SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K/A
Amendment No. 2
Annual Report Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
For the Fiscal Year Ended December 31, 2002
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
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. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes X No
------ -----
The aggregate market value of the voting stock held by non-affiliates at March
1, 2003 was approximately $246,766,019.
The number of shares of common stock outstanding as of December 31, 2002 was
27,201,509 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, 2003
EXPLANATORY NOTE
This Amendment No. 2 to the Swift Energy Company Annual Report on Form
10-K for the fiscal year ended December 31, 2002 is being filed solely to
correct typographical errors in the Certifications for the Chief Executive
Officer and Chief Financial Officer filed pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
Form 10-K
Swift Energy Company and Subsidiaries
10-K Part and Item No. Page
Part I
Item 1. Business 3
Item 2. Properties 6
Item 3. Legal Proceedings 19
Item 4. Submission of Matters to a Vote of
Security Holders 19
Part II
Item 5. Market for the Registrant's Common
Equity and Related Stockholder Matters 19
Item 6. Selected Financial Data 20
Item 7. Management's Discussion and
Analysis of Financial Condition
and Results of Operations 22
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 32
Item 8. Financial Statements and Supple-
mentary Data 33
Item 9. Changes in and Disagreements with
Accountants on Accounting and
Financial Disclosure 58
Part III
Item 10. Directors and Executive Officers of
the Registrant (1) 58
Item 11. Executive Compensation (1) 58
Item 12. Security Ownership of Certain Bene-
ficial Owners and Management (1) 58
Item 13. Certain Relationships and Related
Transactions (1) 58
Item 14 Controls and Procedures 58
Part IV
Item 15 Exhibits, Financial Statement
Schedules and Reports on Form 8-K 59
(1) Incorporated by reference from Notice and Proxy Statement for the
Annual Meeting of Shareholders to be held May 13, 2003.
PART I
Items 1 and 2. Business and Properties
See pages 18 and 19 for explanations of abbreviations and terms used
herein.
General
Swift Energy Company is engaged in developing, exploring, acquiring, and
operating oil and gas properties, with a focus on onshore and inland waters oil
and natural gas reserves in Texas and Louisiana and onshore oil and natural gas
reserves in New Zealand. The Company was founded in 1979 and is headquartered in
Houston, Texas. As of December 31, 2002, we had interests in 932 wells located
domestically in three states, in federal offshore waters, and in New Zealand. We
operated 820 of these wells representing 95% our proved reserves. At year-end
2002, we had estimated proved reserves of 749.4 Bcfe, of which approximately 44%
was natural gas, 42% crude oil, and 14% NGLs, and overall 60% was proved
developed. Our proved reserves are concentrated 41% in Texas, 35% in Louisiana,
and 21% in New Zealand.
We currently focus primarily on development and exploration in four
domestic core areas and two core areas in New Zealand:
% of Year-End % of 2002
Area Location 2002 Proved Reserves Production
------------------------- -------------------------- --------------------------- ----------------
AWP Olmos South Texas 30% 22%
Brookeland East Texas 6% 8%
Lake Washington South Louisiana 25% 9%
Masters Creek Central Louisiana 10% 20%
Rimu/Kauri New Zealand 12% 3%
TAWN New Zealand 9% 28%
--------------------------- ---------------
% of Total 92% 90%
--------------------------- ---------------
We have a well-balanced portfolio of oil and gas properties and prospects.
The AWP Olmos and Lake Washington areas and New Zealand are characterized by
long-lived reserves that we expect to be steadily produced over a long period of
time. The Masters Creek and Brookeland areas are characterized by shorter-lived
reserves with high initial rates of production that decline rapidly. We believe
these shorter-lived reserves complement our long-lived reserves. We focus on
drilling the long-lived properties during periods of decreasing commodity
prices, while the shorter-lived properties provide additional drillable projects
in periods of rising commodity prices. Based on 2002 year-end proved reserves
and 2002 production, we calculated our average reserve life as 17.4 years
domestically and 10.0 years in New Zealand.
We have increased our proved reserves from 361.5 Bcfe at year-end 1997 to
749.4 Bcfe at year-end 2002, which has resulted in the replacement of 278% of
our production during the same five-year period. Our five-year average reserves
replacement costs were $1.25 per Mcfe. Our average annual reserve replacement
costs for the last five years, starting with 2002 were $0.96, $3.30, $0.81,
$1.27 and $1.20 per Mcfe. In 2002, we increased our proved reserves by 16%,
which replaced 308% of our 2002 production. Our 2002 production increased by 11%
in relation to 2001 production. We have increased our production from 25.4 Bcfe
at year-end 1997 to 49.8 Bcfe at year-end 2002. Primarily due to increased
production, this has resulted in average annual growth in net cash provided by
operating activities of 5% per year from year-end 1997 to year-end 2002, even
though in 2002 net cash provided by operating activities fell 49% due to pricing
changes.
Through intensive efforts, we have developed an inventory of exploration
and development prospects, identifying drilling locations through integrated
geological and geophysical studies of our undeveloped acreage and other
prospects. As a result, we added 184.7 Bcfe of proved reserves through drilling
in 2000 (122.5 Bcfe from New Zealand), 105.8 Bcfe in 2001 (17.4 Bcfe from New
Zealand), and 83.9 Bcfe in 2002 (15.9 Bcfe from New Zealand). The 2002 additions
were primarily a result of our development success rate, as 17 of 23 domestic
development wells drilled were successful, while three of seven domestic
exploratory wells were successful.
1
We purchased interests in the Brookeland and Masters Creek areas from Sonat
Exploration Company in the third quarter of 1998 for approximately $85.8 million
in cash. In the first quarter of 2001, we purchased interests in the Lake
Washington field from Elysium Energy, LLC, for approximately $30.5 million in
cash. In the first quarter of 2002, we purchased interests in the four TAWN
fields in New Zealand for approximately $51.4 million, which also included
significant infrastructure, after purchase price adjustments.
We currently plan to spend $115 to $130 million in total capital
expenditures in 2003, excluding acquisition costs and net of approximately $5
million to $15 million in non-core property dispositions. The budget for 2003 is
largely dependent upon our performance and commodity pricing during the year.
Domestic activities account for 85% of our budgeted spending, primarily in the
Lake Washington Area.
Competitive Strengths and Business Strategy
We believe that our competitive strengths, together with a balanced and
comprehensive business strategy, provide us with the flexibility and capability
to accomplish our goals.
Balanced Approach to Adding Reserves
When we believe the market favors increasing reserves through acquisitions,
we apply our considerable experience in evaluating and negotiating prospective
acquisitions. For example, in 1998, when commodity prices were relatively weak,
32% of our capital expenditures consisted of property acquisitions, with 37%
committed to our drilling activities. In contrast, in 2001, when commodity
prices were relatively strong in the first half of the year, only 15% of our
capital expenditures were spent on property acquisitions, with our drilling
expenditures increasing to 67% of total capital expended. We believe this
balanced approach has resulted in our ability to grow reserves in a relatively
low cost manner, while participating in the upside potential of exploration.
Our strategy is to increase our reserves and production through both
drilling and acquisitions, shifting the balance between the two activities in
response to market conditions. Generally, we seek to acquire properties with the
potential for additional reserves and production through development and
exploration efforts. In addition, we seek to enhance the results of our drilling
and production efforts through the implementation of advanced technologies.
During 2002, in response to strong oil prices throughout the year, we
focused our capital expenditures on the Lake Washington Area domestically and on
the TAWN acquisition in New Zealand. Although oil prices remained strong in
2002, natural gas prices for most of the year were lower than prior year levels,
and our cash flow generated due to these commodity prices decreased, as
expected, even though production increased. As a result of lower cash flow in
2002, we reduced our capital expenditures to $155.2 million. Of this amount,
$58.4 million was spent on acquisitions, mainly the TAWN acquisition in New
Zealand. We spent $42.7 million on drilling in the United States, with $34.4 for
development drilling and $8.3 million for exploratory drilling. In New Zealand
we spent $22.9 million on drilling, with $12.6 million for development drilling
and $10.3 million for exploratory drilling. We also spent $10.6 million
constructing a gas processing plant in New Zealand. The remaining capital
expenditures of $20.6 million were spent primarily on leasehold, seismic, and
geological costs of prospects, both in the United States and New Zealand. During
2002, we principally relied upon cash flows from operations of $71.6 million,
net proceeds from the issuance of long-term debt of $195.0 million, and net
proceeds from our public stock offering of $30.5 million, less the repayment of
bank borrowings of $134.0 million, to fund our capital expenditures.
In 145 transactions from 1979 to 2002, we have acquired approximately
$695.7 million of producing oil and gas properties on behalf of our co-investors
and ourselves. We acquired, for our own account, approximately $339.2 million of
producing properties, with original proved reserves estimated at 468.5 Bcfe
during this period. Our producing property acquisition expenditures in the past
three years were $64.2 million in 2002, $41.3 million in 2001, and $34.2 million
in 2000. Our acquisition costs have averaged $0.83 per Mcfe over this three-year
period. Our acquisition cost in 2002 averaged $0.87 per Mcfe.
Concentrated Focus on Core Areas
Our concentration of reserves and our significant acreage positions in our
core areas allow us to realize economies of scale in drilling and production. We
enhance the value of this concentration by acting as the operator of 95% of our
proved reserves at year-end 2002. Our operational control allows us to better
manage production, control our expenses, allocate capital and time field
development. We intend to continue to acquire large acreage positions in
under-explored and under-exploited areas, where, as operator, we can exploit
successful discoveries to create new core areas or grow production from
developed fields. In executing this strategy:
2
o We focus our resources on acquiring properties that we can operate, and in
which we can obtain a significant working interest. With operational
control, we can apply our technical and operational expertise to optimize
our exploration and exploitation of the properties that we acquire.
o We acquire and operate domestic properties in a limited number of
geographic areas. Operating in a concentrated area helps us to better
control our overhead by enabling us to manage a greater amount of acreage
with fewer employees, minimizing incremental costs of increased drilling
and production.
o We continue to believe in natural gas prospects and reserves in the United
States. The natural gas market in the United States has a well-developed
infrastructure. Natural gas is viewed by many as the preferred fuel in
North America for several reasons, including environmental concerns. We
have a strong inventory of natural gas that can be developed in a higher
priced environment.
o We seek to operate large acreage positions with high exploration and
development potential. For example, on our original 100,000 acre New
Zealand permit, only two wells had been drilled at the time that we
acquired our interest. The Masters Creek, Brookeland and Lake Washington
areas also had significant additional development potential when we first
acquired our interest in those areas.
Ability to Build Upon our Recent Discoveries and Acquisitions in New Zealand
Our New Zealand activities provide us with long-term growth opportunities
and significant potential reserves in a country with stable political and
economic conditions, existing oil and gas infrastructure, and favorable tax and
royalty regimes. We have completed construction of our Rimu production and gas
processing facilities, which became operational in May 2002 and enabled us to
begin the sale of production from the Rimu/Kauri area. We were able to bring our
Rimu discovery on commercial production in a significantly shorter period than
any other similar project previously undertaken in New Zealand of which we are
aware.
In January 2002, we acquired the TAWN fields. In our TAWN acquisition, we
also acquired extensive associated processing facilities and pipelines, which
give us a competitive advantage through infrastructure that complements our
existing fields, providing us with increased access to export terminals and
markets and additional excess processing capacity for both oil and natural gas.
Experienced Technical Team
We employ oil and gas professionals, including geophysicists,
petrophysicists, geologists, petroleum engineers, and production and reservoir
engineers, who have an average of approximately 25 years of experience in their
technical fields and have been employed by Swift for an average of over 10
years. We continually apply our extensive in-house expertise and current
advanced technologies to benefit our drilling and production operations. We have
developed a particular expertise in drilling horizontal wells at vertical depths
below 10,000 feet, often in a high-pressure environment, involving single or
dual lateral legs of several thousand feet. This results in an integrated
approach to exploration using multidisciplinary data analysis and interpretation
that has helped us identify a number of exploration prospects.
We use various recovery techniques, including water flooding and acid
treatments, fracturing reservoir rock through the injection of high-pressure
fluid, gravel packing, and inserting coiled tubing velocity strings to enhance
and maintain gas flow. We believe that the application of fracturing technology
and coiled tubing has resulted in significant increases in production and
decreases in completion and operating costs, particularly in our AWP Olmos Area.
We have increasingly used seismic technology to enhance the results of our
drilling and production efforts, including 2-D and 3-D seismic analysis,
amplitude versus offset studies, and detailed formation depletion studies. As a
result, we have maintained internal seismic expertise and have compiled an
extensive database.
When appropriate, we develop new applications for existing technology. For
example, in New Zealand we acquired seismic data by effectively combining marine
data with the acquisition of land seismic data, an application we have not seen
any other company use in New Zealand.
3
Financial Discipline
We practice a disciplined approach to financial management and have
historically maintained a strong capital structure that preserves our ability to
execute our business plan. Key components of our financial discipline include
maintaining a capital budget balanced between drilling and acquisitions,
establishing leverage targets that are reasonable given the volatility of the
oil and gas markets, and opportunistically accessing the capital markets. As of
December 31, 2002, our long-term debt comprised approximately 47% of our total
capitalization. We applied the net proceeds from our common stock offering and
debt offering in April 2002 in the amount of $225.5 million to reduce amounts
outstanding under our credit facility. At December 31, 2002, we had $194.2
million of available borrowing capacity. By replacing indebtedness incurred
under our revolving credit facility in connection with acquisition, development,
and exploitation activity with the net proceeds from our common stock offering
and debt offering, we implemented our strategy of matching long-lived assets
with long-term financing.
Domestic Core Operating Areas
AWP Olmos Area. As of December 31, 2002, we owned approximately 27,900 net
acres in the AWP Olmos Area in South Texas. We have extensive expertise and a
long history of experience with low-permeability, tight-sand formations typical
of this area, having acquired our first acreage there in 1988. These reserves
are approximately 66% gas. At year-end 2002, we owned interests in 495 wells and
operated 494 wells in this area producing gas from the Olmos sand formation at
depths of approximately 9,000 to 11,500 feet. We own nearly 100% of the working
interests in all our operated wells.
In 2002, we performed four fracture extensions and installed coiled tubing
velocity strings in five wells. At year-end 2002, we had 128 proved undeveloped
locations. Also in 2002, we purchased interests in the AWP Olmos area from
partnerships we managed. Our planned 2003 capital expenditures in this area will
focus on drilling 10 wells and performing fracture extensions and installing
coiled tubing velocity strings to maintain a flat production profile.
Brookeland Area. As of December 31, 2002, we owned drilling and production
rights in 76,259 net acres and 3,500 fee mineral acres in this area, which
contains substantial proved undeveloped reserves. This area was part of the
acquisition from Sonat in 1998 and is located in East Texas near the border of
Louisiana in Jasper and Newton counties. It primarily contains horizontal wells
producing from the Austin Chalk formation. The reserves are approximately 55%
oil and natural gas liquids. At year-end 2002, we had 13 proved undeveloped
locations in this area. Our planned 2003 capital expenditures in this area
include drilling one development well.
Lake Washington Field. As of December 31, 2002, we owned drilling and
production rights in 11,080 net acres in the Lake Washington Field. This area is
located in Plaquemines Parish in South Louisiana. The reserves are approximately
98% oil and natural gas liquids. We acquired interests in the Lake Washington
Field in March 2001. This field produces oil from multiple Miocene sands ranging
in depth from less than 1,700 feet to greater than 9,000 feet. The field is
located on a salt dome and has produced over 300 million BOE since its inception
in the 1930s. The area around the dome is heavily faulted, thereby creating a
large number of potential traps. Oil and gas from approximately 38 producing
wells is gathered from three platforms located in water depths from 6 to 11
feet, with drilling and workover operations performed with barge rigs. In 2002,
23 development wells and four exploratory wells were drilled in the area; 17
development and two exploratory wells were successful. At year-end 2002, we had
63 proved undeveloped locations in this field. Our planned 2003 capital
expenditures in this area include drilling 50 to 60 development wells and one
saltwater disposal well.
Masters Creek Area. As of December 31, 2002, we owned drilling and
production rights in 77,475 net acres and 107,000 fee mineral acres in this
area, which contains substantial proved undeveloped reserves. This area was also
part of the acquisition from Sonat in 1998. It is located in Central Louisiana
near the Texas-Louisiana border in the two parishes of Vernon and Rapides. It
contains horizontal wells producing both oil and gas from the Austin Chalk
formation. The reserves are approximately 72% oil and natural gas liquids. At
year-end 2002, we had 12 proved undeveloped locations in the area. Our planned
2003 capital expenditures in this area include drilling one development well.
Domestic Emerging Growth Areas
The Frio Trend. We have been focusing on the deep sands of the Frio
formation (10,000 to 16,000 feet) in an area that straddles the border of Kenedy
County and Willacy County in the southern tip of Texas and is identified as
Garcia Ranch. Retaining a 65% working interest, we had two discoveries in the
area in 2001, one in the Rome prospect in Willacy County and the other in the
Siena prospect in Kenedy County. In 2002, we participated in a successful
non-operated well with a 33% working interest in the Milan prospect in Kenedy
county. We plan to participate in drilling two development wells in 2003 in this
area.
4
The Wilcox Sands. We had three discoveries in the Wilcox sands during 2001,
two of which were located in Goliad County, Texas: the Nita prospect drilled to
a depth of approximately 15,000 feet and the Brandon prospect drilled to a depth
of about 13,000 feet. Our working interests in the two wells are 73% and 60%,
respectively. The third well, in which we have a 25% working interest, was in
the Falcon Ridge prospect in Zapata County, Texas. We plan to participate in one
development well in this area in 2003.
The Woodbine Formation. The Woodbine formation is located in southeast
Texas in San Jacinto, Polk, and Tyler counties. We drilled one well to the
Woodbine formation in 2001, in the Lion prospect in San Jacinto County, Texas,
to a depth of 15,000 feet. Although hydrocarbon-bearing intervals were found,
the well was deemed noncommercial. The Company has two other Woodbine prospects,
the Jaguar and Bobcat prospects, both located in Polk County.
The Miocene Sands. We successfully drilled our first exploratory well in
the Miocene sands in our Lake Washington Area in Plaquemines Parish, Louisiana,
to a depth of 3,348 feet with a retained interest of 100%. This area has
substantial exploration and development potential, with sands extending from
shallow depths down to 10,000 feet or more. Through 2002, we have drilled 28
wells in this area.
New Zealand Core Operating Areas
Our activity in New Zealand began in 1995. As of December 31, 2002, our
permit 38719, which we operate, included approximately 49,800 acres in the
Taranaki Basin of New Zealand's north island. This acreage includes our Rimu and
Kauri areas as well as our Tawa and Matai prospects.
We expanded our operation in New Zealand in January 2002 with our TAWN
purchase of Southern Petroleum (NZ) Exploration, Limited, from Shell New
Zealand, through which we acquired interests in four fields and significant
infrastructure assets.
In March 2002, we completed the acquisition of all of the New Zealand
assets of Antrim. These assets included a 5% working interest in the
Swift-operated permit 38719, increasing the Company's interest in this permit to
95%. An additional 7.5% interest was also acquired in permit 38716 (Huinga
prospect), increasing the Company's interest to 15%.
In August 2002, we were awarded two additional onshore permits, permits
38756 and 38759. These permits include approximately 8,100 and 20,400 gross
acres, respectively, in proximity to our permit 38719.
In September 2002, we completed the acquisition of Bligh's 5% working
interest in permit 38719 and 5% interest in the Rimu petroleum mining permit
38151, along with their 3.24% working interest in the four TAWN petroleum mining
licenses. The Company's interests in permit 38719, petroleum mining permit
38151, and the TAWN petroleum mining licenses are now 100%.
In December 2002, we agreed to acquire an additional 50% interest in permit
38718 (Tuihu prospect) from Shell New Zealand through an existing pre-emptive
right under the joint operating agreement. Following the transaction, SENZ will
sell a 20% interest in the permit to a subsidiary of New Zealand Oil and Gas
Limited. The purchase and subsequent sale, which are subject to certain
government notifications, approvals and consents, will result in SENZ holding a
50% working interest in this permit. We were named operator of the permit.
Permit 38718 contains the Tuihu #1 exploratory well, which was drilled in 2001
and temporarily abandoned. Our 2003 budget calls for a re-entry of this well,
which will sidetrack or deepen the original well.
As of December 31, 2002, our gross investment in New Zealand totaled
approximately $172.8 million. Approximately $145.0 million of our investment
costs have been included in the proved properties portion of our oil and gas
properties, while $27.8 million is included as unproved properties.
Rimu Area. Early in 2002, we were awarded petroleum mining permit 38151 by
the New Zealand Ministry for Economic Development for the development of the
Rimu discovery over an approximately 5,500 acre area for a primary term of 30
years. Commercial production from the Rimu area began in May 2002.
During the first quarter of 2002, the Rimu-A2 sidetrack was completed and
recently underwent fracture stimulation, which was unsuccessful. We plan a CO2
stimulation project during the first half of 2003 to improve its productibility.
The Rimu-B3 development well was also sidetracked in early 2002 but was
unsuccessful.
5
Kauri Area. During 2002, three wells were drilled in the Kauri area. The
Kauri-A1 exploratory well was drilled to the Upper Tariki sand, the Kauri-A3
development well was drilled to the shallow Manutahi sands, and the Kauri-A4
exploratory well was drilled through the Kauri sands and on down to the Lower
Tariki sand, which was found to be too wet for commercial production. After the
drilling of the Kauri-A4 well was completed in October 2002, pipe was set in the
well and perforated over approximately 33 feet of the Kauri sands in preparation
for a hydraulic fracture stimulation in early 2003.
TAWN Area. The TAWN acquisition in January 2002 consisted of a 96.76%
working interest in four petroleum mining licenses, or PML, covering producing
oil and gas fields, and extensive associated hydrocarbon-processing facilities
and pipelines, which give us a competitive advantage through infrastructure that
complements our existing fields, providing us with increased access to export
terminals and markets and additional excess processing capacity for both oil and
natural gas. The TAWN assets are located approximately 17 miles north of the
Rimu area.
