the quality of its drilling efforts, including two-dimensional (2-D) and
three-dimensional (3-D) seismic analysis and amplitude versus offset (AVO)
studies. During 1997, the Company completed its first international seismic
acquisition program in two key areas of its holding in New Zealand. In the Rimu
prospect, Swift acquired a 30 kilometer cross-swath, as well as 2-D seismic data
in the Tawa prospect, complementing existing 2-D and 3-D data. It also acquired
21 miles of 2-D data in the Wheeler Ranch Olmos trend in South Texas and 51
miles of data in the Fayette County Austin Chalk trend. Two more prospects in
the Ark-La-Tex region were shot in the form of 2-D swaths of approximately 16
miles each.

In addition to exploration and development activities in the AWP Olmos
Field and the Austin Chalk trend, the Company is currently focusing its
exploration activities in three main geographical areas: the Gulf Coast Basin,
the Wyoming Powder River Basin, and the North Louisiana Salt Basin.

Gulf Coast Basin. The Company defines this area as including all the Texas
counties and Louisiana parishes along the Gulf Coast and extending into
Mississippi and Alabama, which includes all target formations present except the
Austin Chalk trend and the Olmos sand. In 1997, one successful development well
(out of three) and four successful exploratory wells (out of six) were drilled
in the Gulf Coast Basin, following one successful exploratory well and two
successful development wells drilled in 1996. In 1998, seven exploratory wells
and 18 development wells are scheduled for drilling in the Gulf Coast Basin. The
locations were selected utilizing traditional geologic studies combined with
analyses of available seismic data.

<PAGE>

During 1997, the Company acquired 1,920 gross acres in Jim Hogg County in
which the Company owns a minimum 75% working interest. Additionally, the Company
has an oil and gas lease option on an additional 8,500 gross acres until August
1, 1998. A well drilled by the Company to the Queen City formation, the
Chapparral #1, in 1997 was highly successful. Of the 18 development wells
expected to be drilled in the Gulf Coast Basin in 1998, 10 will be drilled on
this acreage. Two of those 10 have already been successfully drilled in the
first quarter of 1998, with the third well currently being drilled. Further work
in the area through licensing additional 2-D data and acquiring 3-D data jointly
with a third party will help complete the analysis and the interpretation of the
acreage for future development in 1998.

In the North Creole prospect in southern Louisiana, the Company has worked
2-D and 3-D seismic data in conjunction with the Vertical Seismic Profile it
shot in early 1997 to identify development and exploratory locations of deep
high-potential targets to be drilled in the first quarter of 1998. Additional
3-D seismic grids are being quality checked for eventual licensing in the area
to help in the interpretation of the complex geologic features.

In the Sherburne prospect in south central Louisiana, the Company has been
working with 2-D seismic data to identify the location of a Sparta formation
test slated for the first quarter of 1998 and has designed a 2-D seismic
cross-swath to be acquired commencing in March 1998 to identify deeper
high-yield structures in the Wilcox trend.

Wyoming Powder River Basin. The Company intends to drill three exploratory
wells and eight development wells in 1998. In 1997, the Company successfully
drilled one out of two exploratory wells in the Minnelusa trend in Campbell
County, Wyoming. In 1996, the Company successfully drilled one out of three
exploratory wells and one out of three development wells in this trend. The
Minnelusa trend has been the subject of extensive study by the Company's
multidisciplinary teams in order to identify the location of stratigraphic
hydrocarbon traps. Recently, the Company has shifted its emphasis to pursue the
Cretaceous trend in southern Campbell County and northern Converse County in
Wyoming, as well as north into the Williston Basin in Daniels County, Montana.
This shift is due to the Company's commitment to find larger reserve
accumulations at a lower risk by drilling in areas with multiple producing zones
and larger field sizes. The Company has licensed various existing 2-D seismic
data to help map the structural and stratigraphic traps that have been
identified for drilling in 1998.

North Louisiana Salt Basin. The North Louisiana Salt Basin covers the
neighboring corners of Arkansas, Louisiana, and Texas (Ark-La-Tex region). In
1997, the Company drilled two wells, one exploratory and one development, with
the development well being successful, following five successful wells drilled
in 1996, four of which were exploratory. The Company plans to drill four
exploratory wells in the region in 1998. In this area, the Smackover formation
is a prolific hydrocarbon producer from multiple levels and from a variety of
structures, including fault traps, salt anticlines, basement structures, and
stratigraphic traps. In northern Louisiana and southern Arkansas in the
Smackover trend, in 1997 the Company acquired and completed processing two sets
of 2-D seismic swaths that have been interpreted to yield numerous exploratory
locations slated for testing in the first half of 1998. Additional seismic
acquisitions are planned in Bossier Parish, Louisiana, to delineate a prospect
pending the drilling of a test well to determine the presence of hydrocarbon
sands in the area.

The following table sets forth the results of the Company's drilling
activities during the three fiscal years ended December 31, 1997:

Gross Wells Net Wells
-------------------------- ---------------------------
Year Type of Well Total Producing Dry Total Producing Dry
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
1995 Exploratory 8 4 4 3.5 1.5 2.0
Development 68 65 3 38.7 38.0 0.7

1996 Exploratory 11 7 4 5.9 3.7 2.2
Development 142 134 8 110.5 106.7 3.8

1997 Exploratory 15 7 8 7.2 2.7 4.5
Development 167 159 8 127.5 123.6 3.9
</TABLE>

Operations

The Company generally seeks to be named as operator for wells in which it
or its affiliated limited partnerships and joint ventures have acquired a
significant interest, although this typically occurs only when they own the
major portion of the working interest in a particular well or field. The Company
acts as operator of approximately 650 wells at December 31, 1997, which comprise
approximately 91% of the Company's total proved reserves.

As operator, the Company is able to exercise substantial influence over
development and enhancement of a well and to supervise operation and maintenance
activities on a day-to-day basis. The Company does not conduct the actual
drilling of wells on properties for which it acts as operator. Drilling
operations are conducted by independent contractors engaged and supervised by
the Company. The Company employs petroleum engineers, geologists, and other
operations and production specialists who strive to improve production rates,
increase reserves, and/or lower the cost of operating its oil and gas
properties.

Oil and gas properties are customarily operated under the terms of a joint
operating agreement, which provides for reimbursement of the operator's direct
expenses and monthly per-well supervision fees. Per-well supervision fees vary
widely depending on the geographic location and producing formation of the well,
whether the well produces oil or gas, and other factors. Such fees received by
the Company in 1997 ranged from $200 to $1,481 per well per month.

Marketing of Production

The Company typically sells its gas production at or near the wellhead,
although in some cases it must be gathered by the Company or other operators and
delivered to a central point. Gas production is generally sold in the spot
market at prevailing prices. The Company generally sells its oil production at
prevailing market prices. The Company does not refine any oil it produces.

<PAGE>

During the year ended December 31, 1997, three oil or gas purchasers each
accounted for 10% or more of the Company's revenues, with those purchasers
together accounting for 42%. Three oil or gas purchasers accounted for 10% or
more of the Company's revenues during the year ended December 31, 1996, with
those purchasers accounting for approximately 51%. Because of the availability
of other purchasers, the Company does not believe that the loss of any single
oil or gas purchaser or contract would materially affect its sales.

The Company has entered into gas processing and gas transportation
agreements with respect to its natural gas production in the AWP Olmos Field
with Valero Transmission, L.P. and its affiliates ("Valero") for up to 75,000
Mcf per day. These contracts have initial six-year terms, with automatic
one-year extensions unless earlier terminated. The Company believes that these
arrangements adequately provide for its gas transportation and processing needs
in the AWP Olmos Field for the foreseeable future. Additionally, at the
discretion of the Company and Valero, the gas processed and transported under
these agreements may be sold to Valero at monthly indexed prices based upon the
current natural gas price. Effective July 31, 1997, Valero was merged with
Pacific Gas & Electric Corporation ("PG&E"). This merger did not affect the
contractual obligations between the Company and Valero.

Much of the Company's Austin Chalk production from Fayette and Washington
counties, Texas, is currently dedicated under long-term gas purchase and gas
processing contracts with Aquila Southwest Pipeline Corporation ("Aquila"). The
Company believes that these contracts adequately provide for the gas purchase
and processing needs of its Austin Chalk production, subject to practical
limitations inherent in gas field operations. The prices received are
redetermined monthly to reflect the current natural gas price.

The following table summarizes sales volumes, sales prices, and production
cost information for the Company's net oil and gas production for the three-year
period ended December 31, 1997. "Net" production is production that is owned by
the Company either directly or indirectly through partnerships or joint venture
interests and produced to its interest after deducting royalty, limited partner,
and other similar interests.

<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------------------
1997 1996 1995
------------------- ----------------------- ------------------
<S> <C> <C> <C>
Net Sales Volume:
Oil (Bbls) 672,385 623,386 545,435
Gas (Mcf)(1) 21,359,434 15,696,798 7,913,963
Gas equivalents (Mcfe) 25,393,744 19,437,114 11,186,573
Average Sales Price:
Oil (Per Bbl) $ 17.59 $ 19.82 $ 15.66
Gas (Per Mcf) $ 2.68 $ 2.57 $ 1.77
Average Production Cost (per Mcfe) $ 0.45 $ 0.43 $ 0.61
</TABLE>

(1) Natural gas production for 1997, 1996, and 1995 includes 1,015,226,
1,156,361, and 1,211,255 Mcf, respectively, delivered under the volumetric
production payment agreement pursuant to which the Company is obligated to
deliver certain monthly quantities of natural gas (see Note 1 to the Company's
financial statements).

Under the volumetric production payment entered into in 1992, as of
December 31, 1997, the Company has a remaining commitment to deliver
approximately 2.0 Bcf of gas meeting certain heating equivalent and quality
standards through October 2000, when such agreement expires. Since entering into
this agreement, these properties have produced in excess of the required monthly
delivery requirements.

Price Risk Management

The Company's revenues are primarily the result of sales of its oil and
natural gas production. Market prices of oil and natural gas may fluctuate and
adversely affect operating results. To mitigate some of this risk, the Company
does engage periodically in certain limited hedging activities, but only to the
extent of buying protection price floors for portions of its and the limited
partnerships' oil and gas production. Costs and/or benefits derived from these
price floors are accordingly recorded as a reduction or increase, as applicable,
in oil and gas sales revenue and were not significant for any year presented.
The costs to purchase put options are amortized over the option period.

During 1997, the Company entered into oil and natural gas price hedging
contracts covering a portion of the Company's and its affiliated partnerships'
oil and natural gas production. For January, 1,400,000 MMBtu of the natural gas
production was covered, providing for a minimum price of $1.90 per MMBtu.
February was covered for 2,000,000 MMBtu of natural gas, and March and April
were covered for 1,500,000 MMBtu of natural gas, each at a minimum price of
$2.00. For the months of May, June, July, and August, 1,500,000 MMBtu was
covered, providing for a minimum price of $1.80. September, October, and
November had two contracts each month with each separate contract covering
1,500,000 MMBtu of natural gas, providing for minimum prices of $1.80 and $1.90
in September, $1.85 and $1.90 in October, and $1.90 and $2.00 in November.

For the months of January, February, and March, 140,000 Bbls of oil
production were covered, with 70,000 Bbls each month providing for a minimum
price of $17.00 and the other 70,000 Bbls each month providing for a minimum
price of $20.00 per Bbl. April, May, and June were covered for 140,000 Bbls of
oil production at a minimum price of $20.00 in April and May, while June
provided for a minimum price of $19.00. July was covered for 60,000 Bbls of
production at a minimum price of $18.00 and for 60,000 Bbls at a minimum price
of $19.00. August was covered for 120,000 Bbls of production, providing for a
minimum price of $19.00. For the months of September through December, 60,000
Bbls of oil production were covered, providing for a minimum price of $18.00.
Costs related to 1997 hedging activities totaled approximately $1,052,000 with
benefits of approximately $439,000 being received, resulting in a net cash
outlay of approximately $613,000 or $0.014 per Mcfe.

The Company had three open contracts at December 31, 1997, covering
1,500,000 MMBtu of the natural gas

<PAGE>

production for February 1998 at a minimum price of $2.00, 500,000 MMBtu of gas
in March 1998 at a minimum price of $1.90, and 60,000 Bbls of oil production for
February providing for a minimum price of $18.00 per Bbl. The costs related to
the open contracts totaled $95,308 and had a market value of $121,600 as of
December 31, 1997.

Acquisition Activities

Since 1979, the Company has acquired approximately $478.0 million of
producing oil and natural gas properties on behalf of itself and its
co-investors in 129 separate transactions. In recent years, the Company's
acquisition activities have declined, as it has fulfilled its obligation to buy
producing properties for the remaining partnerships which invested in such
properties. As of December 31, 1997, all such partnerships investing in
producing properties had spent their available capital resources on producing
properties. Therefore, the Company anticipates all future acquisition activity
will be for its own behalf. The Company has acquired for its own account
approximately $121.5 million of producing properties, with original proved
reserves estimated at 182.2 Bcfe. The Company's acquisition expenditures the
past three years were approximately $3.5 million, $1.5 million, and $8.4 million
of properties acquired in 1995, 1996, and 1997, respectively. The Company's
acquisition costs have averaged $0.31 per Mcfe over this three-year period.

The Company uses a disciplined, market-driven approach to acquisitions. The
Company generally seeks acquisition of properties for its own account that are
in close proximity to its current reserves and provide the potential to add
reserves and production through additional development efforts.

Foreign Activities

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 $300,000. In May 1995, the Company executed a Management Agreement
with Senega, under which, in return for undertaking to obtain financing for
development of these fields, Swift would be entitled to receive a 49% interest
in production income derived by Senega from this project after repayment of
costs.

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

Venezuela. The Company formed a wholly-owned subsidiary, Swift Energy de
Venezuela, C. A., for the purpose of submitting a bid on August 5, 1993, under
the Venezuelan Marginal Oil Field Reactivation Program. Although the Company did
not win the bid, it has continued to pursue cooperative ventures involving other
fields and opportunities in Venezuela. The Company evaluated a number of Blocks
being offered by Petroleos de Venezuela, S. A. under the Third Operating
Agreement Round in 1997, but decided against submitting any bid on these Blocks.
The Company has entered into an agreement with Tecnoconsult, S. A. a Venezuelan
company, to jointly formulate and submit a proposal to Petroleos de Venezuela,
S. A. for the construction and operation of a methane pipeline. Currently, the
technical and economic feasibility of the project is under study. At December
31, 1997, the Company's investment in Venezuela was approximately $2,435,000 and
is included in the unproved properties portion of oil and gas properties, net of
impairments of $45,668.

New Zealand. Since October 1995, the Company has been issued two Petroleum
Exploration Permits by the New Zealand Minister of Energy. The first permit
covers approximately 65,000 acres in the Onshore Taranaki Basin of New Zealand's
North Island, and the second covers approximately 69,300 adjacent acres. Under
the terms of these permits, the Company is obligated to analyze and interpret
certain seismic data, acquire certain new seismic data and drill one exploratory
well, to be followed by a development well or additional seismic work, all of
which is to be performed on a staged basis in order to maintain the permits,
over periods extending through July 2000 for the first permit and August 1999
for the second permit. The Company formed a wholly-owned subsidiary, Swift
Energy New Zealand Limited, for the purpose of conducting its New Zealand
activities and assigned its interest in the permits to that subsidiary during
the third quarter of 1997. At December 31, 1997, the Company's investment in New
Zealand was approximately $2,480,000 and is included in the unproved properties
portion of oil and gas properties.

