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UNITED STATES
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, 2003
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, 2004 was approximately $540,579,623.
The number of shares of common stock outstanding as of March 1, 2004 was
27,580,593 shares of common stock, $.01 par value.
Documents Incorporated by Reference
Document Incorporated as to
Notice and Proxy Statement for the Part III, Items 10, 11, 12, 13, and 14
Annual Meeting of Shareholders
to be held May 11, 2004
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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 33
Item 8. Financial Statements and Supple-
mentary Data 34
Item 9. Changes in and Disagreements with
Accountants on Accounting and
Financial Disclosure 64
Item 9A. Controls and Procedures 64
Part III
Item 10. Directors and Executive Officers of
the Registrant (1) 65
Item 11. Executive Compensation (1) 65
Item 12. Security Ownership of Certain Bene-
ficial Owners and Management (1) 65
Item 13. Certain Relationships and Related
Transactions (1) 65
Item 14 Principal Accountant Fees and Services (1) 65
Part IV
Item 15 Exhibits, Financial Statement
Schedules and Reports on Form 8-K 66
(1) Incorporated by reference from Notice and Proxy Statement for the
Annual Meeting of Shareholders to be held May 11, 2004.
2
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, 2003, we had interests in 998 wells located
domestically in four states, in federal offshore waters, and in New Zealand. We
operated 870 of these wells representing 95% of our proved reserves. At year-end
2003, we had estimated proved reserves of 820.4 Bcfe, of which approximately 47%
was crude oil, 41% natural gas, and 12% NGLs, and overall 59% was proved
developed. Our proved reserves are concentrated 40% in Louisiana, 37% in Texas,
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 2003
Area Location 2003 Proved Reserves Production
- ----------------- ------------------- ---------------------- -----------
AWP Olmos South Texas 26% 16%
Brookeland East Texas 5% 7%
Lake Washington South Louisiana 32% 23%
Masters Creek Central Louisiana 8% 11%
Rimu/Kauri New Zealand 15% 6%
TAWN New Zealand 6% 30%
---------------------- -----------
% of Total 92% 93%
---------------------- -----------
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. Based on our
total 2003 year-end proved reserves and total 2003 production, we calculated our
average reserve life as 15.4 years.
We have increased our proved reserves to 820.4 Bcfe at year-end 2003 from
436.1 Bcfe at year-end 1998, which has resulted in the replacement of 266% 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 2003, were $1.17, $0.91, $3.43,
$0.82, and $1.21 per Mcfe. In 2003, we increased our proved reserves by 9.5%,
which replaced 234% of our 2003 production. Our 2003 production increased by 7%
in relation to 2002 production. We have increased our production to 53.2 Bcfe at
year-end 2003 from 39.0 Bcfe at year-end 1998. Primarily due to increased
production, this has resulted in average annual growth in net cash provided by
operating activities of 15% per year from year-end 1998 to year-end 2003.
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 105.6 Bcfe of proved reserves through drilling
in 2003 (36.1 Bcfe from New Zealand), 83.9 Bcfe in 2002 (15.9 Bcfe from New
Zealand), and 105.8 Bcfe in 2001 (17.4 Bcfe from New Zealand). The 2003
additions were driven by the result of our development completion rate, as we
successfully completed 53 of 63 domestic development wells, while five of eight
domestic exploratory wells were successfully completed. In New Zealand we
drilled three development wells and one exploratory well. Only one of these four
wells, the exploratory well, was unsuccessful.
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We have also added reserves through acquisitions. In the first quarter of
2002, we purchased interests in the four TAWN fields in New Zealand for
approximately $51.4 million, which also included significant infrastructure,
after price adjustments. 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. 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 146 transactions from 1979 to 2003, we
have acquired approximately $697.6 million of producing oil and gas properties
on behalf of our co-investors and ourselves. We acquired, for our own account,
approximately $341.2 million of producing properties, with original proved
reserves estimated at 469.0 Bcfe during this period. Our producing property
acquisition expenditures in the past three years were $1.9 million in 2003,
$64.2 million in 2002, and $41.3 million in 2001. Our acquisition costs have
averaged $0.83 per Mcfe over this three-year period. Our acquisition costs in
2003 averaged $3.99 per Mcfe and were made up of purchases of limited partner
interests in several of the remaining partnerships we manage.
We currently plan to spend $130 to $150 million in total capital
expenditures in 2004, excluding acquisition costs and net of approximately $5
million to $15 million in non-core property dispositions. As always, the budget
for 2004 is dependent upon our performance and commodity pricing during the
year. As currently planned, domestic activities account for 80% 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. Our primary goals for the next five years are to
increase proved oil and gas reserves at an average rate of 5% to 10% per year
and production at an average rate of 7% to 12% per year.
Balanced Approach to Adding Reserves
When we believe market conditions favor increasing reserves through
acquisitions, we apply our considerable experience in evaluating and negotiating
prospective acquisitions. We believe this balanced approach between acquisitions
and drilling 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.
As both oil and natural gas prices were strong in 2003, carrying over from
2002, we focused our capital expenditures on drilling mainly in the Lake
Washington area and south Texas domestically and in the Rimu/Kauri area in New
Zealand. Our total capital expenditures in 2003 were $144.5 million. Of this
amount, $68.9 million was spent on drilling in the United States, with $57.0
million for development drilling and $11.9 million for exploratory drilling. In
New Zealand we spent $17.4 million on drilling, with $15.1 million for
development drilling and $2.3 for exploratory drilling. We also spent $25.9
million for the construction of domestic production and surface facilities,
mainly in our Lake Washington area. Our leasehold, seismic and geological costs
of prospects, both in the United States and New Zealand, were $17.8 million in
2003. The remaining capital expenditures of $14.5 million were spent on gas
processing plants, field compression facilities and furniture and fixtures, both
in the United States and New Zealand. During 2003, we largely relied upon cash
provided by operating activities of $110.8 million, proceeds of bank borrowings
of $15.9 million, and proceeds from the sale of property and equipment of $10.2
million to fund our capital expenditures.
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 from the 2001 level 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,
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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.
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.
The value of this concentration is enhanced by us acting as the operator of 95%
of our proved reserves at year-end 2003. Our operational control allows us to
better manage production, control our expenses, allocate capital and time field
development. We intend to continue acquiring 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:
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
are able to apply our technical and operational experience to optimize our
exploration and exploitation of such acquired properties.
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 reserves that can be developed in higher priced
environments.
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. We have since drilled 17 wells in New Zealand since operations began
in 1999. When we first acquired our interest in Masters Creek, Brookeland, and
Lake Washington, these areas also had significant additional development
potential, and are still viewed as such.
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. These
facilities and pipelines 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 experience and current
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
5
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 experience 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 provides the ability to
execute our business plan. Key components of our financial discipline include
maintaining a capital budget balanced between drilling and acquisitions,
establishing leverage targets that are reasonable given the volatility of the
oil and gas markets, and opportunistically accessing the capital markets. As of
December 31, 2003, our long-term debt comprised approximately 46% of our total
capitalization. At December 31, 2003, we had $233.3 million of available
borrowing capacity under our credit facility.
Domestic Core Operating Areas
AWP Olmos Area. As of December 31, 2003, we owned 27,900 net acres in the
AWP Olmos Area in South Texas. We have extensive 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 2003, we owned interests in and operated 504 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 2003, we completed eight development wells in this area, performed four
fracture extensions, and installed coiled tubing velocity strings in six wells.
At year-end 2003, we had 124 proved undeveloped locations. Also in 2003, we
purchased interests in the AWP Olmos area from partnerships we managed. Our
planned 2004 capital expenditures in this area will focus on drilling 15 to 18
development wells.
Brookeland Area. As of December 31, 2003, we owned drilling and production
rights in 72,516 net acres and 3,500 fee mineral acres in the Brookeland 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
56% oil and natural gas liquids. In 2003, we completed one development well in
this area. At year-end 2003, we had 12 proved undeveloped locations in this
area. Our planned 2004 capital expenditures in this area include drilling one
development well.
Lake Washington Field. As of December 31, 2003, we owned drilling and
production rights in 12,911 net acres in the Lake Washington Field. This area is
located in Plaquemines Parish in South Louisiana. The reserves are approximately
94% oil and natural gas liquids. We acquired our 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 77
producing wells is gathered from three platforms located in water depths from 2
to 12 feet, with drilling and workover operations performed with barge rigs. In
2003, 52 development wells and six exploratory wells were drilled in the area;
42 development and five exploratory wells were completed. At year-end 2003, we
had 82 proved undeveloped locations in this field. Our planned 2004 capital
expenditures in this area include drilling 25 to 30 development wells and two to
four exploratory wells.
Masters Creek Area. As of December 31, 2003, we owned drilling and
production rights in 62,560 net acres and 91,994 fee mineral acres in the
Masters Creek 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
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both oil and gas from the Austin Chalk formation. The reserves are approximately
71% oil and natural gas liquids. At year-end 2003, we had 12 proved undeveloped
locations in the area. Our planned 2004 capital expenditures in this area
include drilling one to two development wells.