The properties are collectively identified as the TAWN properties, an
acronym derived from the first letters of the field names - the Tariki Field
(PML 38138), the Ahuroa Field (PML 38139), the Waihapa Field (PML 38140), and
the Ngaere Field (PML 38141). The four fields include 17 wells where the
purchaser of gas, Contact Energy, has contracted to take minimum quantities and
can call for higher production levels to meet electrical demand in New Zealand.
Sales gas deliveries to Contact have exceeded the contract minimum during all of
2002.
Solution gas gathered from the Waihapa Production Station ("WPS") flows to
the Tariki Ahuroa gas plant ("TAG"). The current processing capacity of the WPS
facility is up to 15,000 barrels of oil and 40 MMcf of natural gas per day.
Processing capacity tests conducted following facility modifications completed
in the third quarter have confirmed a 12% increase in the gas processing
capacity of the TAG plant. A 32-mile, 8-inch diameter oil export line runs from
the WPS to the Omata Tank Farm at New Plymouth, where oil export facilities
allow for sales into international markets. An additional 32-mile, 8-inch
diameter natural gas pipeline runs from the WPS to the Taranaki Combined Cycle
Electric Generation Facility near Stratford and on to the New Plymouth Power
Station.
We have a service agreement with the owner of the Omata Tank Farm to
utilize the blending, storage, and export capabilities of the facility. The
operator of the facility provides services for a fixed fee per barrel received
and other variable costs as required by the agreement. Under the terms of the
agreement, crude oil produced from the TAWN and Rimu/Kauri areas have access to
the Omata Tank Farm.
Our current contract with Shell Petroleum Mining (SPM), which purchases all
of our New Zealand crude oil production, runs through the end of 2003. The
delivery point for our crude oil sales is the ship's flange. SPM and the Omata
Tank Farm coordinate logistical issues for shipments, and thus SPM's decisions
regarding sales from the Omata Tank Farm can affect the timing of sales of that
portion of our production.
Rimu Production Station. We completed construction on the Rimu Production
Station ("RPS") during the first quarter of 2002, and production was processed
through this facility beginning in the second quarter of 2002. Our oil
production processed through the RPS is transported the 17 miles by truck to our
WPS facility and then sent by pipeline to the Omata Tank Farm. Our natural gas
production processed through the RPS is sold to Genesis Power Ltd. under a
long-term contract. Natural gas prices are substantially lower in New Zealand,
as compared to domestic prices, largely due to the fact that the natural gas
market has been dominated by one large field, the Maui Field, which supplies
approximately 70% of the natural gas supply but is due to be depleted by 2007.
New Zealand Emerging Growth Areas
The Tawa prospect is located northwest of the Rimu and Kauri areas in the
same permit. Its main targets are the Kapuni sands, the Kauri sandstones, and
the Tariki sandstone. Consisting of a combination of structural and
stratigraphic traps, this prospect was developed based upon Swift's analysis of
existing three-dimensional seismic data plus two-dimensional seismic data
acquired during Company surveys in 1997 and 2000.
The Matai prospect, located on the southeast flank of the Tawa prospect
also in permit 37819, will target the Moki and Urenui sandstones. It was
identified based upon the analysis of the two-dimensional seismic data Swift
acquired in 2000.
6
The Tuihu prospect, permit 38718, is located northeast of our TAWN Area. In
December 2002, we agreed to acquire an additional 50% interest in permit 38718
from Shell New Zealand though an existing pre-emptive right under the joint
operating agreement. Following the transaction, SENZ will sell a 20% interest in
the permit to a subsidiary of New Zealand Oil and Gas Limited. The purchase and
subsequent sale, which are subject to certain government notifications,
approvals and consents, will result in SENZ holding a 50% working interest in
this permit. We were named operator of the permit. Permit 38718 contains the
Tuihu #1 exploratory well, which was drilled in 2001 and was temporarily
abandoned. Our 2003 budget calls for a re-entry of this well, which will
sidetrack or deepen the original well.
The Huinga prospect, permit 38716, is located northeast of our Rimu/Kauri
areas. An exploratory well was drilled on this permit, of which we own 15%, in
1998 and was temporarily abandoned. This well was re-entered in 2002 and was
unsuccessful. The operator is currently re-evaluating this prospect.
Oil and Gas Reserves
The following table presents information regarding proved reserves of oil
and gas attributable to our interests in producing properties as of December 31,
2002, 2001, and 2000. The information set forth in the table regarding reserves
is based on proved reserves reports prepared by us and audited by H. J. Gruy and
Associates, Inc., Houston, Texas, independent petroleum engineers. Gruy's audit
was based upon review of production histories and other geological, economic,
ownership, and engineering data provided by Swift.
In accordance with Securities and Exchange Commission guidelines, estimates
of future net revenues from our proved reserves and the PV-10 Value must be 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, 2002, were estimated based upon prices in effect at year-end.
The weighted averages of such year-end prices domestically were $4.23 per Mcf of
natural gas, $29.36 per barrel of oil, and $17.30 per barrel of NGL, compared to
$2.68, $18.51, and $11.00 at year-end 2001 and $11.25, $25.50, and $20.30 at
year-end 2000, respectively. The weighted averages of such year-end 2002 prices
for New Zealand were $1.48 per Mcf of natural gas, $28.80 per barrel of oil, and
$12.24 per barrel of NGL, compared to $1.18, $18.25, and $8.90 in 2001,
respectively. The weighted averages of such year-end 2002 prices for all our
reserves, both domestically and in New Zealand, were $3.49 per Mcf of natural
gas, $29.27 per barrel of oil, and $16.54 per barrel of NGL, compared to $2.51,
$18.45, and $10.70 in 2001, respectively. We have 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 table sets forth estimates of future net revenues presented on the
basis of unescalated prices and costs in accordance with criteria prescribed by
the Securities and Exchange Commission and their PV-10 Value. Operating costs,
development costs, and certain production-related taxes were deducted in
arriving at the estimated future net revenues. No provision was made for income
taxes. The estimates of future net revenues and their present value differ in
this respect from the standardized measure of discounted future net cash flows
set forth in Supplemental Information to our Consolidated Financial Statements,
which is calculated after provision for future income taxes.
7
Year Ended December 31, 2002
---------------------------------------------------------------
Total Domestic New Zealand
---------------------- ----------------- -------------------
Estimated Proved Oil and Gas Reserves
Net natural gas reserves (Mcf):
Proved developed 233,514,572 149,731,562 83,783,010
Proved undeveloped 93,217,100 90,092,500 3,124,600
---------------------- ------------------ ------------------
Total 326,731,672 239,824,062 86,907,610
====================== ================== ==================
Net oil and NGL reserves (Bbl):
Proved developed 35,928,395 26,530,112 9,398,283
Proved undeveloped 34,510,568 32,499,528 2,011,040
---------------------- ------------------ ------------------
Total 70,438,963 59,029,640 11,409,323
====================== ================== ==================
Estimated Present Value of Proved Reserves
Estimated present value of future net cash flows
from proved reserves discounted at 10% annum:
Proved developed $ 679,356,172 $ 516,832,848 $ 162,523,324
Proved undeveloped 481,833,151 456,632,145 25,201,006
---------------------- ------------------ ------------------
Total $ 1,161,189,323 $ 973,464,993 $ 187,724,330
====================== ================== ==================
Year Ended December 31, 2001
---------------------------------------------------------------
Total Domestic New Zealand
---------------------- ----------------- -------------------
Estimated Proved Oil and Gas Reserves
Net natural gas reserves (Mcf):
Proved developed 181,651,578 167,401,736 14,249,842
Proved undeveloped 143,260,547 121,087,764 22,172,783
---------------------- ------------------ ------------------
Total 324,912,125 288,489,500 36,422,625
====================== ================== ==================
Net oil and NGL reserves (Bbl):
Proved developed 23,759,574 20,393,142 3,366,432
Proved undeveloped 29,723,062 22,171,591 7,551,471
---------------------- ------------------ ------------------
Total 53,482,636 42,564,733 10,917,903
====================== ================== ==================
Estimated Present Value of Proved Reserves
Estimated present value of future net cash flows
from proved reserves discounted at 10% annum:
Proved developed $ 344,478,834 $ 306,095,381 $ 38,383,453
Proved undeveloped 258,507,354 186,012,413 72,494,941
---------------------- ------------------ ------------------
Total $ 602,986,188 $ 492,107,794 $ 110,878,394
====================== ================== ==================
8
Year Ended December 31, 2000
---------------------------------------------------------------
Total Domestic New Zealand
---------------------- ----------------- -------------------
Estimated Proved Oil and Gas Reserves
Net natural gas reserves (Mcf):
Proved developed 215,169,833 215,169,833 --
Proved undeveloped 203,444,143 148,130,666 55,313,477
--------------------- ------------------ ------------------
Total 418,613,976 363,300,499 55,313,477
===================== ================== ==================
Net oil and NGL reserves (Bbl):
Proved developed 10,980,196 10,980,196 --
Proved undeveloped 24,153,400 12,962,513 11,190,887
--------------------- ------------------ ------------------
Total 35,133,596 23,942,709 11,190,887
===================== ================== ==================
Estimated Present Value of Proved Reserves
Estimated present value of future net cash flows
from proved reserves discounted at 10% annum:
Proved developed $ 1,257,570,764 $ 1,257,570,764 $ --
Proved undeveloped 1,055,684,045 919,388,009 136,296,036
--------------------- ------------------ ------------------
Total $ 2,313,254,809 $ 2,176,958,773 $ 136,296,036
===================== ================== ==================
At year-end 2002, 60% of the proved reserves were developed reserves. At
year-end 2001, 50% of proved reserves were developed. At year-end 2000, 45% of
proved reserves were developed.
Changes in quantity estimates and the estimated present value of proved
reserves are affected by the change in crude oil and natural gas prices at the
end of each year. Our total proved reserves quantities at year-end 2002
increased by 16% over reserves quantities a year earlier, while the PV-10 Value
of those reserves increased 93% from the PV-10 Value at year-end 2001. While our
total proved reserves quantities, on an equivalent Bcfe basis, at year-end 2001
increased by 3% over reserves quantities in 2000, the PV-10 Value of those
reserves decreased 74% from the PV-10 Value at year-end 2000. This decrease in
2001 prices resulted in 47.1 Bcfe of downward reserves revision, solely
attributed to the decrease in prices used in 2001. The PV-10 Value increase in
2002 and the PV-10 decrease in 2001 were heavily influenced by pricing increases
at year-end 2002 as compared to year-end 2001 and by pricing decreases from
year-end 2001 as compared to year-end 2000. Product prices for natural gas
increased 39% during 2002, from $2.51 per Mcf at year-end 2001 to $3.49 at
year-end 2002, while oil prices increased 59% between the two dates, from $18.45
to $29.27 per barrel. Product prices for natural gas decreased 75% during 2001,
from $9.86 per Mcf at December 31, 2000, to $2.51 per Mcf at year-end 2001,
while oil prices decreased 25% between the two dates, from $24.62 to $18.45 per
barrel. Product prices for natural gas increased 282% during 2000, from $2.58
per Mcf at December 31, 1999, to $9.86 per Mcf at year-end 2000, matched by a 4%
increase in the price of oil between the two dates, from $23.69 to $24.62 per
barrel.
Proved reserves are estimates of hydrocarbons to be recovered in the
future. Reservoir engineering is a subjective process of estimating the sizes of
underground accumulations of oil and gas that cannot be measured in an exact
way. The accuracy of any reserves estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Reserves reports of other engineers might differ from the reports contained
herein. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimates. 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.
No other reports on our reserves have been filed with any federal agency.
9
Oil and Gas Wells
As we continued to liquidate partnerships for those partnerships which
voted to do so, our total gross well count decreased. Acquisitions such as Lake
Washington, where we own nearly a 100% interest in all operated wells, have
increased well ownership on a net basis. The following table sets forth the
gross and net wells in which we owned an interest at the following dates:
Total
Oil Wells Gas Wells Wells(1)
---------- ----------- -----------
December 31, 2002:
Gross 342 555 897
Net 278.9 479.8 758.7
December 31, 2001:
Gross 396 786 1,182
Net 297.0 467.9 764.9
December 31, 2000:
Gross 599 904 1,503
Net 165.2 484.7 649.9
(1) Excludes 35 service wells in 2002, 48 service wells in 2001, and 25 service
wells in 2000. Also excludes five wells in 2001 and three wells in 2000 in
New Zealand that were temporarily shut-in awaiting the commissioning of the
Rimu Production Station.
Oil and Gas Acreage
As is customary in the industry, we generally acquire oil and gas acreage
without any warranty of title except as to claims made by, through, or under the
transferor. Although we have 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 our judgment it would be
uneconomical or impractical to do so.
The following table sets forth the developed and undeveloped leasehold
acreage held by us at December 31, 2002:
Developed (1) Undeveloped (1)
Gross Net Gross Net
------------- ------------- ------------- ------------
Alabama 9,686.01 2,859.10 775.72 291.87
Arkansas 602.00 486.38 280.15 280.15
Louisiana 91,543.91 71,989.49 26,525.22 17,858.76
Mississippi 630.03 163.32 60.00 15.80
Texas 183,416.49 122,312.29 72,737.12 46,983.18
Wyoming 120.00 21.06 73,777.00 70,745.32
All other states 320.00 266.66 160.00 17.32
Offshore Louisiana 4,609.37 276.56 5,000.00 258.34
Offshore Texas 14,400.00 1,600.79 --- ---
------------- ------------- ------------- ------------
Total Domestic 305,327.81 199,975.65 179,315.21 136,450.74
New Zealand 6,760.00 6,454.00 163,262.37 112,652.01
------------- ------------- ------------- ------------
Total 312,087.81 206,429.65 342,577.58 249,102.75
============= ============= ============= ============
(1) Fee mineral acres acquired in the Brookeland and Masters Creek areas
acquisition are not included in the above leasehold acreage table. We have
26,345 developed fee mineral acres and 83,920 undeveloped fee mineral acres
for a total of 110,265 fee mineral acres.
10
Drilling Activities
The following table sets forth the results of our drilling activities
during the three years ended December 31, 2002:
Gross Wells Net Wells
------------------------------------ --------------------------------------
Temporarily Temporarily
Year Type of Well Total Producing Dry Abandoned Total Producing Dry Abandoned
----------------------------------------------------------------------- ------------------------------------
2000 Exploratory-Domestic 9 5 4 -- 6.2 3.4 2.8 --
Development-Domestic 59 52 7 -- 42.4 37.1 5.3 --
Exploratory-New Zealand 2 2 -- -- 1.8 1.8 -- --
2001 Exploratory-Domestic 11 6 5 -- 6.2 4.0 2.2 --
Development-Domestic 36 36 -- -- 29.5 29.5 -- --
Exploratory-New Zealand 2 -- 1 1 1.1 -- 0.9 0.2
Development-New Zealand 4 2 2 -- 3.6 1.8 1.8 --
2002 Exploratory-Domestic 7 3 4 -- 5.0 2.3 2.7 --
Development-Domestic 23 17 6 -- 23.0 17.0 6.0 --
Exploratory-New Zealand 3 2 1 -- 2.2 2.0 0.2 --
Development-New Zealand 3 2 1 -- 3.0 2.0 1.0 --
Operations
We generally seek to be operator in the wells in which we have a
significant economic interest. As operator, we design and manage the development
of a well and supervise operation and maintenance activities on a day-to-day
basis. We do not own drilling rigs or other oil field services equipment used
for drilling or maintaining wells on properties we operate. Independent
contractors supervised by us provide all the equipment and personnel. We employ
drilling, production, and reservoir engineers, geologists, and other specialists
who work to improve production rates, increase reserves, and lower the cost of
operating our oil and gas properties.
Oil and gas properties are customarily operated under the terms of a joint
operating agreement. These agreements usually provide for reimbursement of the
operator's direct expenses and for payment of monthly per-well supervision fees.
Supervision fees vary widely depending on the geographic location and depth of
the well and whether the well produces oil or gas. The fees for these activities
paid to us in 2002 totaled $5.0 million and ranged from $450 to $2,174 per well
per month.
Marketing of Production
Domestically, we typically sell our oil and gas production at market prices
near the wellhead, although in some cases it must be gathered and delivered to a
central point. Gas production is sold in the spot market on a monthly basis,
while we sell our oil production at prevailing market prices. We do not refine
any oil we produce. Eastex Crude Company and Contact Energy in New Zealand each
accounted for 10% or more of our total revenues during the year ended December
31, 2002, with those purchasers accounting for approximately 28% of revenues in
the aggregate. For the year ended December 31, 2001, Eastex Crude Company and
subsidiaries of Enron accounted for approximately 29% of our total revenues.
However, due to the availability of other purchasers, we do not believe that the
loss of any single oil or gas purchaser or contract would materially affect our
revenues.
In 1998, we entered into gas processing and gas transportation agreements
for our gas production in the AWP Olmos Area with PG&E Energy Trading
Corporation, which was assumed in December 2000 by El Paso Hydrocarbon, LP, and
El Paso Industrial, LP, both affiliates of El Paso Merchant Energy, for up to
75,000 Mcf per day, which provided for a ten-year term with automatic one-year
extensions unless earlier terminated. We believe that these arrangements
adequately provide for our gas transportation and processing needs in the AWP
Olmos Area for the foreseeable future. Additionally, the gas processed and
transported under these agreements may be sold to El Paso based upon current
natural gas prices.
11
Our oil production from the Brookeland and Masters Creek areas is sold to
various purchasers at prevailing market prices. Our gas production from these
areas is processed under long-term gas processing contracts with Duke Energy
Field Services, Inc. The processed liquids and residue gas production are sold
in the spot market at prevailing prices.
Our oil production from the Lake Washington Area is delivered into
ExxonMobil's crude oil pipeline system for sales to various purchasers at
prevailing market prices. Our gas production from this area is either consumed
on the lease or is delivered into El Paso's Tennessee Gas Pipeline system and
then sold in the spot market at prevailing prices.
Our oil production in New Zealand is sold into the international market at
prices tied to the Asia Petroleum Price Index (APPI) Tapis posting, less the
cost of storage, trucking, and transportation.
Our gas production from our TAWN fields is sold under a long-term contract
with Contact Energy. Our gas production from the Rimu field is sold to Genesis
Power Ltd. under a long-term contract. Additional production volumes from our
TAWN fields, over the contract minimum, can be sold to Contact Energy or Genesis
Power Ltd. at prevailing market rates.
Our New Zealand natural gas liquids production is sold to RockGas under
long-term contracts tied to New Zealand's domestic natural gas liquids market.
The following table summarizes sales volumes, sales prices, and production
cost information for our net oil and gas production for the three-year period
ended December 31, 2002. "Net" production is production that is owned by us
directly or indirectly through partnerships or joint venture interests and is
produced to our interest after deducting royalty, limited partner, and other
similar interests.
Year Ended December 31,
-------------------------------------------------------------------
2002 2001 2000
------------------- ---------------------- ------------------
Net Sales Volume:
Oil (Bbls) (1) 3,770,128 3,055,373 2,472,014
Gas (Mcf)(2) (3) 27,131,578 26,458,958 27,524,621
Gas equivalents (Mcfe) 49,752,346 44,791,202 42,356,705
Average Sales Price:
Oil (Per Bbl) (1) $ 20.88 $ 22.64 $ 29.35
Gas (Per Mcf) (3) $ 2.30 $ 4.23 $ 4.24
Average Production Cost (per Mcfe) $ 0.83 $ 0.82 $ 0.69
1 Oil production for 2002 includes New Zealand production of 695,454 barrels,
at an average price per barrel of $20.28. Oil production for 2001 includes
New Zealand production of 84,261 barrels, at an average price per barrel of
$21.64.
2 Natural gas production for 2000 includes 405,130 Mcf delivered under the
volumetric production payment agreement pursuant to which we were obligated
to deliver certain monthly quantities of natural gas. Under the volumetric
production payment entered into in 1992, we delivered the last remaining
commitment of gas in October 2000, when such agreement expired.
3 Natural gas production for 2002 includes New Zealand production of
11,351,518 Mcf, with an average price of $1.32 per Mcf.
In the table above, for 2002, natural gas liquids have been combined with
oil and condensate for reporting purposes. The natural gas liquids production
for 2002 was 1,173,504 barrels, at an average price of $12.82 per barrel.
Risk Management
Our 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
12
could expose us to substantial liability due to pollution and other
environmental damage. Additionally, as managing general partner of limited
partnerships, we are solely responsible for the day-to-day conduct of the
limited partnerships' affairs and accordingly have liability for expenses and
liabilities of the limited partnerships. We maintain comprehensive insurance
coverage, including general liability insurance in an amount not less than $50.0
million, as well as general partner liability insurance. We believe that our
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
We operate in a highly competitive environment, competing with major
integrated and independent energy companies for desirable oil and gas
properties, as well as for equipment, labor and materials required to develop
and operate such properties. Many of these competitors have financial and
technological resources substantially greater than ours. The market for oil and
gas properties is highly competitive and we may lack technological information
or expertise available to other bidders. We may incur higher costs or be unable
to acquire and develop desirable properties at costs we consider reasonable
because of this competition.
Regulations
Environmental Regulations
Our exploration, production and marketing operations are regulated
extensively at the international, federal and state and local levels. These
regulations affect the costs, manner and feasibility of our operations. As an
owner of oil and gas properties, we are subject to international, federal, state
and local regulation of discharge of materials into, and protection of, the
environment. We have made and will continue to make significant expenditures in
our efforts to comply with the requirements of these environmental regulations,
which may impose liability on us for the cost of pollution clean-up resulting
from operations, subject us to liability for pollution damages and require
suspension or cessation of operations in affected areas. Changes in or additions
to regulations regarding the protection of the environment could increase our
compliance costs and might hurt our business.
We are subject to state and local regulations domestically and are subject
to New Zealand regulations that impose permitting, reclamation, land use,
conservation and other restrictions on our ability to drill and produce. These
laws and regulations can require well and facility sites to be closed and
reclaimed. We frequently buy and sell interests in properties that have been
operated in the past, and as a result of these transactions we may retain or
assume clean-up or reclamation obligations for our own operations or those of
third parties.
United States Federal, State and New Zealand Regulation of Oil and
Natural Gas
The transportation and certain sales of natural gas in interstate commerce
are heavily regulated by agencies of the federal government and are affected by
the availability, terms and cost of transportation. The price and terms of
access to pipeline transportation are subject to extensive federal and state
regulation. The FERC is continually proposing and implementing new rules and
regulations affecting the natural gas industry, most notably interstate natural
gas transmission companies that remain subject to the FERC's jurisdiction. The
stated purpose of many of these regulatory changes is to promote competition
among the various sectors of the natural gas industry. Some recent FERC
proposals may, however, adversely affect the availability and reliability of
interruptible transportation service on interstate pipelines.
