<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, 1996
Commission File Number 1-8754
SWIFT ENERGY COMPANY
(Exact Name of Registrant as Specified in Its Charter)
Texas 74-2073055
(State of Incorporation) (I.R.S. Employer Identification No.)
16825 Northchase Dr., Suite 400
Houston, Texas 77060
(281) 874-2700
(Address and telephone number of principal
executive offices) Securities registered pursuant
to Section 12(b) of the Act:
Title of Class: Exchanges on Which Registered:
Common Stock, par value $.01 per share New York Stock Exchange
Pacific Stock Exchange
Convertible Subordinated Notes Due 2006 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months and (2) has been subject to such filing requirements for
the past 90 days. Yes__x__ No_____
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the voting stock held by non-affiliates at March
17, 1997 was approximately $359,208,729.
The number of shares of common stock outstanding as of December 31, 1996 was
15,176,417 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 13,
1997
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Form 10-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 13, 1997.
2
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PART I
Items 1 and 2. Business and Properties
See pages 10-11 for explanations of abbreviations and terms used herein.
General
Swift Energy Company (the "Company"), a Texas corporation organized in
October 1979, is engaged in the exploration, development, acquisition, and
operation of oil and gas properties, with a primary focus on U.S. onshore
natural gas reserves. As of December 31, 1996, the Company had interests in over
1,800 oil and gas wells located in 12 states, with 92% of its proved reserves
base concentrated in Texas. At the same date, the Company had estimated proved
reserves of 258.7 Bcfe, approximately 87% of which were natural gas, and
operated 842 wells representing 99% of its proved reserves base.
The Company's primary focus is exploration and development drilling in its
core areas, the AWP Olmos Field located in South Texas and the Texas Austin
Chalk trend. The AWP Olmos Field is characterized by long-lived reserves, while
the Austin Chalk trend is characterized by more short-lived reserves with high
initial production and rapid decline rates. These fields accounted for
approximately 77% and 10%, respectively, of the Company's proved reserves as of
December 31, 1996, and approximately 57% and 18%, respectively, of the Company's
production during 1996. The Company has substantially accelerated its drilling
activities during the last several years, drilling 16, 42, and 116 net wells in
1994, 1995, and 1996, respectively, primarily in these areas. The Company has
also doubled its acreage position in the AWP Olmos Field and quadrupled it in
the Austin Chalk trend during 1996. The Company has budgeted capital
expenditures of $113.0 million for 1997, of which approximately 83% is targeted
for these two fields. The Company is also actively pursuing exploratory and
development drilling opportunities in other basins in Texas, Arkansas,
Louisiana, and Wyoming. As a complement to these domestic activities, the
Company is participating in several high potential international projects with
limited capital exposure to the Company in New Zealand, Russia, and Venezuela.
The Company has increased its proved reserves from 48.4 Bcfe at year end
1991 to 258.7 Bcfe at year end 1996, primarily from additions through the
drillbit, which has resulted in the replacement of 549% of production during the
same five-year period. In 1996, the Company increased its proved reserves by
47%, resulting in the replacement of 552% of 1996 production. The Company's
five-year average reserves replacement costs were $0.68 per Mcfe. As a result of
increased drilling activity, 1996 production increased 74% over 1995 production.
Due to economies of scale, geographic concentration, and increased production,
general and administrative expenses and production costs have fallen from $1.17
and $0.61 per Mcfe in 1991 to $0.33 and $0.43 per Mcfe, respectively, for 1996.
The combination of increased production and decreased operating costs per Mcfe
has resulted in average annual growth in net cash provided by operating
activities of 44% per year from year end 1991 to year end 1996. For 1996, due to
these same production and operating cost factors, net cash provided by operating
activities increased to $37.1 million or 158% over the same period in 1995.
Properties
The Company's proved reserves are geographically concentrated, with
approximately 87% of the Company's proved reserves at December 31, 1996,
attributable to its two largest properties, the AWP Olmos Field and the Austin
Chalk trend.
AWP Olmos Field. The Company's most significant property is located in the
AWP Olmos Field in South Texas. The Company has extensive expertise in the AWP
Olmos Field and a long history of experience with low-permeability tight-sand
formations typical of this field. Since acquiring its first AWP Olmos Field
acreage in 1988, the Company has made detailed studies of drainage patterns in
the formation and has introduced innovations in fracture design and
implementation methods and coiled tubing technology that substantially reduce
overall costs and improve recoveries.
The AWP Olmos Field represented approximately 77% of the Company's proved
reserves at December 31, 1996, and approximately 57% of the Company's 1996
production. At December 31, 1996, the Company owned interests in and was the
operator of approximately 240 wells producing natural gas from the Olmos Sand
Formation at a depth of approximately 10,000 feet. The Company has engaged in
extensive fracturing operations to increase the permeability of the formation
and flow of gas from the wells. In addition, the Company has used coiled tubing
velocity strings in several wells to improve production rates and a system of BJ
Services, Inc., by which the Company is capable of monitoring fracturing
operations from its Houston headquarters through direct computer access to the
field.
During 1996, the Company drilled 123 (119 successful) development wells in
this field and one exploratory well which was successful. During the latter
portion of 1996, the Company utilized eight drilling rigs in continuous
operation in the AWP Olmos Field area, with each rig drilling approximately two
wells per month. The working interest owned by the Company or entities managed
by the Company in this field is 100%. During 1996, the Company acquired an
additional 18,549 net acres in this area. These acquisitions have doubled the
amount of acreage that the Company has under lease. The Company anticipates
continuing its acquisition of acreage in this area in the future. The Company
plans to drill approximately 146 additional development wells and three
exploratory wells in this field in 1997. As part of this effort, the Company
plans to conduct a three-dimensional seismic survey over a 20-square-mile area
to supplement an ongoing study of stratigraphic traps based on available well
log and seismic data.
Austin Chalk Trend. At December 31, 1996, the Company owned drilling and
production rights in 74,010 net acres in the Austin Chalk trend containing
substantial proved undeveloped reserves. The Austin Chalk trend represented
approximately 10% of the Company's proved reserves at December 31, 1996.
Production from this field constituted 18% of oil and gas production in 1996.
The wells in this trend are all horizontally produced natural gas wells that
deliver high initial flow rates and strong initial cash flows which decline
rapidly. The Company believes these reserves complement its long-lived reserves
in the AWP Olmos Field. Since 1992, the Company has participated in 33
horizontal wells in the trend with a 97% success rate, including nine successful
development wells drilled in 1996. The Company believes its success is
attributable to its
3
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ability to identify hydrocarbon-bearing fractures, relying on its expertise in
seismic data analysis, and its ability to drill and operate horizontal wells.
The Company anticipates drilling 12 wells in the Austin Chalk during 1997.
Substantial portions of its property interests in the Austin Chalk trend
have been acquired through joint development arrangements with industry partners
who are active participants in exploration of the Austin Chalk trend, beginning
in 1993 in an arrangement that covered approximately 8,800 acres in which the
Company currently has an average working interest of 25%. In September 1995, the
Company entered into another joint development agreement providing for an area
of mutual interest covering 19,500 gross acres and pursuant to which that
industry partner and the Company alternate serving as operator of any wells
drilled on the acreage. During 1996, the Company purchased its partner's
interest in 9,500 of these gross acres, and the joint development arrangement
now covers a 10,000 gross acre block in which the Company expects to have an
average working interest of 30% to 35% based on certain assumptions relating to
elections to participants with respect to the drilling of various wells. The
Company's working interest in the 9,500 acres is now approximately 50%.
The most recent joint development arrangement covers approximately 8,000
acres in Washington County, Texas, in which the Company has a 25% working
interest. The Company's industry partner is operator, and it is anticipated that
the results of the first exploratory well drilled on this acreage will be known
in early 1997.
Also in 1996, the Company acquired approximately 39,157 net acres in Walker
County, Texas, in which the Company has a 100% working interest. It is
anticipated that the first exploratory well on this acreage will commence
drilling in early 1997. Future operations will be defined by the results of the
initial wells drilled.
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. During 1994, the Company added 25 Bcfe of proved
reserves through drilling, and in 1995, reserves added by drilling had almost
tripled to 72 Bcfe. In 1996, reserves added by drilling increased to 118 Bcfe
with the Company's success rate 64% for exploratory wells (7 out of 11 drilled)
and 94% for development wells (134 out of 142 drilled). These successful
drilling results have led to acquisition of substantial additional acreage
during 1996 in the area of its two core properties, the AWP Olmos Field in South
Texas and the Austin Chalk trend in Fayette, Walker, and Washington counties in
central and eastern Texas.
The Company pursues a "controlled risk" approach to exploratory drilling.
The Company focuses its exploration activities on specific U.S. regions where
its technical staff has considerable experience and which are in close proximity
to known producing horizons where the potential for significant reserves exists.
The Company seeks to minimize its exploration risk by investing in multiple
prospects, farming out interests to industry partners and drilling funds,
utilizing advanced technologies, and drilling in different types of geological
formations.
The Company's development strategy is designed to maximize the value and
productivity of its existing properties through development drilling and
recovery methods, enhancing production results through improved field production
techniques, lowering production costs, and applying the Company's technical
expertise and resources to exploit producing properties efficiently. The Company
employs various recovery techniques, which include water flooding, fracturing
reservoir rock through the injection of high-pressure fluid, inserting coiled
tubing velocity strings to speed gas flow, and acid treatments. The Company
believes that the application of fracturing technology and coiled tubing has
resulted in significant increases in production and decreases in drilling and
operating costs, particularly in the Company's largest single property, the AWP
Olmos Field.
The Company's exploration and development activities are conducted by its
in-house exploration staff, assisted by professionals from other departments,
including reservoir engineers, geologists, geophysicists, petrophysicists,
landmen, and drilling and operations engineers. The Company believes that one of
the keys to its success has been its team approach, which integrates multiple
disciplines to maximize 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 and amplitude versus offset (AVO)
studies. During the second quarter of 1996, the Company completed two 3-D
seismic programs, one in northern Louisiana and the other in central Texas. The
Company has a number of computer workstations from which seismic data is
analyzed and enhanced with advanced software programs, including its three
Landmark Systems(R) workstations. As a result, the Company has developed a
significant internal seismic expertise and has compiled an extensive library of
seismic data.
In addition to exploration and development activities in the AWP Olmos
Field and the Austin Chalk trend, the Company is currently focusing its
exploration activities in three main geographical areas: the Gulf Coast Basin,
the Wyoming Powder River Basin, and the North Louisiana Salt Dome Basin.
Gulf Coast Basin. In 1996, two successful development wells (out of four)
and one successful exploratory well (out of three) were drilled in the Gulf
Coast Basin, following one successful exploratory well and four successful
development wells drilled in 1995. The locations were selected utilizing
traditional geologic studies combined with analyses of available seismic data.
To reduce its exploration and development risks, 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
drilling potential. In 1997, up to five exploratory wells are scheduled for
drilling in the Gulf Coast Basin.
Wyoming Powder River Basin. In 1996, the Company successfully drilled one
out of three exploratory wells and also one out of three 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
4
<PAGE>
studies to determine the hydrocarbon-bearing capacity of the rock. Two seismic
surveys were conducted in 1996 and at least two more are scheduled for 1997. 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 wells in 1997, three wells to the
Minnelusa in Campell County and another well to the Sussex/Parkman formation in
Converse County.
North Louisiana Salt Dome. The North Louisiana Salt Dome covers the
neighboring corners of Arkansas, Louisiana, and Texas. In 1996, the Company
drilled five wells (four exploratory wells and one development well) all of
which were successful. 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. This region was the focus of several seismic surveys conducted by Swift
during 1996, including a 3-D survey in Claiborne Parish, Louisiana, a 2-D
seismic swath in Lafayette County and Hempstead County, Arkansas, a 2-D seismic
line in Lafayette County, Arkansas, and a 2-D seismic line in Columbia County,
Arkansas. In addition, Swift conducted an airborne magnetic survey over Nevada
County, Arkansas, for correlation with existing seismic data. During 1997, two
additional sets of 2-D seismic swaths will be conducted in Lafayette County,
Arkansas, and one will be conducted in Webster Parish, Louisiana. The Company
plans to drill seven exploratory wells in the region in 1997.
The following table sets forth the results of the Company's drilling
activities during the three fiscal years ended December 31, 1996:
<TABLE>
<CAPTION>
Gross Wells Net Wells
---------------------------- -------------------------
Year Type of Well Total Producing Dry Total Producing Dry
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
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
1996 Exploratory 11 7 4 5.9 3.7 2.2
Development 142 134 8 110.5 106.7 3.8
</TABLE>
Operations
The Company generally seeks to be named as operator for wells in which it
or its affiliated limited partnerships and joint ventures have acquired a
significant interest, although this typically occurs only when 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 842 wells at December 31, 1996, which comprise approximately
99% of the Company's total proved reserves.
As operator, the Company is able to exercise substantial influence over
development and enhancement of a well and to supervise operation and maintenance
activities on a day-to-day basis. The Company does not conduct the actual
drilling of wells on properties for which it acts as operator. Drilling
operations are conducted by independent contractors engaged and supervised by
the Company. The Company employs petroleum engineers, geologists, and other
operations and production specialists who strive to improve production rates,
increase reserves, and/or lower the cost of operating its oil and gas
properties.
Oil and gas properties are customarily operated under the terms of a joint
operating agreement, which provides for reimbursement of the operator's direct
expenses and monthly per-well supervision fees. Per-well supervision fees vary
widely depending on the geographic location and producing formation of the well,
whether the well produces oil or gas, and other factors. Such fees received by
the Company in 1996 ranged from $104 to $1,450 per well per month.
Marketing of Production
The Company typically sells its gas production at or near the wellhead,
although in some cases it must be gathered by the Company or other operators and
delivered to a central point. Gas production is generally sold in the spot
market at prevailing prices. The Company generally sells its oil production at
prevailing market prices. The Company does not refine any oil it produces.
During the year ended December 31, 1996, three oil or gas purchasers each
accounted for 10% or more of the Company's revenues, with those purchasers
together accounting for 51%. Only one oil or gas purchaser accounted for 10% or
more of the Company's revenues during the year ended December 31, 1995, with
that purchaser accounting for approximately 12%. This change in concentration is
a direct result of the concentration of the Company's production in its two core
areas, as discussed above. Because of the availability of other purchasers, the
Company does not believe that the loss of any single oil or gas purchaser or
contract would materially affect its sales.