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 identified as Garcia Ranch, which
straddles the border of Kenedy County and Willacy County in the southern tip of
Texas. Retaining a 65% working interest, we had three discoveries in the area in
2001 and 2002, one in the Rome prospect in Willacy County, one in the Siena
prospect in Kenedy County and one in the Milan prospect in Kenedy county. In
2003, we participated in completing one well in the Milan prospect with a 33%
working interest. Two exploratory wells drilled in this area during 2003 were
not successful. We plan to participate in drilling up to five wells in 2004 in
this area.
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
exploratory well in this area in 2004, contingent upon finding a working
interest partner.
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 another Woodbine prospect,
the Jaguar prospect, located in Polk County. The Jaguar prospect may be drilled
in 2004 if a working interest partner joins us for the project.
New Zealand Core Operating Areas
Our activity in New Zealand began in 1995. As of December 31, 2003, 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 (New Zealand) Exploration, Limited (Southern NZ),
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 sold
a 20% interest in the permit to a subsidiary of New Zealand Oil and Gas Limited.
The purchase and subsequent sale resulted 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.
In 2003 this well was re-entered but was unsuccessful.
As of December 31, 2003, our gross capitalized oil and gas property costs
in New Zealand totaled approximately $205.3 million. Approximately $169.5
million of our investment costs have been included in the proved properties
portion of our oil and gas properties, while $35.8 million is included as
unproved properties. Our functional currency in New Zealand is the U.S. Dollar.
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Natural gas prices are substantially lower in New Zealand as compared to
domestic prices, due largely to the predominant supply from the Maui Field under
long standing supply contracts. However, the Maui Field that in recent years has
supplied over 70% of the nation's natural gas appears to have reached its peak
sooner than anticipated, and its production is projected to decline sharply over
the next few years and has begun to put upward pressure on natural gas prices in
New Zealand.
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.
Kauri Area. During 2003, we completed three of four wells in the Kauri
area. Two of these wells successfully targeted the Kauri Sand, the third was
completed in the Manutahi Sand. We also fracture stimulated three Kauri Sand
wells in 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. 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 exceeded the contract minimum during all of
2003.
Solution gas gathered from the Waihapa Production Station ("WPS") flows to
the Tariki Ahuroa gas plant ("TAG"). The current processing capacity per day of
the WPS facility is up to 15,000 barrels of oil and 45 MMcf of natural gas.
Processing capacity tests conducted following facility modifications completed
in the third quarter of 2002 confirmed a 12% increase in the gas processing
capacity of the TAG plant up to the 45 MMcf per day level. 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"), under which SPM
purchases all of our New Zealand crude oil production, runs through the end of
2004. 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 for use at its Huntly Power Station, New Zealand's largest
thermal power station.
New Zealand Emerging Growth Areas
The Tawa prospect is located northwest of the Rimu and Kauri areas in
permit 38719. 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 our analysis of
existing three-dimensional seismic data plus two-dimensional seismic data
acquired during Swift surveys in 1997 and 2000. The Tawa
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prospect may also include a shallower prospect located on the southeast flank of
the Tawa prospect. It was identified based upon the analysis of the
two-dimensional seismic data we acquired in 2000.
Three prospects are located in the Company's TAWN area and are identified
as the Waihapa Deep prospect, the Toko Deep prospect, and the Ahuroa Flank
prospect. All three prospects will have the Kapuni group sands (the major
reservoir in the basin) as their main target, but as these wells are drilled
they will also pass through the Tariki sandstone and other major producers in
the basin.
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 through an existing pre-emptive right under the joint
operating agreement. Following the transaction, SENZ sold a 20% interest in the
permit to a subsidiary of New Zealand Oil and Gas Limited. The purchase and
subsequent sale resulted in SENZ holding a 50% working interest in this permit.
We are the operator of the permit. Permit 38718 contains the Tuihu #1
exploratory well, which was drilled in 2001 and was temporarily abandoned. In
2003, this well was re-entered but was unsuccessful.
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,
2003, 2002, and 2001. 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 conducted according to standards approved by the Board of Directors of the
Society of Petroleum Engineers, Inc. and included examination, on a test basis,
of the evidence supporting our reserves. Gruy's audit was based upon review of
production histories and other geological, economic, and engineering data
provided by Swift. Where Gruy had material disagreements with Swift reserve
estimates, we revised our estimates to be in agreement.
In accordance with Securities and Exchange Commission guidelines, estimates
of future net revenues from our proved reserves and the PV-10 Value are made
using oil and gas sales prices in effect as of the dates of such estimates
adjusted for the effects of hedging 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. Our hedges at year-end 2003 consisted of natural
gas price floors with strike prices lower than the period end price and thus did
not affect prices used in these calculations. Proved reserves as of December 31,
2003, were estimated based upon prices in effect at year-end. The weighted
averages of such year-end prices domestically were $5.53 per Mcf of natural gas,
$30.88 per barrel of oil, and $21.81 per barrel of NGL, compared to $4.23,
$29.36, and $17.30 at year-end 2002 and $2.68, $18.51, and $11.00 at year-end
2001, respectively. The weighted averages of such year-end 2003 prices for New
Zealand were $2.04 per Mcf of natural gas, $26.78 per barrel of oil, and $14.10
per barrel of NGL, compared to $1.48, $28.80, and $12.24 in 2002 and $1.18,
$18.25, and $8.90 in 2001, respectively. The weighted averages of such year-end
2003 prices for all our reserves, both domestically and in New Zealand, were
$4.56 per Mcf of natural gas, $30.16 per barrel of oil, and $20.61 per barrel of
NGL, compared to $3.49, $29.27, and $16.54 in 2002 and $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 its PV-10 Value. Operating costs,
development costs, asset retirement obligation 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, 2003
---------------------------------------------------------------
Total Domestic New Zealand
--------------------- ------------------ -------------------
Estimated Proved Oil and Gas Reserves
Net natural gas reserves (Mcf):
Proved developed 210,119,927 138,173,341 71,946,586
Proved undeveloped 125,684,935 104,147,935 21,537,000
--------------------- ------------------ -------------------
Total 335,804,862 242,321,276 93,483,586
===================== ================== ===================
Net oil and NGL reserves (Bbl):
Proved developed 45,525,366 38,767,983 6,757,383
Proved undeveloped 35,234,537 28,247,710 6,986,827
--------------------- ------------------ -------------------
Total 80,759,903 67,015,693 13,744,210
===================== ================== ===================
Estimated Present Value of Proved Reserves
Estimated present value of future net
cash flows from proved reserves discounted
at 10% annum:
Proved developed $ 940,882,612 $ 805,834,173 $ 135,048,439
Proved undeveloped 597,912,185 517,485,024 80,427,161
---------------------- ------------------ -------------------
Total $ 1,538,794,797 $ 1,323,319,197 $ 215,475,600
====================== ================== ===================
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
===================== ================== ===================
10
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
===================== ================== ===================
At year-end 2003, 59% of the proved reserves were developed reserves. At
year-end 2002, 60% of proved reserves were developed. At year-end 2001, 50% 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 2003
increased by 9% over reserves quantities a year earlier, while the PV-10 Value
of those reserves increased 33% from the PV-10 Value at year-end 2002. While our
total proved reserves quantities, on an equivalent Bcfe basis, at year-end 2002
increased by 16% over reserves quantities in 2001, the PV-10 Value of those
reserves increased 93% from the PV-10 Value at year-end 2001. The PV-10 Value
increases in 2003 and 2002 were heavily influenced by higher prices at year-end
2003 as compared to year-end 2002 and year-end 2002 as compared to year-end
2001. Product prices for natural gas increased 31% during 2003, from $3.49 per
Mcf at year-end 2002 to $4.56 at year-end 2003, while oil prices increased 3%
between the same two dates, from $29.27 to $30.16 per barrel. Product prices for
natural gas increased 39% during 2002, from $2.51 per Mcf at December 31, 2001,
to $3.49 per Mcf 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, matched by a 25% decrease in the price of oil between the
two dates, from $24.62 to $18.45 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 that voted
to do so, our total gross well count decreased from 2001 levels. 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, 2003:
Gross 397 560 957
Net 340.6 504.0 844.6
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
(1) Excludes 41 service wells in 2003, 35 service wells in 2002, and 48
service wells in 2001.
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, 2003:
Developed (1) Undeveloped (1)
Gross Net Gross Net
------------ ------------- ------------- ------------
Alabama 9,686.01 2,859.10 644.22 183.99
Louisiana 82,257.09 65,415.99 16,637.34 10,296.57
Mississippi 630.03 163.32 60.00 15.80
Texas 166,636.81 113,555.70 31,284.03 19,017.64
Wyoming 681.07 151.06 67,698.95 66,078.96
All other states 320.00 266.66 400.00 257.32
Offshore Louisiana 4,609.37 276.56 5,000.00 258.34
Offshore Texas 2,880.00 74.39 --- ---
------------ ------------- ------------- ------------
Total Domestic 267,700.38 182,762.78 121,724.54 96,108.62
New Zealand 7,600.00 7,181.70 162,422.37 124,766.10
------------ ------------- ------------- ------------
Total 275,300.38 189,944.48 284,146.91 220,874.72
============ ============= ============= ============
(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 69,149 undeveloped fee
mineral acres for a total of 95,494 fee mineral acres.