Oil and Gas Reserves

The following table presents information regarding proved reserves of oil
and gas attributable to the Company's interests in producing properties as of
December 31, 1997, 1996, and 1995. The information set forth in the table is
based on proved reserves reports prepared by the Company and audited by H. J.
Gruy and Associates, Inc., Houston, Texas, independent petroleum engineers.
Gruy's estimates were based upon review of production histories and other
geological, economic, ownership, and engineering data provided by the Company.
In accordance with Securities and Exchange Commission guidelines, the Company's
estimates of future net revenues from the Company's proved reserves and the
PV-10 Value are made using oil and gas sales prices in effect as of the dates of
such estimates and are held constant throughout the life of the properties,
except where such guidelines permit alternate treatment, including, in the case
of gas contracts, the use of fixed and determinable contractual price
escalations. Proved reserves as of December 31, 1997, were estimated based upon
weighted average prices of $2.78 per Mcf of natural gas and $15.76 per barrel of
oil, compared to $4.47 and $2.41 per Mcf of natural gas and $23.75 and $18.07
per barrel of oil as of December 31, 1996 and 1995, respectively. The Company
has interests in certain tracts that are estimated to have additional
hydrocarbon reserves that cannot be classified as proved and are not reflected
in the following table. The proved reserves presented for all periods also
exclude any reserves attributable to the volumetric production payment.

<PAGE>

<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------------
1997 1996 1995
------------------ ----------------- -----------------
<S> <C> <C> <C>
Estimated Proved Oil and Gas Reserves

Net natural gas reserves (Mcf):
Proved developed 191,108,214 135,424,880 81,532,025
Proved undeveloped 123,197,455 90,333,321 62,035,495
----------------- ---------------- -----------------
Total 314,305,669 225,758,201 143,567,520
================= ================ =================
Net oil reserves (Bbl):
Proved developed 4,288,696 3,622,480 3,313,226
Proved undeveloped 3,570,222 1,861,829 2,108,755
----------------- ---------------- -----------------
Total 7,858,918 5,484,309 5,421,981
================= ================ =================

Estimated Present Value of Proved Reserves

Estimated present value of future net cash flows from
proved reserves discounted at 10% per annum:
Proved developed $ 244,365,044 $ 310,408,949 $ 85,536,873
Proved undeveloped 105,979,738 160,776,008 61,501,536
----------------- ---------------- -----------------
Total $ 350,344,782 $ 471,184,957 $ 147,038,409
================= ================ =================
</TABLE>

The table also sets forth estimates of future net revenues presented on the
basis of unescalated prices and costs in accordance with criteria prescribed by
the Securities and Exchange Commission and their PV-10 Value. Operating costs,
development costs, and certain production-related taxes were deducted in
arriving at the estimated future net revenues. No provision was made for income
taxes. The estimates of future net revenues and their present value differ in
this respect from the standardized measure of discounted future net cash flows
set forth in Supplemental Information to the Consolidated Financial Statements
of the Company, which is calculated after provision for future income taxes. In
cases where producing properties are subject to gas purchase contracts and the
amount of gas purchased thereunder was reduced during 1997, gas projections used
to estimate future net revenues were based on the reduced gas purchases for the
affected producing properties. The assumption was made that purchases in 1998
and thereafter will be made at an unrestricted level.

The Company's total proved developed and undeveloped reserves have
increased substantially (40%) at December 31, 1997, when compared to December
31, 1996, as shown above and in Supplemental Information to the Company's
financial statements. A substantial portion (40%) of the reserves are proved
undeveloped reserves. This reflects the increased emphasis on exploration and
development activities. This was consistent with the proportions in 1996 of 39%
proved undeveloped and 61% proved developed and reflects the continued emphasis
on exploration and development activities.

Changes in quantity estimates and the estimated present value of proved
reserves are affected by the change in crude oil and natural gas prices at the
end of each year. While the Company's total proved reserves quantities (on an
equivalent Bcfe basis) at year end 1997 increased by 40% over reserves
quantities a year earlier, the PV-10 Value of those reserves decreased 26% from
the PV-10 Value at year end 1996. This decrease was almost totally due to high
product prices at year end 1996, with the price of gas declining 38% during 1997
from $4.47 at December 31, 1996, to $2.78 at year end 1997, matched by a 34%
decrease in the price of oil between the two dates, from $23.75 to $15.76. If
the PV-10 Value as of year end 1997 had been calculated using the same prices in
effect a year earlier, there would have been an increase in the PV-10 Value from
year end 1996 to year end 1997 comparable to the 40% increase in the Company's
total proved reserves quantities during that same period.

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

A portion of the Company's proved reserves has been accumulated through the
Company's interests in the limited partnerships for which it serves as general
partner. The estimates of future net cash flows and their present values, based
on period end prices, assume that some of the limited partnerships in which the
Company owns interests will achieve payout status in the future. Four of the
limited partnerships had achieved payout status at December 31, 1997.

No other reports on the Company's reserves have been filed with any federal
agency.

<PAGE>

Oil and Gas Wells

The following table sets forth the gross and net wells in which the Company
owned an interest at the following dates:

<TABLE>
<CAPTION>
Oil Wells Gas Wells Total Wells(1)
--------- ----------- --------------
<S> <C> <C> <C>
December 31, 1997
Gross 625 926 1,551
Net 48.1 381.7 429.8
December 31, 1996
Gross 734 1,068 1,802
Net 59.5 222.9 282.4
December 31, 1995
Gross 3,049 995 4,044
Net 88.5 121.6 210.1
</TABLE>

(1) Excludes 16 service wells in 1997, 26 service wells in 1996, and 39 service
wells in 1995.

Oil and Gas Acreage

As is customary in the industry, the Company generally acquires oil and gas
acreage without any warranty of title except as to claims made by, through, or
under the transferor. Although the Company has title to developed acreage
examined prior to acquisition in those cases in which the economic significance
of the acreage justifies the cost, there can be no assurance that losses will
not result from title defects or from defects in the assignment of leasehold
rights. In many instances, title opinions may not be obtained if in the
Company's judgment it would be uneconomical or impractical to do so.

The following table sets forth the developed and undeveloped domestic
leasehold acreage held by the Company at December 31, 1997:

Developed Undeveloped
--------------------------- -----------------------------
Gross Net Gross Net
------------ ------------ ------------- -------------
<S> <C> <C> <C> <C>
Alabama 4,495.38 616.70 292.00 41.17
Arkansas 4,139.49 2,070.92 9,608.55 6,858.86
Kansas -- -- 4,600.00 1,988.80
Louisiana 44,481.57 13,610.37 20,085.44 11,750.85
Mississippi 5,236.49 3,379.84 1,828.22 489.42
Montana -- -- 4,851.28 4,851.28
Nebraska -- -- 1,707.04 1,029.53
Oklahoma 38,554.53 14,976.93 3,733.90 1,251.50
Texas 117,016.60 64,543.20 173,589.65 124,198.13
Wyoming 7,859.27 2,060.84 69,278.53 53,824.64
All other states 157.64 6.80 4,850.44 285.33
------------ ------------ ------------ ------------
Total 221,940.97 101,265.60 294,425.05 206,569.51
============ ============ ============= ============
</TABLE>

Partnerships

For many years, the Company relied on limited partnerships as its principal
financing vehicle to fund its activities. The Company has formed 107 limited
partnerships which have raised a total of approximately $502.0 million at
December 31, 1997. However, as the Company has increasingly shifted its emphasis
to exploration and development activities and its reserves base has grown, the
Company has significantly reduced its reliance on limited partnership financing.

During 1996, the limited partners in 18 partnerships, which had been in
operation over nine years and had produced a substantial majority of their
reserves, voted to sell their remaining properties and liquidate the limited
partnerships. Of these partnerships, 10 were the earliest public income
partnerships (formed in 1984 to 1986) and were liquidated in 1996, and in early
1997 eight private drilling partnerships (formed in 1979 to 1985) were
liquidated. During 1997, the limited partners in an additional 11 partnerships,
formed in 1990 and 1991, voted to sell their properties and liquidate the
limited partnerships, which liquidation is expected in early 1998. As the public
income partnerships formed since 1986 grow older, it is anticipated that
proposals will continue to be made to the investors in those partnerships to
sell their properties and liquidate the partnerships.

From 1991 to 1995 (and for prior periods), the Company formed limited
partnerships and joint ventures for the purpose of acquiring interests in
producing oil and gas properties. Since 1993, the Company also has offered
private partnerships formed to engage in the drilling for oil and gas reserves.
The Company serves as the managing general partner of these entities. As of
December 31, 1997, eleven partnerships had been formed (one formed in each of
1993 and 1994, and three in each of 1995, 1996, and 1997) with aggregate
investor contributions of approximately $58.6 million.

The private drilling partnerships have been offered on a no-load basis
under which the Company pays all selling and offering expenses of the offering.
Amounts paid by the Company are treated as a capital contribution to each
partnership. The Company also is entitled to a general and administrative
overhead allowance and an incentive amount. In certain partnerships, the Company
does not bear any of the costs incurred in acquiring or drilling properties. The
Company pays approximately 20% of all continuing costs (approximately 30% after
payout and 35% after 200% payout), and the Company is entitled to receive 20% of
net revenues distributed by each such partnership prior to payout, 30%
distributed after payout, and 35% distributed after 200% payout. As managing
general partner of certain other partnerships, the Company pays out of its own
corporate funds the capital costs (consisting of all prospect costs and the
non-deductible, tangible portion of drilling and completion costs). The Company
pays approximately 40% of all continuing costs (approximately 45% after payout
and 50% after 200% payout), and the Company is entitled to receive 40% of net
revenues distributed by each such partnership prior to payout, 45% distributed
after payout, and 50% distributed after 200% payout.

Under the terms of the Company's limited partnership programs, the Company
generally retains the right to engage in oil and gas exploration and production
for its own account. The partnership agreement for each limited partnership
contains detailed provisions regarding the terms upon which a variety of
transactions between the Company and the limited partnerships may be carried
out. These restrictions, which may limit the ability of the Company to take
certain actions, are intended to ensure that transactions between the Company
and the limited partnerships are fair to such limited partnerships.

Risk Management

The Company's operations are subject to all of the risks normally incident
to the exploration for and the production of oil and gas, including blowouts,
cratering, pipe failure, casing collapse, oil spills, and fires, each of which
could result in severe damage to or destruction of oil and gas wells, production
facilities, or other property, or individual injuries. The oil and gas
exploration business is also subject to environmental hazards, such as oil
spills, gas leaks, and ruptures and discharges of toxic substances or gases that
could expose the Company to substantial liabil-

<PAGE>

ity due to pollution and other environmental damage. Additionally, as managing
general partner of limited partnerships, the Company is solely responsible for
the day-to-day conduct of the limited partnerships' affairs and accordingly has
liability for expenses and liabilities of the limited partnerships. The Company
maintains comprehensive insurance coverage, including general liability
insurance in an amount not less than $25.0 million, as well as general partner
liability insurance. The Company believes that its insurance is adequate and
customary for companies of a similar size engaged in comparable operations, but
losses could occur for uninsurable or uninsured risks or in amounts in excess of
existing insurance coverage.

Competition

The oil and gas industry is highly competitive in all its phases. The
Company encounters strong competition from many other oil and gas producers,
including many that possess substantial financial resources, in acquiring
economically desirable producing properties and exploratory drilling prospects,
and in obtaining equipment and labor to operate and maintain its properties.
Decreases in gas and especially oil prices since year-end 1997 may have an
effect on the Company's cash flow, capital expenditures, or drilling schedule,
although in light of the extreme volatility of prices, it is impossible to
predict the length of time that prices may remain at such levels or may move to
higher or lower levels.

Regulations

Environmental Regulations

The federal government and various state and local governments have adopted
laws and regulations regarding the protection of human health and the
environment. These laws and regulations may require the acquisition of a permit
by operators before drilling commences, prohibit drilling activities on certain
lands lying within wilderness areas, wetlands, or where pollution might cause
serious harm, and impose substantial liabilities for pollution resulting from
drilling operations, particularly with respect to operations in onshore and
offshore waters or on submerged lands. These laws and regulations may increase
the costs of drilling and operating wells. Because these laws and regulations
change frequently, the costs to the Company of compliance with existing and
future environmental regulations cannot be predicted with certainty.

Federal Regulation of Natural Gas

The transportation and sale of natural gas in interstate commerce is
heavily regulated by agencies of the federal government. The following
discussion is intended only as a brief summary of the principal statutes,
regulations, and agency orders that may affect the production and sale of the
Company's natural gas. This summary should not be relied upon as a complete
review of applicable natural gas regulatory provisions.

FERC Orders. Several major regulatory changes were implemented by the
Federal Energy Regulatory Commission ("FERC") after 1985 that affect the
economics of natural gas production, transportation and sales. In addition, the
FERC continues to promulgate revisions to various aspects of the rules and
regulations affecting those segments of the natural gas industry that remain
subject to the FERC's jurisdiction. In April 1992, the FERC issued Order No. 636
pertaining to pipeline restructuring. This rule requires interstate pipelines to
unbundle transportation and sales services by separately stating the price of
each service and by providing customers only the particular service desired,
without regard to the source for purchase of the gas. The rule also requires
pipelines to (i) provide nondiscriminatory "no-notice" service allowing firm
commitment shippers to receive delivery of gas on demand up to certain limits
without penalties, (ii) establish a basis for release and reallocation of firm
upstream pipeline capacity and (iii) provide non-discriminatory access to
capacity by firm transportation shippers on a downstream pipeline. The rule
requires interstate pipelines to use a straight fixed variable rate design.

FERC Order No. 500 affects the transportation and marketability of natural
gas. Traditionally, natural gas has been sold by producers to pipeline
companies, which then resold the gas to end-users. FERC Order No. 500 alters
this market structure by requiring interstate pipelines that transport gas for
others to provide transportation service to producers, distributors and all
other shippers of natural gas on a nondiscriminatory, "first-come, first-served"
basis ("open access transportation"), so that producers and other shippers can
sell natural gas directly to end-users. FERC Order No. 500 contains additional
provisions intended to promote greater competition in natural gas markets.

It is not anticipated that the marketability of and price obtainable for
the Company's natural gas production will be significantly affected by FERC
Order No. 500. Gas produced normally will be sold to intermediaries who have
entered into transportation arrangements with pipeline companies. These
intermediaries will accumulate gas purchased from a number of producers and sell
the gas to end-users through open access transportation.

State Regulations

Production of any oil and gas by the Company will be affected to some
degree by state regulations. Many states in which the Company operates have
statutory provisions regulating the production and sale of oil and gas,
including provisions regarding deliverability. Such statutes, and the
regulations promulgated in connection therewith, are generally intended to
prevent waste of oil and gas and to protect correlative rights to produce oil
and gas between owners of a common reservoir. Certain state regulatory
authorities also regulate the amount of oil and gas produced by assigning
allowable rates of production to each well or proration unit.

