<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
Annual Report Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995
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
(713) 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 $.O1 per share New York Stock Exchange
Pacific Stock Exchange
Convertible Subordinated Debentures Due 2003 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 13, 1996 was approximately $145,121,635.
The number of shares of common stock outstanding as of December 31, 1995 was
12,509,700 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 14,
1996
1
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Form 1O-K
- -------------------------------------------------------------------------------
Swift Energy Company and Subsidiaries
10-K PART AND ITEM NO. ANNUAL REPORT SECTION
- -------------------------------------------- ---------------------------
Part I
Item 1. Business
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Submission of Matters to a Vote of
Security Holders
Part II
Item 5. Market for the Registrant's Common
Equity and Related Stockholder
Matters
Item 6. Selected Financial Data
Item 7. Management's Discussion and
Analysis of Financial Condition
and Results of Operations
Item 8. Financial Statements and Supple-
mentary Data
Item 9. Changes in and Disagreements with
Accountants on Accounting and
Financial Disclosure
Part III
Item 10. Directors and Executive Officers of (1)
the Registrant
Item 11. Executive Compensation (1)
Item 12. Security Ownership of Certain Bene- (1)
ficial Owners and Management
Item 13. Certain Relationships and Related (1)
Transactions
Part IV
Item 14. Exhibits, Financial Statement
Schedules and Reports on Form 8-K
(1) Incorporated by reference from Notice and Proxy Statement for the Annual
Meeting of Shareholders to be held May 14, 1996.
2
<PAGE>
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
SEE PAGE 10 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 natural gas properties, with a primary focus on U.S.
onshore natural gas reserves. The Company has interests in approximately 4,1
00 oil and gas wells located in 15 states, with over 90% of its proved
reserves base concentrated in Texas, Oklahoma, and Louisiana. Between 1985
and 1993, the Company grew primarily through the acquisition of producing
properties funded through limited partnership financing. Commencing in 1991,
the Company began to re-emphasize the addition of reserves through increased
exploration and development drilling activity. As a result of this
reemphasis on drilling activity, the Company added approximately 24.8 Bcfe
and 72.4 Bcfe of proved reserves in 1994 and 1995, respectively, through
exploration and development drilling at a three-year average discovery cost
of $0.70 per Mcfe in 1994 and $0.47 in 1995.
At December 31, 1995, the Company had estimated proved reserves of 143.6
Bcf of natural gas and 5.4 MMBbls of oil (totaling approximately 176.1 Bcfe)
with a present value (PV-10 Value) of approximately $147 million. The
proved reserves at December 31, 1995, represent an increase of 70% over
estimated amounts at December 31, 1994. Approximately 82% of the Company's
proved reserve base at year-end 1995 was natural gas. The Company's reserve
replacement cost over the last three years averaged $0.61 per Mcfe.
At December 31, 1995, the Company operated approximately 770 wells,
which represented 86% of its proved reserve base, and managed reserves on
behalf of limited partnerships that, exclusive of the Company's interests,
had proved reserves of approximately 180.5 Bcfe. The Company's two largest
properties accounted for 73% of the Company's PV-10 Value at December 31,
1995. The South Texas AWP Olmos Field, located in McMullen County, Texas,
and the Austin Chalk Giddings Field, located primarily in Fayette County,
Texas, accounted for 67% and 6%, respectively, of the Company's PV-10 Value
as of such date. The Company believes that the Austin Chalk's prolific but
short-lived wells complement the long-lived reserves of the AWP Olmos Field.
The application of advanced technologies and achievement of operating
efficiencies have enabled the Company to reduce costs and enhance reserves
recoveries in these areas.
EXPLORATION AND DEVELOPMENT DRILLING ACTIVITIES
In 1991, the Company began to increase its inventory of exploration and
development drilling prospects. Drilling locations were selected through
intensive geological and geophysical studies of the Company's undeveloped
acreage and other prospects. The Company has recently begun to realize
benefits from its drilling program, with proved reserves added through
exploration and development drilling of approximately 13 times the amount
added through the acquisition of producing properties in 1995, and
approximately seven times that year's annual production. The Company's
success rate for 1995 drilling activity was 50% for exploratory wells (4 out
of 8 drilled) and 96% for development wells (65 out of 68 drilled).
The Company pursues a "controlled risk" approach to exploratory
drilling. The Company focuses its exploration activities on specific U.S.
regions where its technical staff has considerable experience and near proved
productive properties where the potential for significant reserves exists.
The Company seeks to minimize its exploration risk by investing in multiple
prospects, farming out interests to industry partners and drilling funds,
utilizing advanced technologies, and drilling in different types of
geological formations.
The Company's development strategy is designed to maximize the value and
productivity of its existing properties through development drilling and
recovery methods, enhancing production results through improved field
production techniques, lowering production costs, and applying the Company's
technical expertise and resources to exploit producing properties
efficiently. The Company employs various recovery techniques, which include
water flooding, fracturing reservoir rock through the injection of
high-pressure fluid, inserting coiled tubing velocity strings to speed gas
flow, and acid treatments. The Company believes that the application of
fracturing technology and coiled tubing has resulted in significant increases
in production and decreases in drilling and operating costs in several of its
fields, including the Company's largest single property, the AWP Olmos Field.
The Company's exploration and development activities are conducted by
its in-house exploration staff, assisted by professionals from other
departments, including reservoir engineers, geologists, geophysicists,
petrophysicists, landmen, and drilling and operations engineers. The Company
believes that one of the keys to its success has been its team approach,
which integrates multiple disciplines to maximize utilization of the
information provided by modern seismic techniques.
The Company has increasingly utilized advanced seismic technology to
enhance the quality of its drilling efforts, including two-dimensional (2-D)
and three-dimensional (3-D) seismic analysis, amplitude versus offset (AVO)
studies, and detailed formation simulation studies. Utilizing the Company's
computer workstations, seismic data are analyzed and enhanced with advanced
software programs, many of which are proprietary. As a result, the Company
has developed a significant internal seismic expertise and has compiled an
extensive library of seismic data.
3
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The following table sets forth the results of the Company's drilling
activities during the three fiscal years ended December 31, 1995:
<TABLE>
<CAPTION>
Gross Wells Net Wells(2)
----------------------------- -------------------------------
Year Type of Well(1) Total Producing(3) Dry(4) Total Producing(3) Dry(4)
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
1993 Exploratory 12 5 7 5.6 2.5 3.1
Development 22 21 1 3.8 3.4 .4
1994 Exploratory 14 6 8 9.2 4.7 4.5
Development 30 26 4 6.9 5.0 1.9
1995 Exploratory 8 4 4 3.5 1.5 2.0
Development 68 65 3 38.7 38.0 0.7
</TABLE>
(1) An exploratory well is a well drilled either in search of a new, as yet
undiscovered oil or gas reservoir or to greatly extend the known limits of a
previously discovered reservoir. A developmental well is a well drilled
within the presently proved productive area of an oil or gas reservoir, as
indicated by reasonable interpretation of available data, with the objective
of completing in that reservoir.
(2) Many of the development wells were drilled by company-managed
partnerships or joint ventures that own only a portion of the working interest
in each development well. The Company's share of the fractional interest in
these development wells exists primarily to the extent of its partnership
interest.
(3) A producing well is an exploratory or development well found to be
capable of producing either oil or gas in sufficient quantities to justify
completion as an oil or gas well.
(4) A dry well is an exploratory or development well that is not a producing
well.
At December 31, 1995, the Company had an inventory of development
drilling prospectus in two main fields and exploration prospectus in four
main geological basins:
SOUTH TEXAS AWP OLMOS FIELD. The Company has extensive expertise in
the AWP Olmos Field, where it drilled nine successful development wells on
its original AWP leaseholds in 1995. The Company has a long history of
experience with low-permeability tight-sand formations typical of its AWP
Olmos Field properties. Since acquiring its first AWP Olmos Field Acreage in
1988, the Company has made detailed studies of drainage patterns in the
formation and has introduced innovations in fracture design and
implementation methods and coiled tubing technology that substantially reduce
drilling costs and improve recoveries.
In the fourth quarter of 1994, the Company acquired a leasehold position
in 8,830 net acres in Two Rivers, immediately adjacent to its AWP leasehold
acquired in 1988. The Company subsequently extended its geological and
engineering studies to cover this acreage, and in 1995 drilled and completed
30 new wells. In 1995, the Company acquired an additional leasehold position
in 400 net acres (Encino Ranch) and in 1995 drilled two successful new wells
on this acreage. As a result of these efforts, Swift has identified numerous
proved undeveloped locations in the AWP Olmos Field, where it currently plans
to drill up to 76 development wells in 1996.
AUSTIN CHALK GIDDINGS FIELD. Wells in this area initially have high
deliverability rates, with strong cash flows that decline rapidly. The
Company believes these reserves complement its long-lived reserves in the AWP
Olmos Field. As of year-end 1995, the Company had participated in 24
horizontal wells in the Giddings Field with a 96% success rate, including
nine successful development wells in 1995. The Company believes its success
is attributable to its ability to identify hydrocarbon-bearing fractures,
relying on its expertise in seismic data analysis and its ability to drill
and operate horizontal wells. In 1994, the Company acquired a 2-D swath of
seismic data covering approximately 6,500 acres. In addition, the Company
acquired undeveloped leasehold interests to provide additional flexibility in
designing its development program. The Company currently plans to conduct a
second 2-D swath seismic survey in the area, and to drill an additional eight
development wells in the Austin Chalk in 1996.
GULF COAST BASIN. The Company's drilling program in the Gulf Coast
Basin in 1995 consisted of one successful exploratory well and four
successful development wells. The locations were selected utilizing
traditional geologic studies combined with analyses of available seismic
data. To reduce its exploration and development risk in the Gulf Coast
Basin, the Company conducted a 3-D seismic survey in Jackson County, Texas,
in 1994. The processing and interpretation has identified a number of
potential drilling locations which have been further refined through AVO
analysis. The Company owns interests in the South Louisiana East Mud Lake
and Second Bayou fields with significant proved undeveloped reserves. Up to
four exploratory wells and three development wells are scheduled for drilling
in the Gulf Coast Basin through 1996, principally focusing on the Yegua,
Frio, and Wilcox trends.
ANADARKO BASIN. The Company plans to continue exploration and
development activities in the Anadarko Basin in Oklahoma, principally
focusing on the Red Fork and Skinner formations. The Company participated in
five successful development wells in this area in 1995. The Company's
geologists and geophysicists search for the Red Fork formation's narrow
channel sands using interactive software to integrate geologic and seismic
data. By correlating the two sets of information, the presence of potential
hydrocarbon accumulations is determined and optimum drilling sites are
selected. For 1996, the Company plans to drill one exploratory well in this
area.
WYOMING POWDER RIVER BASIN. In 1995, the Company drilled two successful
exploratory wells and three suc-
4
<PAGE>
cessful development wells in the Minnelusa trend in Campbell County, Wyoming.
The Minnelusa trend has been the subject of extensive study by the Company's
multidisciplinary teams in order to identify the location of stratigraphic
hydrocarbon traps. The Company's staff has evaluated over 5,000 wells
drilled in the area, utilizing 2-D and 3-D seismic data, and has conducted
petrophysical studies to determine the hydrocarbon-bearing capacity of the
rock. To increase the production in some areas, the Company has instituted
secondary and tertiary recovery through water or polymer flooding in the
Minnelusa fields. The Company intends to drill four exploratory and two
development wells in this area in 1996.
NORTH LOUISIANA SALT DOME. The North Louisiana Salt Dome covers the
neighboring corners of Arkansas, Louisiana, and Texas. The Company has
drilled two successful exploratory wells in the area during 1993 and 1994 and
another successful exploratory well in 1995. In this area, the Smackover
formation is a prolific hydrocarbon producer from multiple levels and from a
variety of structures, including fault traps, salt anticlines, basement
structures, and stratigraphic traps. The Company currently has access to a
7,000-mile seismic data base in the area and completed a 3-D seismic survey
in the Smackover formation in early 1996. The Company plans to drill seven
exploratory wells and two development wells in the region in 1996 and is
currently evaluating the implementation of a water flood project in Arkansas.
ACQUISITION ACTIVITIES
Since 1979, the Company has acquired approximately $465.0 million of
producing oil and natural gas properties on behalf of itself and its
co-investors in 122 separate transactions. The Company has acquired for its
own account approximately $111.6 million of producing properties, with
original proved reserves estimated at 145.2 Bcfe. The Company's acquisition
activities have declined over the past three years, with approximately $21.8
million, $13.1 million and $3.5 million of properties acquired in 1993, 1994,
and 1995, respectively. The Company's acquisition costs have averaged $0.78
per Mcfe over this three-year period. For 1996 for its own account, the
Company anticipates spending only $0.5 million to purchase limited partner
interests from existing limited partnerships through the right of presentment
arrangement provided in those partnerships.
The Company uses a disciplined, market-driven approach to acquisitions.
The Company generally seeks acquisition of properties for its own account
that are in close proximity to its current reserves and provide the potential
to add reserves through additional development efforts. As the market for
acquisitions has become more competitive in recent years, the Company has
taken the initiative in creating acquisition opportunities by directly
soliciting property owners who have not placed their properties on the
market. Properties are acquired after the Company has analyzed and evaluated
available reservoir engineering, geological, and geophysical data. In
evaluating producing properties prior to purchase, the Company assesses many
factors, including estimated reserves, anticipated cash flow from production,
production costs, and various factors affecting the marketing of production.
PROPERTIES
The South Texas AWP Olmos Field and the Austin Chalk Giddings Field
accounted for a significant portion of the Company's proved oil and gas
reserves as of December 31, 1995.
SOUTH TEXAS AWP OLMOS FIELD. Swift's AWP leaseholds and its Two Rivers
and Encino Ranch leaseholds are contained entirely within the AWP Olmos Field
in McMullen County, Texas, and represented approximately 67% of the Company's
proved reserves at December 31, 1995. Interests are owned in 123 wells
producing from the Olmos Sand Formation at a depth of 10,000 feet, and the
Company is the operator of all 123 wells. Working interests owned by the
Company and its partnerships in this field range from 97% to 100%. During
1995, the Company drilled 41 successful development wells in this field.
During the period it has operated wells in this field, the Company has
engaged in extensive fracturing operations to enhance the permeability of the
formation and flow of gas from the wells. The introduction of coiled tubing
velocity strings in several wells speeds the velocity of gas flow, preventing
produced liquids from condensing, falling back into the well and blocking gas
flow. The Company has a substantial amount of undeveloped proved reserves in
this area with plans to drill 76 more development wells in 1996.
AUSTIN CHALK GIDDINGS FIELD. This property, located primarily in
Fayette County, Texas, and other adjacent counties, represents approximately
6% of Swift's proved reserves. As of year-end 1995, Swift had participated
in 24 horizontal wells in the Austin Chalk trend since 1992, with a 96%
drilling success rate. The Austin Chalk horizontal wells are initially
high-deliverability wells that provide strong cash flows, often reaching
payout in less than a year. In 1995, Swift participated in nine successful
development wells in the area. The Company plans to drill eight more
development wells in 1996.
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 the Company or
its affiliated limited partnerships and joint ventures own the major portion
of the working interest in a particular well or field. The Company acts as
operator of approximately 770 wells, which comprise approximately 86% of the
Company's total proved reserves.
As operator, the Company is able to exercise substantial influence over
development and enhancement of a well and to supervise operation and
maintenance activities on a day-to-day basis. The Company does not conduct
the actual drilling of wells on properties for which it acts as operator.
Drilling operations are conducted by independent contractors engaged and
supervised by the Company. The Company employs
5
<PAGE>
petroleum engineers, geologists, and other operations and production
specialists who strive to improve production rates, increase reserves, and/or
lower the cost of operating its oil and gas properties.
Oil and gas properties are customarily operated under the terms of a
joint operating agreement, which provides for reimbursement of the operator's
direct expenses and monthly per-well supervision fees. Per-well supervision
fees vary widely depending on the geographic location and producing formation
of the well whether the well produces oil or gas, and other factors. Such fees
received by the Company in 1995 ranged from $50 to $1,433 per well per month.
MARKETING OF PRODUCTION
The Company typically sells its gas production at or near the wellhead,
although in some cases it must be gathered by the Company or other operators
and delivered to a central point. Gas production is generally sold in the
spot market at prevailing prices. The Company generally sells its oil
production at posted prices. The Company does not refine any oil it
produces. Only one single oil or gas purchaser accounted for 10% or more of
the Company's consolidated revenues during the year ended December 31, 1995,
with that purchaser accounting for approximately 12%. The Company does not
believe that the loss of any single oil or gas purchaser or contract would
materially affect its sales.