12
Drilling Activities
The following table sets forth the results of our drilling activities
during the three years ended December 31, 2003:
Gross Wells Net Wells
--------------------------------------- ------------------------------------
Temporarily Temporarily
Year Type of Well Total Producing Dry Abandoned Total Producing Dry Abandoned
- -------------------------------------------------------------------------- ------------------------------------
2003 Exploratory-Domestic 8 5 3 -- 7.3 5.0 2.3 --
Development-Domestic 63 53 10 -- 61.9 51.9 10.0 --
Exploratory-New Zealand 1 -- 1 -- 0.5 -- 0.5 --
Development-New Zealand 3 3 -- -- 3.0 3.0 -- --
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 --
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 --
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 2003 totaled $5.1 million and ranged from $450 to $2,107 per well
per month.
Marketing of Production
Domestically, we typically sell our oil and gas production at market prices
near the wellhead or at a central point after gathering and/or processing. 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.
Shell, both domestically and in New Zealand, and Contact Energy in New Zealand
each accounted for 10% or more of our total revenues during the year ended
December 31, 2003, with those purchasers accounting for approximately 26% of
revenues in the aggregate. For the year ended December 31, 2002, Eastex Crude
Company and Contact Energy in New Zealand accounted for approximately 28% 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
13
believe that these arrangements adequately provide for our gas transportation
and processing needs in the AWP Olmos area for the foreseeable future.
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 or barges 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 to Shell Petroleum Mining at
international 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 that was modified in 2003 and covers
approximately 7.2 Bcfe per year for a three year period. During 2003, additional
production volumes from our TAWN fields, over the contract maximum, were sold to
Contact Energy or Genesis Power Ltd. at prevailing market rates. The gas sales
above the contract maximum expired at the end of 2003.
Our New Zealand natural gas liquids production is sold to Rockgas Ltd.
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, 2003. "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,
------------------------------------------------------------------
2003 2002 2001
------------------ --------------------- -----------------
Net Sales Volume:
Oil (Bbls) (1) (3) 4,192,612 3,770,128 3,055,373
Gas (Mcf)(2) 28,002,719 27,131,578 26,458,958
Gas equivalents (Mcfe) 53,158,384 49,752,346 44,791,202
Average Sales Price:
Oil (Per Bbl) (1) (3) $ 27.47 $ 20.88 $ 22.64
Gas (Per Mcf) (2) $ 3.42 $ 2.30 $ 4.23
Average Production Cost (per Mcfe) $ 0.99 $ 0.83 $ 0.82
1 Oil production for 2003, 2002, and 2001 includes New Zealand production of
855,910 barrels at an average price per barrel of $24.26, 695,454 barrels at an
average price per barrel of $20.28, and 84,261 barrels at an average price per
barrel of $21.64, respectively.
2 Natural gas production for 2003 and 2002 includes New Zealand production of
14,258,679 Mcf with an average price of $1.83 per Mcf, and 11,351,518 Mcf with
an average price of $1.32 per Mcf.
3 In the table above, for 2003 and 2002, natural gas liquids have been combined
with oil and condensate for reporting purposes. The natural gas liquids
production for 2003 was 823,214 barrels at an average price of $17.60 per barrel
and for 2002 was 1,173,504 barrels at an average price of $12.82 per barrel.
14
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, and fires, each of which could result
in severe damage to or destruction of oil and gas wells, production facilities
or other property, or individual injuries. The oil and gas exploration business
is also subject to environmental hazards, such as oil spills, gas leaks, and
ruptures and discharges of toxic substances or gases that could expose us to
substantial liability due to pollution and other environmental damage.
Additionally, as managing general partner of six limited partnerships, we are
solely responsible for the day-to-day conduct of those 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 if a significant accident, or other event occurs that is uninsured or not
fully covered by insurance, it could adversely affect us.
Commodity Risk
The oil and gas industry is affected by the volatility of commodity prices.
Realized commodity prices received for such production are primarily driven by
the prevailing worldwide price for crude oil and spot prices applicable to
natural gas. Our price-risk management program permits the utilization of
agreements and financial instruments (such as futures, forward and options
contracts, and swaps) to mitigate price risk associated with fluctuations in oil
and natural gas prices.
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 subject to
various federal, state and local environmental, health and safety laws and
regulations. These regulatory requirements continue to change and increase in
both number and complexity. We believe that we are in substantial compliance
with current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse impact on
us. The future annual capital costs of complying with the environmental
regulations applicable to our operations is uncertain and will be governed by
several factors, include future changes to regulatory requirements.
Both our domestic and our New Zealand operations are subject to 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. In addition, 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 U.S. federal government and are
affected by the availability, terms and cost of transportation. In particular,
the price and terms of access to pipeline transportation are subject to
extensive U.S. federal and state regulation. The Federal Energy Regulatory
Commission ("FERC") is continually proposing and implementing new rules and
regulations affecting the natural gas industry. The stated purpose of many of
these regulatory changes is to promote competition among the various sectors of
the natural gas industry. The ultimate impact of the complex rules and
regulations issued by FERC cannot be predicted. Some of FERC's more recent
proposals may, however, adversely affect the availability and reliability of
interruptible
15
transportation service on interstate pipelines. While our sales of crude oil,
condensate and natural gas liquids are not currently subject to FERC regulation
our ability to transport and sell such products is dependent on certain
pipelines whose rates, terms and conditions of service are subject to FERC
regulation.
Our domestic production of oil and gas is also 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 that may be produced by assigning allowable rates of production to each
well or proration unit. Likewise, the government of New Zealand regulates the
exploration, production, sales and transportation of oil and natural gas.
Federal Leases
Some of our domestic properties are located on federal oil and gas leases
administered by various federal agencies, including the Bureau of Land
Management. Various regulations and administrative orders affect the terms of
leases, and in turn may affect our exploration and development plans, methods of
operation, and related matters.
Employees
At December 31, 2003, we employed 241 persons. Of these employees, 58 were
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 $164,000 per month. In New Zealand we
lease approximately 16,000 square feet of office space, under leases expiring in
2009. These New Zealand leases require payments of approximately $13,000 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 that we formed and for which we 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. Of the 109 partnerships, 21 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 2003, we
continued to serve as managing general partner for six remaining partnerships,
all of which are drilling partnerships that have been in existence from five to
seven 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.
FASB -- The Financial Accounting Standards Board.
Gigajoules -- A unit of energy equivalent to .95 Mcf of 1,000 Btu of natural
gas.
Gross Acre -- An acre in which a working interest is owned. The number of gross
acres is the total number of acres in which a working interest is owned.
Gross Well -- A well in which a working interest is owned. The number of gross
wells is the total number of wells in which a working interest is owned.
MBbl -- Thousand barrels of oil.
Mcf -- Thousand cubic feet of natural gas.
Mcfe -- Thousand cubic feet of natural gas equivalent, which is determined using
the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf of
natural gas.
MMBbl -- Million barrels of oil.
MMBtu -- Million British thermal units, which is a heating equivalent measure
for natural gas and is an alternate measure of natural gas reserves, as
opposed to Mcf, which is strictly a measure of natural gas volumes. Typically,
prices quoted for natural gas are designated as price per MMBtu, the same
basis on which natural gas is contracted for sale.
MMcf -- Million cubic feet of natural gas.
MMcfe -- Million cubic feet of natural gas equivalent (see Mcfe).
Net Acre -- A net acre is deemed to exist when the sum of fractional working
interests owned in gross acres equals one. The number of net acres is the sum
of fractional working interests owned in gross acres expressed as whole
numbers and fractions thereof.
Net Well -- A net well is deemed to exist when the sum of fractional working
interests owned in gross wells equals one. The number of net wells is the sum
of fractional working interests owned in gross wells expressed as whole
numbers and fractions thereof.
17
NGL--Natural gas liquid.
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.
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 2003 to a vote of
security holders.
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters
COMMON STOCK, 2002 AND 2003
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 2002 and 2003 were as follows:
2002 2003
------------------------------------- -----------------------------------
First Second Third Fourth First Second Third Fourth
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
------------------------------------- -----------------------------------
Low $15.55 $13.44 $10.40 $6.80 $8.51 $7.60 $10.64 $13.57
High $20.58 $20.53 $15.23 $10.54 $9.76 $12.14 $14.57 $18.00
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 348 stockholders of record as of December 31, 2003.