Federal Leases

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

Employees

At December 31, 1997, the Company employed 194 persons. None of the
Company's employees are represented by a union. Relations with employees are
considered to be good.

Facilities

The Company and SEMCO occupy approximately 75,000 square feet of office
space at 16825 Northchase Drive, Houston, Texas, under a ten year lease expiring
in 2005. The lease requires payments of approximately $85,000 per month. A
subsidiary of the Company maintains an office in Denver, Colorado. The Company
has field offices in various locations from which Company employees supervise
local oil and gas operations.

<PAGE>

Glossary of Abbreviations and Terms

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

Bbl -- Barrel or barrels of oil.

Bcf -- Billion cubic feet of natural gas.

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

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

Discovery Cost -- With respect to proved reserves, a three-year average (unless
otherwise indicated) calculated by dividing total incurred exploration and
development costs (exclusive of future development costs) by net reserves
added during the period through extensions, discoveries, and other additions.

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

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

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

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

MBbl -- Thousand barrels of oil.

Mcf -- Thousand cubic feet of natural gas.

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

MMBbl -- Million barrels of oil.

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

MMcf -- Million cubic feet of natural gas.

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

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

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

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

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

Proved Oil and Gas Reserves -- The estimated quantities of crude oil, natural
gas, and natural gas liquids that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, that is, prices
and costs as of the date the estimate is made.

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

PV-10 Value -- The estimated future net revenue to be generated from the
production of proved reserves discounted to present value using an annual
discount rate of 10%. These amounts are calculated net of estimated production
costs and future

<PAGE>

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.

Reserves Replacement Cost -- With respect to proved reserves, a three-year
average (unless otherwise indicated) calculated by dividing total incurred
acquisition, exploration, and development costs (exclusive of future
development costs) by net reserves added during the period.

Volumetric Production Payment -- The 1992 agreement pursuant to which the
Company financed the purchase of certain oil and natural gas interests and
committed to deliver certain monthly quantities of natural gas.
- --------------------------------------------------------------------------------

Item 3. Legal Proceedings

No material legal proceedings are pending other than ordinary routine
litigation incidental to the Company's business.

Item 4. Submission of Matters to a Vote of Security Holders

No matters were submitted during the fourth quarter of 1997 to a vote of
security holders.

PART II

Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters

COMMON STOCK, 1997 AND 1996

Swift Energy Company common stock is traded on the New York Stock Exchange
and the Pacific Exchange, Inc., under the symbol "SFY." The high and low
quarterly sales prices for the common stock for 1997 and 1996 are as follows:

<TABLE>
<CAPTION>
1997 1996
---------------------------------- ----------------------------------
First Second Third Fourth First Second Third Fourth
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
---------------------------------- ----------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Low $19.32 $16.93 $18.86 $19.25 $9.89 $11.82 $15.91 $20.91
High $34.20 $26.02 $26.48 $31.00 $12.84 $16.48 $22.61 $28.86
</TABLE>

Since inception, no cash dividends have been declared on the Company's
common stock. Cash dividends are restricted under the terms of the Company's
credit agreements, as discussed in Note 4 to the Company's financial statements,
and the Company presently intends to continue a policy of using retained
earnings for expansion of its business. The stock prices for 1996 and the first
three quarters of 1997 have been revised to reflect a 10% stock dividend
declared in October 1997.

Swift Energy had approximately 520 stockholders of record as of December
31, 1997.

<PAGE>

Item 6. Selected Financial and Operating Data

<TABLE>
<CAPTION>
1997 1996 1995 1994 (1)
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Revenues
Oil and Gas Sales $69,015,189 $52,770,672 $22,527,892 $19,802,188
Supervision Fees $5,210,022 $4,470,206 $3,838,815 $3,751,061
Fees and Earned Interests(2) $745,856 $937,238 $590,441 $701,528
Interest Income $2,395,406 $433,352 $212,329 $47,980
Other, Net $2,555,729 $2,156,764 $1,761,568 $1,072,535
Total Revenues $79,922,202 $60,768,232 $28,931,045 $25,375,292

Operating Income $33,129,606 $28,785,783 $6,894,537 $4,837,829

Net Income (Loss) $22,310,189 $19,025,450 $4,912,512 ($13,047,027)

Net Cash Provided by Operating Activities $55,255,965 $37,102,578 $14,376,463 $10,394,514
- -----------------------------------------------------------------------------------------------------------------------
Per Share Data
Weighted Shares Outstanding(3) 16,492,856 15,000,901 10,035,143 7,308,673
Net income (Loss) per Share--Basic(3) $1.35 $1.27 $0.49 ($1.79)
Net income (Loss) per Share--Diluted(3) $1.26 $1.25 $0.49 ($1.79)
Shares Outstanding at Year End 16,459,156 15,176,417 12,509,700 6,685,137
Book Value per Share $9.69 $9.41 $7.46 $6.30
Market Price(3)
High $34.20 $28.86 $11.48 $10.35
Low $16.93 $9.89 $7.05 $7.75
Year-End Close $21.06 $27.16 $10.91 $8.86
- -----------------------------------------------------------------------------------------------------------------------
Pro forma amounts assuming 1994 change in
accounting principle is applied retroactively:(2)
Net Income $22,310,189 $19,025,450 $4,912,512 $3,725,671
Net Income per Share--Basic (3) $1.35 $1.27 $0.49 $0.51
Net Income per Share--Diluted (3) $1.26 $1.25 $0.49 $0.51
- -----------------------------------------------------------------------------------------------------------------------
Assets
Current Assets $29,981,786 $101,619,478 $43,380,454 $39,208,418
Oil and Gas Properties, Net of Accumulated
Depreciation, Depletion, and Amortization $301,312,847 $200,010,375 $125,217,872 $88,415,612
Total Assets $339,115,390 $310,375,264 $175,252,707 $135,672,743

Liabilities
Current Liabilities $28,517,664 $32,915,616 $40,133,269 $52,345,859
Long-Term Debt and Bank Borrowings $122,915,000 $115,000,000 $28,750,000 $28,750,000
Total Liabilities $179,714,470 $167,613,654 $81,906,742 $93,545,612

Stockholders' Equity $159,400,920 $142,761,610 $93,345,965 $42,127,131
- -----------------------------------------------------------------------------------------------------------------------
Number of Employees 194 191 176 209
- -----------------------------------------------------------------------------------------------------------------------
Producing Wells
Swift Operated 650 842 767 750
Outside Operated 917 986 3,316 3,422
Total Producing Wells 1,567 1,828 4,083 4,172

Wells Drilled (Gross) 182 153 76 44
- -----------------------------------------------------------------------------------------------------------------------
Proved Reserves
Natural Gas (Mcf) 314,305,669 225,758,201 143,567,520 76,263,964
Oil & Condensate (barrels) 7,858,918 5,484,309 5,421,981 4,553,267
Total Proved Reserves (Mcf equivalent) 361,459,177 258,664,055 176,099,406 103,583,566

Production (Mcf equivalent)(4) 25,393,744 19,437,114 11,186,573 9,600,867

Average Sales Price
Natural Gas (per Mcf) $2.68 $2.57 $1.77 $1.93
Oil (per barrel) $17.59 $19.82 $15.66 $14.35
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)Additional 1994 Data: Income Before Cumulative Effect of Change in Accounting
Principle-$3,725,671; Cumulative Effect of Change in Accounting
Principle-$(16,772,698); Per Share Amounts-Basic-Income Before Cumulative Effect
of Change in Accounting Principle-$0.51, Cumulative Effect of Change in
Accounting Principle-$(2.29); Per Share Amounts-Diluted-Income Before Cumulative
Effect of Change in Accounting Principle-$0.51, Cumulative Effect of Change in
Accounting Principle-$(2.29).

(2)As of January 1, 1994, the Company changed its revenue recognition policy for
earned interests. Accordingly, 1997, 1996, 1995, and 1994 "Fees and Earned
Interests" does not include earned interests revenues.

(3)Amounts have been retroactively restated in all periods presented to give
recognition to: (a) an equivalent change in capital structure as a result of two
10% stock dividends, one in September 1994, the other in October 1997 (see Note
2 to the 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).

(4)Natural gas production for 1992, 1993, 1994, 1995, 1996, and 1997 includes
1,148,862, 1,581,206, 1,358,375, 1,211,255, 1,156,361, and 1,015,226 Mcf,
respectively, delivered under the Company's volumetric production payment
agreement (see Note 1 to the Company's financial statements).

<PAGE>

<TABLE>
<CAPTION>
1993 1992 1991 1990 1989 1988 1987
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
$15,535,671 $12,420,222 $8,361,771 $7,328,190 $3,984,835 $2,838,433 $2,097,815
$3,718,829 $3,443,777 $3,362,800 $2,149,079 $1,651,839 $1,118,794 $1,065,820
$4,071,970 $2,716,277 $2,231,729 $9,882,953 $8,802,816 $8,073,530 $7,956,895
$201,584 $113,387 $192,694 $705,786 $260,286 $165,909 $125,459
$604,599 $515,931 $541,502 $323,981 $232,261 $488,131 $452,059
$24,132,653 $19,209,594 $14,690,496 $20,389,989 $14,932,037 $12,684,797 $11,698,048

$6,628,608 $4,687,519 $3,748,741 $10,811,044 $8,716,673 $7,040,165 $6,632,631

$4,896,253 $4,084,760 $2,512,815 $7,170,642 $5,709,098 $4,678,317 $4,024,003

$7,238,340 $6,349,080 $5,911,588 $4,813,435 $2,751,381 $393,564 $1,705,616
- ---------------------------------------------------------------------------------------------------------

7,246,884 6,748,548 5,899,629 5,806,436 5,129,654 4,897,379 4,822,366
$0.68 $0.61 $0.43 $1.23 $1.11 $0.96 $0.83
$0.64 $0.61 $0.43 $1.23 $1.11 $0.96 $0.83
6,001,075 5,968,579 4,955,134 4,848,315 4,764,862 4,068,968 4,025,108
$9.08 $8.26 $7.80 $7.36 $5.84 $3.88 $2.70

$11.57 $7.85 $9.09 $10.65 $11.15 $8.68 $15.40
$7.14 $4.65 $4.34 $6.93 $5.78 $5.58 $3.41
$7.85 $7.55 $4.95 $8.57 $9.50 $5.68 $6.20
- ---------------------------------------------------------------------------------------------------------

$4,322,478 $3,729,851 $2,950,245 $3,107,451 $2,185,276 $898,962 $561,509
$0.60 $0.55 $0.50 $0.54 $0.43 $0.18 $0.12
$0.57 $0.55 $0.50 $0.54 $0.43 $0.18 $0.12
- ---------------------------------------------------------------------------------------------------------

$65,307,120 $30,830,173 $47,859,278 $72,537,521 $54,818,404 $9,304,370 $8,396,944

$89,656,577 $64,301,509 $47,655,917 $41,952,212 $27,935,170 $19,973,454 $13,092,526
$160,892,917 $100,243,469 $101,421,573 $118,227,480 $85,007,293 $31,463,220 $23,745,504

$55,565,437 $27,876,687 $50,851,447 $71,514,938 $49,354,128 $9,756,431 $8,342,755
$28,750,000 $0 $0 $0 $0 $0 $0
$106,427,203 $50,962,183 $62,761,217 $82,559,406 $57,198,476 $15,694,272 $12,874,849

$54,465,714 $49,281,286 $38,660,356 $35,668,074 $27,808,817 $15,768,948 $10,870,655
- ---------------------------------------------------------------------------------------------------------
188 178 171 164 131 116 94
- ---------------------------------------------------------------------------------------------------------

795 688 674 691 579 491 405
3,407 1,978 2,331 2,228 1,537 857 547
4,202 2,666 3,005 2,919 2,116 1,348 952

34 40 27 23 21 12 14
- ---------------------------------------------------------------------------------------------------------

64,462,805 41,638,100 36,685,881 30,731,741 14,945,348 11,293,268 7,229,352
4,271,069 2,901,621 1,950,209 1,690,520 1,422,815 840,144 597,174
90,089,219 59,047,824 48,387,138 40,874,862 23,482,236 16,334,130 10,812,396

7,368,757 5,678,772 3,980,460 3,303,750 1,900,302 1,440,690 875,547

$1.96 $1.90 $1.58 $1.72 $1.73 $1.67 $1.78
$15.10 $17.19 $18.26 $22.70 $17.93 $14.38 $17.39
- ---------------------------------------------------------------------------------------------------------
</TABLE>

<PAGE>

Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations

The following discussion should be read in conjunction with the Company's
Consolidated Financial Statements and Notes thereto.

General

Swift Energy Company's principal corporate objectives are the accumulation
of crude oil and natural gas reserves for current and future production and sale
and the enhancement of the net present value of those reserves. The Company was
formed in 1979 and from 1985 to 1991 grew primarily through the acquisition of
producing properties funded through limited partnership financing. Commencing in
1991, the Company began to reemphasize the addition of reserves through
increased exploration and development drilling activity. This emphasis on
exploration and development drilling has led to additions of increasing
quantities of reserves in each of the years 1995, 1996, and 1997. The Company's
revenues are primarily comprised of oil and gas sales attributable to properties
in which the Company owns a direct or indirect interest.

Proved Oil and Gas Reserves. In 1997, the Company's proved natural gas
reserves increased 88.5 Bcf (39%) and its proved oil reserves increased
2,374,609 barrels (43%) or a total of 102.8 Bcfe. From 1995 to 1996, the
Company's proved natural gas reserves increased 82.2 Bcf (57%) and its proved
oil reserves increased 62,328 barrels (1%). The Company's additions to proved
reserves from its exploration and development program were 120.2 Bcfe in 1997,
118.2 Bcfe in 1996, and 72.4 Bcfe in 1995. A substantial portion of these
reserves are proved undeveloped reserves comprising 144.6 Bcfe or 40% of total
proved reserves at year end 1997, 101.5 Bcfe or 39% of total proved reserves at
year end 1996, and 74.7 Bcfe or 42% of total proved reserves at year end 1995.
This reflects the emphasis on exploration and development activities.

Proved developed reserves additions in 1997 resulted from drilling activity
(which also increased undeveloped reserves) and the purchases of minerals in
place, offset somewhat by revisions of previous estimates. The change in the
Standardized Measure of Discounted Future Net Cash Flows (see Supplemental
Information to the Company's financial statements) and in the Estimated Present
Value of Proved Reserves (see page 7--"Oil and Gas Reserves") from year end 1996
to year end 1997 is also due to the addition of reserves through the Company's
drilling activity (primarily in the AWP Olmos Field and the Austin Chalk trend)
and the purchases of minerals in place (primarily in the AWP Olmos Field),
offset by revisions of previous estimates and by the 38% decrease in year end
1997 natural gas prices ($2.78 per Mcf versus $4.47 per Mcf at year end 1996),
and to the 34% decrease in year end 1997 oil prices ($15.76 per Bbl at year end
1997, compared to $23.75 per Bbl a year earlier). While the Company's total
proved reserves quantities at year end 1997 increased by 40% over reserves
quantities a year earlier, the PV-10 Value of those reserves decreased 26% from
the PV-10 Value at year end 1996. This decrease was almost totally due to the
high product prices at year end 1996 detailed above. If the PV-10 Value as of
year end 1997 had been calculated using the same prices in effect a year
earlier, there would have been an increase in PV-10 Value from year end 1996 to
year end 1997 comparable to the 40% increase in the Company's total proved
reserves quantities during that same period.