The Company recently entered into gas processing and gas transportation
agreements with respect to its natural gas production in the AWP Olmos Field
with Valero Transmission, L.P. and its affiliates ("Valero") for up to 75,000
Mcf per day. These contracts have initial six-year terms, with automatic
one-year extensions thereof unless earlier terminated. The Company anticipates
that these arrangements will adequately provide for its gas transportation and
processing needs in the AWP Olmos Field for the foreseeable future.
Additionally, at the discretion of the Company and Valero, the gas processed and
transported under these agreements may be sold to Valero at indexed prices based
upon the Inside F.E.R.C. Gas Market Report Houston Ship Channel Monthly Price.
The following table summarizes sales volumes, sales prices, and production
cost information for the Company's net oil and gas production for the three-year
period ended December 31, 1996. "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.
5
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<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------
1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Net Sales Volume:
Oil (Bbls)............. 623,386 545,435 467,056
Gas (Mcf)1.............15,696,798 7,913,963 6,798,531
Gas equivalents
(Mcfe)2.............19,437,114 11,186,573 9,600,867
Average Sales Price:
Oil (Per Bbl)..........$ 19.82 $ 15.66 $ 14.35
Gas (Per Mcf)3........$ 2.57 $ 1.77 $ 1.93
Average Production Cost
(per Mcfe)2............$ 0.43 $ 0.61 $ 0.59
</TABLE>
(1) Natural gas production for 1996, 1995, and 1994 includes 1,156,361,
1,211,255, and 1,358,375 Mcf, respectively, delivered under the volumetric
production payment agreement pursuant to which the Company is obligated to
deliver certain monthly quantities of natural gas.
(2) Converted to Mcf equivalents on a thermal equivalent basis of 6 Mcf per
barrel of oil.
(3) The above natural gas prices reflect the high Btu content of the natural gas
produced from the Company's AWP Olmos and Austin Chalk properties. Gas is sold
on the basis of price per MMBtu, which measures the heating equivalent of such
gas. The prices per Mcf above (Mcf being strictly a physical measure of natural
gas volumes) are therefore higher than the prices which would be paid for
natural gas with a lower Btu content.
Under the volumetric production payment entered into in 1992, as of
December 31, 1996, the Company has a remaining commitment to deliver
approximately 3.0 Bcf of gas meeting certain heating equivalent and quality
standards through October 2000, when such agreement expires. Since entering into
this agreement, these properties have produced in excess of the required monthly
delivery requirements.
Price Risk Management
During 1996, the Company entered into oil and natural gas price hedging
contracts covering a portion of the Company's and its affiliated partnerships'
oil and natural gas production. For January, 1,500,000 MMBtu of the natural gas
production was covered, providing for a minimum price of $1.75 per MMBtu.
February was covered for 1,500,000 MMBtu of natural gas and March was covered
for 1,000,000 MMBtu of natural gas, both at a minimum price of $1.65. For the
months of May, June, July, August, September, and October, 1,400,000 MMBtu was
covered, providing for a minimum price of $1.80. November was covered for
1,400,000 MMBtu of natural gas at a minimum price of $2.20. December was covered
for 1,400,000 MMBtu of natural gas at a minimum price of $2.00. For the months
of March (70,000 Bbls) and April (35,000 Bbls), oil production was covered for a
minimum price of $17.50 per Bbl. For the months of May through September, 70,000
Bbls of oil production was covered, providing for minimum prices of $16.00. For
the months of October through December, 70,000 Bbls of oil production was
covered, providing for a minimum price of $17.00. Costs related to 1996 hedging
activities totaled approximately $800,000, and no payments were received in 1996
as actual prices received exceeded these minimum prices. The Company had five
open contracts at December 31, 1996, covering 2,000,000 MMBtu of the natural gas
production for February 1997, and 70,000 Bbls of oil production for the months
of February and March 1997, providing for minimum prices of $2.00 per MMBtu and
prices of $17.00 and $20.00 per Bbl. The costs related to the open contracts
totaled approximately $127,000 and had a market value of $68,400 as of December
31, 1996.
Acquisition Activities
Since 1979, the Company has acquired approximately $469.0 million of
producing oil and natural gas properties on behalf of itself and its
co-investors in 124 separate transactions. The Company has acquired for its own
account approximately $113.1 million of producing properties, with original
proved reserves estimated at 148.4 Bcfe. The Company's acquisition activities
have declined over the past three years, with approximately $13.1 million, $3.5
million, and $1.5 million of properties acquired in 1994, 1995, and 1996,
respectively. The Company's acquisition costs have averaged $0.83 per Mcfe over
this three-year period. For 1997 for its own account, the Company anticipates
spending $3.0 million primarily 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.
Foreign Activities
Russia. On September 3, 1993, the Company signed a Participation Agreement
with Senega, a Russian Federation joint stock company (in which the Company has
an indirect interest of less than 1%), to assist in the development and
production of reserves from two fields in Western Siberia providing the Company
with a minimum 5% net profits interest from the sale of hydrocarbon products
from the fields for providing managerial, technical, and financial support to
Senega. Additionally, the Company purchased a 1% net profits interest from
Senega for $300,000. In May 1995, the Company executed a Management Agreement
with Senega, under which, in return for undertaking to obtain financing for
development of these fields, Swift is entitled to receive a 49% interest in
production income derived by Senega from this project after repayment of costs.
On July 12, 1996, the Company entered into a partnership agreement which
provides for the Company to contribute its rights under the Participation and
Management Agreement to the partnership and for the partners to share equally
revenues and costs of developing the Samburg Field and funding and management of
the license areas, all in conjunction with Senega. The partnership is to be
funded by the partners upon fulfillment of certain conditions and completion of
certain further arrangements with Senega. It is currently anticipated that any
funding of these activities will be principally through project financing. At
December 31, 1996, the Company's investment in Russia was approximately
$9,530,000 and is included in the unproved properties portion of oil and gas
properties.
Venezuela. The Company formed a wholly owned subsidiary, Swift Energy de
Venezuela, C.A., for the purpose of
6
<PAGE>
submitting a bid on August 5, 1993, under the Venezuelan Marginal Oil Field
Reactivation Program. Although the Company did not win the bids, it continued to
pursue cooperative ventures involving other fields and opportunities in
Venezuela. Currently, the Company is evaluating a number of Blocks being offered
by Petroleos de Venezuela, S.A. under the Third Operating Agreement Round. At
December 31, 1996, the Company's investment in Venezuela was approximately
$1,610,000 and is included in the unproved properties portion of oil and gas
properties net of impairments of $45,668.
New Zealand. Since October 1995, the Company has been issued two Petroleum
Exploration Permits by the New Zealand Minister of Energy. The first permit
covers approximately 65,000 acres in the Onshore Taranaki Basin of New Zealand's
North Island, and the second covers approximately 69,300 adjacent acres. Under
the terms of these permits, the Company is obligated to analyze and interpret
certain seismic data, acquire certain new seismic data, and drill one
exploratory well, to be followed by a development well or additional seismic
work, all of which is to be performed on a staged basis in order to maintain the
permits over periods extending through July 2000 for the first permit and August
1999 for the second permit. At December 31, 1996, the Company's investment in
New Zealand was approximately $750,000 and is included in the unproved
properties portion of oil and gas properties.
Oil and Gas Reserves
The following table presents information regarding proved reserves of oil
and gas attributable to the Company's interests in producing properties as of
December 31, 1996, 1995, and 1994. The information set forth in the table is
based on proved reserves reports prepared by the Company and audited by H.J.
Gruy and Associates, Inc., Houston, Texas, independent petroleum engineers.
Gruy's estimates were based upon review of production histories and other
geological, economic, ownership, and engineering data provided by the Company.
In accordance with Securities and Exchange Commission guidelines, the Company's
estimates of future net revenues from the Company's proved reserves and the
PV-10 Value are made using oil and gas sales prices in effect as of the dates of
such estimates and are held constant throughout the life of the properties,
except where such guidelines permit alternate treatment, including, in the case
of gas contracts, the use of fixed and determinable contractual price
escalations. Proved reserves as of December 31, 1996, were estimated based upon
weighted average prices of $4.47 per Mcf of natural gas and $23.75 per barrel of
oil, compared to $2.41 and $1.85 per Mcf of natural gas and $18.07 and $15.09
per barrel of oil as of December 31, 1995 and 1994, respectively. Natural gas
prices have declined significantly since December 31, 1996. Accordingly, the
estimates of future net revenues from the Company's proved reserves and the
PV-10 Value would be reduced if subsequent gas prices were used. 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>
Year Ended December 31,
-----------------------------------------------
1996 1995 1994
-------------- -------------- ---------------
<S> <C> <C> <C>
Estimated Proved Oil and Gas Reserves
Net natural gas reserves (Mcf):
Proved developed...................................... 135,424,880 81,532,025 46,406,448
Proved undeveloped.................................... 90,333,321 62,035,495 29,857,516
-------------- -------------- ---------------
Total 225,758,201 143,567,520 76,263,964
============== ============== ===============
Net oil reserves (Bbl):
Proved developed..................................... 3,622,480 3,313,226 3,209,387
Proved undeveloped................................... 1,861,829 2,108,755 1,343,880
-------------- -------------- ---------------
Total............................................... 5,484,309 5,421,981 4,553,267
============== ============== ===============
Estimated Present Value of Proved Reserves
Estimated present value of future net cash flows from proved reserves discounted
at 10% per annum:
Proved developed..................................... $ 310,408,949 $ 85,536,873 $ 47,172,093
Proved undeveloped .................................. 160,776,008 61,501,536 22,222,511
-------------- -------------- --------------
Total............................................... $ 471,184,957 $ 147,038,409 $ 69,394,604
============== ============== ==============
</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 1996, 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 1997 and
thereafter will be made at an unrestricted level.
The Company's total proved developed and undeveloped reserves have
increased substantially (47%) at December 31, 1996, 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
7
<PAGE>
due to increased development drilling, revisions of previous quantity estimates,
and higher year end 1996 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. Three of the
limited partnerships had achieved payout status at December 31, 1996.
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, 1996
Gross 734 1,068 1,802
Net 59.5 222.9 282.4
December 31, 1995
Gross 3,049 995 4,044
Net 88.5 121.6 210.1
December 31, 1994
Gross 3,141 1,000 4,141
Net 79.3 109.1 188.4
</TABLE>
(1) Excludes 26 service wells in 1996, 39 service wells in 1995, and 31 service
wells in 1994.
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, 1996:
<TABLE>
<CAPTION>
Developed Undeveloped
------------------------------ -----------------------------
Gross(1) Net(2)(3) Gross(1) Net(2)(3)
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Alabama 895.38 349.58 292.00 41.17
Arkansas 4,089.49 1,761.04 8,964.89 4,557.20
Kansas 1,630.00 571.67 5,450.00 2,268.55
Kentucky -- -- 9,689.00 7,139.25
Louisiana 47,872.62 16,186.90 10,873.56 5,788.00
Mississippi 3,971.49 2,257.84 1,828.22 489.42
Nebraska -- -- 1,707.04 1,029.53
New Mexico 1,407.02 360.70 240.00 28.80
Oklahoma 41,554.53 16,240.33 3,649.62 1,520.45
Texas 103,895.54 53,986.77 112,328.35 73,667.00
West Virginia 16,048.20 10,484.50 -- --
Wyoming 7,859.22 1,652.80 41,415.53 26,002.97
All other states 117.64 2.00 4,610.44 256.53
---------- ---------- ---------- ----------
TOTAL 229,341.13 103,854.13 201,048.65 122,788.87
========== ========== ========== ==========
</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 portion of the Company's acreage is owned by virtue of its interest
derived from limited partnerships. The net acreage reflected on the table shows
the Company's interests assuming that an after payout status is achieved in
these partnerships. At December 31, 1996, three of the limited partnerships had
achieved payout status.
Partnerships
For many years, the Company relied on limited partnerships as its principal
financing vehicle to fund its activities. The Company has formed 104 limited
partnerships which have raised a total of approximately $485.3 million at
December 31, 1996. However, as the Company has increasingly shifted its emphasis
to exploration and development activities and its reserves base has grown, the
Company has significantly reduced its reliance on limited partnership financing.
During 1996, the limited partners in 18 partnerships, which had been in
operation over nine years and have produced a substantial majority of their
reserves, voted to sell their remaining properties and liquidate the limited
partnerships. In 1996, 10 of the earliest public income partnerships were
liquidated, and in early 1997 eight private drilling partnerships will be
liquidated. The Company intends to make similar proposals to other partnerships
for an orderly sale of their properties and liquidation of the partnerships over
the next several years. The Company may offer to acquire certain portions of the
remaining property interests owned by these limited partnerships.
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
8
<PAGE>
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, 1996, eight partnerships had been
formed (one in 1993, one in 1994, three in 1995, and three in 1996) with
aggregate investor contributions of approximately $41.9 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
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.
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. Because these
laws and regulations change frequently, the costs to the Company of compliance
with existing and future environmental regulations cannot be predicted.
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.
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
9
<PAGE>
allowing firm commitment shippers to receive delivery of gas on demand up to
certain limits without penalties, (ii) establish a basis for release and
reallocation of firm upstream pipeline capacity and (iii) provide
non-discriminatory access to capacity by firm transportation shippers on a
downstream pipeline. The rule requires interstate pipelines to use a straight
fixed variable rate design.
FERC Order No. 500 affects the transportation and marketability of natural
gas. Traditionally, natural gas has been sold by producers to pipeline
companies, which then resold the gas to end-users. FERC Order No. 500 alters
this market structure by requiring interstate pipelines that transport gas for
others to provide transportation service to producers, distributors and all
other shippers of natural gas on a nondiscriminatory, "first-come, first-served"
basis ("open access transportation"), so that producers and other shippers can
sell natural gas directly to end-users. FERC Order No. 500 contains additional
provisions intended to promote greater competition in natural gas markets.
It is not anticipated that the marketability of and price obtainable for
the Company's natural gas production will be significantly affected by FERC
Order No. 500. Gas produced normally will be sold to intermediaries who have
entered into transportation arrangements with pipeline companies. These
intermediaries will accumulate gas purchased from a number of producers and sell
the gas to end-users through open access transportation.
