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, 1998
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, 1999 was approximately $110,936,000.
The number of shares of common stock outstanding as of December 31, 1998 was
16,291,242 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 11, 1999
<PAGE>
Form 10-K
Swift Energy Company and Subsidiaries
10-K Part and Item No. Page
<TABLE>
<CAPTION>
<S> <C> <C>
Part I
Item 1. Business 3
Item 2. Properties 3
Item 3. Legal Proceedings 17
Item 4. Submission of Matters to a Vote of
Security Holders 17
Part II
Item 5. Market for the Registrant's Common
Equity and Related Stockholder Matters 17
Item 6. Selected Financial Data 18
Item 7. Management's Discussion and
Analysis of Financial Condition
and Results of Operations 20
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 25
Item 8. Financial Statements and Supple-
mentary Data 26
Item 9. Changes in and Disagreements with
Accountants on Accounting and
Financial Disclosure 49
Part III
Item 10. Directors and Executive Officers of
the Registrant (1) 49
Item 11. Executive Compensation (1) 49
Item 12. Security Ownership of Certain Bene-
ficial Owners and Management (1) 49
Item 13. Certain Relationships and Related
Transactions (1) 49
Part IV
Item 14. Exhibits, Financial Statement
Schedules and Reports on Form 8-K 50
</TABLE>
(1) Incorporated by reference from Notice and Proxy Statement for the
Annual Meeting of Shareholders to be held May 11, 1999.
2
<PAGE>
PART I
Items 1 and 2. Business and Properties
See pages 15 and 16 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, 1998, the Company had interests in over
1,750 oil and gas wells located in eight states, of which the Company operated
836 wells representing 91% of its proved reserves base. At such date, the
Company had estimated proved reserves of 436.1 Bcfe, of which approximately 81%
was natural gas, 55% was proved developed, and 97% was located in both Texas
(84%) and Louisiana (13%).
The Company's primary focus is development and exploration drilling in its
core areas, the AWP Olmos Field located in South Texas and the Austin Chalk
trend in Texas and Louisiana. 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 51% and 42%, respectively, of the Company's proved
reserves as of December 31, 1998, and approximately 40% and 48%, respectively,
of the Company's production during 1998.
In the third quarter of 1998, the Company purchased the Toledo Bend
Properties from Sonat Exploration Company ("Toledo Bend Properties") for
approximately $87.0 million in cash, with approximately $56.8 million of the
total spent for producing properties, approximately $15.0 million to purchase an
interest in two gas processing plants, and approximately $15.2 million to
acquire leasehold properties. This acquisition extended the Company's properties
in the Austin Chalk trend, and the Company expects to utilize its operating
expertise in this area to successfully develop and exploit these properties. As
of December 31, 1998, these properties consisted of 162 producing wells (115 of
which were Company operated), 23 saltwater disposal wells, a 20% interest in two
natural gas plants, associated production facilities, and interests in 200,875
gross (125,378 net) undeveloped acres and approximately 114,000 undeveloped fee
mineral acres. At such date, the estimated proved reserves relating to these
acquired properties were 130.5 Bcfe, of which approximately 58% was natural gas
and 59% was proved undeveloped. The Company's production on these properties,
which began in the third quarter of 1998, amounted to approximately 11.6 Bcfe,
of which 44% was natural gas. Such production comprised approximately 30% of the
Company's production during 1998.
The Company pursues a balanced growth strategy that includes an active
drilling program, strategic acquisitions, and the utilization of advanced
technologies. The Company's operating philosophy is to increase its reserves
base through both drilling and acquisitions, shifting the balance between the
two activities in response to market conditions. Over the last several years,
the Company's growth has resulted primarily from its increased acreage position
and drilling activities in the AWP Olmos Field and the Austin Chalk trend.
Capital expenditures for development and exploration drilling, primarily in the
Company's core areas, were $71.8 million and $101.0 million in 1996 and 1997,
respectively, while capital expenditures for acquisitions were $1.5 million and
$8.4 million. The downward pressure on commodity prices during 1998 caused the
Company to decrease its originally targeted capital expenditures for drilling
and to redirect a portion of those expenditures to the acquisition of producing
properties, primarily the above mentioned Toledo Bend Properties. In 1998,
development and exploration drilling expenditures for the year, concentrated in
the first half of the year, totaled $67.4 million while $59.5 million was spent
for the acquisition of producing properties, almost all in the third quarter of
1998.
In response to market conditions, the Company has budgeted capital
expenditures of only $54.2 million for 1999, of which $36.0 million is targeted
for drilling, $31.3 million for development drilling, and $4.7 million for
exploratory drilling. The remaining $18.2 million is targeted principally for
leasehold, seismic, and geological costs of prospects. The Company plans to fund
this budget primarily through the use of its internally generated cash flows and
limited borrowings under its credit facility. Besides its core areas, the
Company is also actively
3
<PAGE>
pursuing exploratory and development drilling opportunities in other basins in
Texas, Arkansas, Louisiana, Wyoming, and New Zealand.
The Company has increased its proved reserves from 90.1 Bcfe at year-end
1993 to 436.1 Bcfe at year-end 1998, which has resulted in the replacement of
449% of production during the same five-year period. In 1998, the Company
increased its proved reserves by 21%, resulting in the replacement of 296% of
its 1998 production. The Company's five-year average reserves replacement costs
were $0.88 per Mcfe. As a result of both acquisition and drilling activity, 1998
production increased 54% over 1997 production. Due to economies of scale,
geographic concentration, and increased production, general and administrative
expenses and production costs have fallen from $0.44 and $0.36 per Mcfe,
respectively, in 1993 to $0.10 and $0.34 per Mcfe in 1998. 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 50% per
year from year-end 1993 to year-end 1998.
Properties
The Company's proved reserves are geographically concentrated, with
approximately 93% of the Company's proved reserves at December 31, 1998,
attributable to its properties in the AWP Olmos Field and the Austin Chalk
trend.
AWP Olmos Field. The Company's largest unified operation 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.
Properties in the AWP Olmos Field represented approximately 51% of the
Company's proved reserves at December 31, 1998, and approximately 40% of the
Company's 1998 production. At December 31, 1998, the Company owned interests in
and was the operator of 447 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 numerous 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.
In 1998, the Company drilled 33 (31 successful) development wells in the
AWP Olmos Field and three unsuccessful exploratory wells northwest of the field.
Of the properties operated by the Company in the AWP Olmos Field, the Company or
entities managed by the Company own 100% of the working interests in all but 21
wells in this field, and in these 21 wells the smallest ownership interest is
99%. The Company increased its leasehold position in the field in 1998 by
obtaining additional acreage and, if warranted, anticipates acquiring more
acreage in the future. The Company's planned 1999 capital expenditures of $12.0
million in this area will focus on fracture extensions and further use of coiled
tubing velocity strings.
Austin Chalk Trend. At December 31, 1998, the Company owned drilling and
production rights in 596,607 gross acres, 357,588 net acres, and 137,213 fee
mineral acres in the Austin Chalk trend containing substantial proved
undeveloped reserves. Of this acreage position, 402,560 gross acres, 244,662 net
acres, and all 137,213 fee mineral acres were acquired in the Toledo Bend
Properties acquisition described above. The Austin Chalk trend represented
approximately 42% of the Company's proved reserves at December 31, 1998 and 48%
of the Company's production in 1998. The wells in this trend are horizontal
wells, primarily producing natural gas in the Texas portion of the trend and
producing an approximately even split of oil and natural gas in the Louisiana
portion. These wells deliver high initial flow rates and strong initial cash
flows that decline rapidly. The Company believes the Austin Chalk reserves
complement the Company's long-lived reserves in the AWP Olmos Field. Since 1992,
the Company has participated in 78 horizontal wells in the Austin Chalk trend
with an 87% success rate, including 16 successful development wells out of 19
drilled and two successful exploratory wells out of four drilled in 1998. The
Company believes its success in the Austin Chalk trend is attributable to its
ability to identify hydrocarbon-bearing fractures, relying on its expertise in
geological and geophysical analyses, and to its ability to drill and operate
horizontal wells. The Company anticipates drilling 14 development wells and one
exploratory well in the Austin Chalk trend during 1999. The acquisition of
seismic data in the Cougar Run and Nimitz areas in Fayette County during 1998
has helped in upgrading locations to drill 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.
4
<PAGE>
Substantial portions of the Company's 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. The first joint venture, with Chesapeake Energy Corporation in 1993 and
now completed, covered approximately 8,800 acres in Fayette County, Texas, with
the Company currently holding an average working interest of 25%. In September
1995, the Company entered into a joint development agreement with Union Pacific
Resources providing for an area of mutual interest (AMI) covering 19,500 gross
acres in Fayette County (the North Fayetteville Prospect), with the Company and
UPR alternately serving as operator of any wells drilled on the acreage. During
1996, the Company purchased UPR's interest in 9,500 of these gross acres, and
the joint development arrangement was reduced to a 10,000 gross acre block in
which the Company has an average working interest of 30% to 35%. This joint
venture is now completed. The Company has a 100% working interest in the 9,500
acres it purchased and has drilled three wells on the property.
In 1996, the Company and UPR initiated another joint development
arrangement covering approximately 8,000 acres in Washington County, Texas, in
which the Company owns a 25% working interest. This joint development area was
subsequently expanded to encompass approximately 17,000 gross acres in
Washington County. Simultaneously, the Company and UPR entered into two
additional joint development agreements, one covering an approximate 6,300 gross
acre area in Washington County, in which the Company owns a 50% working
interest, and another covering an approximate 8,100 gross acre area in
Washington County and Austin County, in which the Company owns a 75% working
interest and serves as operator.
In 1997, in a joint venture with Belco Oil and Gas Corporation, the Company
acquired a 50% working interest in 20,000 net acres adjoining the North
Fayetteville Prospect area, for which Swift serves as operator. Several wells
were drilled on this acreage in 1998. Also in 1997, in an adjoining area
covering 8,000 gross acres in Fayette County, the Company entered a joint
venture with Chesapeake Energy Corporation with a 68% working interest for which
the Company serves as the operator. Two wells were drilled on this acreage in
1997, and three wells were drilled in 1998.
In 1998, the Company signed a joint development agreement with Chevron USA
Production Company encompassing 144,000 gross acres in central Texas, where the
Company and Chevron are participating in the drilling of a number of wells
targeted for the Edwards Limestone, Sligo, Austin Chalk, and other formations in
the counties of Fayette, Colorado, and Austin. Swift's interests originally
covered 68,000 net acres but were subsequently expanded to 70,000 net acres. The
Company and Chevron each own an undivided 50% working interest within the AMI,
with the Company serving as operator. To date, the Company has drilled two
exploratory wells targeting the Austin Chalk trend in this AMI, one of which was
successful, and is continuing to acquire acreage in selective areas within the
AMI.
Exploration and Development Drilling Activities
In 1991, the Company began an intensive effort to develop an inventory of
exploration and development drilling prospects, identifying drilling locations
through integrated geological and geophysical studies of the Company's
undeveloped acreage and other prospects. As a result, the Company added 118 Bcfe
of proved reserves through drilling in 1996 and 120 Bcfe in 1997. In 1998, the
Company deferred drilling projects scheduled for the second half of the year in
response to market conditions and, accordingly, reserves added by drilling
decreased to 73.9 Bcfe. The 1998 additions were a result of the Company's
success rate of 87% for development wells (53 out of 61 drilled) and 36% for
exploratory wells (5 out of 14 drilled).
The Company's successful drilling program has led to the acquisition of
additional acreage during 1997 and 1998 in the areas of its principal operations
in the AWP Olmos Field in South Texas and in the Austin Chalk trend, the latter
covering several Texas counties and, as of 1998, two Louisiana parishes.
The Company pursues a "controlled risk" approach to exploratory drilling,
focusing its exploration activities on specific U.S. regions in which 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 Company-managed
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, and economic parameters.
5
<PAGE>
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
utilizes various recovery techniques, which include employing water flooding and
acid treatments, fracturing reservoir rock through the injection of
high-pressure fluid, and inserting coiled tubing velocity strings to speed gas
flow. 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 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 production 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 analyses and amplitude versus offset (AVO)
studies. During 1997, the Company completed its first international seismic
acquisition program in two key areas of its holdings 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 AWP Olmos Field in South Texas and 51 miles of data
in the Fayette County portion of the Austin Chalk trend. Two more prospects in
the North Louisiana Salt Basin were shot in the form of 2-D swaths of
approximately 16 miles each. During 1998, the Company performed two additional
2-D acquisitions in Fayette County, Texas. It also conducted a 2-D cross swath
that yielded 3-D data in Point Coupee Parish, Louisiana, which resulted in the
Company's release of acreage in the area.
In addition to development and exploration activities in the AWP Olmos
Field and the Austin Chalk trend, the Company is currently focusing its
exploration activities in three main domestic geographical areas: the Gulf Coast
Basin, the Wyoming Powder River Basin, and the North Louisiana Salt Basin. It
has also initiated an exploration program in New Zealand.
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 and including all target formations present except the
Austin Chalk trend and the Olmos sand. In 1998, three successful development
wells (out of six) and two successful exploratory wells (out of three) were
drilled in the Gulf Coast Basin, following four successful exploratory wells and
one successful development well drilled in 1997. In 1999, two exploratory wells
and one development well are scheduled for drilling in the Gulf Coast Basin.
During 1997, the Company acquired 1,920 gross acres in Jim Hogg County, in
which the Company owns a minimum 75% working interest. A successful exploratory
well drilled by the Company to the Queen City formation in 1997 was followed by
three successful development wells and a successful exploratory well in 1998.
Further work in the area is awaiting a fracture extension program to be carried
out in 1999 to assess the field's full potential.
Wyoming Powder River Basin. The Minnelusa trend has been the subject of
extensive study over several years by the Company's multidisciplinary teams in
order to identify the location of stratigraphic hydrocarbon traps. In recent
years, 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. In 1997,
the Company successfully drilled one out of two exploratory wells in the
Minnelusa trend in Campbell County, Wyoming. In 1998, the Company participated
in a successful exploratory well in Converse County, Wyoming. A second
exploratory well drilled in Daniels County, Montana, was unsuccessful.
North Louisiana Salt Basin. The North Louisiana Salt Basin covers the
neighboring corners of Arkansas, Louisiana, and Texas ("Ark-La-Tex region"). In
this area, the Jurassic Smackover formation, a prolific hydrocarbon producer
from multiple levels and from a variety of structures, including fault traps,
salt anticlines, basement structures, and stratigraphic traps, is the primary
target, and the Haynesville formation is the secondary target. Both formations
have been the subject of intense geophysical and geological analyses by the
Company for a number of years. During 1998, analyses were completed for two 2-D
seismic swaths, each covering 12 miles, that were acquired in 1997 in Lafayette
County, Arkansas, and Bossier Parish, Louisiana.
6
<PAGE>
Since 1996, Swift has had four successes out of five exploratory wells drilled
in the area (the unsuccessful well was drilled in 1998). The Company plans to
drill an additional exploratory well in the area in 1999.
New Zealand. After several years of preparation, including the acquisition
and analyses of seismic data, the Company will drill an exploratory well on its
permit to the Mangahewa formation in the Taranaki Basin on the North Island of
New Zealand in 1999. In 1998, the Company participated in an unsuccessful
exploratory well on a permit in which the Company obtained an interest through
Marabella Enterprises Ltd. See "Foreign Activities - New Zealand."
The following table sets forth the results of the Company's drilling
activities during the three years ended December 31, 1998:
<TABLE>
<CAPTION>
Gross Wells Net Wells
----------------------------- ----------------------------
Year Type of Well Total Producing Dry Total Producing Dry
- --------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
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
1998 Exploratory 14 5 9 8.7 2.7 6.0
Development 61 53 8 37.7 32.8 4.9
</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 836 wells at December 31, 1998, 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 own the drilling rigs
used to drill on properties it operates. Drilling rigs are contracted from
independent contractors and supervised by the Company. The Company employs
drilling, production, and reservoir 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 depth of the well, whether the
well produces oil or gas, and other factors. Such fees received by the Company
in 1998 ranged from $200 to $1,632 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 sold in the spot market at
prevailing prices. The Company sells its oil production at prevailing market
prices. The Company does not refine any oil it produces. During the year ended
December 31, 1998, two purchasers accounted for approximately 16% and 10% of the
Company's revenues. Three oil or gas purchasers accounted for 10% or more of the
Company's revenues during the year ended December 31, 1997, with those
purchasers accounting for approximately 42% of revenues in the aggregate.
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 Pacific Gas & Electric Corporation and its affiliates ("PG&E") for up to
75,000 Mcf per day. These contracts were recently amended, effective May 1,
1998, to provide for an initial ten-year term, with automatic one-year
extensions unless earlier terminated. In addition,
7
<PAGE>
the amended contracts provided for more favorable terms benefiting the Company.
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 PG&E, the gas
processed and transported under these agreements may be sold to PG&E at monthly
indexed prices based upon the current natural gas price.
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 Company's oil production from the Toledo Bend Properties is sold to
credit-worthy purchasers at prevailing market prices. The Company's gas
production from the Toledo Bend Properties is processed under long-term gas
processing contracts with Union Pacific Resources Company ("UPR"). Processed
liquids and residue gas production are sold in the spot market at prevailing
prices. Recently UPR signed a definitive agreement with Duke Energy Field
Services, Inc. ("Duke") for the acquisition by Duke of UPR's gas gathering
processing and marketing subsidiary, Union Pacific Fuels, Inc. ("UPFI"). Through
a merger, UPFI will become a wholly owned subsidiary of Duke. The transaction is
expected to close by the end of March 1999. This merger will not affect the
contractual obligations between the Company and UPR.
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, 1998. "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,
------------------------------------------------------------------
1998 1997 1996
------------------- ---------------------- -----------------
<S> <C> <C> <C>
Net Sales Volume:
Oil (Bbls) 1,800,676 672,385 623,386
Gas (Mcf)(1) 28,225,974 21,359,434 15,696,798
Gas equivalents (Mcfe) 39,030,030 25,393,744 19,437,114
Average Sales Price:
Oil (Per Bbl) $ 11.86 $ 17.59 $ 19.82
Gas (Per Mcf) $ 2.08 $ 2.68 $ 2.57
Average Production Cost (per Mcfe) $ 0.34 $ 0.35 $ 0.32
</TABLE>
(1) Natural gas production for 1998, 1997, and 1996 includes 866,232,
1,015,226, and 1,156,361 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, 1998, the Company has a remaining commitment to deliver
approximately 1.1 Bcf of gas meeting certain heating equivalent and quality
standards through October 2000, when such agreement expires. Since entering into
this agreement, these properties have produced in excess of the required monthly
delivery requirements.
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
engages periodically in certain limited hedging activities, but only to the
extent of buying protection price floors for portions of its and the
Company-managed 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 have not been
significant for any year presented. The costs to purchase put options are
amortized over the option period.
During 1998, 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, 1,500,000 MMBtu of the natural gas
production was covered, and February was covered for 3,000,000 MMBtu of natural
gas, each
8
<PAGE>
at a minimum price of $2.00 per MMBtu. March was covered for 2,000,000 MMBtu of
natural gas at a minimum price of $1.80 per MMBtu and 500,000 MMBtu at $1.90 per
MMBtu. For the months of April, May, June, and July, 1,000,000 MMBtu were
covered, providing for a minimum price of $1.80, $1.90, $2.10, and $2.10 per
MMBtu, respectively.
For the months of January and February 1998, 60,000 Bbls of oil production
were covered each month, providing for a minimum price of $18.00 per Bbl. Costs
related to 1998 hedging activities totaled approximately $377,000, with benefits
of approximately $101,000 being received, resulting in a net cash outlay of
approximately $276,000 or $0.007 per Mcfe.
The Company had entered into four put option contracts for 1999 production
by December 31, 1998, three of which remained open at year-end. January was
covered for 2,000,000 MMBtu of natural gas at $2.00 per MMBtu, with a net profit
of approximately $154,000. The three open contracts at December 31, 1998,
covered 1,000,000 MMBtu and 1,800,000 MMBtu of natural gas production for
February at minimum prices of $1.80 and $1.70 per MMBtu, respectively, and
2,800,000 MMBtu of natural gas for March at a minimum price of $1.60 per MMBtu.
The costs related to these 1999 contracts totaled $317,016 and had a fair market
value of $486,680 as of December 31, 1998.