19
Item 6. Selected Financial Data
2003 2002 2001 2000 1999
Revenues
Oil and Gas Sales $211,032,639 $141,195,713 $181,184,635 $189,138,947 $108,898,696
Fees from affiliated limited partnerships (1) $28,068 $67,173 $427,583 $331,497 $229,749
Interest Income $184,383 $263,738 $49,281 $1,339,386 $833,204
Other, Net $(2,344,107) $8,443,187 $2,145,991 $815,116 $709,358
Total Revenues $208,900,983 $149,969,811 $183,807,490 $191,624,946 $110,671,007
Income (Loss) Before Income Taxes and
Change in Accounting Principle (2) $50,739,178 $18,408,289 ($34,192,333) 92,449,488 $29,736,151
Net Income (Loss) $29,893,812 $11,923,227 ($22,347,765) $59,184,008 $19,286,574
Net Cash Provided by Operating Activities $110,827,279 $71,626,314 $139,884,255 $128,197,227 $73,603,426
Per Share Data
Weighted Average Shares Outstanding(2) 27,357,579 26,382,906 24,732,099 21,244,684 18,050,106
Earnings (Loss) per Share--Basic(2) $1.09 $0.45 ($0.90) $2.79 $1.07
Earnings (Loss) per Share--Diluted(2) $1.08 $0.45 ($0.90) $2.51 $1.07
Shares Outstanding at Year-End 27,484,091 27,201,509 24,795,564 24,608,344 20,823,729
Book Value per Share $14.46 $13.42 $12.61 $13.50 $8.18
Market Price(2)
High $18.00 $20.58 $37.70 $43.50 $13.31
Low $7.60 $6.80 $16.66 $9.75 $5.69
Year-End Close $16.85 $9.67 $20.20 $37.63 $11.50
Pro forma amounts assuming 1994 change in
Accounting principle is applied retroactively(1)
Net Income (Loss) --- --- --- --- ---
Earnings (Loss) per Share--Basic (2) --- --- --- --- ---
Earnings (Loss) per Share--Diluted (2) --- --- --- --- ---
Assets
Current Assets $34,673,672 $29,768,199 $36,752,980 $41,872,879 $50,605,488
Oil and Gas Properties, Net of Accumulated
Depreciation, Depletion, and Amortization $816,459,776 $721,617,941 $628,304,060 $524,052,828 $392,986,589
Total Assets $861,054,932 $767,005,859 $671,684,833 $572,387,001 $454,299,414
Liabilities
Current Liabilities $69,772,730 $46,884,184 $73,245,335 $64,324,771 $34,070,085
Long-Term Debt $340,254,783 $324,271,973 $258,197,128 $134,729,485 $239,068,423
Total Liabilities $463,663,668 $401,932,675 $359,032,113 $240,232,846 $283,895,297
Stockholders' Equity $397,391,264 $365,073,184 $312,652,720 $332,154,155 $170,404,117
Number of Employees 241 234 209 181 173
Producing Wells
Swift Operated 870 820 854 817 769
Outside Operated 128 112 381 711 788
Total Producing Wells 998 932 1,235 1,528 1,557
Wells Drilled (Gross) 75 36 53 70 27
Proved Reserves
Natural Gas (Mcf) 335,804,862 326,731,672 324,912,125 418,613,976 329,959,750
Oil, NGL, & Condensate (barrels) 80,759,903 70,438,963 53,482,636 35,133,596 20,806,263
Total Proved Reserves (Mcf equivalent) 820,364,284 749,365,449 645,807,939 629,415,552 454,797,327
Production (Mcf equivalent)(3) 53,158,384 49,752,346 44,791,202 42,356,705 42,874,303
Average Sales Price
Natural Gas (per Mcf) $3.42 $2.30 $4.23 $4.24 $2.40
Oil (per barrel) $27.47 $20.88 $22.64 $29.35 $16.75
1 As of January 1, 1994, we changed our revenue recognition policy for earned
interests. Accordingly, in 1994 to 2003, "Fees from affiliated limited
partnerships" does not include earned interests revenues.
2 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; (b) the
adoption in 1998 of Statement of Financial Accounting Standards No. 128,
"Earnings per Share," and (c) the adoption in 2003 of Statement of Financial
Accounting Standards No. 145, "Rescission of FASB Statements No. 4, 44, and 64,
Amendment of FASB Statement No. 13, and Technical Corrections," which affected
our presentation of 1999 results by reclassifying the loss on early
extinguishment of debt from an extraordinary item to an operating item.
3 Natural gas production fr 1993, 1994, 1995, 1996, 1997, 1998, 1999, and 2000
includes 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
1998 1997 1996 1995 1994 1993
$80,067,837 $69,015,189 $52,770,672 $22,527,892 $19,802,188 $15,535,671
$333,940 $745,856 $937,238 $590,441 $701,528 $4,071,970
$107,374 $2,395,406 $433,352 $212,329 $47,980 $201,584
$1,960,070 $2,555,729 $2,156,764 $1,761,568 $1,072,535 $604,599
$82,469,221 $74,712,180 $56,298,026 $25,092,230 $21,624,231 $20,413,824
($73,391,581) $33,129,606 $28,785,783 $6,894,537 $4,837,829 $6,628,608
($48,225,204) $22,310,189 $19,025,450 $4,912,512 ($13,047,027) $4,896,253
$54,249,017 $55,255,965 $37,102,578 $14,376,463 $10,394,514 $7,238,340
16,436,972 16,492,856 15,000,901 10,035,143 7,308,673 7,246,884
($2.93) $1.35 $1.27 $0.49 ($1.79) $0.68
($2.93) $1.26 $1.25 $0.49 ($1.79) $0.64
16,291,242 16,459,156 15,176,417 12,509,700 6,685,137 6,001,075
$6.71 $9.69 $9.41 $7.46 $6.30 $9.08
$21.00 $34.20 $28.86 $11.48 $10.35 $11.57
$6.94 $16.93 $9.89 $7.05 $7.75 $7.14
$7.38 $21.06 $27.16 $10.91 $8.86 $7.85
--- --- --- --- $3,725,671 $4,322,478
--- --- --- --- $0.51 $0.60
--- --- --- --- $0.51 $0.57
$35,246,431 $29,981,786 $101,619,478 $43,380,454 $39,208,418 $65,307,120
$356,711,711 $301,312,847 $200,010,375 $125,217,872 $88,415,612 $89,656,577
$403,645,267 $339,115,390 $310,375,264 $175,252,707 $135,672,743 $160,892,917
$31,415,054 $28,517,664 $32,915,616 $40,133,269 $52,345,859 $55,565,437
$261,200,000 $122,915,000 $115,000,000 $28,750,000 $28,750,000 $28,750,000
$294,282,628 $179,714,470 $167,613,654 $81,906,742 $93,545,612 $106,427,203
$109,362,639 $159,400,920 $142,761,610 $93,345,965 $42,127,131 $54,465,714
203 194 191 176 209 188
836 650 842 767 750 795
917 917 986 3,316 3,422 3,407
1,753 1,567 1,828 4,083 4,172 4,202
75 182 153 76 44 34
352,400,835 314,305,669 225,758,201 143,567,520 76,263,964 64,462,805
13,957,925 7,858,918 5,484,309 5,421,981 4,553,237 4,271,069
436,148,385 361,459,177 258,664,055 176,099,406 103,583,566 90,089,219
39,030,030 25,393,744 19,437,114 11,186,573 9,600,867 7,368,757
$2.08 $2.68 $2.57 $1.77 $1.93 $1.96
$11.86 $17.59 $19.82 $15.66 $14.35 $15.10
21
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations
The following discussion and analysis supplements and is provided to
facilitate increased understanding of our 2003, 2002 and 2001 consolidated
financial statements and our accompanying notes included with this report.
Overview
For 2003, Swift Energy experienced record revenues of $209 million and
record production of 53.2 Bcfe. Our revenues were bolstered by oil and gas
prices remaining strong last year. Although 2003 domestic production decreased
by 1% to 33.8 Bcfe from 2002 levels we continued to focus our efforts and
capital throughout the year on better infrastructure, increased production and
the development of longer life oil reserves in the Lake Washington area. In
January 2004, we produced more than approximately 12,000 gross barrels of oil
equivalent per day (approximately 10,000 net barrels of oil equivalent per day)
in Lake Washington, compared to approximately 5,000 gross barrels of oil
equivalent per day (approximately 4,100 net barrels of oil equivalent per day)
in January 2003. During 2003, we also began allocating capital to natural gas
development in our three other domestic core areas. New Zealand accounted for
19.4 Bcfe of 2003 production, a 25% increase from 2002 levels. New Zealand
natural gas and NGL contracts are denominated in New Zealand Dollars, which have
significantly strengthened during 2003 against the U.S. Dollar. The currency
exchange rate increased from approximately $0.52 to approximately $0.66 U.S. per
$1.00 New Zealand during the year.
Our production costs were up in 2003 predominately due to some of the
facility enhancement costs and increased activity and production in Lake
Washington, increased severance taxes, and also due to currency exchange rates
in New Zealand. Our average reserve replacement cost for 2003 was $1.17 per
Mcfe, and we replaced 234% of our 2003 production. Our general and
administrative expenses increased in 2003 predominantly due to our increased
activities in New Zealand, a reduction in reimbursement from partnerships we
managed, an increase in franchise tax expense, and increased costs related to
our corporate governance activities and compliance with the Sarbanes-Oxley Act.
We are working to reduce our production costs for 2004.
We again made significant strides in 2003 in improving the quality and
quantity of our reserve base in accordance with our strategic plan. Year-end
2003 proved reserves of 820.4 Bcfe, representing 9.5% growth for the year, were
47% crude oil, 41% natural gas and 12% NGLs, compared to year-end 2002 proved
reserves of 749.4 Bcfe, which were 42% crude oil, 44% natural gas and 14% NGLs.