State Regulations
Production of any oil and gas by the Company will be affected to some
degree by state regulations. Many states in which the Company operates have
statutory provisions regulating the production and sale of oil and gas,
including provisions regarding deliverability. Such statutes, and the
regulations promulgated in connection therewith, are generally intended to
prevent waste of oil and gas and to protect correlative rights to produce oil
and gas between owners of a common reservoir. Certain state regulatory
authorities also regulate the amount of oil and gas produced by assigning
allowable rates of production to each well or proration unit.
Federal Leases
Some of the Company's properties are located on federal oil and gas leases
administered by various federal agencies, including the Bureau of Land
Management. Various regulations and orders affect the terms of leases,
exploration and development plans, methods of operation, and related matters.
Employees
At December 31, 1996, the Company employed 191 persons. None of the
Company's employees are represented by a union. Relations with employees are
considered to be good.
Facilities
The Company and SEMCO occupy approximately 75,000 square feet of office
space at 16825 Northchase Drive, Houston, Texas, under a ten year lease expiring
in 2005. The lease requires payments of approximately $85,000 per month. A
subsidiary of the Company maintains an office in Denver, Colorado. The Company
has field offices in various locations from which Company employees supervise
local oil and gas operations.
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 Items 1 and 2. Business and Properties 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, and therefore
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 and fluctuations in
oil and natural gas prices, 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 of natural gas equivalent (see Mcfe).
Development Well -- A well drilled within the presently proved productive area
of an oil or natural gas reservoir, as indicated by reasonable interpretation
of available data, with the objective of completing in that reservoir.
Discovery Cost -- With respect to proved reserves, a three-year average (unless
otherwise indicated) calculated by dividing total incurred exploration and
development costs (exclusive of future development costs) by net reserves
added during the period through extensions, discoveries, and other additions.
Dry Well -- An exploratory or development well that is not a producing well.
Exploratory Well -- A well drilled either in search of a new, as yet
undiscovered oil or natural gas reservoir or to greatly extend the known
limits of a previously discovered reservoir.
Gross 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.
10
<PAGE>
Mcfe -- Thousand cubic feet of natural gas equivalent, which is determined using
the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf
of natural gas.
MMBbl -- Million barrels of oil.
MMBtu -- Million British thermal units, which is a heating equivalent measure
for natural gas and is an alternate measure of natural gas reserves, as
opposed to Mcf, which is strictly a measure of natural gas volumes.
Typically, prices quoted for natural gas are designated as price per MMBtu,
the same basis on which natural gas is contracted for sale.
MMcf -- Million cubic feet of natural gas.
MMcfe -- Million cubic feet of natural gas equivalent (see Mcfe).
Net Well -- A net well is deemed to exist when the sum of fractional ownership
working interests in gross wells equals one. The number of net wells is the
sum of fractional working interests owned in gross wells expressed as whole
numbers and fractions thereof.
Producing Well -- An exploratory or development well found to be capable of
producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well.
Proved Developed Oil and Gas Reserves -- Proved developed oil and natural 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 natural gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids that
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions, that is, prices and costs as of the date the estimate
is made.
Proved Undeveloped Oil and Gas Reserves -- Proved undeveloped oil and natural
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, without escalation and without giving effect to
non-property related expenses such as general and administrative expenses,
debt service, future income tax expense, or depreciation, depletion, and
amortization.
Reserves Replacement Cost -- With respect to proved reserves, a three-year
average (unless otherwise indicated) calculated by dividing total incurred
acquisition, exploration, and development costs (exclusive of future
development costs) by net reserves added during the period.
Volumetric Production Payment -- The 1992 agreement pursuant to which the
Company financed the purchase of certain oil and natural gas interests and
committed to deliver certain monthly quantities of natural gas.
- --------------------------------------------------------------------------------
Item 3. Legal Proceedings
No material legal proceedings are pending other than ordinary routine
litigation incidental to the Company's business.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted during the fourth quarter of 1996 to a vote of
security holders.
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters
COMMON STOCK, 1996 AND 1995
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 1996 and 1995 are as follows:
<TABLE>
<CAPTION>
1996 1995
--------------------------------------- -----------------------------------------
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 10 7/8 13 17 1/2 23 8 8 1/2 8 1/4 7 3/4
High 14 1/8 18 1/8 24 7/8 31 3/4 9 7/8 10 1/8 9 5/8 12 5/8
</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.
Swift Energy had approximately 510 stockholders of record as of March 1,
1997.
11
<PAGE>
Item 6. Selected Financial Data
<TABLE>
<CAPTION>
1996 1995 1994(1) 1993
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Revenues
Oil and Gas Sales $52,770,672 $22,527,892 $19,802,188 $15,535,671
Supervision Fees $4,470,206 $3,838,815 $3,751,061 $3,718,829
Fees & Earned Interests(2) $937,238 $590,441 $701,528 $4,071,970
Interest Income $433,352 $212,329 $47,980 $201,584
Other, Net $2,156,764 $1,761,568 $1,072,535 $604,599
Total Revenues $60,768,232 $28,931,045 $25,375,292 $24,132,653
Operating Income $28,785,783 $6,894,537 $4,837,829 $6,628,608
Net Income (Loss) $19,025,450 $4,912,512 $(13,047,027) $4,896,253
Net Cash Provided by Operating Activities $37,102,578 $14,376,463 $10,394,514 $7,238,340
- ---------------------------------------------------------------------------------------------------------------------------
Per Share Data
Weighted Shares Outstanding(3) 13,637,182 9,122,857 6,644,248 6,588,076
Net Income (Loss) per Share--Primary(3) $1.40 $0.54 $(1.96) $0.74
Net Income (Loss) per Share--Fully Diluted(3) $1.37 $0.54 $(1.96) $0.70
Shares Outstanding at Year End 15,176,417 12,509,700 6,685,137 6,001,075
Book Value per Share $9.41 $7.46 $6.30 $9.08
Market Price(3)
High $31.75 $12.63 $11.38 $12.73
Low $10.88 $7.75 $8.52 $7.85
Year-End Close $29.88 $12.00 $9.75 $8.64
- ---------------------------------------------------------------------------------------------------------------------------
Pro forma amounts assuming 1994 change in
accounting principle is applied retroactively:(2)
Net Income $19,025,450 $4,912,512 $3,725,671 $4,322,478
Net Income per Share--Primary $1.40 $0.54 $0.56 $0.66
Net Income per Share--Fully Diluted $1.37 $0.54 $0.56 $0.63
- ---------------------------------------------------------------------------------------------------------------------------
Assets
Current Assets $101,619,478 $43,380,454 $39,208,418 $65,307,120
Oil and Gas Properties, Net of Accumulated
Depreciation, Depletion, and Amortization $200,010,375 $125,217,872 $88,415,612 $89,656,577
Total Assets $310,375,264 $175,252,707 $135,672,743 $160,892,917
Liabilities
Current Liabilities $32,915,616 $40,133,269 $52,345,859 $55,565,437
Long-Term Debt, Net of Current Portion $115,000,000 $28,750,000 $28,750,000 $28,750,000
Total Liabilities $167,613,654 $81,906,742 $93,545,612 $106,427,203
Stockholders' Equity $142,761,610 $93,345,965 $42,127,131 $54,465,714
- ---------------------------------------------------------------------------------------------------------------------------
Number of Employees 191 176 209 188
</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-$0.56, Cumulative Effect of Change in
Accounting Principle-$(2.52); Per Share Amounts-Fully Diluted-Income Before
Cumulative Effect of Change in Accounting Principle-$0.56, Cumulative Effect of
Change in Accounting Principle-$(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, 1996, 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>
1992 1991 1990 1989 1988 1987 1986
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
$12,420,222 $8,361,771 $7,328,190 $3,984,835 $2,838,433 $2,097,815 $954,269
$3,443,777 $3,362,800 $2,149,079 $1,651,839 $1,118,794 $1,065,820 $1,108,410
$2,716,277 $2,231,729 $9,882,953 $8,802,816 $8,073,530 $7,956,895 $2,393,371
$113,387 $192,694 $705,786 $260,286 $165,909 $125,459 $40,174
$515,931 $541,502 $323,981 $232,261 $488,131 $452,059 $471,486
$19,209,594 $14,690,496 $20,389,989 $14,932,037 $12,684,797 $11,698,048 $4,967,710
$4,687,519 $3,748,741 $10,811,044 $8,716,673 $7,040,165 $6,632,631 $1,948,431
$4,084,760 $2,512,815 $7,170,642 $5,709,098 $4,678,317 $4,024,003 $1,108,314
$6,349,080 $5,911,588 $4,813,435 $2,751,381 $393,564 $1,705,616 $1,189,179
- ---------------------------------------------------------------------------------------------------------------------------
6,135,044 5,363,299 5,278,578 4,663,322 4,452,163 4,383,969 4,326,300
$0.67 $0.47 $1.36 $1.22 $1.05 $0.92 $0.26
$0.67 $0.47 $1.36 $1.22 $1.05 $0.92 $0.26
5,968,579 4,955,134 4,848,315 4,764,862 4,068,968 4,025,108 3,949,500
$8.26 $7.80 $7.36 $5.84 $3.88 $2.70 $1.68
$8.64 $10.00 $11.71 $12.27 $9.55 $16.94 $4.89
$5.12 $4.77 $7.62 $6.36 $6.14 $3.75 $1.14
$8.30 $5.45 $9.43 $10.45 $6.25 $6.82 $3.75
- ---------------------------------------------------------------------------------------------------------------------------
$3,729,851 $2,950,245 $3,107,451 $2,185,276 $898,962 $561,509 $290,582
$0.61 $0.55 $0.59 $0.47 $0.20 $0.13 $0.07
$0.61 $0.55 $0.59 $0.47 $0.20 $0.13 $0.07
- ---------------------------------------------------------------------------------------------------------------------------
$30,830,173 $47,859,278 $72,537,521 $54,818,404 $9,304,370 $8,396,944 $6,924,548
$64,301,509 $47,655,917 $41,952,212 $27,935,170 $19,973,454 $13,092,526 $6,913,487
$100,243,469 $101,421,573 $118,227,480 $85,007,293 $31,463,220 $23,745,504 $15,731,279
$27,876,687 $50,851,447 $71,514,938 $49,354,128 $9,756,431 $8,342,755 $6,535,890
$0 $0 $0 $0 $0 $0 $0
$50,962,183 $62,761,217 $82,559,406 $57,198,476 $15,694,272 $12,874,849 $9,114,611
$49,281,286 $38,660,356 $35,668,074 $27,808,817 $15,768,948 $10,870,655 $6,616,668
- ---------------------------------------------------------------------------------------------------------------------------
178 171 164 131 116 94 55
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 was
formed in 1979 and from 1985 to 1991 grew primarily through the acquisition of
producing properties funded through limited partnership financing. Commencing in
1991, the Company began to reemphasize the addition of reserves through
increased exploration and development drilling activity. This emphasis on
exploration and development drilling has led to additions of increasing
quantities of reserves in each of the years 1994, 1995, and 1996.
The Company's revenues are primarily comprised of oil and gas sales
attributable to properties in which the Company owns a direct or indirect
interest. Additionally, prior to 1994, the Company recorded earned interests and
fees from limited partnerships and joint ventures. 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). 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. Under the Company's
current method of accounting, 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 $14.3 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 payment of
approximately $13.8 million 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 3.0 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.
The statements contained in this Annual Report on Form 10-K ("Annual
Report") that are not historical facts are forward-looking statements as that
term is defined in Section 21E of the Securities and Exchange Act of 1934, as
amended, and therefore involve a number of risks and uncertainties. The actual
results of the future events described in such forward-looking statements in
this Annual Report, including those regarding the Company's financial results,
levels of oil and gas production or revenues, capital expenditures, and capital
resource activities, could differ materially from those estimated. Among the
factors that could cause actual results to differ materially are: general
economic conditions, competition and government regulations, and fluctuations in
oil and natural gas prices, as well as the risks and uncertainties set forth
from time to time in the Company's other public reports, filings, and public
statements.
Proved Oil and Gas Reserves. From 1994 to 1995, the Company's proved
natural gas reserves increased 67.3 Bcf (88%) and its proved oil reserves
increased 868,714 barrels (19%). In 1996, the Company's proved natural gas
reserves increased 82.2 Bcf (57%) and its proved oil reserves increased 62,328
barrels (1%). As detailed in Note 9 to the Company's financial statements, the
composition of these reserves has shifted, with proved undeveloped reserves
comprising 37.9 Bcfe or 37% of total proved reserves at year end 1994, 74.7 Bcfe
or 42% of total proved reserves at year end 1995, and 101.5 Bcfe or 39% of total
proved reserves at year end 1996. 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.
The Company's additions to proved reserves from its exploration and development
program were 118.2 Bcfe in 1996, 72.4 Bcfe in 1995, and 24.8 Bcfe in 1994.
Proved developed reserves additions in 1996 resulted from drilling activity
(which increased undeveloped reserves to a much larger degree), revisions of
previous quantities estimates and higher year end 1996 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 page 7--"Oil and Gas Reserves") from year end 1995 to year end
1996 is due to the addition of reserves through the Company's drilling activity
(primarily in the AWP Olmos Field and the Austin Chalk trend), to the 85%
increase in year end 1996 natural gas prices ($4.47 per Mcf versus $2.41 per Mcf
at year end 1995), and to the 31% increase in year end 1996 oil prices ($23.75
per Bbl at year end 1996, compared to $18.07 per Bbl a year earlier).
Under the Securities and Exchange Commission guidelines, the Company's
estimates of cash flows from proved reserves are made using oil and gas sales
prices in effect as of the dates of such estimates and are held constant
throughout the life of the properties, except where such guidelines permit
alternate treatment, including, in the case of gas contracts, the use of fixed
and determinable contractual price escalations. The $4.47 per Mcf and the $23.75
14
<PAGE>
per barrel were prices in effect as of year end 1996 and may not be indicative
of future sales prices received.
Liquidity and Capital Resources
In 1991, the Company's strategy shifted toward an increased reliance on
exploration and development activities, and the Company has significantly
expanded reserves added through these efforts. Previously, the Company relied on
limited partnership capital as its principal financing vehicle to fund its
acquisitions of producing properties. As a result of this shift in strategy, the
Company has reduced its reliance on cash flows generated from and capital raised
through limited partnerships. Cash and working capital are provided through
internally generated cash flows and debt and equity financing.