Our sales of crude oil, condensate and natural gas liquids are not
currently subject to FERC regulation. However, the ability to transport and sell
such products is dependent on certain pipelines whose rates, terms and
conditions of service are subject to FERC regulation.
13
Production of any oil and gas by us will be affected to some degree by
state regulations. Many states in which we operate 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. Likewise, the government of New Zealand regulates the
exploration, production, sales and transportation of oil and natural gas.
Federal Leases
Some of our 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, 2002, we employed 234 persons. Of these employees, 57 are
in New Zealand, eight of whom are members of a union. None of our other
employees are represented by a union. Relations with employees are considered to
be good.
Facilities
We occupy approximately 93,000 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 $167,000 per month. In New Zealand we
lease approximately 15,000 square feet of office space, under leases expiring in
2009. The lease requires payments of approximately $16,000 per month. We also
have field offices in various locations from which our employees supervise local
oil and gas operations.
Partnerships
Prior to 1995, we funded a substantial portion of our operations through
109 limited partnerships which we formed and for which we have served as
managing general partner. These partnerships raised a total of $509.5 million of
capital, with the largest portion (81%) raised to acquire interests in producing
properties. Eight of the earliest partnerships and 13 of the most recently
formed partnerships were created to drill for oil and gas. In all of these
partnerships Swift paid for varying percentages of the capital or front-end
costs and continuing costs of the partnerships and, in return, received
differing percentage ownership interests in the partnerships, along with
reimbursement of costs and/or payment of certain fees. These partnerships began
liquidating and selling their properties in 1996. At year-end 2002, we continued
to serve as managing general partner for six remaining partnerships, all of
which are drilling partnerships that have been in existence from four to six
years.
Available Information
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K, amendments to those reports, changes in and stock ownership
of our directors and executive officers, together with other documents filed
with the Securities and Exchange Commission under the Securities Exchange Act
can be accessed free of charge on our web site at www.swiftenergy.com as soon as
reasonably practicable after we electronically file these reports with the SEC.
All exhibits and supplemental schedules to these reports are available free of
charge through the SEC web site at www.sec.gov. In addition, we have adopted a
Code of Ethics for Senior Financial Officers and Principal Executive Officer. We
have posted this Code of Ethics on our website, where we also intend to post any
waivers from or amendments to this Code of Ethics.
14
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).
BOE -- Barrels of oil equivalent.
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.
Gigajoules -- A unit of energy equivalent to .95 Mcf of 1,000 Btu of natural
gas.
Gross Acre -- An acre in which a working interest is owned. The number of gross
acres is the total number of acres in which a working interest is owned.
Gross Well -- A well in which a working interest is owned. The number of gross
wells is the total number of wells in which a working interest is owned.
MBbl -- Thousand barrels of oil.
Mcf -- Thousand cubic feet of natural gas.
Mcfe -- Thousand cubic feet of natural gas equivalent, which is determined using
the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf of
natural gas.
MMBbl -- Million barrels of oil.
MMBtu -- Million British thermal units, which is a heating equivalent measure
for natural gas and is an alternate measure of natural gas reserves, as
opposed to Mcf, which is strictly a measure of natural gas volumes. Typically,
prices quoted for natural gas are designated as price per MMBtu, the same
basis on which natural gas is contracted for sale.
MMcf -- Million cubic feet of natural gas.
MMcfe -- Million cubic feet of natural gas equivalent (see Mcfe).
Net Acre -- A net acre is deemed to exist when the sum of fractional working
interests owned in gross acres equals one. The number of net acres is the sum
of fractional working interests owned in gross acres expressed as whole
numbers and fractions thereof.
Net Well -- A net well is deemed to exist when the sum of fractional working
interests owned 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.
NGL -- Natural gas liquid.
15
Petajoules -- A unit of energy equivalent to .95 Bcf of 1,000 Btu of natural
gas.
Producing Well -- An exploratory or development well found to be capable of
producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well.
Proved Developed Oil and Gas Reserves -- Reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.
Proved Oil and Gas Reserves -- The estimated quantities of crude oil, natural
gas, and natural gas liquids that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, that is, prices
and costs as of the date the estimate is made.
Proved Undeveloped Oil and Gas Reserves -- Reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Proved Undeveloped (PUD) Locations -- A location containing 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.
PV-10 Value -- The estimated future net revenues 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.
SFAS -- Statement of Financial Accounting Standards.
TAWN -- New Zealand producing properties acquired by Swift in January 2002. TAWN
is comprised of the Tariki, Ahuroa, Waihapa, and Ngaere fields.
Terajoule -- A unit of energy equivalent to 1,000 gigajoules.
Volumetric Production Payment -- The 1992 agreement pursuant to which we
financed the purchase of certain oil and natural gas interests and committed to
deliver certain monthly quantities of natural gas.
16
Item 3. Legal Proceedings
No material legal proceedings are pending other than ordinary, routine
litigation incidental to our business.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted during the fourth quarter of 2002 to a vote of
security holders.
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters
COMMON STOCK, 2001 AND 2002
Our common stock is traded on the New York Stock Exchange and the Pacific
Exchange, Inc., under the symbol "SFY." The high and low quarterly sales prices
for the common stock for 2001 and 2002 were as follows:
2001 2002
------------------------------------- -------------------------------------
First Second Third Fourth First Second Third Fourth
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
------------------------------------- -------------------------------------
Low $28.91 $27.70 $19.00 $16.66 $15.55 $13.44 $10.40 $6.80
High $37.50 $37.70 $32.55 $25.14 $20.58 $20.53 $15.23 $10.54
Since inception, no cash dividends have been declared on our common stock.
Cash dividends are restricted under the terms of our credit agreements, as
discussed in Note 4 to the Consolidated Financial Statements, and we presently
intend to continue a policy of using retained earnings for expansion of our
business.
We had approximately 366 stockholders of record as of December 31, 2002.
17
Item 6. Selected Financial Data
2002 2001 2000 1999 1998
Revenues
Oil and Gas Sales $141,195,713 $181,184,635 $189,138,947 $108,898,696 $80,067,837
Fees and Earned Interests(2) $67,173 $427,583 $331,497 $229,749 $333,940
Interest Income $263,738 $49,281 $1,339,386 $833,204 $107,374
Other, Net $8,443,187 $2,145,991 $815,116 $709,358 $1,960,070
Total Revenues $149,969,811 $183,807,490 $191,624,946 $110,671,007 $82,469,221
Operating Income (Loss) $18,408,289 ($34,192,333) $93,079,346 $29,736,151 ($73,391,581)
Net Income (Loss) $11,923,227 ($22,347,765) $59,184,008 $19,286,574 ($48,225,204)
Net Cash Provided by Operating Activities $71,626,314 $139,884,255 $128,197,227 $73,603,426 $54,249,017
Per Share Data
Weighted Average Shares Outstanding(3) 26,382,906 24,732,099 21,244,684 18,050,106 16,436,972
Earnings (Loss) per Share--Basic(3) $0.45 ($0.90) $2.79 $1.07 ($2.93)
Earnings (Loss) per Share--Diluted(3) $0.45 ($0.90) $2.51 $1.07 ($2.93)
Shares Outstanding at Year-End 27,201,509 24,795,564 24,608,344 20,823,729 16,291,242
Book Value per Share $13.42 $12.61 $13.50 $8.18 $6.71
Market Price(3)
High $20.58 $37.70 $43.50 $13.31 $21.00
Low $6.80 $16.66 $9.75 $5.69 $6.94
Year-End Close $9.67 $20.20 $37.63 $11.50 $7.38
Pro forma amounts assuming 1994 change in
Accounting principle is applied retroactively(2)
Net Income (Loss) --- --- --- --- ---
Earnings (Loss) per Share--Basic (3) --- --- --- --- ---
Earnings (Loss) per Share--Diluted (3) --- --- --- --- ---
Assets
Current Assets $29,768,199 $36,752,980 $41,872,879 $50,605,488 $35,246,431
Oil and Gas Properties, Net of Accumulated
Depreciation, Depletion, and Amortization $721,617,941 $628,304,060 $524,052,828 $392,986,589 $356,711,711
Total Assets $767,005,859 $671,684,833 $572,387,001 $454,299,414 $403,645,267
Liabilities
Current Liabilities $46,884,184 $73,245,335 $64,324,771 $34,070,085 $31,415,054
Long-Term Debt $324,271,973 $258,197,128 $134,729,485 $239,068,423 $261,200,000
Total Liabilities $401,932,675 $359,032,113 $240,232,846 $283,895,297 $294,282,628
Stockholders' Equity $365,073,184 $312,652,720 $332,154,155 $170,404,117 $109,362,639
Number of Employees 234 209 181 173 203
Producing Wells
Swift Operated 820 854 817 769 836
Outside Operated 112 381 711 788 917
Total Producing Wells 932 1,235 1,528 1,557 1,753
Wells Drilled (Gross) 36 53 70 27 75
Proved Reserves
Natural Gas (Mcf) 326,731,672 324,912,125 418,613,976 329,959,750 352,400,835
Oil, NGL, & Condensate (barrels) 70,438,963 53,482,636 35,133,596 20,806,263 13,957,925
Total Proved Reserves (Mcf equivalent) 749,365,449 645,807,939 629,415,552 454,797,327 436,148,385
Production (Mcf equivalent)(4) 49,752,346 44,791,202 42,356,705 42,874,303 39,030,030
Average Sales Price
Natural Gas (per Mcf) $2.30 $4.23 $4.24 $2.40 $2.08
Oil (per barrel) $20.88 $22.64 $29.35 $16.75 $11.86
1 Additional 1994 Data: Income Before Cumulative Effect of Change in
Accounting Principle-$3,725,671; Cumulative Effect of Change in Accounting
Principle-$(16,772,698); Per Share Amounts-Basic-Income Before Cumulative
Effect of Change in Accounting Principle-$0.51, Cumulative Effect of Change
in Accounting Principle-$(2.29); Per Share Amounts-Diluted-Income Before
Cumulative Effect of Change in Accounting Principle-$0.51, Cumulative
Effect of Change in Accounting Principle-$(2.29).
2 As of January 1, 1994, we changed our revenue recognition policy for earned
interests. Accordingly, in 1994 to 1999, "Fees and Earned Interests" does
not include earned interests revenues.
3 Amounts have been retroactively restated in all periods presented to give
recognition to: (a) an equivalent change in capital structure as a result
of two 10% stock dividends, one in September 1994, the other in October
1997; and (b) the adoption in 1998 of Statement of Financial Accounting
Standards No. 128, "Earnings per Share."
4 Natural gas production for 1992, 1993, 1994, 1995, 1996, 1997, 1998, 1999,
and 2000 includes 1,148,862, 1,581,206, 1,358,375, 1,211,255, 1,156,361,
1,015,226, 866,232, 728,235, and 405,130 Mcf, respectively, delivered under
our volumetric production payment agreement.
18
1997 1996 1995 1994 (1) 1993 1992
$69,015,189 $52,770,672 $22,527,892 $19,802,188 $15,535,671 $12,420,222
$745,856 $937,238 $590,441 $701,528 $4,071,970 $2,716,277
$2,395,406 $433,352 $212,329 $47,980 $201,584 $113,387
$2,555,729 $2,156,764 $1,761,568 $1,072,535 $604,599 $515,931
$74,712,180 $56,298,026 $25,092,230 $21,624,231 $20,413,824 $15,765,817
$33,129,606 $28,785,783 $6,894,537 $4,837,829 $6,628,608 $4,687,519
$22,310,189 $19,025,450 $4,912,512 ($13,047,027) $4,896,253 $4,084,760
$55,255,965 $37,102,578 $14,376,463 $10,394,514 $7,238,340 $6,349,080
16,492,856 15,000,901 10,035,143 7,308,673 7,246,884 6,748,548
$1.35 $1.27 $0.49 ($1.79) $0.68 $0.61
$1.26 $1.25 $0.49 ($1.79) $0.64 $0.61
16,459,156 15,176,417 12,509,700 6,685,137 6,001,075 5,968,579
$9.69 $9.41 $7.46 $6.30 $9.08 $8.26
$34.20 $28.86 $11.48 $10.35 $11.57 $7.85
$16.93 $9.89 $7.05 $7.75 $7.14 $4.65
$21.06 $27.16 $10.91 $8.86 $7.85 $7.55
--- --- --- $3,725,671 $4,322,478 $3,729,851
--- --- --- $0.51 $0.60 $0.55
--- --- --- $0.51 $0.57 $0.55
$29,981,786 $101,619,478 $43,380,454 $39,208,418 $65,307,120 $30,830,173
$301,312,847 $200,010,375 $125,217,872 $88,415,612 $89,656,577 $64,301,509
$339,115,390 $310,375,264 $175,252,707 $135,672,743 $160,892,917 $100,243,469
$28,517,664 $32,915,616 $40,133,269 $52,345,859 $55,565,437 $27,876,687
$122,915,000 $115,000,000 $28,750,000 $28,750,000 $28,750,000 $0
$179,714,470 $167,613,654 $81,906,742 $93,545,612 $106,427,203 $50,962,183
$159,400,920 $142,761,610 $93,345,965 $42,127,131 $54,465,714 $49,281,286
194 191 176 209 188 178
650 842 767 750 795 688
917 986 3,316 3,422 3,407 1,978
1,567 1,828 4,083 4,172 4,202 2,666
182 153 76 44 34 40
314,305,669 225,758,201 143,567,520 76,263,964 64,462,805 41,638,100
7,858,918 5,484,309 5,421,981 4,553,237 4,271,069 2,901,621
361,459,177 258,664,055 176,099,406 103,583,566 90,089,219 59,047,824
25,393,744 19,437,114 11,186,573 9,600,867 7,368,757 5,678,772
$2.68 $2.57 $1.77 $1.93 $1.96 $1.90
$17.59 $19.82 $15.66 $14.35 $15.10 $17.19
19
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following discussion should be read in conjunction with our
Consolidated Financial Statements and Notes thereto.
General
Over the last three years, we have emphasized adding reserves through
drilling activity, while adding reserves through strategic purchases of
producing properties when oil and gas prices were at lower levels and other
market conditions were appropriate. We used this flexible strategy of employing
both drilling and acquisitions to add more reserves than we depleted through
production during this period.
Proved Oil and Gas Reserves. At year-end 2002, our total proved reserves
were 749.4 Bcfe with a PV-10 Value of $1.2 billion. In 2002, our proved natural
gas reserves increased 1.8 Bcf, or 1%, while our proved oil reserves increased
17.0 MMBbl, or 32%, for a total equivalent increase of 103.6 Bcfe, or 16%. In
2001, our proved natural gas reserves decreased by 93.7 Bcf, or 22%, while our
proved oil reserves increased by 18.3 MMBbl, or 52%, for a total equivalent
increase of 16.4 Bcfe, or 3%. We added reserves in 2002 through both our
drilling activity and through purchases of minerals in place. Through drilling
we added 83.9 Bcfe (15.9 Bcfe of which came from New Zealand) of proved reserves
in 2002, 105.8 Bcfe (17.4 Bcfe of which came from New Zealand) in 2001, and
184.7 Bcfe (122.5 Bcfe of which came from New Zealand) in 2000. Through
acquisitions we added 74.2 Bcfe of proved reserves in 2002, 54.6 Bcfe in 2001,
and 39.7 Bcfe in 2000. At year-end 2002, 60% of our total proved reserves were
proved developed, compared with 50% at year-end 2001 and 45% at year-end 2000.
Our total proved reserves quantities at year-end 2002 increased by 16% over
reserves quantities a year earlier, while the PV-10 Value of those reserves
increased 93% from the PV-10 Value at year-end 2001. Gas prices increased in
2002 to $3.49 per Mcf from $2.51 per Mcf at year-end 2001, compared to $9.86 per
Mcf at year-end 2000. Oil prices increased in 2002 to $29.27 per barrel from
$18.45 per Bbl at year-end 2001, compared to $24.62 in 2000. Under SEC
guidelines, estimates of proved reserves must be made using year-end oil and gas
sales prices and are held constant throughout the life of the properties.
Subsequent changes to such year-end oil and gas prices could have a significant
impact on the calculated PV-10 Value. While our total proved reserves quantities
increased by 3% during 2001, the PV-10 Value of those reserves decreased 74%,
due to much lower prices at year-end 2001 than at year-end 2000. Between those
two year-ends, there was a 75% decrease in natural gas prices and a 25% decrease
in oil prices. This decrease in prices resulted in 47.1 Bcfe of downward
reserves revisions, solely attributed to the decrease in prices at year-end
2001. The year-end 2001 gas price of $2.51 was significantly lower than the
average gas price of $4.23 we received during 2001. The year-end 2001 oil price
of $18.45 per barrel was also lower than the average oil price of $22.64 we
received in 2001.
Contractual Commitments and Obligations
Our contractual commitments for the next five years and thereafter are as
follows:
2003 2004 2005 2006 2007 Thereafter (3)
---------------------------------------------------------------------------------------
Non-cancelable operating lease commitments $2,190,363 $2,191,495 $523,755 $190,676 $190,676 186,834
Capital commitments due to pipeline 933,666 --- --- --- --- ---
operators
Senior Notes due 2009(1) --- --- --- --- --- 125,000,000
Senior Notes due 2012(1) --- --- --- --- --- 200,000,000
Credit Facility which expires in October --- --- --- --- --- ---
2005(2)
---------------------------------------------------------------------------------------
$3,124,029 $2,191,495 $523,755 $190,676 $190,676 $325,186,834
=======================================================================================
1 These amounts do not include the interest obligation, which is paid
semiannually.
2 The repayment of the credit facility is based upon the zero balance at
December 31, 2002. This amount excludes $0.8 million of a standby letter of
credit issued under this facility.
3 These amounts exclude asset retirement obligations, as accounted for under
SFAS No. 143 "Accounting for Asset Retirement Obligations." We adopted this
statement on January 1, 2003, and recorded a liability of $8.9 million.
This standard required us to record a liability for the fair value of its
dismantlement and abandonment costs, excluding salvage values.
20
Commodity Price Trends and Uncertainties
Oil and natural gas prices historically have been volatile and will likely
continue to be volatile in the future. Worldwide supply disruptions, such as the
reduction in crude oil production from Venezuela, together with perceived risks
such as the threat of war between the United States and Iraq, along with other
factors, have caused the price of oil to increase significantly in the first
quarter of 2003 when compared to historical prices. Other factors such as
actions taken by OPEC, worldwide economic conditions, and weather conditions can
cause wide fluctuations in the price of oil. Natural gas prices have also
increased significantly in the first quarter of 2003 when compared to historical
prices. North American weather conditions, the industrial and consumer demand
for natural gas, storage levels of natural gas, and the availability and
accessibility of natural gas deposits in North America can cause wide
fluctuations in the price of natural gas. All of the above factors are beyond
our control.
Liquidity and Capital Resources
During 2002, we principally relied upon cash provided by operating
activities of $71.6 million, net proceeds from the issuance of long-term debt of
$195.0 million, and net proceeds from our public stock offering of $30.5
million, less the repayment of bank borrowings of $134.0 million, to fund
capital expenditures of $155.2 million. During 2001, we relied both upon
internally generated cash flows of $139.9 million and upon additional borrowings
from our bank credit facility of $123.4 million to fund capital expenditures of
$275.1 million.
Net Cash Provided by Operating Activities. In 2002, net cash provided by
our operating activities decreased by 49% to $71.6 million, as compared to
$139.9 million in 2001 and $128.2 million in 2000. The 2002 decrease of $68.3
million was primarily due to a reduction of oil and gas sales of $40.0 million
due to lower commodity prices and to an increase in interest of $10.6 million
due to the higher debt balances and interest rates in 2002. The 2001 increase of
$11.7 million was primarily due to a $14.0 million reduction in working capital
as oil and gas sales receivables decreased in 2001 along with a reduction in
interest expense of $3.3 million. These increases in cash flow were offset by an
$8.0 million reduction of oil and gas sales, a $7.5 million increase in oil and
gas production costs, and a $2.6 million increase in general and administrative
expense.
Existing Credit Facilities. At December 31, 2002, we had no outstanding
borrowings under our credit facility. Our credit facility at year-end 2002
consisted of a $300.0 million revolving line of credit with a $195.0 million
borrowing base. The borrowing base is re-determined at least every six months
and was reconfirmed by our bank group in November 2002 with the $195.0 million
borrowing base. Our revolving credit facility includes, among other
restrictions, requirements as to maintenance of certain minimum financial ratios
(principally pertaining to working capital, debt, and equity ratios) and
limitations on incurring other debt. We are in compliance with the provisions of
this agreement. The credit facility extends until October 2005. At December 31,
2001, we had $134.0 million in outstanding borrowings under this facility.
Working Capital. Our working capital increased from a deficit of $36.5
million at December 31, 2001, to a deficit of $17.1 million at December 31,
2002. The increase was primarily due to reductions in payables to partnerships
related to December 2001 property sales.
Capital Expenditures. In 2002, our capital expenditures of approximately
$155.2 million included:
New Zealand activities of $95.2 million as follows:
o $56.1 million, or 36%, on producing properties acquisitions, with
approximately $51.7 million spent on the TAWN acquisition and the
remainder for the cash portion of our Bligh and Antrim acquisitions;
o $12.6 million, or 8%, on developmental drilling to further delineate
the Rimu and Kauri areas;
o $10.6 million, or 7%, on gas processing plants, principally the Rimu
Production Station;
o $10.3 million, or 7%, for exploratory drilling in the Rimu and Kauri
areas;
o $5.2 million, or 3%, on prospect costs, principally seismic and
geological costs;
o $0.4 million, or less than 1%, for fixed assets, principally computers
and office furniture and fixtures.
21
Domestic activities of $60.0 million as follows:
o $34.4 million, or 22%, on developmental drilling;
o $11.1 million, or 7%, on domestic prospect costs, principally
leasehold, seismic, and geological costs;
o $8.3 million, or 5%, on exploratory drilling;
o $2.3 million, or 1%, for producing property acquisitions, including
the purchase of property interests from partnerships managed by us;
o $2.0 million, or 1%, on gas processing plants in the Brookeland and
Masters Creek areas; o$1.1 million, or less than 1% on field
compression facilities; and
o $0.8 million, or less than 1%, for fixed assets.