Under the Securities and Exchange Commission guidelines, the Company's
estimates of cash flows from proved reserves are made using oil and gas sales
prices in effect as of the dates of such estimates and are held constant
throughout the life of the properties, except where such guidelines permit
alternate treatment, including, in the case of gas contracts, the use of fixed
and determinable contractual price escalations. The $2.78 per Mcf and the $15.76
per barrel were prices in effect as of year end 1997 and may not be indicative
of future sales prices received.

Liquidity and Capital Resources

During the first ten months of 1996, the Company relied upon internally
generated cash flows and bank borrowings to fund its capital expenditures, and
thereafter upon net proceeds from its $115.0 million public offering of 6.25%
Convertible Subordinated Notes due 2006 and its internally generated cash flows,
along with $7.9 million of bank borrowings in the closing weeks of 1997, all as
described

15
<PAGE>

below. Cash and working capital in 1998 are expected to be provided through
internally generated cash flows, bank borrowings, and debt and/or equity
financing.

Net Cash Provided by Operating Activities. In 1997, 1996, and 1995, the
Company's operating activities provided net cash of $55.3 million, $37.1
million, and $14.4 million, respectively. These increases were primarily due to
increased production volumes, as discussed below. The 1997 increase of $18.2
million was primarily due to an increase in cash flows from oil and gas sales,
which increased $16.5 million (32%), exclusive of the non-cash amortization of
deferred revenues associated with the Company's volumetric production payment.
The 1996 increase of $22.7 million in net cash from operations was primarily due
to the cash flows from oil and gas sales, which increased $30.4 million (146%),
exclusive of the non-cash amortization of deferred revenues associated with the
Company's volumetric production payment, partially offset by a $1.6 million
increase in oil and gas production costs, a $1.1 million increase in general and
administrative costs, plus changes to assets and liabilities and deferred income
taxes. These 1997 and 1996 increases in oil and gas sales were primarily the
result of the Company's increased drilling activity, as well as being affected
by product price fluctuations, as described below.

Sale of Convertible Subordinated Notes. In November 1996, the Company
issued $115.0 million of 6.25% Convertible Subordinated Notes due November 15,
2006, in a public offering. Proceeds of the offering were used for repayment in
full of all the Company's bank borrowings ($33.1 million on November 25, 1996)
and, together with internally generated cash flows, to fund capital expenditures
through 1997 and working capital needs. The principal terms of these Notes are
more fully described in Note 4 to the Company's financial statements.

Other Financing Activities. During the third quarter of 1995, the Company
sold 5.75 million shares of common stock in a public offering at $8.50 per
share, with net proceeds of $45.7 million principally used to repay outstanding
indebtedness and finance the Company's exploration and development activities.
As described in Note 4 to the Company's financial statements included herein, in
August 1996 the $28.75 million of 6.5% Convertible Debentures sold in 1993 were
converted by their holders into 2.34 million shares of the Company's common
stock following the Company's July 1996 announcement of their redemption. As a
result of this conversion, the Company's stockholders' equity increased
approximately $27.65 million.

Credit Facilities. In the first ten months of 1996 and in the closing weeks
of 1997, the Company's credit facilities have been used to fund a portion of the
Company's exploration and development activities. Currently, these credit
facilities consist of a $100.0 million unsecured revolving line of credit with a
$40.0 million borrowing base and a $7.0 million secured revolving line of credit
with a $5.5 million borrowing base. The principal terms and restrictions of
these credit facilities are described in Note 4 to the Company's financial
statements included herein.

At December 31, 1997, the Company had outstanding borrowings of $7,915,000
under the credit facilities. At December 31, 1996, and until mid-December 1997,
the Company had no outstanding balances under these borrowing arrangements,
since the balance of those borrowings was repaid in November 1996 with proceeds
from the Company's public sale of $115.0 million of 6.25% Convertible
Subordinated Notes.

Partnership Programs. Since late 1993, the Company has offered private
partnerships formed to drill for oil and gas. During 1997, the Company formed
three drilling partnerships with subscriptions of approximately $16.8 million
and in 1996 formed three partnerships with subscriptions of approximately $22.0
million. The Company anticipates that it will continue to offer such drilling
partnerships for the foreseeable future.

At December 31, 1997, limited partnership formation and marketing costs
(which under the current drilling partnership offerings are borne by the Company
as part of the Company's general partner contribution) amounted to $297,000, a
decrease of $213,000 when compared with the balance at December 31, 1996.

Working Capital. The Company's working capital has decreased from $68.7
million at December 31, 1996, to $1.5 million at December 31, 1997. This
decrease is primarily the result of the Company's capital expenditures as
described below.

Since year end 1996, the Company's receivable account from limited
partnerships and its receivable account from joint interest owners increased
$1.8 million and $4.3 million, respectively, due to the increase in drilling
activity between the periods.

Due to the nature of the Company's business highlighted above, the
individual components of working capital fluctuate considerably from period to
period. The Company incurs significant working capital requirements in
connection with its role as operator of approximately 650 wells, its accelerated
drilling programs, and the management of affiliated partnerships. In this
capacity, the Company is responsible for certain day-to-day cash management,
including the collection and disbursement of oil and gas revenues and related
expenses.

Common Stock Repurchase Program. In March 1997, the Company's Board of
Directors approved a common stock repurchase program for up to $20.0 million of
the Company's common stock and subsequently extended the program through June
30, 1998. Purchases of shares are made in the open market. Under this program,
through December 31, 1997, the Company used $8.52 million of working capital to
acquire 387,800 shares at an average cost of $21.97 per share.

Common Stock Dividend. In October 1997, the Company declared a 10% stock
dividend to shareholders of record. The transaction was valued based on the
closing price ($28.8125) of the Company's common stock on the New York Stock
Exchange on October 1, 1997. As a result of the issuance of 1,494,606 shares of
the Company's common stock as a

<PAGE>

dividend, retained earnings were reduced by $43,063,335, with the common stock
and additional paid-in capital accounts increased by the same amount.

Capital Expenditures. The Company's capital expenditures were approximately
$132.0 million, $91.5 million, and $40.0 million for 1997, 1996, and 1995,
respectively. The 1997 capital expenditures included (a) $90.3 million (68% of
1997 capital expenditures) on developmental drilling (primarily in the AWP Olmos
Field and Austin Chalk trend), (b) $10.7 million (8%) on exploratory drilling,
(c) $18.4 million (14%) on domestic prospect costs (principally prospect
leasehold, seismic, and geological costs of unproven prospects for the Company's
account), (d) the purchase of $8.4 million (6%) of producing property interests,
$7.1 million from third parties (primarily in the AWP Olmos Field), along with
the purchase of $1.3 million of limited partner interests in previously formed
partnerships through the right of presentment arrangement provided in those
partnerships, (e) $3.2 million (3%) invested in foreign business opportunities
in Russia ($0.7 million), Venezuela ($0.8 million), and New Zealand ($1.7
million), as described in Note 8 to the Company's financial statements, and (f)
$0.9 million (1%) spent on fixed assets. In 1997, the Company participated in
drilling 182 wells (15 exploratory and 167 development wells with 7 exploratory
successes and 159 development successes). The steady growth in the Company's
unproved property account ($41.8 million), which is not being amortized, is
indicative of the shift to a focus on drilling activity as the Company acquires
prospect acreage, including $3.2 million of capital expenditures in 1997 made in
relation to the Company's foreign business opportunities, as described above.

Capital expenditures for 1998 are estimated to be approximately $154.8
million, including investments in all areas in which 1997 capital was spent.
Approximately $123.9 million of the 1998 budget is allocated to exploration and
development drilling, with approximately 73% of this amount to be spent in the
Company's two primary development areas in Texas. The Company's plan anticipates
drilling 113 development and 21 exploratory wells in 1998.

The Company believes that 1998's anticipated internally generated cash
flows (expected to increase as the Company's production base increases as a
result of its accelerated drilling program), together with the existing credit
facilities, will be sufficient to finance the costs associated with its
currently budgeted 1998 capital expenditures.

Results of Operations

Revenues. The Company's revenues in 1997 increased by 32% over revenues in
1996 and by 110% in 1996 over 1995 revenues, principally due to increases in oil
and gas sales revenues.

Oil and Gas Sales. The Company's net sales volumes in 1997 (including the
volumetric production payment associated with each year's production) increased
by 31% (6.0 Bcfe) over net sales volumes in 1996, while 1996 net sales volumes
increased by 74% (8.3 Bcfe) over net sales volumes in 1995. Oil and gas sales
revenues in 1997 increased by 31% ($16.2 million) over those revenues for 1996,
while in 1996 those revenues increased by 134% ($30.2 million) over oil and gas
sales in 1995. Average prices for oil increased from $15.66 per Bbl in 1995 to
$19.82 per Bbl in 1996 and then decreased to $17.59 per Bbl in 1997, while
average gas prices increased from $1.77 per Mcf in 1995 to $2.57 per Mcf in 1996
and to $2.68 per Mcf in 1997. The Company's $16.2 million increase in oil and
gas sales during 1997 was comprised of volume increases that added $14.5 million
of sales from the 5.7 Bcf increase in gas sales volumes and $1.0 million of
sales from the 49,000 barrel increase in oil sales volumes, while price
variances contributed $2.2 million in increased sales from the increase in
average gas prices received, offset somewhat by a $1.5 million decrease in sales
from the decrease in average oil prices received. The Company's $30.2 million
increase in oil and gas sales during 1996 was comprised of volume increases that
added $13.8 million of sales from the 7.8 Bcf increase in gas sales volumes and
$1.2 million of sales from the 78,000 barrel increase in oil sales volumes,
while price variances contributed $12.7 million in increased sales from the
increase in average gas prices received and $2.5 million in increased sales from
the increase in average oil prices received.

The increases in oil and gas sales for 1997 and 1996 were primarily the
result of production from the Company's accelerated drilling program, most
notably from the Company's two primary development areas, the AWP Olmos Field
and the Austin Chalk trend. The Company's 1997 oil and gas sales from the AWP
Olmos Field were $42.2 million ($29.9 million in 1996) from 15.5 Bcfe of net
sales volumes (11.2 Bcfe in 1996) for an increase of 4.3 Bcfe, while the Austin
Chalk trend generated 1997 oil and gas sales of $12.9 million ($9.4 million in
1996) from 4.9 Bcfe of net sales volumes (3.4 Bcfe in 1996) for an increase of
1.5 Bcfe.

Revenues from oil and gas sales comprised 86%, 87%, and 78%, respectively,
of total revenues for 1997, 1996, and 1995. The majority (83%, 77%, and 62%,
respectively) of these oil and gas revenues in these periods were derived from
the sale of the Company's gas production. The Company expects oil and gas sales
to continue to increase as a direct consequence of the addition of oil and gas
reserves through the Company's active drilling program.

Average prices received from oil and gas production can have a dramatic
impact on the Company's oil and gas sales revenues. This is evident not only in
the yearly comparisons as described above but also when comparing fourth quarter
1997 revenues to those for the fourth quarter of 1996. While oil and gas
production volumes increased 1.0 Bcfe (17%) during the fourth quarter of 1997
when compared to the fourth quarter of 1996, oil and gas sales increased only
$1.1 million (6%) due to average oil prices received being 25% lower and average
gas prices received being 6% lower than in the fourth quarter of 1996.

Supervision Fees. These fees continue to increase, having grown from $3.8
million in 1995 to $4.5 million in 1996 to $5.2 million in 1997, primarily due
to the annual escalation in well overhead rates and the increase in drilling
activity by the Company, which in turn increases the drilling well overhead
portion of such fees paid to the Company as operator of these wells.

Costs and Expenses. General and administrative expenses in 1997 decreased
$0.3 million (4%) from the level of such expenses in 1996, while 1996 general
and administrative expenses increased $1.1 million (21%) over 1995 levels. The
slight decrease in these costs in 1997 over 1996 reflected the Company's ability
to continue increasing its drilling activity without increasing such costs in
1997. The increase in costs in 1996 over 1995 reflected the increase in the
Company's activities. The Company's general and administrative expenses per Mcfe
produced have decreased in each of the past three years from $0.47 per Mcfe
produced in 1995 to $0.33 per Mcfe produced in 1996 to $0.24 per

<PAGE>

Mcfe produced in 1997. The majority of the companies in the oil and gas industry
treat supervision fees as a reduction of their general and administrative
expenses. If the Company were to follow this practice, these expenses net of
supervision fees would have decreased to $0.13 per Mcfe produced in 1995, $0.10
per Mcfe produced in 1996, and $0.04 per Mcfe produced in 1997.

Depreciation, depletion, and amortization (DD&A) has steadily increased,
primarily due to the Company's reserves additions and associated costs and to
the related sale of increased quantities of oil and gas produced therefrom. The
Company's DD&A rate per Mcfe of production was $0.79 in 1995, $0.85 in 1996, and
$0.95 in 1997, reflecting variations in the per unit cost of reserves additions.

Production costs in 1997 increased $3.0 million (36%) over such expenses in
1996, while those expenses in 1996 increased $1.6 million (23%) over 1995. The
increases in each of the periods primarily relate to the increase in the
Company's oil and gas sales volumes. The Company's production costs per Mcfe
produced were $0.45 in 1997, $0.43 in 1996, and $0.61 in 1995. As discussed
above, the Company's increase in production is primarily through its drilling
activities in the AWP Olmos Field and Austin Chalk trend, where the Company
already has an established operating base. The increase in production costs has
been partially offset by an exemption in these same fields from the 7.5% Texas
severance tax applicable to gas production from certain natural gas wells
certified to be in tight formations or to be deep wells by the Texas Railroad
Commission. This exemption in 1996 was a major contributor in reducing the
Company's production costs per Mcfe produced from the 1995 rate of $0.61 to the
1996 rate of $0.43. Additionally, commencing September 1, 1996, certain wells
certified as "high cost gas" wells are entitled to a reduction of severance tax
based upon a formula amount but not the full exemption of 7.5% received on
certified wells drilled prior to September 1, 1996. This tax exemption has had a
positive impact on the Company's production costs during 1996 and 1997, although
under the new rules, the proportionate amount of the exemption was decreased in
the 1997 period, thus contributing to the $0.02 increase in production costs per
Mcfe produced in 1997 when compared to 1996.

Interest expense in 1997 on the Notes, including amortization of debt
issuance costs, totaled $7.5 million, compared to $0.7 million on the Notes and
$1.0 million on the Debentures in 1996 and $2.0 million on only the Debentures
in 1995, while interest expense on the credit facilities, including commitment
fees, totaled $0.1 million ($1.1 million in 1996 and $1.7 million in 1995), for
a 1997 total of $7.6 million (of which $2.6 million was capitalized). The 1996
total was $2.8 million (of which $2.1 million was capitalized), while the 1995
total was $3.7 million (of which $2.6 million was capitalized). The Company
capitalizes a portion of interest related to certain exploration, partnership,
and foreign business development activities. The increase in interest expense in
1997 is attributable to the larger outstanding principal amount on the Notes
($115.0 million) compared to the Debentures ($28.75 million), offset to some
degree by larger outstanding balances under the Company's credit facilities in
1996 and by the $2.4 million in interest income earned in 1997 on the portion of
the net proceeds of the Notes invested pending use. The lower amount of interest
expense in 1996, compared to 1995 was attributable to a smaller average balance
under the Company's credit lines necessary to finance the Company's capital
expenditures, as well as to paying only six months of interest on the Debentures
as they were converted into common stock in the third quarter of 1996.