Acquisition Activities
Since 1979, the Company has acquired approximately $537.5 million of
producing oil and gas properties on behalf of itself and its co-investors in 133
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 and as industry
conditions brought a redirection of the Company's strategy towards increasing
reserves through drilling. 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 on its own behalf. The Company has acquired for its own account
approximately $181.0 million of producing properties, with original proved
reserves estimated at 279.9 Bcfe. The Company's producing property acquisition
expenditures in the past three years were approximately $1.5 million in 1996,
$8.4 million in 1997, and $59.5 million in 1998. The Company's acquisition costs
have averaged $0.52 per Mcfe over this three-year period.
The Company uses a disciplined, market-driven approach to acquisitions,
generally seeking to acquire properties in close proximity to its current
reserves with the potential to add reserves and production through additional
development and exploration efforts.
Foreign Activities
New Zealand. Since October 1995, the Company has been issued two Petroleum
Exploration Permits by the New Zealand Minister of Energy. The first permit
covered approximately 65,000 acres in the Onshore Taranaki Basin of New
Zealand's North Island, and the second covered approximately 69,300 adjacent
acres. A wholly-owned subsidiary, Swift Energy New Zealand Limited, formed in
late 1997, conducts its New Zealand activities and owns the interest in the
permits. In March 1998, the Company surrendered approximately 46,400 acres
covered in the first permit, and the remaining acreage has been included as an
extension of the area covered in the second permit. Under the terms of the
expanded permit, the Company is obligated to drill one exploratory well prior to
August 12, 1999. All other obligations under the permit have been fulfilled,
including the reinterpretation of existing seismic data and the acquisition and
processing of new seismic data.
On October 23, 1998, the Company entered into separate agreements with
Marabella Enterprises Ltd. (Marabella), a subsidiary of Bligh Oil & Minerals
N.L., an Australian company, to obtain from Marabella a 25% working interest in
another New Zealand Petroleum Exploration Permit and for Marabella to become a
5% participant in the Company's permit. An exploration well on the Marabella
permit commenced drilling on October 16, 1998, the results of which were
unsuccessful. Accordingly, the $400,000 cost of such well was charged against
earnings. The Company has also agreed in principle to participate with Marabella
in an additional permit as a 17.5% working interest owner.
At December 31, 1998, the Company's investment in New Zealand was
approximately $5.4 million and is included in the unproved properties portion of
oil and gas properties. Approximately $0.4 million of such costs have been
impaired.
Russia. On September 3, 1993, the Company signed a Participation Agreement
with Senega, a Russian Federation joint stock company (in which the Company has
an indirect interest of less than 1%), to assist in the
9
<PAGE>
development and production of reserves from two fields in Western Siberia,
providing the Company with a minimum 5% net profits interest from the sale of
hydrocarbon products from the fields for providing managerial, technical, and
financial support to Senega. Additionally, the Company purchased a 1% net
profits interest from Senega for $0.3 million.
On December 10, 1997, the Company amended and restated the Participation
Agreement. Under the amended and restated Participation Agreement, the Company
retains its 6% net profits interest in the Samburg Field and agreed to assist
Senega in obtaining investments necessary to develop the field. Senega is
charged with the management and control of the field development. The Company's
investment in Russia, prior to its impairment in the third quarter of 1998, was
approximately $10.8 million and was previously included in the unproved
properties portion of oil and gas properties. However, the economic and
political uncertainty and currency concerns that arose during the third quarter
of 1998 in Russia, combined with the price volatility and severe tightening of
international capital markets, caused the Company to re-evaluate the timing of
the recovery of its capitalized costs in that country. See Note 1 to the
Company's financial statements for a more detailed discussion of the impairment.
Subsequent to such impairment, any costs incurred in Russia have been reported
as a charge to earnings.
Venezuela. The Company formed a wholly-owned subsidiary, Swift Energy de
Venezuela, C. A., for the purpose of submitting a bid on August 5, 1993, under
the Venezuelan Marginal Oil Field Reactivation Program. Although the Company did
not win the bid, it has continued to gather information relating to reserves and
geological and geophysical data in Venezuela and continued to pursue cooperative
ventures involving other fields and opportunities in Venezuela. The Company
evaluated a number of blocks being offered by Petroleos de Venezuela, S. A.,
under the Third Operating Agreement Round in 1997 but decided against submitting
any bid on these blocks. The Company has entered into an agreement with
Tecnoconsult, S. A., and Corporation EDC, S.A.C.A., Venezuelan companies, to
jointly formulate and submit a proposal to Petroleos de Venezuela, S. A., for
the construction and operation of a methane pipeline. Currently, the technical
and economic feasibility of the project is under study. The Company's investment
in Venezuela, prior to its impairment in the third quarter of 1998, was
approximately $2.8 million and was previously included in the unproved
properties portion of oil and gas properties. However, the economic uncertainty
and currency concerns in Venezuela, combined with the price volatility and
severe tightening of international capital markets, caused the Company to
re-evaluate its prospects of participating in further Venezuelan exploration
activities in the near-term and the recovery of its capitalized costs in that
country. See Note 1 to the Company's financial statements for a more detailed
discussion of the impairment. Subsequent to such impairment, any costs incurred
in Venezuela have been reported as a charge to earnings.
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, 1998, 1997, and 1996. 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, 1998, were estimated based upon
weighted average prices of $2.23 per Mcf of natural gas and $11.23 per barrel of
oil, compared to $2.78 and $15.76 in 1997 and $4.47 and $23.75 in 1996,
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.
10
<PAGE>
The table sets forth estimates of future net revenues presented on the
basis of unescalated prices and costs in accordance with criteria prescribed by
the 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 Company's financial statements,
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 1998, 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 1999 and
thereafter will be made at an unrestricted level.
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------
1998 1997 1996
---------------- ---------------- -----------------
<S> <C> <C> <C>
Estimated Proved Oil and Gas Reserves
Net natural gas reserves (Mcf):
Proved developed 197,105,963 191,108,214 135,424,880
Proved undeveloped 155,294,872 123,197,455 90,333,321
---------------- ---------------- -----------------
Total 352,400,835 314,305,669 225,758,201
================ ================ =================
Net oil reserves (Bbl):
Proved developed 7,142,566 4,288,696 3,622,480
Proved undeveloped 6,815,359 3,570,222 1,861,829
---------------- ---------------- -----------------
Total 13,957,925 7,858,918 5,484,309
================ ================ =================
Estimated Present Value of Proved Reserves
Estimated present value of future net cash flows from
proved reserves discounted at 10% per annum:
Proved developed $ 243,124,194 $ 244,365,044 $ 310,408,949
Proved undeveloped 97,660,811 105,979,738 160,776,008
---------------- ---------------- -----------------
Total $ 340,785,005 $ 350,344,782 $ 471,184,957
================ ================ =================
</TABLE>
The Company's total proved developed and undeveloped reserves increased 21%
at December 31, 1998, over amounts at December 31, 1997, as shown above and in
Supplemental Information to the Company's financial statements. At year-end
1998, 45% of the reserves were proved undeveloped reserves. This reflects the
increased emphasis on development and exploration activities. In 1997, 40% of
proved reserves were undeveloped and 60% were proved developed.
Changes in quantity estimates and the estimated present value of proved
reserves are affected by the change in crude oil and natural gas prices at the
end of each year. While the Company's total proved reserves quantities (on an
equivalent Bcfe basis) at year-end 1998 increased by 21% over reserves
quantities a year earlier, the PV-10 Value of those reserves decreased 3% from
the PV-10 Value at year-end 1997. This decrease was due almost entirely to
pricing declines at year-end 1998 as compared to year-end 1997, which more than
offset the 21% Bcfe increase in reserves quantities. Product prices for natural
gas declined 20% during 1998 from $2.78 per Mcf at December 31, 1997, to $2.23
per Mcf at year-end 1998, matched by a 29% decrease in the price of oil between
the two dates, from $15.76 to $11.23 per barrel.
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.
11
<PAGE>
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. At December 31,
1998, 17 of the limited partnerships managed by the Company had achieved payout
status.
No other reports on the Company's reserves have been filed with any federal
agency.
Oil and Gas Wells
The following table sets forth the gross and net wells in which the Company
owned an interest at the following dates:
<TABLE>
<CAPTION>
Total
Oil Wells Gas Wells Wells(1)
---------- ----------- -----------
<S> <C> <C> <C>
December 31, 1998
Gross 657 1,060 1,717
Net 89.4 494.5 583.9
December 31, 1997
Gross 625 926 1,551
Net 48.1 381.7 429.8
December 31, 1996
Gross 734 1,068 1,802
Net 59.5 222.9 282.4
</TABLE>
(1) Excludes 36 service wells in 1998, 16 service wells in 1997, and 26 service
wells in 1996.
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, 1998:
<TABLE>
<CAPTION>
Developed (1) Undeveloped (1)
-------------------------- ---------------------------
Gross Net Gross Net
----------- ---------- ---------- -----------
<S> <C> <C> <C> <C>
Alabama 4,495.38 616.70 292.00 72.90
Arkansas 3,339.49 1,736.30 8,092.80 5,022.95
Kansas -- -- 4,600.00 1,988.80
Louisiana 100,233.66 50,356.48 159,555.53 101,109.80
Mississippi 4,186.10 2,240.85 3,693.84 910.69
Montana -- -- 4,411.28 4,411.28
Oklahoma 33,240.59 14,197.02 3,209.04 886.50
Texas 260,232.49 146,577.24 301,336.20 161,354.21
Wyoming 4,713.90 1,969.49 120,253.29 104,579.29
All other states -- -- 6,317.48 1,286.06
---------- ----------- ---------- -----------
Total 410,441.61 217,694.08 611,761.46 381,622.48
========== =========== ========== ===========
</TABLE>
(1) Fee minerals acquired in the Toledo Bend Properties acquisition are not
included in the above leasehold acreage table. The Company acquired 23,178.56
developed fee mineral acres and 114,034.44 undeveloped fee mineral acres for a
total of 137,213 fee mineral acres.
12
<PAGE>
Partnerships
For many years, the Company relied on limited partnerships as its principal
vehicle to fund its activities. The Company has formed 109 limited partnerships
which had raised a total of approximately $509.5 million at December 31, 1998.
However, as the Company has increasingly shifted its emphasis to development and
exploration 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. 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
occurred in June 1998.
From 1984 to 1995, 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, 1998, thirteen
private drilling partnerships had been formed (one formed in each of 1993 and
1994, three in each of 1995, 1996, and 1997, and two in 1998) with aggregate
investor contributions of approximately $66.1 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.
In October 1998, the Company notified investors in 63 Swift-managed
production partnerships formed between 1986 and 1994 that it had delayed calling
investor meetings to consider its purchase of all of the oil and gas properties
owned by these partnerships, which was proposed in March 1998. This decision
principally reflected significant market changes that had occurred during the
long period necessary for regulatory review of soliciting materials, the age of
the third-party appraisals of these partnership properties, and the much
publicized weakness in both the equity and debt markets for energy companies.
During the last six months, the weakness in oil and natural gas prices has
deepened, creating concern over the appropriateness of selling properties at
this time. The Company expects to continue to re-evaluate the status and
operation of these partnerships, whether to propose some form of liquidating
transaction, and if so when and in what form.
Risk Management
The Company's operations are subject to all of the risks normally incident
to the exploration for and the production of oil and gas, including blowouts,
cratering, pipe failure, casing collapse, oil spills, and fires, each of which
could result in severe damage to or destruction of oil and gas wells, production
facilities or other property, or individual injuries. The oil and gas
exploration business is also subject to environmental hazards, such as oil
spills, gas leaks, and ruptures and discharges of toxic substances or gases that
could expose the Company to substantial liability due to pollution and other
environmental damage. Additionally, as managing general partner of limited
partnerships, the Company is solely responsible for the day-to-day conduct of
the limited partnerships' affairs and accordingly has liability for expenses and
liabilities of the limited partnerships. The Company maintains comprehensive
insurance coverage, including general liability insurance in an amount not less
than $35.0 million, as well as general partner liability insurance. The Company
believes that its
13
<PAGE>
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.
Continued decreases in natural gas and oil prices have had an effect on the
Company's cash flow, capital expenditures, and drilling schedule. 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 certain sales of natural gas in interstate commerce
are heavily regulated by agencies of the federal government. The following
discussion is intended only as a brief summary of agency rules and regulations
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.
In April 1992, the Federal Energy Regulatory Commission ("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.
In addition, interstate pipelines that transport gas for others must
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.
Gas produced normally will be sold to intermediaries who have entered into
transportation arrangements with pipeline companies. These intermediaries
typically 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.
14
<PAGE>
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, 1998, the Company employed 203 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 $95,000 per month. The
Company has field offices in various locations from which Company employees
supervise local oil and gas operations.
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.
15
<PAGE>
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 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.
16
<PAGE>
Item 3. Legal Proceedings
From time to time, litigation arises in the ordinary course of Swift's oil
and gas drilling and production activities. In early 1997, Swift and the Lower
Colorado River Authority, the "LCRA," filed claims against each other in the
155th Judicial District Court of Fayette County, Texas, over the interpretation
of an oil and gas farmout agreement from LCRA to Swift covering land in Fayette
County, Texas. Swift originally sued to force LCRA to assign to Swift leases
which LCRA had refused to assign, covering wells successfully drilled by Swift
on the farmout acreage, and seeking declaration as to the parties' interests in
the properties involved. LCRA counterclaimed for damages and claimed fraud and
conversion, plus conspiracy to convert oil and gas among Swift, certain of its
officers and managed partnerships. LCRA has not quantified its damages, but in
December 1998 alleged that they do not exceed $10 million, exclusive of punitive
damages. Swift does not believe LCRA's counterclaims are valid nor that the
claimed damage amount is a credible number, and Swift intends to vigorously
pursue its claims under the farmout. A July 6, 1999, trial date has been
tentatively set for this case. Although certain proceeds from production of the
field involved have been escrowed in the court pending resolution of this case,
based on discovery to date, the Company does not believe that this case will
have a materially adverse impact upon its financial condition or results of
operations.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted during the fourth quarter of 1998 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 1998
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 1998 are as follows:
<TABLE>
<CAPTION>
1997 1998
------------------------------------- -----------------------------------
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 $15.88 $15.00 $8.81 $6.94
High $34.20 $26.02 $26.48 $31.00 $21.00 $20.75 $16.75 $11.19
</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 the first three
quarters of 1997 have been revised to reflect a 10% stock dividend declared in
October 1997.
Swift Energy had approximately 565 stockholders of record as of December 31,
1998.
17
<PAGE>
Item 6. Selected Financial Data
<TABLE>
<CAPTION>
1998 1997 1996 1995
<S> <C> <C> <C> <C>
Revenues
Oil and Gas Sales $80,067,837 $69,015,189 $52,770,672 $22,527,892
Fees and Earned Interests(2) $333,940 $745,856 $937,238 $590,441
Interest Income $107,374 $2,395,406 $433,352 $212,329
Other, Net $1,960,070 $2,555,729 $2,156,764 $1,761,568
Total Revenues $82,469,221 $74,712,180 $56,298,026 $25,092,230
Operating Income (Loss) ($73,391,581) $33,129,606 $28,785,783 $6,894,537
Net Income (Loss) ($48,225,204) $22,310,189 $19,025,450 $4,912,512
Net Cash Provided by Operating Activities $54,249,017 $55,255,965 $37,102,578 $14,376,463
Per Share Data
Weighted Average Shares Outstanding(3) 16,436,972 16,492,856 15,000,901 10,035,143
Earnings (Loss) per Share--Basic(3) ($2.93) $1.35 $1.27 $0.49
Earnings (Loss) per Share--Diluted(3) ($2.93) $1.26 $1.25 $0.49
Shares Outstanding at Year-End 16,291,242 16,459,156 15,176,417 12,509,700
Book Value per Share $6.71 $9.69 $9.41 $7.46
Market Price(3)
High $21.00 $34.20 $28.86 $11.48
Low $6.94 $16.93 $9.89 $7.05
Year-End Close $7.38 $21.06 $27.16 $10.91
Pro forma amounts assuming 1994 change in
accounting principle is applied retroactively(2)
Net Income (Loss) ($48,225,204) $22,310,189 $19,025,450 $4,912,512
Earnings (Loss) per Share--Basic (3) ($2.93) $1.35 $1.27 $0.49
Earnings (Loss) per Share--Diluted (3) ($2.93) $1.26 $1.25 $0.49
Assets
Current Assets $35,246,431 $29,981,786 $101,619,478 $43,380,454
Oil and Gas Properties, Net of Accumulated
Depreciation, Depletion, and Amortization $356,457,106 $301,312,847 $200,010,375 $125,217,872
Total Assets $403,645,267 $339,115,390 $310,375,264 $175,252,707
Liabilities
Current Liabilities $31,415,054 $28,517,664 $32,915,616 $40,133,269
Convertible Notes and Bank Borrowings $261,200,000 $122,915,000 $115,000,000 $28,750,000
Total Liabilities $294,282,628 $179,714,470 $167,613,654 $81,906,742
Stockholders' Equity $109,362,639 $159,400,920 $142,761,610 $93,345,965
Number of Employees 203 194 191 176
Producing Wells
Swift Operated 836 650 842 767
Outside Operated 917 917 986 3,316
Total Producing Wells 1,753 1,567 1,828 4,083
Wells Drilled (Gross) 75 182 153 76
Proved Reserves
Natural Gas (Mcf) 352,400,835 314,305,669 225,758,201 143,567,520
Oil & Condensate (barrels) 13,957,925 7,858,918 5,484,309 5,421,981
Total Proved Reserves (Mcf equivalent) 436,148,385 361,459,177 258,664,055 176,099,406
Production (Mcf equivalent)(4) 39,030,030 25,393,744 19,437,114 11,186,573
Average Sales Price
Natural Gas (per Mcf) $2.08 $2.68 $2.57 $1.77
Oil (per barrel) $11.86 $17.59 $19.82 $15.66
</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, in 1994 to 1998, "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, 1997, and 1998
includes 1,148,862, 1,581,206, 1,358,375, 1,211,255, 1,156,361, 1,015,226, and
866,232 Mcf, respectively, delivered under the Company's volumetric production
payment agreement (see Note 1 to the Company's financial statements).
18
<PAGE>
<TABLE>
<CAPTION>
1994 (1) 1993 1992 1991 1990 1989 1988
<S> <C> <C> <C> <C> <C> <C>
$19,802,188 $15,535,671 $12,420,222 $8,361,771 $7,328,190 $3,984,835 $2,838,433
$701,528 $4,071,970 $2,716,277 $2,231,729 $9,882,953 $8,802,816 $8,073,530
$47,980 $201,584 $113,387 $192,694 $705,786 $260,286 $165,909
$1,072,535 $604,599 $515,931 $541,502 $323,981 $232,261 $488,131
$21,624,231 $20,413,824 $15,765,817 $11,327,696 $18,240,910 $13,280,198 $11,566,003
$4,837,829 $6,628,608 $4,687,519 $3,748,741 $10,811,044 $8,716,673 $7,040,165
($13,047,027) $4,896,253 $4,084,760 $2,512,815 $7,170,642 $5,709,098 $4,678,317
$10,394,514 $7,238,340 $6,349,080 $5,911,588 $4,813,435 $2,751,381 $393,564
7,308,673 7,246,884 6,748,548 5,899,629 5,806,436 5,129,654 4,897,379
($1.79) $0.68 $0.61 $0.43 $1.23 $1.11 $0.96
($1.79) $0.64 $0.61 $0.43 $1.23 $1.11 $0.96
6,685,137 6,001,075 5,968,579 4,955,134 4,848,315 4,764,862 4,068,968
$6.30 $9.08 $8.26 $7.80 $7.36 $5.84 $3.88
$10.35 $11.57 $7.85 $9.09 $10.65 $11.15 $8.68
$7.75 $7.14 $4.65 $4.34 $6.93 $5.78 $5.58
$8.86 $7.85 $7.55 $4.95 $8.57 $9.50 $5.68
$3,725,671 $4,322,478 $3,729,851 $2,950,245 $3,107,451 $2,185,276 $898,962
$0.51 $0.60 $0.55 $0.50 $0.54 $0.43 $0.18
$0.51 $0.57 $0.55 $0.50 $0.54 $0.43 $0.18
$39,208,418 $65,307,120 $30,830,173 $47,859,278 $72,537,521 $54,818,404 $9,304,370
$88,415,612 $89,656,577 $64,301,509 $47,655,917 $41,952,212 $27,935,170 $19,973,454
$135,672,743 $160,892,917 $100,243,469 $101,421,573 $118,227,480 $85,007,293 $31,463,220
$52,345,859 $55,565,437 $27,876,687 $50,851,447 $71,514,938 $49,354,128 $9,756,431
$28,750,000 $28,750,000 $0 $0 $0 $0 $0
$93,545,612 $106,427,203 $50,962,183 $62,761,217 $82,559,406 $57,198,476 $15,694,272
$42,127,131 $54,465,714 $49,281,286 $38,660,356 $35,668,074 $27,808,817 $15,768,948
209 188 178 171 164 131 116
750 795 688 674 691 579 491
3,422 3,407 1,978 2,331 2,228 1,537 857
4,172 4,202 2,666 3,005 2,919 2,116 1,348
44 34 40 27 23 21 12
76,263,964 64,462,805 41,638,100 36,685,881 30,731,741 14,945,348 11,293,268
4,553,237 4,271,069 2,901,621 1,950,209 1,690,520 1,422,815 840,144
103,583,566 90,089,219 59,047,824 48,387,138 40,874,862 23,482,236 16,334,130
9,600,867 7,368,757 5,678,772 3,980,460 3,303,750 1,900,302 1,440,690
$1.93 $1.96 $1.90 $1.58 $1.72 $1.73 $1.67
$14.35 $15.10 $17.19 $18.26 $22.70 $17.93 $14.38
</TABLE>
19
<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
The Company's principal corporate objectives are the accumulation of crude
oil and natural gas reserves for production and sale and the enhancement of the
net present value of those reserves. Commencing in 1991, the Company began to
emphasize the addition of reserves through increased development and exploration
drilling activity. This emphasis on development and exploration drilling has led
to additions of reserves in excess of the Company's production in each of the
years 1996, 1997, and 1998. 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. At year-end 1998, the Company's total proved
reserves were 436.1 Bcfe with a PV-10 Value of $340.8 million. In 1998, the
Company's proved natural gas reserves increased 38.1 Bcf (12%) and its proved
oil reserves increased 6,099,007 barrels (78%) for a total of 74.7 Bcfe (21%).