Proved developed reserves remained essentially the same at 59% of total reserves
at year-end 2003, compared to 60% the previous year. Domestic proved reserves
increased at year-end 2003 to 644.4 Bcfe, driven mainly by the reserve increase
in the Lake Washington Field. Proved reserves in New Zealand increased to 176.0
Bcfe at year-end 2003, primarily attributable to drilling additions in the Kauri
and Manutahi Sands. For 2003, our proved undeveloped reserves, 41% of total
reserves, were slightly higher than the 30% to 40% range we had targeted. Most
of these proved undeveloped reserves were in the Lake Washington area (13% of
total reserves) and in the AWP Olmos area (9% of total reserves), and both areas
are characterized as long reserve life fields. The 30% to 40% range is again our
target for 2004 as we work to convert proved undeveloped reserves into proved
producing reserves.
Our debt to PV-10 ratio has decreased from 43% in 2001 to 28% in 2002, and
further decreased to 22% for 2003. Our debt to capitalization ratio was 46% at
December 31, 2003, which is essentially the same as at year-end 2002, and 2001.
Management continues to believe that our current cash flow is best utilized on
capital projects rather than reducing debt. However, we will continue to look
for opportunities in 2004 to improve our balance sheet and liquidity but expect
our capital expenditures to continue to equal or modestly exceed our cash flow
for the near term.
Our 2004 capital expenditure budget assumes increased drilling activity in
all domestic core areas except Lake Washington. For Lake Washington, the 2004
budget assumes reduced drilling activity, 25 to 30 wells, accompanied by an
extensive three-dimensional seismic survey, together with the analysis of the
resulting data, to enhance our drilling program in the area for years to come.
We plan to drill 15 to 18 wells in AWP Olmos, with the objective of again
maintaining production levels in that area. Additionally, we expect to have
ongoing exploratory efforts in our South Texas Garcia Ranch properties. In New
Zealand, we plan to drill 8 to 12 wells, primarily in the areas in which we had
success in 2003. We continue to see a tightening natural gas
22
market with strengthening gas prices in New Zealand. For 2004, we believe we are
positioned for production growth of 11% to 17% and reserve growth of 5% to 8%,
and expect commodity prices to remain strong.
Results of Operations
Revenues. Our revenues in 2003 increased by 39% compared to revenues in
2002, due primarily to increases in oil and gas prices and production from our
New Zealand and Lake Washington areas. Revenues in 2002 decreased by 18%
compared to 2001 revenues primarily due to the drop in domestic natural gas
prices in 2002. Revenues from our oil and gas sales comprised substantially all
of net revenues for 2003, 94% of total revenues for 2002, and 99% for 2001.
Natural gas production made up 53% of our production volumes in 2003, 55% in
2002, and 59% in 2001. Domestic natural gas production made up 49% of our total
natural gas production volumes in 2003, 58% in 2002, and 100% in 2001.
Oil and gas sales in 2003 increased by 49%, or $69.8 million, from the
level of those revenues for 2002, and our net sales volumes in 2003 increased by
7%, or 3.4 Bcfe, over net sales volumes in 2002. Average prices received for oil
increased to $29.89 per Bbl in 2003 from $24.52 per Bbl in 2002. Average gas
prices received increased to $3.42 per Mcf in 2003 from $2.30 per Mcf in 2002.
Average NGL prices received increased to $17.60 per Bbl in 2003 from $12.82 per
Bbl in 2002. The increase in production during the 2003 period was primarily
from our New Zealand and Lake Washington areas.
In 2003, our $69.8 million increase in oil, NGL, and gas sales resulted
from:
oPrice variances that had a $59.0 million favorable impact on sales, of
which $31.4 million was attributable to the 49% increase in average gas
prices received and $27.6 million was attributable to the 32% increase in
average combined oil and NGL prices received; and
oVolume variances that had a $10.8 million favorable impact on sales, with
$8.8 million of increases coming from the 422,000 Bbl increase in oil and
NGL sales volumes, and $2.0 million of the increases from the 0.9 Bcf
increase in gas sales volumes.
In 2002, oil and gas sales decreased by 22%, or $40.0 million, from the
level of those revenues in 2001 even though our net sales volumes in 2002
increased by 11%, or 5.0 Bcfe, over net sales volumes in 2001. Average combined
prices received for oil and NGLs 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
was primarily from our New Zealand and Lake Washington areas.
In 2002, our $40.0 million decrease in oil, NGL, 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 combined
oil and NGL 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 and
NGL sales volumes, and $2.8 million of the increases from the 0.7 Bcf
increase in gas sales volumes.
23
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 two New Zealand core areas:
Oil and Gas Sales Net Oil and Gas Sales
(In millions) Volume (Bcfe)
--------------------------------- ------------------------------
Area 2003 2002 2003 2002
------------------------- --------------- -------------- ------------ --------------
AWP Olmos $43.7 $33.1 8.4 10.9
Brookeland 16.4 11.9 3.9 4.1
Lake Washington 59.5 18.5 12.1 4.4
Masters Creek 25.7 32.3 5.7 9.7
Other 18.9 16.3 3.7 5.2
--------------- -------------- ------------ --------------
Total Domestic $164.2 $112.1 33.8 34.3
Rimu/Kauri 11.6 4.0 3.3 1.5
TAWN 35.2 25.1 16.1 14.0
--------------- -------------- ------------ --------------
Total New Zealand $46.8 $29.1 19.4 15.5
--------------- -------------- ------------ --------------
Total $211.0 $141.2 53.2 49.8
=============== ============== ============ ==============
The following table provides additional information regarding our quarterly
oil and gas sales:
Net Oil and Gas Sales Volume Average Sales Price
----------------------------------------------- ----------------------------
Oil and NGLs Gas Combined Oil and NGLs Gas
(MBbl) (Bcf) (Bcfe) (Bbl) (Mcf)
-------------- ----------- ------------- --------------- ---------
2001:
First 603 6.7 10.3 $27.63 $6.86
Second 691 7.1 11.3 $26.05 $4.66
Third 813 6.8 11.7 $23.76 $2.94
Fourth 948 5.9 11.5 $16.02 $2.21
-------------- ----------- -------------
3,055 26.5 44.8 $22.64 $4.23
============== =========== =============
2002:
First 944 6.6 12.3 $16.10 $1.72
Second 1,002 6.7 12.7 $20.98 $2.60
Third 908 6.7 12.2 $23.05 $2.32
Fourth 916 7.1 12.6 $23.55 $2.55
-------------- ----------- -------------
3,770 27.1 49.8 $20.88 $2.30
============== =========== =============
2003:
First 864 7.6 12.9 $30.55 $3.71
Second 1,033 7.1 13.3 $25.48 $3.47
Third 1,164 6.7 13.6 $26.60 $3.17
Fourth 1,132 6.6 13.4 $27.84 $3.29
-------------- ----------- -------------
4,193 28.0 53.2 $27.47 $3.42
============== =========== =============
In the table above, for 2002 and 2003, natural gas liquids have been
combined with oil for reporting purposes. Natural gas liquids production for
2002 was 1,174 MBbls, at an average price of $12.82 per barrel; and for 2003,
was 823 MBbls, at an average price of $17.60 per barrel.
Costs and Expenses. Our expenses in 2003 increased $26.6 million, or 20%,
compared to 2002 expenses. The majority of the increase was due to the $11.4
million increase in oil and gas production costs and the $6.8 million increase
in depreciation, depletion and amortization, both of which increased as our
production volumes increased in 2003. Our expenses in 2002 decreased by $86.4
million, or 40%, compared to 2001 expenses. This decrease was due primarily to
the $98.9 million non-cash write-down of domestic oil and gas properties in
2001.
As discussed in Note 1 to the Consolidated Financial Statements, we adopted
SFAS No. 143 on January 1, 2003. Our adoption of SFAS No. 143 resulted in a
one-time net of taxes charge of $4.4 million, which is recorded as a "Cumulative
Effect of Change in Accounting Principle" in the 2003 consolidated statement of
income. We adopted SFAS No. 133, amended by SFAS No. 137 and SFAS No. 138, on
January 1, 2001. Our
24
adoption of SFAS No. 133 resulted in a one-time net of taxes charge of $0.4
million, which is recorded as a "Cumulative Effect of Change in Accounting
Principle" in the 2001 consolidated statement of income.
Our 2003 general and administrative expenses, net increased $3.5 million,
or 33%, from the level of such expenses in 2002, while 2002 general and
administrative expenses increased $2.4 million, or 29%, over 2001 levels. These
increases in 2002 and 2003 are due primarily to our increased activities in New
Zealand and a reduction in reimbursement from partnerships we managed as almost
all of these partnerships have liquidated. In addition, our 2003 expense
increased due to an increase in franchise tax expense and increased costs
related to our corporate governance activities and compliance with the
Sarbanes-Oxley Act. Our general and administrative expenses per Mcfe produced
increased to $0.27 per Mcfe in 2003 from $0.21 per Mcfe in 2002 and $0.18 per
Mcfe in 2001. The portion of supervision fees recorded as a reduction to general
and administrative expenses was $3.6 million for 2003, $3.2 million for 2002,
and $3.5 million for 2001.