Net Income. Net income of $22.3 million and earnings per share of $1.35 for
1997 were 17% and 6% higher, respectively, than net income of $19.0 million and
earnings per share of $1.27 in 1996. This increase in net income primarily
reflected the effect of a 31% increase in oil and gas sales revenues as a result
of a 36% increase in natural gas production, an 8% increase in crude oil
production, and a slight 4% increase in gas prices received, offset somewhat by
an 11% decrease in oil prices received. The lower percentage increase in
earnings per share reflects a 10% increase in weighted average shares
outstanding in 1997 as a result of the conversion of the Debentures into 2.34
million shares of common stock in the third quarter of 1996. The Company's
consolidated effective tax rate was 32.7%, 33.9%, and 28.7% in 1997, 1996, and
1995, respectively.

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

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

<PAGE>

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 8. Financial Statements and Supplementary Data
- --------------------------------------------------------------------------------

Report of Independent Public Accountants......................................20

Consolidated Balance Sheets...................................................21

Consolidated Statements of Income.............................................22

Consolidated Statements of Stockholders' Equity...............................23

Consolidated Statements of Cash Flows.........................................24

Notes to Consolidated Financial Statements....................................25

1. Summary of Significant Accounting Policies..............................25
2. Income Per Share........................................................27
3. Provision for Income Taxes..............................................27
4. Long-Term Debt and Bank Borrowings......................................28
5. Commitments and Contingencies...........................................29
6. Stockholders' Equity....................................................29
7. Related-Party Transactions..............................................31
8. Foreign Activities......................................................31

Supplemental Information (Unaudited)..........................................32
- --------------------------------------------------------------------------------

<PAGE>

Report of Independent Public Accountants
- --------------------------------------------------------------------------------

To the Stockholders and Board of Directors of Swift Energy Company:

We have audited the accompanying consolidated balance sheets of Swift Energy
Company (a Texas corporation) and subsidiaries as of December 31, 1997 and 1996,
and the related consolidated statements of income, stockholders' equity, and
cash flows for each of the three years in the period ended December 31, 1997.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these 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, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.

ARTHUR ANDERSEN LLP

Houston, Texas
February 10, 1998

<PAGE>

Consolidated Balance Sheets
- --------------------------------------------------------------------------------
Swift Energy Company and Subsidiaries

<TABLE>
<CAPTION>
December 31,
1997 1996
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents............................................ $ 2,047,332 $ 77,794,974
Accounts receivable-
Oil and gas sales............................................... 11,143,033 13,637,390
Associated limited partnerships and joint ventures.............. 8,498,702 6,396,149
Joint interest owners........................................... 7,357,660 3,079,619
Other current assets................................................. 935,059 711,346
------------- -------------
Total Current Assets......................................... 29,981,786 101,619,478
------------- -------------

Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized............................... 326,836,431 216,310,033
Unproved properties not being amortized......................... 41,839,809 27,620,462
------------- -------------
368,676,240 243,930,495
Furniture, fixtures, and other equipment ............................ 6,242,927 5,729,228
------------- -------------
374,919,167 249,659,723
Less - Accumulated depreciation, depletion, and amortization......... (70,700,240) (46,685,736)
------------- -------------
304,218,927 202,973,987
------------- -------------
Other Assets:
Receivables from associated limited partnerships, net of current
portion......................................................... 433,444 759,711
Limited partnership formation and marketing costs.................... 297,219 510,607
Deferred charges..................................................... 4,184,014 4,511,481
------------- -------------
4,914,677 5,781,799
------------- -------------
$ 339,115,390 $ 310,375,264
============= =============

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities............................. $ 16,518,240 $ 20,416,589
Payable to associated limited partnerships........................... 3,245,445 1,444,648
Undistributed oil and gas revenues................................... 8,753,979 11,054,379
------------- -------------
Total Current Liabilities.................................. 28,517,664 32,915,616
------------- -------------

Long-Term Debt............................................................ 115,000,000 115,000,000
Bank Borrowings........................................................... 7,915,000 --
Deferred Revenues......................................................... 2,927,656 4,404,081
Deferred Income Taxes..................................................... 25,354,150 15,293,957

Commitments and Contingencies

Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none
outstanding..................................................... -- --
Common stock, $.01 par value, 35,000,000 shares authorized,
16,846,956 and 15,176,417 shares issued, and 16,459,156 and
15,176,417 shares outstanding, respectively..................... 168,470 151,764
Additional paid-in capital........................................... 147,542,977 102,018,861
Treasury stock held, at cost, 387,800 shares......................... (8,519,665) --
Unearned ESOP compensation........................................... (150,055) (521,354)
Retained earnings.................................................... 20,359,193 41,112,339
------------- -------------
159,400,920 142,761,610
------------- -------------
$ 339,115,390 $ 310,375,264
============= =============
</TABLE>

See accompanying notes to Consolidated Financial Statements.

<PAGE>

Consolidated Statements of Income
- --------------------------------------------------------------------------------
Swift Energy Company and subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31,

1997 1996 1995
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues:
Oil and gas sales........................ $ 69,015,189 $ 52,770,672 $ 22,527,892
Fees from limited partnerships
and joint ventures..................... 745,856 937,238 590,441
Supervision fees......................... 5,210,022 4,470,206 3,838,815
Interest income.......................... 2,395,406 433,352 212,329
Other, net............................... 2,555,729 2,156,764 1,761,568
--------------- ----------------- --------------

79,922,202 60,768,232 28,931,045
--------------- ----------------- --------------

Costs and Expenses:
General and administrative, net of
reimbursement.......................... 6,128,615 6,385,067 5,256,184
Depreciation, depletion, and
amortization........................... 24,247,142 16,526,379 8,838,657
Oil and gas production................... 11,383,887 8,377,044 6,826,306
Interest expense, net.................... 5,032,952 693,959 1,115,361
--------------- ----------------- --------------

46,792,596 31,982,449 22,036,508
--------------- ----------------- --------------

Income Before Income Taxes.................... 33,129,606 28,785,783 6,894,537

Provision for Income Taxes.................... 10,819,417 9,760,333 1,982,025
--------------- ----------------- --------------

Net Income.................................... $ 22,310,189 $ 19,025,450 $ 4,912,512
=============== ================= ==============

Per Share Amounts-
Basic.................................... $ 1.35 $ 1.27 $ 0.49
=============== ================= ==============

Diluted.................................. $ 1.26 $ 1.25 $ 0.49
=============== ================= ==============

Weighted Average Shares Outstanding........... 16,492,856 15,000,901 10,035,143
=============== ================= ==============
</TABLE>

See accompanying notes to Consolidated Financial Statements.

<PAGE>

Consolidated Statements of Stockholders' Equity
- --------------------------------------------------------------------------------
Swift Energy Company and Subsidiaries

<TABLE>
<CAPTION>
Unearned
Additional ESOP
Common Paid-in Treasury Compen- Retained
Stock(1) Capital Stock sation Earnings Total
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1994..... $ 66,851 $ 24,885,903 $ - $ - $ 17,174,377 $ 42,127,131
Stock issued for benefit
plans (31,113 shares)...... 311 283,463 - - - 283,774
Stock options exercised
(5,761 shares)........... 58 33,736 - - - 33,794
Employee stock purchase
plan (37,689 shares)..... 377 289,465 - - - 289,842
Stock issued in public
offering (5,750,000
shares).................. 57,500 45,641,412 - - - 45,698,912
Net income................... - - - - 4,912,512 4,912,512
---------- ------------- -------------- ------------ ------------- --------------

Balance, December 31, 1995..... $ 125,097 $ 71,133,979 $ - $ - $ 22,086,889 $ 93,345,965
Stock issued for benefit
plans (30,015 shares)..... 300 347,345 - - - 347,645
Stock options exercised
(257,207 shares).......... 2,572 2,630,959 - - - 2,633,531
Employee stock purchase
plan (36,387 shares)...... 364 272,178 - - - 272,542
Loan to ESOP for purchase
of shares................. - - - (568,750) - (568,750)
Allocation of ESOP shares.... - 5,382 - 47,396 - 52,778
Debenture conversion
(2,343,108 shares)........ 23,431 27,629,018 - - - 27,652,449
Net income................... - - - - 19,025,450 19,025,450
---------- ------------- -------------- ------------ ------------- --------------

Balance, December 31, 1996..... $ 151,764 $ 102,018,861 $ - $ (521,354) $ 41,112,339 $ 142,761,610
Stock issued for benefit
plans (12,227 shares)..... 122 371,359 - - - 371,481
Stock options exercised
(137,155 shares).......... 1,372 1,613,071 - - - 1,614,443
Employee stock purchase
plan (26,551 shares)...... 266 403,145 - - - 403,411
10% stock dividend
(1,494,606 shares)........ 14,946 43,048,389 - - (43,063,335) -
Allocation of ESOP shares.... - 88,152 - 371,299 - 459,451
Purchase of 387,800 shares
as treasury stock........ - - (8,519,665) - - (8,519,665)
Net income................... - - - - 22,310,189 22,310,189
---------- ------------- -------------- ------------ ------------- --------------

Balance, December 31, 1997 $ 168,470 $ 147,542,977 $ (8,519,665) $ (150,055) $ 20,359,193 $ 159,400,920
========== ============= ============== ============ ============= ==============
</TABLE>

(1)$.01 par value.

See accompanying notes to Consolidated Financial Statements.

<PAGE>

Consolidated Statements of Cash Flows
- --------------------------------------------------------------------------------
Swift Energy Company and Subsidiaries

<TABLE>
<CAPTION>
Year Ended December 31,

1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Flows from Operating Activities:
Net income............................................... $ 22,310,189 $ 19,025,450 $ 4,912,512
Adjustments to reconcile net income to net cash provided
by operating activities-
Depreciation, depletion, and amortization........... 24,247,142 16,526,379 8,838,657
Deferred income taxes............................... 10,060,193 8,449,283 2,326,162
Deferred revenue amortization related to production
payment............................................. (1,449,808) (1,670,172) (1,787,974)
Other............................................... 786,917 140,047 112,890
Change in assets and liabilities-
Increase in accounts receivable.................. (204,475) (5,008,592) (488,599)
Increase (decrease) in accounts payable and
accrued liabilities, excluding income
taxes payable................................. (564,323) (444,966) 1,074,532
Increase (decrease) in income taxes payable...... 70,130 85,149 (611,717)
-------------- ------------- -------------
Net Cash Provided by Operating Activities..... 55,255,965 37,102,578 14,376,463
-------------- ------------- -------------

Cash Flows from Investing Activities:
Additions to property and equipment...................... (131,967,444) (91,487,176) (40,032,944)
Proceeds from the sale of property and equipment......... 3,369,982 2,247,799 230,242
Net cash received (distributed) as operator of oil
and gas properties................................... (1,829,008) (2,074,104) 7,662,419
Net cash received (distributed) as operator of
partnerships and joint ventures...................... (2,102,553) 11,284,793 5,316,693
Other.................................................... (259,255) 840 (41,181)
--------------- -------------- -------------
Net Cash Used in Investing Activities......... (132,788,278) (80,027,848) (26,864,771)
--------------- -------------- -------------

Cash Flows from Financing Activities:
Proceeds from long-term debt............................. -- 115,000,000 --
Net proceeds from (payments of) bank borrowings.......... 7,915,000 -- (27,229,000)
Net proceeds from issuances of common stock.............. 2,389,336 3,264,482 46,306,322
Purchase of treasury stock............................... (8,519,665) -- --
Loan to ESOP for purchase of shares...................... -- (568,750) --
Payments of debt issuance costs.......................... -- (4,550,000) --
-------------- ------------- -------------
Net Cash Provided by Financing Activities..... 1,784,671 113,145,732 19,077,322
-------------- ------------- -------------

Net Increase (Decrease) in Cash and Cash Equivalents.......... $ (75,747,642) $ 70,220,462 $ 6,589,014

Cash and Cash Equivalents at Beginning of Year................ 77,794,974 7,574,512 985,498
-------------- ------------- -------------

Cash and Cash Equivalents at End of Year...................... $ 2,047,332 $ 77,794,974 $ 7,574,512
============== ============= =============

Supplemental Disclosures of Cash Flows Information:

Cash paid during year for interest, net of
amounts capitalized.................................. $ 4,638,308 $ 831,516 $ 68,097
Cash paid during year for income taxes........................ $ 381,514 $ 676,920 $ 277,580
</TABLE>

See accompanying notes to Consolidated Financial Statements.

<PAGE>

Notes to Consolidated Financial Statements
- --------------------------------------------------------------------------------
Swift Energy Company and Subsidiaries

1. Summary of Significant Accounting Policies

Principles of Consolidation. The accompanying consolidated financial
statements include the accounts of Swift Energy Company (Swift) and its wholly
owned subsidiaries (collectively referred to as the "Company"), which are
engaged in the acquisition, development, operation, and exploration of oil and

natural gas properties, with particular emphasis on U.S. onshore natural gas
reserves. The Company also has oil and gas investments in Russia, Venezuela, and
New Zealand. The Company's investments in associated oil and gas partnerships
and its joint ventures are accounted for using the proportionate consolidation
method, whereby the Company's proportionate share of each entity's assets,
liabilities, revenues, and expenses is included in the appropriate
classifications in the consolidated financial statements. Intercompany balances
and transactions have been eliminated in preparing the consolidated statements.
Certain reclassifications have been made to prior year amounts to conform to the
current year presentation.

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

Property and Equipment. The Company follows the "full-cost" method of
accounting for oil and gas property and equipment costs. Under this method of
accounting, all productive and nonproductive costs incurred in the acquisition,
exploration, and development of oil and gas reserves are capitalized. Such costs
include lease acquisitions, geological and geophysical services, drilling,
completion, equipment, and certain general and administrative costs directly
associated with acquisition, exploration, and development activities. General
and administrative costs related to production and general overhead are expensed
as incurred. No gains or losses are recognized upon the sale or disposition of
oil and gas properties, except in transactions that involve a significant amount
of reserves. The proceeds from the sale of oil and gas properties are generally
treated as a reduction of oil and gas property costs. Fees from associated oil
and gas exploration and development limited partnerships are credited to oil and
gas property costs to the extent they do not represent reimbursement of general
and administrative expenses currently charged to expense.

Future development, site restoration, and dismantlement and abandonment
costs, net of salvage values, are estimated on a property-by-property basis
based on current economic conditions and are amortized to expense as the
Company's capitalized oil and gas property costs are amortized. The Company's
properties are all onshore and historically the salvage value of the tangible
equipment offsets the Company's site restoration and dismantlement and
abandonment costs. The Company expects this relationship will continue.