In 2002, we participated in drilling 23 domestic development wells and
seven domestic exploratory wells, of which 17 development wells and three
exploratory wells were successful. In New Zealand three development wells and
three exploratory wells were drilled. One of the development wells and one of
the exploratory wells were dry.
We currently plan to spend $115 to $130 million in total capital
expenditures in 2003, excluding acquisition costs and net of approximately $5
million to $15 million in non-core property dispositions. The budget for 2003 is
largely dependent upon performance and pricing during the year. Domestic
activities account for 85% of budgeted spending, primarily in the Lake
Washington Area.
We believe that the anticipated internally generated cash flows for 2003,
together with bank borrowings under our credit facility, will be sufficient to
finance the costs associated with our currently budgeted 2003 capital
expenditures. If other producing property acquisitions become attractive during
2003, we will explore the use of debt and/or equity offerings to fund such
activity.
Our capital expenditures were approximately $275.1 million in 2001 and
$173.3 million in 2000. During 2000, we used cash flows from operating
activities of $128.2 million to fund capital expenditures of $173.3 million,
along with part of the remaining net proceeds from our third quarter 1999
issuance of Senior Notes and common stock. During 2001, we relied both upon
internally generated cash flows of $139.9 million and upon additional borrowings
of $123.4 million from our bank credit facility to fund capital expenditures of
$275.1 million. Our capital expenditures in 2001 included:
Domestic activities of $224.3 million as follows:
o $120.6 million, or 44%, on developmental drilling;
o $40.5 million, or 15%, for producing property acquisitions, with
approximately $32.6 million spent on the Lake Washington acquisition
and the remainder for the purchase of property interests from
partnerships managed by us;
o $36.4 million, or 13%, on exploratory drilling;
o $25.3 million, or 9%, on domestic prospect costs, principally
leasehold, seismic, and geological costs; o$1.1 million, or less than
1%, for fixed assets;
o $0.3 million on field compression facilities; and
o $0.1 million on gas processing plants in the Brookeland and Masters
Creek areas.
New Zealand activities of $50.8 million as follows:
o $19.0 million, or 7%, on developmental drilling to further delineate
the Rimu and Kauri areas;
o $17.9 million, or 7%, on the Rimu Production Station;
o $7.2 million, or 3%, for exploratory drilling in the Rimu and Kauri
areas;
o $5.5 million, or 2%, on prospect costs, principally seismic and
geological costs;
o $0.8 million, or less than 1%, on producing property acquisition
evaluation costs related to our TAWN acquisition; and
o $0.4 million for fixed assets, principally computers and office
furniture and fixtures.
In 2001, we participated in drilling 40 development wells and 13
exploratory wells, of which 38 development wells and six exploratory wells were
successful. Four of the development wells were drilled in New Zealand to
delineate the Rimu and Kauri areas, two of which were successful. Two of the
exploratory wells were drilled in New Zealand; one was unsuccessful and one was
temporarily abandoned.
22
Results of Operations
Revenues. Our revenues in 2002 decreased by 18% compared to revenues in
2001 due primarily to decreases in oil and gas prices. Partially offsetting the
decrease in commodity prices received was the effect of an increase in
production from our New Zealand and Lake Washington areas.
Oil and gas sales revenues in 2002 decreased by 22%, or $40.0 million, from
the level of those revenues for 2001 even though our net sales volumes in 2002
increased by 11%, or 5.0 Bcfe, over net sales volumes in 2001. Average prices
received for oil decreased to $20.88 per Bbl in 2002 from $22.64 per Bbl in
2001. Average gas prices received decreased to $2.30 per Mcf in 2002 from $4.23
per Mcf in 2001. The increase in production during the 2002 period is primarily
from our New Zealand and Lake Washington areas.
In 2002, our $40.0 million decrease in oil and gas sales resulted from:
o Price variances that had a $59.0 million unfavorable impact on sales,
of which $6.6 million was attributable to the 8% decrease in average
oil prices received and $52.4 million was attributable to the 46%
decrease in average gas prices received; and
o Volume variances that had a $19.0 million favorable impact on sales,
with $16.2 million of increases coming from the 715,000 Bbl increase
in oil sales volumes, and $2.8 million of the increases from the 0.7
Bcf increase in gas sales volumes.
Revenues in 2001 decreased by 4% compared to 2000 revenues. In 2001, oil
and gas sales revenues decreased by 4%, or $8.0 million, from the level of those
revenues in 2000 even though our net sales volumes in 2001 increased by 6%, or
2.4 Bcfe, over net sales volumes in 2000. Average prices received for oil
decreased to $22.64 per Bbl in 2001 from $29.35 per Bbl in 2000. Average gas
prices received decreased slightly to $4.23 per Mcf in 2001 from $4.24 per Mcf
in 2000.
In 2001, our $8.0 million decrease in oil and gas sales resulted from:
o Price variances that had a $20.6 million unfavorable impact on sales,
of which $20.5 million was attributable to the 23% decrease in average
oil prices received and $0.1 million was attributable to the slight
decrease in average gas prices received; and
o Volume variances that had a $12.6 million favorable impact on sales,
with an increase of $17.1 million from the 583,000 Bbl increase in oil
sales volumes offset somewhat by a decrease of $4.5 million from the
1.1 Bcf decrease in gas sales volumes.
The following table provides additional information regarding the changes
in the sources of our oil and gas sales and volumes from our four domestic core
areas and New Zealand:
Revenues Net Sales Volume (Bcfe)
(In millions)
------------------------ --------------------------
Area 2002 2001 2002 2001
-------------------------- --------- ----------- --------- ----------
AWP Olmos $ 33.1 $ 56.1 10.9 13.0
Brookeland 11.9 25.1 4.1 6.5
Lake Washington 18.5 4.6 4.4 1.2
Masters Creek 32.3 62.3 9.7 15.3
Other 16.3 31.3 5.2 8.3
--------- ----------- --------- ----------
Total Domestic $ 112.1 $ 179.4 34.3 44.3
Rimu/Kauri 4.0 1.8 1.5 0.5
TAWN 25.1 - 14.0 -
--------- ----------- --------- ----------
Total New Zealand $ 29.1 $ 1.8 15.5 0.5
--------- ----------- --------- ----------
Total $ 141.2 $ 181.2 49.8 44.8
========= =========== ========= ==========
23
The following table provides additional information regarding our oil and
gas sales:
Net Sales Volume Average Sales Price
------------------------------------------- -----------------------
Oil and Gas Combined Oil and Gas
Condensate Condensate
(MBbl) (Bcf) (Bcfe) (Bbl) (Mcf)
-------------- ------- -------------- -------------- ---------
2000:
First Qtr. 653 6.6 10.6 $27.35 $2.93
Second Qtr. 650 6.9 10.8 $27.55 $3.99
Third Qtr. 591 7.0 10.5 $30.68 $4.39
Fourth Qtr. 578 7.0 10.5 $32.26 $5.55
-------------- ------- --------------
2,472 27.5 42.4 $29.35 $4.24
============== ======= ==============
2001:
First Qtr. 603 6.7 10.3 $27.63 $6.86
Second Qtr. 691 7.1 11.3 $26.05 $4.66
Third Qtr. 813 6.8 11.7 $23.76 $2.94
Fourth Qtr. 948 5.9 11.5 $16.02 $2.21
-------------- ------- --------------
3,055 26.5 44.8 $22.64 $4.23
============== ======= ==============
2002:
First Qtr. 944 6.6 12.3 $16.10 $1.72
Second Qtr. 1,002 6.7 12.7 $20.98 $2.60
Third Qtr. 908 6.7 12.2 $23.05 $2.32
Fourth Qtr. 916 7.1 12.6 $23.55 $2.55
-------------- ------- --------------
3,770 27.1 49.8 $20.88 $2.30
============== ======= ==============
In the table above, for 2002, natural gas liquids have been combined with
oil and condensate for reporting purposes. The natural gas liquids production
for 2002 was 1,174 MBbls, at an average price of $12.82 per barrel.
In March 2002, we received $7.5 million for our interest in the Samburg
project located in Western Siberia, Russia as a result of the sale by a third
party of its ownership in a Russia joint stock company that owned and operated
the field. Although the proceeds from sales of oil and gas properties are
generally treated as a reduction of oil and gas property costs, because we had
previously charged to expense all $10.8 million of cumulative costs relating to
our Russian activities, this cash payment, net of transaction expenses, resulted
in recognition of a $7.3 million non-recurring gain on asset disposition in the
first quarter of 2002. This activity was recorded in "Gain on asset disposition"
in the accompanying consolidated statement of income.
During 2002, we recognized net losses of $191,701 relating to our
derivative activities, as compared to net gains of $1,173,094 in 2001. In 2002,
$7,889 of the losses were unrealized, while $16,784 of losses recognized in 2001
were unrealized. This activity is recorded in "Price-risk management and other,
net" on the accompanying income statement.
Revenues from our oil and gas sales comprised 94% of total revenues for
2002 and 99% of total revenues for both 2001 and 2000. Natural gas production
made up 55% of our production volumes in 2002, 59% in 2001, and 65% in 2000.
Costs and Expenses. Our expenses in 2002 decreased $86.4 million, or 40%,
compared to 2001 expenses. The majority of the decrease was due to the $98.9
million non-cash write-down of domestic oil and gas properties in 2001, offset
by increases in operating costs in 2002 related to our increased activities in
New Zealand. Our expenses in 2001 increased by $119.5 million, or 121%, compared
to 2000 expenses. The majority of this increase was due to the non-cash
write-down of domestic oil and gas properties in 2001.
Our general and administrative expenses, net in 2002 increased $2.4
million, or 29%, from the level of such expenses in 2001, while 2001 general and
administrative expenses increased $2.6 million, or 47%, over 2000 levels. These
increases reflect additional costs needed to run our increased activities in New
Zealand, along with a reduction in reimbursement from partnerships we manage as
these partnerships have liquidated. Our general and administrative expenses per
Mcfe produced increased to $0.21 per Mcfe in 2002 from $0.18 per Mcfe in 2001
and $0.13 per Mcfe in 2000. The portion of supervision fees netted from general
and administrative expenses was $3.0 million for 2002, $3.1 million for 2001,
and $3.4 million for 2000.
24
Depreciation, depletion, and amortization of our assets, or DD&A, decreased
$3.3 million, or 6%, in 2002 from 2001 levels, while 2001 DD&A increased $11.7
million, or 25%, from 2000 levels. Domestically, DD&A decreased $15.6 million
due to decreased production in the 2002 period, the domestic non-cash write-down
of oil and gas properties in the fourth quarter of 2001 that decreased our
depletable oil and gas property base, and higher reserve volumes that were added
primarily though our Lake Washington activities. In New Zealand, our production
and the depletable oil and gas property base both increased in the 2002 period
due primarily to the TAWN acquisition. The May 2002 commissioning of our Rimu
Production Station also increased the depletable oil and gas property base. In
2001, the increase domestically was primarily due to additional dollars spent to
add to our reserves and increased associated costs in an environment where
demand for oil and gas services had increased compared to 2000, along with a 6%
increase in production. Our DD&A rate per Mcfe of production was $1.13 in 2002,
$1.33 in 2001, and $1.13 in 2000, reflecting variations in per unit cost of
reserves additions.
Our production costs per Mcfe produced were $0.83 in 2002, $0.82 in 2001,
and $0.69 in 2000. The portion of supervision fees netted from production costs
was $2.0 million for 2002, $3.1 million for 2001, and $3.4 million for 2000. Our
production costs in 2002 increased $4.8 million, or 13%, over such expenses in
2001, while those expenses in 2001 increased $7.5 million, or 26%, over 2000
costs. Overall, production costs increased in 2002 as our New Zealand activities
increased, offsetting the domestic production costs decrease which mainly was
due to a decrease in production volumes. Approximately $1.7 million of the
increase in production costs during 2001 was related to severance taxes.
Severance taxes increased primarily from the expiration of certain specific well
severance tax exemptions. The remainder of the 2001 increase reflected costs
associated with new wells drilled and acquired and the related increase in costs
in procuring such services in an environment where demand for oil and gas
services has increased from the prior year.
Interest expense on our Senior Notes issued in July 1999, including
amortization of debt issuance costs, totaled $13.2 million in 2002 and $13.1
million in both 2001 and 2000. Interest expense on our Senior Notes issued in
April 2002, including amortization of debt issuance costs, totaled $13.5 million
in 2002. Interest expense on our Convertible Notes due 2006, including
amortization of debt issuance costs, totaled $7.4 million in 2000. Interest
expense on the credit facility, including commitment fees and amortization of
debt issuance costs, totaled $3.6 million in 2002, $5.8 million in 2001, and
$0.7 million in 2000. The total interest cost in 2002 was $30.3 million, of
which $7.0 million was capitalized. The total interest cost in 2001 was $18.9
million, of which $6.3 million was capitalized. The 2000 total interest cost was
$21.2 million, of which $5.2 million was capitalized. We capitalize that portion
of interest related to our exploration, partnership, and foreign business
development activities. The increase in interest expense in 2002 was attributed
to the replacement of our bank borrowings in April 2002 with the Senior Notes
that carry a higher interest rate. The decrease in total interest expense in
2001 was attributed to the conversion and extinguishment of our Convertible
Notes in December 2000 and the increase in capitalized interest, partially
offset by the increase in interest paid on our credit facility.
In the fourth quarter of 2001, we recognized a domestic non-cash write-down
of oil and gas properties, as discussed in Note 1 to the Consolidated Financial
Statements. Lower prices for both oil and natural gas at December 31, 2001,
necessitated a pre-tax domestic full-cost ceiling write-down of $98.9 million,
or $63.5 million after tax. In addition to this domestic ceiling write-down, we
also expensed $2.1 million of charges in the fourth quarter of 2001 for certain
delinquent accounts receivable, the majority of which were related to gas sold
to Enron, and a write-off of debt issuance costs for a planned offering that was
cancelled based upon market conditions following the events of September 11,
2001.
As discussed in Note 1 to the Consolidated Financial Statements, we adopted
SFAS No. 133, amended by SFAS No. 137 and SFAS No. 138, on January 1, 2001. Our
adoption of SFAS No. 133 resulted in a one-time net of taxes charge of $392,868,
which is recorded as a "Cumulative Effect of Change in Accounting Principle" on
the 2001 consolidated statement of income.
In the fourth quarter of 2000, we recorded a $0.6 million loss on the early
extinguishment of debt (net of taxes), as discussed in Note 4 to the financial
statements. We called our Convertible Notes for redemption effective December
26, 2000. Holders of approximately $100.0 million of the Convertible Notes
elected to convert their notes into shares of our common stock. Holders of the
remaining $15.0 million of the Convertible Notes elected to redeem their notes
for cash plus accrued interest. This cash redemption resulted in this
extraordinary item.
25
Net Income (Loss). Our net income in 2002 of $11.9 million was 153% higher
and basic earnings per share ("Basic EPS") of $0.45 was 150% higher than our
2001 net loss of $(22.3) million and basic loss per share ("Basic EPS") of
$(0.90). Our earnings per diluted share in 2002 of $0.45 was 150% higher than
our 2001 loss per diluted share of $(0.90). These amounts increased in 2002 due
to overall lower costs, as a non-cash write-down of oil and gas properties
occurred in 2001 and not 2002, offset somewhat by lower revenue in 2002.
Our net loss in 2001 of $(22.3) million was 138% lower and basic loss per
share of $(0.90) was 132% lower than our 2000 net income of $59.2 million and
basic earnings per share of $2.79. Our earnings per diluted share in 2001 of
$(0.90) was 136% lower than our 2000 earnings per diluted share of $2.51. These
decreases reflected the effect of $101.0 million in charges in 2001 as described
above.
Critical Accounting Policies
The following summarizes several of our critical accounting policies. See a
complete list of significant accounting policies in Note 1 to the Consolidated
Financial Statements.
Use of Estimates. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities, if
any, at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from estimates.
Property and Equipment. We follow 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 exploration, development and
acquisition of oil and gas reserves are capitalized. Under the full-cost method
of accounting, such costs may be incurred both prior to or after the acquisition
of a property and include lease acquisitions, geological and geophysical
services, drilling, completion and equipment. Internal costs incurred that are
directly identified with exploration, development and acquisition activities
undertaken by us for our own account, and which are not related to production,
general corporate overhead or similar activities, are also capitalized. For the
years 2002, 2001, and 2000, such internal costs capitalized totaled $10.7
million, $11.6 million, and $10.3 million, respectively. Interest costs related
to unproved properties are also capitalized to unproved oil and gas properties.
Interest not capitalized and 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 involving a significant amount of
reserves or where the proceeds from the sale of oil and gas properties would
significantly alter the relationship between capitalized costs and proved
reserves of oil and gas attributable to a cost center.
Future development, site restoration, and dismantlement and abandonment
costs, net of salvage values, are estimated property by property based on
current economic conditions and are amortized to expense as our capitalized oil
and gas property costs are amortized.
We compute the provision for depreciation, depletion, and amortization of
oil and gas properties by the unit-of-production method. Under this method, we
compute the provision by multiplying the total unamortized costs of oil and gas
properties--including future development, site restoration, and dismantlement
and abandonment costs, net of salvage value, but excluding costs of unproved
properties--by an overall rate determined by dividing the physical units of oil
and gas produced during the period by the total estimated units of proved oil
and gas reserves. This calculation is done on a country-by-country basis.
Furniture, fixtures and other equipment are depreciated by the straight-line
method at rates based on the estimated useful lives of the property. Repairs and
maintenance are charged to expense as incurred. Renewals and betterments are
capitalized.
The cost of unproved properties not being amortized is assessed quarterly,
on a country-by-country basis, to determine whether such properties have been
impaired. In determining whether such costs should be impaired, we evaluate
current drilling results, lease expiration dates, current oil and gas industry
conditions, international economic conditions, capital availability, foreign
currency exchange rates, the political stability in the countries in which we
have an investment, and available geological and geophysical information. Any
impairment assessed is added to the cost of proved properties being amortized.
To the extent costs accumulate in countries where there are no proved reserves,
any costs determined by management to be impaired are charged to expense.
26
Full-Cost Ceiling Test. 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 unhedged period-end prices, discounted at 10%, and the lower of
cost or fair value of unproved properties, adjusted for related income tax
effects ("Ceiling Test"). This calculation is done on a country-by-country basis
for those countries with proved reserves.
The calculation of the Ceiling Test and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves. There are
numerous uncertainties inherent in estimating quantities of proved reserves and
in projecting the future rates of production, timing, and plan of development.
The accuracy of any reserves estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. Results of
drilling, testing, and production subsequent to the date of the estimate may
justify revision of such estimate. Accordingly, reserves estimates are often
different from the quantities of oil and gas that are ultimately recovered.
In the fourth quarter of 2001, as a result of low oil and gas prices at
December 31, 2001, we reported a non-cash write-down on a before-tax basis of
$98.9 million ($63.5 million after tax) on our domestic properties. We had no
write-down on our New Zealand properties.
Given the volatility of oil and gas prices, it is reasonably possible that
our estimate of discounted future net cash flows from proved oil and gas
reserves could change in the near term. If oil and gas prices decline from our
period-end prices used in the Ceiling Test, even if only for a short period, it
is possible that additional non-cash write-downs of oil and gas properties could
occur in the future.
Price-Risk Management Activities. We follow SFAS No. 133 which requires
that changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. The statement also
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be reported in the balance sheet as either an asset or liability
measured at its fair value. Special hedge accounting for qualifying hedges would
allow the gains and losses on derivatives to offset related results on the
hedged item in the income statements and would require that a company formally
document, designate, and assess the effectiveness of transactions that receive
hedge accounting.
We have a price-risk management policy to use derivative instruments to
protect against declines in oil and gas prices, mainly through the purchase of
protection price floors and collars. We adopted SFAS No. 133 effective January
1, 2001. Accordingly, we marked our open contracts at December 31, 2000, to fair
value at that date, resulting in a one-time net of taxes charge of $392,868,
which was recorded as a Cumulative Effect of Change in Accounting Principle.
During 2002 and 2001, we recognized net losses of $191,701 and net gains of
$1,173,094 relating to our derivative activities. Approximately $7,889 of the
losses recognized in 2002 were unrealized as the contracts were still open,
while $16,784 of losses recognized in the comparative 2001 period were
unrealized. This activity is recorded in "Price-risk management and other, net"
on the accompanying statements of income. At December 31, 2002, we had recorded
$178,053, net of taxes of $100,155, of derivative losses in "Other comprehensive
loss" on the accompanying balance sheet. This amount represents the change in
fair value for the effective portion of our collar transactions that were
qualified as cash flow hedges. The ineffectiveness reported in "Price-risk
management and other, net" for 2002 was not material. We expect to reclassify
all amounts held in "Other comprehensive loss" into the statement of income
within the next six months.
As of December 31, 2002, we had entered into the cash flow hedge commodity
derivative instruments set forth in the table below for our domestic oil and
natural gas production for portions of 2003. When we entered into the following
transactions they were designated as a hedge of the variability in cash flows
associated with the forecasted sale of our oil and natural gas production.
Changes in the fair value of a hedge that is highly effective and is designated
and qualifies as a cash flow hedge, to the extent that the hedge is effective,
are initially recorded in Other Comprehensive Income (Loss). When the hedged
transactions are recorded upon the actual sale of oil and natural gas, these
gains or losses are transferred from Other Comprehensive Income (Loss) and
recorded in "Price-risk management and other, net" on the statement of income.
The fair value of our derivatives are computed using the Black-Scholes option
pricing model and are periodically verified against quotes from brokers. The
fair value of these instruments is recognized on the balance sheet, in "Accounts
payable and accrued liabilities," at December 31, 2002.