Depreciation, depletion, and amortization of our oil and gas properties, or
DD&A, increased $6.8 million, or 12%, in 2003 from 2002 levels, while 2002 DD&A
decreased $3.3 million, or 6%, from 2001 levels. Domestically, DD&A increased
$1.0 million in 2003 due to increases in the depletable oil and gas property
base, offset by slightly lower production in the 2003 period and higher reserve
volumes that were added primarily through our Lake Washington activities. In New
Zealand, DD&A increased by $5.8 million in 2003 due to increased production in
the 2003 period. In 2002, our domestic DD&A decreased by $15.6 million due to
lower production in the 2002 period and the domestic non-cash write-down of oil
and gas properties in the fourth quarter of 2001 that decreased our depletable
base, along with higher reserve volumes that were added primarily through our
Lake Washington activities. In New Zealand, our 2002 DD&A increased $12.3
million as our production and the depletable oil and gas property base both
increased in the 2002 period due primarily to the TAWN acquisition. Our DD&A
rate per Mcfe of production was $1.19 in 2003, $1.13 in 2002, and $1.33 in 2001,
reflecting variations in per unit cost of reserves additions.
We recorded $0.9 million of accretion on our asset retirement obligation in
2003 associated with the adoption of SFAS No. 143 implemented on January 1,
2003.
Our production costs per Mcfe produced were $0.99 in 2003, $0.83 in 2002,
and $0.82 in 2001. The portion of supervision fees recorded as a reduction to
production costs was $1.5 million for 2003, $2.1 million for 2002, and $3.3
million for 2001. Our production costs in 2003 increased $11.4 million, or 27%,
over such expenses in 2002, while those expenses in 2002 increased $4.8 million,
or 13%, over such expenses in 2001. Approximately $6.2 million of the increase
in production costs during 2003 was related to domestic severance taxes, which
increased along with commodity prices and higher production from our Lake
Washington area in that period. In New Zealand, production costs increased by
$5.2 million in 2003 mainly due to royalty payments made on higher production in
the period. In 2002 production costs increased as our New Zealand activities
increased, partially offsetting the domestic production costs decrease, which
mainly was due to a decrease in production volumes.
Interest expense on our Senior Notes issued in April 2002, including
amortization of debt issuance costs, totaled $19.1 million in 2003 and $13.5
million in 2002. Interest expense on our Senior Notes issued in July 1999,
including amortization of debt issuance costs, totaled $13.2 million in both
2003 and 2002 and $13.1 million in 2001. Interest expense on the credit
facility, including commitment fees and amortization of debt issuance costs,
totaled $1.6 million in 2003, $3.6 million in 2002, and $5.8 million in 2001.
Other interest cost was $0.3 million in 2003. The total interest cost in 2003
was $34.2 million, of which $6.9 million was capitalized. The total interest
cost in 2002 was $30.3 million, of which $7.0 million was capitalized. The 2001
total interest cost was $18.9 million, of which $6.3 million was capitalized. We
capitalize that portion of interest related to unproved properties. The increase
in interest expense in 2003 and 2002 was attributed to the replacement of our
bank borrowings in April 2002 with the Senior Notes issued in 2002 that carry a
higher interest rate.
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.
25
Income tax expense in 2003 includes a reduction of approximately $1.3
million from the U.S. statutory rate, primarily from the result of the currency
exchange rate effect on the New Zealand deferred tax. This amount is partially
offset by higher deferred state taxes and other items.
Net Income (Loss). Our net income in 2003 of $29.9 million was 151% higher
and basic earnings per share ("Basic EPS") of $1.09 were 142% higher than our
2002 net income of $11.9 million and Basic EPS of $0.45. Our earnings per
diluted share ("Diluted EPS") in 2003 of $1.08 were 140% higher than our 2002
Diluted EPS of $0.45. These amounts increased in the 2003 period as oil and gas
sales increased due to higher commodity prices and increased production.
Our net income in 2002 of $11.9 million was 153% higher and Basic EPS of
$0.45 was 150% higher than our 2001 net loss of $(22.3) million and Basic EPS of
$(0.90). Our Diluted EPS in 2002 of $0.45 was 150% higher than our 2001 Diluted
EPS of $(0.90). These amounts increased in 2002 due to overall lower costs, as a
non-cash write-down of oil and gas properties occurred in 2001 and not in 2002,
offset somewhat by lower revenue in 2002 due to lower commodity prices.
Proved Oil and Gas Reserves. At year-end 2003, our total proved reserves
were 820.4 Bcfe with a PV-10 Value of $1.5 billion. In 2003, our proved natural
gas reserves increased 9.1 Bcf, or 3%, while our proved oil reserves increased
10.3 MMBbl, or 15%, for a total equivalent increase of 71.0 Bcfe, or 9%. In
2002, our proved natural gas reserves increased by 1.8 Bcf, or 1%, while our
proved oil reserves increased by 17.0 MMBbl, or 32%, for a total equivalent
increase of 103.6 Bcfe, or 16%. We added reserves over the past three years
through both our drilling activity and purchases of minerals in place. Through
drilling we added 105.6 Bcfe (36.1 Bcfe of which came from New Zealand) of
proved reserves in 2003, 83.9 Bcfe (15.9 Bcfe of which came from New Zealand) in
2002, and 105.8 Bcfe (17.4 Bcfe of which came from New Zealand) in 2001. Through
acquisitions we added 0.5 Bcfe of proved reserves in 2003, 74.2 Bcfe in 2002,
and 54.6 Bcfe in 2001. At year-end 2003, 59% of our total proved reserves were
proved developed, compared with 60% at year-end 2002 and 50% at year-end 2001.
The PV-10 Value of our total proved reserves increased 33% from the PV-10
Value at year-end 2002. Gas prices increased in 2003 to $4.56 per Mcf from $3.49
per Mcf at year-end 2002, compared to $2.51 per Mcf at year-end 2001. Oil prices
increased in 2003 to $30.16 per barrel from $29.27 per Bbl at year-end 2002,
compared to $18.45 in 2001. 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.
26
Contractual Commitments and Obligations
Our contractual commitments for the next five years and thereafter as of
December 31, 2003 are as follows:
2004 2005 2006 2007 2008 Thereafter Total
--------------------------------------------------------------------------------------
Non-cancelable operating lease commitments $2,143,447 $492,613 $159,065 $156,649 $125,132 $13,500 $3,090,406
Capital commitments due to pipeline 96,244 --- --- --- --- --- 96,244
operators
Asset Retirement Obligation (1) 1,703,549 2,603,866 --- 129,478 74,286 5,626,294 10,137,473
Drilling Rig and Seismic Commitments 5,919,000 --- --- --- --- --- 5,919,000
Senior Notes due 2009 (2) --- --- --- --- --- 125,000,000 125,000,000
Senior Notes due 2012 (2) --- --- --- --- --- 200,000,000 200,000,000
Credit Facility which expires in October --- 15,900,000 --- --- --- --- 15,900,000
2005 (3)
--------------------------------------------------------------------------------------
$9,862,240 $18,996,479 $159,065 $286,127 $199,418 $330,639,794 $360,143,123
======================================================================================
1 Amounts shown by year are the fair values at December 31, 2003.
2 These amounts do not include the interest obligation, which is paid
semiannually.
3 These amounts exclude a $0.8 million standby letter of credit outstanding
under this facility.
Commodity Price Trends and Uncertainties
Oil and natural gas prices historically have been volatile and are expected
to continue to be volatile in the future. Worldwide supply disruptions, such as
the reduction in crude oil production from Venezuela, together with perceived
risks associated with the unrest in Iraq, along with other factors, have caused
the price of oil to increase significantly in 2003 when compared to historical
prices. Other factors such as actions taken by OPEC, worldwide economic
conditions, weather conditions, and fluctuating currency exchange rates can
cause wide fluctuations in the price of oil. Domestic natural gas prices
increased significantly in the first quarter of 2003 when compared to historical
prices and have since declined somewhat. 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 significant fluctuations in the price of natural gas. Such factors are
beyond our control.
Liquidity and Capital Resources
During 2003, we largely relied upon cash provided by operating activities
of $110.8 million, proceeds from bank borrowings of $15.9 million, and proceeds
from the sale of property and equipment of $10.2 million to fund capital
expenditures of $144.5 million. 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. For 2004, we believe
that our credit facility and cash flow will be sufficient to fund our planned
capital expenditures.
Net Cash Provided by Operating Activities. In 2003, net cash provided by
our operating activities increased by 55% to $110.8 million, as compared to
$71.6 million in 2002 and $139.9 million in 2001. The 2003 increase of $39.2
million was primarily due to an increase of oil and gas sales of $69.8 million
due to higher commodity prices and production. 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 higher debt balances and interest rates in 2002.
Existing Credit Facilities. At December 31, 2003, we had $15.9 million in
outstanding borrowings under our credit facility. At December 31, 2002, we had
no outstanding borrowings under this facility. Our credit facility at year-end
2003 consisted of a $300.0 million revolving line of credit with a $250.0
million borrowing base. The borrowing base is re-determined at least every six
months and was reconfirmed by our bank group and increased to $250.0 million,
effective November 1, 2003. We requested that the commitment amount with our
bank group be reduced to $150.0 million effective May 9, 2003. Under the terms
of the credit facility, we
27
can increase this commitment amount back to the total amount of the borrowing
base at our discretion, subject to the terms of the credit agreement. 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.