From 1996 to 1997, the Company's proved natural gas reserves increased 88.5 Bcf
(39%) and its proved oil reserves increased 2,374,609 barrels (43%) for a total
of 102.8 Bcfe (40%). The Company's additions to proved reserves from its
development and exploration program were 73.9 Bcfe in 1998, 120.2 Bcfe in 1997,
and 118.2 Bcfe in 1996. The Company's additions to proved reserves from
acquisitions were 97.6 Bcfe in 1998, 33.8 Bcfe in 1997, and 3.3 Bcfe in 1996. A
substantial portion of these reserves are proved undeveloped reserves comprising
45% of total proved reserves at year-end 1998, 40% of total proved reserves at
year-end 1997, and 39% of total proved reserves at year-end 1996.
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 Business and Properties - Oil
and Gas Reserves) from year-end 1997 to year-end 1998 is 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 Austin Chalk trend with the Toledo Bend Properties
acquisition), offset by revisions of previous estimates and by the 20% decrease
in year-end 1998 natural gas prices ($2.23 per Mcf at year-end 1998 versus $2.78
per Mcf at year-end 1997), and to the 29% decrease in year-end 1998 oil prices
($11.23 per Bbl at year-end 1998, compared to $15.76 per Bbl the prior year).
While the Company's total proved reserves quantities at year-end 1998 increased
by 21% over those at year-end 1997, the PV-10 Value of those reserves decreased
3% over the same period almost entirely due to pricing declines during 1998.
Under SEC guidelines, the Company's estimates of proved reserves are made
using oil and gas sales prices in effect at year-end and are held constant
throughout the life of the properties. The $2.23 per Mcf and the $11.23 per
barrel prices used to calculate the PV-10 Value were year-end 1998 prices, which
may not be indicative of future sales prices ultimately received.
Liquidity and Capital Resources
Net Cash Provided by Operating Activities. In 1998, 1997, and 1996, the
Company's operating activities provided net cash of $54.2 million, $55.3
million, and $37.1 million, respectively. The slight decrease of $1.1 million in
1998 was primarily due to the 54% increase in production volumes being more than
offset by (a) the 25% decrease in average commodity prices received, (b) the
associated 50% increase in oil and gas production costs, and (c) a decrease in
interest income and an increase in interest expense as a result of all the net
proceeds of the $115.0 million Convertible Notes offering having been expended
during 1997 and increased bank borrowings occurring during 1998. The 1997
increase of $18.2 million was primarily due to an increase of $16.5 million in
cash flows from oil and gas sales and interest income.
20
<PAGE>
Existing Credit Facilities. At December 31, 1998, the Company had
outstanding borrowings of $146.2 million under its new credit facility
syndicated in August 1998. At December 31, 1997, the Company had $7.9 million
outstanding under its borrowing arrangements. Currently, the new credit facility
consists of a $250.0 million revolving line of credit with a $170.0 million
borrowing base. The borrowing base is redetermined at least every six months.
The Company's $250.0 million revolving credit facility includes, among other
restrictions, requirements as to maintenance of certain minimum financial ratios
(principally pertaining to working capital, debt, and equity ratios) and
limitations on incurring other debt. The Company is currently in compliance with
the provisions of this agreement, as amended in mid-March 1999 to modify the
cash flow-to-debt covenant. The New Credit Facility will extend until August
2002.
Working Capital. The Company's working capital has increased from $1.5
million at December 31, 1997, to $3.8 million at December 31, 1998. This
increase is primarily the result of an increase in oil and gas sales receivables
resulting from the Company's increase in production volumes.
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 836 wells and its drilling
and acquisition activities. 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.
Capital Expenditures. The Company's capital expenditures were approximately
$183.8 million, $132.0 million, and $91.5 million for 1998, 1997, and 1996,
respectively. The 1998 capital expenditures included (a) $59.5 million (32% of
1998 capital expenditures) spent on producing properties acquisitions (almost
all of which was for the Toledo Bend Properties acquisition), (b) $54.8 million
(30%) on developmental drilling (primarily in the AWP Olmos Field and Austin
Chalk trend), (c) $12.6 million (7%) on exploratory drilling, (d) $34.7 million
(19%) on domestic prospect costs (principally leasehold, seismic, and geological
costs of unproven prospects for the Company's account, including $15.2 million
for leaseholds in the Toledo Bend Properties acquisition), (e) $15.0 million
(8%) for the purchase of gas processing plants in the Toledo Bend Properties
acquisition, (f) $3.9 million (2%) invested in foreign business opportunities in
New Zealand ($2.9 million), Venezuela ($0.4 million), and Russia ($0.6 million),
as described in Note 8 to the Company's financial statements, (g) $2.2 million
(1%) on field compression facilities, and (h) $1.0 million (1%) on fixed assets.
In 1998, the Company participated in drilling 75 wells (61 development
wells and 14 exploratory with 53 development successes and 5 exploratory
successes). The steady growth in the Company's unproved property account ($56.0
million), which is not being amortized, is indicative of the shift to a focus on
drilling activity in recent years as the Company has acquired prospect acreage
in or near its core areas (such as the acquisition of substantial leasehold
positions in the Toledo Bend Properties acquisition) and in the pursuit of its
New Zealand activities.
Sources and Uses of Funds. During 1997, the Company relied upon net
proceeds from the sale of its $115.0 million of Convertible Notes and its
internally generated cash flows, along with $7.9 million of bank borrowings to
fund capital expenditures. During 1998, the Company relied upon $138.3 million
of bank borrowings, along with its internally generated cash flows of $54.2
million, to fund its capital expenditures of $183.8 million. Cash and working
capital for 1999 are expected to be provided primarily through internally
generated cash flows and limited bank borrowings.
Capital expenditures for 1999 are estimated to be substantially lower at
approximately $54.2 million. Approximately $36.0 million of the 1999 budget is
allocated to development and exploration drilling, primarily in its two core
areas. The Company anticipates drilling 20 wells (15 development and five
exploratory) in 1999. The remaining $18.2 million is targeted principally for
leasehold, seismic, and geological costs of unproved properties.
The Company believes that 1999's anticipated internally generated cash
flows, together with limited borrowings under the new credit facility, will be
sufficient to finance the costs associated with its currently budgeted 1999
capital expenditures.
21
<PAGE>
Results of Operations
Revenues. The Company's revenues in 1998 increased by 10% over revenues in
1997 and by 32% in 1997 over 1996 revenues, principally due to increases in oil
and gas sales revenues.
The Company's net sales volumes in 1998 (including the volumetric
production payment associated with each year's production) increased by 54%
(13.6 Bcfe) over net sales volumes in 1997, while 1997 net sales volumes
increased by 31% (6.0 Bcfe) over net sales volumes in 1996. Oil and gas sales
revenues in 1998 increased by 16% ($11.1 million) over those revenues for 1997,
while in 1997 those revenues increased by 31% ($16.2 million) over oil and gas
sales revenues in 1996. Average prices for oil have declined from $19.82 per Bbl
in 1996 to $17.59 per Bbl in 1997 to $11.86 per Bbl in 1998, while average gas
prices increased slightly from $2.57 per Mcf in 1996 to $2.68 per Mcf in 1997
and then decreased to $2.08 per Mcf in 1998.
In 1998, the elements of the Company's $11.1 million increase in oil and
gas sales included (a) volume increases that added $18.4 million of sales from
the 6.9 Bcf increase in gas sales volumes and $19.9 million of sales from the
1.1 million barrel increase in oil sales volumes and (b) price variances that
had a $27.2 million unfavorable impact on sales due to the 22% decrease in
average gas prices received ($16.9 million), and the 33% decrease in average oil
prices received ($10.3 million).
In 1997, the Company's $16.2 million increase in oil and gas sales included
(a) 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, and (b) price variances that 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.
In 1998, the increases in oil and gas sales were primarily the result of
production from the Toledo Bend Properties acquisition and secondarily from the
Company's scaled-down drilling program, most notably from the Austin Chalk
trend. The decisions to make this acquisition and to defer some drilling were
both in response to market conditions. In 1997, the increases in oil and gas
sales 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 1998 oil and gas
sales from the Toledo Bend Properties were $24.2 million (none in 1997) from
11.6 Bcfe of net sales volumes, while sales from the rest of the Austin Chalk
trend were $14.6 million ($12.9 million in 1997) from 7.0 Bcfe of net sales
volumes (4.9 Bcfe in 1997), for an increase of 2.1 Bcfe. Sales in 1998 from the
AWP Olmos Field were $33.5 million ($42.2 million in 1997) from 15.5 Bcfe of net
sales volumes in both 1998 and 1997.
Revenues from oil and gas sales comprised 97%, 92%, and 94%, respectively,
of total revenues for 1998, 1997, and 1996. The majority (73%, 83%, and 77%,
respectively) of these oil and gas revenues in these periods were derived from
the sale of the Company's gas production. The Toledo Bend Properties
acquisition, which has a higher percentage of its production from oil (56% of
1998 production), has somewhat altered the Company's predominate gas production
mix. Even though the Company has scaled back its 1999 capital expenditures
budget, the Company expects oil and gas sales volumes to increase in 1999 when
compared to 1998, primarily due to the full year of production from the Toledo
Bend Properties. However, to the extent the Company curtails its development and
exploration program as a result of the continued low price environment, oil and
gas sales volumes will likely decrease in years subsequent to 1999.
Costs and Expenses. General and administrative expenses in 1998 increased
$0.3 million (9%) from the level of such expenses in 1997, while 1997 general
and administrative expenses decreased $0.6 million (15%) over 1996 levels. The
small variances in these costs over the three-year period reflect the Company's
ability to continue increasing its activities and reserves base without
materially increasing such costs. The Company's general and administrative
expenses per Mcfe produced have decreased in each of the past three years from
$0.21 per Mcfe produced in 1996 to $0.14 per Mcfe produced in 1997 to $0.10 per
Mcfe produced in 1998. Supervision fees netted from general and administrative
expenses for 1998, 1997, and 1996 were $2.7 million, $2.6 million, and $2.2
million, respectively.
Depreciation, depletion, and amortization ("DD&A") has steadily increased
(62% in 1998 and 47% in 1997), 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 (54% in 1998 and 31% in 1997). The Company's DD&A rate
per Mcfe of production was $0.85 in 1996, $0.95 in 1997, and $1.01 in 1998,
reflecting variations in the per unit cost of reserves additions.
22
<PAGE>
Production costs in 1998 increased $4.4 million (50%) over such expenses in
1997, while those expenses in 1997 increased $2.6 million (43%) over 1996 costs.
The increases in each of the periods primarily relate to the increases in the
Company's oil and gas sales volumes. The Company's production costs per Mcfe
produced were $0.34 in 1998, $0.35 in 1997, and $0.32 in 1996. Supervision fees
netted from production costs for 1998, 1997, and 1996 were $2.7 million, $2.6
million, and $2.2 million, respectively.
Interest expense in both 1998 and 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, while interest expense on the
credit facilities, including commitment fees, in 1998 totaled $5.6 million ($0.1
million in 1997 and $1.1 million in 1996), for a 1998 total interest expense of
$13.1 million (of which $4.4 million was capitalized). The 1997 total interest
expense was $7.6 million (of which $2.6 million was capitalized), while the 1996
total interest expense was $2.8 million (of which $2.1 million was capitalized).
The Company capitalizes that portion of interest related to its exploration,
partnership, and foreign business development activities. The increase in
interest expense in 1998 was attributable to the increase in interest incurred
on the amounts outstanding on its existing credit facility. The increase in
interest expense in 1997 was 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.
A non-cash write-down of oil and gas properties occurred during the third
quarter of 1998, as discussed in Note 1 to the Company's financial statements.
Lower prices for both oil and natural gas at September 30, 1998, necessitated a
pre-tax domestic full-cost ceiling write-down of $77.2 million ($50.9 million
after tax). Concurrently, in the third quarter, the Company re-evaluated the
timing of the recovery of its capitalized unproved properties costs in Russia
due to economical and political uncertainty and impaired its total investment of
$10.8 million. In addition, the international economic uncertainty and currency
concerns in Venezuela, combined with the price volatility and severe tightening
of international credit markets, also caused the Company to impair its
capitalized unproved properties costs in Venezuela of $2.8 million. The
re-evaluation of the unproved properties costs in these two countries resulted
in a separate non-cash pre-tax charge to earnings of $13.6 million ($9.0 million
after tax). The combination of the non-cash full-cost ceiling write-down and the
non-cash foreign impairment charges resulted in a combined non-cash pre-tax
charge to earnings of $90.8 million ($59.9 million after tax).
The Company's full-cost ceiling cushion at December 31, 1998, was
approximately $25.0 million. If during 1999, oil and gas prices decrease
appreciably from year-end 1998 prices, then the Company might be required to
make another ceiling test write-down.
Net Income. Before the non-cash write-down of oil and gas properties in
1998, net income of $11.7 million and basic earnings per share of $0.71 were 48%
and 47% lower, respectively, than net income of $22.3 million and basic earnings
per share of $1.35 in the same period for 1997. This decrease primarily
reflected the effect of the 33% and 22% decreases in oil and gas prices,
respectively, while costs and expenses increased in proportion to the 54%
increase in production volumes discussed above.
Net income of $22.3 million and basic earnings per share of $1.35 for 1997
were 17% and 6% higher, respectively, than net income of $19.0 million and basic
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 basic
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.
23
<PAGE>
Year 2000. The Year 2000 issue results from computer programs and embedded
computer chips with date fields that cannot distinguish between the years 1900
and 2000. The Company is currently implementing the steps necessary to make the
Company's operations capable of addressing the Year 2000. These steps include
upgrading, testing, and certifying its computer systems and field operation
services and obtaining Year 2000 compliance certification from the Company's
critical business suppliers, customers, venders, and other service providers.
The Company formed a task force during 1998 to address the Year 2000 issue and
prepare the Company's business systems for the Year 2000. By mid-1999 the
Company expects the mission critical systems to be either replaced or updated
and testing to be virtually completed.
The Company's business systems are almost entirely comprised of
off-the-shelf software. Most of the necessary changes in computer instructional
code can be made by upgrading such software. The Company is currently in the
process of either upgrading the off-the-shelf software or receiving
certification as to Year 2000 compliance from vendors or third-party
consultants. A testing phase is being conducted as the software is updated or
certified and is expected to be completed by mid-1999.
The Company does not believe that costs incurred to address the Year 2000
issue with respect to its business systems will have a material effect on the
Company's results of operations or its liquidity and financial condition. The
estimated total cost to address Year 2000 issues is projected to be less than
$150,000, most of which will be spent during the testing phase.
The failure to correct a material Year 2000 problem could result in an
interruption or failure of certain normal business activities or operations.
Based on activities to date, the Company believes that it will be able to
resolve any Year 2000 problems concerning its financial and administrative
systems. It is undeterminable how all the aspects of the Year 2000 issue will
impact the Company; however, field operations and the myriad of peripheral
technical applications which perform the Company's core business functions of
oil and gas exploration are primarily non-information technology systems which
are not date specific and are predicted to perform correctly. The most
reasonably likely worst case scenario, therefore, would involve a prolonged
disruption of external power sources upon which core equipment relies, resulting
in a substantial decrease in the Company's oil and gas production activities.
Although the Company maintains limited on-site secondary power supplies such as
generators, it is not economically feasible to maintain a secondary power supply
to fully replace primary power; therefore, a prolonged interruption could
materially affect the Company's operations, liquidity or capital resources. In
addition, pipeline operators to whom the Company sells natural gas, as well as
other customers and suppliers, could be prone to Year 2000 problems that could
not be assessed or detected by the Company. The Company is contacting its major
purchasers, customers, suppliers, financial institutions and others with whom it
conducts business to determine whether they will be able to resolve in a timely
manner any Year 2000 problems directly affecting the Company and to inform them
of the Company's internal assessment of its Year 2000 review. There can be no
assurance that such third parties will not fail to appropriately address their
Year 2000 issues or will not themselves suffer a Year 2000 disruption that could
have a material adverse effect on the Company's business, financial condition,
or operating results. Based upon these responses and any problems that arise
during the testing phase, contingency plans or back-up systems would be
determined and addressed. The Company has utilized, and will continue to
utilize, both internal and external resources to complete tasks and perform
testing necessary to address the Year 2000 problem.
Forward Looking Statements
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, Year 2000 issues, 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
24
<PAGE>
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.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk. The Company's major market risk exposure is the commodity
pricing applicable to its oil and natural gas production. Realized commodity
prices received for such production are primarily driven by the prevailing
worldwide price for crude oil and spot prices applicable to natural gas. The
effects of such pricing volatility have been discussed above, and such
volatility is expected to continue.
To mitigate some of this risk, the Company engages periodically in certain
limited hedging activities but only to the extent of buying protection price
floors for portions of its and the Company managed 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 Company does not
hold or issue derivative instruments for trading purposes. The costs related to
1998 hedging activities totaled approximately $377,000, with benefits of
approximately $101,000 being received, resulting in a net cash outlay of
approximately $276,000 or $0.007 per Mcfe. The costs related to the open
contracts totaled approximately $252,000 and had a market value of $267,000 as
of December 31, 1998. The costs related to 1997 hedging activities totaled
approximately $1,052,000 ($800,000 in 1996) with benefits of approximately
$439,000 (none in 1996) being received, resulting in a net cash outlay of
approximately $613,000 or $0.014 ($0.041 in 1996) per Mcfe.
Interest Rate Risk. The Company considers its interest rate risk exposure
to be minimal as a result of a fixed interest rate on the $115,000,000
Convertible Notes. In regards to its New Credit Facility, the result of a 10%
fluctuation in short-term interest rates (approximately 63 basis points) would
impact 1999 cash flow by approximately $0.9 million.
Financial Instruments & Debt Maturities. The Company's financial
instruments consist of cash and cash equivalents, accounts receivable, accounts
payable, bank borrowings, and convertible notes. The carrying amounts of cash
and cash equivalents, accounts receivable, and accounts payable approximate fair
value due to the highly liquid nature of these short-term instruments. The fair
values of the bank borrowings approximate the carrying amounts as of December
31, 1998 and 1997 and were determined based upon interest rates currently
available to the Company for borrowings with similar terms. The fair values of
the convertible notes were $81.4 million and $113.6 million at December 31, 1998
and 1997, respectively, and were based on quoted market prices as of the
respective dates. Bank borrowings under the Company's new credit facility mature
on August 18, 2002. The Company's $115.0 million convertible notes mature on
November 15, 2006.