During the first half of 1995, the Company used a combination of bank
financing, internally generated cash flows, and partnership financing to fund
its operations. In the third quarter of 1995, the Company realized $45.7 million
in net proceeds from an offering of common stock that provided sufficient
capital to repay its bank financing and finance its capital expenditures for the
second half of 1995. During the first ten months of 1996, the Company relied
upon internally generated cash flows and bank borrowings to fund its capital
expenditures. In November 1996, the Company realized $110.45 million in net
proceeds from an offering of 6.25% Convertible Subordinated Notes due 2006 that
provided sufficient capital to repay the Company's bank financing and finance
its capital expenditures during the remainder of 1996 and is expected to
provide, along with internally generated cash flows, for capital expenditures
and working capital needs through 1997. Described below are the major elements
of the Company's liquidity and capital resources.
Net Cash Provided by Operating Activities. In 1996, 1995, and 1994, the
Company's operating activities provided net cash of $37.1 million, $14.4
million, and $10.4 million, respectively. These increases were primarily due to
increased production volumes and higher product prices, as discussed below. The
1996 increase of $22.7 million in net cash from operations was primarily due to
the cash flows from oil and gas sales, which increased $30.4 million (146%),
exclusive of the non-cash amortization of deferred revenues associated with the
Company's volumetric production payment, partially offset by a $1.6 million
increase in oil and gas production costs and a $1.1 million increase in general
and administrative costs. This increase in oil and gas sales was primarily the
result of the Company's recent increase in drilling activity and product price
increases as described below. The 1995 increase of $4.0 million was primarily
due to an increase in cash flows from oil and gas sales, which increased $2.9
million (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 $.7 million increase in other revenues, and a $.7 million
decrease in interest expense, partially offset by a $1.2 million increase in oil
and gas production costs.
Sale of Convertible Subordinated Notes. In November 1996, the Company
issued $115.0 million of 6.25% Convertible Subordinated Notes due November 15,
2006, in a public offering. Proceeds of the offering were used for repayment in
full of all the Company's bank borrowings ($33.1 million on November 25, 1996)
and for capital expenditures for the remainder of 1996, with the remainder of
the proceeds to be used, along with internally generated cash flows, to fund
capital expenditures and working capital needs. The principal terms of these
Notes are more fully described in Note 5 to the Company's financial statements.
1995 Stock Offering. During the third quarter of 1995, the Company sold
5.75 million shares of common stock in a public offering at $8.50 per share,
with net proceeds of $45.7 million principally used to repay outstanding
indebtedness and finance the Company's exploration and development activities.
Other Financing Activities. On June 30, 1993, the Company issued the 6.5%
Convertible Subordinated Debentures due 2003 in the amount of $28.75 million 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 program. As described in Note 5 to the Company's
financial statements included herein, in August 1996 the 6.5% Convertible
Subordinated Debentures were converted by their holders into 2.34 million shares
of the Company's common stock following the Company's July 1996 announcement
that the 6.5% Debentures would be redeemed in August 1996, unless earlier
converted. As a result of this conversion, the Company's stockholders' equity
increased approximately $27.65 million.
Credit Facilities. Recently, the Company's credit facilities have been used
to fund a portion of the Company's exploration and development activities.
Formerly, the Company established credit facilities which 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. These credit facilities
consist of a $100.0 million unsecured revolving line of credit with a $5.0
million borrowing base and a $7.0 million secured revolving line of credit with
a $2.0 million borrowing base. The principal terms and restrictions of these
credit facilities are described in Note 4 to the Company's financial statements
included herein.
At December 31, 1996, the Company had no outstanding balances under these
borrowing arrangements, since those borrowings were repaid with proceeds from
the Company's 6.25% Convertible Subordinated Notes offering in 1996. The
borrowings since year end 1995 were used, along with internally generated cash
flows, principally to fund the Company's 1996 capital expenditures described
below. At December 31, 1995, the Company also had no outstanding balances under
these borrowing arrangements, since those borrowings were repaid with proceeds
from the Company's 1995 stock offering.
Partnership Programs. 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
$12.4 million, compared to $32.1 million raised in eight 1994 SDI partnerships.
In 1996, three drilling partnerships were formed, with total subscriptions of
approximately $22.0 million compared to $15.9 million of subscriptions raised in
three drilling partnerships in 1995 and $2.6 million raised in one partnership
in 1994. The Company anticipates that it will continue to offer the drilling
partnerships for the foreseeable future.
15
<PAGE>
At December 31, 1996, 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 $511,000, a
decrease of $348,000 when compared with the balance at December 31, 1995. Upon
the Company's decision to conclude the SDI offering in December 1995, the
remaining limited partnership formation and marketing costs related to the SDI
offering (approximately $1.75 million) were transferred to the oil and gas
properties account.
During 1996, the limited partners in 18 partnerships, which had been in
operation over nine years and had produced a substantial majority of their
reserves, voted to sell their remaining properties and liquidate the limited
partnerships. In 1996, 10 of the earliest public income partnerships were
liquidated, and in early 1997 eight private drilling partnerships will be
liquidated. The Company intends to make similar proposals to other partnerships
for an orderly sale of their properties and liquidation of the partnerships over
the next several years. The Company may offer to acquire certain portions of the
remaining property interests owned by these limited partnerships.
Working Capital. The Company's working capital increased significantly from
$3.2 million at December 31, 1995, to $68.7 million at December 31, 1996. This
increase is primarily the result of the receipt of net proceeds from the 6.25%
Convertible Subordinated Notes offerings in November 1996.
Since year end 1995, the Company's receivable account from limited
partnerships decreased significantly due to (a) repayments made with funds
generated from property sales proceeds realized by these partnerships and (b) an
increase in oil and gas prices received by these partnerships. Both of these
increased the cash flows of the partnerships, thus allowing them to reduce their
balances owed to the Company.
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 840 wells, its accelerated
drilling programs, and the management of affiliated partnerships. In this
capacity, the Company is responsible for certain day-to-day cash management,
including the collection and disbursement of oil and gas revenues and related
expenses.
Capital Expenditures. The Company's capital expenditures were approximately
$91.5 million, $40.0 million, and $34.5 million for 1996, 1995, and 1994,
respectively. The 1996 capital expenditures included (a) $69.1 million (75% of
1996 capital expenditures) on developmental drilling (primarily in the AWP Olmos
Field and Austin Chalk trend), (b) $2.7 million (3%) on exploratory drilling,
(c) $12.7 million (14%) on prospect costs (principally prospect leasehold,
seismic and geological costs of unproven prospects for the Company's account),
(d) the purchase of $1.5 million (2%) of limited partner interests in previously
formed partnerships through the right of presentment arrangement provided in
those partnerships, (e) $3.7 million (4%) invested in foreign business
opportunities in Russia ($2.7 million), in Venezuela ($0.5 million), and in New
Zealand ($0.5 million), as described in Note 9 to the Company's financial
statements, and (f) $1.8 million (2%) spent on fixed assets. In 1996, the
Company participated in drilling 153 wells (11 exploratory and 142 development
wells with 7 exploratory successes and 134 development successes). The steady
growth in the Company's unproved property account, which is not being amortized,
is indicative of the shift to a focus on drilling activity, as the Company
acquires prospect acreage. This unproved property account also reflects $3.7
million of capital expenditures in 1996 made in relation to the Company's
foreign business opportunities, as described above.
Capital expenditures for 1997 are estimated to be approximately $113.0
million, including investments in all areas in which 1996 capital was spent.
Approximately $85.0 million of the 1997 budget is allocated to exploration and
development drilling, with approximately 83% to be spent in the Company's two
primary development areas in Texas. The Company's plan anticipates drilling 158
development and 20 exploratory wells in 1997.
The Company believes that 1997'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 November 1996 Convertible Subordinated Notes offering,
will be sufficient to finance the costs associated with its 1997 budgeted
capital expenditures. Further liquidity needs may also be met by its existing
credit facilities.
Results of Operations
Revenues. The Company's revenues in 1996 increased by 110% over revenues in
1995 and by 14% in 1995 over 1994 revenues, principally due to increases in oil
and gas sales revenues.
Oil and Gas Sales. The Company's net sales volumes in 1996 (including the
volumetric production payment associated with each year's production) increased
by 74% (8.3 Bcfe) over net sales volumes in 1995, while 1995 net sales volumes
increased by 17% (1.6 Bcfe) over net sales volumes in 1994. Combined oil and gas
sales revenues in 1996 increased by 134% ($30.2 million) over those revenues for
1995, while in 1995 those revenues increased by 14% ($2.7 million) over oil and
gas sales in 1994. Average prices for oil increased from $14.35 per Bbl in 1994
to $15.66 per Bbl in 1995 and to $19.82 per Bbl in 1996, while average gas
prices decreased from $1.93 per Mcf in 1994 to $1.77 per Mcf in 1995 and then
rose significantly to $2.57 per Mcf in 1996. The Company's $30.2 million
increase in oil and gas sales during 1996 was comprised of volume variances of
$13.8 million from the 7.8 Bcf increase in gas sales volumes and $1.2 million
from the 78,000-barrel increase in oil sales volumes, while price variances
contributed $12.7 million from the increase in average gas prices received and
$2.5 million from the increase in average oil prices received.
The increase in oil and gas sales for 1996 was primarily the result of
production from the Company's accelerated drilling program, most notably from
the Company's two primary development areas, the AWP Olmos Field and the Austin
Chalk trend. The Company's 1996 oil and gas sales from the AWP Olmos Field were
$29.8 million ($5.3 million in 1995) from 11.1 Bcfe of net sales volumes (3.4
Bcfe in 1995) for an increase of 7.7 Bcfe, while the Austin Chalk trend
generated oil and gas sales of $10.1 million ($4.4 million in 1995) from 3.6
Bcfe of net sales volumes (2.1 Bcfe in 1995) for an increase of 1.5 Bcfe.
The increase in oil and gas sales for 1995 was also primarily the result of
the Company's development drilling in the AWP Olmos Field and the Austin Chalk
trend. The Company began drilling on additional acreage adjacent to
16
<PAGE>
its original leasehold acreage in the AWP Olmos Field during the second quarter
of 1995, which resulted in oil and gas sales of $2.3 million from 1.0 Bcfe of
net sales volume. Austin Chalk trend wells that were placed into production
during 1995 contributed oil and gas sales of $3.1 million from 1.6 Bcfe of net
sales volume. As a percentage of total revenues, oil and gas sales rose from 78%
of total revenues in 1994 to 87% of total revenues in 1996.
Supervision Fees. These fees continue to increase, having grown from $3.75
million in 1994 to $3.84 million in 1995 to $4.47 million in 1996, due to the
annual escalation in well overhead rates and the increase in drilling activity
by the Company, which in turn increases the drilling well overhead portion of
such fees.
Costs and Expenses. General and administrative expenses in 1996 increased
$1.1 million (21%) over such expenses in 1995, while 1995 general and
administrative expenses increased $58,000 (1%) over 1994. The increase in costs
in 1996 reflects the increase in the Company's activities. However, the
Company's general and administrative expenses per Mcfe produced decreased from
$0.54 per Mcfe produced in 1994 to $0.47 per Mcfe produced in 1995 and $0.33 per
Mcfe produced in 1996. The majority of the companies in the oil and gas industry
treat supervision fees as a reduction of their general and administrative
expenses. If the Company were to follow this practice, these expenses net of
supervision fees would have decreased to $0.15 per Mcfe produced in 1994, $0.13
per Mcfe produced in 1995, and $0.10 per Mcfe produced in 1996.
Depreciation, depletion, and amortization (DD&A) has steadily increased,
primarily due to the Company's reserves additions and associated costs and to
the related sale of increased quantities of oil and gas therefrom. The Company's
DD&A rate per Mcfe of production was $0.82 in 1994, $0.79 in 1995, and $0.85 in
1996, reflecting variations in the per unit cost of reserves additions. 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 which occurred in 1994 as discussed in Note 2 to
the Company's financial statements.
Production costs in 1996 increased $1.6 million (23%) over such expenses in
1995, while those expenses in 1995 increased $1.2 million (21%) over 1994. The
increases in each of the periods relate to the increase in the Company's oil and
gas sales volumes. However, the Company's production costs per Mcfe produced
have decreased to $0.43 in 1996, from $0.61 and $0.59 per Mcfe produced in 1995
and 1994, respectively. As discussed above, the Company's increase in production
is primarily through its drilling activities in the AWP Olmos Field and the
Austin Chalk trend, where the Company already has an established operating base.
The increase in production costs is partially offset by an exemption in these
same fields from the 7.5% Texas severance tax applicable to gas production from
certain natural gas wells certified to be in tight formations or to be deep
wells by the Texas Railroad Commission. Additionally, commencing September 1,
1996, certain wells certified as "high cost gas" wells are entitled to a
reduction of severance tax based upon a formula amount. Therefore, the increase
in drilling activity and production has not been accompanied by a proportionate
increase in operating costs. This tax exemption has had a positive impact on the
Company's production costs during 1995 and 1996, although under the new rules,
the proportionate amount of the exemption is likely to be reduced in future
periods.
Interest expense in 1996 on the Debentures, including amortization of debt
issuance costs, totaled $1.0 million ($2.0 million in 1995 and $2.0 million in
1994), while interest expense on the credit facilities, including commitment
fees, totaled $1.1 million ($1.7 million in 1995 and $1.7 million in 1994), and
interest expense on the Notes, including amortization of debt issuance costs,
totaled $0.7 million for a 1996 total of $2.8 million (of which $2.1 million was
capitalized). The 1995 total was $3.7 million (of which $2.6 million was
capitalized), while the 1994 total was $3.7 million (of which $1.9 million 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 1996 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,
as they were converted into common stock in the third quarter of 1996.
Net Income (Loss). Net income of $19.0 million and earnings per share of
$1.40 for 1996 were 287% and 159% higher, respectively, than net income of $4.9
million and earnings per share of $0.54 in 1995. This increase in net income
primarily reflected the effect of a 134% increase in oil and gas sales revenues
as a result of a 98% increase in natural gas production, a 14% increase in crude
oil production, and product price improvements. The lower percentage increase in
earnings per share reflects a 49% increase in weighted average shares
outstanding for the period, as a result of the sale of 5.75 million shares of
common stock in the third quarter of 1995 and the conversion of the Debentures
into 2.34 million shares of common stock in the third quarter of 1996. The
Company's consolidated effective tax rate was 33.9%, 28.7%, and 23.0% in 1996,
1995, and 1994, respectively.