The following table summarizes sales volume, sales price, and production
cost information for the Company's net oil and gas production for the
three-year period ended December 31, 1995. "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,
---------------------------------
1995 1994 1993
--------- --------- ---------
<S> <C> <C> <C>
Net Sales Volume
Oil (Bbls)....................... 545,435 467,056 324,486
Gas (Mcf)(1)..................... 7,913,963 6,798,531 5,421,841
Average Sales Price
Oil (per Bbl).................... $ 15.66 $ 14.35 $ 15.10
Gas (per Mcf) ................... $ 1.77 $ 1.93 $ 1.96
Average Production Cost
(per Mcf Equivalent)(2).......... $ .61 $ .59 $ .62
</TABLE>
(1) Natural gas production for 1995, 1994, and 1993 includes 1,211,255,
1,358,375, and 1,581,206 Mcf, respectively, delivered under the Company's
volumetric production payment agreement.
(2) Converted to Mcf equivalents on a thermal equivalent basis of 6 Mcf per
barrel of oil.
Under the volumetric production payment entered into in 1992, as of
December 31, 1995, the Company has a remaining commitment to deliver
approximately 4.1 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.
During 1995, the Company entered into oil and natural gas price hedging
contracts covering a small portion of the Company's and its affiliated
partnerships' oil and natural gas production. For the months of January,
February, March, and April, 300,000 MMBtu of the natural gas production was
covered, providing for a minimum price of $1.58. For the months of November
and December, 1,000,000 MMBtu and 1,250,000 MMBtu, respectively, were
covered, providing for minimum prices ranging from $1.65 to $1.75. For the
months of March through December, 75,000 Bbls of oil production was covered,
providing for minimum prices ranging from $17.00 to $18.00. Costs related to
1995 hedging activities totaled approximately $448,000, and benefits received
totaled approximately $140,000. Open contracts at December 31, 1995, cover
1,500,000 MMBtu of the natural gas production for the months of January and
February 1996, 1,000,000 MMBtu for March 1996, and 35,000 Bbls of oil
production for March and April 1996, providing for minimum prices ranging
from $1.65 to $1.75 per MMBtu and $17.50 per Bbl. The costs related to the
open contracts totaled approximately $148,000 and had a market value of
$39,000 as of December 31, 1995.
FOREIGN ACTIVITIES
During 1993, the Company entered into a Participation Agreement (the
"Participation Agreement") with Senega, a Russian Federation joint stock
company (in which the Company has an indirect interest of less than 1%), to
develop and produce reserves in two fields in Western Siberia. Under this
Participation Agreement, the Company will receive a minimum 5% net profits
interest. Additionally, the Company purchased a 1% net profits interest from
the Russian Federation joint stock company for $300,000. In May 1995, the
Company executed a Management Agreement with Senega. In return for obtaining
financing for development of these fields, the Company was given certain
rights by Senega, including a 49% interest in production income derived by
Senega from this project after repayment of costs. During 1995, the Company
was approved for the grant of a Petroleum Exploration Permit by the New
Zealand Minister of Energy. This permit covers approximately 65,000 acres in
the onshore Taranaki Basin region. The Company also is pursuing
opportunities in the oil and gas industry in Venezuela. These activities are
described in greater detail in Note 9 to the Company's financial statements.
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, 1995, 1994, and 1993. 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
6
<PAGE>
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, 1995, were estimated based upon weighted
average prices of $2.41 per Mcf of natural gas and $18.07 per barrel of oil,
compared to $1.85 and $2.50 per Mcf of natural gas and $15.09 and $12.87
per barrel of oil as of December 31, 1994 and 1993, 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.
<TABLE>
<CAPTION>
AT DECEMBER 31,
-------------------------------------
1995 1994 1993
---------- ---------- -----------
<S> <C> <C> <C>
ESTIMATED PROVED OIL AND GAS RESERVES
Net natural gas reserves (Mcf:)
Proved developed 81,532,025 46,406,448 50,936,942
Proved undeveloped 62,035,495 29,857,516 13,525,863
------------ ----------- -----------
Total 143,567,520 76,263,964 64,462,805
------------ ----------- -----------
------------ ----------- -----------
Net oil reserves (Bbl):
Proved developed 3,313,226 3,209,387 3,110,505
Proved undeveloped 2,108,755 1,343,880 1,160,564
------------ ----------- -----------
Total 5,421,981 4,553,267 4,271,069
------------ ----------- -----------
------------ ----------- -----------
ESTIMATED PRESENT VALUE OF PROVED RESERVES
Estimated present value of future
net cash flows from proved reserves
discounted at 10% per annum:
Proved developed $ 85,536,873 $47,172,093 $66,309,471
Proved undeveloped 61,501,536 22,222,511 17,451,305
------------ ----------- -----------
Total $147,038,409 $69,394,604 $83,760,776
------------ ----------- -----------
------------ ----------- -----------
</TABLE>
The table also sets forth estimates of future net revenues presented on
the basis of unescalated prices and costs in accordance with criteria
prescribed by the Securities and Exchange Commission and their PV-10 Value.
Operating costs, development costs, and certain production-related taxes were
deducted in arriving at the estimated future net revenues. No provision was
made for income taxes. The estimates of future net revenues and their
present value differ in this respect from the standardized measure of
discounted future net cash flows set forth in Note 9 to the Consolidated
Financial Statements of the Company, which is calculated after provision for
future income taxes. In cases where producing properties are subject to gas
purchase contracts and the amount of gas purchased thereunder was reduced
during 1995, 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 1996 and thereafter will be made at an
unrestricted level.
The Company's total proved developed and undeveloped reserves have
increased substantially (70%) since December 31, 1994, as shown above and
in Note 9 to the Company's financial statements. A substantial portion of
the increased reserves represent proved undeveloped reserves. This shift
reflects the increased emphasis on exploration and development activities,
which results in additions of substantial proved undeveloped reserves. The
Company's higher level of proved developed reserves was due to increased
development drilling, revisions of previous quantity estimates, and higher
year-end 1995 prices. 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.
Proved reserves are estimates of hydrocarbons to be recovered in the
future. Reservoir engineering is a subjective process of estimating the
sizes of underground accumulations of oil and gas that cannot be measured in
an exact way. The accuracy of any reserves estimate is a function of the
quality of available data and of engineering and geological interpretation
and judgment. Reserves reports of other engineers might differ from the
reports contained herein. Results of drilling, testing, and production
subsequent to the date of the estimate may justify revision of such estimate.
Future prices received for the sale of oil and gas may be different from
those used in preparing these reports. The amounts and timing of future
operating and development costs may also differ from those used.
Accordingly, reserves estimates are often different from the quantities of
oil and gas that are ultimately recovered. There can be no assurance that
these estimates are accurate predictions of the present value of future net
cash flows from oil and gas reserves.
A portion of the Company's proved reserves has been accumulated through
the Company's interests in the limited partnerships for which it serves as
general partner. The estimates of future net cash flows and their present
values, based on period end prices, assume that some of the limited
partnerships in which the Company owns interests will achieve payout status
in the future. None of the limited partnerships had achieved payout status
at December 31, 1995.
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>
Oil Wells Gas Wells Total Wells(1)
--------- --------- --------------
<S> <C> <C> <C>
December 31, 1995
Gross(2) 3,049 995 4,044
Net(3) 88.5 121.6 210.1
December 31, 1994
Gross(2) 3,141 1,000 4,141
Net(3) 79.3 109.1 188.4
December 31, 1993
Gross(2) 3,165 872 4,037
Net(3) 72.5 52.4 124.9
</TABLE>
(1) Excludes 39 service wells in 1995, 31 service wells in 1994, and 165
service wells in 1993.
(2) A gross well is a well in which a working interest is owned. The number
of gross wells is the total number of wells in which a working interest is
owned.
(3) A net well is deemed to exist when the sum of fractional ownership
working interests in gross wells equals one. The number of net wells is the
sum of fractional working interests owned in gross wells expressed as whole
numbers and fractions thereof.
7
<PAGE>
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 leasehold
acreage held by the Company at December 31, 1995:
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
----------------------- -----------------------
GROSS(1) NET(2)(3) GROSS(1) NET(2)(3)
---------- ---------- --------- ---------
<S> <C> <C> <C> <C>
Alabama 7,075.72 820.82 372.00 61.17
Arkansas 8,960.45 3,271.17 4,754.86 2,978.63
Kansas 1,630.00 571.67 5,450.00 2,268.55
Louisiana 56,766.05 18,620.66 11,985.24 7,222.14
Mississippi 10,680.29 4,211.95 4,965.61 887.68
Nebraska - - 1,707.04 1,029.53
New Mexico 1,854.47 473.61 240.00 28.80
North Dakota 1,276.19 147.25 160.00 17.32
Oklahoma 54,270.93 21,420.96 4,410.02 2,103.06
Texas 116,635.23 53,438.69 22,897.00 15,938.33
West Virginia 16,048.20 10,484.50 - -
Wyoming 10,434.00 3,225.25 27,177.72 10,941.82
All other states 477.64 128.66 4,690.44 272.81
---------- ---------- --------- ---------
TOTAL 286,109.17 116,815.19 88,809.93 43,749.84
---------- ---------- --------- ---------
---------- ---------- --------- ---------
</TABLE>
(1) A gross acre is an acre in which a working interest is owned. The number
of gross acres is the total number of acres in which a working interest is
owned.
(2) A net acre is deemed to exist when the sum of fractional ownership
working interests in gross acres equals one. The number of net acres is
the sum of fractional working interests owned in gross acres expressed as
whole numbers and fractions thereof.
(3) A material portion of the Company's acreage is owned by virtue of its
interests derived from limited partnerships. The net acreage reflected on
this table shows the Company's interests assuming that an after payout
status is achieved in these partnerships. At December 31, 1995, none of
the limited partnerships had achieved payout status.
PARTNERSHIPS
The Company has historically relied on limited partnerships as its
principal financing vehicle to fund its activities. The Company has formed
101 limited partnerships which have raised a total of approximately $463.3
million at December 31, 1995. However, as the Company has increasingly
shifted its emphasis to exploration and development activities and its
reserves base has grown, the Company has significantly reduced its reliance
on limited partnership financing.
Approximately 18 of the limited partnerships formed and managed by the
Company have been in operation for over nine years and have produced a
substantial majority of their reserves. Given the age of these limited
partnerships, the Company has proposed that the limited partners in 10 of
these limited partnerships vote to sell their remaining properties and
liquidate the limited partnerships. The Company anticipates that these
proposals will be approved by these partnerships' limited partners and that
these partnerships will be liquidated in 1996. The Company intends to make
the same proposal to the other eight partnerships later this year.
From 1991 to 1995, the Company offered Swift Depositary Interests
("SDI"), a publicly offered partnership program under which partnerships were
formed to acquire interests in producing oil and gas properties. Since 1993,
the Company also has offered private partnerships formed to engage in the
drilling of development and exploratory wells.
The Company concluded the SDI Program upon the formation of its last two
partnerships organized on December 14, 1995. Under the SDI program,
partnerships were formed on a sequential basis and, in 1995, the Company
raised approximately $12.4 million under the SDI program. The SDI
partnerships acquire, manage, and ultimately sell interests in properties
that are producing oil and gas in commercial quantities or which contain
shut-in wells capable of such production. The SDI partnerships seek to profit
primarily from the sale of oil and gas produced from the properties in which
they own interests, and from the proceeds of the eventual sale of their
interests.
In September of 1993, the Company began offering interests in private
drilling partnerships. As of December 31, 1995, five partnerships had been
formed (one in 1993, one in 1994, and three in 1995) with aggregate investor
contributions of approximately $19.9 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.
CONFLICTS OF INTEREST BETWEEN THE COMPANY AND LIMITED PARTNERSHIPS
Under the terms of the Company's limited partnership programs, the Company
generally retains the right to engage in oil and gas exploration and
production
8
<PAGE>
through other limited partnerships and joint ventures and for its own
account. The partnership agreement for each limited partnership contains
detailed provisions regarding the terms upon which a variety of transactions
between the Company and the limited partnerships may be carried out,
including (i) sales of properties by the Company to the limited partnerships,
(ii) operation of limited partnership properties by the Company, (iii)
rendering of oil field or drilling services by the Company to a limited
partnership, (iv) handling of limited partnership funds by the Company, and
(v) loans between the Company and a limited partnership. These restrictions,
which may limit the ability of the Company to take certain actions, are
intended to ensure that transactions between the Company and the limited
partnerships are fair to such limited partnerships.
RISK MANAGEMENT
The Company's operations are subject to all of the risks normally
incident to the exploration for and the production of oil and gas, including
blowouts, cratering, pipe failure, casing collapse, oil spills, and fires,
each of which could result in severe damage to or destruction of oil and gas
wells, production facilities, or other property, or individual injuries. The
oil and gas exploration business is also subject to environmental hazards,
such as oil spills, gas leaks, and ruptures and discharges of toxic
substances or gases that could expose the Company to substantial liability
due to pollution and other environmental damage. Additionally, as managing
general partner of limited partnerships, the Company is solely responsible
for the day-to-day conduct of the limited partnerships' affairs and
accordingly has liability for expenses and liabilities of the limited
partnerships. The Company maintains comprehensive insurance coverage,
including general liability insurance in an amount not less than $20.0
million, as well as general partner liability insurance. The Company
believes that its insurance is adequate and customary for companies of a
similar size engaged in comparable operations, but losses could occur for
uninsurable or uninsured risks or in amounts in excess of existing insurance
coverage.
COMPETITION
The oil and gas industry is highly competitive in all its phases. The
Company encounters strong competition from many other oil and gas producers,
including many that possess substantial financial resources, in acquiring
economically desirable producing properties and exploratory drilling
prospects, and in obtaining equipment and labor to operate and maintain its
properties. In marketing its partnership programs, the Company competes with
other oil and gas companies sponsoring similar programs and with numerous
other investment opportunities.
REGULATIONS
ENVIRONMENTAL REGULATIONS
The federal government and various state and local governments have
adopted laws and regulations regarding the control of contamination of the
environment. These laws and regulations may require the acquisition of a
permit by operators before drilling commences, prohibit drilling activities
on certain lands lying within wilderness areas or where pollution arises, and
impose substantial liabilities for pollution resulting from drilling
operations particularly operations in offshore waters or on submerged lands.
These laws and regulations may also increase the costs of drilling and
operation of wells. However, the Company does not believe that it is
affected in a significantly different manner by these regulations than are
its competitors in the oil and gas industry.
FEDERAL REGULATION OF NATURAL GAS
The transportation and sale of natural gas in interstate commerce is
heavily regulated by agencies of the federal government. The following
discussion is intended only as a brief summary of the principal statutes,
regulations, and orders that may affect the production and sale of the
Company's natural gas. This summary should not be relied upon as a complete
review of applicable natural gas regulatory provisions.
PRICE CONTROLS. Prior to January 1, 1993, the sale of natural gas
production was subject to regulation under the Natural Gas Act and the
Natural Gas Policy Act of 1978 ("NGPA"). However, under the Natural Gas
Wellhead Decontrol Act of 1989 all price regulation under the NGPA and
Natural Gas Act of rate, certificate and abandonment requirements were phased
out effective as of January 1, 1993.
FERC ORDERS. Several major regulatory changes have been implemented by
the Federal Energy Regulatory Commission ("FERC") from 1985 to the present
that affect the economics of natural gas production, transportation and
sales. In addition, the FERC continues to promulgate revisions to various
aspects of the rules and regulations affecting those segments of the natural
gas industry that remain subject to the FERC's jurisdiction. In April 1992
the FERC issued Order No. 636 pertaining to pipeline restructuring. This
rule requires interstate pipelines to unbundle transportation and sales
services by separately stating the price of each service and by providing
customers only the particular service desired, without regard to the source
for purchase of the gas. The rule also requires pipelines to (i) provide
nondiscriminatory "no-notice" service allowing firm commitment shippers to
receive delivery of gas on demand up to certain limits without penalties,
(ii) establish a basis for release and reallocation of firm upstream pipeline
capacity, and (iii) provide non-discriminatory access to capacity by firm
transportation shippers on a downstream pipeline. The rule requires
interstate pipelines to use a straight fixed variable rate design.
FERC Order No. 500 affects the transportation and marketability of
natural gas. Traditionally, natural gas had been sold by producers to
pipeline companies, which then resold the gas to end-users. FERC Order No.
500 altered this market structure by requiring interstate pipelines that
transport gas for others to provide transportation service to producers,
distributors and all other shippers of natural gas on a nondiscriminatory,
"first-come, first-served" basis ("open access
9
<PAGE>
transportation"), so that producers and other shippers can sell natural gas
directly to end-users. FERC Order No. 500 contains additional provisions
intended to promote greater competition in natural gas markets.
It is not anticipated that the marketability of and price obtainable for
the Company's natural gas production will be significantly affected by FERC
Order No. 500. Gas produced normally will be sold to intermediaries who have
entered into transportation arrangements with pipeline companies. These
intermediaries will accumulate gas purchased from a number of producers and
sell the gas to end-users through open access transportation.