25
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
Item 8. Financial Statements and Supplementary Data
Report of Independent Public Accountants..........................................27
Consolidated Balance Sheets.......................................................28
Consolidated Statements of Income.................................................29
Consolidated Statements of Stockholders' Equity...................................30
Consolidated Statements of Cash Flows.............................................31
Notes to Consolidated Financial Statements........................................32
1. Summary of Significant Accounting Policies..................................32
2. Earnings Per Share..........................................................36
3. Provision for Income Taxes..................................................37
4. Long-Term Debt .............................................................38
5. Commitments and Contingencies...............................................38
6. Stockholders' Equity........................................................39
7. Related-Party Transactions..................................................41
8. Foreign Activities..........................................................42
9. Acquisition of Properties...................................................43
Supplemental Information (Unaudited)..............................................44
</TABLE>
26
<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, 1998 and 1997,
and the related consolidated statements of income, stockholders' equity, and
cash flows for each of the three years in the period ended December 31, 1998.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Swift Energy Company and
subsidiaries as of December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
February 10, 1999
27
<PAGE>
Consolidated Balance Sheets
Swift Energy Company and Subsidiaries
<TABLE>
<CAPTION>
December 31,
1998 1997
---------------- ---------------
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents $ 1,630,649 $ 2,047,332
Accounts receivable-
Oil and gas sales 12,764,568 11,143,033
Associated limited partnerships and joint ventures 10,058,239 8,498,702
Joint interest owners 9,767,940 7,357,660
Other current assets 1,025,035 935,059
---------------- ---------------
Total Current Assets 35,246,431 29,981,786
---------------- ---------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized 497,296,068 326,836,431
Unproved properties not being amortized 56,041,886 41,839,809
---------------- ---------------
553,337,954 368,676,240
Furniture, fixtures, and other equipment 7,098,305 6,242,927
---------------- ---------------
560,436,259 374,919,167
Less - Accumulated depreciation, depletion, and amortization (200,713,621) (70,700,240)
---------------- ---------------
359,722,638 304,218,927
---------------- ---------------
Other Assets:
Receivables from associated limited partnerships, net of current 3,170,067 433,444
portion
Limited partnership formation and marketing costs 917,189 297,219
Deferred income taxes 254,984 ---
Deferred charges 4,333,958 4,184,014
---------------- ---------------
8,676,198 4,914,677
---------------- ---------------
$ 403,645,267 $ 339,115,390
================ ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 18,639,649 $ 16,518,240
Payable to associated limited partnerships 380,692 3,245,445
Undistributed oil and gas revenues 12,394,713 8,753,979
---------------- ---------------
Total Current Liabilities 31,415,054 28,517,664
---------------- ---------------
Convertible Notes 115,000,000 115,000,000
Bank Borrowings 146,200,000 7,915,000
Deferred Revenues 1,667,574 2,927,656
Deferred Income Taxes --- 25,354,150
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none --- ---
outstanding
Common stock, $.01 par value, 35,000,000 shares authorized, 16,972,517
and 16,846,956 shares issued, and 16,291,242 and 16,459,156
shares outstanding, respectively 169,725 168,470
Additional paid-in capital 148,901,270 147,542,977
Treasury stock held, at cost, 681,275 and 387,800 shares, (11,841,884) (8,519,665)
respectively
Unearned ESOP compensation --- (150,055)
Retained earnings (deficit) (27,866,472) 20,359,193
---------------- ---------------
109,362,639 159,400,920
---------------- ---------------
$ 403,645,267 $ 339,115,390
================ ===============
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
28
<PAGE>
Consolidated Statements of Income
Swift Energy Company and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31,
1998 1997 1996
-------------------------------------------------------
<S> <C> <C> <C>
Revenues:
Oil and gas sales $ 80,067,837 $ 69,015,189 $ 52,770,672
Fees from limited partnerships and joint
ventures 333,940 745,856 937,238
Interest income 107,374 2,395,406 433,352
Other, net 1,960,070 2,555,729 2,156,764
--------------- --------------- -------------
82,469,221 74,712,180 56,298,026
--------------- --------------- -------------
Costs and Expenses:
General and administrative, net
of reimbursement 3,853,812 3,523,604 4,149,964
Depreciation, depletion, and amortization 39,343,187 24,247,142 16,526,379
Oil and gas production 13,138,980 8,778,876 6,141,941
Interest expense, net 8,752,195 5,032,952 693,959
Write-down of oil and gas properties 90,772,628 --- ---
--------------- --------------- -------------
155,860,802 41,582,574 27,512,243
--------------- ---------------- -------------
Income (Loss) Before Income Taxes (73,391,581) 33,129,606 28,785,783
Provision (Benefit) for Income Taxes (25,166,377) 10,819,417 9,760,333
--------------- --------------- -------------
Net Income (Loss) $ (48,225,204) $ 22,310,189 $ 19,025,450
=============== =============== =============
Per Share Amounts-
Basic $ (2.93) $ 1.35 $ 1.27
=============== =============== =============
Diluted $ (2.93) $ 1.26 $ 1.25
=============== =============== =============
Weighted Average Shares Outstanding 16,436,972 16,492,856 15,000,901
=============== =============== =============
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
29
<PAGE>
Consolidated Statements of Stockholders' Equity
Swift Energy Company and Subsidiaries
<TABLE>
<CAPTION>
Unearned
Additional ESOP Retained
Common Paid-in Treasury Compen- Earnings
Stock (1) Capital Stock sation (Deficit) Total
---------- -------------- ------------- ------------- --------------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1995 $ 125,097 $ 71,133,979 $ - $ - $ 22,086,889 $ 93,345,965
Stock issued for benefit
plans (30,015 shares) 300 347,345 - - - 347,645
Stock options exercised
(257,207 shares) 2,572 2,630,959 - - - 2,633,531
Employee stock purchase plan
(36,387 shares) 364 272,178 - - - 272,542
Loan to ESOP for purchase
of shares - - - (568,750) - (568,750)
Allocation of ESOP shares - 5,382 - 47,396 - 52,778
Debenture conversion
(2,343,108 shares) 23,431 27,629,018 - - - 27,652,449
Net income - - - - 19,025,450 19,025,450
---------- -------------- -------------- ------------- -------------- --------------
Balance, December 31, 1996 $ 151,764 $ 102,018,861 $ - $ (521,354) $ 41,112,339 $ 142,761,610
Stock issued for benefit
plans (12,227 shares) 122 371,359 - - - 371,481
Stock options exercised
(137,155 shares) 1,372 1,613,071 - - - 1,614,443
Employee stock purchase plan
(26,551 shares) 266 403,145 - - - 403,411
10% stock dividend
(1,494,606 shares) 14,946 43,048,389 - - (43,063,335) -
Allocation of ESOP shares - 88,152 - 371,299 - 459,451
Purchase of 387,800 shares
as treasury stock - - (8,519,665) - - (8,519,665)
Net income - - - - 22,310,189 22,310,189
---------- -------------- ------------- ------------- -------------- --------------
Balance, December 31, 1997 $ 168,470 $ 147,542,977 $ (8,519,665) $ (150,055) $ 20,359,193 $ 159,400,920
Stock issued for benefit
plans (20,032 shares) 200 367,058 - - - 367,258
Stock options exercised
(84,757 shares) 847 735,746 - - - 736,593
Employee stock purchase
plan (20,756 shares) 208 317,340 - - - 317,548
Stock dividend adjustment
(16 shares) - 461 - - (461) -
Allocation of ESOP shares - (62,312) - 150,055 - 87,743
Purchase of 293,475 shares
as treasury stock - - (3,322,219) - - (3,322,219)
Net loss - - - - (48,225,204) (48,225,204)
---------- -------------- ------------- ------------- -------------- --------------
Balance, December 31, 1998 $ 169,725 $ 148,901,270 $ (11,841,884) $ - $ (27,866,472) $ 109,362,639
========== ============== ============= ============= ============== ==============
(1)$.01 par value.
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
30
<PAGE>
Consolidated Statements of Cash Flows
Swift Energy Company and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------------
1998 1997 1996
---------------- ----------------- --------------
<S> <C> <C> <C>
Cash Flows from Operating Activities:
Net income (loss) $ (48,225,204) $ 22,310,189 $ 19,025,450
Adjustments to reconcile net income to net cash provided
by operating activities-
Depreciation, depletion, and amortization 39,343,187 24,247,142 16,526,379
Write-down of oil and gas properties 90,772,628 -- --
Deferred income taxes (25,609,134) 10,060,193 8,449,283
Deferred revenue amortization related to production
payment (1,248,800) (1,449,808) (1,670,172)
Other 478,470 786,917 140,047
Change in assets and liabilities-
Increase in accounts receivable (2,129,360) (204,475) (5,008,592)
Increase (decrease) in accounts payable and accrued
liabilities, excluding income taxes payable 689,347 (564,323) (444,966)
Increase in income taxes payable 177,883 70,130 85,149
---------------- ----------------- --------------
Net Cash Provided by Operating Activities 54,249,017 55,255,965 37,102,578
------------------ ----------------- --------------
Cash Flows from Investing Activities:
Additions to property and equipment (183,815,927) (131,967,444) (91,487,176)
Proceeds from the sale of property and equipment 1,533,112 3,369,982 2,247,799
Net cash distributed as operator of oil and gas properties (5,933,171) (1,829,008) (2,074,104)
Net cash received (distributed) as operator of
partnerships and joint ventures (1,559,537) (2,102,553) 11,284,793
Limited partnership formation and marketing costs (619,970) -- --
Other (113,716) (259,255) 840
------------------ ----------------- --------------
Net Cash Used in Investing Activities (190,509,209) (132,788,278) (80,027,848)
---------------- ----------------- --------------
Cash Flows from Financing Activities:
Proceeds from convertible notes -- -- 115,000,000
Net proceeds from bank borrowings 138,285,000 7,915,000 --
Net proceeds from issuances of common stock 1,421,399 2,389,336 3,264,482
Purchase of treasury stock (3,322,219) (8,519,665) --
Loan to ESOP for purchase of shares -- -- (568,750)
Payments of debt issuance costs (540,671) -- (4,550,000)
---------------- ----------------- --------------
Net Cash Provided by Financing Activities 135,843,509 1,784,671 113,145,732
---------------- ------------------ --------------
Net Increase (Decrease) in Cash and Cash Equivalents $ (416,683) $ (75,747,642) $ 70,220,462
Cash and Cash Equivalents at Beginning of Year 2,047,332 77,794,974 7,574,512
---------------- ----------------- --------------
Cash and Cash Equivalents at End of Year $ 1,630,649 $ 2,047,332 $ 77,794,974
================ ================= ==============
Supplemental Disclosures of Cash Flows Information:
Cash paid during year for interest, net of amounts capitalized $ 8,343,445 $ 4,638,308 $ 831,516
Cash paid during year for income taxes $ 36,286 $ 381,514 $ 676,920
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
31
<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 exploration, development, acquisition, and operation of oil and
natural gas properties, with particular emphasis on U.S. onshore natural gas
reserves. The Company also has oil and gas activities in New Zealand, Venezuela,
and Russia. The Company's investments in associated oil and gas partnerships and
its joint ventures are accounted for using the proportionate consolidation
method, whereby the Company's proportionate share of each entity's assets,
liabilities, revenues, and expenses is included in the appropriate
classifications in the consolidated financial statements. Intercompany balances
and transactions have been eliminated in preparing the consolidated statements.
In the second quarter of 1998, the Company began netting supervision fees
against general and administrative expenses and oil and gas production costs.
This reclassification has been made for all periods presented. Certain other
reclassifications have been made to prior year amounts to conform to the current
year presentation.
Use of Estimates. The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities, if any, at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from
estimates.
Property and Equipment. The Company follows the "full-cost" method of
accounting for oil and gas property and equipment costs. Under this method of
accounting, all productive and nonproductive costs incurred in the acquisition,
exploration, and development of oil and gas reserves are capitalized. Under the
full-cost method of accounting, such costs may be incurred both prior to or
after the acquisition of a property and include lease acquisitions, geological
and geophysical services, drilling, completion, equipment, and certain general
and administrative costs directly associated with acquisition, exploration, and
development activities. Interest costs related to unproved properties are also
capitalized to unproved oil and gas properties. The Company's management
believes this capitalization of such costs is appropriate under full-cost
accounting rules. General and administrative costs related to production and
general overhead are expensed as incurred.
No gains or losses are recognized upon the sale or disposition of oil and
gas properties, except in transactions that involve a significant amount of
reserves. The proceeds from the sale of oil and gas properties are generally
treated as a reduction of oil and gas property costs. Fees from associated oil
and gas exploration and development limited partnerships are credited to oil and
gas property costs to the extent they do not represent reimbursement of general
and administrative expenses currently charged to expense.
Future development, site restoration, and dismantlement and abandonment
costs, net of salvage values, are estimated on a property-by-property basis
based on current economic conditions and are amortized to expense as the
Company's capitalized oil and gas property costs are amortized. The Company's
properties are all onshore, and historically the salvage value of the tangible
equipment offsets the Company's site restoration and dismantlement and
abandonment costs. The Company expects that this relationship will continue in
the future.
The Company computes the provision for depreciation, depletion, and
amortization of oil and gas properties on the unit-of-production method. Under
this method, the Company computes the provision by multiplying the total
unamortized costs of oil and gas properties--including future development, site
restoration, and dismantlement and abandonment costs, but excluding costs of
unproved properties--by an overall rate determined by dividing the physical
units of oil and gas produced during the period by the total estimated units of
proved oil and gas reserves. This calculation is done on a country-by-country
basis for those countries with oil and gas production. The Company currently has
production in the United States only. All other equipment is depreciated by the
straight-line method at rates based on the estimated useful lives of the
property. Repairs and maintenance are charged to expense as incurred. Renewals
and betterments are capitalized.
32
<PAGE>
The cost of unproved properties not being amortized is assessed quarterly,
on a country-by-country basis, to determine whether such properties have been
impaired. Domestically, any impairment assessed is added to the cost of proved
properties being amortized. To the extent costs accumulated in the Company's
international initiatives are determined by management to be costs that will not
result in the addition of proved reserves, any impairment is charged to income.
In determining whether such costs should be impaired, the Company's management
evaluates, among other factors, current oil and gas industry conditions,
international economic conditions, capital availability, foreign currency
exchange rates, the political stability in the countries in which the Company
has an investment, and available geological and geophysical information.
Domestic Properties. At the end of each quarterly reporting period, the
unamortized cost of oil and gas properties, net of related deferred income
taxes, is limited to the sum of the estimated future net revenues from proved
properties using current period-end prices, discounted at 10%, and the lower of
cost or fair value of unproved properties, adjusted for related income tax
effects ("Ceiling Test"). This calculation is done on a country-by-country basis
for those countries with proved reserves. Currently, the Company has proved
reserves in the United States only.
The calculation of the Ceiling Test and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves. There are
numerous uncertainties inherent in estimating quantities of proved reserves and
in projecting the future rates of production, timing, and plan of development.
The accuracy of any reserves estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. Results of
drilling, testing, and production subsequent to the date of the estimate may
justify revision of such estimate. Accordingly, reserves estimates are often
different from the quantities of oil and gas that are ultimately recovered.
As a result of low oil and gas prices at September 30, 1998, the Company
reported a non-cash write-down on a before-tax basis of $77.2 million ($50.9
million after tax) on its domestic properties.
Foreign Properties. In addition, during the third quarter of 1998, as it
does every reporting period, the Company evaluated all of its foreign
unevaluated properties (a detailed description of which is included in Note 8 to
the Company's financial statements), especially in light of the then increased
volatility in the oil and gas markets, international uncertainty, and turmoil in
the world capital markets.
The increased volatility in the oil and gas markets affected the Company's
cash flows available for further exploration and forced the Company to scale
back its capital expenditures budget. All of this was further accentuated in
Venezuela by the economic crisis there, the results of which were to diminish
the availability of financing in international markets for Venezuelan projects
and to worsen Venezuelan currency problems. Petroleos de Venezuela, S.A.
layoffs, threatened oil worker strikes, reduced OPEC production allocations, and
other third quarter 1998 events highlight the problems that the oil and gas
industry is encountering in Venezuela. As a result of these and other factors,
in the third quarter of 1998, the Company decided to impair all $2.8 million of
costs related to its Venezuelan oil and gas exploration activities.
In addition, in the third quarter of 1998, the Company impaired all $10.8
million of costs relating to its Russian activities. This impairment is
attributed not only to the volatility in the oil and gas markets and the severe
tightening of international credit markets discussed above, but also to the
increased political instability in Russia and the August 1998 collapse of the
Russian currency. The Company believed that the economic and political situation
would result in the lack of capital to develop these reserves underlying the
Company's net profits interest in the near term. Although the Company continues
to believe that its net profits interest is legally enforceable under
international law, for all these reasons the Company does not believe that
realistically it will be able to recover its investment in Russia in the
foreseeable future. Because of this, the Company determined that it no longer
had a reasonable basis to continue capitalization of the costs in its Russia
cost center.
The combination of the third-quarter domestic full-cost ceiling write-down
and foreign activities impairment charges reduced before-tax earnings by $90.8
million ($59.9 million after tax). Since such impairment, any costs incurred in
Venezuela and Russia have been charged to income.
Also, during the fourth quarter of 1998, the Company's $0.4 million portion
of drilling costs associated with an unsuccessful exploratory well drilled by
another operator in New Zealand was charged to income as depreciation,
depletion, and amortization costs.
33
<PAGE>
Oil and Gas Revenues. Gas revenues are reported using the entitlement
method in which the Company recognizes its ownership interest in natural gas
production as revenue. If the Company's sales exceed its ownership share of
production, the differences are reported as deferred revenue. Natural gas
balancing receivables are reported when the Company's ownership share of
production exceeds sales. As of December 31, 1998, the Company did not have any
material natural gas imbalances.
Deferred Charges. Legal and accounting fees, underwriting fees, printing
costs, and other direct expenses associated with the public offering in November
1996 of the Company's 6.25% Convertible Subordinated Notes (the "Notes") have
been capitalized and are being amortized over the life of the Notes, which
mature on November 15, 2006. The balance of these issuance costs at December 31,
1998 was $3,826,864, net of accumulated amortization of $723,136. The issuance
costs associated with its new $250.0 million revolving credit facility (the "New
Credit Facility"), which closed in August 1998, have been capitalized and are
being amortized over the life of the facility, which will extend until August
2002. The balance of these issuance costs at December 31, 1998, was $507,094,
net of accumulated amortization of $51,600.
Limited Partnerships and Joint Ventures. Between 1984 and 1995, the Company
formed limited partnerships and joint ventures for the purpose of acquiring
interests in producing oil and gas properties and, since 1993, partnerships
engaged in drilling for oil and gas reserves. The Company serves as managing
general partner or manager of these entities.
The Company acquired producing oil and gas properties and transferred those
properties to the partnership entities which invested in producing oil and gas
properties. These transfers were at cost, including interest, other carrying
costs, closing costs, and screening and evaluation costs of properties not
acquired, or, in certain instances, at fair market value based upon the opinion
of an independent expert. These costs were reduced by net operating revenues
from the effective date of the acquisition to the date of transfer to these
entities. Such net operating revenue amounts totaled approximately $100,000 and
$300,000 in 1997 and 1996, respectively. With the acquisitions made in 1997, the
Company fulfilled its responsibility of acquiring properties for such
partnerships, as these partnerships are fully invested in properties.
Commencing in September 1993, the Company began offering, on a private
placement basis, general and limited partnership interests in limited
partnerships to be formed to drill for oil and gas. As managing general partner,
the Company pays for all front-end costs incurred in connection with these
offerings, for which the Company receives an interest in the partnerships.
Through December 31, 1998, approximately $66.1 million had been raised in
thirteen partnerships, one each formed in 1993 and 1994; three each in 1995,
1996, and 1997; and two in 1998. In June and October 1998, the Company closed
the twelfth and thirteenth partnerships with total subscriptions of
approximately $3.2 million and $4.3 million, respectively. Costs of syndication
and qualification of these limited partnerships incurred by the Company have
been deferred. Under the current private limited partnership offerings, selling
and formation costs borne by the Company serve as the Company's general partner
contribution to such partnerships.
During 1996, the limited partners in 18 partnerships, which had been in
operation over nine years and had produced a substantial majority of their
reserves, voted to sell their remaining properties and liquidate the limited
partnerships. Of these partnerships, 10 were the earliest public income
partnerships formed between 1984 and 1986. In early 1997, eight private drilling
partnerships formed between 1979 and 1985 were liquidated. During 1997, the
limited partners in an additional 11 partnerships, formed in 1990 and 1991,
voted to sell their properties and liquidate the limited partnerships, which
occurred in June 1998.