Net income of $4.9 million 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 $3.7 million and earnings per share of $0.56
in 1994. The increase in net income in 1995 was primarily due to an increase in
production volumes and the related oil and gas sales therefrom. The 1995
decrease in earnings per share reflected a 37% increase in weighted average
shares outstanding for the period, as a result of the sale of $5.75 million
shares of common stock in the third quarter of 1995.
Net loss for 1994 of $13.0 million included a cumulative effect of a change
in accounting principle (see Note 2 to the Company's financial statements) of
$16.8 million.
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. 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, 1996
and 1995, and the related consolidated statements of income, stockholders'
equity, and cash flows for each of the three years in the period ended December
31, 1996. 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, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, 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 10, 1997
19
<PAGE>
Consolidated Balance Sheets
- --------------------------------------------------------------------------------
Swift Energy Company and Subsidiaries
December 31,
1996 1995
------------- ---------------
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents............................................. $ 77,794,974 $ 7,574,512
Accounts receivable--
Oil and gas sales.................................................. 13,637,390 14,765,336
Associated limited partnerships and joint ventures................. 6,396,149 16,108,298
Joint interest owners.............................................. 3,079,619 4,044,817
Other current assets.................................................. 711,346 887,491
------------- ---------------
Total Current Assets 101,619,478 43,380,454
============= ===============
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized ................................ 216,310,033 132,673,707
Unproved properties not being amortized........................... 27,620,462 20,652,151
------------- ---------------
243,930,495 153,325,858
Furniture, fixtures, and other equipment................................ 5,729,228 4,367,719
------------- ---------------
249,659,723 157,693,577
Less-- Accumulated depreciation, depletion, and amortization............ (46,685,736) (30,169,303)
------------- ---------------
202,973,987 127,524,274
------------- ---------------
Other Assets:
Receivables from associated limited partnerships, net of current
portion.............................................................. 759,711 2,332,355
Limited partnership formation and marketing costs.................... 510,607 858,559
Deferred charges..................................................... 4,511,481 1,157,065
------------- ---------------
5,781,799 4,347,979
------------- ---------------
$ 310,375,264 $ 175,252,707
============= ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities............................. $ 20,416,589 $ 23,075,982
Payable to associated limited partnerships........................... 1,444,648 16,983
Undistributed oil and gas revenues................................... 11,054,379 17,040,304
------------- ---------------
Total Current Liabilities...................................... 32,915,616 40,133,269
------------- ---------------
Long-Term Debt.......................................................... 115,000,000 28,750,000
Deferred Revenues....................................................... 4,404,081 6,063,467
Deferred Income Taxes................................................... 15,293,957 6,960,006
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized,
none outstanding.................................................. -- --
Common stock, $.01 par value, 35,000,000 shares authorized,
15,176,417 and 12,509,700 shares issued and outstanding,
respectively...................................................... 151,764 125,097
Additional paid-in capital........................................... 102,018,861 71,133,979
Unearned ESOP compensation........................................... (521,354) --
Retained earnings.................................................... 41,112,339 22,086,889
------------- --------------
142,761,610 93,345,965
------------- --------------
$ 310,375,264 $ 175,252,707
============= ==============
</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,
-----------------------------------------------
1996 1995 1994
-------------- ------------- ------------
<S> <C> <C> <C>
Revenues:
Oil and gas sales....................................................... $ 52,770,672 $ 22,527,892 $ 19,802,188
Fees from limited partnerships and joint ventures....................... 937,238 590,441 701,528
Supervision fees........................................................ 4,470,206 3,838,815 3,751,061
Interest income......................................................... 433,352 212,329 47,980
Other, net.............................................................. 2,156,764 1,761,568 1,072,535
-------------- ------------- ------------
60,768,232 28,931,045 25,375,292
-------------- ------------- ------------
Costs and Expenses:
General and administrative, net of reimbursement........................ 6,385,067 5,256,184 5,197,899
Depreciation, depletion, and amortization............................... 16,526,379 8,838,657 7,904,801
Oil and gas production.................................................. 8,377,044 6,826,306 5,639,630
Interest expense, net................................................... 693,959 1,115,361 1,795,133
-------------- ------------- ------------
31,982,449 22,036,508 20,537,463
-------------- ------------- ------------
Income Before Income Taxes................................................. 28,785,783 6,894,537 4,837,829
Provision for Income Taxes................................................. 9,760,333 1,982,025 1,112,158
-------------- ------------- ------------
Income Before Cumulative Effect of Change in Accounting Principle.......... 19,025,450 4,912,512 3,725,671
Cumulative Effect of Change in Accounting Principle........................ -- -- (16,772,698)
-------------- ------------- ------------
Net Income (Loss).......................................................... $ 19,025,450 $ 4,912,512 $(13,047,027)
============== ============= ============
Per Share Amounts--
Primary:
Income Before Cumulative Effect of Change in Accounting Principle....... $ 1.40 $ 0.54 $ 0.56
============== ============= ============
Cumulative Effect of Change in Accounting Principle..................... $ -- $ -- $ (2.52)
============== ============= ============
Net Income (Loss)....................................................... $ 1.40 $ 0.54 $ (1.96)
============== ============= ============
Fully Diluted:
Income Before Cumulative Effect of Change in Accounting Principle....... $ 1.37 $ 0.54 $ 0.56
============== ============= ============
Cumulative Effect of Change in Accounting Principle..................... $ -- $ -- $ (2.52)
============== ============= =============
Net Income (Loss)....................................................... $ 1.37 $ 0.54 $ (1.96)
============== ============= ============
Weighted Average Shares Outstanding........................................ 13,637,182 9,122,857 6,644,248
============== ============= ============
Pro forma amounts assuming change in accounting for earned interests is applied
retroactively (see Note 2)--
Net Income................................................................................................... $ 3,725,671
Per Share Amounts--
Primary................................................................................................... $ 0.56
Fully Diluted............................................................................................. $ 0.56
</TABLE>
See accompanying notes to Consolidated Financial Statements.
21
<PAGE>
Consolidated Statements of Stockholders' Equity
- --------------------------------------------------------------------------------
Swift Energy Company and Subsidiaries
<TABLE>
<CAPTION>
Unearned
Additional ESOP
Common Paid-In Compen- Retained
Stock(1) Capital sation Earnings Total
---------- ------------- ----------- ------------- -------------
<S> <C> <C> <C> <C> <C>
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
Stock issued for benefit plans (30,015 shares)...... 300 347,345 -- -- 347,645
Stock options exercised (257,207 shares)............ 2,572 2,630,959 -- -- 2,633,531
Employee stock purchase plan (36,387 shares)........ 364 272,178 -- -- 272,542
Loan to ESOP for purchase of shares................. -- -- (568,750) -- (568,750)
Amortization of ESOP................................ -- 5,382 47,396 -- 52,778
Debenture conversion (2,343,108 shares)............. 23,431 27,629,018 -- -- 27,652,449
Net income.......................................... -- -- -- 19,025,450 19,025,450
---------- -------------- ---------- ------------- -------------
Balance, December 31, 1996............................$ 151,764 $ 102,018,861 $ (521,354) $ 41,112,339 $ 142,761,610
========== ============== ========== ============= =============
</TABLE>
(1)$.01 par value.
See accompanying notes to Consolidated Financial Statements.
22
<PAGE>
Consolidated Statements of Cash Flows
- --------------------------------------------------------------------------------
Swift Energy Company and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995 1994
-------------- -------------- -------------
<S> <C> <C> <C>
Cash Flows from Operating Activities:
Net income (loss).......................................................$ 19,025,450 $ 4,912,512 $ (13,047,027)
Adjustments to reconcile net income to net cash provided
by operating activities--
Depreciation, depletion, and amortization............................ 16,526,379 8,838,657 7,904,801
Deferred income taxes................................................ 8,449,283 2,326,162 963,324
Deferred revenue amortization related to production payment.......... (1,670,172) (1,787,974) (1,993,863)
Cumulative effect of change in accounting principle.................. -- -- 16,772,698
Other ............................................................... 140,047 112,890 105,180
Change in assets and liabilities--
Increase in accounts receivable................................... (5,008,592) (488,599) (762,789)
Increase (decrease) in accounts payable and accrued liabilities,
excluding income taxes payable................................ (444,966) 1,074,532 142,883
Increase (decrease) in income taxes payable....................... 85,149 (611,717) 309,307
-------------- -------------- -------------
Net Cash Provided by Operating Activities...................... 37,102,578 14,376,463 10,394,514
-------------- -------------- -------------
Cash Flows from Investing Activities:
Additions to property and equipment..................................... (91,487,176) (40,032,944) (34,531,180)
Proceeds from the sale of property and equipment........................ 2,247,799 230,242 861,073
Net cash received (distributed) as operator of oil and gas properties... (2,074,104) 7,662,419 (229,351)
Net cash received (distributed) as operator of partnerships and
joint ventures....................................................... 11,284,793 5,316,693 (1,408,031)
Other................................................................... 840 (41,181) (25,320)
-------------- -------------- -------------
Net Cash Used in Investing Activities.......................... (80,027,848) (26,864,771) (35,332,809)
-------------- -------------- -------------
Cash Flows from Financing Activities:
Proceeds from long-term debt............................................ 115,000,000 -- --
Net proceeds from (payments of) short-term bank borrowings.............. -- (27,229,000) 24,579,000
Net proceeds from issuances of common stock............................. 3,264,482 46,306,322 708,444
Loan to ESOP for purchase of shares..................................... (568,750) -- --
Payments of debt issuance costs......................................... (4,550,000) -- --
-------------- -------------- -------------
Net Cash Provided by Financing Activities...................... 113,145,732 19,077,322 25,287,444
-------------- -------------- -------------
Net Increase in Cash and Cash Equivalents..................................$ 70,220,462 $ 6,589,014 $ 349,149
Cash and Cash Equivalents at Beginning of Year............................. 7,574,512 985,498 636,349
-------------- -------------- -------------
Cash and Cash Equivalents at End of Year...................................$ 77,794,974 $ 7,574,512 $ 985,498
============== ============== =============
Supplemental Disclosures of Cash Flows Information:
Cash paid during year for interest, net of amounts capitalized.............$ 831,516 $ 68,097 $ 1,691,400
Cash paid during year for income taxes.....................................$ 676,920 $ 277,580 $ 97,200
</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 are
engaged in the acquisition, development, operation, and exploration of oil and
natural gas properties, with particular emphasis on U.S. onshore natural gas
reserves. The Company also has oil and gas investments in Russia, Venezuela, and
New Zealand. The Company's investments in associated oil and gas partnerships
and its joint ventures are accounted for using the proportionate consolidation
method, whereby the Company's proportionate share of each entity's assets,
liabilities, revenues, and expenses is included in the appropriate
classifications in the consolidated financial statements. Intercompany balances
and transactions have been eliminated in preparing the consolidated statements.
Certain reclassifications have been made to prior year amounts to conform to the
current year presentation.
Use of Estimates. The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities, if any, at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period.
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 and Other. Legal and accounting fees, underwriting fees,
printing costs, and other direct expenses associated with the issuance of the
Company's 6.5% Convertible Subordinated Debentures due 2003 (the "Debentures")
in June 1993 were capitalized and through June 1996 were being amortized over
the life of the Debentures. Due to the conversion of all outstanding Debentures
into common stock in August 1996, the related unamortized costs ($1,097,551)
were transferred to the Company's appropriate capital accounts in the third
quarter of 1996. The issuance costs associated with the Company's 6.25%
Convertible Subordinated Notes (the "Notes") sold in a public offering in
November 1996 have been capitalized and are being amortized over the life of the
Notes, which mature on November 15, 2006. The balance of these issuance costs at
December 31, 1996 ($4,511,481) is net of accumulated amortization of $38,519.
Limited Partnerships and Joint Ventures. Between 1991 and 1995 (and for
prior periods), the Company formed limited partnerships and joint ventures for
the purpose of acquiring interests in producing oil and gas properties and,
since 1993, partnerships engaged in drilling for oil and gas reserves. The
Company serves as managing general partner or manager of these entities. Because
the Company serves as the general partner of these entities, under state
partnership law it is contingently liable for the liabilities of
24
<PAGE>
these partnerships, virtually all of which are owed to the Company and are not
material for any of the periods presented in relation to the partnerships'
respective assets.
Under the Swift Depositary Interests limited partnership offering ("SDI
Offering"), which commenced in March 1991 and concluded in December 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. 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
Company's oil and gas properties account.
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 $300,000, $600,000, and
$4,100,000 in 1996, 1995, and 1994, respectively.
Commencing September 15, 1993, the Company began offering, on a private
placement basis, general and limited partnership interests in limited
partnerships to be formed to drill for oil and gas. As managing general partner,
the Company pays for all front-end costs incurred in connection with these
offerings, for which the Company receives an interest in the partnerships.
Through December 31, 1996, approximately $41.9 million had been raised in eight
partnerships, one formed in each of 1993 and 1994, and three in each of 1995 and
1996. In July, September, and November 1996, the Company closed the sixth,
seventh, and eighth partnerships with total subscriptions of approximately $4.9
million, $10.0 million, and $7.1 million, respectively. Costs of syndication and
qualification of these limited partnerships incurred by the Company have been
deferred. Under the current private limited partnership offerings, selling and
formation costs borne by the Company serve as the Company's general partner
contribution to such partnerships.
During 1996, the limited partners in 18 partnerships, which had been in
operation over nine years and have produced a substantial majority of their
reserves, voted to sell their remaining properties and liquidate the limited
partnerships. In 1996, 10 of the earliest public income partnerships were
liquidated, and in early 1997 eight private drilling partnerships will be
liquidated. The Company intends to make similar proposals to other partnerships
for an orderly sale of their properties and liquidation of the partnerships over
the next several years. The Company may offer to acquire certain portions of the
remaining property interests owned by these limited partnerships.
Hedging Activities. The Company's revenues are primarily the result of
sales of its oil and natural gas production. Market prices of oil and natural
gas may fluctuate and adversely affect operating results. To mitigate some of
this risk, the Company does engage periodically in certain limited hedging
activities, but only to the extent of buying protection price floors for
portions of its and the limited partnerships' oil and gas production (see page
6--"Price Risk Management"). Costs and/or benefits derived from these price
floors are accordingly recorded as a reduction or increase in oil and gas sales
revenue and were not significant for any year presented. The costs to purchase
put options are amortized over the option period. The costs related to the open
contracts totaled approximately $127,000 and had a market value of $68,400 as of
December 31, 1996.