27
Crude Oil - Cash Flow Hedges Collars
----------------------------
Floors Ceilings December 31, 2002
Period and Type Volume in Weighted Weighted Fair Value
Of Contract Bbls (000s) Average Average (000s)
---------------------------------- --------------- --------------- ------------ -----------------------
January 2003 - June 2003
Participating Collar Contracts 360 $ 21.00 $ 76
144 $ 30.35 $ (256)
------------------------
Total $ (180)
------------------------
Natural Gas - Cash Flow Hedges Collars
----------------------------
Floors Ceilings December 31, 2002
Period and Type Volume in Weighted Weighted Fair Value
Of Contract MMBtu (000s) Average Average (000s)
---------------------------------- --------------- --------------- ------------ -----------------------
January 2003 - June 2003
Participating Collar Contracts 1,900 $ 3.00 $ 12
760 $ 5.27 $ (122)
------------------------
Total $ (110)
------------------------
In January and February 2003, we entered into natural gas "floors"
financial transactions covering contract periods April 2003 to October 2003.
Notional volumes are 450,000 MMBtu per month at a weighted average floor price
of $4.36 per MMBtu. In January 2003, we entered into crude oil "floors"
financial transactions covering the contract periods of February to April 2003.
Notional volumes are 625,000 barrels over the three-month period with a weighted
average floor price of $26.39 per barrel. Also in February 2003, we entered into
a crude oil "collar" financial transaction covering the contract period April
2003 to June 2003. Notional volumes are 120,000 barrels over the three-month
period with a weighted average floor price of $25.25 per barrel and 48,000
barrels over the three-month period with a weighted average ceiling price of
$33.08 per barrel.
See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk"
for additional discussion of commodity risk.
Related-Party Transactions
We have been the operator of a number of properties owned by our affiliated
limited partnerships and, accordingly, charge these entities operating fees. The
operating fees charged to the partnerships in 2002, 2001, and 2000 totaled
approximately $300,000, $925,000, and $1,775,000, respectively, and are recorded
as reductions of general and administrative expense and oil and gas production
expense. We also have been reimbursed for direct, administrative, and overhead
costs incurred in conducting the business of the limited partnerships, which
totaled approximately $973,000, $3,140,000, and $4,465,000 in 2002, 2001, and
2000, respectively. In partnerships in which the limited partners voted to sell
their remaining properties and liquidate their limited partnerships, we also
have been reimbursed for direct, administrative, and overhead costs incurred in
the disposition of such properties, which costs totaled approximately $510,000,
$2,360,000, and $1,220,000 in 2002, 2001, and 2000, respectively.
28
Forward-Looking Statements
The statements contained in this 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. Such forward-looking statements
may pertain to, among other things, financial results, capital expenditures,
drilling activity, development activities, cost savings, production efforts and
volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory
matters, and competition. Such forward-looking statements generally are
accompanied by words such as "plan," "future," "estimate," "expect," "budget,"
"predict," "anticipate," "projected," "should," "believe," or other words that
convey the uncertainty of future events or outcomes. Such forward-looking
information is based upon management's current plans, expectations, estimates,
and assumptions, upon current market conditions, and upon engineering and
geologic information available at this time, and is subject to change and to a
number of risks and uncertainties, and, therefore, actual results may differ
materially. Among the factors that could cause actual results to differ
materially are: volatility in oil and natural gas prices, internationally or in
the United States; availability of services and supplies; fluctuations of the
prices received or demand for our oil and natural gas; the uncertainty of
drilling results and reserve estimates; operating hazards; requirements for
capital; general economic conditions; changes in geologic or engineering
information; changes in market conditions; competition and government
regulations; as well as the risks and uncertainties discussed herein and set
forth from time to time in our other public reports, filings, and public
statements. Also, because of the volatility in oil and gas prices and other
factors, interim results are not necessarily indicative of those for a full
year.
29
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk. Our major market risk exposure is the commodity pricing
applicable to our oil and natural gas production. Realized commodity prices
received for such production are primarily driven by the prevailing worldwide
price for crude oil and spot prices applicable to natural gas. The effects of
such pricing volatility are discussed above, and such volatility is expected to
continue.
Our price-risk program permits the utilization of agreements and financial
instruments (such as futures, forward and options contracts, and swaps) to
mitigate price risk associated with fluctuations in oil and natural gas prices.
Below is a description of the financial instruments we have utilized to hedge
our exposure to price risk.
o Price Floors - At February 28, 2003, we had in place price floors in
effect through the October 2003 contract month for natural gas and
April 2003 for crude oil. The natural gas price floors cover notional
volumes of 3,150,000 MMBtu, with a weighted average floor price of
$4.36 per MMBtu. The crude oil price floors cover notional volumes of
400,000 barrels of oil, with a weighted average floor price of $26.13
per barrel.
o Participating Collars - At February 28, 2003, we had in place certain
"collar" financial transactions in effect through the June 2003
contract month. The natural gas collars cover notional volumes of
1,100,000 MMBtu, with a floor price of $3.00 per MMBtu and ceiling
prices ranging from $4.75 per MMBtu to $6.00 per MMBtu, plus 60%
participation by us in prices realized above the ceiling. The crude
oil collars cover notional volumes of 360,000 barrels of oil, with
floor prices ranging from $21.00 to $26.00 per barrel and ceiling
prices ranging from $29.04 to $35.05 per barrel, plus 60%
participation by us in prices realized above these ceilings.
o New Zealand Gas Contracts - All of our gas production in New Zealand
is sold under long-term, fixed-price contracts denominated in New
Zealand dollars. These contracts protect against price volatility, and
our revenue from these contracts will vary only due to production
fluctuations and foreign exchange rates.
Interest Rate Risk. Our Senior Notes have a fixed interest rate, so
consequently we are not exposed to cash flow risk from market interest rate
changes on our Senior Notes. At December 31, 2002, we had no outstanding
borrowings under our credit facility, which is subject to floating rates and
therefore susceptible to interest rate fluctuations. The result of a 10%
fluctuation in the bank's base rate would constitute 43 basis points and would
not impact 2003 cash flows based on this same level of borrowing.
Financial Instruments & Debt Maturities. Our financial instruments consist
of cash and cash equivalents, accounts receivable, accounts payable, bank
borrowings, and notes. The carrying amounts of cash and cash equivalents,
accounts receivable, and accounts payable approximate fair value due to the
highly liquid nature of these short-term instruments. The fair values of the
bank borrowings approximate the carrying amounts as of December 31, 2002 and
2001, and were determined based upon interest rates currently available to us
for borrowings with similar terms. Based on quoted market prices as of the
respective dates, the fair value of our Senior Notes due 2009 was $129.0 million
at December 31, 2002, and $126.5 million at December 31, 2001. Based upon quoted
market prices as of the respective dates, the fair value of our Senior Notes due
2012 was $189.2 million at December 31, 2002. Our credit facility with the banks
expires October 1, 2005. Our $125.0 million Senior Notes mature on August 1,
2009. Our $200.0 million Senior Notes mature on May 1, 2012.
Customer Credit Risk. We are exposed to the risk of financial
non-performance by customers. Our ability to collect on sales to our customers
is dependant on the liquidity of our customer base. To manage customer credit
risk, we monitor credit ratings of customers and seek to minimize exposure to
any one customer where other customers are readily available. Due to
availability of other purchasers, we do not believe the loss of any single oil
or gas customer would materially affect our revenues.
30
Item 8. Financial Statements and Supplementary Data
Report of Independent Auditors................................................34
Report of Independent Public Accountants......................................35
Consolidated Balance Sheets...................................................36
Consolidated Statements of Income.............................................37
Consolidated Statements of Stockholders' Equity...............................38
Consolidated Statements of Cash Flows.........................................39
Notes to Consolidated Financial Statements....................................40
1. Summary of Significant Accounting Policies..............................40
2. Earnings Per Share......................................................44
3. Provision for Income Taxes..............................................44
4. Long-Term Debt .........................................................46
5. Commitments and Contingencies...........................................47
6. Stockholders' Equity....................................................48
7. Related-Party Transactions..............................................49
8. Foreign Activities......................................................50
9. Acquisitions and Dispositions...........................................50
Supplemental Information (Unaudited)..........................................51
31
Report of Independent Auditors
Board of Directors and Stockholders
Swift Energy Company
We have audited the accompanying consolidated balance sheet of Swift Energy
Company and subsidiaries as of December 31,2002, and the related consolidated
statements of income, stockholders' equity and cash flows for the year then
ended. 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 audit. The consolidated financial statements of Swift
Energy Company and subsidiaries as of December 31, 2001, and for each of the two
years in the period ended December 31, 2001, were audited by other auditors who
have ceased operations and whose report dated February 18, 2002, expressed an
unqualified opinion on those statements.
We conducted our audit in accordance with auditing standards generally
accepted in the United States. 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 audit provides a reasonable basis
for our opinion.
In our opinion, the 2002 financial statements referred to above present
fairly, in all material respects, the consolidated financial position of Swift
Energy Company and subsidiaries at December 31, 2002, and the consolidated
results of their operations and their cash flows for the year then ended, in
conformity with accounting principles generally accepted in the United States.
ERNST & YOUNG LLP
Houston, Texas
February 10, 2003
32
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, 2001
and 2000, and the related consolidated statements of income, stockholders'
equity, and cash flows for each of the three years in the period ended December
31, 2001. 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 auditing standards generally
accepted in the United States. 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, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
February 18, 2002
NOTE: This is a copy of the report previously issued by Arthur Andersen LLP and
has not been reissued.
33
Consolidated Balance Sheets
Swift Energy Company and Subsidiaries
December 31,
ASSETS 2002 2001
-------------- ---------------
Current Assets:
Cash and cash equivalents $ 3,816,107 $ 2,149,086
Accounts receivable-
Oil and gas sales 17,360,716 14,215,189
Associated limited partnerships and joint ventures 191,964 6,259,604
Joint interest owners 3,364,846 11,467,461
Other current assets 5,034,566 2,661,640
------------------ -----------------
Total Current Assets 29,768,199 36,752,980
------------------ -----------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties 1,150,633,802 974,698,428
Unproved properties 69,603,481 95,943,163
------------------ -----------------
1,220,237,283 1,070,641,591
Furniture, fixtures, and other equipment 9,595,944 8,706,414
------------------ -----------------
1,229,833,227 1,079,348,005
Less - Accumulated depreciation, depletion, and amortization (504,323,773) (448,139,334)
------------------- -----------------
725,509,454 631,208,671
------------------ -----------------
Other Assets:
Deferred income taxes 2,680,585 ---
Deferred charges 9,047,621 3,723,182
------------------ -----------------
11,728,206 3,723,182
------------------ -----------------
$ 767,005,859 $ 671,684,833
================== =================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 43,028,708 $ 38,884,380
Payable to associated limited partnerships 91,126 26,573,490
Undistributed oil and gas revenues 3,764,350 7,787,465
------------------ -----------------
Total Current Liabilities 46,884,184 73,245,335
------------------ -----------------
Long-Term Debt 324,271,973 258,197,128
Deferred Income Taxes 30,776,518 27,589,650
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none --- ---
outstanding
Common stock, $.01 par value, 85,000,000 shares authorized,
27,811,632 and 25,634,598 shares issued, and 27,201,509 and
24,795,564 shares outstanding, respectively 278,116 256,346
Additional paid-in capital 333,543,471 296,172,820
Treasury stock held, at cost, 610,123 and 839,034 shares, (8,749,922) (12,032,791)
respectively
Retained earnings 40,179,572 28,256,345
Accumulated other comprehensive loss, net of income tax (178,053) ---
------------------- -----------------
365,073,184 312,652,720
------------------ -----------------
$ 767,005,859 671,684,833
================== =================
See accompanying Notes to Consolidated Financial Statements.
34
Consolidated Statements of Income
Swift Energy Company and Subsidiaries
Year Ended December 31,
2002 2001 2000
---------------------------------------------------------
Revenues:
Oil and gas sales $ 141,195,713 $ 181,184,635 $ 189,138,947
Fees from limited partnerships and joint ventures 67,173 427,583 331,497
Interest income 263,738 49,281 1,339,386
Gain on asset disposition 7,332,668 --- ---
Price-risk management and other, net 1,110,519 2,145,991 815,116
----------------- ------------------ ---------------
149,969,811 183,807,490 191,624,946
----------------- ------------------ ---------------
Costs and Expenses:
General and administrative, net 10,564,849 8,186,654 5,585,487
Depreciation, depletion, and amortization 56,224,392 59,502,040 47,771,393
Oil and gas production 41,497,312 36,719,609 29,220,315
Interest expense, net 23,274,969 12,627,022 15,968,405
Other expenses --- 2,102,251 ---
Write-down of oil and gas properties --- 98,862,247 ---
----------------- ------------------ ---------------
131,561,522 217,999,823 98,545,600
----------------- ------------------ ---------------
Income (Loss) Before Income Taxes, Extraordinary Item
and Change in Accounting Principle 18,408,289 (34,192,333) 93,079,346
Provision (Benefit) for Income Taxes 6,485,062 (12,237,436) 33,265,480
----------------- ------------------- ---------------
Income (Loss) Before Extraordinary Item and Change
In Accounting Principle $ 11,923,227 $ (21,954,897) $ 59,813,866
Extraordinary Loss on Early Extinguishment of Debt (net of --- --- 629,858
taxes)
Cumulative Effect of Change in Accounting Principle (net of --- 392,868 ---
taxes)
----------------- ------------------ ---------------
Net Income (Loss) $ 11,923,227 $ (22,347,765) $ 59,184,008
================= =================== ===============
Per Share Amounts-
Basic: Income (Loss) Before Extraordinary Item
and Change in Accounting Principle $ 0.45 $ (0.89) $ 2.82
Extraordinary Loss --- --- (0.03)
Change in Accounting Principle --- (0.01) ---
----------------- ------------------ ---------------
Net Income (Loss) $ 0.45 $ (0.90) $ 2.79
================= ================== ===============
Diluted: Income (Loss) Before Extraordinary Item
and Change in Accounting Principle $ 0.45 $ (0.89) $ 2.53
Extraordinary Loss --- --- (0.02)
Change in Accounting Principle --- (0.01) ---
----------------- ------------------ ---------------
Net Income (Loss) $ 0.45 $ (0.90) $ 2.51
================= ================== ===============
Weighted Average Shares Outstanding 26,382,906 24,732,099 21,244,684
================= ================== ===============
See accompanying Notes to Consolidated Financial Statements.
35
Consolidated Statements of Stockholders' Equity
Swift Energy Company and Subsidiaries
Accumulated
Additional Retained Other
Common Paid-in Treasury Earnings Comprehensive
Stock (1) Capital Stock (Deficit) Loss Total
----------- ---------------- -------------- -------------- ----------------- --------------
Balance, December 31, 1999 $ 216,832 $ 191,092,851 $ (12,325,668) $ (8,579,898) $ - $ 170,404,117
Stock issued for benefit plans
(46,632 shares) 310 297,060 224,469 - - 521,839
Stock options exercised
(543,450 shares) 5,434 4,316,446 - - - 4,321,880
Employee stock purchase plan
(29,889 shares) 299 297,414 - - - 297,713
Subordinated notes conversion
(3,164,644 shares) 31,646 97,392,952 - - - 97,424,598
Comprehensive income:
Net income - - - 59,184,008 - 59,184,008
--------------
Total comprehensive income - - - - - 59,184,008
----------- ---------------- -------------- -------------- ----------------- --------------
Balance, December 31, 2000 $ 254,521 $ 293,396,723 $ (12,101,199) $ 50,604,110 $ - $ 332,154,155
=========== ================ ============== ============== ================= ==============
Stock issued for benefit plans
(11,945 shares) 72 354,973 68,408 - - 423,453
Stock options exercised
(152,915 shares) 1,529 1,942,634 - - - 1,944,163
Employee stock purchase plan
(22,360 shares) 224 478,490 - - - 478,714
Comprehensive income:
Net loss - - - (22,347,765) - (22,347,765)
--------------
Total comprehensive income - - - - - (22,347,765)
----------- ---------------- -------------- -------------- ----------------- --------------
Balance, December 31, 2001 $ 256,346 $ 296,172,820 $ (12,032,791) $ 28,256,345 $ - $ 312,652,720
=========== ================ ============== ============== ================= ==============
Stock issued for benefit plans
(38,149 shares) 292 617,960 127,795 - - 746,047
Stock options exercised
(112,995 shares) 1,130 1,206,413 - - - 1,207,543
Public stock offering
(1,725,000 shares) 17,250 30,465,809 - - - 30,483,059
Employee stock purchase plan
(9,801 shares) 98 122,343 - - - 122,441
Stock issued in acquisitions
(520,000 shares) 3,000 4,958,126 3,155,074 - - 8,116,200
Comprehensive income:
Net income - - - 11,923,227 - 11,923,227
Change in fair value of
cash flow hedges, net of
income tax - - - - (178,053) (178,053)
--------------
Total comprehensive income - - - - - 11,745,174
----------- ---------------- -------------- -------------- ----------------- --------------
Balance, December 31, 2002 $ 278,116 $ 333,543,471 $ (8,749,922) $ 40,179,572 $ (178,053) $ 365,073,184
=========== ================ ============== ============== ================= ==============
(1)$.01 par value.
See accompanying Notes to Consolidated Financial Statements.
36
Consolidated Statements of Cash Flows
Swift Energy Company and Subsidiaries
Year Ended December 31,
-------------------------------------------------------
2002 2001 2000
------------------ ------------------ ----------------
Cash Flows from Operating Activities:
Net income (loss) $ 11,923,227 $ (22,347,765) $ 59,184,008
Adjustments to reconcile net income (loss) to net cash
provided by operating activities-
Depreciation, depletion, and amortization 56,224,392 59,502,040 47,771,393
Write-down of oil and gas properties --- 98,862,247 ---
Deferred income taxes 6,482,724 (12,555,618) 33,413,626
Gain on asset disposition (7,332,668) --- ---
Deferred revenue amortization related to production --- --- (587,629)
payment
Other 270,770 509,973 1,075,848
Change in assets and liabilities-
(Increase) decrease in accounts receivable, 283,419 16,207,377 (14,308,274)
excluding
income taxes receivable
Increase in accounts payable and accrued 3,174,450 12,984 1,601,042
liabilities
(Increase) decrease in income taxes receivable 600,000 (306,983) 47,213
------------------ ------------------- ---------------
Net Cash Provided by Operating Activities 71,626,314 139,884,255 128,197,227
------------------ ------------------ ----------------
Cash Flows from Investing Activities:
Additions to property and equipment (155,233,923) (275,126,333) (173,277,356)
Proceeds from the sale of property and equipment 13,256,674 9,274,440 3,844,375
Net cash received as operator of oil and gas properties 4,152,645 5,927,539 19,769,213
Net cash received (distributed) as operator of
partnerships and joint ventures (23,241,501) (3,574,601) 2,674,593
Other (39,953) (534,898) (1,329)
------------------- ------------------ -----------------
Net Cash Used in Investing Activities (161,106,058) (264,033,853) (146,990,504)
------------------- ------------------ -----------------
Cash Flows from Financing Activities:
Proceeds from (payments of) long-term debt 200,000,000 --- (15,203,000)
Net proceeds from (payments of) bank borrowings (134,000,000) 123,400,000 10,600,000
Net proceeds from issuances of common stock 31,409,200 1,633,508 2,697,561
Payments of debt issuance costs (6,262,435) (721,756) ---
------------------ ------------------ ----------------
Net Cash Provided by (Used in) Financing 91,146,765 124,311,752 (1,905,439)
Activities ------------------- ------------------ ----------------
Net Increase (Decrease) in Cash and Cash Equivalents $ 1,667,021 $ 162,154 $ (20,698,716)
Cash and Cash Equivalents at Beginning of Year 2,149,086 1,986,932 22,685,648
------------------ ------------------ ----------------
Cash and Cash Equivalents at End of Year $ 3,816,107 $ 2,149,086 $ 1,986,932
================== ================== ================
Supplemental Disclosures of Cash Flows Information:
Cash paid during year for interest, net of amounts capitalized $ 19,189,822 $ 12,207,205 $ 15,528,280
Cash paid during year for income taxes $ 2,500 $ 441,926 $ ---
Non-Cash Financing Activity:
Issuance of common stock in acquisitions $ 8,116,200 $ --- $ ---
Conversion of convertible notes to common stock $ --- $ --- $ 99,797,000
See accompanying Notes to Consolidated Financial Statements.
37
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 our wholly
owned subsidiaries, which are engaged in the exploration, development,
acquisition, and operation of oil and natural gas properties, with a focus on
onshore and inland waters oil and natural gas reserves in Texas and Louisiana,
as well as onshore oil and natural gas reserves in New Zealand. Our investments
in associated oil and gas partnerships and joint ventures are accounted for
using the proportionate consolidation method, whereby our proportionate share of
each entity's assets, liabilities, revenues, and expenses are included in the
appropriate classifications in the consolidated financial statements.
Intercompany balances and transactions have been eliminated in preparing the
consolidated financial statements.
Use of Estimates. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities, if
any, at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from estimates.
Property and Equipment. We follow 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 exploration, development, and
acquisition of oil and gas reserves are capitalized. Under the full-cost method
of accounting, such costs may be incurred both prior to or after the acquisition
of a property and include lease acquisitions, geological and geophysical
services, drilling, completion, and equipment. Internal costs incurred that are
directly identified with exploration, development, and acquisition activities
undertaken by us for our own account, and which are not related to production,
general corporate overhead or similar activities, are also capitalized. For the
years 2002, 2001, and 2000, such internal costs capitalized totaled $10.7
million, $11.6 million, and $10.3 million, respectively. Interest costs related
to unproved properties are also capitalized to unproved oil and gas properties.
Interest not capitalized and 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 involving a significant amount of
reserves or where the proceeds from the sale of oil and gas properties would
significantly alter the relationship between capitalized costs and proved
reserves of oil and gas attributable to a cost center.
Future development, site restoration, and dismantlement and abandonment
costs, net of salvage values, are estimated property by property based on
current economic conditions and are amortized to expense as our capitalized oil
and gas property costs are amortized.
We compute the provision for depreciation, depletion, and amortization of
oil and gas properties by the unit-of-production method. Under this method, we
compute the provision by multiplying the total unamortized costs of oil and gas
properties--including future development, site restoration, and dismantlement
and abandonment costs, net of salvage value, but excluding costs of unproved
properties--by an overall rate determined by dividing the physical units of oil
and gas produced during the period by the total estimated units of proved oil
and gas reserves. This calculation is done on a country-by-country basis.
Furniture, fixtures and other equipment are depreciated by the straight-line
method at rates based on the estimated useful lives of the property. Repairs and
maintenance are charged to expense as incurred. Renewals and betterments are
capitalized.