In October 1998, the Company notified investors in 63 Company-managed
partnerships, formed between 1986 and 1994, that it had delayed calling investor
meetings to consider its purchase of all of the oil and gas properties owned by
these partnerships, which was proposed in March 1998. This decision principally
reflected significant market changes that had occurred during the long period
necessary for regulatory review of soliciting materials, the age of the third-
party appraisals of these partnership properties, and the much publicized
weakness in both the equity and debt markets for energy companies. During the
last six months, the weakness in oil and natural gas prices has deepened,
creating concern over the appropriateness of selling properties at this time.
The Company expects to continue to re-evaluate the status and operation of these
partnerships, whether to propose some form of liquidating transaction and, if
so, when and in what form.
Hedging Activities. The Company's revenues are primarily the result of
sales of its oil and natural gas production. Market prices of oil and natural
gas may fluctuate and adversely affect operating results. To mitigate some of
this risk, the Company engages periodically in certain limited hedging
activities, but only to the extent of buying protection price floors for
portions of its and the limited partnerships' oil and natural gas production.
Costs and any benefits derived from these price floors are accordingly recorded
as a reduction or
34
<PAGE>
an increase, as applicable, in oil and gas sales revenue and were not
significant for any year presented. The costs to purchase put options are
amortized over the option period. The costs related to 1998 hedging activities
totaled approximately $377,000 with benefits of approximately $101,000 being
received, resulting in a net cash outlay of approximately $276,000 or $0.007 per
Mcfe. The costs related to the open contracts as of December 31, 1998, totaled
approximately $252,000 and had a fair market value of $267,000.
Income Taxes. The Company accounts for income taxes using the liability
method, and deferred taxes are determined based on the estimated future tax
effects of differences between the financial statement and tax bases of assets
and liabilities given the provisions of the enacted tax laws.
Deferred Revenues. In May 1992, the Company purchased interests in certain
wells using funds provided by the Company's sale of a volumetric production
payment in these properties to Enron. Under the production payment agreement,
the Company is required to deliver to Enron approximately 9.5 Bcf over an
eight-year period, or for such longer period as is necessary to deliver a
specified heating equivalent quantity at an average price of $1.115 per MMBtu.
The Company receives all proceeds from sale of excess gas at current market
prices plus the proceeds from sale of oil or condensate. Volumes remaining to be
delivered through October 2000 under the volumetric production payment were
approximately 1.1 Bcf at December 31, 1998, and were not included in the
Company's proved reserves. Net proceeds from the sale of the production payment
were recorded as deferred revenues. Deliveries under the production payment
agreement are recorded as oil and gas sales revenues and a corresponding
reduction of deferred revenues.
Cash and Cash Equivalents. The Company considers all highly liquid debt
instruments with an initial maturity of three months or less to be cash
equivalents.
Credit Risk Due to Certain Concentrations. The Company extends credit,
primarily in the form of monthly oil and gas sales and joint interest owners
receivables, to various companies in the oil and gas industry, which results in
a concentration of credit risk. The concentration of credit risk may be affected
by changes in economic or other conditions and may accordingly impact the
Company's overall credit risk. However, the Company believes that the risk of
these unsecured receivables is mitigated by the size, reputation, and nature of
the companies to which the Company extends credit. During 1998, oil and gas
sales to subsidiaries of PG&E Energy Trading Corporation and Aquila Southwest
Pipeline Corporation were $13.0 million (16.2% of oil and gas sales) and $8.0
million (10.0%), respectively. In 1997, oil and gas sales to PG&E Energy Trading
Corporation, Aquila Southwest Pipeline Corporation, and Koch Oil Company were
$13.5 million (19.5%), $8.1 million (11.7%), and $7.1 million (10.3%),
respectively. In 1996, oil and gas sales to TECO Gas Marketing Company were $6.9
million (13.0%).
Fair Value of Financial Instruments. The Company's financial instruments
consist of cash and cash equivalents, accounts receivable, accounts payable,
bank borrowings, and convertible notes. The carrying amounts of cash and cash
equivalents, accounts receivable, and accounts payable approximate fair value
due to the highly liquid nature of these short-term instruments. The fair values
of the bank borrowings approximate the carrying amounts as of December 31, 1998
and 1997 and were determined based upon interest rates currently available to
the Company for borrowings with similar terms. The fair values of the
convertible notes were $81.4 million and $113.6 million at December 31, 1998 and
1997, respectively, and were based on quoted markets prices as of the respective
dates.
New Accounting Pronouncements. In the first quarter of 1998, the Company
adopted the Statement of Financial Accounting Standards ("SFAS") No. 130,
"Reporting Comprehensive Income," which requires the display of comprehensive
income and its components in the financial statements. Comprehensive income
represents all changes in equity during the reporting period, including net
income and charges directly to equity, which are excluded from net income. The
adoption of this statement does not have a material impact on the Company or its
financial disclosures, as the Company has not historically and currently does
not enter into transactions that result in charges (or credits) directly to
equity (such as additional minimum pension liability changes, currency
translation adjustments, and unrealized gains and losses on available-for-sale
securities).
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." The Statement
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows the gains and losses on derivatives to offset related results on the
hedged item in the income statements and requires that a company must formally
document, designate, and assess the effectiveness of transactions that receive
hedge accounting. SFAS No.
35
<PAGE>
133 is effective for fiscal years beginning after June 15, 1999. The Company is
currently evaluating the new standard, but has not yet determined the impact it
will have on its financial position and results of operations.
2. Earnings Per Share
Basic earnings per share ("Basic EPS") has been computed using the weighted
average number of common shares outstanding during the respective periods. Basic
EPS has been retroactively restated in all periods presented to give recognition
to the 10% stock dividend declared in October 1997 that resulted in an
additional 1,494,622 shares being issued.
The calculation of diluted earnings per share ("Diluted EPS") assumes
conversion of the Company's Convertible Notes as of the beginning of the
respective periods and the elimination of the related after-tax interest expense
and assumes, as of the beginning of the period, exercise of stock options and
warrants (using the treasury stock method). Certain of the Company's stock
options that would potentially dilute Basic EPS in the future were not included
in the computation of Diluted EPS because to do so would have been antidilutive
for the 1998 period. Diluted EPS has also been retroactively restated for all
periods presented to give effect to the 10% stock dividend. The original
conversion price of the Convertible Notes of $34.6875 was revised to $31.534 to
reflect the October 1997 stock dividend declared.
The following is a reconciliation of the numerators and denominators used
in the calculation of Basic and Diluted EPS for the years ended December 31,
1998, 1997, and 1996:
<TABLE>
<CAPTION>
1998 1997 1996
--------------------------------- ----------------------------------- ---------------------------------
Per Per Per
Net Share Net Share Net Share
Loss Shares Amount Income Shares Amount Income Shares Amount
------------- ------------ ------ ------------ ---------- ------- ------------ ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Basic EPS:
Net Income (Loss) and
Share Amounts $ (48,225,204) 16,436,972 $(2.93) $ 22,310,189 16,492,856 $ 1.35 $ 19,025,450 15,000,901 $ 1.27
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 (Loss) and
Assumed Share
Conversions $ (48,225,204) 16,436,972 $(2.93) $ 25,835,997 20,567,739 $ 1.26 $ 19,814,160 15,827,646 $ 1.25
------------- ----------- ------------ ---------- ------------ ----------
</TABLE>
36
<PAGE>
3. Provision for Income Taxes
The following is an analysis of the consolidated income tax provision
(benefit):
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------
1998 1997 1996
-------------- -------------- --------------
<S> <C> <C> <C> <C>
Current $ 214,169 $ 77,402 $ 759,253
Deferred (25,380,546) 10,742,015 9,001,080
-------------- --------------- --------------
Total $ (25,166,377) $ 10,819,417 $ 9,760,333
============== =============== ==============
</TABLE>
There are differences between income taxes computed using the statutory
rate (34% for 1998, 1997, and 1996) and the Company's effective income tax rates
(34.3%, 32.7%, and 33.9% for 1998, 1997, and 1996, respectively), primarily as
the result of certain tax credits available to the Company. Reconciliations of
income taxes computed using the statutory rate to the effective income tax rates
are as follows:
<TABLE>
<CAPTION>
1998 1997 1996
-------------- ------------- -------------
<S> <C> <C> <C>
Income taxes computed at federal statutory rate $ (24,953,138) $ 11,264,066 $ 9,787,166
State tax provisions, net of federal benefits 23,949 48,058 75,936
Nonconventional fuel source credit (287,000) (294,000) (306,000)
Depletion deductions in excess of basis (42,500) (51,000) (26,520)
Other, net 92,312 (147,707) 229,751
-------------- ------------- -------------
Provision (benefit) for income taxes $ (25,166,377) $ 10,819,417 $ 9,760,333
============== ============= =============
</TABLE>
The tax effects of significant temporary differences representing the net
deferred tax liability (asset) at December 31, 1998 and 1997, were as follows:
<TABLE>
<CAPTION>
1998 1997
-------------- --------------
<S> <C> <C>
Deferred tax assets:
Alternative minimum tax credits $ (1,979,399) $ (1,831,299)
Other (237,587) (237,587)
-------------- --------------
Total deferred tax assets $ (2,216,986) $ (2,068,886)
Deferred tax liabilities:
Oil and gas properties $ 1,531,651 $ 26,785,212
Other 430,351 637,824
-------------- --------------
Total deferred tax
liabilities $ 1,962,002 $ 27,423,036
-------------- --------------
Net deferred tax liability (asset) $ (254,984) $ 25,354,150
============== ==============
</TABLE>
The Company did not record any valuation allowances against deferred tax
assets at December 31, 1998 or 1997.
37
<PAGE>
At December 31, 1998, the Company had alternative minimum tax credits of
$1,979,399 that carry forward indefinitely and are available to reduce future
regular tax liability to the extent they exceed the related tentative minimum
tax otherwise due.
4. Long-Term Debt
Convertible Notes. The Company's convertible notes at December 31, 1998 and
1997, consist of $115,000,000 of 6.25% Convertible Subordinated Notes due 2006.
The 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, and commenced 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.
Interest expense on the Notes, including amortization of debt issuance
costs, totaled $7,544,650 and $7,514,967 in 1998 and 1997, respectively.
Bank Borrowings. In August 1998, the Company closed its new $250.0 million
revolving credit facility with a syndicate of ten banks (the "New Credit
Facility"). At December 31, 1998, the Company had outstanding borrowings of
$146.2 million under its New Credit Facility. At December 31, 1997, the Company
had outstanding borrowings of $7.9 million under its borrowing arrangements. At
December 31, 1998, the New Credit Facility consisted of a $250.0 million
revolving line of credit with a $170.0 million borrowing base. The interest rate
is either (a) the lead bank's prime rate (7.75% at December 31, 1998) or (b) the
adjusted London Interbank Offered Rate ("LIBOR") plus the applicable margin
depending on the level of outstanding debt (a weighted average of 6.34% at
December 31, 1998). The applicable margin is based on the Company's ratio of
outstanding balance on the New Credit Facility to the last calculated borrowing
base. Of the $146.2 million borrowed at December 31, 1998, $145.0 million was
borrowed at the LIBOR rate.
The terms of the New Credit Facility include, among other restrictions, a
limitation on the level of cash dividends (not to exceed $2.0 million in any
fiscal year), requirements as to maintenance of certain minimum financial ratios
(principally pertaining to working capital, debt, and equity ratios), and
limitations on incurring other debt. Since inception, no cash dividends have
been declared on the Company's common stock. The Company is currently in
compliance with the provisions of this agreement, as amended in mid-March 1999
to modify the cash flow-to-debt covenant. The New Credit Facility will extend
until August 2002.
Previously, the Company's credit facilities consisted of a $100.0 million
revolving line of credit with an $80.0 million borrowing base and a $7.0 million
revolving line of credit with a $5.1 million borrowing base. These facilities
were with a two-bank group. Depending on the level of outstanding debt, the
interest rate on the $100.0 million revolving line of credit was (a) either the
bank's base rate or the bank's base rate plus 0.25% or (b) the LIBOR rate plus
1% to 1.5%. The interest rate on the $7.0 million revolving line of credit was
the bank's base rate less 0.25%.
In addition to interest on these credit facilities, the Company pays a
commitment fee to compensate the banks for making funds available. The fee on
the revolving line of credit is calculated on the average daily remainder, if
any, of the commitment amount less the aggregate principal amounts outstanding,
plus the amount of all letters of credit outstanding during the period. The
aggregate amounts of commitment fees paid by the Company were $114,000 in 1998
and $31,000 in 1997.
5. Commitments and Contingencies
Total rental and lease expenses were $1,117,351 in 1998, $1,039,210 in
1997, and $957,797 in 1996. The Company's remaining minimum annual obligations
under non-cancelable operating lease commitments are $1,146,229 for 1999,
$1,151,249 for 2000, $1,151,249 for 2001, $1,273,007 for 2002, and $1,358,238
for 2003.
38
<PAGE>
As of December 31, 1998, the Company is the managing general partner of 80
limited partnerships. Because the Company serves as the general partner of these
entities, under state partnership law it is contingently liable for the
liabilities of these partnerships, which liabilities are not material for any of
the periods presented in relation to the partnerships' respective assets.
In the ordinary course of business, the Company has been party to various
legal actions, which arise primarily from its activities as operator of oil and
gas wells. In management's opinion, the outcome of any such currently pending
legal actions will not have a material adverse effect on the financial position
or results of operations of the Company.
6. Stockholders' Equity
Common Stock. In October 1997, the Company declared a 10% stock dividend to
stockholders of record. The transaction was valued based on the closing price
($28.8125) of the Company's common stock on the New York Stock Exchange on
October 1, 1997. As a result of the issuance of 1,494,622 shares of the
Company's common stock as a dividend, retained earnings were reduced by
$43,063,796, with the common stock and additional paid-in capital accounts
increased by the same amount. Basic and Diluted EPS were restated for all
periods presented to reflect the effect of the stock dividend.
Stock-Based Compensation Plans. The Company has two stock option plans, the
1990 stock compensation plan and the 1990 non-qualified plan, as well as an
employee stock purchase plan.
Under the 1990 stock compensation plan, incentive stock options and other
options and awards may be granted to employees to purchase shares of common
stock. Under the 1990 non-qualified plan, non-employee members of the Company's
Board of Directors may be granted options to purchase shares of common stock.
Both plans provide that the exercise prices equal 100% of the fair value of the
common stock on the date of grant. Options become exercisable for 20% of the
shares on the first anniversary of the grant of the option and are exercisable
for an additional 20% per year thereafter. Options granted expire 10 years after
the date of grant or earlier in the event of the optionee's separation from
employment. At the time the stock options are exercised, the option price is
credited to common stock and additional paid-in capital.
On December 9, 1998, the Company canceled certain previously issued options
under the 1990 stock compensation plan and reissued them at an option price that
reflected current market value of the Company's common stock as of that date. No
compensation expense was recognized in 1998 as a result of this transaction.
The employee stock purchase plan provides eligible employees the
opportunity to acquire shares of Company common stock at a discount through
payroll deductions. The plan year is from June 1 to the following May 31. The
first year of the plan commenced June 1, 1993. To date, employees have been
allowed to authorize payroll deductions of up to 10% of their base salary during
the plan year by making an election to participate prior to the start of a plan
year. The purchase price for stock acquired under the plan will be 85% of the
lower of the closing price of the Company's common stock as quoted on the New
York Stock Exchange at the beginning or end of the plan year or a date during
the year chosen by the participant. Under this plan, the Company issued 20,756
shares at a price range of $13.65 to $18.06 in 1998, 26,551 shares at a price of
$15.19 in 1997, and 36,387 shares at a price range of $6.59 to $7.97 in 1996.
The estimated weighted average fair value of shares issued under this plan was
$6.86 in 1998, $4.39 in 1997, and $2.13 in 1996. As of December 31, 1998, there
remained 437,448 shares available for issuance under this plan. There are no
charges or credits to income in connection with this plan.
39
<PAGE>
The Company accounts for the two stock option plans under Accounting
Principles Board Opinion No. 25, under which no compensation expense has been
recognized. Had compensation expense for these plans been determined consistent
with SFAS No. 123, "Accounting for Stock-Based Compensation," the Company's net
income (loss) and earnings per share would have been reduced to the following
pro forma amounts (1996 amounts have been restated to reflect the October 1997
10% stock dividend):
<TABLE>
<CAPTION>
1998 1997 1996
------------ ----------- -----------
<S> <C> <C> <C> <C>
Net Income (Loss): As Reported ($48,225,204) $22,310,189 $19,025,450
Pro Forma ($49,985,171) $21,362,722 $18,750,064
Basic EPS: As Reported ($2.93) $1.35 $1.27
Pro Forma ($3.04) $1.30 $1.25
Diluted EPS: As Reported ($2.93) $1.26 $1.25
Pro Forma ($3.04) $1.21 $1.23
</TABLE>
Because the SFAS No. 123 method of accounting has not been applied to
options granted prior to January 1, 1995, the resulting pro forma compensation
cost may not be representative of the cost to be expected in future years.
The following is a summary of the Company's stock options under these plans
as of December 31, 1998, 1997, and 1996:
<TABLE>
<CAPTION>
1998 1997 1996
----------------------- ---------------------- -------------------------
Wtd. Avg. Wtd. Avg. Wtd. Avg.
Exer. Exer. Exer.
Shares Price Shares Price Shares Price
----------------------- ---------------------- -------------------------
<S> <C> <C> <C> <C> <C> <C>
Options outstanding, beginning of period 1,761,512 $ 14.71 1,399,769 $ 12.09 1,308,391 $ 8.83
Options granted 1,319,881 $ 9.72 401,390 $ 26.23 302,281 $ 23.78
Options cancelled (730,490) $ 24.15 (31,404) $ 12.99 (11,251) $ 8.81
Options exercised (84,757) $ 7.54 (137,155) $ 8.54 (199,652) $ 8.65
Options adjusted for 10% stock dividend -- 128,912 --
----------- ----------- -----------
Options outstanding, end of period 2,266,146 $ 9.03 1,761,512 $ 4.71 1,399,769 $ 12.09
=========== =========== ===========
Options exercisable, end of period 888,695 $ 8.64 869,484 $ 9.05 700,271 $ 8.82
=========== =========== ===========
Options available for future grant, end
of period 915,236 1,501,622 38,546
=========== =========== ===========
Estimated weighted average fair value per
share of options granted during the year $3.82 $13.98 $15.17
=========== =========== ===========
</TABLE>
40
<PAGE>
The fair value of each option grant, as opposed to its exercise price, is
estimated on the date of grant using the Black-Scholes option-pricing model with
the following weighted average assumptions in 1998, 1997, and 1996,
respectively: no dividend yield, expected volatility factors of 42.3%, 38.7%,
and 40.4%, risk-free interest rates of 4.69%, 6.02%, and 6.42%, and expected
lives of 7.0, 7.5, and 10.0 years. The following table summarizes information
about stock options outstanding at December 31, 1998:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
--------------------------------------- -------------------------
Wtd. Avg. Wtd. Avg.
Range of Number Remaining Number Wtd. Avg.
Exercise Outstanding Contractual Exercise Exercisable Exercise
Prices at 12/31/98 Life Price at 12/31/98 Price
- -------------------- ------------ ------------ ----------- ------------- -----------
<S> <C> <C> <C> <C> <C>
$ 4.00 to $ 8.99 1,147,917 6.3 $ 7.87 598,490 $ 7.75
$ 9.00 to $17.99 1,057,251 7.5 $ 9.57 279,687 $ 9.96
$18.00 to $27.00 60,978 8.3 $ 21.47 10,518 $ 23.72
------------ -----------
$ 4.00 to $27.00 2,266,146 7.0 $ 9.03 888,695 $ 8.64
============ ===========
</TABLE>
Employee Stock Ownership Plan. In 1996, the Company established an Employee
Stock Ownership Plan ("ESOP") effective January 1, 1996. All employees over the
age of 21 with one year of service are participants. The Plan has a five-year
cliff vesting, and service is recognized after the Plan effective date. The ESOP
is designed to enable employees of the Company to accumulate stock ownership.
While there will be no employee contributions, participants will receive an
allocation of stock that has been contributed by the Company. Compensation
expense is reported when such shares are released to employees. The Plan may
also acquire common stock of the Company purchased at fair market value. The
ESOP can borrow money from the Company to buy Company stock. This was done in
September 1996 to purchase 25,000 shares (adjusted to 27,500 shares after the
October 1, 1997, 10% stock dividend) from the Company's chairman. Benefits will
be paid in a lump sum or installments, and the participants generally have the
choice of receiving cash or stock. At December 31, 1998, all of the ESOP
compensation was earned. At December 31, 1997 and 1996, the unearned portions of
the ESOP, $150,055 and $521,354, respectively, were recorded as a contra-equity
account entitled "Unearned ESOP Compensation."