The Company computes the provision for depreciation, depletion, and
amortization of oil and gas properties on the unit-of-production method. Under
this method, the Company computes the provision by multiplying the total
unamortized costs of oil and gas properties--including future development, site
restoration, and dismantlement and abandonment costs but excluding costs of
unproved properties--by an overall rate determined by dividing the physical
units of oil and gas produced during the period by the total estimated units of
proved oil and gas reserves. This calculation is done on a country by country
basis for those countries with oil and gas production. The Company currently has
production in the United States only. The cost of unproved properties not being
amortized is assessed quarterly to determine whether the value has been impaired
below the capitalized cost. Any impairment assessed is added to the cost of
proved properties being amortized. To the extent costs accumulated in the
Company's international initiatives will not result in the addition of proved
reserves, an impairment would be charged to income upon such determination.

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

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

All other equipment is depreciated by the straight-line method at rates
based on the estimated useful lives of the property. Repairs and maintenance are
charged to expense as incurred. Renewals and betterments are capitalized.

Deferred Charges. Legal and accounting fees, underwriting fees, printing
costs, and other direct expenses associated with the issuance of the Company's
6.5% Convertible Subordinated Debentures due 2003 ("Debentures") were
capitalized in June 1993 and through June 1996 were being amortized over the
life of the Debentures. Due to the conversion of all outstanding Debentures into
common stock in August 1996, the related unamortized costs ($1,097,551) were
transferred to the Company's appropriate capital accounts in the third quarter
of 1996. The issuance costs associated with the public offering in November 1996
of the Company's 6.25% Convertible Subordinated Notes (the "Notes") have been
capitalized and are being amortized over the life of the Notes, which mature on
November 15, 2006. The balance of these issuance costs at December 31, 1997,
($4,184,014) is net of accumulated amortization of $365,986.

Limited Partnerships and Joint Ventures. Between 1991 and 1995 (and for
prior periods), the Company formed

<PAGE>

limited partnerships and joint ventures for the purpose of acquiring interests
in producing oil and gas properties and, since 1993, partnerships engaged in
drilling for oil and gas reserves. The Company serves as managing general
partner or manager of these entities. Because the Company serves as the general
partner of these entities, under state partnership law it is contingently liable
for the liabilities of these partnerships, virtually all of which are owed to
the Company and are not material for any of the periods presented in relation to
the partnerships' respective assets.

The Company acquired producing oil and gas properties and transferred those
properties to the partnership entities which invested in producing oil and gas
properties at cost, including interest, other carrying costs, closing costs, and
screening and evaluation costs of properties not acquired, or in certain
instances at fair market value based upon the opinion of an independent expert.
These costs were reduced by net operating revenues from the effective date of
the acquisition to the date of transfer to these entities. Such net operating
revenue amounts totaled approximately $100,000, $300,000, and $600,000 in 1997,
1996, and 1995, respectively. The Company, with the acquisitions made in 1997,
has fulfilled its responsibility of acquiring properties for such partnerships,
as these partnerships are fully invested in properties.

Commencing September 15, 1993, the Company began offering, on a private
placement basis, general and limited partnership interests in limited
partnerships to be formed to drill for oil and gas. As managing general partner,
the Company pays for all front-end costs incurred in connection with these
offerings, for which the Company receives an interest in the partnerships.
Through December 31, 1997, approximately $58.6 million had been raised in eleven
partnerships, one formed in each of 1993 and 1994 and three in each of 1995,
1996, and 1997. In May, July, and September 1997, the Company closed the ninth,
tenth, and eleventh partnerships with total subscriptions of approximately $4.4
million, $3.0 million, and $9.4 million, respectively. Costs of syndication and
qualification of these limited partnerships incurred by the Company have been
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.

Hedging Activities. The Company's revenues are primarily the result of
sales of its oil and natural gas production. Market prices of oil and natural
gas may fluctuate and adversely affect operating results. To mitigate some of
this risk, the Company does engage periodically in certain limited hedging
activities, but only to the extent of buying protection price floors for
portions of its and the limited partnerships' oil and gas production. Costs and
any benefits derived from these price floors are accordingly recorded as a
reduction or increase, as applicable, in oil and gas sales revenue and were not
significant for any year presented. The costs to purchase put options are
amortized over the option period. The costs related to the open contracts
totaled approximately $95,308 and had a market value of $121,600 as of December
31, 1997.

Income Taxes. The Company accounts for income taxes using Statement of
Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes."
SFAS No. 109 utilizes the liability method, and deferred taxes are determined
based on the estimated future tax effects of differences between the financial
statement and tax bases of assets and liabilities given the provisions of the
enacted tax laws.

Deferred Revenues. In May 1992, the Company purchased interests in certain
wells using funds provided by the Company's sale of a volumetric production
payment in these properties. Under the production payment agreement, the Company
is required to deliver to Enron approximately 9.5 Bcf over an eight-year period,
or for such longer period as is necessary to deliver a specified heating
equivalent quantity at an average price of $1.115 per MMBtu. The Company is
responsible for all production-related costs associated with operating these
properties. The amount to be delivered varies from month to month in generally
decreasing quantities. To the extent monthly gas production from the properties
exceeds the agreed upon deliverable quantities (as it has in every year since
the purchase date), the Company receives all proceeds from sale of such excess
gas at current market prices plus the proceeds from sale of oil or condensate.
Volumes remaining to be delivered through October 2000 under the volumetric
production payment (approximately 2.0 Bcf at December 31, 1997) are not included
in the Company's proved reserves. Net proceeds from the sale of the production
payment were recorded as deferred revenues. Deliveries under the production
payment agreement are recorded as oil and gas sales revenues and a corresponding
reduction of deferred revenues. Hydrocarbons produced in excess of the amount
required to be delivered are sold by the Company for its own account.

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

Credit Risk Due to Certain Concentrations. The Company extends credit,
primarily in the form of monthly oil and gas sales and joint interest owners
receivables, to various companies in the oil and gas industry, which results in
a concentration of credit risk. The concentration of credit risk may be affected
by changes in economic or other conditions and may accordingly impact the
Company's overall credit risk. However, the Company believes that the risk of
these unsecured receivables is mitigated by the size, reputation, and nature of
the companies to which the Company extends credit.

During the year ended December 31, 1997, three oil or gas purchasers each
accounted for 10% or more of the Company's revenues, with those purchasers
together accounting for approximately 42%. Three oil or gas purchasers accounted
for 10% or more of the Company's revenues during the year ended December 31,
1996, with those purchasers together accounting for approximately 51%. Because
of the availability of other purchasers, the

<PAGE>

Company does not believe that the loss of any single oil or gas purchaser or
contract would materially affect its sales.

Fair Value of Financial Instruments. The Company's financial instruments
consist of cash and cash equivalents, accounts receivable, accounts payable, and
long-term debt. The carrying amounts of cash and cash equivalents, accounts
receivable, and accounts payable approximate fair value due to the highly liquid
nature of these short-term instruments. The fair value of long-term debt was
determined based upon interest rates currently available to the Company for
borrowings with similar terms. The fair value of long-term debt approximates the
carrying amount as of December 31, 1997.

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

2. Income Per Share

The Company has adopted SFAS No. 128, "Earnings per Share," which
establishes new standards for computing and presenting earnings per share. Basic
income per share has been computed using the weighted average number of common
shares outstanding during the respective periods. Basic income per share has
been retroactively restated in all periods presented to give recognition to the
adoption of SFAS No. 128, as well as to give recognition to an equivalent change
in capital structure as a result of a 10% stock dividend declared in October
1997 that resulted in an additional 1,494,606 shares being issued.

The calculation of diluted income per share assumes conversion of the
Company's Notes as of the beginning of the respective periods and the
elimination of the related after-tax interest expense and assumes, as of the
beginning of the period, exercise (using the treasury stock method) of stock
options and warrants. Diluted income per share has also been retroactively
restated for all periods presented to give effect to the adoption of SFAS No.
128 and the 10% stock dividend. For periods presented in which the Notes were
outstanding, the original conversion price of $34.6875 was revised to $31.534 to
reflect the October 1997 stock dividend declared.

The following is a reconciliation of the numerators and denominators used
in the calculation of basic and diluted earnings per share for the years ended
December 31, 1997, 1996, and 1995:

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

3. Provision for Income Taxes
The following is an analysis of the consolidated income tax provision:

<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------
1997 1996 1995
------------- -------------- --------------
<S> <C> <C> <C>
Current............ $ 77,402 $ 759,253 $ (344,137)
Deferred........... 10,742,015 9,001,080 2,326,162
------------- ------------- --------------

Total.............. $ 10,819,417 $ 9,760,333 $ 1,982,025
============= ============= ==============
</TABLE>

<PAGE>

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

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

Provision for income taxes......................... $ 10,819,417 $ 9,760,333 $ 1,982,025
=============== ============== =============
</TABLE>

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

<TABLE>
<CAPTION>
1997 1996
--------------- --------------
<S> <C> <C>
Deferred tax assets:
Alternative minimum tax credits.... $ 1,831,299 $ 1,517,470
Other.............................. 237,587 --
--------------- --------------
Total deferred tax assets....... $ 2,068,886 $ 1,517,470

Deferred tax liabilities:
Oil and gas properties............. $ 26,785,212 $ 15,935,855
Other.............................. 637,824 875,572
--------------- --------------

Total deferred tax liabilities.. $ 27,423,036 $ 16,811,427
--------------- --------------

Net deferred tax liability ........... $ 25,354,150 $ 15,293,957
=============== ==============
</TABLE>

The Company did not record any valuation allowances against deferred tax
assets at December 31, 1997, 1996, and 1995.

At December 31, 1997, the Company had alternative minimum tax credits of
$1,831,299 that carry forward indefinitely available to reduce future regular
tax liability to the extent they exceed the related tentative minimum tax
otherwise due.
- --------------------------------------------------------------------------------

4. Long-Term Debt and Bank Borrowings

Long-Term Debt. The Company's long-term debt at December 31, 1997 and 1996,
consists of $115,000,000 of 6.25% Convertible Subordinated Notes due 2006
("Notes"). The Notes were issued on November 25, 1996, and will mature on
November 15, 2006. The Notes are convertible into common stock of the Company at
the option of the holders at any time prior to maturity at an adjusted
conversion price of $31.534 per share, subject to adjustment upon the occurrence
of certain events. The original conversion price of $34.6875 was adjusted
downward to reflect the October 1997 10% stock dividend. Interest on the Notes
is payable semiannually on May 15 and November 15, commencing with the first
payment on May 15, 1997. On or after November 15, 1999, the Notes are redeemable
for cash at the option of the Company, with certain restrictions, at 104.375% of
principal, declining to 100.625% in 2005. Upon certain changes in control of the
Company, if the price of the Company's common stock is not above certain levels,
each holder of Notes will have the right to require the Company to repurchase
the Notes at the principal amount thereof, together with accrued and unpaid
interest to the date of repurchase but after the repayment of any Senior
indebtedness, as defined.

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

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

Bank Borrowings. At the end of 1996, the Company had available, through a
two bank-group, a $100,000,000 unsecured revolving line of credit. The available
borrowing base at December 31, 1996, was $5,000,000. Prior to December 1, 1996,
the borrowing base was $30,000,000. At the Company's request, it was reduced to
the $5,000,000 amount effective December 1, 1996. This was requested in order to
reduce the amount of commitment fees paid on this facility, the calculation of
which is described below. Depending on the level of outstanding debt, the
interest rate is either the bank's base rate (8.25% at December 31, 1996) or the
bank's base rate plus 0.25%. This facility also allows, at the Company's option,
draws which bear interest for

<PAGE>

specific periods at the London Interbank Offered Rate ("LIBOR"). The LIBOR
option will now vary from LIBOR plus 1% to plus 1.5%. There was no outstanding
balance under this line of credit at December 31, 1996.

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

The terms of the revolving line of credit include, among other
restrictions, a limitation on the level of cash dividends (not to exceed
$2,000,000 in any fiscal year), requirements as to maintenance of certain
minimum financial ratios (principally pertaining to working capital, debt, and
equity ratios), and limitations on incurring other debt. Since inception, no
cash dividends have been declared on the Company's common stock. For all periods
presented, the Company was in compliance with the provisions of these
agreements.

The Company's other credit facility, which is the Company's only secured
facility, is an amended and restated revolving line of credit with the lead bank
of the two bank-group, secured by certain Company receivables. Effective April
30, 1996, this facility was increased to $7,000,000, with interest at the bank's
base rate less 0.25% (8% at December 31, 1996 and 8.25% at December 31, 1997).
The available borrowing base was $2,000,000 at December 31, 1996, and $5,484,000
at December 31, 1997, and is redetermined monthly. There were no outstanding
amounts under this facility at December 31, 1996, while at December 31, 1997,
the outstanding amount was $5,484,000. The restated credit facility extends
through September 30, 1999.

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

5. Commitments and Contingencies

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

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

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

6. Stockholders' Equity

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

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

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

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

The Company also granted certain stock options to individuals who were
neither employees, officers, nor directors for specific services rendered to the
Company. During 1996 all of these remaining options were either exercised
(57,555 shares) or canceled (11,195 shares) so that no such options remain
outstanding.

The employee stock purchase plan provides eligible employees the
opportunity to acquire shares of Company common stock at a discount through
payroll deductions. This plan was approved at the May 11, 1993, shareholders
meeting. The plan year is from June 1 to the following May 31. The first year of
the plan commenced June 1, 1993. Employees may authorize payroll deductions of
up to 10% of their base salary during the plan year by making an election to
participate prior to the start of a plan year. The purchase price for stock
acquired under the plan will be 85% of the lower of the closing price of the
Company's common stock as quoted on the New York Stock Exchange at the beginning
or end of the plan year or a date during the year chosen by the participant.
Under this plan the Company issued 26,551 shares at a price of $15.19 in 1997,
36,387 shares at a price range of $6.59 to $7.97 in 1996, and 37,689 shares at a
price range of $6.80 to $7.92 in 1995. The estimated weighted average fair value
of shares issued under this plan was $4.39 in 1997, $2.13 in 1996, and $2.59 in
1995. As of December 31, 1997, there remained 458,204 shares available for
issuance under this plan. There are no charges or credits to income in
connection with this plan.

<PAGE>

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

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

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

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

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

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

<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
-------------------------------------- ------------------------
Wtd. Avg.
Range of Number Remaining Wtd. Avg. Number Wtd. Avg.
Exercise Outstanding Contractual Exercise Exercisable Exercise
Prices at 12/31/97 Life Price at 12/31/97 Price
------------- ------------ ------------ ----------- ------------ -----------
<S> <C> <C> <C> <C> <C>
$ 4 to $ 9 787,384 4.8 $ 7.73 606,413 $ 7.63
$ 9 to $18 358,900 6.2 $ 10.67 220,631 $ 9.68
$18 to $27 615,228 9.5 $ 26.00 42,440 $ 25.91
--------- -------
$ 4 to $27 1,761,512 6.7 $ 14.71 869,484 $ 9.05
========= =======
</TABLE>

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

<PAGE>

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

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

7. Related-Party Transactions

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

8. Foreign Activities

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

The Company formed a wholly-owned subsidiary, Swift Energy de Venezuela, C.
A., for the purpose of submitting a bid on August 5, 1993, under the Venezuelan
Marginal Oil Field Reactivation Program. Although the Company did not win the
bid, it has continued to pursue cooperative ventures involving other fields and
opportunities in Venezuela. The Company evaluated a number of Blocks being
offered by Petroleos de Venezuela, S. A. under the Third Operating Agreement
Round in 1997, but decided against submitting any bid on these Blocks. The
Company has entered into an agreement with Tecnoconsult, S. A., a Venezuelan
company, to jointly formulate and submit a proposal to Petroleos de Venezuela,
S. A. for the construction and operation of a methane pipeline. Currently, the
technical and economic feasibility of the project is under study. At December
31, 1997, the Company's investment in Venezuela was approximately $2,435,000 and
is included in the unproved properties portion of oil and gas properties, net of
impairments of $45,668.