STATE REGULATIONS
Production of any oil and gas by the Company will be affected to some
degree by state regulations. Many states in which the Company operates have
statutory provisions regulating the production and sale of oil and gas,
including provisions regarding deliverability. Such statutes, and the
regulations promulgated in connection therewith, are generally intended to
prevent waste of oil and gas and to protect correlative rights to produce oil
and gas between owners of a common reservoir. Certain state regulatory
authorities also regulate the amount of oil and gas produced by assigning
allowable rates of production to each well or proration unit.
FEDERAL LEASES
Some of the Company's properties are located on federal oil and gas
leases administered by various federal agencies, including the Bureau of Land
Management. Various regulations and orders affect the terms of leases,
exploration and development plans, methods of operation, and related matters.
EMPLOYEES
At December 31, 1995, the Company employed 176 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 $81,000 per
month. A subsidiary of the Company maintains an office in Denver, Colorado.
The Company has field offices in various locations from which Company
employees supervise local oil and gas operations.
FORWARD-LOOKING INFORMATION
The statements contained in this Annual Report on Form 10-K ("Annual
Report") that are not historical facts, including, but not limited to,
statements found in this Item 1. Business and Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations, are
forward-looking statements, as that term is defined in Section 21E of the
Securities and Exchange Act of 1934, as amended, that involve a number of
risks and uncertainties. The actual results of the future events described in
such forward-looking statements in this Annual Report could differ materially
from those stated in such forward-looking statements. Among the factors that
could cause actual results to differ materially are: 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.
_________________________
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 equivalent (see Mcfe).
Development Well -- A well drilled within the presently proved productive
area of an oil or gas reservoir, as indicated by reasonable interpretation of
available data, with the objective of completing in that reservoir.
Discovery Cost -- With respect to proved reserves, a three-year average
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 gas reservoir or to greatly extend the known limits of a
previously discovered reservoir.
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 equivalent, which is determined using the ratio
of one barrel of oil, condensate, or natural gas liquids to 6 Mcf of natural
gas.
MMBbl -- Million barrels of oil.
MMBtu -- Million British thermal units, which is a heating equivalent measure
for natural gas and is an alternate measure of natural gas reserves, as
opposed to Mcf, which is strictly a measure of natural gas volumes.
Typically, prices quoted for natural gas are designated as price per MMBtu,
the same basis on which natural gas is contracted for sale.
MMcf -- Million cubic feet of natural gas.
MMcfe -- Million cubic feet equivalent (see Mcfe).
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.
10
<PAGE>
Producing Well -- An exploratory or development well found to be capable of
producing either oil or gas in sufficient quantities to justify completion as
an oil or gas well.
Proved Developed Oil and Gas Reserves -- Proved developed oil and gas
reserves are reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods.
Proved Oil and Gas Reserves -- Proved oil and gas reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids, which
geological and engineering data demonstrate with reasonable certainly 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 -- 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.
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, and without giving effect to non-property
related expenses such as debt service, future income tax expense, or
depreciation, depletion, and amortization.
Reserve Replacement Cost -- With respect to proved reserves, a three-year
average 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 gas interests and committed
to deliver certain monthly quantities of natural gas.
- -----------------------------------------------------------------------------
ITEM 3. LEGAL PROCEEDINGS
No material legal proceedings are pending other than ordinary routine
litigation incidental to the Company's business.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted during the fourth quarter of 1995 to a vote of
security holders.
- -----------------------------------------------------------------------------
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
COMMON STOCK, 1995 AND 1994
Swift Energy Company common stock is traded on the New York Stock
Exchange and the Pacific Stock Exchange under the symbol "SFY." The high and
low quarterly sales prices for the common stock for 1995 and 1994 are as
follows:
<TABLE>
<CAPTION>
1995 1994
--------------------------------------- -------------------------------------
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 8 8 1/2 8 1/4 7 3/4 8 1/2 9 9 1/4 9 1/2
High 9 7/8 10 1/8 9 5/8 12 5/8 11 1/4 10 1/8 10 1/2 11 3/8
</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 above 1994
prices have been revised to reflect the September 1994 stock dividend.
Swift Energy had approximately 623 stockholders of record as of December
31, 1995.
11
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
1995 1994(1) 1993 1992 1991
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Revenues
Oil and Gas Sales $22,527,892 $19,802,188 $15,535,671 $12,420,222 $8,361,771
Supervision Fees $3,838,815 $3,751,061 $3,718,829 $3,443,777 $3,362,800
Earned Interests & Fees (2) $590,441 $701,528 $4,071,970 $2,716,277 $2,231,729
Interest Income $212,329 $47,980 $201,584 $113,387 $192,694
Other, Net $1,761,568 $1,072,535 $604,599 $515,931 $541,502
Total Revenues $28,931,045 $25,375,292 $24,132,653 $19,209,594 $14,690,496
Operating Income $6,894,537 $4,837,829 $6,628,608 $4,687,519 $3,748,741
Net Income (Loss) $4,912,512 $(13,047,027) $4,896,253 $4,084,760 $2,512,815
- ---------------------------------------------------------------------------------------------------------
PER SHARE DATA
Weighted Shares Outstanding (3) 9,122,857 6,644,248 6,588,076 6,135,044 5,363,299
Net Income (Loss) per Share-
Primary (3) $0.54 $(1.96) $0.74 $0.67 $0.47
Net Income (Loss) per Share-
Fully Diluted (3) $0.54 $(1.96) $0.70 $0.67 $0.47
Shares Outstanding at Year End 12,509,700 6,685,137 6,001,075 5,968,579 4,955,134
Book Value per Share $7.46 $6.30 $9.08 $8.26 $7.80
Market Price (3)
High $12.63 $11.38 $12.73 $8.64 $10.00
Low $7.75 $8.52 $7.85 $5.12 $4.77
Year-End Close $12.00 $9.75 $8.64 $8.30 $5.45
- ---------------------------------------------------------------------------------------------------------
PRO FORMA AMOUNTS ASSUMING CHANGE
IN ACCOUNTING PRINCIPLE IS
APPLIED RETROACTIVELY. (2)
Net Income $4,912,512 $3,725,671 $4,322,478 $3,729,851 $2,950,245
Net Income per Share-
Primary $0.54 $0.56 $0.66 $0.61 $0.55
Net Income per Share-
Fully Diluted $0.54 $0.56 $0.63 $0.61 $0.55
- ---------------------------------------------------------------------------------------------------------
ASSETS
Current Assets $43,380,454 $39,208,418 $65,307,120 $30,830,173 $47,859,278
Oil and Gas Properties, Net of
Accumulated Depreciation,
Depletion, and Amortization $125,217,872 $88,415,612 $89,656,577 $64,301,509 $47,655,917
TOTAL ASSETS $175,252,707 $135,672,743 $160,892,917 $100,243,469 $101,421,573
LIABILITIES
Current Liabilities $40,133,269 $52,345,859 $55,565,437 $27,876,687 $50,851,447
Long-Term Debt, Net of
Current Portion $28,750,000 $28,750,000 $28,750,000 $0 $0
Total Liabilities $81,906,742 $93,545,612 $106,427,203 $50,962,183 $62,761,217
Stockholders' Equity $93,345,965 $42,127,131 $54,465,714 $49,281,286 $38,660,356
- ---------------------------------------------------------------------------------------------------------
Number of Employees 176 209 188 178 171
</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 - Primary -
Income Before Cumulative Effect of Change in Accounting Principle - $O.56,
Cumulative Effect of Change in Accounting Principle - $(2.52); Per
Share Amounts - Fully Diluted - Income Before Cumulative Effect of
Change in Accounting Principle - $O.56, Cumulative Effect of Change in
Accounting Principle - $(2.52).
(2) As of January 1, 1994, the Company changed its revenue recognition policy
for earned interests. See Note 2 to the Company's financial statements.
Accordingly, 1995 and 1994 "Earned Interests and Fees" does not include
earned interests revenues.
(3) Amounts have been retroactively restated in all periods presented to give
recognition to an equivalent change in capital structure as a result of a
10% stock dividend in September 1994. See Note 1 to the Company's
financial statements.
12
<PAGE>
<TABLE>
<CAPTION>
1990 1989 1988 1987 1986 1985
- ------------------------------------------------------------------------------------------------------------------------
<S> <S> <C> <C> <C> <C> <C>
Revenues
Oil and Gas Sales $7,328,190 $3,984,835 $2,838,433 $2,097,815 $954,269 $908,928
Supervision Fees $2,149,079 $1,651,839 $1,118,794 $1,065,820 $1,108,410 $963,917
Earned Interests & Fees (2) $9,882,953 $8,802,816 $8,073,530 $7,956,895 $2,393,371 $1,173,841
Interest Income $705,786 $260,286 $165,909 $125,459 $40,174 $99,919
Other, Net $323,981 $232,261 $488,131 $452,059 $471,486 $348,235
Total Revenues $20,389,989 $14,932,037 $12,684,797 $11,698,048 $4,967,710 $3,494,840
Operating Income $10,811,044 $8,716,673 $7,040,165 $6,632,631 $1,948,431 $1,410,998
Net Income (Loss) $7,170,642 $5,709,098 $4,678,317 $4,024,003 $1,108,314 $778,197
- ------------------------------------------------------------------------------------------------------------------------
PER SHARE DATA
Weighted Shares Outstanding (3) 5,278,578 4,663,322 4,452,163 4,383,969 4,326,300 4,290,000
Net Income (Loss) per Share-
Primary (3) $1.36 $1.22 $1.05 $0.92 $0.26 $0.18
Net Income (Loss) per Share-
Fully Diluted (3) $1.36 $1.22 $1.05 $0.92 $0.26 $0.18
Shares Outstanding at Year End 4,848,315 4,764,862 4,068,968 4,025,108 3,949,500 3,900,000
Book Value per Share $7.36 $5.84 $3.88 $2.70 $1.68 $1.39
Market Price (3)
High $11.71 $12.27 $9.65 $16.94 $4.89 $1.94
Low $7.62 $6.36 $6.14 $3.75 $1.14 $1.03
Year-End Close $9.43 $10.45 $6.25 $6.82 $3.75 $1.59
- ------------------------------------------------------------------------------------------------------------------------
PRO FORMA AMOUNTS ASSUMING CHANGE
IN ACCOUNTING PRINCIPLE IS
APPLIED RETROACTIVELY. (2)
Net Income $3,107,451 $2,185,276 $898,962 $561,509 $290,582 $310,314
Net Income per Share-
Primary $0.59 $0.47 $0.20 $0.13 $0.07 $0.07
Net Income per Share-
Fully Diluted $0.59 $0.47 $0.20 $0.13 $0.07 $0.07
- ------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets $72,537,521 $54,818,404 $9,304,370 $8,396,944 $6,924,548 $7,994,603
Oil and Gas Properties, Net of
Accumulated Depreciation,
Depletion, and Amortization $41,952,212 $27,935,170 $19,973,454 $13,092,526 $6,913,487 $4,766,258
TOTAL ASSETS $118,227,480 $85,007,293 $31,463,220 $23,745,504 $15,731,279 $14,781,775
LIABILITIES
Current Liabilities $71,514,938 $49,354,128 $9,756,431 $8,342,755 $6,535,890 $7,579,679
Long-Term Debt, Net of
Current Portion $0 $0 $0 $0 $0 $23,030
Total Liabilities $82,559,406 $57,198,476 $15,694,272 $12,874,849 $9,114,611 $9,379,600
Stockholders' Equity $35,668,074 $27,808,817 $15,768,948 $10,870,655 $6,616,668 $5,402,175
- ------------------------------------------------------------------------------------------------------------------------
Number of Employees 164 131 116 94 55 50
</TABLE>
13
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
- -----------------------------------------------------------------------------
The following discussion should be read in conjunction with the
Company's Consolidated Financial Statements and Notes thereto.
GENERAL
Swift Energy Company's principal corporate objectives are the
accumulation of crude oil and natural gas reserves for current and future
production and sale and the enhancement of the net present value of those
reserves. The Company has historically financed most of its growth with
capital raised through limited partnership financing, having raised
approximately $463 million through limited partnership financing from 1979
through 1995. Beginning in 1985, the Company increasingly emphasized this
financing vehicle thereby enabling the Company to accelerate its growth and
purchase larger producing properties. Commencing in 1991, the Company began
re-emphasizing the addition of reserves through increased drilling on
internally generated exploration and development prospects.
The Company's revenue is primarily comprised of oil and gas sales
attributable to properties in which the Company owns a direct or indirect
interest. Additionally, prior to 1994, the Company also recorded earned
interests and fees from limited partnerships and joint ventures. Effective
January 1, 1994, the Company changed its revenue recognition policy for
earned interests. The cumulative effect in 1994 of this change in accounting
principle resulted in a one-time accounting adjustment of $16.8 million, or a
loss of $2.52 per share (after reduction for income taxes of $8.6 million),
from applying the new method retroactively. Earned interests represented
revenues in the form of interests in proved developed oil and gas properties
conveyed to limited partnerships and joint ventures formed in connection with
the Company's organization and management of limited partnerships and joint
ventures, representing the difference between the Company's capital
contributions to each limited partnership or joint venture and its earned
revenue interest in the limited partnership's or venture's properties (based
upon the expected levels of cash distributions to the limited partners or
joint ventures). Under the Company's current method of accounting for earned
interests, such amounts will not be recognized as income, thereby reducing
the Company's investment in oil and gas property. The Company believes the
change in policy results in financial statements that better reflect its
business focus and that are more comparable to prevalent practices in the oil
and gas exploration and production industry.
In May 1992, the Company purchased interests in certain wells from the
Manville Corporation for $13.8 million using funds provided by the Company's
sale of a volumetric production payment in these properties to a subsidiary
of Enron Corp. Net proceeds from the sale of the production were recorded as
deferred revenues. Deliveries under the volumetric production payment are
recorded as oil and gas sales revenues which are offset by a corresponding
reduction of deferred revenues. Under this arrangement, the Company is
required to deliver a fixed quantity of hydrocarbons produced from the
properties over specified periods through October 2000. Volumes remaining to
be delivered under the volumetric production payment (approximately 4.1 Bcfe)
are not included in the Company's proved reserves. Under the volumetric
production payment, hydrocarbons produced in excess of the amount required to
be delivered are sold by the Company for its own account.
PROVED OIL AND GAS RESERVES. From 1993 to 1994, the Company's proved
natural gas reserves increased 11.8 Bcf (18%) and its proved oil reserves
increased by 282,198 barrels (7%). In 1995, the Company's proved natural gas
reserves increased 67.3 Bcf (88%) and its proved oil reserves increased
868,714 barrels (19%). As detailed in Note 9 to the Company's financial
statements, the composition of these reserves shifted substantially, with
proved developed reserves comprising 77% of total proved reserves at year-end
1993, 63% of total proved reserves at year-end 1994, and 58% of total proved
reserves at year-end 1995. This shift reflects the increased portion of the
Company's reserves generated by recent exploration and development
activities, resulting in additions of substantial proved undeveloped reserves.
Proved developed reserves additions in 1995 resulted from drilling
activity (which increased undeveloped reserves to a much larger degree),
revisions of previous quantities estimates and higher year-end 1995 prices.
The increase in the Standardized Measure of Discounted Future Net Cash Flows
(see Note 9 to the Company's financial statements) and in the Estimated
Present Value of Proved Reserves (see Form 10-K-"Oil and Gas Reserves") from
year-end 1994 to year-end 1995 is due to additions in reserves through the
Company's drilling activity (primarily in the AWP Olmos Field and the
Giddings Field), to the 30% increase in year-end 1995 natural gas prices
($2.41 per Mcf versus $1.85 per Mcf at year-end 1994), and to the 20%
increase in year-end 1995 oil prices ($18.07 per barrel at year-end 1995,
compared to $15.09 per barrel a year earlier).
LIQUIDITY AND CAPITAL RESOURCES
The Company historically relied on limited partnership capital as its
principal financing vehicle to fund its acquisitions of producing properties.
Since 1991, however, the Company's strategy has shifted toward an increased
reliance on exploration and development activities, and it has significantly
expanded reserves added through these efforts. As a result, the Company has
reduced its reliance on cash flows generated from, and capital raised
through, limited partnerships. Supplemental cash and working capital are
provided through internally generated cash flows and debt and equity
financing.
14
<PAGE>
NET CASH FROM OPERATIONS. In 1995, 1994, and 1993, the Company's
operating activities provided net cash of $14,376,000, $10,395,000, and
$7,238,000, respectively. The 1995 increase of $3,982,000 was primarily due
to an increase in cash flows from oil land gas sales, which increased
$2,932,000 (16%), exclusive of the non-cash amortization of deferred revenues
associated with the Company's volumetric production payment. During 1995,
the Company also had a $689,000 increase in other revenues, and a $680,000
decrease in interest expense, partially offset by a $1,187,000 increase in
oil and gas production costs. The 1994 increase of $3,156,000 in net cash
from operations was primarily due to the cash flows from oil and gas sales,
which increased $4,577,000 (35%), exclusive of the non-cash amortization of
deferred revenues associated with the Company's volumetric production
payment, partially offset by a $1,099,000 increase in oil and gas production
costs and a $1,198,000 increase in interest expense.