Common Stock Repurchase Program. In March 1997, the Company's Board of
Directors approved a common stock repurchase program for up to $20.0 million of
the Company's common stock and subsequently extended this program through June
30, 1998. Under this program, the Company used approximately $9.3 million of
working capital to acquire 435,274 shares in the open market at an average cost
of $21.47 per share. On July 23, 1998, the Board of Directors approved a new
repurchase program for up to $10.0 million of the Company's common stock through
the end of 1998. Subsequently, the Company used approximately $2.5 million of
working capital to acquire another 246,001 shares for an average cost of $10.14
per share. Through December 31, 1998, 681,275 shares have been acquired at a
total cost of $11,841,884 and are included in "Treasury stock held, at cost" on
the balance sheet.
Shareholder Rights Plan. In August 1997, the Board of Directors declared a
dividend of one preferred share purchase right on each outstanding share of the
Company's common stock. The rights are not currently exercisable but would
become exercisable if certain events occurred relating to any person or group
acquiring or attempting to acquire 15% or more of the Company's outstanding
shares of common stock. Thereafter, upon certain triggers, each right not owned
by an acquirer allows its holder to purchase Company securities with a market
value of two times the $150 exercise price.
7. Related-Party Transactions
The Company is the operator of a substantial number of properties owned by
its affiliated limited partnerships and joint ventures and accordingly, charges
these entities and third-party joint interest owners operating fees. The Company
is also reimbursed for direct, administrative, and overhead costs incurred in
conducting the business of the limited partnerships, which totaled approximately
$5,000,000, $6,300,000, and $6,100,000 in 1998, 1997, and 1996, respectively.
The Company was also reimbursed by the limited partnerships and joint ventures
for costs incurred in the screening, evaluation, and acquisition of producing
oil and gas properties on their behalf. Such costs totaled approximately
$490,000 and $250,000 in 1997 and 1996, respectively. The Company, with the
acquisitions made in 1997, has fulfilled its responsibility of acquiring
41
<PAGE>
properties for such partnerships, as those partnerships are fully invested in
properties. In the case where the limited partners voted to sell their remaining
properties and liquidate their limited partnerships, the Company was also
reimbursed for direct, administrative, and overhead costs incurred in the
disposition of such properties, which costs totaled approximately $580,000,
$675,000, and $805,000 in 1998, 1997, and 1996, respectively.
The ESOP can borrow money from the Company to buy Company stock. This was
done in September 1996 to purchase 25,000 shares (adjusted to 27,500 shares
after the October 1, 1997 10% stock dividend) from the Company's chairman.
Benefits will be paid in a lump sum or installments, and the participants
generally have the choice of receiving cash or stock.
8. Foreign Activities
New Zealand. Since October 1995, the Company has been issued two Petroleum
Exploration Permits by the New Zealand Minister of Energy. The first permit
covered approximately 65,000 acres in the Onshore Taranaki Basin of New
Zealand's North Island, and the second covered approximately 69,300 adjacent
acres. A wholly owned subsidiary, Swift Energy New Zealand Limited, formed in
late 1997, conducts the Company's New Zealand activities and owns the interest
in the permits. In March 1998, the Company surrendered approximately 46,400
acres covered in the first permit, and the remaining acreage has been included
as an extension of the area covered in the second permit. Under the terms of the
expanded permit, the Company is obligated to drill one exploratory well prior to
August 12, 1999. All other obligations under the permit have been fulfilled,
including the reinterpretation of existing seismic data and the acquisition and
processing of new seismic data.
On October 23, 1998, the Company entered into separate agreements with
Marabella Enterprises Ltd. ("Marabella"), a subsidiary of Bligh Oil & Minerals
N.L., an Australian company, to obtain from Marabella a 25% working interest in
another New Zealand Petroleum Exploration Permit and for Marabella to become a
5% participant in the Company's permit. An exploration well on the Marabella
permit commenced drilling on October 16, 1998, the results of which were
unsuccessful. Accordingly, the $0.4 million costs of such well were charged
against earnings. The Company has also agreed in principle to participate with
Marabella in an additional permit as a 17.5% working interest owner.
At December 31, 1998, the Company's investment in New Zealand was
approximately $5.0 million and is included in the unproved properties portion of
oil and gas properties. Approximately $0.4 million of such costs have been
impaired.
Russia. On September 3, 1993, the Company signed a Participation Agreement
with Senega, a Russian Federation joint stock company (in which the Company has
an indirect interest of less than 1%), to assist in the development and
production of reserves from two fields in Western Siberia, providing the Company
with a minimum 5% net profits interest from the sale of hydrocarbon products
from the fields for providing managerial, technical, and financial support to
Senega. Additionally, the Company purchased a 1% net profits interest from
Senega for $0.3 million.
On December 10, 1997, the Company amended and restated the Participation
Agreement. Under the amended and restated Participation Agreement, the Company
retains its 6% net profits interest in the Samburg Field and agreed to assist
Senega in obtaining investments necessary to develop the field. Senega is
charged with the management and control of the field development. The Company's
investment in Russia, prior to its impairment in the third quarter of 1998, was
approximately $10.8 million and was previously included in the unproved
properties portion of oil and gas properties. However, the economic and
political uncertainty and currency concerns that arose during the third quarter
of 1998 in Russia, combined with the price volatility and severe tightening of
international capital markets, caused the Company to re-evaluate the timing of
the recovery of its capitalized costs in that country. See Note 1 to the
Company's financial statements for a more detailed discussion of the impairment.
Subsequent to such impairment, any costs incurred in Russia have been reported
as a charge to earnings.
Venezuela. The Company formed a wholly owned subsidiary, Swift Energy de
Venezuela, C. A., for the purpose of submitting a bid on August 5, 1993, under
the Venezuelan Marginal Oil Field Reactivation Program. Although the Company did
not win the bid, it has continued to gather information relating to reserves and
geological and geophysical data in Venezuela, and continued to pursue
cooperative ventures involving other fields and opportunities in Venezuela. The
Company evaluated a number of blocks being offered by Petroleos de Venezuela, S.
A. under the Third Operating Agreement Round in 1997, but decided against
submitting any bid on these blocks. The Company has entered into an agreement
with Tecnoconsult, S. A., and Corporation
42
<PAGE>
EDC, S.A.C.A., Venezuelan companies, to jointly formulate and submit a proposal
to Petroleos de Venezuela, S. A. for the construction and operation of a methane
pipeline. Currently, the technical and economic feasibility of the project is
under study. The Company's investment in Venezuela, prior to its impairment in
the third quarter of 1998, was approximately $2.8 million and was previously
included in the unproved properties portion of oil and gas properties. However,
the economic uncertainty and currency concerns in Venezuela, combined with the
price volatility and severe tightening of international capital markets, caused
the Company to re-evaluate its prospects of participating in further Venezuelan
exploration activities in the near-term and the prospects for recovery of its
capitalized costs in that country. See Note 1 to the Company's financial
statements for a more detailed discussion of the impairment. Subsequent to such
impairment, any costs incurred in Venezuela have been reported as a charge to
earnings.
9. Acquisition of Properties
In the third quarter of 1998, the Company purchased from Sonat Exploration
Company ("Sonat"), a subsidiary of Sonat Inc., the Toledo Bend Properties
located in Texas and Louisiana in the vicinity of Toledo Bend Lake for
approximately $87.0 million in cash, with approximately $56.8 million of the
total spent for producing properties, approximately $15.0 million to purchase an
interest in two gas processing plants, and approximately $15.2 million to
acquire leasehold properties. Post-closing purchase price adjustments are still
being determined, but management does not expect that these adjustments will be
material to the Company's financial statements.
As of December 31, 1998, estimated proved reserves for the Toledo Bend
Properties were 130.5 Bcfe, of which approximately 58% was natural gas, and 59%
was proved undeveloped. At such date the properties include 162 producing oil
and natural gas wells in the Brookeland Field in Southeast Texas and the Masters
Creek Field in Western Louisiana, 23 saltwater disposal wells, a 20% interest in
two natural gas plants, associated production facilities, working interests in
approximately 200,875 gross undeveloped (125,378 net undeveloped) acres, and
approximately 114,000 undeveloped fee mineral acres. The Company has become
operator of 115 of the 162 wells. The two gas plants are operated by a third
party and have combined capacity of 250 MMcfe per day.
The Toledo Bend Properties extend one of the Company's core areas by adding
producing reserves that the Company believes will significantly increase its
production on a short-term basis. The Company's production on these properties
amounted to approximately 11.6 Bcfe, of which 44% was natural gas. Furthermore,
as a result of the Company's extensive experience in other parts of the Austin
Chalk trend, the Company believes that it can successfully exploit incremental
drilling opportunities in the future.
This acquisition was accounted for by the purchase method and was
incorporated into the Company's results of operations in the third quarter of
1998. The following unaudited pro forma supplemental information presents
consolidated results of operations as if this acquisition had occurred on
January 1, 1997:
<TABLE>
<CAPTION>
Year ended December 31,
-----------------------------------------
1998 1997
------------- -------------
(Thousands, except per share amounts) (Unaudited)
<S> <C> <C>
Revenue $ 115,394 $ 139,584
Net Income Before Non-Cash Charge $ 19,098 $ 38,528
Net Income (Loss) $ (40,812) $ 38,528
Net Income (Loss) Per Share Amounts-
Basic $ (2.48) $ 2.34
Diluted $ (2.48) $ 2.04
</TABLE>
43
<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,
-----------------------------------------
1998 1997
------------------ ----------------
<S> <C> <C>
Oil and Gas Properties:
Proved $ 497,296,068 $ 326,836,431
Unproved (not being amortized)--Domestic 51,040,378 26,735,460
Unproved (not being amortized)--Foreign 5,001,508 15,104,349
------------------ ----------------
553,337,954 368,676,240
Accumulated Depreciation, Depletion, and
Amortization (196,626,243) (67,363,393)
------------------ ----------------
$ 356,711,711 $ 301,312,847
================== ================
</TABLE>
Of the $51,040,378 of domestic unproved property costs (primarily seismic
and lease acquisition costs) at December 31, 1998, excluded from the amortizable
base, $33,360,518 was incurred in 1998, $11,966,626 was incurred in 1997,
$3,260,112 was incurred in 1996, and $2,953,122 was incurred in prior years.
When the Company is in an active drilling mode, it has evaluated the majority of
these unproved costs within a two to three year time frame. In response to
current market conditions, the Company has decreased its planned 1999 drilling
expenditures when compared to recent years, which when coupled with the $15.2
million of leasehold properties acquired in the Toledo Bend Properties
acquisition may extend the evaluation timeframe of such costs.
Of the $5,001,508 of net foreign unproved property costs at December 31,
1998, being excluded from the amortizable base, $2,521,761 was incurred in 1998,
$1,731,561 was incurred in 1997, $545,980 was incurred in 1996, and $202,206 was
incurred in 1995. All of these costs are costs incurred in New Zealand, as the
costs incurred in Russia and Venezuela were impaired in the third quarter of
1998 (see Note 1 to the Company's financial statements). The Company expects it
will complete its evaluation of the New Zealand properties as wells are drilled
over the next two to three years.
44
<PAGE>
Capital Expenditures. The following table sets forth capital expenditures
related to the Company's oil and gas operations:
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------
1998 1997 1996
--------------- --------------- -------------
<S> <C> <C> <C>
Acquisition of proved properties $ 59,487,524 $ 8,417,318 $ 1,529,611
Lease acquisitions (1),(2) 38,658,047 21,603,732 16,426,327
Exploration 12,578,124 10,705,115 2,704,281
Development 54,821,131 82,885,549 69,067,024
--------------- --------------- -------------
Total acquisition, exploration, and development (3) $ 165,544,826 $ 123,611,714 $ 89,727,243
--------------- --------------- -------------
Processing plants $ 15,000,000 $ -- $ --
Field compression facilities 2,228,101 7,444,070 --
--------------- --------------- -------------
Total plants and facilities $ 17,228,101 $ 7,444,070 $ --
--------------- --------------- -------------
Total capital expenditures $ 182,772,927 $ 131,055,784 $ 89,727,243
=============== =============== =============
</TABLE>
(1)Lease acquisitions for 1998, 1997, and 1996 include expenditures of:
$2,521,761, $1,731,561, and $545,980, respectively, relating to the Company's
initiatives in New Zealand; $421,602, $828,133, and $487,597, respectively,
relating to initiatives in Venezuela; and $592,841, $658,145, and $2,712,278,
respectively, relating to initiatives in Russia.
(2)These are actual amounts as incurred by year, including both proved and
unproved lease costs. The annual lease acquisition amounts added to proved oil
and gas properties (being amortized) for 1998, 1997, and 1996, were $13,853,129,
$7,384,385, and $9,458,016, respectively.
(3)Includes capitalized general and administrative costs directly associated
with the acquisition, exploration, and development efforts of approximately
$12,300,000, $11,700,000, and $7,400,000 in 1998, 1997, and 1996, respectively.
In addition, total includes $3,849,665, $2,326,691, and $1,549,575 in 1998,
1997, and 1996, respectively, of capitalized interest on unproved properties.
Results of Operations. The following table sets forth results of the
Company's oil and gas operations:
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------
1998 1997 1996
-------------- --------------- ---------------
<S> <C> <C> <C>
Oil and gas sales $ 80,067,837 $ 69,015,189 $ 52,770,672
Oil and gas production costs (13,138,980) (8,778,876) (6,141,941)
Depreciation, depletion, and amortization (38,069,355) (23,443,273) (15,812,134)
Write-down of oil and gas properties (90,772,628) -- --
-------------- --------------- ---------------
(61,913,126) 36,793,040 30,816,597
Provision (benefit) for income taxes (21,236,202) 12,015,816 10,448,917
-------------- --------------- ---------------
Results of producing activities $ (40,676,924) $ 24,777,224 $ 20,367,680
============== =============== ===============
Amortization per physical unit of production
(equivalent Mcf of gas) $ 0.98 $ 0.92 $ 0.81
============== =============== ===============
</TABLE>
45
<PAGE>
Supplemental Reserve Information. The following information presents
estimates of the Company's proved oil and gas reserves, which are all located
onshore in the United States. All of the Company's reserves were determined by
the Company and audited by H. J. Gruy and Associates, Inc. ("Gruy"), independent
petroleum consultants. Gruy's summary report dated January 27, 1999, is set
forth as an exhibit to the Form 10-K Report for the year ended December 31,
1998, and includes definitions and assumptions that served as the basis for the
estimates of proved reserves and future net cash flows. Such definitions and
assumptions should be referred to in connection with the following information:
Estimates of Proved Reserves
<TABLE>
<CAPTION>
Oil and
Natural Gas Condensate
(Mcf) (Bbls)
------------ -----------
<S> <C> <C>
Proved reserves as of December 31, 1995 (1) 143,567,520 5,421,981
Revisions of previous estimates (2) (9,544,391) (816,065)
Purchases of minerals in place 2,676,393 97,178
Sales of minerals in place (4,163,770) (340,706)
Extensions, discoveries, and other additions 107,762,886 1,745,307
Production (3) (14,540,437) (623,386)
------------ -----------
Proved reserves as of December 31, 1996 (1) 225,758,201 5,484,309
Revisions of previous estimates (2) (22,774,899) (427,412)
Purchases of minerals in place 30,342,398 580,278
Sales of minerals in place (1,155,706) (50,909)
Extensions, discoveries, and other additions 102,479,883 2,945,037
Productionn (3) (20,344,208) (672,385)
------------ -----------
Proved reserves as of December 31, 1997 (1) 314,305,669 7,858,918
Revisions of previous estimates (2) (42,958,447) (2,291,223)
Purchases of minerals in place 54,189,901 7,237,298
Sales of minerals in place (1,727,878) (39,932)
Extensions, discoveries, and other additions 55,951,332 2,993,540
Production (3) (27,359,742) (1,800,676)
------------ -----------
Proved reserves as of December 31, 1998 (1) 352,400,835 13,957,925
============ ===========
Proved developed reserves,
December 31, 1995 81,532,025 3,313,226
December 31, 1996 135,424,880 3,622,480
December 31, 1997 191,108,214 4,288,696
December 31, 1998 197,105,963 7,142,566
</TABLE>
(1)Proved reserves exclude quantities subject to the Company's volumetric
production payment agreement.
(2)Revisions of previous estimates are related to upward or downward variations
based on current engineering information for production rates, volumetrics, and
reservoir pressure. Additionally, changes in quantity estimates are affected by
the increase or decrease in crude oil and natural gas prices at each year end.
Proved reserves, as of December 31, 1998, were based upon prices of $2.23 per
Mcf of natural gas and $11.23 per barrel of oil, compared to $2.78 per Mcf and
$15.76 per barrel as of December 31, 1997.
(3)Natural gas production for 1996, 1997, and 1998 excludes 1,156,361,
1,015,226, and 866,232 Mcf, respectively, delivered under the Company's
volumetric production payment agreement.
46
<PAGE>
Standardized Measure of Discounted Future Net Cash Flows. The standardized
measure of discounted future net cash flows relating to proved oil and gas
reserves is as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------------
1998 1997 1996
---------------- ---------------- -----------------
<S> <C> <C> <C>
Future gross revenues $ 972,852,038 $ 994,828,072 $ 1,141,831,786
Future production costs (294,307,549) (273,475,056) (228,626,881)
Future development costs (118,420,782) (92,946,811) (59,988,855)
---------------- ---------------- -----------------
Future net cash flows before income taxes 560,123,707 628,406,205 853,216,050
Future income taxes (123,875,660) (135,587,216) (211,375,632)
---------------- ---------------- -----------------
Future net cash flows after income taxes 436,248,047 492,818,989 641,840,418
Discount at 10% per annum (145,974,944) (199,980,649) (274,608,116)
---------------- ---------------- -----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 290,273,103 $ 292,838,340 $ 367,232,302
================ ================ =================
</TABLE>
The standardized measure of discounted future net cash flows from
production of proved reserves was developed as follows:
1. Estimates are made of quantities of proved reserves and the future
periods during which they are expected to be produced based on year-end economic
conditions.
2. The estimated future gross revenues of proved reserves are priced on the
basis of year-end prices, except in those instances where fixed and determinable
gas price escalations are covered by contracts limited to the price the Company
reasonably expects to receive.
3. The future gross revenue streams are reduced by estimated future costs
to develop and to produce the proved reserves, as well as certain abandonment
costs based on year-end cost estimates and the estimated effect of future income
taxes.
4. Future income taxes are computed by applying the statutory tax rate to
future net cash flows reduced by the tax basis of the properties, the estimated
permanent differences applicable to future oil and gas producing activities, and
tax carry forwards.
The estimates of cash flows and reserves quantities shown above are based
on year-end oil and gas prices for each period. Under Securities and Exchange
Commission rules, companies that follow the full-cost accounting method are
required to make quarterly Ceiling Test calculations, using prices in effect as
of the period end date presented (see Note 1). Application of these rules during
periods of relatively low oil and gas prices, even if of short-term seasonal
duration, may result in write-downs.
The standardized measure of discounted future net cash flows is not
intended to present the fair market value of the Company's oil and gas property
reserves. An estimate of fair value would also take into account, among other
things, the recovery of reserves in excess of proved reserves, anticipated
future changes in prices and costs, an allowance for return on investment, and
the risks inherent in reserve estimates.
