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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the Fiscal Year Ended December 31, 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 Part III, Items 10, 11, 12, and 13
for the Annual Meeting of
Shareholders to be held May 13, 2003
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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.
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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.
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
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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:
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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.
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
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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.
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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.
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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.
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
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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.
9
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
===================== ================= =================
10
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.
11
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.
12
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
13
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.
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
14
spills, gas leaks, and ruptures and discharges of toxic substances or gases that
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.
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.
15
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.
16
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).
NetAcre -- 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.
NetWell -- 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.
17
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.
18
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.
19
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.
20
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
21
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 operators 933,666 --- --- --- --- ---
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.
22
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.
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.
23
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.
24
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:
oPrice 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
oVolume 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:
oPrice 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
oVolume 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
(In millions) (Bcfe)
---------------------- ------------------------
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
========= ========= ======== =========
25
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
26
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.
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 mill