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 Debentures
were not and the Notes 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 in September 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 Notes as of the issuance date and 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. For the periods presented
in which the Debentures were outstanding, the conversion price of the Debentures
was revised to reflect the 10% stock dividend declared in September 1994. The
original conversion price was $13.50 per common share and the revised conversion
price per common share was $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 was 14,512,242, 11,671,243, and 9,053,736 for the respective years
ended December 31, 1996, 1995, and 1994.
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 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.
25
<PAGE>
Credit Risk 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.
During the year ended December 31, 1996, three oil or gas purchasers each
accounted for 10% or more of the Company's revenues, with those purchasers
together accounting for 51%. Only one oil or gas purchaser accounted for 10% or
more of the Company's revenues during the year ended December 31, 1995, with
that purchaser accounting for approximately 12%. Because of the availability of
other purchasers, the Company does not believe that the loss of any single oil
or gas purchaser or contract would materially affect its sales.
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, 1996.
- --------------------------------------------------------------------------------
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 are not
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 felt the change in policy resulted in more
comparable financial statements in relation to its business focus and in
comparison to its 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 $10,000,000. The effect of
the Act on income tax expense for the years ended December 31, 1996, 1995, 1994,
and the Company's net deferred tax liability was not material.
The following is an analysis of the consolidated income tax provision:
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------
1996 1995 1994
----------- ------------ ------------
<S> <C> <C> <C>
Current...........$ 759,253 $ (344,137) $ 148,834
Deferred.......... 9,001,080 2,326,162 963,324
----------- ------------ ------------
Total.............$ 9,760,333 $ 1,982,025 $ 1,112,158
=========== ============ ============
</TABLE>
There are differences between income taxes computed using the statutory
rate (34% for 1996, 1995, and 1994) and the Company's effective income tax rates
(33.9%, 28.7%, and 23.0% for 1996, 1995, and 1994, 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>
1996 1995 1994
------------ ----------- ------------
<S> <C> <C> <C>
Income taxes computed at federal statutory rate................................ $ 9,787,166 $ 2,344,143 $ 1,644,862
State tax provisions, net of federal benefits.................................. 75,936 84,202 46,525
Nonconventional fuel source credit............................................. (306,000) (370,000) (435,016)
Depletion deductions in excess of basis........................................ (26,520) (34,000) (30,895)
Other, net..................................................................... 229,751 (42,320) (113,318)
------------ ----------- ------------
Provision for income taxes..................................................... $ 9,760,333 $ 1,982,025 $ 1,112,158
============ =========== ============
</TABLE>
26
<PAGE>
The tax effects of significant temporary differences representing the net
deferred tax liability at December 31, 1996, 1995, and 1994, were as follows:
<TABLE>
<CAPTION>
1996 1995 1994
------------- ------------- -------------
<S> <C> <C> <C>
Deferred tax assets:
Alternative minimum tax credits............................................$ 1,517,470 $ 1,372,978 $ 900,562
Other...................................................................... -- 115,332 7,112
------------- ------------- -------------
Total deferred tax assets.................................................$ 1,517,470 $ 1,488,310 $ 907,674
Deferred tax liabilities:
Oil and gas properties.....................................................$ 15,935,855 $ 7,682,701 $ 4,811,886
Other...................................................................... 875,572 650,283 614,300
------------- ------------- -------------
Total deferred tax liabilities............................................$ 16,811,427 $ 8,332,984 $ 5,426,186
------------- ------------- -------------
Net deferred tax liability(1)................................................$ 15,293,957 $ 6,844,674 $ 4,518,512
============= ============= =============
</TABLE>
(1) This amount includes current deferred tax asset amounts of $115,332
and $103,679 for 1995 and 1994, respectively.
The Company did not record any valuation allowances against deferred tax
assets at December 31, 1996, 1995, and 1994.
At December 31, 1996, the Company had an alternative minimum tax
carryforward of $1,517,470 indefinitely available to reduce future regular tax
liability to the extent it exceeds the related tentative minimum tax otherwise
due.
- --------------------------------------------------------------------------------
4. Bank Borrowings
At the end of 1995, the Company had available, through a two-bank group, a
revolving line of credit of $35,000,000 bearing interest at the bank's base rate
plus 0.5% (9%), secured by the Company's interests in certain oil and gas
properties and general partner interests. This facility also allowed, 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.
Effective April 30, 1996, this credit agreement was restated. The facility
was increased to $100,000,000 and is now unsecured. The available borrowing base
at December 31, 1996, was $5,000,000 and will be redetermined periodically.
Prior to December 1, 1996, the borrowing base was $30,000,000. At the Company's
request, it was reduced to the $5,000,000 amount effective December 1, 1996.
This was requested in order to reduce the amount of commitment fees paid on this
facility, the calculation of which is described below. Depending on the level of
outstanding debt, the interest rate will be either the bank's base rate (8.25%
at December 31, 1996) or the bank's base rate plus 0.25%. This facility also
allows, at the Company's option, draws which bear interest for specific periods
at LIBOR. The LIBOR option will now vary from plus 1% to plus 1.5%. There was no
outstanding balance under this line of credit at December 31, 1996.
The terms of the revolving line of credit include, among other
restrictions, a limitation on the level of cash dividends (not to exceed
$2,000,000 in any fiscal year), requirements as to maintenance of certain
minimum financial ratios (principally pertaining to working capital, debt, and
equity ratios) and limitations on incurring other debt. Since inception, no cash
dividends have been declared on the Company's common stock. The Company
presently intends to continue a policy of using retained earnings for expansion
of its business. For all periods presented, the Company was in compliance with
the provisions of these agreements.
At December 31, 1995, the Company's second credit facility was 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%), secured by certain Company receivables.
There were no outstanding amounts under this facility at December 31, 1995.
Effective April 30, 1996, this facility was amended to $7,000,000, with interest
at the bank's base rate less 0.25% (8% at December 31, 1996). The available
borrowing base is $2,000,000 at December 31, 1996, and will be redetermined
periodically. This borrowing base decrease from $7,000,000 was also effective
December 1, 1996, at the Company's request. There were no outstanding amounts
under this facility at December 31, 1996. The restated credit facility extends
through September 30, 1999.
In addition to interest on these credit facilities, the Company pays a
commitment fee to compensate the banks for making funds available. The fee on
the revolving line of credit is calculated on the average daily remainder, if
any, of the commitment amount less the aggregate principal amounts outstanding,
plus the amount of all letters of credit outstanding during the period. The
aggregate amounts of commitment fees paid by the Company were $120,000 in 1996
and $154,000 in 1995.
- --------------------------------------------------------------------------------
5. Long-Term Debt
The Company's long-term debt at December 31, 1996, consists of $115,000,000
of 6.25% Convertible Subordinated Notes due 2006. The Notes were issued on
November 25, 1996, and will mature on November 15, 2006. The Notes are
convertible into common stock of the Company at the option of the holders at any
time prior to maturity at a conversion price of $34.69 per share, subject to
adjustment upon the occurrence of certain events. Interest on the Notes is
payable semiannually on May 15 and November 15, commencing with the first
payment on May 15, 1997. On or after November 15, 1999, the Notes are redeemable
for cash at the option of the Company, with certain restrictions, at 104.375% of
principal, declining to 100.625% in 2005. Upon certain changes in control of the
Company, if the price of the Company's common stock is not above certain levels
each holder of Notes will have the right to require the Company to repurchase
the Notes at the principal amount thereof, together with accrued and unpaid
interest to the date of repurchase but after the repayment of any Senior
Indebtedness, as defined.
The Company's long-term debt at December 31, 1995, consisted of $28,750,000
of 6.5% Convertible Subordinated Debentures. The Debentures were issued on June
30, 1993, and were convertible into common stock of the Company at an adjusted
conversion price of $12.27 per share. Interest on the Debentures was payable
semiannually on
27
<PAGE>
June 30 and December 31, commencing with the payment made at December 31, 1993.
The Debentures became redeemable for cash at the option of the Company after
June 30, 1996. On July 1, 1996, the Company called all of the Debentures for
redemption on August 5, 1996, at 104.55% of their face amount. Prior to the
redemption date, the holders of all of the outstanding Debentures elected to
convert their Debentures into shares of common stock, resulting in the issuance
of 2.34 million shares of common stock in August 1996. Upon conversion of the
Debentures into common stock, the approximate $27,650,000 net carrying amount of
the debt (the face amount less unamortized deferred charges) was transferred to
the Company's appropriate capital accounts during the third quarter of 1996.
Interest expense on both the Notes and Debentures, including amortization
of debt issuance costs, totaled $1,731,194 in 1996 and $1,981,639 in 1995.
- --------------------------------------------------------------------------------
6. Commitments and Contingencies
Total rental and lease expenses charged to earnings before reimbursements
were $957,797 in 1996, $998,714 in 1995, and $1,159,673 in 1994. The Company's
remaining minimum annual obligations under non-cancelable operating lease
commitments are $1,068,825 for 1997, $1,136,523 for 1998, $1,175,546 for 1999,
$1,181,455 for 2000, and $1,181,455 for 2001.
As of December 31, 1996, the Company is the managing general partner of 94
limited partnerships. Because the Company serves as the general partner of these
entities, under state partnership law it is contingently liable for the
liabilities of these partnerships, which liabilities are not material for any of
the periods presented in relation to the partnerships' respective assets.
In the ordinary course of business, the Company has been party to various
legal actions, which arise primarily from its activities as operator of oil and
gas wells. In management's opinion, the outcome of any such currently pending
actions will not have a material adverse effect on the financial position or
results of operations of the Company.
- --------------------------------------------------------------------------------
7. Stockholders' Equity
Common Stock. In September 1994, the Company declared a 10% stock dividend
to shareholders of record. 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 principally to finance the
Company's exploration and development activities.
In August 1996, the holders of the Company's Debentures converted such
Debentures into 2,343,108 shares of the Company's common stock, which resulted
in a third quarter 1996 increase in the Company's capital accounts of
approximately $27,650,000.
Stock-Based Compensation Plans. The Company has two stock option plans, the
1990 stock compensation plan and the 1990 nonqualified plan, as well as an
employee stock purchase plan.
Under the 1990 compensation plan, incentive stock options and other options
and awards may be granted to employees to purchase shares of common stock. Under
the 1990 non-qualified plan, non-employee members of the Company's Board of
Directors may be granted options to purchase shares of common stock. Both plans
provide that the exercise prices equal 100% of the fair value of the common
stock on the date of grant. Options become exercisable for 20% of the shares on
the first anniversary of the grant of the option and are exercisable for an
additional 20% per year thereafter. Options granted expire 10 years after the
date of grant or earlier in the event of the optionee's separation from
employment. 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 Company also granted certain stock options to individuals who are
neither employees, officers, nor directors for specific services rendered to the
Company. During 1996 all of these remaining options were either exercised
(57,555) or cancelled (11,195) so that no such options remain outstanding at
December 31, 1996.
The employee stock purchase plan provides eligible employees the
opportunity to acquire shares of Company common stock at a discount through
payroll deductions. This plan was approved at the May 11, 1993, shareholders
meeting. The plan year is from June 1 to the following May 31. The first year of
the plan commenced June 1, 1993. Employees may authorize payroll deductions of
up to 10% of their base salary during the plan year by making an election to
participate prior to the start of a plan year. The purchase price for stock
acquired under the plan will be 85% of the lower of the closing price of the
Company's common stock as quoted on the New York Stock Exchange at the beginning
or end of the plan year or a date during the year chosen by the participant.
Under this plan the Company issued 36,387 shares at a price range of $6.59 to
$7.97 in 1996, 37,689 shares at a price range of $6.80 to $7.92 in 1995, and
29,840 shares at a price of $8.71 in 1994. As of December 31, 1996, there were
443,100 shares available for issuance under this plan. There are no charges or
credits to income in connection with this plan.
The Company accounts for the two stock option plans under APB Opinion No.
25, under which no compensation cost has been recognized. Had compensation cost
for these plans been determined consistent with SFAS No. 123 "Accounting for
Stock-Based Compensation," the Company's net income and earnings per share would
have been reduced to the following pro forma amounts:
<TABLE>
<CAPTION>
1996 1995
----------- ----------
<S> <C> <C> <C>
Net Income: As Reported $19,025,450 $4,912,512
Pro Forma $18,750,064 $4,628,678
Primary EPS: As Reported $1.40 $0.54
Pro Forma $1.37 $0.51
Fully Diluted EPS: As Reported $1.37 $0.54
Pro Forma $1.35 $0.52
</TABLE>
Because the SFAS No. 123 method of accounting has not been applied to
options granted prior to January 1, 1995, the resulting pro forma compensation
cost may not be representative of that to be expected in future years.
28
<PAGE>
The following is a summary of the Company's stock options under these plans
as of December 31, 1996 and 1995:
<TABLE>
<CAPTION>
1996 1995
------------------------- ---------------------
Wtd. Avg. Wtd. Avg.
Shares Exer. Price Shares Exer.Price
------------------------ ----------------------
<S> <C> <C> <C> <C>
Options outstanding, beginning of period.............. 1,308,391 $ 8.83 1,166,920 $ 8.86
Options granted....................................... 302,281 $ 23.78 227,502 $ 8.63
Options terminated.................................... (11,251) $ 8.81 (80,270) $ 8.78
Options exercised..................................... (199,652) $ 8.65 (5,761) $ 7.59
--------- ---------
Options outstanding, end of period.................... 1,399,769 $ 12.09 1,308,391 $ 8.83
========= =========
Options exercisable, end of period.................... 700,271 $ 8.82 722,627 $ 8.81
========= =========
Options available for future grant, end of period..... 38,546 343,344
========= =========
Estimated weighted average fair value of
options granted during the year............... $15.17 $4.76
========= =========
</TABLE>
Of the 1,399,769 options outstanding at December 31, 1996, 1,117,488 have
exercise prices between $5.46 and $12.39, with a weighted average exercise price
of $8.93 and a weighted average remaining contractual life of 5.7 years. Of
these options, 700,271 are exercisable with a weighted average price of $8.82.
The remaining 282,281 options (representing substantially all the 1996 options
granted) have exercise prices between $15.88 and $28.75, with a weighted average
exercise price of $24.61 and a weighted average remaining contractual life of
9.8 years.