Since October 1995, the Company has been issued two Petroleum Exploration
Permits by the New Zealand Minister of Energy. The first permit covers
approximately 65,000 acres in the Onshore Taranaki Basin of New Zealand's North
Island, and the second covers approximately 69,300 adjacent acres. Under the
terms of these permits, the Company is obligated to analyze and interpret
certain seismic data, acquire certain new seismic data and drill one exploratory
well, to be followed by a development well or additional seismic work, all of
which is to be performed on a staged basis in order to maintain the permits,
over periods extending through July 2000 for the first permit and August 1999
for the second permit. The Company formed a wholly-owned subsidiary, Swift
Energy New Zealand Limited, for the purpose of conducting its New Zealand
activities and assigned its interest in the permits to that subsidiary during
the third quarter of 1997. At December 31, 1997, the Company's investment in New
Zealand was approximately $2,480,000 and is included in the unproved properties
portion of oil and gas properties.

<PAGE>

Supplemental Information (Unaudited)
- --------------------------------------------------------------------------------
Swift Energy Company and Subsidiaries

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

<TABLE>
<CAPTION>
Year ended December 31,
----------------------------------------
1997 1996
---------------- ----------------
<S> <C> <C>
Oil and Gas Properties:
Proved..................................... $ 326,836,431 $ 216,310,033
Unproved (not being amortized)--Domestic... 26,735,460 15,733,952
Unproved (not being amortized)--Foreign.... 15,104,349 11,886,510
---------------- ----------------
368,676,240 243,930,495
Accumulated Depreciation, Depletion, and
Amortization............................... (67,363,393) (43,920,120)
---------------- ----------------
$ 301,312,847 $ 200,010,375
================ ================
</TABLE>

Of the $41,839,809 of net unproved property costs (primarily seismic and
lease acquisition costs) at December 31, 1997, being excluded from the
amortizable base, $20,120,485 was incurred in 1997, $8,990,306 was incurred in
1996, $4,583,249 was incurred in 1995, and $8,145,769 was incurred in prior
years. The Company expects it will complete its evaluation of the properties
representing the majority of these costs within the next two to three years.

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

<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------
1997 1996 1995
--------------- -------------- --------------
<S> <C> <C> <C>
Acquisition of proved properties......................... $ 8,417,318 $ 1,529,611 $ 3,461,091
Lease acquisitions (1),(2)............................... 21,603,732 16,426,327 9,742,543
Exploration.............................................. 10,705,115 2,704,281 2,289,814
Development.............................................. 90,329,619 69,067,024 23,555,988
--------------- -------------- --------------

Total (3)................................................ $ 131,055,784 $ 89,727,243 $ 39,049,436
=============== ============== ==============
</TABLE>

(1) Lease acquisitions for 1997, 1996, and 1995 include expenditures of
$658,145, $2,712,278, and $2,814,395, respectively, relating to the Company's
initiatives in Russia; 1997, 1996, and 1995 expenditures of $828,133, $487,597,
and $304,610, respectively, relating to initiatives in Venezuela; and 1997,
1996, and 1995 expenditures of $1,731,561, $545,980, and $202,206, respectively,
relating to initiatives in New Zealand.

(2) These are actual amounts as incurred by year, including both proved and
unproved lease costs. The annual lease acquisition amounts added to proved oil
and gas properties (being amortized) for 1997, 1996, and 1995, respectively,
were $7,384,385, $9,458,016, and $3,895,871.

(3) Includes capitalized general and administrative costs directly associated
with the acquisition, development, and exploration efforts of approximately
$11,700,000, $7,400,000, and $7,100,000 in 1997, 1996, and 1995, respectively.
In addition, total includes $2,326,691, $1,549,575, and $1,442,022 in 1997,
1996, and 1995, respectively, of capitalized interest on unproved properties.

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

<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------
1997 1996 1995
--------------- --------------- --------------
<S> <C> <C> <C>
Oil and gas sales............................... $ 69,015,189 $ 52,770,672 $ 22,527,892
Production costs................................ (11,383,887) (8,377,044) (6,826,306)
Depreciation, depletion, and amortization....... (23,443,273) (15,812,134) (8,349,324)
--------------- --------------- --------------
34,188,029 28,581,494 7,352,262
Income taxes ................................... (11,165,058) (9,689,126) (2,110,099)
--------------- --------------- --------------
Results of producing activities................. $ 23,022,971 $ 18,892,368 $ 5,242,163
=============== =============== ==============
Amortization per physical unit of production
(equivalent Mcf of gas)..................... $ 0.92 $ 0.81 $ 0.75
=============== =============== ==============
</TABLE>

Supplemental Reserve Information. The following information presents
estimates of the Company's proved oil and gas reserves, which are all located
onshore in the United States. All of the Company's reserves were determined by
Company personnel and audited by H. J. Gruy and Associates, Inc. ("Gruy"),
independent petroleum consultants. Gruy's summary report dated February 9, 1998,
is set forth as an exhibit to the Form 10-K Report for the year ended December
31, 1997, and includes definitions and assumptions that served as the basis for
the estimates of proved reserves and future net cash flows. Such definitions and
assumptions should be referred to in connection with the following information:

<PAGE>

Estimates of Proved Reserves

<TABLE>
<CAPTION>
Oil and
Natural Gas Condensate
(Mcf) (Bbls)
------------- -------------
<S> <C> <C>
Proved reserves as of December 31, 1994(1).......... 76,263,964 4,553,267
Revisions of previous estimates(2)............... 6,982,317 (421,901)
Purchases of minerals in place................... 4,166,922 254,211
Sales of minerals in place....................... (13,215) (10,617)
Extensions, discoveries, and other additions..... 62,870,240 1,592,456
Production(3).................................... (6,702,708) (545,435)
------------- -----------
Proved reserves as of December 31, 1995(1).......... 143,567,520 5,421,981
Revisions of previous estimates(2)............... (9,544,391) (816,065)
Purchases of minerals in place................... 2,676,393 97,178
Sales of minerals in place....................... (4,163,770) (340,706)
Extensions, discoveries, and other additions..... 107,762,886 1,745,307
Production(3).................................... (14,540,437) (623,386)
------------- -------------
Proved reserves as of December 31, 1996(1).......... 225,758,201 5,484,309
Revisions of previous estimates(2)............... (22,774,899) (427,412)
Purchases of minerals in place................... 30,342,398 580,278
Sales of minerals in place....................... (1,155,706) (50,909)
Extensions, discoveries, and other additions..... 102,479,883 2,945,037
Production(3).................................... (20,344,208) (672,385)
------------- -------------
Proved reserves as of December 31, 1997(1).......... 314,305,669 7,858,918
============= =============

Proved developed reserves,
December 31, 1994................................ 46,406,448 3,209,387
December 31, 1995................................ 81,532,025 3,313,226
December 31, 1996................................ 135,424,880 3,622,480
December 31, 1997................................ 191,108,214 4,288,696
</TABLE>

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

(2)Revisions of previous quantity estimates are related to upward or downward
variations based on current engineering information for production rates,
volumetrics, and reservoir pressure. Additionally, changes in quantity estimates
are affected by the increase or decrease in crude oil and natural gas prices at
each year end. Proved reserves as of December 31, 1997, were based upon prices
of $2.78 per Mcf of natural gas and $15.76 per barrel of oil, compared to $4.47
per Mcf and $23.75 per barrel as of December 31, 1996.

(3)Natural gas production for 1995, 1996, and 1997 excludes 1,211,255,
1,156,361, and 1,015,226 Mcf, respectively, delivered under the Company's
volumetric production payment agreement.

Standardized Measure of Discounted Future Net Cash Flows. The standardized
measure of discounted future net cash flows relating to proved oil and gas
reserves is as follows:

<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------
1997 1996 1995
--------------- ----------------- ----------------
<S> <C> <C> <C>
Future gross revenues ................................... $ 994,828,072 $ 1,141,831,786 $ 445,572,715
Future production costs ................................. (273,475,056) (228,626,881) (121,317,850)
Future development costs ................................ (92,946,811) (59,988,855) (42,607,921)
--------------- ----------------- ----------------
Future net cash flows before income taxes................ 628,406,205 853,216,050 281,646,944
Future income taxes...................................... (135,587,216) (211,375,632) (55,469,213)
--------------- ----------------- ----------------
Future net cash flows after income taxes................. 492,818,989 641,840,418 226,177,731
Discount at 10% per annum................................ (199,980,649) (274,608,116) (97,273,647)
--------------- ----------------- ----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves............... $ 292,838,340 $ 367,232,302 $ 128,904,084
=============== ================= ================
</TABLE>

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

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

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

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

4. Future income taxes are computed by applying the statutory tax rate to
future net cash flows reduced by the tax

33
<PAGE>

basis of the properties, the estimated permanent differences applicable to
future oil and gas producing activities, and tax carry forwards.

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

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

The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------
1997 1996 1995
---------------- --------------- --------------
<S> <C> <C> <C>
Beginning balance ................................. $ 367,232,302 $ 128,904,084 $ 66,471,967
---------------- --------------- --------------
Revisions to reserves proved in prior years--
Net changes in prices, production costs,
and future development costs............... (238,743,291) 144,386,724 25,415,116
Net changes due to revisions in quantity
estimates.................................. (27,188,512) (25,755,091) 4,735,186
Accretion of discount .......................... 47,068,172 14,703,841 6,939,460
Other........................................... (38,347,310) 6,649,394 (10,981,721)
---------------- --------------- --------------
Total revisions ................................... (257,210,941) 139,984,868 26,108,041

New field discoveries and extensions, net of future
production and development costs................ 110,396,029 208,250,909 44,292,042
Purchases of minerals in place..................... 29,290,334 6,835,362 4,928,563
Sales of minerals in place......................... (2,373,547) (8,084,581) (74,858)
Sales of oil and gas produced, net of production
costs........................................... (56,181,494) (42,723,456) (13,913,612)
Previously estimated development costs incurred.... 55,742,684 19,883,446 16,303,629
Net change in income taxes......................... 45,942,973 (85,818,330) (15,211,688)
---------------- --------------- --------------
Net change in standardized measure of discounted
future net cash flows........................... (74,393,962) 238,328,218 62,432,117
---------------- --------------- --------------
Ending balance..................................... $ 292,838,340 $ 367,232,302 $ 128,904,084
================ =============== ==============
</TABLE>

Quarterly Results. The following table presents summarized quarterly
financial information for the years ended December 31, 1996 and 1997:

<TABLE>
<CAPTION>
Income Before Basic Income Diluted Income
Revenues Income Taxes Net Income Per Share(1) Per Share(1)
---------------- --------------- --------------- ------------- --------------
<S> <C> <C> <C> <C> <C>
1996
First Quarter $ 11,188,847 $ 4,561,523 $ 3,082,381 $ .22 $ .20
Second Quarter 12,557,891 5,480,944 3,678,316 .26 .24
Third Quarter 15,432,193 7,178,573 4,641,953 .30 .29
Fourth Quarter 21,589,301 11,564,743 7,622,800 .46 .46
---------------- --------------- ---------------
Total $ 60,768,232 $ 28,785,783 $ 19,025,450 $ 1.27 $ 1.25
================ =============== ===============

1997
First Quarter $ 21,245,469 $ 10,161,045 $ 6,769,263 $ .41 $ .37
Second Quarter 16,925,842 6,007,474 4,113,689 .25 .24
Third Quarter 19,225,453 7,024,524 4,685,689 .29 .27
Fourth Quarter 22,525,438 9,936,563 6,741,548 .41 .37
---------------- --------------- ---------------
Total $ 79,922,202 $ 33,129,606 $ 22,310,189 $ 1.35 $ 1.26
================ =============== ===============
</TABLE>

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

<PAGE>

Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure

None.
- --------------------------------------------------------------------------------

PART III

Item 10. Directors and Executive Officers of the Registrant

The information to be set forth under the captions "Election of Directors"
and "Executive Officers" in the Company's definitive proxy statement to be filed
within 120 days after the close of the fiscal year end in connection with the
May 12, 1998, annual shareholders' meeting is incorporated herein by reference.

Item 11. Executive Compensation

The information appearing under the caption "Executive Officers--Executive
Cash Compensation" in the Company's definitive proxy statement to be filed
within 120 days after the close of the fiscal year end in connection with the
May 12, 1998, annual shareholders' meeting is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management

The information appearing under the caption "Principal Shareholders" in the
Company's definitive proxy statement to be filed within 120 days after the close
of the fiscal year end in connection with the May 12, 1998, annual shareholders'
meeting is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions

The information appearing under the caption "Transactions with Affiliates"
(if any such captioned information is included) in the Company's definitive
proxy statement to be filed within 120 days after the close of the fiscal year
end in connection with the May 12, 1998, annual shareholders' meeting is
incorporated herein by reference.