47
<PAGE>
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------
1998 1997 1996
----------------- ----------------- ---------------
<S> <C> <C> <C>
Beginning balance $ 292,838,340 $ 367,232,302 $ 128,904,084
----------------- ----------------- ---------------
Revisions to reserves proved in prior years--
Net changes in prices, production costs, and future
development costs (107,301,930) (237,149,170) 145,661,994
Net changes due to revisions in quantity
estimates (47,924,995) (27,188,512) (25,755,091)
Accretion of discount 35,034,478 47,068,172 14,703,841
Other (34,966,058) (37,336,420) 7,609,227
----------------- ----------------- ---------------
Total revisions (155,158,505) (254,605,930) 142,219,971
New field discoveries and extensions, net of future
production and development costs 73,956,430 110,396,029 208,250,909
Purchases of minerals in place 87,628,829 29,290,334 6,835,362
Sales of minerals in place (1,928,900) (2,373,547) (8,084,581)
Sales of oil and gas produced, net of production
costs (65,680,050) (58,786,505) (44,958,559)
Previously estimated development costs incurred 51,622,419 55,742,684 19,883,446
Net change in income taxes 6,994,540 45,942,973 (85,818,330)
----------------- ----------------- ---------------
Net change in standardized measure of discounted
future net cash flows (2,565,237) (74,393,962) 238,328,218
----------------- ----------------- ---------------
Ending balance $ 290,273,103 $ 292,838,340 $ 367,232,302
================= ================= ===============
</TABLE>
Quarterly Results. The following table presents summarized quarterly
financial information for the years ended December 31, 1997 and 1998:
<TABLE>
<CAPTION>
Income (Loss) Basic Earnings Diluted Earnings
Before Income Net Income (Loss) (Loss)
Revenues Taxes (Loss) Per Share(1) Per Share(1)
--------------- ---------------- ---------------- ------------ ----------------
<S> <C> <C> <C> <C> <C>
1997
First Quarter $ 19,997,502 $ 10,161,045 $ 6,769,263 $ .41 $ .37
Second Quarter 15,653,078 6,007,474 4,113,689 .25 .24
Third Quarter 17,895,979 7,024,524 4,685,689 .29 .27
Fourth Quarter 21,165,621 9,936,563 6,741,548 .41 .37
--------------- ---------------- -----------------
Total $ 74,712,180 $ 33,129,606 $ 22,310,189 $ 1.35 $ 1.26
=============== ================ ================
1998
First Quarter $ 16,475,229 $ 4,835,502 $ 3,229,615 $ .20 $ .20
Second Quarter 16,340,730 4,270,153 2,896,470 .18 .18
Third Quarter(2) 24,557,553 (87,052,299) (57,431,015) (3.50) (3.50)
Fourth Quarter 25,095,709 4,555,063 3,079,726 .19 .19
--------------- ---------------- ----------------
Total $ 82,469,221 $ (73,391,581) $ (48,225,204) $ (2.93) $ (2.93)
=============== ================ ================
</TABLE>
(1)Amounts prior to the fourth quarter of 1997 have been retroactively restated
to give recognition to: (a) an equivalent change in capital structure as a
result of a 10% stock dividend in October 1997 (see Note 2 to the Company's
financial statements); and (b) the adoption of Statement of Financial Accounting
Standards No. 128, "Earnings per Share." See Note 2 to the Company's financial
statements.
(2)The loss in the third quarter of 1998 was the result of a pre-tax write-down
of oil and gas properties of $90.8 million ($59.9 million after tax). See Note 1
to the Company's financial statements.
48
<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 11, 1999, annual shareholders' meeting is incorporated herein by reference.
Item 11. Executive Compensation
The information appearing under the caption "Executive 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 11, 1999, 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 11, 1999, annual shareholders'
meeting is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions
The information appearing under the caption "Certain Relationships and
Related Transactions" 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 11, 1999, annual shareholders' meeting is incorporated herein by reference.
49
<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,
1999, and the data contained therein are included in Item 8 hereof:
<TABLE>
<CAPTION>
<S> <C>
Report of Independent Public Accountants................................................27
Consolidated Balance Sheets.............................................................28
Consolidated Statements of Income.......................................................29
Consolidated Statements of Stockholders' Equity.........................................30
Consolidated Statements of Cash Flows...................................................31
Notes to Consolidated Financial Statements..............................................32
</TABLE>
2. Financial Statement Schedules
None
3. Exhibits
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(a)(8) Indenture dated as of November 25, 1996, between Swift
Energy Company and Bank One, Columbus, N.A. 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) + Swift Energy Company 1990 Nonqualified Stock Option
Plan.
10.3 (12) Credit Agreement among Swift Energy Company and Bank
One, Texas, National Association as administrative
agent, Bank of Montreal as syndication agent, and
Nationsbank, N.A. as documentation agent and the
lenders signatory hereto dated August 18, 1998.
10.4* First and Second Amendments to Credit Agreement among
Swift Energy Company and Bank One, Texas, National
Association as administrative agent, Bank of Montreal
as syndication agent, and Nationsbank, N.A. as
documentation agent and the lenders signatory hereto
dated September 30, 1998, and December 31, 1998.
10.5 (13) + Amended and Restated Swift Energy Company 1990 Stock
Compensation Plan, as of May 1997.
50
<PAGE>
10.6 (3) + Employment Agreement dated as of November 1, 1995, by
and between Swift Energy Company and Terry E. Swift.
10.7 (3) + Employment Agreement dated as of November 1, 1995, by
and between Swift Energy Company and John R. Alden.
10.8 (3) + Employment Agreement dated as of November 1, 1995, by
and between Swift Energy Company and James M.
Kitterman.
10.9 (3) + Employment Agreement dated as of November 1, 1995, by
and between Swift Energy Company and Bruce H. Vincent.
10.10 (3) + Employment Agreement dated as of November 1, 1995, by
and between Swift Energy Company and A. Earl Swift.
10.11 (6) + Agreement and Release between Swift Energy Company and
Virgil Neil Swift effective June 1, 1994.
10.12 (7) + First Amendment to Agreement and Release dated as of
12/1/95, by and between Swift Energy Company and Virgil
Neil Swift.
10.13 (7) + 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.
10.14 (7) + 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.
10.15 (10) Employment Agreement dated as of February 1, 1998, by
and between Swift Energy Company and Joseph A. D'Amico.
10.16 (9) Rights Agreement dated as of August 1, 1997, between
Swift Energy Company and American Stock Transfer &
Trust Company.
10.17 (11) Purchase and Sale Agreement dated as of June 1, 1998,
between Swift Energy Company and Sonat Inc.
10.18* Amendment to Employment Agreement dated as of November
1, 1995, by and between Swift Energy Company and A.
Earl Swift.
18 (5) Letter from Arthur Andersen LLP dated February 17,
1995, regarding change in accounting principle.
21 (6) List of Subsidiaries of Swift Energy Company.
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 Registration
Statements.
27 Financial Data Schedule (included in electronic filing
only).
99* The summary of H. J. Gruy and Associates, Inc. report,
dated January 27, 1999.
51
<PAGE>
(b) During the fourth quarter of 1998 the Company filed a report on Form
8-K, dated November 25, 1998, pertaining to the Company's filing of a
Registration Statement on Form S-4 (Registration No. 333-50637) relating
to the Company's then pending proposal to purchase substantially all of
the assets of 63 partnerships of which the Company is the Managing General
Partner. The Form 8-K included unaudited financial statements for the
quarter ended September 30, 1998, for 24 of the 63 partnerships which are
not required to file reports pursuant to Section 13 or 15(d) of the
Securities and Exchange Act of 1934, as amended, so that if such financial
statements were sent to investors in the partnerships in connection with
proposals which were to be made to them, such financials would be publicly
available.
(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. 33-36310 on Form
S-8 filed on August 10, 1990.
(5)Incorporated by reference from Swift Energy Company Annual Report on Form
10-K for the fiscal year ended December 31, 1994.
(6)Incorporated by reference from Registration Statement No. 33-60469 on Form
S-2 filed on June 22, 1995.
(7)Incorporated by reference from Swift Energy Company Annual Report on Form
10-K from the fiscal year ended December 31, 1996.
(8)Incorporated by reference from Registration Statement No. 33-14785 on Form
S-3 filed on October 24, 1996.
(9)Incorporated by reference from Swift Energy Company Report on Form 8-K dated
August 1, 1997.
(10)Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q filed for the quarterly period ended June 30, 1998.
(11)Incorporated by reference from Swift Energy Company Report on Form 8-K dated
July 2, 1998.
(12)Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q filed for the quarterly period ended September 30, 1998.
(13)Incorporated by reference from Swift Energy Company definitive proxy
statement for annual shareholders meeting filed April 14, 1997.
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
52
<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, 1999
A. Earl Swift
/S/ John R. Alden Senior Vice President--Finance
- -------------------------------- Principal Financial Officer March 24, 1999
John R. Alden
/S/ Alton D. Heckaman, Jr. Vice President & Controller
- -------------------------------- Principal Accounting Officer March 24, 1999
Alton D. Heckaman, Jr.
/S/ Virgil N. Swift
- -------------------------------- Director March 24, 1999
Virgil N. Swift
/S/ G. Robert Evans
- -------------------------------- Director March 24, 1999
G. Robert Evans
</TABLE>
53
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C>
/S/ Raymond O. Loen
- -------------------------------- Director March 24, 1999
Raymond O. Loen
/S/ Henry C. Montgomery
- -------------------------------- Director March 24, 1999
Henry C. Montgomery
/S/ Clyde W. Smith, Jr.
- -------------------------------- Director March 24, 1999
Clyde W. Smith, Jr.
/S/ Harold J. Withrow
- -------------------------------- Director March 24, 1999
Harold J. Withrow
</TABLE>
54
<PAGE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
EXHIBITS
TO
FORM 10-K REPORT
FOR THE
YEAR ENDED DECEMBER 31, 1998
SWIFT ENERGY COMPANY
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060
55
<PAGE>
EXHIBITS
10.4 First and Second Amendments to Credit Agreement among Swift Energy
Company and Bank One, Texas, National Association as administrative
agent, Bank of Montreal as syndication agent, and Nationsbank, N.A. as
documentation agent and the lenders signatory hereto dated September
30, 1998, and December 31, 1998.
10.18 Amendment to Employment Agreement dated as of November 1, 1995, by and
between Swift Energy Company and A. Earl Swift.
23(a) The consent of H.J. Gruy and Associates, Inc.
23(b) The consent of Arthur Andersen LLP as to incorporation by reference of
its report into Form S-8 Registration Statements.
99 The summary of H.J. Gruy and Associates, Inc. report, dated January 27,
1999.
56
<PAGE>
EXHIBIT 10.4
57
<PAGE>
FIRST AMENDMENT TO
CREDIT AGREEMENT
AMONG
SWIFT ENERGY COMPANY,
AS BORROWER,
BANK ONE, TEXAS, NATIONAL ASSOCIATION
AS ADMINISTRATIVE AGENT,
BANK OF MONTREAL
AS SYNDICATION AGENT, AND
NATIONSBANK, N.A.
AS DOCUMENTATION AGENT
AND
THE LENDERS SIGNATORY HERETO
Effective September 30, 1998
58
<PAGE>
<TABLE>
<CAPTION>
TABLE OF CONTENTS
-----------------
PAGE
<S> <C> <C>
ARTICLE I DEFINITIONS ............................................................................1
1.01 Terms Defined Above...............................................................1
1.02 Terms Defined in Agreement........................................................1
1.03 References........................................................................2
1.04 Articles and Sections.............................................................2
1.05 Number and Gender.................................................................2
ARTICLE II AMENDMENTS..............................................................................2
2.01 Amendment of Section 6.13.........................................................2
2.02 Amendment of Section 6.16.........................................................2
ARTICLE II CONDITIONS..............................................................................2
3.01 Receipt of Documents..............................................................2
3.02 Accuracy of Representations and Warranties........................................2
3.03 Matters Satisfactory to Lender....................................................2
ARTICLE IV REPRESENTATIONS AND WARRANTIES..........................................................3
ARTICLE V RATIFICATION............................................................................3
ARTICLE VI MISCELLANEOUS...........................................................................3
6.01 Scope of Amendment................................................................3
6.02 Agreement as Amended..............................................................3
6.03 Parties in Interest...............................................................3
6.04 Rights of Third Parties...........................................................3
6.05 ENTIRE AGREEMENT..................................................................3
6.06 GOVERNING LAW.....................................................................3
6.07 JURISDICTION AND VENUE............................................................4
</TABLE>
i
59
<PAGE>
FIRST AMENDMENT TO CREDIT AGREEMENT
-----------------------------------
This FIRST AMENDMENT TO CREDIT AGREEMENT (this "Amendment") is
made and entered into effective as of September 30, 1998, by and among SWIFT
ENERGY COMPANY, a Texas corporation (the "Borrower"), each lender that is a
signatory hereto or becomes a signatory hereto as provided in Section 9.1
(individually, together with its successors and assigns, a "Lender" and,
collectively, together with their respective successors and assigns, the
"Lenders"), and BANK ONE, TEXAS, NATIONAL ASSOCIATION, a national banking
association, as Administrative Agent for the Lenders (in such capacity, together
with its successors in such capacity pursuant to the terms hereof, the
"Administrative Agent"), BANK OF MONTREAL, a Canadian chartered bank as
Syndication Agent, and NATIONSBANK, N.A., a national banking association as
Documentation Agent.
W I T N E S S E T H:
- - - - - - - - - -
WHEREAS, the above named parties did execute and exchange
counterparts of that certain Credit Agreement dated August 18, 1998, (the
"Agreement"), to which reference is here made for all purposes;
WHEREAS, the parties subject to and bound by the Agreement are
desirous of amending the Agreement in the particulars hereinafter set forth;
NOW, THEREFORE, in consideration of the mutual covenants and
agreements of the parties to the Agreement, as set forth therein, and the mutual
covenants and agreements of the parties hereto, as set forth in this Amendment,
the parties hereto agree as follows:
ARTICLE I.
DEFINITIONS
-----------
1.01 Terms Defined Above. As used herein, each of the terms
"Agreement," "Borrower," "Amendment," and "Lender" shall have the meaning
assigned to such term hereinabove.
1.02 Terms Defined in Agreement. As used herein, each term
defined in the Agreement shall have the meaning assigned thereto in the
Agreement, unless expressly provided herein to the contrary.
1.03 References References in this Amendment to Article or
Section numbers shall be to Articles and Sections of this Amendment, unless
expressly stated herein to the contrary. References in this Amendment to
"hereby," "herein," "hereinafter," "hereinabove," "hereinbelow," "hereof," and
"hereunder" shall be to this Amendment in its entirety and not only to the
particular Article or Section in which such reference appears.
1.04 Articles and Sections. This Amendment, for convenience
only, has been divided into Articles and Sections and it is understood that the
rights, powers, privileges, duties, and other legal relations of the parties
hereto shall be determined from this Amendment as an entirety and without regard
to such division into Articles and Sections and without regard to headings
prefixed to such Articles and Sections.
1.05 Number and Gender Whenever the context requires,
reference herein made to the single number shall be understood to include the
plural and likewise the plural shall be understood to include the singular.
Words denoting sex shall be construed to include the masculine, feminine, and
neuter, when such construction is appropriate, and specific enumeration shall
not exclude the general, but shall be construed as cumulative. Definitions of
terms defined in the singular and plural shall be equally applicable to the
plural or singular, as the case may be.
1
60
<PAGE>
ARTICLE II.
AMENDMENTS
----------
The Borrower and the Lender hereby amend the Agreement in the
following particulars:
2.01 Amendment of Section 6.13 Section 6.13 of the Agreement
is hereby amended to read as follows:
"6.13 Tangible Net Worth. Permit Tangible Net Worth
as of the close of any fiscal quarter to be less
than $86,589,159 plus 75% of positive Net Income and
100% of net proceeds from any equity offering for
all fiscal periods ending subsequent to September
30, 1998."
2.02 Amendment of Section 6.16 Section 6.16 of the Agreement
is hereby amended to read as follows:
"6.16 Total Liabilities to Tangible Net Worth.
Permit the ratio of total liabilities of the
Borrower and its Subsidiaries on a consolidated
basis to Tangible Net Worth to be at any time
greater than 3.5 to 1.0 from September 30, 1998
through June 30, 1999, 3.0 to 1.0 from September 30,
1999 through June 30, 2000, 2.75 to 1.0 from
September 30, 2000 through June 30, 2001, and 2.5 to
1.0 from September 30, 2001 to Final Maturity."
ARTICLE III.
CONDITIONS
------------
The obligation of the Lender to amend the Agreement as
provided herein is subject to the fulfillment of the following conditions
precedent:
3.01 Receipt of Documents. The Lender shall have received,
reviewed, and approved the following documents and other items, appropriately
executed when necessary and in form and substance satisfactory to the Lender:
(a) multiple counterparts of this Amendment, as
requested by the Lender;
(b) Notice of Final Agreement; and
(c) such other agreements, documents, items,
instruments, opinions, certificates, waivers,
consents, and evidence as the Lender may reasonably
request.
3.02 Accuracy of Representations and Warranties. The
representations and warranties contained in Article IV of the Agreement and this
Amendment shall be true and correct.
3.03 Matters Satisfactory to Lender. All matters incident to
the consummation of the transactions contemplated hereby shall be satisfactory
to the Lender.
2
61
<PAGE>
ARTICLE IV.
REPRESENTATIONS AND WARRANTIES
------------------------------
The Borrower hereby expressly re-makes, in favor of the
Lender, all of the representations and warranties set forth in Article IV of the
Agreement, and represents and warrants that all such representations and
warranties remain true and unbreached.
ARTICLE V.
RATIFICATION
------------
Each of the parties hereto does hereby adopt, ratify, and
confirm the Agreement and the other Loan Documents, in all things in accordance
with the terms and provisions thereof, as amended by this Amendment.
ARTICLE VI.
MISCELLANEOUS
-------------
6.01 Scope of Amendment The scope of this Amendment is
expressly limited to the matters addressed herein and this Amendment shall not
operate as a waiver of any past, present, or future breach, Default, or Event of
Default under the Agreement, except to the extent, if any, that any such breach,
Default, or Event of Default is remedied by the effect of this Amendment.
6.02 Agreement as Amended. All references to the Agreement in
any document heretofore or hereafter executed in connection with the
transactions contemplated in the Agreement shall be deemed to refer to the
Agreement as amended by this Amendment.
6.03 Parties in Interest All provisions of this Amendment
shall be binding upon and shall inure to the benefit of the Borrower, the Lender
and their respective successors and assigns.
6.04 Rights of Third Parties All provisions herein are imposed
solely and exclusively for the benefit of the Lender and the Borrower, and no
other Person shall have standing to require satisfaction of such provisions in
accordance with their terms and any or all of such provisions may be freely
waived in whole or in part by the Lender at any time if in its sole discretion
it deems it advisable to do so.
6.05 ENTIRE AGREEMENT. THIS AMENDMENT CONSTITUTES THE ENTIRE
AGREEMENT BETWEEN THE PARTIES HERETO WITH RESPECT TO THE SUBJECT HEREOF AND
SUPERSEDES ANY PRIOR AGREEMENT, WHETHER WRITTEN OR ORAL, BETWEEN SUCH PARTIES
REGARDING THE SUBJECT HEREOF. FURTHERMORE IN THIS REGARD, THIS AMENDMENT, THE
AGREEMENT, THE NOTE, THE SECURITY INSTRUMENTS, AND THE OTHER WRITTEN DOCUMENTS
REFERRED TO IN THE AGREEMENT OR EXECUTED IN CONNECTION WITH OR AS SECURITY FOR
THE NOTE REPRESENT, COLLECTIVELY, THE FINAL AGREEMENT AMONG THE PARTIES THERETO
AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT
ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE
PARTIES.
6.06 GOVERNING LAW. THIS AMENDMENT, THE AGREEMENT AND THE NOTE
SHALL BE DEEMED TO BE CONTRACTS MADE UNDER AND SHALL BE CONSTRUED IN ACCORDANCE
WITH AND GOVERNED BY THE LAWS OF THE STATE OF TEXAS. THE PARTIES ACKNOWLEDGE AND
AGREE THAT THIS AGREEMENT AND THE NOTE AND THE TRANSACTIONS
3
62
<PAGE>
CONTEMPLATED HEREBY BEAR A NORMAL, REASONABLE, AND SUBSTANTIAL RELATIONSHIP TO
THE STATE OF TEXAS.
6.07 JURISDICTION AND VENUE. ALL ACTIONS OR PROCEEDINGS WITH
RESPECT TO, ARISING DIRECTLY OR INDIRECTLY IN CONNECTION WITH, OUT OF, RELATED
TO, OR FROM THIS AMENDMENT, THE AGREEMENT OR ANY OTHER LOAN DOCUMENT MAY BE
LITIGATED IN COURTS HAVING SITUS IN HARRIS COUNTY, TEXAS. EACH OF THE BORROWER
AND THE LENDER HEREBY SUBMITS TO THE JURISDICTION OF ANY LOCAL, STATE, OR
FEDERAL COURT LOCATED IN HARRIS COUNTY, TEXAS, AND HEREBY WAIVES ANY RIGHTS IT
MAY HAVE TO TRANSFER OR CHANGE THE JURISDICTION OR VENUE OF ANY LITIGATION
BROUGHT AGAINST IT BY THE BORROWER OR THE LENDER IN ACCORDANCE WITH THIS
SECTION.
4
63
<PAGE>
IN WITNESS WHEREOF, this Amendment to Credit Agreement is
executed effective the date first hereinabove written.