SALE OF COMMON STOCK. During the third quarter of 1995, the Company
closed the sale to the public of 5,750,000 shares of common stock at a price
of $8.50 per share. Net proceeds from this stock sale were $45,698,912.
Consequently, the Company's stockholders' equity at December 31, 1995, grew
to over $93,000,000. Net proceeds from the offering were used to repay
outstanding indebtedness, and the remainder of the proceeds will be used or
have been used to finance the Company's exploration and development
activities and to acquire producing oil and gas properties, including limited
partnership interests.
SALE OF CONVERTIBLE SUBORDINATED DEBENTURES. On June 30, 1993, the
Company issued $28,750,000 of Convertible Subordinated Debentures
(Debentures) due June 30, 2003, in a public offering. Proceeds of the
offering were used primarily to acquire producing oil and gas properties and
to finance the Company's expanding exploration and development programs. The
principal terms of these Debentures are more fully described in Note 5 to the
Company's financial statements.
OTHER FINANCING ACTIVITIES. Between 1991 and 1995, the Company offered
interests in oil and gas production partnerships under its Swift Depositary
Interests (SDI) offering and since late 1993 has offered private partnerships
formed to drill for oil and gas. The SDI program concluded at the end of
1995. Four SDI partnerships were formed during 1995, with total subscriptions
of approximately $12,400,000, compared to $32,100,000 raised in eight 1994
SDI partnerships. During 1995, the Company closed three drilling
partnerships with a total of $15,900,000 of subscriptions, compared to
$2,600,000 of drilling partnership subscriptions in 1994. The Company
anticipates that it will continue to offer drilling partnerships in the
foreseeable future.
At December 31, 1995, limited partnership formation and marketing costs
(which under the current drilling partnership offerings are borne by the
Company as part of the Company's general partner contribution) amounted to
$858,559, a decrease of $2,133,314, when compared with the December 31, 1994,
balance. Upon the Company's decision to conclude the SDI offering, the
remaining limited partnership formation and marketing costs related to the
SDI offering (approximately $1,750,000) were accordingly transferred to the
oil and gas properties account.
CREDIT FACILITIES. The Company has established credit facilities which
formerly were used principally to finance the Company's purchase of producing
oil and gas properties on an interim basis pending transfer of the properties
to newly formed partnerships and joint ventures and to provide working
capital. More recently the Company's credit facilities have been used to fund
a portion of the Company's exploration and development activities. The
principal terms and restrictions of these credit facilities are described
in Note 4 to the Company's financial statements included herein.
At December 31, 1995, the Company had no outstanding balances under
these borrowing arrangements, since these borrowings were repaid with
proceeds from the Company's 1995 stock offering. The borrowings since
year-end 1994 had been used primarily to fund a substantial portion of the
Company's 1995 capital expenditures described below.
At December 31, 1994, the Company had $27,229,000 outstanding under
these borrowing arrangements. Approximately $8,000,000 used to finance
producing oil and gas property purchases was either reimbursed in January
1995 or reflected at December 31, 1994, in the "Producing oil and gas
properties held for transfer" account on the balance sheet. The Company used
the remainder of the outstanding balance of the credit facilities, along with
internally generated cash flows, principally to fund the Company's capital
expenditures in 1994 and, to a lesser extent, to provide working capital.
WORKING CAPITAL. The Company's working capital increased significantly
since year end, from a working capital deficit of $13,137,441 at December 31,
1994, to positive working capital of $3,247,185 at December 31, 1995. This
increase is primarily the result of the net proceeds from the 1995 common
stock offering.
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 770 wells and the
management of affiliated partnerships. In this capacity, the Company is
responsible for certain day-to-day cash management, including the collection
and disbursement of oil and gas revenues and related expenses.
CAPITAL EXPENDITURES. The Company's capital expenditures were
approximately $40,000,000, $34,500,000, and $24,200,000 for 1995, 1994, and
1993, respectively. Including the Company's general partner capital
contribution to drilling partnerships formed in 1995 ($3,200,000),
approximately $23,600,000 (59%) of the 1995 capital expenditures were spent
on developmental drilling (primarily in the AWP Olmos Field and Giddings
Field) and $2,300,000 (6%) was expended on exploratory drilling. The Company
expended approximately $6,400,000 (16%
15
<PAGE>
of 1995 capital expenditures) for prospect costs, principally prospect
leasehold, seismic and geological costs of unproven prospects for the
Company's account. The Company funded approximately $2,100,000 (5%) for the
Company's general partner capital contribution to partnerships formed under
its SDI offering. The Company also purchased approximately $500,000 (1%)
of limited partner interests primarily in previously formed partnerships
through the right of presentment arrangement provided in those partnerships.
In its foreign activities, as described in Note 9 to the Company's financial
statements, the Company invested another $2,800,000 (7%), $300,000 (1%),
and $200,000 (1%), respectively in its Russia, Venezuela, and New Zealand
initiatives. Finally, the Company spent the remaining amounts on fixed assets
(primarily for computer equipment) and other additions.
Capital expenditures for 1996 are estimated to be approximately
$62,000,000, including investments in all areas in which 1995 capital was
spent, with the exception of its general partner contribution in SDI.
Expenditures for exploratory and development drilling are expected to make up
a higher proportion of 1996 capital expenditures. The Company plans to
continue its increased drilling effort in 1996, with current plans to drill
110 exploratory and development wells during the year.
The Company believes that 1996's anticipated internally generated cash
flows (expected to increase as the Company's production base increases as a
result of its accelerated drilling program), together with the remainder of
the net proceeds from the sale of 5,750,000 shares of common stock in 1995,
and its existing credit facilities, will be sufficient to finance the costs
associated with its currently budgeted capital expenditures at least through
1996. Further liquidity needs may also be met by additional availability
under its credit facilities based upon the value of the Company's proved
reserves, as management continually evaluates future use of debt and/or
equity to finance its capital needs.
RESULTS OF OPERATIONS
REVENUES. The Company's revenues in 1995 increased by 14% over revenues
in 1994, and by 5% in 1994 over 1993 revenues, principally due to increases
in oil and gas sales revenues. Revenues for 1993 included recognition of
earned interests, discussed above amounting to $3,309,000. On a pro forma
basis, after considering the retroactive application of the Company's change
in accounting for earned interests, revenues for 1993 would have been reduced
14% to $20,824,030.
OIL AND GAS SALES. The increase in oil and gas sales for 1995 was
primarily the result of production from exploratory and developmental wells
drilled in late 1994 and in 1995. In 1995, the Company's additions to reserves
from drilling were approximately 13 times its additions to reserves from
producing property acquisitions. In 1994, reserves added through drilling
were approximately double the additions to reserves from producing property
acquisitions. As a percentage of total revenues, oil and gas sales have risen
from 64% of total revenues in 1993 to 78% of total revenues in 1995.
The Company's net sales volumes in 1995 (including the volumetric
production payment associated with each year's production) increased by 17%
(1,585,706 Mcfe) over net sales volumes in 1994, while 1994 net sales volumes
increased by 30% (2,232,110 Mcfe) over net sales volumes in 1993. Combined
oil and gas sales revenues in 1995 increased by 14% ($2,725,704) over those
revenues for 1994, while in 1994 these revenues increased by 27% ($4,266,517)
over oil and gas sales in 1993. Average prices for oil dropped from $15.10
per Bbl in 1993, to $14.35 per Bbl in 1994, back up to $15.66 per Bbl in
1995, while average gas prices decreased from $1.96 per Mcf in 1993, to $1.93
per Mcf in 1994, to $1.77 per Mcf in 1995.
Since the first quarter of 1994, the Company's quarterly net sales
volumes have fluctuated within a certain range that has not significantly
varied from quarter to quarter until the last quarter of 1995. For the
preceding four quarters, average prices received were also very stable.
Fourth quarter 1995 average gas prices have returned to levels last
experienced in early to mid-1994, but the impact on the Company has been much
more significant, as the net sales volumes have increased to a level 35%
higher than the highest quarterly sales level during 1994. From the fourth
quarter of 1994 to the third quarter of 1995, average gas prices ranged from
$1.63 per Mcf to $1.68 per Mcf, then increased to $2.03 per Mcf in the fourth
quarter of 1995.
Increased 1995 oil and gas sales were attributable to the sale of
production from properties owned by the Company for its own account, which
include production derived from (i) producing properties acquired for its own
account in 1994 and (ii) wells placed into production in 1994 and 1995
through exploratory and development drilling (the largest primary contributor
to the Company's increased oil and gas sales in 1995). In 1995, oil and gas
sales, exclusive of both the Company's interests in partnerships and in sales
delivered under the volumetric production payment, were $10,798,198
(5,257,365 Mcfe) compared to similar oil and gas sales in 1994 of $7,020,614
(3,244,150 Mcfe), an increase between years of $3,777,584 (2,013,215 Mcfe).
These same sales in 1993 were $2,167,823 (940,618 Mcfe). As a percentage of
total oil and gas sales, these sales have comprised 48%, 35%, and 14% of the
total for the respective years 1995, 1994, and 1993.
The Company's oil and gas sales revenues derived through the Company's
interest in partnerships was $7,619,437 (3,827,158 Mcfe) in 1995, $8,691,031
(4,210,449 Mcfe) in 1994, and $8,805,345 (3,979,487 Mcfe) in 1993. As a
percentage of total oil and gas sales, revenues from these interests have
comprised 34%, 44%, and 57% of the total for 1995,1994, and 1993, respectively.
The final major source of the Company's oil and gas sales revenues is
from the sale of production from the properties acquired from Manville
Corporation in May 1992. The Company records the entire amount of
hydrocarbons sold as revenue, which was $4,110,255 (18% of total oil and gas
sales revenue) from 2,102,044 Mcfe sold in 1995, of which 44% was a non-cash
16
<PAGE>
amortization of deferred revenues associated with the volumetric production
payment, while the remaining 56% equals cash proceeds from sale of oil and
excess gas for the Company's account. For 1994, the Company recorded
$4,090,543 of revenue (21% of total oil and gas sales revenue) from the sale
of 2,146,268 Mcfe, of which 49% was non-cash amortization of deferred
revenues and 51% cash proceeds from the sale of oil and excess gas. For
1993, the Company recorded $4,562,503 of revenue (29% of total oil and gas
sales) from the sale of 2,448,652 Mcfe, of which 51% was non-cash
amortization of deferred revenues and 49% cash proceeds from sale of oil and
excess gas.
SUPERVISION FEES. Supervision fees continue to increase slightly,
having grown from $3,718,829 in 1993 to $3,751,061 in 1994 to $3,838,815 in
1995, due to the change in properties operated by the Company, the annual
escalation in well overhead rates, and the increase in drilling activity by
the Company, which in turn increases the drilling well overhead portion of
such fees.
COSTS AND EXPENSES. General and administrative expenses, net of
reimbursement to the Company for services performed on behalf of its limited
partnerships, increased 3% from 1993 to 1994 and 1% from 1994 to 1995. A
substantial portion of the costs of personnel involved in property
acquisitions and operational activities is reimbursed by the production
partnerships and joint ventures for which such activities are performed.
However, the Company's general and administrative expenses per Mcfe produced
decreased from $0.69 per Mcfe in 1993, to $0.54 per Mcfe produced in 1994, to
$0.47 per Mcfe produced in 1995.
Depreciation, depletion, and amortization (DD&A) has steadily increased,
primarily due to the increase in the Company's producing properties and the
related sale of increased quantities of oil and gas therefrom. The Company's
DD&A rate per Mcfe of production has, however, decreased from $0.99 in 1993
to $0.82 in 1994 to $0.79 in 1995, reflecting variations in the per unit
cost of property additions and changes in the mix of reserves. Since 1994,
DD&A also has been favorably affected by the reduction in the Company's oil
and gas properties account as a result of the change in accounting principle
relating to earned interests, as discussed in Note 2 to the Company's
financial statements. This reduction in oil and gas properties from the
accounting principle change should continue to have a favorable impact on
DD&A in future years.
The 24% increase in oil and gas production costs from 1993 to 1994 and
the 21% increase from 1994 to 1995 also relates to the growth in the
Company's production volumes. The 1995 increase was also affected by certain
one-time remedial well expenses. The Company's production costs were $0.62
per Mcfe produced in 1993, $0.59 per Mcfe produced in 1994, and $0.61 per
Mcfe produced in 1995.
Interest expense in 1995 on the Debentures, including amortization of
debt issuance costs, totaled $1,981,639 ($1,973,931 in 1994 and $984,239 in
1993), while interest expense on the credit facilities, including commitment
fees, totaled $1,680,400 ($1,707,601 in 1994 and $598,839 in 1993) for a
total of $3,662,039 (of which $2,546,678 was capitalized). The 1994 total
was $3,681,531 (of which $1,886,398 was capitalized) while the 1993 total was
$1,583,079 (of which $985,614 was capitalized). The Company capitalizes
that portion of interest related to its exploration, partnership, and foreign
business development activities. The lower amount of interest expense in
1993 was attributable to a smaller average balance under the Company's credit
lines necessary to finance the Company's capital expenditures, as well as
paying only six months of interest on the Debentures.
NET INCOME (LOSS). Net income of $4,912,512 and earnings per share of
$0.54 for 1995 were 32% higher and 4% lower, respectively than "Income before
cumulative effect of change in accounting principle" of $3,725,671 and
earnings per share of $0.56 in 1994. The increase in net income was
primarily due to an increase in production volumes and the related oil and
gas sales therefrom. The 1995 decrease in earnings per share reflects a 37%
increase in weighted average shares outstanding for the period, as a result
of the sale of 5,750,000 shares of common stock in the third quarter of 1995.
The Company's consolidated effective tax rate was 26.1%, 23.0%, and 28.7% in
1993, 1994, and 1995, respectively.
Net loss for 1994 of $13,047,027 included a cumulative effect of a
change in accounting principle (see Note 2 to the Company's financial
statements) of $16,772,698. Income before cumulative effect of change in
accounting principle for 1994 was 24% less than net income for 1993.
On a pro forma basis, after considering the retroactive application of
the Company's change in accounting for earned interests, net income would
have been $3,725,671 and $4,322,478 for 1994 and 1993, respectively.
17
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Public Accountants........... 19
Consolidated Balance Sheets........................ 20
Consolidated Statements of Income.................. 21
Consolidated Statements of Stockholders' Equity.... 22
Consolidated Statements of Cash Flows.............. 23
Notes to Consolidated Financial Statements......... 24
1. Summary of Significant Accounting Policies... 24
2. Change in Accounting Principle............... 26
3. Provision for Income Taxes................... 26
4. Short-Term Bank Borrowings................... 27
5. Long-Term Debt............................... 27
6. Commitments and Contingencies................ 28
7. Stockholders' Equity......................... 28
8. Related-Party Transactions................... 29
9. Oil and Gas Producing Activities............. 29
10. Quarterly Results (Unaudited)................ 33
18
<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, 1995
and 1994, and the related consolidated statements of income, stockholders'
equity, and cash flows for each of the three years in the period ended
December 31, 1995. 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, 1995 and 1994, and the results of
their operations and their cash flows for each of the three years in the
period ended December 31,1995, in conformity with generally accepted
accounting principles.
As discussed in Note 2 to the consolidated financial statements,
effective January 1, 1994, the Company changed its method of accounting for
earned interests.
ARTHUR ANDERSEN LLP
Houston, Texas
February 19, 1996
19
<PAGE>
CONSOLIDATED BALANCE SHEETS
- ------------------------------------------------------------------------------
SWIFT ENERGY COMPANY AND SUBSIDIARIES
<TABLE>
<CAPTION>
DECEMBER 31,
1995 1994
------------ ------------
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents.......................................................... $ 7,574,512 $ 985,498
Accounts receivable-
Oil and gas sales............................................................... 14,765,336 12,394,636
Associated limited partnerships and joint ventures.............................. 16,108,298 17,899,150
Joint interest owners........................................................... 4,044,817 4,335,283
Producing oil and gas properties held for transfer................................. -- 3,525,841
Other current assets............................................................... 887,491 68,010
------------ ------------
Total Current Assets.......................................................... 43,380,454 39,208,418
------------ ------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized............................................... 132,673,707 93,368,795
Unproved properties not being amortized......................................... 20,652,151 14,805,479
------------ ------------
153,325,858 108,174,274
Furniture, fixtures, and other equipment........................................... 4,367,719 3,476,695
------------ ------------
157,693,577 111,650,969
Less - Accumulated depreciation, depletion, and amortization....................... (30,169,303) (21,364,949)
------------ ------------
127,524,274 90,286,020
------------ ------------
Other Assets:
Receivables from associated limited partnerships, net of current portion........... 2,332,355 1,916,477
Limited partnership formation and marketing costs.................................. 858,559 2,991,873
Deferred charges................................................................... 1,157,065 1,269,955
------------ ------------
4,347,979 6,178,305
------------ ------------
$175,252,707 $135,672,743
------------ ------------
------------ ------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Short-term bank borrowings........................................................ $ -- $ 27,229,000
Accounts payable and accrued liabilities.......................................... 23,075,982 9,516,005
Payable to associated limited partnerships........................................ 16,983 637,991
Undistributed oil and gas revenues................................................ 17,040,304 14,962,863
------------ ------------
Total Current Liabilities ,.................................................. 40,133,269 52,345,859
------------ ------------
Long-Term Debt...................................................................... 28,750,000 28,750,000
Deferred Revenues................................................................... 6,063,467 7,827,562
Deferred Income Taxes............................................................... 6,960,006 4,622,191
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.O1 par value, 5,000,000 shares authorized, none outstanding... -- --
Common stock, $.O1 par value, 35,000,000 shares authorized, 12,509,700
and 6,685,137 shares issued and outstanding, respectively...................... 125,097 66,851
Additional paid-in capital....................................................... 71,133,979 24,885,903
Retained earnings................................................................ 22,086,889 17,174,377
------------ ------------
93,345,965 42,127,131
------------ ------------
$175,252,707 $135,672,743
------------ ------------
------------ ------------
</TABLE>
See accompanying notes to Consolidated Financial Statements.