The fair value of each option grant, as opposed to its exercise price, is
estimated on the date of grant using the Black-Scholes option pricing model with
the following weighted average assumptions used for grants in 1996 and 1995
respectively: average risk-free interest rates of 6.42 and 6.98 percent, average
expected lives of 10 and 7.7 years, average expected volatility factors of 40.4
and 39.7 percent, and no dividend yield. The estimated weighted average fair
value of options granted in 1996 and 1995 under the Company`s two stock option
plans are shown in the table above. The estimated weighted average fair value of
shares issued under the Company`s employee stock purchase plan was $2.13 in 1996
and $2.59 in 1995.
Employee Stock Ownership Plan. In 1996, the Company established an Employee
Stock Ownership Plan ("ESOP"), effective as of January 1, 1996. All employees
over the age of 21 with one year of service are participants. The Plan has a
five year cliff vesting, and service is recognized after the Plan effective
date. The ESOP is designed to enable employees of the Company to accumulate
stock ownership. While there will be no employee contributions, participants
will receive an allocation of stock which has been contributed by the Company.
Compensation costs are reported when such shares are released to employees. The
Plan may also acquire Swift Energy Company common stock purchased at fair market
value. The ESOP can borrow money from the Company to buy Company stock as was
done in September 1996 to purchase 25,000 shares from the Company's chairman.
Benefits will be paid in a lump sum or installments, and the participants
generally have the choice of receiving cash or stock. At December 31, 1996, the
unearned portion of the ESOP ($521,354) was recorded as a contra-equity account
entitled "Unearned ESOP Compensation."
- --------------------------------------------------------------------------------
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
$6,100,000, $4,800,000, and $4,400,000 in 1996, 1995, and 1994, 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
$250,000, $600,000, and $1,400,000 in 1996, 1995, and 1994, respectively.
- --------------------------------------------------------------------------------
9. Oil and Gas Producing Activities
Capitalized Costs. The following table presents the Company's aggregate
capitalized costs relating to oil and gas producing activities and the related
depreciation, depletion, and amortization:
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------
1996 1995
------------- --------------
<S> <C> <C>
Oil and Gas Properties:
Proved...........................................................$ 216,310,033 $ 132,673,707
Unproved (not being amortized)................................... 27,620,462 20,652,151
------------- --------------
243,930,495 153,325,858
Accumulated Depreciation, Depletion, and Amortization............... (43,920,120) (28,107,986)
------------- --------------
$ 200,010,375 $ 125,217,872
============= ==============
</TABLE>
Of the $27,620,462 of net unproved property costs (primarily seismic and
lease acquisition cost) at December 31, 1996, being excluded from the
amortizable base, $13,678,675 was incurred in 1996, $6,901,011 was incurred in
1995, $4,071,345 was incurred in 1994, and $2,969,431 was incurred in prior
years. The Company expects it will complete its evaluation of the properties
representing the majority of these costs within the next two to three years.
29
<PAGE>
Capital Expenditures. The following table sets forth capital expenditures
related to the Company's oil and gas operations:
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------
1996 1995 1994
------------- ------------- -------------
<S> <C> <C> <C>
Acquisition of proved properties, including earned interests
in limited partnerships and joint ventures...................$ 1,529,611 $ 3,461,091 $ 13,078,242
Lease acquisitions(1)(2)........................................ 16,426,327 9,742,543 9,905,237
Exploration..................................................... 2,704,281 2,289,814 4,003,400
Development..................................................... 69,067,024 23,555,988 5,637,285
------------- ------------- -------------
Total(3).................................................$ 89,727,243 $ 39,049,436 $ 32,624,164
============= ============= ==============
</TABLE>
(1) Lease acquisitions for 1996, 1995, and 1994 include expenditures of
$2,712,278, $2,814,395, and $2,973,971, respectively, relating to the Company's
initiatives in Russia; 1996, 1995, and 1994 expenditures of $487,597, $304,610,
and $356,136, respectively, relating to initiatives in Venezuela; and 1996 and
1995 expenditures of $545,980 and $202,206, respectively, relating to
initiatives in New Zealand.
(2) These are actual amounts as incurred by year, including both proved and
unproved lease costs. The annual lease acquisition amounts added to proved oil
and gas properties (being amortized) for 1996, 1995, and 1994, respectively,
were $9,458,016, $3,895,871, and $3,032,315.
(3) Includes capitalized general and administrative costs directly associated
with the acquisition, development, and exploration efforts of approximately
$7,400,000, $7,100,000, and $5,800,000 in 1996, 1995, and 1994, respectively. In
addition, total includes $1,549,575, $1,442,022, and $766,572 in 1996, 1995, and
1994, respectively, of capitalized interest on unproved properties.
Results of Operations. The following table sets forth results of the
Company's oil and gas operations:
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1996 1995 1994
------------ ------------ ------------
<S> <C> <C> <C>
Oil and gas sales.......................................$ 52,770,672 $ 22,527,892 $ 19,802,188
Production costs........................................ (8,377,044) (6,826,306) (5,639,630)
Depreciation, depletion, and amortization............... (15,812,134) (8,349,324) (7,590,877)
------------ ------------ ------------
28,581,494 7,352,262 6,571,681
Income taxes............................................ (9,689,126) (2,110,099) (1,511,487)
------------ ------------ ------------
Results of producing activities.........................$ 18,892,368 $ 5,242,163 $ 5,060,194
============ ============ ============
Amortization per physical unit of production
(equivalent Mcf of gas)......................... $ 0.81 $ 0.75 $ 0.79
============ ============ ============
</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
providing the Company with a minimum 5% net profits interest from the sale of
hydrocarbon products from the fields for providing managerial, technical, and
financial support to Senega. Additionally, the Company purchased a 1% net
profits interest from Senega for $300,000. In May 1995, the Company executed a
Management Agreement with Senega, under which, in return for undertaking to
obtain financing for development of these fields, Swift is entitled to receive a
49% interest in production income derived by Senega from this project after
repayment of costs.
On July 12, 1996, the Company entered into a partnership agreement which
provides for the Company to contribute its rights under the Participation and
Management Agreement to the partnership and for the partners to share equally
revenues and costs of developing the Samburg Field and funding and management of
the license areas, all in conjunction with Senega. The partnership is to be
funded by the partners upon fulfillment of certain conditions and completion of
certain further arrangements with Senega. It is currently anticipated that these
activities would be funded principally through project financing. At December
31, 1996, the Company's investment in Russia was approximately $9,530,000 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. Although the Company did not
win the bids, it continued to pursue cooperative ventures involving other fields
and opportunities in Venezuela. Currently, the Company is evaluating a number of
Blocks being offered by Petroleos de Venezuela, S.A. under the Third Operating
Agreement Round. At December 31, 1996, the Company's investment in Venezuela was
approximately $1,610,000 and is included in the unproved properties portion of
oil and gas properties net of impairments of $45,668.
Since October 1995, the Company has been issued two Petroleum Exploration
Permits by the New Zealand Minister of Energy. The first permit covers
approximately 65,000 acres in the Onshore Taranaki Basin of New Zealand's North
Island, and the second covers approximately 69,300 adjacent acres. Under the
terms of these permits, the Company is obligated to analyze and interpret
certain seismic data, acquire certain new seismic data, and drill one
exploratory well, to be followed by a development well or additional seismic
work, all of which is to be performed on a staged basis in order to maintain the
permits over periods extending through July 2000 for the first permit and August
1999 for the second permit. At December 31, 1996, the Company's investment in
New Zealand was approximately $750,000 and is included in the unproved
properties portion of oil and gas properties.
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 7, 1997, is set forth as an exhibit to the Form 10-K Report for the
year ended December 31, 1996, 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, 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
Revisions of previous estimates(2).................................. (9,544,391) (816,065)
Purchases of minerals in place...................................... 2,676,393 97,178
Sales of minerals in place.......................................... (4,163,770) (340,706)
Extensions, discoveries, and other additions........................ 107,762,886 1,745,307
Production(3)....................................................... (14,540,437) (623,386)
----------- ---------
Proved reserves as of December 31, 1996(1)............................. 225,758,201 5,484,309
=========== =========
Proved developed reserves,
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
December 31, 1996................................................... 135,424,880 3,622,480
</TABLE>
(1) Proved reserves exclude quantities subject to the Company's volumetric
production payment agreement.
(2) Revisions of previous quantity estimates are related to upward or downward
variations based on current engineering information for production rates,
volumetrics, and reservoir pressure. Additionally, changes in quantity estimates
are affected by the increase or decrease in crude oil and natural gas prices at
each year end. Proved reserves as of December 31, 1996, were based upon prices
of $4.47 per Mcf of natural gas and $23.75 per barrel of oil, compared to $2.41
per Mcf and $18.07 per barrel as of December 31, 1995.
(3) Natural gas production for 1994, 1995, and 1996 excludes 1,358,375,
1,211,255, and 1,156,361 Mcf, respectively, delivered under the Company's
volumetric production payment agreement.
31
<PAGE>
Standardized Measure of Discounted Future Net Cash Flows (Unaudited). The
standardized measure of discounted future net cash flows relating to proved oil
and gas reserves is as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------
1996 1995 1994
--------------- -------------- -------------
<S> <C> <C> <C>
Future gross revenues................................$ 1,141,831,786 $ 445,572,715 $ 211,210,430
Future production and development costs.............. (288,615,736) (163,925,771) (92,053,163)
--------------- -------------- -------------
Future net cash flows before income taxes............ 853,216,050 281,646,944 119,157,267
Future income taxes.................................. (211,375,632) (55,469,213) (14,143,796)
--------------- -------------- -------------
Future net cash flows after income taxes............. 641,840,418 226,177,731 105,013,471
Discount at 10% per annum............................ (274,608,116) (97,273,647) (38,541,504)
--------------- -------------- -------------
Standardized measure of discounted future
net cash flows relating to proved oil
and gas reserves...............................$ 367,232,302 $ 128,904,084 $ 66,471,967
=============== =============== =============
</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.
Natural gas prices have declined significantly since December 31, 1996.
Accordingly, the discounted future net cash flows shown above would be reduced
if the standardized measure were calculated in the first quarter of 1997.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------
1996 1995 1994
-------------- -------------- --------------
<S> <C> <C> <C>
Beginning balance..........................................$ 128,904,084 $ 66,471,967 $ 74,968,171
-------------- -------------- --------------
Revisions to reserves proved in prior years--
Net changes in prices, production costs, and future
development costs.................................... 144,386,724 25,415,116 (21,326,677)
Net changes due to revisions in quantity estimates...... (25,755,091) 4,735,186 (11,644,586)
Accretion of discount................................... 14,703,841 6,939,460 8,376,078
Other................................................... 6,649,394 (10,981,721) (5,631,646)
-------------- -------------- --------------
Total revisions............................................ 139,984,868 26,108,041 (30,226,831)
New field discoveries and extensions, net of future
production and development costs........................ 208,250,909 44,292,042 15,585,767
Purchases of minerals in place............................. 6,835,362 4,928,563 7,964,821
Sales of minerals in place................................. (8,084,581) (74,858) (574,651)
Sales of oil and gas produced, net of production costs..... (42,723,456) (13,913,612) (12,168,695)
Previously estimated development costs incurred............ 19,883,446 16,303,629 5,053,417
Net change in income taxes................................. (85,818,330) (15,211,688) 5,869,968
-------------- -------------- --------------
Net change in standardized measure of discounted
future net cash flows................................... 238,328,218 62,432,117 (8,496,204)
-------------- -------------- --------------
Ending balance.............................................$ 367,232,302 $ 128,904,084 $ 66,471,967
============== ============== ==============
</TABLE>
32
<PAGE>
10. Quarterly Results (Unaudited)
The following table presents summarized quarterly financial information for the
years ended December 31, 1995 and 1996:
<TABLE>
<CAPTION>
Net Income Fully Diluted
Income Before (Loss) Primary Income Income
Revenues Income Taxes (As Restated) Per Share Per Share
------------- ------------ ------------- -------------- ----------
<S> <C> <C> <C> <C> <C>
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
============= ============ ============= ======== =========
1996
First Quarter $ 11,188,847 $ 4,561,523 $ 3,082,381 $ .25 $ .22
Second Quarter 12,557,891 5,480,944 3,678,316 .29 .25
Third Quarter 15,432,193 7,178,573 4,641,953 .33 .31
Fourth Quarter 21,589,301 11,564,743 7,622,800 .50 .50
------------- ------------ ------------- -------- ---------
Total $ 60,768,232 $ 28,785,783 $ 19,025,450 $ 1.40 $ 1.37
============= ============ ============= ======== =========
</TABLE>
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 13, 1997 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 13, 1997 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 13, 1997 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 13, 1997 annual shareholders' meeting is
incorporated herein by reference.
33
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. The following consolidated financial statements of Swift Energy Company
together with the report thereon of Arthur Andersen LLP dated February 10,
1997, 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).1 (1) Articles of Incorporation, as amended through June 3, 1988.
3(a).2 (2) Articles of Amendment to Articles of Incorporation filed on June 4, 1990.
3(b) (3) By-Laws, as amended through August 14, 1995.
4(b) (4) Indenture dated as of June 30, 1993, between Swift Energy Company
and Bank One, Texas, National Association as Trustee.
10.1 (1)+ Indemnity Agreement dated July 8, 1988, between Swift Energy
Company and A. Earl Swift (plus schedule of other persons with whom Indemnity
Agreements have been entered into).
10.2 (4) Amended and Restated Credit Agreement dated March 24, 1992,
between Swift Energy Company and Bank One, Texas, National Association.
10.3 (4) Purchase and Sale Agreement dated May 27, 1992, between Swift
Energy Company and Enron Reserve Acquisition Corp.
10.4 (4) Purchase and Sale Agreement dated May 12, 1992, between the Company and Riverwood
Energy Resources, Inc.
10.5 (5) + Swift Energy Company 1990 Nonqualified Stock Option Plan.
10.6 (6) First Amendment effective May 13, 1993, to Amended and Restated
Credit Agreement dated March 24, 1992, between Swift Energy Company and Bank
One, Texas, National Association.
10.7 (6) Second Amendment effective December 31, 1993, to Amended and
Restated Credit Agreement dated March 24, 1992, between Swift Energy Company and
Bank One, Texas, National Association.