BORROWER:
SWIFT ENERGY COMPANY
By:
--------------------------------
John R. Alden
Senior Vice President
Address for Notices:
Swift Energy Corporation
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Attention: John R. Alden
Telecopy: (281) 874-2701
5
64
<PAGE>
ADMINISTRATIVE AGENT AND LENDER:
BANK ONE, TEXAS, NATIONAL
ASSOCIATION
By:
-----------------------------
David W. Phillips
Vice President
Applicable Lending Office
for Floating Rate Loans and
LIBO Rate Loans:
910 Travis
Houston, Texas 77002
Address for Notices:
Bank One, Texas, National Association
910 Travis
Houston, Texas 77002
Attention: Steve Shatto
Telecopy: (713) 751-3544
6
65
<PAGE>
SECOND AMENDMENT TO
CREDIT AGREEMENT
AMONG
SWIFT ENERGY COMPANY,
AS BORROWER,
BANK ONE, TEXAS, NATIONAL ASSOCIATION
AS ADMINISTRATIVE AGENT,
BANK OF MONTREAL
AS SYNDICATION AGENT, AND
NATIONSBANK, N.A.
AS DOCUMENTATION AGENT
AND
THE LENDERS SIGNATORY HERETO
Effective December 31, 1998
66
<PAGE>
<TABLE>
<CAPTION>
TABLE OF CONTENTS
PAGE
<S> <C> <C>
ARTICLE I DEFINITIONS............................................................................1
1.01 Terms Defined Above..............................................................1
1.02 Terms Defined in Agreement.......................................................1
1.03 References.......................................................................1
1.04 Articles and Sections............................................................1
1.05 Number and Gender................................................................1
ARTICLE II AMENDMENTS.............................................................................2
2.01 Amendment of Section 1.2.........................................................2
2.0 Amendment of Section 6.15........................................................2
ARTICLE III CONDITIONS.............................................................................3
3.01 Receipt of Documents.............................................................3
3.02 Accuracy of Representations and Warranties.......................................3
3.03 Matters Satisfactory to Lender...................................................3
ARTICLE IV REPRESENTATIONS AND WARRANTIES.........................................................3
ARTICLE V RATIFICATION...........................................................................3
ARTICLE VI MISCELLANEOUS..........................................................................3
6.01 Scope of Amendment...............................................................3
6.02 Agreement as Amended.............................................................3
6.03 Parties in Interest..............................................................3
6.04 Rights of Third Parties..........................................................4
6.05 ENTIRE AGREEMENT.................................................................4
6.06 GOVERNING LAW....................................................................4
6.07 JURISDICTION AND VENUE...........................................................4
</TABLE>
i
67
<PAGE>
SECOND AMENDMENT TO CREDIT AGREEMENT
------------------------------------
This SECOND AMENDMENT TO CREDIT AGREEMENT (this "Amendment")
is made and entered into effective as of December 31, 1998, by and among SWIFT
ENERGY COMPANY, a Texas corporation (the "Borrower"), each lender that is a
signatory hereto or becomes a signatory hereto as provided in Section 9.1
(individually, together with its successors and assigns, a "Lender" and,
collectively, together with their respective successors and assigns, the
"Lenders"), and BANK ONE, TEXAS, NATIONAL ASSOCIATION, a national banking
association, as Administrative Agent for the Lenders (in such capacity, together
with its successors in such capacity pursuant to the terms hereof, the
"Administrative Agent"), BANK OF MONTREAL, a Canadian chartered bank as
Syndication Agent, and NATIONSBANK, N.A., a national banking association as
Documentation Agent.
W I T N E S S E T H:
- - - - - - - - - -
WHEREAS, the above named parties did execute and exchange
counterparts of that certain Credit Agreement dated August 18, 1998, as amended
by First Amendment to Credit Agreement dated September 30, 1998, (the
"Agreement"), to which reference is here made for all purposes;
WHEREAS, the parties subject to and bound by the Agreement are
desirous of amending the Agreement in the particulars hereinafter set forth;
NOW, THEREFORE, in consideration of the mutual covenants and
agreements of the parties to the Agreement, as set forth therein, and the mutual
covenants and agreements of the parties hereto, as set forth in this Amendment,
the parties hereto agree as follows:
ARTICLE I.
DEFINITIONS
-----------
1.01 Terms Defined Above. As used herein, each of the terms
"Agreement," "Borrower," "Amendment," and "Lender" shall have the meaning
assigned to such term hereinabove.
1.02 Terms Defined in Agreement. As used herein, each term
defined in the Agreement shall have the meaning assigned thereto in the
Agreement, unless expressly provided herein to the contrary.
1.03 References. References in this Amendment to Article or
Section numbers shall be to Articles and Sections of this Amendment, unless
expressly stated herein to the contrary. References in this Amendment to
"hereby," "herein," "hereinafter," "hereinabove," "hereinbelow," "hereof," and
"hereunder" shall be to this Amendment in its entirety and not only to the
particular Article or Section in which such reference appears.
1.04 Articles and Sections. This Amendment, for convenience
only, has been divided into Articles and Sections and it is understood that the
rights, powers, privileges, duties, and other legal relations of the parties
hereto shall be determined from this Amendment as an entirety and without regard
to such division into Articles and Sections and without regard to headings
prefixed to such Articles and Sections.
1.05 Number and Gender. Whenever the context requires,
reference herein made to the single number shall be understood to include the
plural and likewise the plural shall be understood to include the singular.
Words denoting sex shall be construed to include the masculine, feminine, and
neuter, when such construction is appropriate, and specific enumeration shall
not exclude the general, but shall be construed as cumulative. Definitions of
terms defined in the singular and plural shall be equally applicable to the
plural or singular, as the case may be.
1
68
<PAGE>
ARTICLE II.
AMENDMENTS
----------
The Borrower and the Lender hereby amend the Agreement in the
following particulars:
2.01 Amendment of Section 1.2 Section 1.2 of the Agreement is
hereby amended in part to read as follows:
The following definitions are amended to read as follows:
"Applicable Margin" shall mean at any time for LIBO Rate Loans
and Floating Rate Loans an incremental rate of interest shall be
determined by the ratio of (i) the sum of the Loan Balance and L/C
Exposure to (ii) the last calculated Borrowing Base as set out below in
basis points:
<TABLE>
<CAPTION>
Floating LIBO
Ratio Rate Margin Margin
----- ----------- ------
<S> <C> <C>
less than 50% 0.00 bps 112.50 bps
equal to or greater than 50% but 0.00 bps 137.50 bps
less than 75%
equal to or greater than 75% but 0.00 bps 162.50 bps
less than 90%
equal to or greater than 90% 0.00 bps 175.00 bps
</TABLE>
"Debt Service" shall mean, at any time, four percent
of the aggregate amount of all Subordinated Debt,
Senior Subordinated Debt, amounts funded under this
Agreement, and any other funded debt of the Borrower
and its Subsidiaries on a consolidated basis allowed
by the Lenders."
2.02 Amendment of Section 6.15. Section 6.15 of the Agreement
is hereby amended to read as follows:
"6.15.Debt Coverage Ratio. Permit the ratio for any
fiscal quarter of Cash Flow to Debt Service to be
less than 1.00 to 1.00 at December 31, 1998, March
31, 1999, and June 30, 1999; 1.05 to 1.00 at
September 30, 1999; 1.10 to 1.00 at December 31,
1999; 1.15 to 1.00 at March 31, 2000; and 1.20 to
1.00 at June 30, 2000, and thereafter."
2
69
<PAGE>
ARTICLE III.
CONDITIONS
------------
The obligation of the Lender to amend the Agreement as
provided herein is subject to the fulfillment of the following conditions
precedent:
3.01 Receipt of Documents. The Lender shall have received,
reviewed, and approved the following documents and other items, appropriately
executed when necessary and in form and substance satisfactory to the Lender:
(a) multiple counterparts of this Amendment, as
requested by the Lender;
(b) Notice of Final Agreement; and
(c) such other agreements, documents, items,
instruments, opinions, certificates, waivers,
consents, and evidence as the Lender may reasonably
request.
3.02 Accuracy of Representations and Warranties. The
representations and warranties contained in Article IV of the Agreement and this
Amendment shall be true and correct.
3.03 Matters Satisfactory to Lender. All matters incident to
the consummation of the transactions contemplated hereby shall be satisfactory
to the Lender.
ARTICLE IV.
REPRESENTATIONS AND WARRANTIES
------------------------------
The Borrower hereby expressly re-makes, in favor of the
Lender, all of the representations and warranties set forth in Article IV of the
Agreement, and represents and warrants that all such representations and
warranties remain true and unbreached.
ARTICLE V.
RATIFICATION
------------
Each of the parties hereto does hereby adopt, ratify, and
confirm the Agreement and the other Loan Documents, in all things in accordance
with the terms and provisions thereof, as amended by this Amendment.
ARTICLE VI.
MISCELLANEOUS
-------------
6.01 Scope of Amendment. The scope of this Amendment is
expressly limited to the matters addressed herein and this Amendment shall not
operate as a waiver of any past, present, or future breach, Default, or Event of
Default under the Agreement, except to the extent, if any, that any such breach,
Default, or Event of Default is remedied by the effect of this Amendment.
6.02 Agreement as Amended. All references to the Agreement in
any document heretofore or hereafter executed in connection with the
transactions contemplated in the Agreement shall be deemed to refer to the
Agreement as amended by this Amendment.
6.03 Parties in Interest. All provisions of this Amendment
shall be binding upon and shall inure to the benefit of the Borrower, the Lender
and their respective successors and assigns.
3
70
<PAGE>
6.04 Rights of Third Parties. All provisions herein are
imposed solely and exclusively for the benefit of the Lender and the Borrower,
and no other Person shall have standing to require satisfaction of such
provisions in accordance with their terms and any or all of such provisions may
be freely waived in whole or in part by the Lender at any time if in its sole
discretion it deems it advisable to do so.
6.05 ENTIRE AGREEMENT. THIS AMENDMENT CONSTITUTES THE ENTIRE
AGREEMENT BETWEEN THE PARTIES HERETO WITH RESPECT TO THE SUBJECT HEREOF AND
SUPERSEDES ANY PRIOR AGREEMENT, WHETHER WRITTEN OR ORAL, BETWEEN SUCH PARTIES
REGARDING THE SUBJECT HEREOF. FURTHERMORE IN THIS REGARD, THIS AMENDMENT, THE
AGREEMENT, THE NOTE, THE SECURITY INSTRUMENTS, AND THE OTHER WRITTEN DOCUMENTS
REFERRED TO IN THE AGREEMENT OR EXECUTED IN CONNECTION WITH OR AS SECURITY FOR
THE NOTE REPRESENT, COLLECTIVELY, THE FINAL AGREEMENT AMONG THE PARTIES THERETO
AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT
ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE
PARTIES.
6.06 GOVERNING LAW. THIS AMENDMENT, THE AGREEMENT AND THE NOTE
SHALL BE DEEMED TO BE CONTRACTS MADE UNDER AND SHALL BE CONSTRUED IN ACCORDANCE
WITH AND GOVERNED BY THE LAWS OF THE STATE OF TEXAS. THE PARTIES ACKNOWLEDGE AND
AGREE THAT THIS AGREEMENT AND THE NOTE AND THE TRANSACTIONS CONTEMPLATED HEREBY
BEAR A NORMAL, REASONABLE, AND SUBSTANTIAL RELATIONSHIP TO THE STATE OF TEXAS.
6.07 JURISDICTION AND VENUE. ALL ACTIONS OR PROCEEDINGS WITH
RESPECT TO, ARISING DIRECTLY OR INDIRECTLY IN CONNECTION WITH, OUT OF, RELATED
TO, OR FROM THIS AMENDMENT, THE AGREEMENT OR ANY OTHER LOAN DOCUMENT MAY BE
LITIGATED IN COURTS HAVING SITUS IN HARRIS COUNTY, TEXAS. EACH OF THE BORROWER
AND THE LENDER HEREBY SUBMITS TO THE JURISDICTION OF ANY LOCAL, STATE, OR
FEDERAL COURT LOCATED IN HARRIS COUNTY, TEXAS, AND HEREBY WAIVES ANY RIGHTS IT
MAY HAVE TO TRANSFER OR CHANGE THE JURISDICTION OR VENUE OF ANY LITIGATION
BROUGHT AGAINST IT BY THE BORROWER OR THE LENDER IN ACCORDANCE WITH THIS
SECTION.
4
71
<PAGE>
IN WITNESS WHEREOF, this Amendment to Credit Agreement is
executed effective the date first hereinabove written.
BORROWER:
SWIFT ENERGY COMPANY
By:
-----------------------------
John R. Alden
Senior Vice President
Address for Notices:
Swift Energy Corporation
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Attention: John R. Alden
Telecopy: (281) 874-2701
5
72
<PAGE>
ADMINISTRATIVE AGENT AND LENDER:
BANK ONE, TEXAS, NATIONAL
ASSOCIATION
By:
-----------------------------
Jeff Dalton
Vice President
Applicable Lending Office
for Floating Rate Loans and
LIBO Rate Loans:
910 Travis
Houston, Texas 77002
Address for Notices:
Bank One, Texas, National Association
910 Travis
Houston, Texas 77002
Attention: Charles Kingswell-Smith
Telecopy: (713) 751-3544
6
73
<PAGE>
EXHIBIT 10.18
74
<PAGE>
AMENDMENT TO
EMPLOYMENT AGREEMENT
Dated as of
November 1, 1995
This document, dated February 15, 1999, by its terms, amends that
certain EMPLOYMENT AGREEMENT ("Agreement") dated as of November 1, 1995, by and
between Swift Energy Company, a Texas corporation (the "Company") and A. Earl
Swift ("Mr. Swift").
Section 1 - Employment and Term of Employment is hereby deleted in its
entirety and in its place is inserted the following:
1. Employment and Term of Employment. Subject to the terms and
conditions of this Agreement, the Company hereby agrees to
employ Mr. Swift and Mr. Swift hereby agrees to serve as
Chairman of the Board and Chief Executive Officer of the
Company, or in such other position as is mutually acceptable
to both Mr. Swift and the Company, for a period of up to ten
years (depending on the length of the "Initial Term" as
hereinafter defined) commencing on November 1, 1995, herein
referred to as the "Term of Employment". The "Initial Term" of
the Term of Employment shall commence on November 1, 1995, and
shall continue thereafter for a period of five years, unless
earlier terminated (i) by Mr. Swift, at his option, upon 180
days prior written notice of termination given to the Board of
Directors of the Company specifying the date of such
termination; or (ii) by the Board of Directors of the Company
by 180 days prior written notice given to Mr. Swift enclosing
a true copy of a formal, duly adopted resolution of the Board
of Directors of the Company specifying the date of such
termination. The
1
75
<PAGE>
"Subsequent Term" of the Term of Employment shall be a
five-year period commencing upon the date of
termination of the Initial Term.
Section 3 - Compensation at subsection 3(a). The word "annual" is
inserted in the seventh line after the word "total" and before the word
"compensation".
Section 3 - Compensation at subsection 3(b). The word "annual" is
inserted after the word "total" and before the word "compensation" in the eighth
line. In the last line the words "three years of the" are hereby deleted.
Section 3 - Compensation at subsection 3(c). In the last line the words
"shall be paid to Mr. Swift's estate" are hereby deleted and replaced by the
words "(or the entire amount) shall be paid to Mr. Swift's spouse, if living,
otherwise to his estate". Exhibit "A" to the original Agreement, dated November
1 1995, is hereby deleted in its entirety and Exhibit "A" attached hereto, is
substituted therefor and made a part hereof.
Section 4 - Additional Compensation and Benefits. At the beginning of
the second line the word "Employee's" is hereby deleted and replaced by the
words "Mr. Swift's".
Section 4 - Additional Compensation and Benefits. At line thirteen of
Section 4(b) the words "eight years" are hereby deleted.
Section 7 - Termination at Subsection 7(c). In the fifth line between
the words "Mr. Swift or" and the words "the estate of" the words "to Mr. Swift's
spouse, if living, or otherwise to" are inserted, the word "and" should be
deleted at the end of the tenth line, and at the end of
2
76
<PAGE>
Subsection 7(c) the words "and (iii) any remaining unpaid installments of the
Non-Competition Payment to be paid under the provisions of Section 3(c) hereof."
are inserted.
IN WITNESS WHEREOF, the parties hereto affix their signature hereunder
as of February 15, 1999.
SWIFT ENERGY COMPANY
By:
-----------------------------
Name:
---------------------------
Title:
--------------------------
A. EARL SWIFT
--------------------------------
Address:
------------------------
------------------------
------------------------
3
77
<PAGE>
EXHIBIT 23 (A)
78
<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, 1998, to our letter report dated January 27, 1999, 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 15, 1999
79
<PAGE>
EXHIBIT 23 (B)
80
<PAGE>
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report dated February 10, 1999, included in the annual report of Swift Energy
Company on Form 10-K for the year ended December 31, 1998, into Swift Energy
Company's previously filed Registration Statements File Numbers 33-14305,
33-36310, 33-80228, and 33-80240 on Form S-8.
ARTHUR ANDERSEN LLP
Houston, Texas
March 24, 1999
81
<PAGE>
EXHIBIT 99
82
<PAGE>
January 27, 1999
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Re: Year End 1998
Reserves Audit
98-003-140
Gentlemen:
At your request, we have audited the reserves and future net cash flow as of
December 31, 1998, prepared by Swift Energy Company (Swift) for certain
interests owned by Swift through partnerships in 13 drilling funds, 24 income
funds, 13 pension asset funds, and 30 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. Consequently, we agree in the
aggregate with the net reserves. The estimated net reserves, future net cash
flow, and discounted future net cash flow are summarized by reserve category as
follows:
<TABLE>
<CAPTION>
Estimated Estimated
Net Reserves Future Net Cash Flow
---------------------------------- ----------------------------------
Oil & Discounted
Condensate Gas at 10%
(Barrels) (Mcf) Nondiscounted Per Year
------------- ------------ --------------- ---------------
<S> <C> <C> <C> <C>
Proved Developed 7,142,566 197,105,963 $ 364,487,813 $ 243,124,194
Proved Undeveloped 6,815,359 155,294,872 $ 195,635,891 $ 97,660,811
------------- ------------ --------------- ---------------
Total Proved 13,957,925 352,400,835 $ 560,123,704 $ 340,785,005
G & A $ (5,053,001) $ (3,067,351)
------------- ------------ -------------- ---------------
TOTAL 13,957,925 352,400,835 $ 555,070,703 $ 337,717,654
</TABLE>
Attachment I summaries the reserves and cash flow of Swift by partnership and
the additional interests owned directly by Swift prior to the deduction of
general and accounting expenses.
The discounted future net cash flow 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 uncertainty.
1
83
<PAGE>
The estimated future net cash flow shown is that cash flow 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 state or 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 contained in the Securities
and Exchange Commission Regulation S-X, Rule 4-10(a). The definitions are
included in part as Attachment II.
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 1998 except in those instances in which data were
available through December. Interim production to December 31, 1998 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.
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.
2
84
<PAGE>
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, PE
Executive Vice President
JHH:akr
Attachment
3
85
<PAGE>
ATTACHMENT II
86
<PAGE>
DEFINITIONS OF PROVED OIL AND GAS RESERVES1
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 on 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 are 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 UNDEVELOPED 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)
5
87
<TABLE> <S> <C>
<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, 1998.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> Dec-31-1998
<PERIOD-END> Dec-31-1998
<CASH> 1,630,649
<SECURITIES> 0
<RECEIVABLES> 35,760,814
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 35,246,431
<PP&E> 560,436,259
<DEPRECIATION> (200,713,621)
<TOTAL-ASSETS> 403,645,267
<CURRENT-LIABILITIES> 31,415,054
<BONDS> 0
0
0
<COMMON> 169,725
<OTHER-SE> 109,192,914
<TOTAL-LIABILITY-AND-EQUITY> 403,645,267
<SALES> 80,067,837
<TOTAL-REVENUES> 82,469,221
<CGS> 0
<TOTAL-COSTS> 52,482,167<F1>
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 8,752,195
<INCOME-PRETAX> (73,391,581)
<INCOME-TAX> (25,166,377)
<INCOME-CONTINUING> (48,225,204)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (48,225,204)
<EPS-PRIMARY> (2.93)
<EPS-DILUTED> (2.93)
<FN>
<F1>INCLUDES DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE AND OIL AND GAS
PRODUCTION COSTS. EXCLUDES GENERAL AND ADMINISTRATIVE, INTEREST EXPENSE, AND
WRITE-DOWN OF OIL AND GAS PROPERTIES.
</FN>
</TABLE>