20
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
- -------------------------------------------------------------------------------
Swift Energy Company and Subsidiaries
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Revenues:
Oil and gas sales........................................................ $22,527,892 $ 19,802,188 $15,535,671
Earned interests from limited partnerships and joint ventures............ - - 3,308,623
Fees from limited partnerships and joint ventures........................ 590,441 701,528 763,347
Supervision fees......................................................... 3,838,815 3,751,061 3,718,829
Interest income.......................................................... 212,329 47,980 201,584
Other, net............................................................... 1,761,568 1,072,535 604,599
----------- ------------ -----------
28,931,045 25,375,292 24,132,653
----------- ------------ -----------
Costs and Expenses:
General and administrative, net of reimbursement......................... 5,256,184 5,197,899 5,065,323
Depreciation, depletion, and amortization ............................... 8,838,657 7,904,801 7,300,967
Oil and gas production................................................... 6,826,306 5,639,630 4,540,290
Interest expense, net.................................................... 1,115,361 1,795,133 597,465
----------- ------------ -----------
22,036,508 20,537,463 17,504,045
----------- ------------ -----------
Income Before Income Taxes.................................................. 6,894,537 4,837,829 6,628,608
Provision for Income Taxes.................................................. 1,982,025 1,112,158 1,732,355
----------- ----------- -----------
Income Before Cumulative Effect of Change in Accounting Principle........... 4,912,512 3,725,671 4,896,253
Cumulative Effect of Change in Accounting Principle......................... - (16,772,698) -
----------- ------------ -----------
Net Income (Loss)........................................................... $ 4,912,512 $(13,047,027) $ 4,896,253
----------- ------------ -----------
----------- ------------ -----------
Per Share Amounts-
Primary:
Income Before Cumulative Effect of Change in Accounting Principle........ $ 0.54 $ 0.56 $ 0.74
----------- ------------ -----------
----------- ------------ -----------
Cumulative Effect of Change in Accounting Principle...................... $ - $ (2.52) $ -
----------- ------------ -----------
----------- ------------ -----------
Net Income (Loss)........................................................ $ 0.54 $ (1.96) $ 0.74
----------- ------------ -----------
----------- ------------ -----------
Fully Diluted:
Income Before Cumulative Effect of Change in Accounting Principle........ $ 0.54 $ 0.56 $ 0.70
----------- ------------ -----------
----------- ------------ -----------
Cumulative Effect of Change in Accounting Principle...................... $ - $ (2.52) $ -
----------- ------------ -----------
----------- ------------ -----------
Net Income (Loss)........................................................ $ 0.54 $ (1.96) $ 0.70
----------- ------------ -----------
----------- ------------ -----------
Weighted Average Shares Outstanding......................................... 9,122,857 6,644,248 6,588,076
----------- ------------ -----------
----------- ------------ -----------
PRO FORMA AMOUNTS ASSUMING CHANGE IN ACCOUNTING FOR EARNED
INTERESTS IS APPLIED RETROACTIVELY (SEE NOTE 2)-
Net Income............................................................... $ 3,725,671 $ 4,322,478
Per Share Amounts-
Primary................................................................ $ 0.56 $ 0.66
Fully Diluted.......................................................... $ 0.56 $ 0.63
</TABLE>
See accompanying notes to Consolidated Financial Statements.
21
<PAGE>
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
- -------------------------------------------------------------------------------
Swift Energy Company and Subsidiaries
<TABLE>
<CAPTION>
ADDITIONAL
COMMON PAID-IN RETAINED
STOCK(1) CAPITAL EARNINGS TOTAL
--------- ----------- ------------ ------------
<S> <C> <C> <C> <C>
Balance, December 31, 1992............................ $ 59,686 $17,227,567 $ 31,994,033 $ 49,281,286
Stock issued for benefit plans (19,096 shares)...... 191 170,059 - 170,250
Stock options exercised (13,400 shares)............. 134 117,791 - 117,925
Net income.......................................... - - 4,896,253 4,896,253
-------- ----------- ------------ ------------
Balance, December 31, 1993............................ $ 60,011 $17,515,417 $ 36,890,286 $ 54,465,714
Stock issued for benefit plans (26,488 shares)...... 265 271,176 - 271,441
Stock options exercised (21,472 shares)............. 214 176,808 - 177,022
Employee stock purchase plan (29,840 shares)........ 298 259,683 - 259,981
10% stock dividend (606,262 shares)................. 6,063 6,662,819 (6,668,882) -
Net loss............................................ - - (13,047,027) (13,047,027)
-------- ----------- ------------ ------------
Balance, December 31, 1994............................ $ 66,851 $24,885,903 $ 17,174,377 $ 42,127,131
Stock issued for benefit plans (31,113 shares)...... 311 283,463 - 283,774
Stock options exercised (5,761 shares).............. 58 33,736 - 33,794
Employee stock purchase plan (37,689 shares)........ 377 289,465 - 289,842
Stock issued in public offering (5,750,000 shares).. 57,500 45,641,412 - 45,698,912
Net income.......................................... - - 4,912,512 4,912,512
-------- ----------- ------------ ------------
Balance, December 31, 1995............................ $125,097 $71,133,979 $ 22,086,889 $ 93,345,965
-------- ----------- ------------ ------------
-------- ----------- ------------ ------------
</TABLE>
(1) $.O1 par value.
See accompanying notes to Consolidated Financial Statements.
22
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
- -------------------------------------------------------------------------------
Swift Energy Company and Subsidiaries
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1995 1994 1993
------------ ------------ ------------
<S> <C> <C> <C>
Cash Flows from Operating Activities:
Net income (loss)....................................................... $ 4,912,512 $(13,047,027) $ 4,896,253
Adjustments to reconcile net income to net cash provided
by operating activities-
Depreciation, depletion, and amortization........................... 8,838,657 7,904,801 7,300,967
Deferred income taxes............................................... 2,326,162 963,324 1,199,057
Earned interests from limited partnerships and joint ventures....... - - (3,308,623)
Deferred revenue amortization related to production payment......... (1,787,974) (1,993,863) (2,304,080)
Cumulative effect of change in accounting principle................. - 16,772,698 -
Other............................................................... 112,890 105,180 49,865
Change in assets and liabilities-
Increase in accounts receivable.................................. (488,599) (762,789) (412,960)
Increase in accounts payable and accrued liabilities,
excluding income taxes payable................................ 1,074,532 142,883 110,324
Increase (decrease) in income taxes payable...................... (611,717) 309,307 (292,463)
------------ ------------ ------------
Net Cash Provided by Operating Activities..................... 14,376,463 10,394,514 7,238,340
------------ ------------ ------------
Cash Flows from Investing Activities:
Additions to property and equipment..................................... (40,032,944) (34,531,180) (24,229,103)
Proceeds from the sale of property and equipment........................ 230,242 861,073 157,972
Net cash received (distributed) as operator of oil and gas properties... 7,662,419 (229,351) (2,556,483)
Property acquisition costs (incurred on behalf of) reimbursed
by partnerships and joint ventures.................................. 5,316,693 (1,408,031) (10,252,142)
Limited partnership formation and marketing costs....................... - - (103,871)
Prepaid drilling costs.................................................. - - (1,100,076)
Other................................................................... (41,181) (25,320) (98,437)
------------ ------------ ------------
Net Cash Provided by (Used in) Investing Activities........... (26,864,771) (35,332,809) (38,182,140)
------------ ------------ ------------
Cash Flows from Financing Activities:
Proceeds from long-term debt............................................ - - 28,750,000
Net proceeds from (payments of) short-term bank borrowings.............. (27,229,000) 24,579,000 2,650,000
Net proceeds from issuances of common stock............................. 46,306,322 708,444 288,175
Payments of debt issuance costs......................................... - - (1,425,000)
------------ ------------ ------------
Net Cash Provided by Financing Activities..................... 19,077,322 25,287,444 30,263,175
------------ ------------ ------------
Net Increase (Decrease) in Cash and Cash Equivalents....................... $ 6,589,014 $ 349,149 $ (680,625)
Cash and Cash Equivalents at Beginning of Year............................. 985,498 636,349 1,316,974
------------ ------------ ------------
Cash and Cash Equivalents at End of Year................................... $ 7,574,512 $ 985,498 $ 636,349
------------ ------------ ------------
------------ ------------ ------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION:
Cash paid during year for interest, net of amounts capitalized............. $ 68,097 $ 1,691,400 $ 605,063
Cash paid during year for income taxes .................................... $ 277,580 $ 97,200 $ 756,761
</TABLE>
See accompanying notes to Consolidated Financial Statements.
23
<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
is engaged in the acquisition, development, operation, and exploration of oil
and natural gas properties, with particular emphasis on U.S. onshore natural
gas reserves. The Company also has oil and gas investments in Russia,
Venezuela, and New Zealand. The Company's investments in associated oil and
gas partnerships and its joint ventures are accounted for using the
proportionate consolidation method, whereby the Company's proportionate share
of each entity's assets, liabilities, revenues, and expenses is included in
the appropriate classifications in the consolidated financial statements.
Intercompany balances and transactions have been eliminated in preparing the
consolidated statements. Certain reclassifications have been made to prior
year amounts to conform to the current year presentation.
USE OF ESTIMATES. The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities, if any, at
the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period.
PROPERTY AND EQUIPMENT. The Company follows the "full-cost" method of
accounting for oil and gas property and equipment costs. Under this method
of accounting, all productive and nonproductive costs incurred in the
acquisition, exploration, and development of oil and gas reserves are
capitalized. Such costs include lease acquisitions, geological and
geophysical services, drilling, completion, equipment, and certain general
and administrative costs directly associated with acquisition, exploration,
and development activities. General and administrative costs related to
production and general overhead are expensed as incurred. No gains or losses
are recognized upon the sale or disposition of oil and gas properties, except
in transactions that involve a significant amount of reserves. The proceeds
from the sale of oil and gas properties are generally treated as a reduction
of oil and gas property costs. Fees from associated oil and gas exploration
and development limited partnerships are credited to oil and gas property
costs to the extent they do not represent reimbursement of general and
administrative expenses currently charged to expense.
Future development, site restoration, and dismantlement and abandonment
costs, net of salvage values, are estimated on a property-by-property basis
based on current economic conditions and are amortized to expense as the
Company's capitalized oil and gas property costs are amortized. The
Company's properties are all onshore and historically the salvage value of
the tangible equipment offsets the Company's site restoration and
dismantlement and abandonment costs. The Company expects this relationship
will continue.
The Company computes the provision for depreciation, depletion, and
amortization of oil and gas properties on the unit-of-production method.
Under this method, the Company computes the provision by multiplying the
total unamortized costs of oil and gas properties-including future
development, site restoration, and dismantlement and abandonment costs but
excluding costs of unproved properties-by an overall rate determined by
dividing the physical units of oil and gas produced during the period by the
total estimated units of proved oil and gas reserves. The cost of unproved
properties not being amortized is assessed quarterly to determine whether the
value has been impaired below the capitalized cost. Any impairment assessed
is added to the cost of proved properties being amortized.
At the end of each quarterly reporting period, the unamortized cost of
oil and gas properties, net of related deferred income taxes, is limited to
the sum of the estimated future net revenues from proved properties using
current prices, discounted at 10%, and the lower of cost or fair value of
unproved properties, adjusted for related income tax effects ("Ceiling
Limitation").
The calculation of the Ceiling Limitation and provision for
depreciation, depletion, and amortization is based on estimates of proved
reserves. There are numerous uncertainties inherent in estimating quantities
of proved reserves and in projecting the future rates of production, timing,
and plan of development. The accuracy of any reserves estimate is a function
of the quality of available data and of engineering and geological
interpretation and judgment. Results of drilling, testing, and production
subsequent to the date of the estimate may justify revision of such estimate.
Accordingly, reserves estimates are often different from the quantities of
oil and gas that are ultimately recovered.
All other equipment is depreciated by the straight-line method at rates
based on the estimated useful lives of the property. Repairs and maintenance
are charged to expense as incurred. Renewals and betterments are capitalized.
DEFERRED CHARGES. Legal and accounting fees, underwriting fees,
printing costs, and other direct expenses associated with the issuance of the
Company's Convertible Subordinated Debentures in June 1993 have been
capitalized and are being amortized over the life of the Debentures, which
mature on June 30, 2003. The balance at December 31, 1995, is net of
accumulated amortization of $267,935.
LIMITED PARTNERSHIPS AND JOINT VENTURES. Between 1991 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.
24
<PAGE>
Under the Swift Depositary Interests limited partnership offering ("SDI
Offering"), which commenced in March 1991 and concluded after the formation
of its last two partnerships on December 14, 1995, the Company received a
reimbursement of certain costs and a fee, both payable out of revenues. The
Company bore all front-end costs of the offering and partnership formations
for which it received an interest in the partnerships. Prior to 1994 the
Company recognized as revenue fees (earned interests) received in the form of
additional interests in producing oil and gas properties acquired by these
entities. As described in Note 2, effective January 1, 1994, the Company
changed its revenue recognition policy for earned interests and under its
newly adopted policy, will no longer recognize earned interests as revenue.
The Company acquires producing oil and gas properties and transfers
those properties to the entities at cost, including interest, other carrying
costs, closing costs, and screening and evaluation costs of properties not
acquired, or in certain instances at fair market value based upon the opinion
of an independent expert. These costs are reduced by net operating revenues
from the effective date of the acquisition to the date of transfer to the
entities. Such net operating revenue amounts totaled approximately $600,000,
$4,100,000, and $3,200,000 in 1995, 1994, and 1993, respectively.
Certain designated oil and gas properties acquired in advance of
formation of partnerships or joint ventures and held by the Company pending
resale to those partnerships or joint ventures are classified as "Producing
oil and gas properties held for transfer."
Commencing September 15, 1993, the Company began offering, on a private
placement basis, general and limited partnership interests in 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
this offering, for which the Company receives an interest in the
partnerships. Through December 31, 1995, approximately $19,900,000 had been
raised in five partnerships in which the proceeds are to be invested in
development drilling and exploratory drilling. The first five partnerships
closed December 8, 1993, July 18, 1994, March 15, 1995, August 1, 1995, and
December 8, 1995.
Costs of syndication, registration, 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. Upon the Company's decision to conclude the SDI offering at the
end of 1995, the remaining limited partnership formation and marketing costs
related to the SDI offering (approximately $1,750,000) were accordingly
transferred to the oil and gas properties account.
HEDGING ACTIVITIES. The Company's revenues are primarily the result of
sales of its oil and natural gas production. Market prices of oil and
natural gas may fluctuate and adversely affect operating results. To
mitigate some of this risk, the Company does engage periodically in certain
limited hedging activities, but only to the extent of buying protection price
floors for portions of its and the limited partnerships' oil and gas
production. Costs and/or benefits derived from these price floors are
accordingly recorded as a reduction or increase in oil and gas sales revenue
and was not significant for any year presented.
INCOME (LOSS) PER SHARE. Primary income (loss) per share has been
computed using the weighted average number of common shares outstanding
during the respective periods. Stock options and warrants outstanding do not
have a dilutive effect on primary income (loss) per share. The Company's
Convertible Subordinated Debentures are not common stock equivalents for the
purpose of computing primary income (loss) per share.
Primary income (loss) per share has been retroactively restated in all
periods presented to give recognition to an equivalent change in capital
structure as a result of a 10% stock dividend. On September 6, 1994, the
Company declared a 10% stock dividend to shareholders of record on September
19, 1994, which was distributed on September 29, 1994, resulting in an
additional 606,262 shares being issued.