<PAGE>

PART IV

Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a) 1. The following consolidated financial statements of Swift Energy
Company together with the report thereon of Arthur Andersen LLP dated February
10, 1998, and the data contained therein are included in Item 8 hereof:

Report of Independent Public Accountants............................20
Consolidated Balance Sheets.........................................21
Consolidated Statements of Income...................................22
Consolidated Statements of Stockholders' Equity.....................23
Consolidated Statements of Cash Flows...............................24
Notes to Consolidated Financial Statements..........................25

2. Financial Statement Schedules

None

3. Exhibits
<TABLE>
<S> <C>
3(a).1(1) Articles of Incorporation, as amended through June 3, 1988.
3(a).2(2) Articles of Amendment to Articles of Incorporation filed on
June 4, 1990.
3(b)(3) By-Laws, as amended through August 14, 1995.
4(b)(4) Indenture dated as of June 30, 1993, between Swift Energy
Company and Bank One, Texas, National Association as
Trustee.
10.1(1) + Indemnity Agreement dated July 8, 1988, between Swift Energy
Company and A. Earl Swift (plus schedule of other persons
with whom Indemnity Agreements have been entered into).
10.2(4) Amended and Restated Credit Agreement dated March 24, 1992,
between Swift Energy Company and Bank One, Texas, National
Association.
10.3(4) Purchase and Sale Agreement dated May 27, 1992, between
Swift Energy Company and Enron Reserve Acquisition Corp.
10.4(4) Purchase and Sale Agreement dated May 12, 1992, between the
Company and Riverwood Energy Resources, Inc.
10.5(5) + Swift Energy Company 1990 Nonqualified Stock Option Plan.
10.6(6) First Amendment effective May 13, 1993, to Amended and
Restated Credit Agreement dated March 24, 1992, between
Swift Energy Company and Bank One, Texas, National
Association.
10.7(6) Second Amendment effective December 31, 1993, to Amended and
Restated Credit Agreement dated March 24, 1992, between
Swift Energy Company and Bank One, Texas, National
Association.
10.8(6) Third Amendment dated December 31, 1994, to Amended and
Restated Credit Agreement dated March 24, 1992, between
Swift Energy Company and Bank One, Texas, National
Association.
10.9(7) Amended and Restated Credit Agreement dated March 1, 1994,
among Swift Energy Company, Bank One, Texas, National
Association and Bank of Montreal.
10.10(7) First Amendment dated June 15, 1994, to Amended and Restated
Credit Agreement dated March 1, 1994, among Swift Energy
Company, Bank One, Texas, National Association and Bank of
Montreal.
10.11(6) Second Amendment dated December 31, 1994, to Amended and
Restated Credit Agreement dated March 1, 1994, among Swift
Energy Company, Bank One, Texas, National Association and
Bank of Montreal.
10.12(8) Credit Agreement dated April 30, 1996, among Swift Energy
Company, Bank One, Texas, National Association and Bank of
Montreal.
10.13(8) Credit Agreement dated April 30, 1996, among Swift Energy
Company, Bank One, Texas, National Association.
10.14(9) + Amended and Restated Swift Energy Company 1990 Stock
Compensation Plan, as of May 1993.
10.15(3) + Employment Agreement dated as of November 1, 1995, by and
between Swift Energy Company and Terry E. Swift.
10.16(3) + Employment Agreement dated as of November 1, 1995, by and
between Swift Energy Company and John R. Alden.
10.17(3) + Employment Agreement dated as of November 1, 1995, by and
between Swift Energy Company and James M. Kitterman.
10.18(3) + Employment Agreement dated as of November 1, 1995, by and
between Swift Energy Company and Bruce H. Vincent.
10.19(3) + Employment Agreement dated as of November 1, 1995, by and
between Swift Energy Company and A. Earl Swift.
10.20(9) + Agreement and Release between Swift Energy Company and
Virgil Neil Swift effective June 1, 1994.
10.21(10)+ First Amendment to Agreement and Release dated as of
12/1/95, by and between Swift Energy Company and Virgil Neil
Swift.
10.22(10)+ Second Amendment to Agreement and Release dated as of
2/2/96, by and between Swift Energy Company and Virgil Neil
Swift, effective January 1, 1996.
10.23(10)+ Second [sic] Amendment to Agreement and Release dated as of
1/14/97, by and between Swift Energy Company and Virgil Neil
Swift, effective December 1, 1996.
10.24(11) Indenture dated as of November 25, 1996, between Swift
Energy Company and Bank One, Columbus, N.A. as Trustee.
10.25(12) Rights Agreement dated as of August 1, 1997 between Swift
Energy Company and American Stock Transfer & Trust Company.
18(6) Letter from Arthur Andersen LLP regarding change in
accounting principle.
21(9) List of Subsidiaries of Swift Energy Company.
</TABLE>

36
<PAGE>

<TABLE>
<CAPTION>
<S> <C>
23(a)13 The consent of H. J. Gruy and Associates, Inc.
23(b)13 The consent of Arthur Andersen LLP as to incorporation by
reference regarding Form S-8 and S-3 Registration
Statements.
27 Financial Data Schedule (included in electronic filing
only).
99(13) The summary of H. J. Gruy and Associates, Inc. report, dated
February 9, 1998.
</TABLE>

(b) No Form 8-K reports were filed during the fourth quarter of 1997.

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

(1)Incorporated by reference from Swift Energy Company Annual Report on Form
10-K for the fiscal year ended December 31, 1988, File No. 1-8754.

(2)Incorporated by reference from Swift Energy Company Annual Report on Form
10-K for the fiscal year ended December 31, 1992.

(3)Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q filed for the quarterly period ended September 30, 1995.

(4)Incorporated by reference from Registration Statement No. 33-63112 on Form
S-1 filed on May 20, 1993.

(5)Incorporated by reference from Registration Statement No. 33-36310 on Form
S-8 filed on August 10, 1990.

(6)Incorporated by reference from Swift Energy Company Annual Report on Form
10-K from the fiscal year ended December 31, 1994.

(7)Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q filed for the quarterly period ended June 30, 1994.

(8)Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q filed for the quarterly period ended March 31, 1996.

(9)Incorporated by reference from Registration Statement No. 33-60469 filed on
June 22, 1995.

(10)Incorporated by reference from Swift Energy Company Annual Report on Form
10-K from the fiscal year ended December 31, 1996.

(11)Incorporated by reference from Registration Statement No. 33-14785 on Form
S-3 filed on October 24, 1996.

(12)Incorporated by reference from Swift Energy Company Report on Form 8-K dated
August 1, 1997.

(13)Filed herewith.

+ Management contract or compensatory plan or arrangement.

<PAGE>

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant, Swift Energy Company, has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.

SWIFT ENERGY COMPANY

By /S/ A. Earl Swift
------------------------------
A. Earl Swift
Chairman of the Board,
Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant, Swift Energy Company, and in the capacities and on the dates
indicated:

<TABLE>
<CAPTION>
Signatures Title Date
---------- ----- ----
<S> <C> <C>

/S/ A. Earl Swift Chairman of the Board
- ---------------------------------- Chief Executive Officer March 24, 1998
A. Earl Swift

/S/ John R. Alden Senior Vice President--Finance
- ---------------------------------- Principal Financial Officer March 24, 1998
John R. Alden

/S/ Alton D. Heckaman, Jr. Vice President & Controller
- ---------------------------------- Principal Accounting Officer March 24, 1998
Alton D. Heckaman, Jr.

/S/ Virgil N. Swift
- ---------------------------------- Director March 24, 1998
Virgil N. Swift
</TABLE>

<PAGE>

Signatures Title Date
---------- ----- ----
<S> <C> <C>

/S/ G. Robert Evans
- ---------------------------------- Director March 24, 1998
G. Robert Evans

/S/ Raymond O. Loen
- ---------------------------------- Director March 24, 1998
Raymond O. Loen

/S/ Henry C. Montgomery
- ---------------------------------- Director March 24, 1998
Henry C. Montgomery

/S/ Clyde W. Smith, Jr.
- ---------------------------------- Director March 24, 1998
Clyde W. Smith, Jr.

/S/ Harold J. Withrow
- ---------------------------------- Director March 24, 1998
Harold J. Withrow
</TABLE>

<PAGE>

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20439

EXHIBITS

FORM 10-K REPORT

FOR THE

YEAR ENDED DECEMBER 31, 1997

SWIFT ENERGY COMPANY

16825 NORTHCHASE DRIVE, SUITE 400

HOUSTON, TEXAS 77060

<PAGE>

EXHIBITS

23 (a) The consent of H.J. Gruy and Associates, Inc.

23 (b) The consent of Arthur Andersen LLP as to incorporation by reference
regarding Form S-8 and S-3 Registration Statements.

99 The summary of H.J. Gruy and Associates, Inc. report, dated February 9,
1998.

<PAGE>

EXHIBIT 23 (A)

<PAGE>

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

H.J. Gruy and Associates, Inc. (Gruy) hereby consents to the reference
in the Annual Report on Form 10-K of Swift Energy Company for the year ended
December 31, 1997, to our letter report dated February 9, 1998, relating to our
audit of Swift Energy Company's estimates of proved oil and gas reserves.

Yours very truly,

H.J. GRUY AND ASSOCIATES, INC.

Houston, Texas
March 24, 1998

JHH:akr
A:\CONSENT.LTR

<PAGE>

EXHIBIT 23 (B)

<PAGE>

CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS

As independent public accountants, we hereby consent to the incorporation of our
report dated February 10, 1998, included in the annual report of Swift Energy
Company on Form 10-K for the year ended December 31, 1997, into Swift Energy
Company's previously filed Registration Statements File Numbers 33-14305,
33-36310, 33-80228, 33-80240, and 333-12831 on Form S-8 and S-3.

ARTHUR ANDERSEN LLP

Houston, Texas
March 24, 1998

<PAGE>

EXHIBIT 99

<PAGE>

February 9, 1998

Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060

Re: Reserves Audit
97-003-133

Gentlemen:

At your request, we have audited the reserves and future net revenue as of
December 31, 1997, prepared by Swift Energy Company ("Swift") for certain
interests owned by Swift through partnerships in 11 drilling funds, 29 income
funds, 16 pension asset funds, and 34 depositary interest funds along with
several additional interests owned directly by Swift Energy Company. This audit
has been conducted according to the standards pertaining to the estimating and
auditing of oil and gas reserve information approved by the Board of Directors
of the Society of Petroleum Engineers on October 30, 1979. We have reviewed
these properties and where we disagreed with the Swift reserve estimates, Swift
revised its estimates to be in agreement. The estimated net reserves, future net
revenue and discounted future net revenue are summarized by reserve category as
follows:

<TABLE>
<CAPTION>
Estimated Net Reserves Estimated Future Net Revenue
----------------------------------- ----------------------------------------
Oil & Discounted
Condensate Gas at 10%
(Barrels) (Mcf) Nondiscounted Per Year
---------------- ---------------- ------------------- -----------------
<S> <C> <C> <C> <C>
Proved Developed......... 4,288,696 191,108,214 $412,092,801 $244,365,044

Proved Undeveloped....... 3,570,222 123,197,455 $216,313,406 $105,979,738
---------------- ---------------- ------------------- -----------------

Total Proved............. 7,858,918 314,305,669 $628,406,207 $350,344,782

G & A.................... ($10,196,418) ($5,988,505)
---------------- ---------------- ------------------- -----------------

TOTAL.................... 7,858,918 314,305,669 $618,209,789 $344,356,277
</TABLE>

Attachment I summaries the reserves and cash flow of Swift by partnership and
the additional interests owned directly by Swift.

<PAGE>

Swift Energy Company 2 February 9, 1998

The discounted future net revenue is not represented to be the fair market value
of these reserves and the estimated reserves included in this report have not
been adjusted for risk.

The estimated future net revenue shown is that revenue which will be realized
from the sale of the production from estimated net reserves after deduction of
royalties, ad valorem and production taxes, direct operating costs and required
capital expenditures, when applicable. Surface and well equipment salvage values
and well plugging and field abandonment costs have not been considered in the
cash flow projections. Future net cash flow as stated in this report is before
the deduction of federal income tax.

In the economic projections, prices, operating costs and development costs
remain constant for the projected life of each lease.

For those wells with sufficient production history, reserve estimates and rate
projections are based on the extrapolation of established performance trends.
Reserves for other producing and nonproducing properties have been estimated
from volumetric calculations and analogy with the performance of comparable
wells. The reserves included in this study are estimates only and should not be
construed as exact quantities. Future conditions may affect recovery of
estimated reserves and cash flow, and all categories of reserves may be subject
to revision as more performance data become available. The proved reserves in
this report conform to the applicable definitions promulgated by the Securities
and Exchange Commission. Attachment II, following this letter, sets forth all
reserve definitions incorporated in this study.

Extent and character of ownership, oil and gas prices, production data, direct
operating costs, capital expenditure estimates and other data provided by Swift
have been accepted as represented. The production data available to us were
through the month of October 1997 except in those instances in which data were
available through December. Interim production to December 31, 1997 has been
estimated. No independent well tests, property inspections or audits of
operating expenses were conducted by our staff in conjunction with this study.
We did not verify or determine the extent, character, obligations, status or
liabilities, if any, arising from any current or possible future environmental
liabilities that might be applicable.

In order to audit the reserves, costs and future cash flows shown in this
report, we have relied in part on geological, engineering and economic data
furnished by our client. Although we have made a best efforts attempt to acquire
all pertinent data and to analyze it carefully with methods accepted by the
petroleum industry, there is no guarantee that the volumes of oil or gas or the
cash flows projected will be realized.

Production rates may be subject to regulation and contract provisions and may
fluctuate according to market demand or other factors beyond the control of the
operator. The reserve and cash flow projections presented in this report may
require revision as additional data become available.

<PAGE>

Swift Energy Company 3 February 9, 1998

We are unrelated to Swift and we have no interest in the properties included in
the information reviewed by us. In particular:

1. We do not own a financial interest in Swift or its oil and gas
properties.

2. Our fee is not contingent on the outcome of our work or report.

3. We have not performed other services for or have any other
relationship with Swift that would affect our independence.

If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such person with the approval of our
client is invited to visit our offices at his expense so that he can evaluate
the assumptions made and the completeness and extent of the data available on
which our estimates are based.

Any distribution or publication of this report or any part thereof must include
this letter in its entirety.

Yours very truly,

H.J. GRUY AND ASSOCIATES, INC.

James H. Hartsock, PhD., P.E.
Executive Vice President

JHH:llb
A:\YEAREND.LTR
Attachment

<PAGE>

ATTACHMENT II

DEFINITIONS OF PROVED OIL AND GAS RESERVES(1)

PROVED OIL AND GAS RESERVES

Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquid which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.

Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.

Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis an which the project or program was based.

Estimates of proved reserves do not include the following: (A) oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.

PROVED DEVELOPED OIL AND GAS RESERVES

Proved developed oil and gas reserves arc reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.

PROVED UNIDEVELOPED RESERVES

Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.

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

(1)Contained in Securities and Exchange Commission Regulation S-X, Rule 4-10 (a)
A:\FORMS\NEW_SEC.

<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM SWIFT ENERGY
COMPANY'S FINANCIAL STATEMENTS CONTAINED IN ITS ANNUAL REPORT ON FORM 10-K FOR
THE YEAR ENDED DECEMBER 31, 1997.
</LEGEND>

<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 2,047,332
<SECURITIES> 0
<RECEIVABLES> 27,432,839
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 29,981,786
<PP&E> 374,919,167
<DEPRECIATION> 70,700,240
<TOTAL-ASSETS> 339,115,390
<CURRENT-LIABILITIES> 28,517,664
<BONDS> 0
0
0
<COMMON> 168,470
<OTHER-SE> 159,232,450
<TOTAL-LIABILITY-AND-EQUITY> 339,115,390
<SALES> 69,015,189
<TOTAL-REVENUES> 79,922,202
<CGS> 0
<TOTAL-COSTS> 35,631,029<F1>
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 5,032,952
<INCOME-PRETAX> 33,129,606
<INCOME-TAX> 10,819,417
<INCOME-CONTINUING> 22,310,189
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 22,310,189
<EPS-PRIMARY> 1.35<F2>
<EPS-DILUTED> 1.26<F2>
<FN>
<F1>INCLUDES DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE AND OIL AND GAS
PRODUCTION COSTS. EXCLUDES GENERAL AND ADMINISTRATIVE AND INTEREST EXPENSE.
<F2>PREPARED IN ACCORDANCE WITH SFAS NO. 128. BASIC AND DILUTED EPS HAVE BEEN
ENTERED IN PLACE OF PRIMARY AND FULLY DILUTED, RESPECTIVELY. PRIOR PERIOD
RESTATEMENTS ARE CONTAINED IN THE COMPANY'S CONSOLIDATED FINANCIAL STATEMENTS
CONTAINED IN ITS ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31,1997.
</FN>

</TABLE>