Our $125.0 million Senior Notes mature on August 1, 2009 and are callable August
1, 2004. Our $200.0 million Senior Notes mature on May 1, 2012. The indentures
underlying our Senior Notes contain covenants that impose restrictions on us.
Under the indentures, we are limited to the amount of debt that we can incur
such that in general, after giving pro forma effect to such new debt, the
consolidated interest coverage ratio would not exceed 2.5 to 1.0, or our
indebtedness under our bank credit facility does not exceed the greater of
$250.0 million or $150.0 million plus 25% of adjusted consolidated net tangible
assets as defined under the indentures. The aggregate amount of our common stock
that we can repurchase is limited to $5.0 million under the indenture governing
our Senior Notes due 2012 and $2.0 million under the indenture governing our
Senior Notes due 2009. We believe that these restrictions will not have any
material effect upon our business for the foreseeable future.
In January 2004, we filed a universal shelf registration statement with the SEC
to allow us to offer up to $350 million of our securities in the future. Upon
effectiveness of the registration statement, for a period of two years we may
periodically offer one or more of these securities in amounts, prices and on
terms to be announced when and if the securities are offered. The specifics of
any future offerings, along with the use of proceeds of any securities offered,
will be described in detail in a prospectus supplement at the time of any such
offering.
Working Capital. Our working capital declined from a negative $17.1 million at
December 31, 2002, to a negative $35.1 million at December 31, 2003. The
decrease was primarily due to an increase in accounts payable and accrued
liabilities due to our year-end 2003 drilling activities. Consistent with prior
years, we can draw on our available credit facility to remedy our working
capital deficit if needed.
Capital Expenditures. In 2003, our capital expenditures of approximately $144.5
million included:
Domestic activities of $114.4 million, or 79% of total expenditures, as follows:
o$57.0 million, or 39%, on developmental drilling, primarily in our Lake
Washington area;
o$25.9 million, or 18%, for the construction of production and surface
facilities, mainly in our Lake Washington area;
o$11.9 million, or 8%, on exploratory drilling, primarily in our Lake
Washington area;
o$11.4 million, or 8%, on domestic prospect costs, principally leasehold,
seismic, and geological costs;
o$4.4 million, or 3%, on field compression facilities;
o$2.0 million, or 1%, for producing property acquisitions, including the
purchase of property interests from partnerships managed by us;
o$0.9 million, or less than 1%, for fixed assets; and
o$0.9 million, or less than 1%, on gas processing plants in the Brookeland
and Masters Creek areas.
New Zealand activities of $30.1 million, or 21% of total expenditures, as
follows:
o$15.1 million, or 10%, on developmental activities primarily to further
delineate the Rimu and Kauri areas;
o$6.4 million, or 4%, on prospect costs;
o$5.7 million, or 4%, on gas processing plants;
o$2.3 million, or 2%, for exploratory drilling mainly for the Tuihu
exploratory well;
o$0.3 million, or less than 1%, on producing properties acquisitions; and
o$0.3 million, or less than 1%, for fixed assets.
In 2003, we participated in drilling 63 domestic development wells and
eight domestic exploratory wells, of which 53 development wells and five
exploratory wells were completed. In New Zealand we drilled three development
wells and one exploratory well. Only one of these four wells, the exploratory
well, was unsuccessful.
We currently plan to spend $130 to $150 million in total capital
expenditures in 2004, excluding acquisition costs and net of approximately $5
million to $15 million in non-core property dispositions. The budget for 2004,
as always, is dependent upon operational performance and commodity pricing
levels during the year.
28
Domestic activities account for 80% of budgeted spending, with the largest
allocation going to the Lake Washington area.
We believe that the anticipated internally generated cash flows for 2004,
together with bank borrowings under our credit facility, will be sufficient to
finance the costs associated with our currently budgeted 2004 capital
expenditures. If producing property acquisitions become attractive during 2004,
we will explore the use of debt and/or equity offerings to fund such activity.
Our capital expenditures were approximately $155.2 million in 2002 and
$275.1 million in 2001. 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.
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. Our capital expenditures in 2002 included:
New Zealand activities of $95.2 million, or 61% of total expenditures, as
follows:
o$56.1 million, or 36%, on property 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; and
o$0.4 million, or less than 1%, for fixed assets, principally computers and
office furniture and fixtures.
Domestic activities of $60.0 million, or 39% of total expenditures, 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 completed. In New Zealand we drilled three development
wells and three exploratory wells. One of the development wells and one of the
exploratory wells were unsuccessful.
Critical Accounting Policies
The following summarizes several of our critical accounting policies. See a
complete list of significant accounting policies in Note 1 to the Consolidated
Financial Statements.
Use of Estimates. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities, if
any, at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from estimates. Significant estimates include proved reserve volumes, DD&A, and
deferred income taxes.
Property and Equipment. We follow the "full-cost" method of accounting for
oil and gas property and equipment costs as described in detail in Note 1 to our
Consolidated Financial Statements. Under this method of accounting, all
productive and nonproductive costs incurred in the exploration, development, and
acquisition of oil and gas reserves are capitalized and amortized on an
aggregate basis over the estimated lives of the properties using the
units-of-production method. For the years 2003, 2002, and 2001, internal costs
capitalized totaled $11.5 million, $10.7 million, and $11.6 million,
respectively. Interest costs related to unproved properties are also capitalized
to unproved oil and gas properties. For the years 2003, 2002, and 2001,
capitalized interest
29
on unproved properties totaled $6.8 million, $7.0 million, and $6.3 million,
respectively. Interest not capitalized and general and administrative costs
related to production and general overhead are expensed as incurred.
Full-Cost Ceiling Test. These capitalized costs are subject to a ceiling
test, however, which limits the unamortized cost of oil and gas properties,
including deferred income taxes, to the sum of the estimated future net revenues
from proved properties, excluding cash outflows from asset retirement
obligations, using hedge adjusted period-end prices, discounted at 10%, and the
lower of cost or fair value of unproved properties, adjusted for related income
tax effects ("Ceiling Test"). Our hedges at year-end 2003 consisted of natural
gas price floors with strike prices lower than the period end price and thus did
not affect prices used in this calculation.
At December 31, 2003 and 2002, our unamortized costs of natural gas and oil
properties did not exceed the ceiling amount. At December 31, 2003, our PV-10
value was calculated based upon quoted market prices of $4.56 per Mcf for gas
and $30.16 per barrel for oil, adjusted for market differentials. In the fourth
quarter of 2001, as a result of low oil and gas prices at December 31, 2001, we
reported a non-cash write-down on a before-tax basis of $98.9 million ($63.5
million after tax) on our domestic properties. We had no write-down on our New
Zealand properties. A decline in natural gas and oil prices from year-end 2003
levels or other factors, without mitigating circumstances, could cause a future
non-cash write-down of capitalized costs and a non-cash charge against future
earnings.
Accounts Receivable. Included in the total "Accounts receivable" balance,
which totaled $28.6 million and $20.9 million at December 31, 2003 and 2002,
respectively, on the accompanying balance sheet, was approximately $2.3 million
of receivables related to volumes produced from 2001 and 2002 that we were
notified were disputed in early 2003. Accordingly, we did not record a
receivable to date with regard to 2003 volumes. We assess the collectibility of
trade and other receivables. Based on our judgment, we would accrue a reserve
when we believe a receivable may not be collected. At December 31, 2003 and
2002, we had an allowance for doubtful accounts of $0.8 million and $0.3
million, respectively. These allowance for doubtful accounts balances have been
deducted from the total "Accounts receivable" balances on the balance sheet
included in our Consolidated Financial Statements.
Price-Risk Management Activities. We have a price-risk management policy to
use derivative instruments to protect against declines in oil and gas prices,
mainly through the purchase of price floors and collars. We adopted SFAS No. 133
effective January 1, 2001, which requires that changes in the derivative's fair
value be recognized currently in earnings unless specific hedge accounting
criteria are met as further described in Note 1 to our Consolidated Financial
Statements.
Accordingly, we marked our open contracts at December 31, 2000, to fair
value at that date, resulting in a one-time net of taxes charge of $0.4 million,
which was recorded as a Cumulative Effect of Change in Accounting Principle.
During 2003, 2002 and 2001, we recognized net losses (gains) of $2.8 million,
$0.2 million and ($1.2 million), respectively, relating to our derivative
activities. This activity is recorded in "Price-risk management and other, net"
on the accompanying statements of income. At December 31, 2003, we had recorded
$0.3 million, net of taxes of $0.2 million, of derivative losses in "Other
comprehensive loss" on the accompanying balance sheet. This amount represents
the change in fair value for the effective portion of our transactions that
qualified as cash flow hedges. The ineffectiveness reported in "Price-risk
management and other, net" for 2003 and 2002 was not material. We expect to
reclassify all amounts held in "Other comprehensive loss" into the statement of
income within the next six months when the forecasted sale of hedge products
occurs.