The calculation of fully diluted income (loss) per share assumes
conversion of the Company's Convertible Subordinated Debentures as of the
beginning of the period and the elimination of the related after-tax interest
expense and assumes, as of the beginning of the period, exercise (using the
treasury stock method) of stock options and warrants. The conversion price
of the Convertible Subordinated Debentures was revised to reflect the 10%
stock dividend declared September 6, 1994. The original conversion price was
$13.50 per common share and the revised conversion price per common share is
$12.27. Fully diluted income (loss) per share has also been retroactively
restated for all periods presented to give effect to the resulting conversion
price revision stemming from the 10% stock dividend. The weighted average
number of shares used in the computation of fully diluted per share amounts
were 11,671,243, 9,053,736, and 7,797,660 for the respective years ended
December 31, 1995, 1994, and 1993.
INCOME TAXES. The Company accounts for Income Taxes using Statement of
Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes."
SFAS No. 109 utilizes the liability method and deferred taxes are determined
based on the estimated future tax effects of differences between the
financial statement and tax bases of assets and liabilities given the
provisions of the enacted tax laws.
DEFERRED REVENUES. In May 1992, as discussed in Note 9 "Oil and Gas
Producing Activities," the Company purchased interests in certain wells using
funds provided by the Company's sale of a volumetric production payment in
these properties. Under the terms of the production payment agreement, the
Company continues to own the properties purchased but is required to deliver
a minimum quantity of hydrocarbons produced from the properties (meeting
certain quality and heating equivalent requirements) over a specified period.
Since entering into this agreement, the Company has met all scheduled
deliveries. Net proceeds from the sale of the production
25
<PAGE>
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.
VULNERABILITY DUE TO CERTAIN CONCENTRATIONS. The Company extends credit
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 is mitigated by the size, reputation, and nature of the companies to
which the Company extends credit.
Only one single oil or gas purchaser accounted for 10% or more of the
Company's consolidated revenues during the year ended December 31, 1995, with
that purchaser accounting for approximately 12%. The Company does not
believe that the loss of any single oil and gas purchaser or contract would
materially affect its sales.
FAIR VALUE OF FINANCIAL INSTRUMENTS. The Company's financial
instruments consist of cash and cash equivalents, accounts receivable,
accounts payable, and long-term debt. The carrying amounts of cash and cash
equivalents, accounts receivable, and accounts payable approximate fair value
due to the highly liquid nature of these short-term instruments. The fair
value of long-term debt was determined based upon interest rates currently
available to the Company for borrowings with similar terms. The fair value
of long-term debt approximates the carrying amount as of December 31, 1995.
- -------------------------------------------------------------------------------
2. CHANGE IN ACCOUNTING PRINCIPLE
In the fourth quarter of 1994, the Company changed its revenue
recognition policy for earned interests, effective January 1, 1994. Under
the Company's current method of accounting for earned interests, such amounts
will not be recognized as income, thereby reducing the Company's investment
in oil and gas property. This change was made as the result of a transition
in the Company's current business activities and changes in the oil and gas
limited partnership syndication markets. The Company feels the change in
policy results in more comparable financial statements in relation to its
current business focus and in comparison to its current peers and competitors
in the oil and gas exploration and production industry.
The effect of the change was to increase 1994 income before cumulative
effect of change in accounting principle by approximately $1,047,000 or $.16
per share. This increase was a result of the decrease in current year
depletion expense more than offsetting the decrease in revenues as a result
of not recognizing earned interests. The cumulative effect of this change in
accounting principle resulted in a downward adjustment to earnings of
$16,772,698 or $2.52 per share (after reduction for income taxes of
$8,640,481), to retroactively apply the new method, thereby reducing net
income in 1994. See Note 9 to the Company's financial statements for the
effect this change had on oil and gas properties and accumulated
depreciation, depletion, and amortization. The pro forma amounts shown on the
income statement have been adjusted for the effect of retroactive
application, had the new method been in effect during the periods presented.
- -------------------------------------------------------------------------------
3. PROVISION FOR INCOME TAXES
The Omnibus Budget Reconciliation Act of 1993 (the "Act") was enacted on
August 10, 1993. The Act contains several changes to federal income tax
provisions, including an increase in the highest corporate tax rate from 34%
to 35%, for companies with taxable income in excess of $10,000,000. The
effect of the Act on income tax expense for the year ended December 31, 1993,
and the Company's net deferred tax liability was not material.
The following is an analysis of the consolidated income tax provision:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------
1995 1994 1993
---------- ---------- ----------
<S> <C> <C> <C>
Current........... $ (344,137) $ 148,834 $ 533,298
Deferred.......... 2,326,162 963,324 1,199,057
---------- ---------- ----------
Total............. $1,982,025 $1,112,158 $1,732,355
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
There are differences between income taxes computed using the statutory
rate (34% for 1995, 1994, and 1993) and the Company's effective income tax
rates (28.7%, 23.0%, and 26.1% for 1995, 1994, and 1993, 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>
1995 1994 1993
---------- ---------- ----------
<S> <C> <C> <C>
Income taxes computed at federal statutory rate..... $2,344,143 $1,644,862 $2,253,727
State tax provisions, net of federal benefits....... 84,202 46,525 149,002
Nonconventional fuel source credit.................. (370,000) (435,016) (553,651)
Depletion deductions in excess of basis............. (34,000) (30,895) (98,596)
Other, net.......................................... (42,320) (113,318) (18,127)
---------- ---------- ----------
Provision for income taxes.......................... $1,982,025 $1,112,158 $1,732,355
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
26
<PAGE>
The tax effects of significant temporary differences representing the
net deferred tax liability at December 31, 1995, 1994, and 1993 were as
follows:
<TABLE>
<CAPTION>
1995 1994 1993
------------- ------------ ------------
<S> <C> <C> <C>
Deferred tax assets:
Alternative minimum tax credits $ 1,372,978 $ 900,562 $ 786,774
Other 115,332 7,112 231,292
------------- ------------ ------------
Total deferred tax assets $ 1,488,310 $ 907,674 $ 1,018,066
Deferred tax liabilities:
Oil and gas properties $ 7,682,701 $ 4,811,886 $ 12,576,208
Other 650,283 614,300 637,527
------------- ------------ ------------
Total deferred tax liabilities $ 8,332,984 $ 5,426,186 $ 13,213,735
------------- ------------ ------------
Net deferred tax liability(1) $ 6,844,674 $ 4,518,512 $ 12,195,669
------------- ------------ ------------
------------- ------------ ------------
</TABLE>
(1) This amount includes current deferred tax asset amounts of
$115,332. $103,679, and $96,567 for 1995, 1994. and 1993,
respectively.
The Company did not record any valuation allowances against deferred tax
assets at December 31, 1995, 1994, and 1993.
At December 31, 1995, the Company had an alternative minimum tax carry
forward of $1,372,978 indefinitely available to reduce future regular tax
liability to the extent it exceeds the related tentative minimum tax
otherwise due.
- ------------------------------------------------------------------------------
4. SHORT-TERM BANK BORROWINGS
The Company had available, through a two-bank group, a revolving line of
credit of $35,000,000 at the end of 1995 and $29,000,000 at the end of 1994
bearing interest at the bank's base rate plus 0.5% (9% at both December 31,
1995, and at December 31, 1994), secured by the Company's interests in
certain oil and gas properties and general partner interests. This facility
also allows, at the Company's option, draws which bear interest for specific
periods at the London Interbank Offered Rate ("LIBOR") plus 2.25%. There was
no outstanding balance under this line of credit at December 31, 1995. At
December 31, 1994, $14,000,000 of the $18,600,000 outstanding was at the
LIBOR plus 2.25% rates (7.875% on $3,000,000, 8.1875% on $6,000,000, and
8.5% on $5,000,000). The outstanding amount under this facility at December
31, 1994 ($18,600,000) was borrowed primarily to fund the advance purchase of
producing properties on behalf of affiliated partnerships and/or joint
ventures to be subsequently reimbursed and to fund the Company's working
capital and capital expenditures needs. This credit agreement is currently
being restated and the facility will be unsecured with a maximum of
$100,000,000. The available borrowing base currently will not change and
will be redetermined periodically. Depending on the level of outstanding
debt, the interest rate currently will be either the bank's base rate or the
bank's base rate plus 0.25%. The LIBOR option will now vary from plus 1% to
plus 1.5%.
The terms of the revolving line of credit include, among other
restrictions, a limitation on the level of cash dividends (not to exceed
$424,000 in any fiscal year), requirements as to maintenance of certain
minimum financial ratios (principally pertaining to working capital, debt,
and equity ratios) and limitations on incurring other debt. Since inception,
no cash dividends have been declared on the Company's common stock. The
Company presently intends to continue a policy of using retained earnings for
expansion of its business. As of December 31, 1995, the Company was in
compliance with the provisions of these agreements. The revolving line of
credit will extend through September 30, 1999.
The Company's second credit line was an Acquisition Advance Agreement
with the same two-bank group, bearing interest at the greater of (a) the
bank's base rate plus 1% or (b) the Federal Funds rate plus 1.5%, to be
secured by producing oil and gas properties acquired and held for transfer.
At December 31, 1994, $3,629,000 had been borrowed under this agreement to
fund the advance purchase of producing properties on behalf of affiliated
partnerships and/or joint ventures to be subsequently reimbursed. This credit
agreement expired June 15, 1995.
The Company's third credit facility is an amended and restated revolving
line of credit with the lead bank for $5,000,000, bearing interest at the
bank's base rate (8.5% at both December 31, 1995, and at December 31, 1994),
secured by certain Company receivables. There were no outstanding amounts
under this facility at December 31, 1995. At December 31, 1994, $5,000,000
was outstanding under this facility. This facility is currently being
amended to $7,000,000, with interest at the bank's base rate plus 0.25%. This
credit facility will extend through September 30, 1999.
In addition to interest on these credit facilities, the Company pays a
commitment fee to compensate the banks for making funds available. The fee
on the revolving line of credit is calculated on the average daily remainder,
if any, of the commitment amount less the aggregate principal amounts
outstanding, plus the amount of all letters of credit outstanding during the
period. The fee on the Acquisition Advance Agreement was 0.5% of the amount
of the advance. The aggregate amounts of commitment fees paid by the Company
were $154,000 in 1995 and $150,000 in 1994.
- ------------------------------------------------------------------------------
5. LONG-TERM DEBT
The Company's long-term debt consists of $28,750,000 of 6.5% Convertible
Subordinated Deben-
27
<PAGE>
tures ("Debentures"). The Debentures were issued on June 30, 1993, and will
mature on June 30, 2003. The Debentures are convertible into common stock of
the Company by the holders at any time prior to maturity at a conversion
price of $12.27 per share, subject to adjustment upon the occurrence of
certain events. The conversion price reflects an adjustment of the original
conversion price of $13.50 per share to reflect the 10% stock dividend
declared September 6, 1994, and distributed September 29, 1994. Interest on
the Debentures is payable semi-annually on June 30 and December 31, commencing
with the payment made at December 31, 1993. After June 30, 1997 (or in certain
circumstances after June 30,1996), the Debentures are redeemable for cash at
the option of the Company, with certain restrictions, at 104.55% of principal,
declining to 100.65% in 2002. Upon certain changes in control of the Company,
if the price of the Company's common stock is not above certain levels each
holder of Debentures will have the right to require the Company to repurchase
the Debentures at the principal amount thereof, together with accrued and unpaid
interest to the date of repurchase but after the repayment of any Senior
Indebtedness, as defined.
Interest expense on the Debentures, including amortization of debt
issuance costs, totaled $1,981,639, $1,973,931, and $984,239 for 1995, 1994,
and 1993, respectively.
- ------------------------------------------------------------------------------
6. COMMITMENTS AND CONTINGENCIES
Total rental and lease expenses charged to earnings before reimbursements
were $998,714 in 1995, $1,159,673 in 1994, and $1,155,564 in 1993. The
Company's remaining minimum annual obligations under non-cancelable operating
lease commitments are $1,016,616 for 1996, $1,083,830 for 1997, $1,159,185
for 1998, $1,207,707 for 1999, and $1,201,448 for 2000.
As of December 31, 1995, the Company is the managing general partner of
101 limited partnerships. Because the Company serves as the general partner
of these entities, under state partnership law it is contingently liable for
the liabilities of these partnerships, which liabilities are not material for
any of the periods presented in relation to the partnerships' respective
assets. These partnership liabilities generally consist of third party
borrowings from time to time to fund capital expenditures for development of
oil and gas properties, and will be repaid from oil and gas sales proceeds of
the partnerships in future periods.
In the ordinary course of business, the Company has been party to
various legal actions, which arise primarily from its activities as operator
of oil and gas wells. In management's opinion, the outcome of any such
currently pending actions will not have a material adverse effect on the
financial position or results of operations of the Company.
- ------------------------------------------------------------------------------
7. STOCKHOLDERS' EQUITY
COMMON STOCK. On September 6, 1994, the Company declared a 10% stock
dividend to shareholders of record on September 19, 1994, which was
distributed on September 29, 1994. The transaction was valued based on the
closing price ($11.00) of the Company's common stock on the New York Stock
Exchange on September 6, 1994. As a result of the issuance of 606,262 shares
of the Company's common stock as a dividend, retained earnings were reduced
by $6,668,882, with the common stock and additional paid-in capital accounts
increased by the same amount. Primary and fully diluted income (loss) per
share was restated for all periods presented to reflect the effect of the
stock dividend.
During the third quarter of 1995, the Company closed the sale to the
public of 5,750,000 shares of common stock at a price of $8.50 per share.
Net proceeds from this offering were $45,698,912 and were used to repay
outstanding indebtedness, with the remaining proceeds being used to finance
the Company's exploration and development activities, and to acquire
producing oil and gas properties, including limited partnership interests.
STOCK OPTIONS AND WARRANTS. The Company has an employee option plan
under which incentive stock options and other options and awards may be
granted to employees to purchase shares of common stock and a nonqualified
stock option plan under which non-employee members of the Company's Board of
Directors may be granted options to purchase shares of common stock. The
plans provide that the exercise prices equal 100% of the fair value of the
common stock on the date of grant. Options become exercisable for 20% of the
shares on the first anniversary of the grant of the option and are
exercisable for an additional 20% per year thereafter. Options granted
expire 10 years after the date of grant or earlier in the event of the
optionee's separation from employment. No accounting entries are required
until the stock options are exercised, at which time the option price is
credited to the common stock and additional paid-in capital accounts. The
effect of the 10% stock dividend increased the number of shares and decreased
the price according to the respective agreements.
The following is a summary of stock options under these plans:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1995 1994
<S> <C> <C>
Options outstanding,
beginning of period 1,166,920 899,650
Options granted 227,502 202,760
Options terminated (80,270) (20,658)
Options exercised (5,761) (21,472)
Options adjusted for
stock dividend - 106,640
---------------- ----------------
Options outstanding,
end of period 1,308,391 1,166,920
---------------- ----------------
---------------- ----------------
Options exercisable,
end of period 722,627 546,172
---------------- ----------------
---------------- ----------------
Options available for
future grant, end
of period 343,344 498,909
---------------- ----------------
---------------- ----------------
Option price range:
Options granted $7.045 - $10.114 $9.091 - $10.25
Options terminated $7.045 - $10.114 $7.045 - $12.386
Options exercised $7.045 - $10.114 $7.045 - $ 9.773
Options outstanding,
end of period $5.455 - $12.386 $5.455 - $12.386
</TABLE>
28
<PAGE>
The Company also has granted certain stock options to individuals who
are neither employees, officers, nor directors, for specific services
rendered to the Company. At December 31, 1995, the only outstanding options
under this plan were granted in 1991 covering 68,750 shares at $9.773 (after
adjustment for the September 1994 stock dividend). During the three years
ended December 31, 1995, the only other activity has been the cancellation of
5,350 option shares in 1993.
The Company also has a plan which provides eligible employees the
opportunity to acquire shares of Company common stock at a discount through
payroll deductions. This plan was approved at the May 11, 1993,
shareholders meeting. The plan year is from June 1 to the following May 31.
The first year of the plan commenced June 1, 1993. Employees may authorize
payroll deductions of up to 10% of their base salary during the plan year by
making an election to participate prior to the start of a plan year. The
purchase price for stock acquired under the plan will be 85% of the lower of
the closing price of the Company's common stock as quoted on the New York
Stock Exchange at the beginning or end of the plan year or a date during the
year chosen by the participant. The Company issued 37,689 and 29,840 shares
under this plan at a range of prices of $6.80 to $7.92 and a price of $8.71
during 1995 and 1994, respectively. As of December 31,1995, there were
479,487 shares available for issuance under this plan. There are no charges
or credits to income in connection with this plan.
In October 1995 the FASB issued SFAS No. 123, "Accounting for
Stock-Based Compensation," which establishes accounting and reporting
standards for stock-based employee compensation plans. SFAS No. 123 defines
a fair value-based method of accounting for stock options or similar equity
instruments, but allows companies to continue to measure compensation cost
using the intrinsic value-based method prescribed by Accounting Principles
Board Opinion ("APB") No. 25, "Accounting for Stock Issued to Employees."
Under the fair value-based method, compensation cost is measured at the grant
date based on the value of the award and is recognized over the service
period (generally, the vesting period). Under the intrinsic value-based
method, compensation cost is the excess, if any, of the quoted market price
of the stock at the date of grant over the exercise price.