The cost of unproved properties not being amortized is assessed quarterly,
on a country-by-country basis, to determine whether such properties have been
impaired. In determining whether such costs should be impaired, we evaluate
current drilling results, lease expiration dates, current oil and gas industry
conditions, international economic conditions, capital availability, foreign
currency exchange rates, the political stability in the countries in which we
have an investment, and available geological and geophysical information. Any
impairment assessed is added to the cost of proved properties being amortized.
To the extent costs accumulate in countries where there are no proved reserves,
any costs determined by management to be impaired are charged to expense.
38
Full-Cost Ceiling Test. 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 unhedged period-end prices, discounted at 10%, and the lower of
cost or fair value of unproved properties, adjusted for related income tax
effects ("Ceiling Test"). This calculation is done on a country-by-country basis
for those countries with proved reserves.
The calculation of the Ceiling Test and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves. There are
numerous uncertainties inherent in estimating quantities of proved reserves and
in projecting the future rates of production, timing, and plan of development.
The accuracy of any reserves estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. Results of
drilling, testing, and production subsequent to the date of the estimate may
justify revision of such estimate. Accordingly, reserves estimates are often
different from the quantities of oil and gas that are ultimately recovered.
In the fourth quarter of 2001, as a result of low oil and gas prices at
December 31, 2001, we reported a non-cash write-down on a before-tax basis of
$98.9 million ($63.5 million after tax) on our domestic properties. We had no
write-down on our New Zealand properties.
Given the volatility of oil and gas prices, it is reasonably possible that
our estimate of discounted future net cash flows from proved oil and gas
reserves could change in the near term. If oil and gas prices decline from the
Company's period-end prices used in the Ceiling Test, even if only for a short
period, it is possible that additional non-cash write-downs of oil and gas
properties could occur in the future.
Oil and Gas Revenues. Oil and gas revenues are recognized, as the product
is delivered, using the entitlement method in which we recognize our ownership
interest in production as revenue. If our sales exceed our ownership share of
production, the differences are reported as deferred revenues. Natural gas
balancing receivables are reported when our ownership share of production
exceeds sales. As of December 31, 2002, we did not have any material natural gas
imbalances.
Deferred Charges. Legal and accounting fees, underwriting fees, printing
costs, and other direct expenses associated with the public offering in August
1999 of our 10.25% Senior Subordinated Notes (the "Senior Notes"), the September
2001 extension of our bank credit facility, and the public offering in April
2002 of our 9.375% Senior Subordinated Notes were capitalized and are amortized
over the life of each of the respective note offerings and credit facility. The
Convertible Notes were called for redemption effective December 26, 2000, and
the balance of their unamortized issuance costs at that time of $3,046,181 was
either transferred to the common stock equity accounts ($2,643,476) for the
portion of the Convertible Notes converted into common stock at the election of
those note holders or was recorded, net of taxes, as Extraordinary Loss on Early
Extinguishment of Debt ($402,705) for the portion of the Convertible Notes
redeemed for cash. The Senior Notes due 2009 mature on August 1, 2009, and the
balance of their issuance costs at December 31, 2002, was $2,686,678, net of
accumulated amortization of $814,764. The issuance costs associated with our
revolving credit facility, which closed in September 2001, have been capitalized
and are being amortized over the life of the facility. The balance of revolving
credit facility issuance costs at December 31, 2002, was $986,957, net of
accumulated amortization of $937,591. The Senior Notes due 2012 mature on May 1,
2012, and the balance of their issuance costs at December 31, 2002, was
$5,373,986, net of accumulated amortization of $244,349.
Limited Partnerships and Joint Ventures. We formed 88 limited partnerships
between 1984 and 1995 to acquire interests in producing oil and gas properties
and 13 partnerships between 1993 and 1998 to drill for oil and gas. In all of
these partnerships, Swift paid for varying percentages of the capital or
front-end costs and continuing costs of the partnerships and, in return,
received differing percentage ownership interests in the partnerships, along
with reimbursement of costs and/or payment of certain fees. At year-end 2002, we
continue to serve as managing general partner for six remaining drilling
partnerships, and during fiscal 2002 less than 1% of our total oil and gas sales
was attributable to our interests in those partnerships.
During 1997 and 1998, eight drilling partnerships formed between 1979 and
1985 and 21 of the production purchase partnerships sold their properties and
were dissolved, in each case following a vote of the investors in the particular
partnerships approving such liquidations. Between 1999 and 2001, the investors
in all but six of the remaining partnerships voted to sell the partnerships'
properties or their interests in the partnerships and dissolve. During 2001,
seven drilling partnerships and two production purchase partnerships were
dissolved. During 2002, an additional 65 production purchase partnerships were
dissolved. The remaining six partnerships will continue to operate until their
limited partners vote otherwise.
39
Price-Risk Management Activities. The Company follows SFAS No. 133 which
requires that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. The statement also
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or a liability
measured at its fair value. Special hedge accounting for qualifying hedges would
allow the gains and losses on derivatives to offset related results on the
hedged item in the income statements and would require that a company formally
document, designate, and assess the effectiveness of transactions that receive
hedge accounting. SFAS No. 133, as amended by SFAS No. 137 and SFAS No. 138, was
adopted by us on January 1, 2001.
We have a price-risk management policy to use derivative instruments to
protect against declines in oil and gas prices, mainly through the purchase of
protection price floors and collars. Upon adoption of SFAS No. 133 on January 1,
2001, we recorded a net of taxes charge of $392,868, which is recorded as a
Cumulative Effect of Change in Accounting Principle. During 2002 and 2001, we
recognized net losses of $191,701 and net gains of $1,173,094, respectively,
relating to our derivative activities. Approximately $7,889 of the losses
recognized in 2002 were unrealized as the contracts were still open, while
$16,784 of losses recognized in the comparative 2001 period were unrealized.
This activity is recorded in "Price-risk management and other, net" on the
accompanying statements of income. At December 31, 2002, the Company had
recorded $178,053, net of taxes of $100,155, of derivative losses in "Other
comprehensive loss" on the accompanying balance sheet. This amount represents
the change in fair value for the effective portion of our collar transactions
that were qualified as cash flow hedges. The ineffectiveness reported in
"Price-risk management and other, net" for 2002 was not material. The Company
expects to reclassify all amounts held in "Other comprehensive loss" into the
statement of income within the next six months.
As of December 31, 2002, the Company had entered into certain "collar"
financial transactions in effect through the June 2003 contract month. The
natural gas collars cover notional volumes of 1,900,000 MMBtu for the price
floors and 760,000 MMBtu for the price ceilings, with a weighted average floor
price of $3.00 per MMBtu and a weighted average ceiling price of $5.27 per
MMBtu. The crude oil collars cover notional volumes of 360,000 barrels for the
price floors and 144,000 barrels for the price ceilings, with a weighted average
floor price of $21.00 per barrel and a weighted average ceiling price of $30.35
per barrel. When the Company entered into the following transactions they were
designated as a hedge of the variability in cash flows associated with the
forecasted sale of its oil and natural gas production. Changes in the fair value
of a hedge that is highly effective and is designated and qualifies as a cash
flow hedge, to the extent that the hedge is effective, are initially recorded in
Other Comprehensive Income (Loss). When the hedged transactions are recorded
upon the actual sale of oil and natural gas, these gains or losses are
transferred from Other Comprehensive Income (Loss) and recorded in "Price-risk
management and other, net" on the income statement. The fair value of our
derivatives are computed using the Black- Scholes option pricing model and are
periodically verified against quotes from brokers. At December 31, 2002, the
fair value of the natural gas collars was a liability of $0.1 million and the
fair value of our crude oil collars was a liability of $0.2 million. These
instruments are recognized on the balance sheet in "Accounts payable and accrued
liabilities" at December 31, 2002.
Income Taxes. Under SFAS No. 109, "Accounting for Income Taxes," 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.
Cash and Cash Equivalents. We consider all highly liquid debt instruments
with an initial maturity of three months or less to be cash equivalents.
Credit Risk Due to Certain Concentrations. We extend credit, primarily in
the form of monthly oil and gas sales and joint interest owners receivables, to
various companies in the oil and gas industry, which results in a concentration
of credit risk. The concentration of credit risk may be affected by changes in
economic or other conditions and may accordingly impact our overall credit risk.
However, we believe that the risk of these unsecured receivables is mitigated by
the size, reputation, and nature of the companies to which we extend credit.
During 2002, oil and gas sales to Eastex Crude Company were $25.4 million, or
18.0% of oil and gas sales, while sales to subsidiaries of Contact Energy in New
Zealand were $14.6 million, or 10.3% of oil and gas sales. During 2001, oil and
gas sales to subsidiaries of Eastex Crude Company were $31.6 million, or 18.1%
of oil and gas sales, while sales to subsidiaries of Enron were $18.2 million,
or 10.4% of oil and gas sales. During 2000, oil and gas sales to subsidiaries of
Eastex Crude Company were $47.4 million, or 25.7% of our oil and gas sales,
while sales to subsidiaries of PG&E Energy Trading Corporation were $21.2
million, or 11.5% of oil and gas sales. Beginning in December 2000, the
subsidiaries of PG&E Energy Trading Corporation to which we made sales were sold
to subsidiaries of El Paso Corporation. All receivables from PG&E were
40
collected. During the fourth quarter of 2001, we wrote off $1.4 million due to
uncollected receivables related to gas sold to Enron in November 2001. This
amount is included in "Other expenses" on the Consolidated Statement of Income.
We have discontinued sales of oil and gas to Enron and are selling that
production to other purchasers.
Environmental Costs. Our operations include activities which are subject to
extensive federal and state environmental regulations. Costs associated with
redemption projects, which are probable and quantifiable, are accrued in
advance. Ongoing environmental compliance costs are expensed as incurred.
Fair Value of Financial Instruments. Our financial instruments consist of
cash and cash equivalents, accounts receivable, accounts payable, bank
borrowings, and senior notes. The carrying amounts of cash and cash equivalents,
accounts receivable, and accounts payable approximate fair value due to the
highly liquid nature of these short-term instruments. The fair values of the
bank borrowings approximate the carrying amounts as of December 31, 2002 and
2001, and were determined based upon variable interest rates currently available
to us for borrowings with similar terms. Based on quoted market prices as of the
respective dates, the fair values of our Senior Notes due 2009 were $129.0
million and $126.5 million at December 31, 2002 and 2001, respectively. Based
upon quoted market prices as of December 31, 2002, the fair value of our Senior
Notes due 2012 was $189.2 million. The carrying value of our Senior Notes due
2009 was $124.3 million and $124.2 million at December 31, 2002 and 2001,
respectively. The carrying value of our Senior Notes due 2012 was $200.0 million
at December 31, 2002.
Stock Based Compensation. We have three stock-based compensation plans,
which are described more fully in Note 6. We account for those plans under the
recognition and measurement principles of APB Opinion No. 25, "Accounting for
Stock Issued to Employees," and related interpretations. No stock-based employee
compensation cost is reflected in net income, as all options granted under those
plans had an exercise price equal to the market value of the underlying common
stock on the date of the grant. Had compensation expense for these plans been
determined based on the fair value of the options consistent with SFAS No. 123,
"Accounting for Stock-Based Compensation," our net income (loss) and earnings
(loss) per share would have been adjusted to the following pro forma amounts:
2002 2001 2000
---------------- -------------- ----------------
Net Income As Reported $11,923,227 $(22,347,765) $59,184,008
(Loss):
Stock-based
employee
compensation expense
determined under
fair value method
for all awards, net
of tax (4,451,799) (4,284,859) (2,652,343)
---------------- -------------- ----------------
Pro Forma $7,471,428 $(26,632,624) $56,531,665
Basic EPS: As Reported $.45 $(0.90) $2.79
Pro Forma $.28 $(1.08) $2.66
Diluted EPS: As Reported $.45 $(0.90) $2.51
Pro Forma $.27 $(1.08) $2.40
Pro forma compensation cost reflected above may not be representative of
the cost to be expected in future 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 in 2002, 2001, and 2000, respectively: no dividend yield; expected
volatility factors of 73.72%, 46.9%, and 46.7%; risk-free interest rates of
4.74%, 5.24%, and 6.61%; and expected lives of 7.4, 7.3, and 6.7 years.
41
New Accounting Pronouncements. In June 2001, the Financial Accounting
Standards Board issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." The statement requires entities to record the fair value of a
liability for legal obligations associated with the retirement obligations of
tangible long-lived assets in the period in which it is incurred. When the
liability is initially recorded, the entity increases the carrying amount of the
related long-lived asset. Over time, accretion of the liability is recognized
each period, and the capitalized cost is depreciated over the useful life of the
related asset. Upon settlement of the liability, an entity either settles the
obligation for its recorded amount or incurs a gain or loss upon settlement.
This standard will require us to record a liability for the fair value of our
dismantlement and abandonment costs, excluding salvage values. The standard is
effective for fiscal years beginning after June 15, 2002. The Company has
completed its assessment of SFAS No. 143. At January 1, 2003, we estimate that
the present value of our future Asset Retirement Obligation ("ARO") for oil and
gas properties and related equipment is approximately $8.9 million. We estimate
that the cumulative effect of change in accounting principle, due to the
adoption of SFAS No. 143, will be a loss of $6.8 million, or a loss of $4.4
million net of taxes. This cumulative effect of change in accounting principle
will be a non-cash charge to net income in the first quarter of 2003.
2. Earnings Per Share
Basic earnings per share ("Basic EPS") have been computed using the
weighted average number of common shares outstanding during the respective
periods. The calculation of diluted earnings per share ("Diluted EPS") for 2000
assumes conversion of our Convertible Notes as of the beginning of the
respective periods and the elimination of the related after-tax interest
expense. The calculation of diluted earnings per share for all periods assumes,
as of the beginning of the period, exercise of stock options and warrants using
the treasury stock method. Certain of our stock options that would potentially
dilute Basic EPS in the future were also antidilutive for the 2002 and 2001
periods.
The following is a reconciliation of the numerators and denominators used
in the calculation of Basic and Diluted EPS for the years ended December 31,
2002, 2001, and 2000:
2002 2001 2000
-------------------------------- ---------------------------------- ----------------------------------
Net Per Share Net Per Share Net Per Share
Income Shares Amount Loss Shares Amount Income Shares Amount
----------- -------- -------- ---------- --------- --------- --------- --------- ---------
Basic EPS:
Net Income (Loss)
and Share Amounts $11,923,227 26,382,90 $ 0.45 $ (22,347,765) 24,732,099 $ (0.90) $ 59,184,008 21,244,684 $ 2.79
Dilutive Securities:
6.25% Convertible -- -- -- -- 4,772,418 3,546,933
Notes
Stock Options -- 372,700 -- -- -- 713,112
------------ --------- -------------- ---------- ------------ ----------
Diluted EPS:
Net Income (Loss) and
Assumed Share
Conversions $11,923,227 26,755,60 $ 0.45 $ (22,347,765 24,732,099 $ (0.90) $ 63,956,426 25,504,729 $ 2.51
=========== ========= ============= ========== ============ ==========
42
3. Provision for Income Taxes
The following is an analysis of the consolidated income tax provision
(benefit):
Year Ended December 31,
-----------------------------------------------------
2002 2001 2000
---------------- --------------- ---------------
Current $ 2,338 $ 114,611 $ (29,000)
Deferred 6,482,724 (12,352,047) 33,294,480
---------------- --------------- ---------------
Total $ 6,485,062 $ (12,237,436) $ 33,265,480
================ =============== ===============
There are differences between income taxes computed using the federal
statutory rate (35% for 2002, 2001, and 2000) and our effective income tax rates
(35.2%, 35.8%, and 35.7% for 2002, 2001, and 2000, respectively), primarily as
the result of state income taxes, foreign income taxes, and in 2002 a currency
exchange rate gain on the net foreign deferred tax asset. New Zealand's
statutory rate and effective tax rate are 33%. We have not computed any
provision for U.S. taxes on the undistributed earnings of our New Zealand
subsidiaries as management intends to permanently reinvest such earnings. The
undistributed earnings of the New Zealand subsidiaries were $8,175,013 and
$1,234,919 for 2002 and 2001, respectively. Upon distribution of these earnings
in the form of dividends or otherwise, we may be subject to U.S. income taxes
and New Zealand withholding taxes. It is not practical, however, to estimate the
amount of taxes that may be payable on the eventual remittance of these
earnings. Presently, there are no foreign tax credits available to reduce the
U.S. taxes on such amounts if repatriated. Reconciliations of income taxes
computed using the statutory rate to the effective income tax rates are as
follows:
2002 2001 2000
---------------- --------------- ---------------
Income taxes computed at U.S. statutory rate $ 6,442,901 $ (11,967,317) $ 32,577,772
State tax provisions, net of federal benefits 298,933 (279,875) 775,850
Effect of foreign operations (163,500) (24,698) ---
Currency translation gain on foreign tax asset (208,688) --- ---
Other, net 115,416 34,454 (88,142)
---------------- --------------- ---------------
Provision (benefit) for income taxes $ 6,485,062 $ (12,237,436) $ 33,265,480
================ =============== ===============
The tax effects of temporary differences representing the net deferred tax
liability (asset) at December 31, 2002 and 2001, were as follows:
2002 2001
---- ----
Long-term deferred tax assets:
Alternative minimum tax credits (Domestic) (1,979,399) ($1,979,399)
Carryover items (Domestic) (51,174,237) (18,877,969)
Acquired deferred tax asset (Foreign) (4,753,044)
-
Carryover Items (Foreign) (19,494,129) -
------------ ------------
Total long-term deferred tax assets (77,400,809) (20,857,368)
------------ ------------
Long-term deferred tax liabilities
U.S. oil and gas properties 83,361,520 47,556,981
Foreign oil and gas properties 21,566,588 407,524
Other 568,634 482,513
------------ ------------
Total long-term deferred tax liability 105,496,742 48,447,018
------------ ----------
Net long-term deferred tax liability $28,095,933 $27,589,650
============ ===========
43
The tax basis of the assets of Southern NZ on the acquisition date exceeded
the cash purchase price paid by SENZ to acquire this entity. To account for the
future tax benefits of this additional basis, SENZ recorded a deferred tax asset
of $4,944,786. Additionally, the Company recognized a currency exchange rate
gain, primarily attributable to this acquired asset, in the amount of $632,389.
The asset is being amortized over the period in which the tax amortization is
deducted. The remaining asset value at December 31, 2002, is $4,753,044, of
which $950,609 will be amortized in 2003. The total foreign carryover asset
amount is $19,494,129, of which $7,807,407 is expected to reverse in 2003. The
asset is attributable to cumulative New Zealand net operating losses with a
$U.S. equivalent value of $59,073,129 (using the December 31, 2002, exchange
rate) multiplied by the New Zealand tax rate of 33%. These net operating losses
include the costs of drilling oil and gas wells classified as exploratory. Under
New Zealand tax rules, such costs are deductible at the time the well is
drilled, but are "clawed back" into revenue if and when the well establishes
commercial production. After the clawback, the costs are then amortized as
development expenditures. This clawback is expected to occur in 2003, but should
be absorbed by the cumulative excess of tax amortization over book depreciation,
depletion, and amortization. New Zealand tax net operating losses do not expire.
At December 31, 2002, the Company had alternative minimum tax credits of
$1,979,399 that carry forward indefinitely. These credits are available to
reduce future regular tax liability to the extent they exceed the related
tentative minimum tax otherwise due.
The domestic deferred tax carryover items are attributable to expected
future tax benefits in the amounts of $43,290,193 for federal net operating
losses, $1,291,637 for State of Louisiana net operating losses, $6,574,726 for
capital losses, and other items totaling $17,681. At December 31, 2002,
cumulative federal net operating losses were $124 million, which will expire
between 2018 and 2022. Louisiana net operating losses total $37 million and will
expire between 2013 and 2017.
The Company has not recorded any valuation allowance against the deferred
tax assets attributable to net operating loss carryovers at December 31, 2002
and 2001, as management estimates that it is more likely than not that these
assets will be fully utilized before they expire. Significant changes in
estimates caused by changes in oil and gas prices, production levels, capital
expenditures, and other variables could impact the Company's ability to utilize
the carryover amounts.
In 2002 we recognized a capital loss of approximately $18.2 million as the
result of the liquidation of our partnerships. This loss can only be utilized to
offset capital gains and will expire in 2007. The Company plans to continue
selling, in the ordinary course of business, a number of oil and gas properties
over the next few years in order to optimize its portfolio of non-core oil and
gas properties. To generate gains from these dispositions that can absorb the
capital loss carryforward, the sales proceeds must exceed the Company's total
investment in the properties before depreciation, depletion, and IDC deductions
and amortization. Company management has identified several qualified properties
to sell which have estimated current market values in excess of the total
original costs. Management believes that it is more likely than not that the
Company will fully utilize the capital loss carryover. If the Company is unable
to complete the sale of these properties at the prices it has estimated to be
the fair market value, then a significant portion of the capital loss carryover
could expire before it is utilized.
44
4. Long-Term Debt
Our long-term debt as of December 31, 2002 and 2001, is as follows:
2002 2001
------------ -------------
Bank Borrowings $ --- $ 134,000,000
Senior Notes due 2009 124,271,973 124,197,128
Senior Notes due 2012 200,000,000 ---
------------ -------------
Long-Term Debt $ 324,271,973 $ 258,197,128
============ =============
Bank Borrowings. At December 31, 2002, we had no outstanding borrowings
under our $300.0 million credit facility with a syndicate of nine banks which
has a borrowing base of $195.0 million and expires in October 2005. At December
31, 2001, we had borrowings of $134.0 million under our credit facility. The
interest rate is either (a) the lead bank's prime rate (4.25% at December 31,
2002) or (b) the adjusted London Interbank Offered Rate ("LIBOR") plus the
applicable margin depending on the level of outstanding debt. The applicable
margin is based on the ratio of the outstanding balance to the last calculated
borrowing base. Of the $134.0 million borrowed at December 31, 2001, $130.0
million was borrowed at the LIBOR rate plus applicable margin, which averaged
3.64%.