10.8 (6) Third Amendment dated December 31, 1994, to Amended and Restated
Credit Agreement dated March 24, 1992, between Swift Energy Company and Bank
One, Texas, National Association.
10.9 (7) Amended and Restated Credit Agreement dated March 1, 1994, among
Swift Energy Company, Bank One, Texas, National Association and Bank of
Montreal.
10.10(7) First Amendment dated June 15, 1994, to Amended and Restated
Credit Agreement dated March 1, 1994, among Swift Energy Company, Bank One,
Texas, National Association and Bank of Montreal.
10.11(6) Second Amendment dated December 31, 1994, to Amended and
Restated Credit Agreement dated March 1, 1994, among Swift Energy Company, Bank
One, Texas, National Association and Bank of Montreal.
10.12(8) Credit Agreement dated April 30, 1996, among Swift Energy
Company, Bank One, Texas, National Association and Bank of Montreal.
10.13(8) Credit Agreement dated April 30, 1996, among Swift Energy Company, Bank One, Texas,
National Association.
10.14(9) + Amended and Restated Swift Energy Company 1990 Stock Compensation Plan.
10.15(3) + Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and Terry E. Swift.
10.16(3) + Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and John R. Alden.
10.17(3) + Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and James M. Kitterman.
10.18(3) + Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and Bruce H. Vincent.
10.19(3) + Employment Agreement dated as of November 1, 1995, by and between Swift Energy
Company and A. Earl Swift.
10.20(9) + Agreement and Release between Swift Energy Company and Virgil Neil Swift effective June
1, 1994.
10.21(10)+ First Amendment to Agreement and Release dated as of 12/1/95,
by and between Swift Energy Company and Virgil Neil Swift.
10.22(10)+ Second Amendment to Agreement and Release dated as of 2/2/96,
by and between Swift Energy Company and Virgil Neil Swift, effective January 1,
1996.
10.23(10)+ Second [sic] Amendment to Agreement and Release dated as of
1/14/97, by and between Swift Energy Company and Virgil Neil Swift, effective
December 1, 1996.
18 (6) Letter from Arthur Andersen LLP regarding change in accounting principle.
21 (9) List of Subsidiaries of Swift Energy Company.
</TABLE>
34
<PAGE>
<TABLE>
<C> <S>
23(a)(10) The consent of H. J. Gruy and Associates, Inc.
23(b)(10) 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 (10) The summary of H. J. Gruy and Associates, Inc. report, dated February 7, 1997.
</TABLE>
(b) No Form 8-K reports were filed during the fourth quarter of 1996.
- ------------------------------
(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 Swift Energy Company Quarterly Report on
Form 10-Q filed for the quarterly period ended March 31, 1996.
(9) Incorporated by reference from Registration Statement No. 33-60469 filed
on June 22, 1995.
(10) Filed herewith.
+ Management contract or compensatory plan or arrangement.
35
<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,
on this 26th day of March 1997.
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>
Chairman of the Board
President and Chief Executive
/S/ A. Earl Swift Officer, Swift Energy
- ---------------------------------- Company March 26, 1997
A. Earl Swift
Senior Vice President--Finance,
/S/ John R. Alden Principal Financial Officer,
- ---------------------------------- Swift Energy Company March 26, 1997
John R. Alden
Vice President and
Controller, Principal
/S/ Alton D. Heckaman, Jr. Accounting Officer, Swift
- ---------------------------------- Energy Company March 26, 1997
Alton D. Heckaman, Jr.
/S/ Virgil N. Swift Director, Swift Energy
- ---------------------------------- Company March 26, 1997
Virgil N. Swift
</TABLE>
36
<PAGE>
<TABLE>
<CAPTION>
Signatures Title Date
---------- ----- ----
<S> <C> <C>
/S/ G. Robert Evans Director, Swift Energy
- ---------------------------------- Company March 26, 1997
G. Robert Evans
/S/ Raymond O. Loen Director, Swift Energy
- ---------------------------------- Company March 26, 1997
Raymond O. Loen
/S/ Henry C. Montgomery Director, Swift Energy
- ---------------------------------- Company March 26, 1997
Henry C. Montgomery
/S/ Clyde W. Smith, Jr. Director, Swift Energy
- ---------------------------------- Company March 26, 1997
Clyde W. Smith, Jr.
/S/ Harold J. Withrow Director, Swift Energy
- ---------------------------------- Company March 26, 1997
Harold J. Withrow
</TABLE>
37
<PAGE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20439
EXHIBITS
TO
FORM 10-K REPORT
FOR THE
YEAR ENDED DECEMBER 31, 1996
SWIFT ENERGY COMPANY
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060
38
<PAGE>
EXHIBITS
10.21 First Amendment to Agreement and Release dated as of 12/1/95, by and
between Swift Energy Company and Virgil Neil Swift.
10.22 Second Amendment to Agreement and Release dated as of 2/2/96, by and
between Swift Energy Company and Virgil Neil Swift, effective January 1,
1996.
10.23 Second [sic] Amendment to Agreement and Release dated as of 1/14/97, by
and between Swift Energy Company and Virgil Neil Swift, effective December
1, 1996.
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 7,
1997.
39
<PAGE>
EXHIBIT 10.21
40
<PAGE>
FIRST AMENDMENT
TO AGREEMENT AND RELEASE
The following Amendment is made and entered into between Virgil Neil Swift and
Swift Energy Company to add the following to the terms and provisions of the
Agreement and Release between Swift Energy Company and Virgil Neil Swift
executed June 1, 1994:
Eight-five (85) days following the date of termination of employment
under this Agreement by either party, all outstanding options to
purchase shares of common stock of the Company held by Mr. Swift
(whether vested or unvested) shall be converted into new non-qualified
options to purchase common stock of the Company. Each new non-qualified
option shall cover the same number of shares as the stock option which
it replaces, and shall be exercisable for five years, at an exercise
price which is the lower of (x) the closing price of the Company's
common stock on the New York Stock Exchange (or other exchange or
automated quotation system upon which it is listed or quoted) as of the
date of termination of employment or (y) the original exercise price of
the previously outstanding option which it replaces.
AGREED AND APPROVED: SWIFT ENERGY COMPANY
/s/ Virgil Neil Swift /s/ A. Earl Swift
- ---------------------------- ---------------------------
Virgil Neil Swift A. Earl Swift, President
12/1/95
CORPHOU:9136.1 14323-00005
41
<PAGE>
EXHIBIT 10.22
42
<PAGE>
SECOND AMENDMENT
TO AGREEMENT AND RELEASE
The following Amendment is made and entered into between Virgil N. Swift and
Swift Energy Company to add the following to the terms and provisions of the
Agreement and Release between Swift Energy Company and Virgil N. Swift executed
June 1, 1994:
Effective January 1, 1996 Virgil N. Swift will be paid for hours worked
in excess of the hours specified in the Agreement and Release. The rate
of compensation will be determined in accordance with minimum hours and
reduced salary as specified in Section I.D. and I.E. of the Agreement
and Release.
AGREED AND APPROVED: SWIFT ENERGY COMPANY
/s/ Virgil N. Swift /s/ A. Earl Swift
- ---------------------------- --------------------------------
Virgil N. Swift A. Earl Swift, President
2/2/96
CORPHOU:9136.1 14323-00005
43
<PAGE>
EXHIBIT 10.23
44
<PAGE>
SECOND AMENDMENT
TO AGREEMENT AND RELEASE
This is an amendment to the Agreement and Release previously entered
into between Virgil Neil Swift (hereinafter referred to as "Swift"), whose
current address is 2807 Trail Lodge, Kingwood, Texas 77339 and Swift Energy
Company (hereinafter referred to as "Company"), with current business address at
16825 Northchase, Houston, Texas 77060 executed and effective June 1, 1994 as
amended by First Amendment dated December 1, 1995.
The parties hereby amend paragraph 1 (E) of the prior Agreement and
Release in consideration of the fact that for much of the time said Agreement
has been in effect, Swift has spent more time providing services to Company than
ordinally anticipated, and the fact that he has done so has been of benefit to
Company. Accordingly, said paragraph is amended to provide that effective
December 1, 1996, for the remainder of the period of the original Agreement, it
is hereby agreed that for as long as Swift continues to provide services to
Company in accord with said original Agreement, but in excess of 30 hours per
week, his salary shall be changed to the rate of $6,750 per semi-monthly pay
period. In the event that Swift's hours of service drop to 30 hours or less per
week for more than four consecutive weeks, his salary shall revert to $5,377
adjusted for cost of living or by determination of the Compensation Committee of
the Board of Directors per the original Agreement. This amendment shall not
adversely impact any other provisions of the original Agreement, including the
cost of living provisions as set forth in paragraph 1 (E) thereof.
AGREED AND APPROVED SWIFT ENERGY COMPANY
/s/ Virgil Neil Swift /s/ A. Earl Swift
- ---------------------------- ------------------------------------
Virgil Neil Swift A. Earl Swift, President
Date: 1/10/97 Date: 1/14/97
----------------------- --------------------------------
CORPHOU:9136.1 14323-00005
45
<PAGE>
EXHIBIT 23 (A)
46
<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
H.J. Gruy and Associates, Inc. (Gruy) hereby consents to the reference
in the Annual Report on Form 10-K of Swift Energy Company for the year ended
December 31, 1996, to our letter report dated February 7, 1997, relating to our
audit of Swift Energy Company's estimates of proved oil and gas reserves.
Yours very truly,
BY: /S/ JAMES H. HARTSOCK
---------------------------------
Executive Vice President
Houston, Texas
March 26, 1997
47
<PAGE>
EXHIBIT 23 (B)
48
<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, 33-80228, 33-80240, and 333-12831.
ARTHUR ANDERSEN LLP
Houston, Texas
March 26, 1997
49
<PAGE>
EXHIBIT 99
50
<PAGE>
February 7, 1997
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Re: Reserves Audit
96-003-129
Gentlemen:
At your request, we have audited the reserves and future net cash flow as of
December 31, 1996, prepared by Swift Energy Company ("Swift") for certain
interests owned by Swift through partnerships in 15 drilling funds, 29 income
funds, 16 pension asset funds, and 34 depositary interest funds along with
several additional interests owned directly by Swift Energy Company. This audit
has been conducted according to the standards pertaining to the estimating and
auditing of oil and gas reserve information approved by the Board of Directors
of the Society of Petroleum Engineers on October 30, 1979. We have reviewed
these properties and where we disagreed with the Swift reserve estimates, Swift
revised its estimates to be in agreement. The estimated net reserves, future net
cash flow and discounted future net cash flow are summarized by reserve category
as follows:
<TABLE>
<CAPTION>
Estimated Estimated
Net Reserves Future Net Cash Flow
---------------------------------- ------------------------------------
Oil & Discounted
Condensate Gas at 10%
(Barrels) (Mcf) Nondiscounted Per Year
----------- ------------- --------------- --------------
<S> <C> <C> <C> <C>
Proved Developed 3,622,480 135,424,880 $ 539,110,044 $ 310,408,949
Proved Undeveloped 1,861,829 90,333,321 $ 314,106,001 $ 160,776,008
---------- ------------- --------------- --------------
Total Proved 5,484,309 225,758,201 $ 853,216,045 $ 471,184,957
G & A $ (6,287,920) $ (3,216,558)
---------- ------------- --------------- --------------
TOTAL 5,484,309 225,758,201 $ 846,928,125 $ 467,968,399
</TABLE>
The discounted future net cash flow is not represented to be the fair market
value of these reserves and the estimated reserves included in this report have
not been adjusted for risk.
51
<PAGE>
Swift Energy Company - 2 - February 7, 1997
The estimated future net cash flow 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 cash flow as stated in this report is before the
deduction of federal income tax.
In the economic projections, prices, operating costs and development costs
remain constant for the projected life of each lease.
For those wells with sufficient production history, reserve estimates and rate
projections are based on the extrapolation of established performance trends.
Reserves for other producing and nonproducing properties have been estimated
from volumetric calculations and analogy with the performance of comparable
wells. The reserves included in this study are estimates only and should not be
construed as exact quantities. Future conditions may affect recovery of
estimated reserves and cash flow, and all categories of reserves may be subject
to revision as more performance data become available. The proved reserves in
this report conform to the applicable definitions promulgated by the Securities
and Exchange Commission. Attachment 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 1996 except in those instances in which data were
available through December. Interim production to December 31, 1996 has been
estimated. No independent well tests, property inspections or audits of
operating expenses were conducted by our staff in conjunction with this study.
We did not verify or determine the extent, character, obligations, status or
liabilities, if any, arising from any current or possible future environmental
liabilities that might be applicable.
In order to audit the reserves, costs and future cash flows shown in this
report, we have relied in part on geological, engineering and economic data
furnished by our client. Although we have made a best efforts attempt to acquire
all pertinent data and to analyze it carefully with methods accepted by the
petroleum industry, there is no guarantee that the volumes of oil or gas or the
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 cash flow projections presented in this report may
require revision as additional data become available.
52
<PAGE>
Swift Energy Company - 3 - February 7, 1997
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:rrw
Attachment
53
<PAGE>
ATTACHMENT I
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 reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) Oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
Proved Developed Oil and Gas Reserves
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
54
<PAGE>
Proved Undeveloped Reserves
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
55
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This Schedule contains summary financial information extracted from Swift Energy
Company's financial statements contained in its annual report on Form 10-K for
the year ended December 31, 1996.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 77,794,974
<SECURITIES> 0
<RECEIVABLES> 23,872,869
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 101,619,478
<PP&E> 249,659,723
<DEPRECIATION> 46,685,736
<TOTAL-ASSETS> 310,375,264
<CURRENT-LIABILITIES> 32,915,616
<BONDS> 0
0
0
<COMMON> 151,764
<OTHER-SE> 142,609,846
<TOTAL-LIABILITY-AND-EQUITY> 310,375,264
<SALES> 52,770,672
<TOTAL-REVENUES> 60,768,232
<CGS> 0
<TOTAL-COSTS> 24,903,423<F1>
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 693,959
<INCOME-PRETAX> 28,785,783
<INCOME-TAX> 9,760,333
<INCOME-CONTINUING> 19,025,450
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 19,025,450
<EPS-PRIMARY> 1.40
<EPS-DILUTED> 1.37
<FN>
<F1>Includes depreciation, depletion and amortization expense and oil and gas
production costs. Excludes general and administrative and interest expense.
</FN>
</TABLE>