Under the provisions of SFAS No. 123, a company may elect to measure
compensation cost associated with its stock option and similar plans as a
component of compensation expense in its statement of operations. Companies
may also elect to continue to measure compensation cost under the provisions
of APB No. 25. Companies which elect to continue measurement under APB No.
25 are required to provide pro forma disclosure in the notes to financial
statements reflecting the difference, if any, between compensation cost
included in net income and the cost if the fair value-based method were used
including effects on earnings per share. Since the inception of the Option
Plan, the Company has not recognized any compensation cost related to grants
of stock options. The disclosure requirements of this statement are
effective for financial statements for fiscal years beginning after December
15, 1995. At this time, the Company does not expect to adopt the fair value
based method of accounting for its stock option plans and, accordingly,
adoption of this statement will have no impact on the Company's results of
operations.
- ------------------------------------------------------------------------------
8. 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 $4,800,000, $4,400,000, and $4,200,000, in 1995,1994,
and 1993, 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 $600,000, $1,400,000, and
$2,500,000 in 1995, 1994, and 1993, respectively.
- -------------------------------------------------------------------------------
9. OIL AND GAS PRODUCING ACTIVITIES
CAPITALIZED COSTS. The following table presents the Company's aggregate
capitalized costs relating to oil and gas producing activities and the
related depreciation, depletion, and amortization:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1995 1994
------------- -------------
<S> <C> <C>
Oil and Gas Properties:
Proved............................ $ 132,673,707 $ 93,368,795(1)
Unproved (not being amortized).... 20,652,151 14,805,479
------------- -------------
153,325,858 108,174,274
Accumulated Depreciation, Depletion,
and Amortization.................. (28,107,986) (19,758,662)(1)
------------- -------------
$ 125,217,872 $ 88,415,612
------------- -------------
------------- -------------
</TABLE>
(1) The effect of the 1994 change in accounting principle (see Note 2) was
to decrease proved property costs by $37,773,087 and accumulated
depreciation, depletion, and amortization by $12,359,908.
29
<PAGE>
Of the $20,652,151 of net unproved property costs (primarily seismic and
lease acquisition costs) at December 31, 1995, being excluded from the
amortizable base, $8,825,568 was incurred in 1995, $6,977,963 was incurred
in 1994, $2,018,174 was incurred in 1993, and $2,830,446 was incurred in
prior years. The Company expects it will complete its evaluation of the
properties representing the majority of these costs within the next two to
three years.
CAPITAL EXPENDITURES. The following table sets forth capital expenditures
related to the Company's oil and gas operations:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1995 1994 1993
------------ ------------ ------------
<S> <C> <C> <C>
Acquisition of proved properties, including earned interests in limited
partnerships and joint ventures(1)......................................... $ 3,461,091 $ 13,078,242 $ 21,832,157
Lease acquisitions(2)(3)..................................................... 9,742,543 9,905,237 5,388,243
Exploration.................................................................. 2,289,814 4,003,400 2,195,473
Development.................................................................. 23,555,988 5,637,285 3,164,803
------------ ------------ ------------
Total(4)................................................................. $ 39,049,436 $ 32,624,164 $ 32,580,676
------------ ------------ ------------
------------ ------------ ------------
</TABLE>
(1) There are no earned interests in 1995 or in 1994. Earned interests amounts
included in 1993 are $3,308,623.
(2) Lease acquisitions for 1995, 1994, and 1993 include expenditures of
$2,814,395, $2,973,971, and $1,032,656, respectively, relating to the
Company's initiatives in Russia; 1995, 1994, and 1993 expenditures of
$304,610, $356,136, and $456,681, respectively, relating to initiatives
in Venezuela; and include 1995 expenditures of $202,206 relating to
initiatives in New Zealand.
(3) 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 1995, 1994, and 1993,
respectively, were $3,895,871, $3,032,315, and $4,198,429.
(4) Includes capitalized general and administrative costs directly associated
with the acquisition, development, and exploration efforts of approximately
$7,100,000, $5,800,000, and $8,300,000 in 1995, 1994, and 1993. In
addition, total includes $1,442,022, $766,572, and $389,352 in 1995, 1994,
and 1993, 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,
-------------------------------------------
1995 1994 1993
<S> <C> <C> <C>
Oil and gas sales...................................................... $ 22,527,892 $ 19,802,188 $ 15,535,671
Production costs....................................................... (6,826,306) (5,639,630) (4,540,290)
Depreciation, depletion, and amortization.............................. (8,349,324) (7,590,877) (7,067,636)
------------- ------------ ------------
7,352,262 6,571,681 3,927,745
Income taxes........................................................... (2,110,099) (1,511,487) (1,025,141)
------------- ------------ ------------
Results of producing activities........................................ $ 5,242,163 $ 5,060,194 $ 2,902,604
------------- ------------ ------------
------------- ------------ ------------
Amortization per physical unit of production (equivalent Mcf of gas)... $0.75 $0.79 $0.96
------------- ------------ ------------
------------- ------------ ------------
</TABLE>
PROPERTY PURCHASE AND PRODUCTION PAYMENT AGREEMENT. In May 1992, the
Company purchased from a subsidiary of Manville Corporation ("Manville")
additional interests in certain wells in McMullen County, Texas, in which the
Company had owned interests for over three years. The funds for this
purchase were provided by the Company's sale of a volumetric production
payment in the Manville properties to Enron Reserve Acquisition Corp.
("Enron") for net proceeds of $13,790,000. These proceeds were recorded as
deferred revenues and are amortized as the required deliveries are made.
Under the production payment agreement, the Company continues to own the
properties purchased from Manville, but is required to deliver to Enron
approximately 9.5 Bcf over an eight-year period, or for such longer period as
is necessary to deliver a specified heating equivalent quantity at an average
price of $1.115 per MMBtu. The Company is responsible for all production
related costs associated with operating these properties. The amount to be
delivered varies from month to month in generally decreasing quantities. To
the extent monthly gas production from the properties exceeds the agreed upon
deliverable quantities (as it has in every year since the purchase date), the
Company receives all proceeds from sale of such excess gas at current market
prices, plus the proceeds from sale of oil or condensate. Since entering
into the volumetric production payment, the Company has met all scheduled
deliveries to Enron under this agreement.
FOREIGN ACTIVITIES. On September 3, 1993, the Company signed a
Participation Agreement with Senega, a Russian Federation joint stock company
(in which the Company has an indirect interest of less than 1%), to assist in
the development and production of reserves from two fields in Western
Siberia. Under the terms of the Participation Agreement, the Company will
receive a minimum 5% net profits interest from the sale of hydrocarbon
products from the fields for providing managerial, technical and financial
support to Senega. Additionally, the Company purchased a 1% net profits
interest from Senega for $300,000. In May 1995, the Company executed a
Management Agreement with Senega. In return for obtaining financing for
development of these fields, Swift was given certain rights by Senega,
including a 49% interest in production income derived by Senega from this
project after repayment of costs. At December 31, 1995, the Company's
investment in Russia was approximately $6,820,000 and is included in the
unproved properties portion of oil and gas properties.
30
<PAGE>
The Company formed a wholly owned subsidiary, Swift Energy de Venezuela,
C.A., for the purpose of submitting a bid on August 5, 1993,
under the Venezuelan Marginal Oil Field Reactivation Program on the
Quiriquire Unit located in Northeastern Venezuela. Swift (together with a
minority interest holder) was one of six bidders on the Quiriquire Unit. The
Company did not win the bid for the Quiriquire Unit; however, other fields
and opportunities are continuing to be evaluated in Venezuela. At December
31, 1995, the Company's investment in Venezuela was approximately $1,120,000
and is included in the unproved properties portion of oil and gas properties
net of impairments of $45,668.
On October 12, 1995, the Company was approved for the grant of Petroleum
Exploration Permit by the New Zealand Minister of Energy and the acceptance
of which was approved by the Company's board of directors on November 7,
1995. This permit (PEP 38717) covers approximately 65,000 acres in the
Onshore Taranaki Basin region. This permit primarily requires the Company
to: (a) post a $175,000 bond (which was done by the Company on December 22,
1995) before January 11, 1996; (b) before December 31, 1997, analyze and
interpret approximately 460 kilometers of existing seismic data and acquire
approximately 100 kilometers of new seismic data; (c) commence drilling one
well prior to July 31, 1998; (d) review results prior to July 31,1999, and
(e) prior to July 31, 2000, drill a development well or acquire additional
seismic data. At December 31, 1995, the Company's investment in New Zealand
was approximately $200,000 and is included in the unproved properties portion
of oil and gas properties.
ACQUISITION OF PROPERTIES BY SWIFT. During the second quarter of 1994,
the Company acquired approximately $18,100,000 of producing oil and gas
properties in a single acquisition transaction. Approximately $3,500,000 and
$12,700,000 of the properties were transferred to affiliated partnerships
formed under the Company's SDI offering in 1995 and 1994, respectively.
Approximately $1,900,000 of the properties were retained by the Company for
its own account.
SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED). The following information
presents estimates of the Company's proved oil and gas reserves, which are
all located onshore in the United States. All of the Company's reserves were
determined by company personnel and audited by H. J. Gruy and Associates,
Inc. ("Gruy"), independent petroleum consultants. Gruy's summary report
dated February 19, 1996, is set forth as an exhibit to the Form 10-K Report
for the year ended December 31, 1995, 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, 1992(1)................. 41,638,100 2,901,621
Reserved of previous estimates(2)........................ (1,800,178) (200,906)
Purchases of minerals in place........................... 17,892,709 1,429,463
Sales of minerals in place............................... (61,996) (12,555)
Extensions, discoveries, and other additions............. 10,634,805 477,932
Production(3)............................................ (3,840,635) (324,486)
----------- ---------
Proved reserves as of December 31, 1993(1)................. 64,462,805 4,271,069
Revisions of previous estimates(2)....................... (10,570,138) (714,246)
Purchases of minerals in place........................... 8,136,270 790,523
Sales of minerals in place............................... (881,770) (34,834)
Extensions, discoveries, and other additions............. 20,556,953 707,811
Production(3)............................................ (5,440,156) (467,056)
----------- ---------
Proved reserves as of December 31, 1994(1)................. 76,263,964 4,553,267
Revisions of previous estimates(2)....................... 6,982,317 (421,901)
Purchases of minerals in place........................... 4,166,922 254,211
Sales of minerals in place............................... (13,215) (10,617)
Extensions, discoveries, and other additions............. 62,870,240 1,592,456
Production(3)............................................ (6,702,708) (545,435)
----------- ---------
Proved reserves as of December 31, 1995(1)................. 143,567,520 5,421,981
----------- ---------
----------- ---------
Proved developed reserves,
December 31, 1992......................................... 32,955,080 2,082,885
December 31, 1993......................................... 50,936,942 3,110,505
December 31, 1994......................................... 46,406,448 3,209,387
December 31, 1995......................................... 81,532,025 3,313,226
</TABLE>
(1) Proved reserves for these periods exclude quantities subject to the
Company's volumetric production payment agreement.
(2) Revisions of previous quantity estimates are related to upward or
downward variations based on current engineering information for
production rates, volumetrics, and reservoir pressure. Additionally,
changes in quantity estimates are affected by the increase or decrease
in crude oil and natural gas prices at each year end, Proved reserves as
of December 31, 1995, were based upon prices of $2.41 per Mcf of natural
gas and $18.07 per barrel of oil, compared to $1.85 per Mcf and $15.09
per barrel as of December 31, 1994.
(3) Natural gas production for 1993, 1994, and 1995 excludes 1,581,206,
1,358,375, and 1,211,255 Mcf, respectively, delivered under the Company's
volumetric production payment agreement.
31
<PAGE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED). The
standardized measure of discounted future net cash flows relating to proved
oil and gas reserves is as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1995 1994 1993
------------- ------------ ------------
<S> <C> <C> <C>
Future gross revenues....................... $ 445,572,715 $211,210,430 $218,321,639
Future production and development costs..... (163,925,771) (92,053,163) (75,769,590)
------------- ------------ ------------
Future net cash flows before income taxes... 281,646,944 119,157,267 142,552,049
Future income taxes......................... (55,469,213) (14,143,796) (26,303,502)
------------- ------------ ------------
Future net cash flows after income taxes.... 226,177,731 105,013,471 116,248,547
Discount at 10% per annum................... (97,273,647) (38,541,504) (41,280,376)
------------- ------------ ------------
Standardized measure of discounted future
net cash flows relating to proved oil
and gas reserves........................... $ 128,904,084 $ 66,471,967 $ 74,968,171
------------- ------------ ------------
------------- ------------ ------------
</TABLE>
The standardized measure of discounted future net cash flows from
production of proved reserves was developed as follows:
1. Estimates are made of quantities of proved reserves and the future
periods during which they are expected to be produced based on year-end
economic conditions.
2. The estimated future gross revenues of proved reserves are priced on
the basis of year-end prices, except in those instances where fixed and
determinable gas price escalations are covered by contracts, limited to the
price the Company reasonably expects to receive.
3. The future gross revenue streams are reduced by estimated future
costs to develop and to produce the proved reserves, as well as certain
abandonment costs based on year-end cost estimates and the estimated effect
of future income taxes.
4. Future income taxes are computed by applying the statutory tax rate
to future net cash flows reduced by the tax basis of the properties, the
estimated permanent differences applicable to future oil and gas producing
activities and tax carryforwards.
The estimates of cash flows and reserves quantities shown above are
based on year-end oil and gas prices. Under Securities and Exchange
Commission rules, companies that follow the full-cost accounting method are
required to make quarterly Ceiling Limitation calculations, using prices in
effect as of the period end date presented (see Note 1). Application of
these rules during periods of relatively low oil and gas prices, even if of
short-term seasonal duration, may result in write-downs.
The standardized measure of discounted future net cash flows is not
intended to present the fair market value of the Company's oil and gas
property reserves. An estimate of fair value would also take into account,
among other things, the recovery of reserves in excess of proved reserves,
anticipated future changes in prices and costs, an allowance for return on
investment, and the risks inherent in reserve estimates.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1995 1994 1993
------------ ------------ -----------
<S> <C> <C> <C>
Beginning balance............................... $ 66,471,967 $ 74,968,171 $46,582,994
------------ ------------ -----------
Revisions to reserves proved in prior years-
Net changes in prices, production costs, and
future development costs..................... 25,415,116 (21,326,677) (4,140,177)
Net changes due to revisions in quantity
estimates................................... 4,735,186 (11,644,586) (2,860,642)
Accretion of discount........................ 6,939,460 8,376,078 5,543,984
Other........................................ (10,981,721) (5,631,646) (4,485,723)
------------ ------------ -----------
Total revisions................................. 26,108,041 (30,226,831) (5,942,558)
New field discoveries and extensions, net of
future production and development costs........ 44,292,042 15,585,767 13,972,435
Purchases of minerals in place.................. 4,928,563 7,964,821 27,074,564
Sales of minerals in place...................... (74,858) (574,651) (85,174)
Sales of oil and gas produced, net of
production costs............................... (13,913,612) (12,168,695) (8,691,301)
Previously estimated development costs
incurred....................................... 16,303,629 5,053,417 1,992,967
Net change in income taxes...................... (15,211,688) 5,869,968 64,244
------------ ------------ -----------
Net change in standardized measure of discounted
future net cash flows.......................... 62,432,117 (8,496,204) 28,385,177
------------ ------------ -----------
Ending balance.................................. $128,904,084 $ 66,471,967 $74,968,171
------------ ------------ -----------
------------ ------------ -----------
</TABLE>
32
<PAGE>
10. QUARTERLY RESULTS (UNAUDITED)
The following table presents summarized quarterly financial information
for the years ended December 31, 1993, 1994, and 1995:
<TABLE>
<CAPTION>
NET INCOME PRIMARY INCOME FULLY DILUTED
INCOME BEFORE (LOSS) (LOSS) PER INCOME (LOSS)
REVENUES INCOME TAXES (AS RESTATED) SHARE (2) PER SHARE (2)
----------- ------------- ------------- -------------- -------------
<S> <C> <C> <C> <C> <C>
1993
First Quarter $ 5,325,054 $1,411,809 $ 988,266 $ .15 $ .15
Second Quarter 6,012,174 1,743,606 1,220,524 .19 .19
Third Quarter 6,603,605 1,905,880 1,441,549 .22 .19
Fourth Quarter 6,191,820 1,567,313 1,245,914 .19 .17
----------- ---------- ------------ ------ ------
Total $24,132,653 $6,628,608 $ 4,896,253 $ .74 $ .70
----------- ---------- ------------ ------ ------
----------- ---------- ------------ ------ ------
1994
First Quarter $ 6,138,535 $1,753,003 (1) $(15,561,976)(1) $(2.36)(1) $(2.36)(1)
Second Quarter 6,106,954 (1) 1,462,980 (1) 1,076,077 (1) .16 (1) .15 (1)
Third Quarter 6,962,612 1,439,620 (1) 1,130,398 (1) .17 (1) .16 (1)
Fourth Quarter 6,167,191 182,226 308,474 .05 .05
----------- ---------- ------------ ------ ------
Total $25,375,292 $4,837,829 $(13,047,027) $(1.96) $(1.96)
----------- ---------- ------------ ------ ------
----------- ---------- ------------ ------ ------
1995
First Quarter $ 6,258,588 $ 676,434 $ 524,600 $ .08 $ .08
Second Quarter 6,564,910 965,448 731,275 .11 .11
Third Quarter 7,048,934 1,737,763 1,264,556 .12 .12
Fourth Quarter 9,058,613 3,514,892 2,392,081 .19 .16
----------- ---------- ------------ ------ ------
Total $28,931,045 $6,894,537 $ 4,912,512 $ .54 $ .54
----------- ---------- ------------ ------ ------
----------- ---------- ------------ ------ ------
</TABLE>
(1) In the fourth quarter of 1994, the Company changed its revenue
recognition policy for earned interests. See Note 2 "Change in Accounting
Principle" for further discussion. This change was effective beginning
January 1, 1994, and, accordingly, the cumulative effect of this change
($(16,772,698) or $(2.52) per share) has been reflected in the first
quarter of 1994, and the first three quarters have been restated to reflect
the basis of the newly adopted accounting principle. Net Income, Primary
Income Per Share, and Fully Diluted Income Per Share were previously
reported as $814,325, $0.14, and $0.14, respectively, for the first quarter
of 1994; $1,140,197, $0.19, and $0.17, respectively, for the second quarter
of 1994; and $768,161, $0.12, and $0.12, respectively, for the third
quarter of 1994.