The terms of our credit facility include, among other restrictions, a
limitation on the level of cash dividends (not to exceed $5.0 million in any
fiscal year), a remaining aggregate limitation on purchases of our stock of
$15.0 million, 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 our common stock. We are currently in compliance with the
provisions of this agreement. The credit facility is secured by our domestic oil
and gas properties. We have also pledged 65% of the stock in our two active New
Zealand subsidiaries as collateral for this credit facility. The borrowing base
is re-determined at least every six months and was reconfirmed by our bank group
in November 2002 with the same $195.0 million borrowing base. The next scheduled
borrowing base review is in May 2003.
Interest expense on the credit facility, including commitment fees and
amortization of debt issuance costs, totaled $3,618,570 in 2002, $5,833,564 in
2001, and $654,936 in 2000. The amount of commitment fees included in interest
expense was $569,773, $306,663, and $284,633 in 2002, 2001, and 2000,
respectively.
Convertible Notes. In November 1996, we sold $115.0 million of 6.25%
Convertible Subordinated Notes due 2006. The Convertible Notes were unsecured
and convertible into Swift common stock at the option of the holders at an
adjusted conversion price of $31.534 per share. Interest on the notes was
payable semiannually, on May 15 and November 15. On December 11, 2000, we called
for the redemption of our Convertible Notes effective December 26, 2000, at
103.75% of their principal amount. Holders of approximately $100.0 million of
45
the Convertible Notes elected to convert their notes into 3,164,644 shares of
our common stock. Holders of the remaining $15.0 million of the Convertible
Notes elected to redeem their notes for cash plus accrued interest. This cash
redemption resulted in our recognizing an Extraordinary Loss on the Early
Extinguishment of Debt (net of taxes) of $0.6 million, or $1.0 million before
taxes.
Interest expense on the Convertible Notes, including amortization of debt
issuance costs, totaled $7,426,599 in 2000.
Senior Notes Due 2009. Our Senior Notes due 2009 consist of $125.0 million
of 10.25% Senior Subordinated Notes due August 2009. The Senior Notes were
issued at 99.236% of the principal amount on August 4, 1999, and will mature on
August 1, 2009. The Senior Notes are unsecured senior subordinated obligations
and are subordinated in right of payment to all our existing and future senior
debt, including our bank debt. Interest on the Senior Notes is payable
semiannually, on February 1 and August 1, and commenced with the first payment
on February 1, 2000. On or after August 1, 2004, the Senior Notes are redeemable
for cash at the option of Swift, with certain restrictions, at 105.125% of
principal, declining to 100% in 2007. Upon certain changes in control of Swift,
each holder of Senior Notes will have the right to require us to repurchase the
Senior Notes at a purchase price in cash equal to 101% of the principal amount,
plus accrued and unpaid interest to the date of purchase. We are currently in
compliance with the provisions of the indenture governing the Senior Notes.
Interest expense on the Senior Notes due 2009, including amortization of
debt issuance costs and discount, totaled $13,156,973 in 2002, $13,123,052 in
2001, and $13,092,127 in 2000.
Senior Notes Due 2012. Our Senior Notes due 2012 at December 31, 2002,
consist of $200,000,000 of 9.375% Senior Subordinated Notes due May 2012. The
Senior Notes were issued on April 11, 2002, and will mature on May 1, 2012. The
notes are unsecured senior subordinated obligations and are subordinated in
right of payment to all our existing and future senior debt, including our bank
debt. Interest on the Senior Notes is payable semiannually on May 1 and November
1, with the first interest payment on November 1, 2002. On or after May 1, 2007,
the Senior Notes are redeemable for cash at the option of Swift, with certain
restrictions, at 104.688% of principal, declining to 100% in 2010. In addition,
prior to May 1, 2005, we may redeem up to 33.33% of the Senior Notes with the
proceeds of qualified offerings of our equity at 109.375% of the principal
amount of the Senior Notes, together with accrued and unpaid interest. Upon
certain changes in control of Swift, each holder of Senior Notes will have the
right to require us to repurchase the Senior Notes at a purchase price in cash
equal to 101% of the principal amount, plus accrued and unpaid interest to the
date of purchase. We are currently in compliance with the provisions of the
indenture governing the Senior Notes.
Interest expense on the Senior Notes due 2012, including amortization of
debt issuance costs and discount, totaled $13,525,599 in 2002.
We have capitalized interest in the amount of $7,000,000, $6,300,000, and
$5,000,000 in 2002, 2001, and 2000, respectively.
5. Commitments and Contingencies
Total rental and lease expenses were $1,923,451 in 2002, $1,322,611 in
2001, and $1,255,474 in 2000. Our remaining minimum annual obligations under
non-cancelable operating lease commitments are $2,190,363 for 2003, $2,191,495
for 2004, $523,755 for 2005, $190,676 for 2006, $190,676 in 2007 and $186,834
thereafter or $5,473,799 in the aggregate. The rental and lease expenses and
remaining minimum annual obligations under non-cancelable operating lease
commitments primarily relate to the lease of our office space in Houston, Texas,
and in New Zealand.
In the ordinary course of business, we have entered into agreements with
pipeline operators that require us to contribute a portion of the pipeline
construction cost in the event certain transportation volumes are not met. We
have $933,666 accrued in "Accounts payable and accrued liabilities" at December
31, 2002, on the accompanying balance sheet related to these commitments.
As of December 31, 2002, we were the managing general partner of six
limited partnerships. Because we serve as the general partner of these entities,
under state partnership law we are 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.
46
In the ordinary course of business, we have been party to various legal
actions, which arise primarily from our activities as operator of oil and gas
wells. In management's opinion, the outcome of any such currently pending legal
actions will not have a material adverse effect on the financial position or
results of operations of Swift.
6. Stockholders' Equity
Common Stock. In December 2000, the holders of approximately $100.0 million
of our Convertible Notes converted such notes into 3,164,644 shares of our
common stock, which resulted in an increase in our common stock capital accounts
of approximately $97.4 million.
During the first quarter of 2002, we issued 1.725 million shares of common
stock at a price of $18.25 per share. Gross proceeds from this offering were
$31,481,250, with issuance costs of $998,191.
Stock-Based Compensation Plans. We have two current stock option plans, the
2001 Omnibus Stock Compensation Plan, which was adopted by our board of
directors in February 2001 and was approved by shareholders at the 2001 annual
meeting of shareholders, and the 1990 Non-Qualified Stock Option Plan solely for
our independent directors. In addition, we have an employee stock purchase plan.
Under the 2001 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 our board of directors are
automatically granted options to purchase shares of common stock on a formula
basis. Both plans provide that the exercise prices equal 100% of the fair value
of the common stock on the date of grant. Unless otherwise provided, options
become exercisable for 20% of the shares on the first anniversary of the grant
of the option and are exercisable for an additional 20% per year thereafter.
Options granted expire 10 years after the date of grant or earlier in the event
of the optionee's separation from employment. At the time the stock options are
exercised, the option price is credited to common stock and additional paid-in
capital.
The employee stock purchase plan provides eligible employees the
opportunity to acquire shares of Swift common stock at a discount through
payroll deductions. The plan year is from June 1 to the following May 31. The
first year of the plan commenced June 1, 1993. To date, employees have been
allowed to authorize payroll deductions of up to 10% of their base salary during
the plan year by making an election to participate prior to the start of a plan
year. The purchase price for stock acquired under the plan is 85% of the lower
of the closing price of our 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 for the last three years, we have
issued 9,801 shares at a price of $12.47 in 2002, 22,360 shares at a price of
$21.41 in 2001, and 29,889 shares at a price range of $8.40 to $10.57 in 2000.
The estimated weighted average fair value of shares issued under this plan, as
determined using the Black-Scholes option-pricing model, was $1.92 in 2002,
$8.19 in 2001, and $4.25 in 2000. As of December 31, 2002, 352,627 shares
remained available for issuance under this plan. There are no charges or credits
to income in connection with this plan.
The following is a summary of our stock options under these plans as of
December 31, 2002, 2001, and 2000:
2002 2001 2000
------------------------ ---------------------- --------------------------
Wtd. Avg. Wtd. Avg. Wtd. Avg.
Shares Exer. Price Shares Exer. Price Shares Exer. Price
------------------------ ---------------------- --------------------------
Options outstanding, beginning of period 2,639,504 $ 17.44 2,076,593 $ 11.70 2,148,511 $ 9.08
Options granted 585,055 $ 12.32 747,073 $ 31.51 645,944 $ 16.88
Options canceled (84,254) $ 23.37 (31,247) $ 14.09 (174,412) $ 8.71
Options exercised (121,800) $ 8.61 (152,915) $ 8.69 (543,450) $ 8.48
------------ ----------- -----------
Options outstanding, end of period 3,018,505 $ 16.64 2,639,504 $ 17.44 2,076,593 $ 11.70
============ =========== ===========
Options exercisable, end of period 1,480,490 $ 13.71 1,181,141 $ 11.49 897,711 $ 9.35
============ =========== ===========
Options available for future grant, end of 419,845 1,155,057 181,235
period ============ =========== ===========
Estimated weighted average fair value per
share of options granted during the year $9.55 $20.68 $10.90
============ =========== ===========
47
The following table summarizes information about stock options outstanding
at December 31, 2002:
Options Outstanding Options Exercisable
--------------------------------------- -------------------------
Range of Number Wtd. Avg. Wtd. Avg. Number Wtd. Avg.
Exercise Outstanding Remaining Exercise Exercisable Exercise
Prices at 12/31/02 Contractual Price At 12/31/02 Price
Life
------------------- -------------- ----------- ----------- ------------- -----------
$ 5.00 to $16.99 2,018,767 6.2 $ 10.32 1,126,267 $ 9.31
$17.00 to $28.99 272,480 5.4 $ 23.01 183,625 $ 23.52
$29.00 to $41.00 727,258 8.1 $ 31.82 170,598 $ 32.18
-------------- -----------
$ 5.00 to $41.00 3,018,505 6.6 $ 16.64 1,480,490 $ 13.71
============== ===========
Employee Stock Ownership Plan. In 1996, we established an Employee Stock
Ownership Plan ("ESOP") effective January 1, 1996. All employees over the age of
21 with one year of service are participants. This plan has a five-year cliff
vesting, and service is recognized after the ESOP effective date. The ESOP is
designed to enable our employees to accumulate stock ownership. While there will
be no employee contributions, participants will receive an allocation of stock
that has been contributed by Swift. Compensation expense is reported when such
shares are released to employees. The plan may also acquire Swift common stock,
purchased at fair market value. The ESOP can borrow money from Swift to buy
Swift stock. 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, 2002, 2001, and 2000, all of the ESOP compensation was earned.
Employee Savings Plan. We have a savings plan under Section 401(k) of the
Internal Revenue Code. Eligible employees may make voluntary contributions into
the 401(k) savings plan with Swift contributing on behalf of the eligible
employee an amount equal to 100% of the first 2% of compensation and 75% of the
next 4% of compensation based on the contributions made by the eligible
employees. Our contribution to the 401(k) savings plan totaled $603,000,
$558,000, and $483,000 for the years ended December 31, 2002, 2001, and 2000,
respectively. The contributions in 2002 and 2001 were made all in common stock,
while the 2000 contribution was made half in common stock and half in cash. The
shares of common stock contributed to the 401(k) savings plan totaled 64,490,
28,798, and 7,175 shares for the 2002, 2001, and 2000 contributions,
respectively.
Common Stock Repurchase Program. In March 1997, our board of directors
approved a common stock repurchase program that terminated as of June 30, 1999.
Under this program, we spent approximately $13.3 million to acquire 927,774
shares in the open market at an average cost of $14.34 per share. At December
31, 2002, 610,123 shares remain in treasury (net of 317,651 shares used to fund
ESOP, 401(k) contributions and acquisitions) with a total cost of $8,749,922 and
are included in "Treasury stock held, at cost" on the balance sheet.
Shareholder Rights Plan. In August 1997, the board of directors declared a
dividend of one preferred share purchase right on each outstanding share of
Swift common stock. The rights are not currently exercisable but would become
exercisable if certain events occurred relating to any person or group acquiring
or attempting to acquire 15% or more of our outstanding shares of common stock.
Thereafter, upon certain triggers, each right not owned by an acquirer allows
its holder to purchase Swift securities with a market value of two times the
$150 exercise price.
48
7. Related-Party Transactions
We are the operator of a number of properties owned by our affiliated
limited partnerships and, accordingly, charge these entities operating fees. The
operating fees charged to the partnerships in 2002, 2001, and 2000 totaled
approximately $300,000, $925,000, and $1,775,000, respectively, and are recorded
as reductions in general and administrative expense and oil and gas production
expense. We are also reimbursed for direct, administrative, and overhead costs
incurred in conducting the business of the limited partnerships, which totaled
approximately $973,000, $3,140,000, and $4,465,000 in 2002, 2001, and 2000,
respectively. In partnerships in which the limited partners have voted to sell
their remaining properties and liquidate their limited partnerships, we are also
reimbursed for direct, administrative, and overhead costs incurred in the
disposition of such properties, which costs totaled approximately $510,000,
$2,360,000, and $1,220,000 in 2002, 2001, and 2000, respectively.
8. Foreign Activities
As of December 31, 2002, our gross capitalized oil and gas property costs
in New Zealand totaled approximately $172.8 million. Approximately $145.0
million have been included in the proved properties portion of our oil and gas
properties while $27.8 million is included as unproved properties. Our
functional currency in New Zealand is the U.S. dollar.
9. Acquisitions and Dispositions
New Zealand
Through our subsidiary, Swift Energy New Zealand Limited ("SENZ"), we
acquired Southern Petroleum (NZ) Exploration Limited ("Southern NZ") in January
2002 for approximately $51.4 million in cash. We allocated $36.1 million of the
acquisition price to "Proved properties," $10.0 million to "Unproved
properties," $4.9 million to "Deferred income taxes" and $0.4 million to "Other
current assets" on our Consolidated Balance Sheet. Southern NZ was an affiliate
of Shell New Zealand and owns interests in four onshore producing oil and gas
fields, hydrocarbon processing facilities, and pipelines connecting the fields
and facilities to export terminals and markets. This acquisition was accounted
for by the purchase method of accounting. In conjunction with this TAWN
acquisition, we granted Shell New Zealand a short-term option to acquire an
undivided 25% interest in our permit 38719, which included our Rimu and Kauri
areas and the Rimu Production Station. This option was not exercised and expired
on May 15, 2002.
In March 2002, we purchased through our subsidiary, SENZ, all of the New
Zealand assets owned by Antrim for 220,000 shares of Swift Energy common stock
valued at $4.2 million and an effective date adjustment of approximately $0.5
million for total consideration of $4.7 million. Antrim owned a 5% interest in
permit 38719 and a 7.5% interest in permit 38716.
In September 2002, we purchased through our subsidiary, SENZ, Bligh's 5%
working interest in permit 38719 and 5% interest in the Rimu petroleum mining
permit 38151, along with their 3.24% working interest in the four TAWN petroleum
mining licenses for 300,000 shares of Swift Energy common stock valued at $3.9
million and $2.7 million in cash for total consideration of $6.6 million.
Russia
In 1993, we entered into a Participation Agreement with Senega, a Russian
Federation joint stock company, to assist in the development and production of
reserves from two fields in Western Siberia and received a 5% net profits
interest. We also purchased a 1% net profits interest. Our investment in Russia
was fully impaired in the third quarter of 1998. In March 2002, we received $7.5
million for our investment in Russia. Although the proceeds from sales of oil
and gas properties are generally treated as a reduction of oil and gas property
costs, because we had previously charged to expense all $10.8 million of
cumulative costs relating to our Russian activities, this cash payment, net of
transaction expenses, resulted in recognition of a $7.3 million non-recurring
gain on asset disposition in the first quarter of 2002.
49
Supplemental Information (Unaudited)
Swift Energy Company and Subsidiaries
Capitalized Costs. The following table presents our aggregate capitalized
costs relating to oil and gas producing activities and the related depreciation,
depletion, and amortization:
Total Domestic New Zealand
--------------------- ---------------- -----------------
December 31, 2002:
Proved oil and gas properties $ 1,150,633,802 $ $ 145,050,310
1,005,583,492
Unproved oil and gas properties 69,603,481 41,850,890 27,752,591
--------------------- ---------------- -----------------
--------------------- ---------------- -----------------
1,220,237,283 1,047,434,382 172,802,901
Accumulated depreciation, depletion, and amortization (498,619,342) (485,289,654) (13,329,688)
--------------------- --------------- -----------------
--------------------- ---------------- -----------------
Net capitalized costs $ 721,617,941 $ 562,144,728 $ 159,473,213
===================== ================ =================
===================== ================ =================
December 31, 2001:
Proved oil and gas properties $ 974,698,428 $ 929,172,460 $ 45,525,968
Unproved oil and gas properties 95,943,163 57,096,694 38,846,469
--------------------- ---------------- -----------------
--------------------- ---------------- -----------------
1,070,641,591 986,269,154 84,372,437
Accumulated depreciation, depletion, and amortization (442,337,531) (442,166,052) (171,479)
--------------------- ---------------- -----------------
--------------------- ---------------- -----------------
Net capitalized costs $ 628,304,060 $ 544,103,102 $ 84,200,958
===================== ================ =================
Of the $41,850,890 of domestic unproved property costs (primarily seismic
and lease acquisition costs) at December 31, 2002, excluded from the amortizable
base, $10,041,167 was incurred in 2002, $16,553,117 was incurred in 2001,
$7,068,192 was incurred in 2000, and $8,188,414 was incurred in prior years.
When we are in an active drilling mode, we evaluate the majority of these
unproved costs within a two to four year time frame.
Of the $27,752,591 of net New Zealand unproved property costs at December
31, 2002, excluded from the amortizable base, $18,392,660 was incurred in 2002,
$2,717,517 was incurred in 2001, $4,427,033 was incurred in 2000, and $2,215,381
was incurred in prior years. We expect to continue drilling in New Zealand to
delineate our prospects there within a two to four year time frame.
50
Costs Incurred. The following table sets forth costs incurred related to
our oil and gas operations:
Year Ended December 31, 2002
-----------------------------------------------------------
Total Domestic New Zealand
--------------------- ---------------- -----------------
Acquisition of proved properties $ 64,229,283 $ 5,415,932 $ 58,813,351
Lease acquisitions(1) 16,009,939 10,789,876 5,220,063
Exploration 18,395,335 7,571,215 10,824,120
Development 47,407,087 40,366,378 7,040,709
--------------------- ---------------- -----------------
Total acquisition, exploration, and development(2) $ 146,041,644 $ 64,143,401 $ 81,898,243
--------------------- ---------------- -----------------
Processing plants $ 7,845,520 $ 1,313,299 $ 6,532,221
Field compression facilities 2,251,247 2,251,247 --
--------------------- ---------------- -----------------
Total plants and facilities $ 10,096,767 $ 3,564,546 $ 6,532,221
--------------------- ---------------- -----------------
Total costs incurred $ 156,138,411 $ 67,707,947 $ 88,430,464
===================== ================ =================
Year Ended December 31, 2001
-----------------------------------------------------------
Total Domestic New Zealand
--------------------- --------------- -----------------
Acquisition of proved properties $ 41,286,539 $ 40,491,203 $ 795,336
Lease acquisitions1 31,225,493 25,688,068 5,537,425
Exploration 41,981,536 35,944,405 6,037,131
Development 132,246,713 112,597,856 19,648,857
--------------------- --------------- -----------------
Total acquisition, exploration, and development(2) $ 246,740,281 $ 214,721,532 $ 32,018,749
--------------------- --------------- -----------------
Processing plants $ 23,331,095 $ 817,454 $ 22,513,641
Field compression facilities 319,703 319,703 --
--------------------- --------------- -----------------
Total plants and facilities $ 23,650,798 $ 1,137,157 $ 22,513,641
--------------------- --------------- -----------------
Total costs incurred $ 270,391,079 $ 215,858,689 $ 54,532,390
===================== =============== =================
Year Ended December 31, 2000
-----------------------------------------------------------
Total Domestic New Zealand
--------------------- ---------------- -----------------
Acquisition of proved properties $ 34,191,883 $ 34,191,883 $ --
Lease acquisitions1 20,842,103 16,315,749 4,526,354
Exploration 20,150,834 18,524,883 1,625,951
Development 104,083,409 93,931,500 10,151,909
--------------------- ---------------- -----------------
Total acquisition, exploration, and development 2 $ 179,268,229 $ 162,964,015 $ 16,304,214
--------------------- ---------------- -----------------
Processing plants $ 1,819,464 $ 755,119 $ 1,064,345
Field compression facilities 203,789 203,789 --
--------------------- ---------------- -----------------
Total plants and facilities $ 2,023,253 $ 958,908 $ 1,064,345
--------------------- ---------------- -----------------
Total costs incurred $ 181,291,482 $ 163,922,923 $ 17,368,559
===================== ================ =================
(1) 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 in 2002, 2001, and 2000 were $23,454,234,
$22,470,263, and $16,791,834, respectively.
(2) Includes capitalized general and administrative costs directly associated
with the acquisition, exploration, and development efforts of approximately
$10,700,000, $11,600,000, and $10,300,000 in 2002, 2001, and 2000,
respectively. In addition, total includes $7,000,000, $6,300,000, and
$5,000,000 in 2002, 2001, and 2000, respectively, of capitalized interest
on unproved properties.