(2) Amounts prior to the fourth quarter of 1994 have been retroactively
restated to give recognition to an equivalent change in capital structure
as a result of the 10% stock dividend. See Note 1 "Summary of Significant
Accounting Policies-Income (Loss) Per Share" for further discussion.
Pro forma amounts assuming the new earned interests recognition policy
is applied retroactively:
<TABLE>
<CAPTION>
FULLY DILUTED
PRIMARY INCOME INCOME
NET INCOME PER SHARE PER SHARE
---------- -------------- -------------
<S> <C> <C> <C>
1993
First Quarter $ 917,895 $.14 $.14
Second Quarter 1,247,263 .19 .19
Third Quarter 1,113,049 .17 .15
Fourth Quarter 1,044,271 .16 .15
---------- ---- ----
Total $4,322,478 $.66 $.63
---------- ---- ----
---------- ---- ----
1994
First Quarter $1,210,722 $.18 $.17
Second Quarter 1,076,077 .16 .15
Third Quarter 1,130,398 .17 .16
Fourth Quarter 308,474 .05 .05
---------- ---- ----
Total $3,725,671 $.56 $.56
---------- ---- ----
---------- ---- ----
</TABLE>
33
<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 14, 1996 annual shareholders' meeting is
incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information appearing under the caption "Executive
Officers-Executive Cash Compensation" in the Company's definitive proxy
statement to be filed within 120 days after the close of the fiscal year-end
in connection with the May 14, 1996 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 14, 1996 annual
shareholders' meeting is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information appearing under the caption "Transactions with
Affiliates" (if any such captioned information is included) in the Company's
definitive proxy statement to be filed within 120 days after the close of the
fiscal year-end in connection with the May 14, 1996 annual shareholders'
meeting is incorporated herein by reference.
34
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) l. The following consolidated financial statements of Swift Energy
Company together with the report thereon of Arthur Andersen LLP dated
February 19, 1996, and the data contained therein are included in Item 8
hereof:
Report of Independent Public Accountants....................... 19
Consolidated Balance Sheets.................................... 20
Consolidated Statements of Income.............................. 21
Consolidated Statements of Stockholders' Equity................ 22
Consolidated Statements of Cash Flows.......................... 23
Notes to Consolidated Financial Statements..................... 24
2. Financial Statement Schedules
None
3. Exhibits
<TABLE>
<C> <S>
3(a).l (1) Articles of Incorporation, as amended through June 3, 1988.
3(a).2 (2) Articles of Amendment to Articles of Incorporation filed on June 4, 1990.
3(b) (3) By-Laws, as amended through August 14, 1995.
4(b) (4) Indenture dated as of June 30, 1993, between Swift Energy Company and Bank
One, Texas, National Association as Trustee.
10.1 (1)+ Indemnity Agreement dated July 8, 1988, between Swift Energy Company and
A. Earl Swift (plus schedule of other persons with whom Indemnity Agreements
have been entered into).
10.2 (4) Amended and Restated Credit Agreement dated March 24, 1992, between Swift Energy
Company and Bank One, Texas, National Association.
10.3 (4) Purchase and Sale Agreement dated May 27, 1992, between Swift Energy Company and
Enron Reserve Acquisition Corp.
10.4 (4) Purchase and Sale Agreement dated May 12, 1992, between the Company and Riverwood
Energy Resources, Inc.
10.5 (5)+ Swift Energy Company 1990 Nonqualified Stock Option Plan.
10.6 (6) First Amendment effective May 13, 1993, to Amended and Restated Credit Agreement
dated March 24, 1992, between Swift Energy Company and Bank One, Texas, National
Association.
10.7 (6) Second Amendment effective December 31, 1993, to Amended and Restated Credit
Agreement dated March 24, 1992, between Swift Energy Company and Bank One, Texas,
National Association.
10.8 (6) Third Amendment dated December 31, 1994, to Amended and Restated Credit Agreement
dated March 24, 1992, between Swift Energy Company and Bank One, Texas, National
Association.
10.9 (7) Amended and Restated Credit Agreement dated March 1, 1994, among Swift Energy
Company, Bank One, Texas, National Association and Bank of Montreal.
10.10(7) First Amendment dated June 15, 1994, to Amended and Restated Credit Agreement
dated March 1, 1994, among Swift Energy Company, Bank One, Texas, National
Association and Bank of Montreal.
10.11(6) Second Amendment dated December 31, 1994, to Amended and Restated Credit Agreement
dated March 1, 1994, among Swift Energy Company, Bank One, Texas, National
Association and Bank of Montreal.
10.12(8)+ Amended and Restated Swift Energy Company 1990 Stock Compensation Plan.
10.13(3)+ Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and Terry E. Swift.
10.14(3)+ Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and John R. Alden.
10.15(3)+ Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and James M. Kitterman.
10.16(3)+ Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and Bruce H. Vincent.
10.17(3)+ Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and A. Earl Swift.
10.18(8)+ Agreement and Release between Swift Energy Company and Virgil Neil Swift
effective June 1, 1994.
18 (6) Letter from Arthur Andersen LLP regarding change in accounting principle.
21 (8) List of Subsidiaries of Swift Energy Company.
23(a)(9) The consent of H. J. Gruy and Associates, Inc.
23(b)(9) The consent of Arthur Andersen LLP as to incorporation by reference regarding
Form S-8 and S-3 Registration Statements.
27 Financial Data Schedule (included in electronic filing only).
99 (9) The summary of H. J. Gruy and Associates, Inc. report, dated February 19, 1996.
</TABLE>
35
<PAGE>
(b) No Form 8-K reports were filed during the fourth quarter of 1995.
__________________________
(1) Incorporated by reference from Swift Energy Company Annual Report on
Form 10-K for the fiscal year ended December 31, 1988, File No. 1-8754.
(2) Incorporated by reference from Swift Energy Company Annual Report on
Form 10-K for the fiscal year ended December 31, 1992.
(3) Incorporated by reference from Swift Energy Company Quarterly Report on
Form 10-Q filed for the quarterly period ended September 30, 1995.
(4) Incorporated by reference from Registration Statement No. 33-63112 on
Form S-1 filed on May 20, 1993.
(5) Incorporated by reference from Registration Statement No. 33-36310 on
Form S-8 fixed on August 10, 1990.
(6) Incorporated by reference from Swift Energy Company Annual Report on
Form 10-K from the fiscal year ended December 31, 1994.
(7) Incorporated by reference from Swift Energy Company Quarterly Report on
Form 10-Q filed for the quarterly period ended June 30, 1994.
(8) Incorporated by reference from Registration Statement No. 33-60469
filed on June 22, 1995.
(9) Filed herewith.
+ Management contract or compensatory plan or arrangement.
36
<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, President
and Chief Executive Officer,
Swift Energy Company
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
- ---------------------------------- President and Chief Executive March 27, 1996
A. Earl Swift Officer, Swift Energy
Company
/s/ John R. Alden Senior Vice President-Finance,
- ---------------------------------- Principal Financial Officer, March 27, 1996
John R. Alden Swift Energy Company
/s/ Alton D. Heckaman, Jr. Assistant Vice President and
- ---------------------------------- Controller, Principal March 27, 1996
Alton D. Heckaman, Jr. Accounting Officer, Swift
Energy Company
/s/ Virgil N. Swift Director, Swift Energy
- ---------------------------------- Company March 27, 1996
Virgil N. Swift
</TABLE>
37
<PAGE>
<TABLE>
<CAPTION>
SIGNATURES TITLE DATE
---------- ----- ----
<S> <C> <C>
/s/ Harold J. Withrow Director, Swift Energy
- ---------------------------------- Company March 27, 1996
Harold J. Withrow
/s/ Raymond 0. Loen Director, Swift Energy
- ---------------------------------- Company March 27, 1996
Raymond 0. Loen
/s/ Clyde W. Smith, Jr. Director, Swift Energy
- ---------------------------------- Company March 27, 1996
Clyde W. Smith, Jr.
/s/ Henry C. Montgomery Director, Swift Energy
- ---------------------------------- Company March 27, 1996
Henry C. Montgomery
/s/ G. Robert Evans Director, Swift Energy
- ---------------------------------- Company March 27, 1996
G. Robert Evans
</TABLE>
38
<PAGE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20439
EXHIBITS
TO
FORM 10-K REPORT
FOR THE
YEAR ENDED DECEMBER 31, 1995
SWIFT ENERGY COMPANY
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060
39
<PAGE>
EXHIBITS
23(a) The consent of H.J. Gruy and Associates, Inc.
23(b) The consent of Arthur Andersen LLP as to incorporation by reference
regarding Form S-8 and S-3 Registration Statements.
99 The summary of H.J. Gruy and Associates, Inc. report, dated
February 19, 1996.
40
<PAGE>
H.J. GRUY AND ASSOCIATES, INC.
- ----------------------------------------------------------------------------
1200 SMITH STREET, SUITE 3040, HOUSTON, TEXAS 77002 * FAX (713)739-6112
* (713) 739-1000
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We hereby consent to the incorporation by reference in this
Registration Statement on Form S-3 of information derived from our reserve
report dated February 19, 1996, relating to the estimated quantities of
certain of the Company's proved reserves of oil and gas and the related
estimates of future net revenue and present values thereof for certain
periods, included in the Company's Annual Report of Form 10-K for the year
ended December 31, 1995, as well as in the Notes to the Consolidated
Financial Statements of the Company in such annual report. We also consent to
the reference to us under the heading of "Experts" in such Registration
Statement as well as in the Notes to the Consolidated Financial Statements of
the Company in such Registration Statement.
H.J. GRUY AND ASSOCIATES, INC.
BY: /s/ JAMES H. HARTSOCK
------------------------------------
Executive Vice President
Houston, Texas
March 4, 1996
<PAGE>
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of
our reports included (or incorporated by reference) in this Form 10-K, into
the Company's previously filed Registration Statements File Numbers 33-14305,
33-36310, 33-41327, 33-48699, 33-80228, and 33-80240.
ARTHUR ANDERSEN LLP
Houston, Texas
March 27, 1996
<PAGE>
EXHIBIT 99
H.J. GRUY AND ASSOCIATES, INC.
- -----------------------------------------------------------------------------
1200 SMITH STREET, SUITE 3040, HOUSTON, TEXAS 77002
- - FAX (713) 739-6112 - (713) 739-1000
February 19, 1996
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
RE: RESERVES AUDIT
95-003-124
Gentlemen:
At your request, we have audited the reserves and future net revenue as of
December 31, 1995, prepared by Swift Energy Company ("Swift") for certain
interests owned by Swift through partnerships in 12 drilling funds, 38 income
funds, 16 pension asset funds, and 32 depositary interest funds along with
several additional interests owned directly by Swift Energy Company. This
audit has been conducted according to the standards pertaining to the
estimating and auditing of oil and gas reserve information approved by the
Board of Directors of the Society of Petroleum Engineers on October 30, 1979.
We have reviewed these properties and where we disagreed with the Swift
reserve estimates, Swift revised its estimates to be in agreement. The
estimated net reserves, future net revenue and discounted future net revenue
are summarized by reserve category as follows:
<TABLE>
<CAPTION>
ESTIMATED ESTIMATED
NET RESERVES FUTURE NET REVENUE
--------------------------------------------------------
OIL & DISCOUNTED
CONDENSATE GAS AT 10%
(BARRELS) (MCF) NONDISCOUNTED PER YEAR
---------- ----------- ------------- ------------
<S> <C> <C> <C> <C>
Proved Developed 3,313,226 81,532,025 $ 162,723,296 $ 85,536,873
Proved Undeveloped 2,108,755 62,035,495 $ 118,923,638 $ 61,501,536
---------- ----------- ------------- ------------
TOTAL PROVED 5,421,981 143,567,520 $ 281,646,934 $147,038,409
G & A $ (2,963,994) $ (1,467,417)
---------- ----------- ------------- ------------
TOTAL 5,421,981 143,567,520 $ 278,682,940 $145,570,992
</TABLE>
The discounted future net revenue is not represented to be the fair market
value of these reserves and the estimated reserves included in this report
have not been adjusted for risk.
<PAGE>
-2-
The estimated future net revenue shown is that revenue which will be realized
from the sale of the 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
revenue projections. Future net revenue as stated in this report is before
the deduction of federal income tax.
In the economic projections, prices, operating costs and development costs
remain constant for the projected life of each lease.
For those wells with sufficient production history, reserve estimates and
rate projections are based on the extrapolation of established performance
trends. Reserves for other producing and nonproducing properties have been
estimated from volumetric calculations and analogy with the performance of
comparable wells. The reserves included in this study are estimates only and
should not be construed as exact quantities. Future conditions may affect
recovery of estimated reserves and revenue, and all categories of reserves
may be subject to revision as more performance data become available. The
proved reserves in this report conform to the applicable definitions
promulgated by the Securities and Exchange Commission. Attachment 1,
following this letter, sets forth all reserve definitions incorporated in
this study.
Extent and character of ownership, oil and gas prices, production data,
direct operating costs, capital expenditure estimates and other data provided
by Swift have been accepted as represented. The production data available to
us were through the month of October 1995 except in those instances in which
data were available through December. Interim production to December 31,
1995 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 revenues 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 revenues 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 revenue projections presented in this report
may require revision as additional data become available.
<PAGE>
-3-
We are unrelated to Swift and we have no interest in the properties included
in the information reviewed by us. In particular:
1. We do not own a financial interest in Swift or its oil and gas
properties.
2. Our fee is not contingent on the outcome of our work or report.
3. We have not performed other services for or have any other relationship
with Swift that would affect our independence.
If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such person with the approval of
our client is invited to visit our offices at his expense so that he can
evaluate the assumptions made and the completeness and extent of the data
available on which our estimates are based.
Any distribution or publication of this report or any part thereof must
include this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
/s/ JAMES H. HARTSOCK
----------------------------------
James H. Hartsock, PhD., P.E.
Executive Vice President
JHH:llb
Attachment
<PAGE>
ATTACHMENT 1
<PAGE>
ATTACHMENT 1
DEFINITIONS FOR OIL AND GAS RESERVES
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 reasonable
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, resevoir 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.
<PAGE>
PROVED UNDEVELOPED RESERVES
Proved undeveloped oil and gas 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.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM
THE REGISTRANT'S FINANCIAL STATEMENTS CONTAINED IN ITS ANNUAL REPORT
ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 1995 AND IS QUALIFIED
IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 7,574,512
<SECURITIES> 0
<RECEIVABLES> 37,250,806
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 43,380,454
<PP&E> 157,693,577
<DEPRECIATION> 30,169,303
<TOTAL-ASSETS> 175,252,707
<CURRENT-LIABILITIES> 40,133,269
<BONDS> 0
0
0
<COMMON> 125,097
<OTHER-SE> 93,220,868
<TOTAL-LIABILITY-AND-EQUITY> 175,252,707
<SALES> 22,527,892
<TOTAL-REVENUES> 28,931,045
<CGS> 0
<TOTAL-COSTS> 15,664,963<F1>
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,115,361
<INCOME-PRETAX> 6,894,537
<INCOME-TAX> 1,982,025
<INCOME-CONTINUING> 4,912,512
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 4,912,512
<EPS-PRIMARY> 0.54
<EPS-DILUTED> 0.54
<FN>
<F1>Includes depreciation, depletion and amortization of oil and gas
production costs. Excludes general and administrative and interest
expense.
</FN>
</TABLE>