51
Results of Operations. New Zealand operations began in 2001 while all our
oil and gas operations in 2000 were domestic. The following table sets forth
results of our oil and gas operations:
Year Ended December 31, 2002
---------------------------------------------------
Total Domestic New Zealand
---------------- --------------- ----------------
Oil and gas sales $ 141,195,713 $ 112,065,003 $ 29,130,710
Oil and gas production costs (41,497,312) (33,088,958) (8,408,354)
Depreciation and depletion (55,254,467) (42,807,364) (12,447,103)
---------------- --------------- ----------------
44,443,934 36,168,681 8,275,253
Provision for income taxes 15,860,064 13,129,231 2,730,833
---------------- --------------- ----------------
Results of producing activities $ 28,583,870 $ 23,039,450 $ 5,544,420
================ =============== ================
Amortization per physical unit of production
(equivalent Mcf of gas) $ 1.11 $ 1.25 $ 0.80
================ =============== ================
Year Ended December 31, 2001
---------------------------------------------------
Total Domestic New Zealand
---------------- --------------- ----------------
Oil and gas sales $ 181,184,635 $ 179,360,844 $ 1,823,791
Oil and gas production costs (36,719,609) (36,554,418) (165,191)
Depreciation and depletion (58,589,116) (58,417,637) (171,479)
Write-down of oil and gas properties (98,862,247) (98,862,247) --
---------------- --------------- ----------------
(12,986,337) (14,473,458) 1,487,121
---------------- --------------- ----------------
Provision (benefit) for income taxes $ (4,647,810) (5,138,560) 490,750
================ =============== ================
Results of producing activities (8,338,527) $ (9,334,898) $ 996,371
Amortization per physical unit of production
================ =============== ================
(equivalent Mcf of gas) $ 1.31 1.32 0.34
================ =============== ================
Year Ended December 31, 2000
---------------------------------------------------
Total Domestic New Zealand
---------------- --------------- ----------------
Oil and gas sales $ 189,138,947 $ 189,138,947 $ --
Oil and gas production costs (29,220,315) (29,220,315) --
Depreciation and depletion (46,849,819) (46,849,819) --
---------------- --------------- ----------------
113,068,813 113,068,813 --
Provision for income taxes 40,365,566 40,365,566 --
---------------- --------------- ----------------
Results of producing activities $ 72,703,247 $ 72,703,247 $ --
================ =============== ================
Amortization per physical unit of production
(equivalent Mcf of gas) $ 1.11 $ 1.11 $ --
================ =============== ================
These results of operations do not include the effects of our hedging
activities.
52
Supplemental Reserve Information. The following information presents
estimates of our proved oil and gas reserves. Reserves were determined by us and
audited by H. J. Gruy and Associates, Inc. ("Gruy"), independent petroleum
consultants. Gruy's summary report dated February 7, 2003, is set forth as an
exhibit to the Form 10-K Report for the year ended December 31, 2002, and
includes definitions and assumptions that served as the basis for the audit 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 Total Domestic New Zealand
-------------------------- ----------------------------- -------------------------
Oil, NGL, Oil, NGL, Oil, NGL,
and and and
Natural Gas Condensate Natural Gas Condensate Natural Gas Condensate
(Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls)
------------- ------------ -------------- ------------ ------------ ------------
Proved reserves as of December 31, 1999(1) 329,959,750 20,806,263 329,959,750 20,806,263 -- --
Revisions of previous estimates(2) (4,300,787) (455,606) (4,300,787) (455,606) -- --
Purchases of minerals in place 26,567,925 2,196,547 26,567,925 2,196,547 -- --
Sales of minerals in place (363,262) (76,288) (363,262) (76,288) -- --
Extensions, discoveries, and other 93,869,841 15,134,694 38,556,364 3,943,807 55,313,477 11,190,887
additions
Production3 (27,119,491) (2,472,014) (27,119,491) (2,472,014) -- --
------------- ------------ -------------- ------------ ------------ ------------
Proved reserves as of December 31, 2000 418,613,976 35,133,596 363,300,499 23,942,709 55,313,477 11,190,887
Revisions of previous estimates(2) (122,127,541) 5,621,556 (101,693,477) 8,460,690 (20,434,064)(2,839,134)
Purchases of minerals in place 10,038,803 7,430,591 10,038,803 7,430,591 -- --
Sales of minerals in place (7,508,064) (555,586) (7,508,064) (555,586) -- --
Extensions, discoveries, and other 52,353,909 8,907,852 50,810,697 6,257,441 1,543,212 2,650,411
additions
Production (26,458,958) (3,055,373) (26,458,958) (2,971,112) -- (84,261)
------------- ------------ -------------- ------------ ------------ ------------
Proved reserves as of December 31, 2001 324,912,125 53,482,636 288,489,500 42,564,733 36,422,625 10,917,903
Revisions of previous estimates(2) (29,972,714) 5,298,439 (29,470,419) 8,675,082 (502,295) (3,376,643)
Purchases of minerals in place 51,940,044 3,711,948 226,245 24,207 51,713,799 3,687,741
Sales of minerals in place (3,839,124) (464,490) (3,839,124) (464,490) -- --
Extensions, discoveries, and other 10,822,919 12,180,558 197,919 11,304,782 10,625,000 875,776
additions
Production (27,131,578) (3,770,128) (15,780,059) (3,074,674) (11,351,519) (695,454)
------------- ------------ -------------- ------------ ------------ ------------
Proved reserves as of December 31, 2002 326,731,672 70,438,963 239,824,062 59,029,640 86,907,610 11,409,323
============= ============ ============== ============ ============ ============
Proved developed reserves:
December 31, 1999 174,046,096 8,437,299 174,046,096 8,437,299 -- --
December 31, 2000 215,169,833 10,980,196 215,169,833 10,980,196 -- --
December 31, 2001 181,651,578 23,759,574 167,401,736 20,393,142 14,249,842 3,366,432
December 31, 2002(4) 233,514,572 35,928,395 149,731,562 26,530,112 83,783,010 9,398,283
(1) Proved reserves exclude quantities subject to our volumetric production
payment agreement, which expired with the last required delivery of volumes
in October 2000.
(2) Revisions of previous estimates are related to upward or downward
variations based on current engineering information for production rates,
volumetrics, and reservoir pressure. Additionally, changes in quantity
estimates are affected by the increase or decrease in crude oil and natural
gas prices at each year-end. Proved reserves, as of December 31, 2002, were
based upon prices in effect at year-end. The weighted average of 2002
year-end prices for total, domestic, and New Zealand were $3.49, $4.23, and
$1.48 per Mcf of natural gas, $29.27, $29.36, and $28.80 per barrel of oil
and $16.54, $17.30 and $12.24 per barrel of NGL, respectively. This
compares to $2.51, $2.68, and $1.18 per Mcf, $18.45, $18.51, and $18.25 per
barrel of oil and $10.70, $11.00 and $8.90 per barrel of NGL as of December
31, 2001, for total, domestic, and New Zealand, respectively.
(3) Natural gas production for 2000 excludes 405,130 Mcf, respectively,
delivered under our volumetric production payment agreement.
(4) At December 31, 2002, 60% of our reserves are proved developed and 40% are
proved undeveloped.
53
Standardized Measure of Discounted Future Net Cash Flows. The standardized
measure of discounted future net cash flows relating to proved oil and gas
reserves is as follows:
Year Ended December 31, 2002
---------------------------------------------------------
Total Domestic New Zealand
----------------- ----------------- -----------------
Future gross revenues $ 2,990,669,570 $ 2,578,435,576 $ 412,233,994
Future production costs (720,599,745) (612,094,088) (108,505,657)
Future development costs (224,792,520) (208,492,520) (16,300,000)
----------------- ----------------- -----------------
Future net cash flows before income taxes 2,045,277,305 1,757,848,968 287,428,337
Future income taxes (599,195,484) (512,966,321) (86,229,163)
----------------- ----------------- -----------------
Future net cash flows after income taxes 1,446,081,821 1,244,882,647 201,199,174
Discount at 10% per annum (609,212,030) (540,375,347) (68,836,683)
----------------- ----------------- -----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 836,869,791 $ 704,507,300 $ 132,362,491
================= ================= =================
Year Ended December 31, 2001
---------------------------------------------------------
Total Domestic New Zealand
----------------- ----------------- -----------------
Future gross revenues $ 1,706,475,138 $ 1,485,480,927 $ 220,994,211
Future production costs (483,588,857) (436,141,429) (47,447,428)
Future development costs (198,172,628) (185,347,628) (12,825,000)
----------------- ----------------- -----------------
Future net cash flows before income taxes 1,024,713,653 863,991,870 160,721,783
Future income taxes (261,635,331) (208,726,729) (52,908,602)
----------------- ----------------- -----------------
Future net cash flows after income taxes 763,078,322 655,265,141 107,813,181
Discount at 10% per annum (308,520,417) (274,882,174) (33,638,243)
----------------- ----------------- -----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 454,557,905 $ 380,382,967 $ 74,174,938
================= ================= =================
Year Ended December 31, 2000
---------------------------------------------------------
Total Domestic New Zealand
----------------- ----------------- -----------------
Future gross revenues $ 4,995,951,799 $ 4,737,560,630 $ 258,391,169
Future production costs (817,127,348) (807,436,139) (9,691,209)
Future development costs (204,620,116) (180,320,116) (24,300,000)
----------------- ----------------- -----------------
Future net cash flows before income taxes 3,974,204,335 3,749,804,375 224,399,960
Future income taxes (1,321,061,952) (1,243,731,594) (77,330,358)
----------------- ----------------- -----------------
Future net cash flows after income taxes 2,653,142,383 2,506,072,781 147,069,602
Discount at 10% per annum (1,075,183,917) (1,017,995,158) (57,188,759)
----------------- ----------------- -----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 1,577,958,466 $ 1,488,077,623 $ 89,880,843
================= ================= =================
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 we
reasonably expect to receive.
54
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, net of salvage value, based on year-end cost estimates and the estimated
effect of future income taxes.
4. Future income taxes are computed by applying the statutory tax rate to
future net cash flows reduced by the tax basis of the properties, the estimated
permanent differences applicable to future oil and gas producing activities, and
tax carry forwards.
The estimates of cash flows and reserves quantities shown above are based
on year-end oil and gas prices for each period and do not include the effects of
our hedging activities. Subsequent changes to such year-end oil and gas prices
could have a significant impact on discounted future net cash flows. Under
Securities and Exchange Commission rules, companies that follow the full-cost
accounting method are required to make quarterly Ceiling Test calculations,
using prices in effect as of the period end date presented (see Note 1 to the
Consolidated Financial Statements). 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 our 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 reserves estimates.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
Year Ended December 31,
-------------------------------------------------------
2002 2001 2000
------------------ ------------------ ----------------
Beginning balance $ 454,557,905 $ 1,577,958,466 $ 438,943,834
------------------ ------------------ ----------------
Revisions to reserves proved in prior years--
Net changes in prices, production costs, and future
development costs 373,890,614 (1,692,627,074) 1,523,487,598
Net changes due to revisions in quantity 2,582,633 (93,669,181) (36,102,814)
estimates
Accretion of discount 60,298,619 231,325,481 56,405,451
Other (88,675,455) (204,768,815) (220,119,873)
------------------ ------------------ ----------------
Total revisions 348,096,411 (1,759,739,589) 1,323,670,362
New field discoveries and extensions, net of future
production and development costs 190,461,371 110,213,160 359,265,150
Purchases of minerals in place 76,538,437 39,544,163 160,240,785
Sales of minerals in place (5,769,642) (50,131,970) (598,021)
Sales of oil and gas produced, net of production (99,698,403) (144,262,145) (159,331,003)
costs
Previously estimated development costs incurred 48,752,814 94,107,760 65,953,028
Net change in income taxes (176,069,102) 586,868,060 (610,185,669)
------------------ ------------------ ----------------
Net change in standardized measure of discounted
future net cash flows 382,311,886 (1,123,400,561) 1,139,014,632
------------------ ------------------ ----------------
Ending balance $ 836,869,791 $ 454,557,905 $ 1,577,958,466
================== ================== ================
55
Quarterly Data (Unaudited). The following table presents summarized
quarterly financial information for the years ended December 31, 2001 and 2002:
Income/(Loss) Basoc EPS Diluted EPS
Before Income/(Loss) Income/(Loss) Income/(Loss)
Income Taxes, Before Before Before
Extraordinary Extraordinary Extraordinary Extraordinary Basic Diluted
Item and Item and Item and Item and EPS EPS
Change in Change in Change In Change In Net Net
Accounting Accounting Net Accounting Accounting Income/ Income/
Revenues Principle(b) Principle(b) Income/(Loss) Principle(b) Principle(b) (Loss) (Loss)
------------ ------------- ------------- ------------- ----------------- ------------------ --------- ---------
2001:
First Quarter $ 62,392,014 $ 35,513,130 $ 22,719,653 $ 22,326,785 $ 0.92 $ 0.89 $ 0.91 $ 0.88
Second 52,303,265 23,408,900 14,972,946 14,972,946 0.61 0.59 0.61 0.59
Quarter
Third Quarter 41,244,583 11,607,563 7,420,090 7,420,090 0.30 0.29 0.30 0.29
Fourth 27,867,628 (104,721,926) (67,067,586) (67,067,586) (2.71) (2.71) (2.71) (2.71)
Quarter
------------ -------------- ------------- -------------
Total $183,807,490 $ (34,192,333) (21,954,897) $ (22,347,765) $ (0.89) $ (0.89) $ (0.90) $ (0.90)
============= ============== ============= =============
2002:
First $ 34,354,077 $ 4,674,075 $ 3,019,810 $ 3,019,810 $ 0.12 $ 0.12 $ 0.12 $ 0.12
Quarter(a)
Second 38,570,269 5,518,886 3,584,092 3,584,092 0.13 0.13 0.13 0.13
Quarter
Third Quarter 36,570,809 2,933,350 1,947,006 1,947,006 0.07 0.07 0.07 0.07
Fourth 40,474,656 5,281,978 3,372,319 3,372,319 0.12 0.12 0.12 0.12
Quarter
------------ ------------- ------------- -------------
Total $149,969,811 $ 18,408,289 $ 11,923,227 $ 11,923,227 $ 0.45 $ 0.45 $ 0.45 $ 0.45
============ ============= ============= =============
(a) First quarter 2002 results include a gain on asset disposition of
$7,332,668.
(b) There were no extraordinary items in 2001 or 2002.
56
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
We have had no changes in or disagreements with our independent accountants
since our Board of Directors' June 12, 2002 appointment, based upon the
recommendation of our Audit committee, of Ernst & Young LLP as Swift's
independent auditors for the fiscal year ended December 31, 202, replacing
Arthur Andersen LLP as our independent auditors. That change was reported by
Swift in a Current Report on Form 8-K dated June 12, 2002, filed with the SEC on
June 18, 2002.
A copy of the previously issued report dated February 18, 2002 of Arthur
Andersen LLP on the consolidated financial statements of the Company as of and
for the fiscal years ended December 31, 2000 and December 31, 2001 is included
in this Form 10-K Report for the year ended December 31, 2002, but such
previously issued report has not been reissued.
PART III
Item 10. Directors and Executive Officers of the Registrant
The information required under Item 10 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 13, 2003, annual shareholders'
meeting is incorporated herein by reference.
Item 11. Executive Compensation
The information required under Item 11 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 13, 2003, annual shareholders'
meeting is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information required under Item 12 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 13, 2003, annual shareholders'
meeting is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions
The information required under Item 13 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 13, 2003, annual shareholders'
meeting is incorporated herein by reference.
Item 14. Controls and Procedures
The Company's chief executive officer and chief financial officer have
evaluated the Company's disclosure controls and procedures, as defined in Rules
13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934 (the "Exchange
Act") as of a date within 90 days before the filing of this report. Based on
that evaluation, they have concluded that such disclosure controls and
procedures are effective in alerting them on a timely basis to material
information relating to the Company required under the Exchange Act to be
disclosed in this report.
There were no significant changes in the Company's internal controls that
could significantly affect such controls subsequent to the date of their
evaluation.
57
PART IV
Item 15. 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 Ernst & Young LLP dated February 10,
2003, and the data contained therein are included in Item 8 hereof:
Report of Independent Auditors............................................34
Report of Independent Public Accountants..................................35
Consolidated Balance Sheets...............................................36
Consolidated Statements of Income.........................................37
Consolidated Statements of Stockholders' Equity...........................38
Consolidated Statements of Cash Flows.....................................39
Notes to Consolidated Financial Statements................................40
2. Financial Statement Schedules
[None]
58
3. Exhibits
3(a)(1) Amended and Restated Articles of Incorporation of Swift Energy Company.
3(b)(12) Second Amended and Restated Bylaws of Swift Energy Company, as amended through November 5, 2002.
4(a).1(2) Indenture dated as of July 29, 1999, between Swift Energy Company and Bank One, N.A., as Trustee.
4(a).2(3) First Supplemental Indenture dated as of August 4, 1999, between Swift Energy Company and Bank One, N.A.,
including the form of 10.25% Senior Subordinated Notes due 2009.
4(a).3(4) Indenture dated as of April 16, 2002, between Swift Energy Company and Bank One, N.A., as Trustee.
4(a).4(5) First Supplemental Indenture dated as of April 16, 2002, between Swift Energy Company and Bank One, N.A.,
including the form of 9 3/8% Senior Subordinated Notes due 2012.
10.1(13) 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(6) + Amended and Restated Swift Energy Company 1990 Nonqualified Stock Option Plan, as of May 1997.
10.5(7) + Swift Energy Company 2001 Omnibus Stock Compensation Plan
10.6(8) + Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company and A. Earl
Swift.
10.7(1) + Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company and Terry E.
Swift.
10.8(1) + Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company and James M.
Kitterman.
10.9(1) + Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company and Bruce H.
Vincent.
10.10(1)+ Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company and Joseph A.
D'Amico.
10.11(1)+ Employment Agreement dated as of May 9, 2001 between Swift Energy Company and Victor R. Moran.
10.13(1)+ Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company and Alton D.
Heckaman, Jr.
10.14(8)+ Fourth Amended and Restated Agreement and Release, by and between Swift Energy Company and Virgil Neil Swift,
dated November 20, 2000.
10.15(9) Amended and Restated Rights Agreement between Swift Energy and American Stock Transfer & Trust Company, dated
March 31, 1999.
10.16(10) Amended and Restated Credit Agreement among Swift Energy Company and Bank One, N.A. as administrative agent,
CIBC Inc. as syndication agent and Credit Lyonnais New York Branch and Societe Generale as documentation
agents and the lenders signatory hereto dated September 28, 2001.
10.17(11) First Amendment to Amended and Restated Credit Agreement, effective January 25, 2002 among Swift Energy
Company, as Borrower, Bank One, NA as Administrative Agent, CIBC Inc. as Syndication Agent, Credit Lyonnais,
New York Branch as Documentation Agent, Societe Generale as Documentation Agent and The Lenders
Signatory Hereto and Banc One Capital Markets, Inc. as Sole Lead Arranger and Sole Book Runner.
10.18(11) Second Amendment to Amended and Restated Credit Agreement, effective April 5, 2002 among Swift Energy Company,
as Borrower, Bank One, NA as Administrative Agent, CIBC Inc. as Syndication Agent, Wells Fargo Bank (Texas),
National Association as Syndication Agent, Credit Lyonnais, New York Branch as Documentation Agent, Societe
Generale as Documentation Agent and The Lenders Signatory Hereto and Banc One Capital Markets, Inc. as Sole
Lead Arranger and Sole Book Runner.
12* Swift Energy Company Ratio of Earnings to Fixed Charges.
21* List of Subsidiaries of Swift Energy Company
23(a)* The consent of H.J. Gruy and Associates, Inc.
23(b)* Consent of Ernst & Young LLP as to incorporation by reference regarding Forms S-8 and S-3 Registration
Statements.
31(a)* Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)* Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32* Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
99.1* The summary of H.J. Gruy and Associates, Inc. report, dated February 7, 2003.
(b) No Reports on Form 8-K were filed during the last quarter of 2002.
------------------------------------------------------------------------------------------------------------------------------------
1 Incorporated by reference from Swift Energy Company Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2001,
File No. 1-8754.
2 Incorporated by reference from Exhibit 4.2 to Pre-Effective Amendment No. 1 to Form S-3 Registration Statement No. 33-81651 of
Swift Energy Company, filed July 9, 1999, which Exhibit 4.2 is the form of such indenture.
3 Incorporated by reference from Swift Energy Company Report on Exhibit 4.1 to Form 8-K dated August 4, 1999, File No. 1-8754.
4 Incorporated by reference from Swift Energy Company Report on Exhibit 4-1 to Form 8-K dated April 16, 2002, File No. 1-8754.
5 Incorporated by reference from Swift Energy Company Report on Exhibit 4-2 to Form 8-K dated April 16, 2002, File No. 1-8754.
6 Incorporated by reference from Swift Energy Company definitive proxy statement for annual shareholders meeting filed April 14,
1997, File No. 1-8754.
7 Incorporated by reference from Registration Statement No. 333-67242 on Form S-8 filed on August 10, 2001.
8 Incorporated by reference from Swift Energy Company Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File
No. 1-8754.
9 Incorporated by reference from Swift Energy Company Amendment No. 1 to Form 8-A, filed April 7, 1999.
10 Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q for the quarterly period ended September 30, 2001, File No. 1-8754.
11 Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q for the quarterly period ended March 31, 2002, File No. 1-8754.
12 Incorporated by reference from Registration Statement No. 33-60469 on Form S-2 filed on June 22, 1995.
13 Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q for the quarterly period ended September 30, 2002, File No. 1-8754.
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
59
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant, Swift Energy Company, has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.
SWIFT ENERGY COMPANY
By /s/ Terry E. Swift
------------------------------
Terry E. Swift
Chief Executive Officer and President
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:
Signatures Title Date
----------- ------ -----
/s/ A. Earl Swift
---------------------------------- Chairman of the Board April 16, 2004
A. Earl Swift
/s/ Terry E. Swift Director
---------------------------------- Chief Executive Officer April 16, 2004
Terry E. Swift President
/s/ Alton D. Heckaman Jr. Sr. Vice-President--Finance
---------------------------------- Principal Financial Officer April 16, 2004
Alton D. Heckaman Jr.
/s/ David W. Wesson Controller
---------------------------------- Principal Accounting Officer April 16, 2004
David W. Wesson
/s/ Virgil N. Swift
---------------------------------- Director April 16, 2004
Virgil N. Swift
/s/ G. Robert Evans
---------------------------------- Director April 16, 2004
G. Robert Evans
/s/ Harold J. Withrow
---------------------------------- Director April 16, 2004
Harold J. Withrow
60
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
EXHIBITS
TO
FORM 10-K REPORT
FOR THE
YEAR ENDED DECEMBER 31, 2002
SWIFT ENERGY COMPANY
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060
EXHIBITS
12 Swift Energy Company Ratio of Earnings to Fixed Charges.
21 Significant Subsidiaries.
23(a) The consent of H.J. Gruy and Associates, Inc.
23(b) The consent of Ernst & Young LLP as to incorporation by
reference regarding Forms S-8 and S-3 Registration Statements.
31(a) Certification of the Chief Executive Officer pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
31(b) Certification of the Chief Financial Officer pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
32 Certification of Chief Executive Officer and Chief Financial Officer
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1 The Summary of H.J. Gruy and Associates, Inc. report, dated
February 7, 2003.