As of December 31, 2003, we had in place natural gas price floors in effect
for the January 2004 contract month through the June 2004 contract month that
cover our domestic natural gas production for January 2004 to June 2004. The
natural gas price floors cover notional volumes of 3,300,000 Mmbtu with a
weighted average floor price of $4.77. When we entered into these transactions
they were designated as a hedge of the variability in cash flows associated with
the forecasted sale of natural gas production. Changes in the fair value of a
hedge that is highly effective and is designated and qualifies as a cash flow
hedge, to the extent that the hedge is effective, are initially recorded in
Other Comprehensive Income (Loss). When the hedged transactions are recorded
upon the actual sale of oil and natural gas, these gains or losses are
reclassified from Other Comprehensive Income (Loss) and recorded in "Price-risk
management and other, net" on the statement of income. The fair value of our
derivatives are computed using the Black-Scholes option pricing model and are
periodically verified against quotes from brokers. The fair value of these
instruments at December 31, 2003, was $0.5 million and is recognized on the
balance sheet in "Other current assets."
30
In January 2004, we entered into additional natural gas "floors" covering
contract periods April 2004 to June 2004, which cover our natural gas production
for January 2004 to June 2004. Notional volumes are 200,000 MMBtu per month at a
weighted average floor price of $5.00 per MMBtu.
See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk"
for additional discussion of commodity risk.
Stock Based Compensation. We have three stock-based compensation plans,
which are described more fully in Note 6 to our Consolidated Financial
Statements. We account for those plans under the recognition and measurement
principles of APB Opinion No. 25, "Accounting for Stock Issued to Employees,"
and related interpretations. No stock-based employee compensation cost is
reflected in net income, as all options granted under those plans had an
exercise price equal to the market value of the underlying common stock on the
date of the grant; or in the case of the employee stock purchase plan, the
purchase price is 85% of the lower of the closing price of our common stock as
quoted on the New York Stock Exchange at the beginning or end of the plan year
or a date during the year chosen by the participant.
Foreign Currency. We use the U.S. Dollar as our functional currency in New
Zealand. The functional currency is determined by examining the entities' cash
flows, commodity pricing environment and financing arrangements. We have both
assets and liabilities denominated in New Zealand Dollars, predominantly our
portion of our "Deferred income taxes" and a portion of our "Asset Retirement
Obligation" on the accompanying balance sheet. For accounts other than "Deferred
income taxes," as the currency rate changes between the U.S. Dollar and the New
Zealand Dollar, we recognize transaction gains and losses in "Price-risk
management and other, net" on the accompanying statements of income. We
recognize transaction gains and losses on "Deferred income taxes" in "Provision
for Income Taxes" on the accompanying statement of income.
New Accounting Pronouncements. In June 2002, the FASB issued SFAS No. 141,
"Business Combinations," and SFAS No. 142 "Goodwill and Intangible Assets." We
adopted these statements on July 1, 2001, and January 1, 2002, respectively. An
issue has arisen for companies engaged in oil and gas exploration and production
regarding the application of SFAS No. 141 and SFAS No. 142 as they relate to
mineral rights held under lease or other contractual arrangements and as to
whether costs associated with these rights should be classified as intangible
assets on the balance sheet, apart from other capitalized oil and gas property
costs. We understand that the Emerging Issues Task Force of the FASB has placed
this issue on its agenda, although the date and the outcome of the resolution of
the issue is unknown.
Historically we have classified our oil and gas mineral rights held under
lease as tangible assets along with our other oil and gas properties, which is
in accordance with the Securities and Exchange Commission's ("SEC") full cost
accounting rules, and we intend to continue to do so until further guidance is
provided. We have estimated the amount associated with these mineral rights
using historical depletion rates, estimates of the timing of impairment of
unproved properties and assuming the cost for the mineral rights was unaffected
by the ceiling test write-down recorded in December 2001 because we cannot
associate the ceiling test write-down with particular types of costs. Based on
these limitations and assumptions, we estimate the net cost of mineral rights
that would be reclassified from oil and gas properties to intangible assets to
be approximately $55-60 million at December 31, 2003 and approximately $45-50
million at December 31, 2002. These amounts are from July 1, 2001 (the date we
adopted SFAS No. 141) to December 31, 2003 as we are not able to calculate
amounts to reclassify before that period as our property records did not break
out that information. Only our balance sheet accounts would be affected by the
reclassification, and our results of operations and cash flows would not be
materially impacted by any such reclassification.
Related-Party Transactions
We have been the operator of a number of properties owned by our affiliated
limited partnerships and, accordingly, charge these entities operating fees. The
operating fees charged to the partnerships in 2003, 2002, and 2001 totaled
approximately $0.2 million, $0.3 million, and $0.9 million, respectively, and
are recorded as reductions of general and administrative expense and oil and gas
production expense. We also have been reimbursed for direct, administrative, and
overhead costs incurred in conducting the business of the limited partnerships,
which totaled approximately $0.4 million, $1.0 million, and $3.1 million in
2003, 2002, and 2001, respectively. In partnerships in which the limited
partners voted to sell their remaining properties and liquidate their limited
partnerships, we also have been reimbursed for direct, administrative, and
overhead costs incurred in the disposition of such properties, which costs
totaled approximately $0.1 million, $0.5 million, and $2.4 million in 2003,
2002, and 2001, respectively.
31
Forward-Looking Statements
The statements contained in this report that are not historical facts are
forward-looking statements as that term is defined in Section 21E of the
Securities and Exchange Act of 1934, as amended. Such forward-looking statements
may pertain to, among other things, financial results, capital expenditures,
drilling activity, development activities, cost savings, production efforts and
volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory
matters, and competition. Such forward-looking statements generally are
accompanied by words such as "plan," "future," "estimate," "expect," "budget,"
"predict," "anticipate," "projected," "should," "believe," or other words that
convey the uncertainty of future events or outcomes. Such forward-looking
information is based upon management's current plans, expectations, estimates,
and assumptions, upon current market conditions, and upon engineering and
geologic information available at this time, and is subject to change and to a
number of risks and uncertainties, and, therefore, actual results may differ
materially. Among the factors that could cause actual results to differ
materially are: volatility in oil and natural gas prices, internationally or in
the United States; availability of services and supplies; fluctuations of the
prices received or demand for our oil and natural gas; the uncertainty of
drilling results and reserve estimates; operating hazards; requirements for
capital; general economic conditions; changes in geologic or engineering
information; changes in market conditions; competition and government
regulations; as well as the risks and uncertainties discussed herein and set
forth from time to time in our other public reports, filings, and public
statements. Also, because of the volatility in oil and gas prices and other
factors, interim results are not necessarily indicative of those for a full
year.
32
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk. Our major market risk exposure is the commodity pricing
applicable to our oil and natural gas production. Realized commodity prices
received for such production are primarily driven by the prevailing worldwide
price for crude oil and spot prices applicable to natural gas. The effects of
such pricing volatility are expected to continue.
Our price-risk management policy permits the utilization of agreements and
financial instruments (such as futures, forward and options contracts, and
swaps) to mitigate price risk associated with fluctuations in oil and natural
gas prices. Below is a description of the financial instruments we have utilized
to hedge our exposure to price risk.
oPrice Floors - At March 1, 2004, we had in place price floors in effect
through the June 2004 contract month for natural gas, these cover our
domestic natural gas production for March 2004 to June 2004. The natural
gas price floors cover notional volumes of 2,550,000 MMBtu, with a
weighted average floor price of $4.84 per MMBtu. Our hedges in place at
March 1, 2004 are expected to cover approximately 55% to 65% of our
domestic natural gas production from March 2004 to June 2004.
oNew Zealand Gas Contracts - All of our gas production in New Zealand is
sold under long-term, fixed-price contracts denominated in New Zealand
Dollars. These contracts protect against price volatility, and our revenue
from these contracts will vary only due to production fluctuations and
foreign exchange rates.
Interest Rate Risk. Our Senior Notes have a fixed interest rate, so
consequently we are not exposed to cash flow risk from market interest rate
changes on our Senior Notes. At December 31, 2003, we had $15.9 million in
outstanding borrowings under our credit facility, which bears a floating rate of
interest and therefore susceptible to interest rate fluctuations. The result of
a 10% fluctuation in the bank's base rate would constitute 40 basis points and
would reduce 2004 cash flows by $0.1 million based on the December 31, 2003
level of borrowing.
Income Tax Carryforwards. We have significant federal and state net
operating loss and capital loss carryforwards at December 31, 2003. The Company
has not recorded a valuation allowance against the deferred tax assets
attributable to these carryovers at December 31, 2003, as management estimates
that it is more likely than not that these assets will be fully utilized before
they expire. Significant changes in estimates caused by changes in oil and gas
prices, production levels, capital expenditures, and other variables could
impact the Company's ability to utilize the carryover amounts. If we are not
able to use our carryforwards, our results of operations and cash flows will be
negatively impacted.
Financial Instruments and Debt Maturities. Our financial instruments
consist of cash and cash equivalents, accounts receivable, accounts payable,
bank borrowings, and notes. The carrying amounts of cash and cash equivalents,
accounts receivable, and accounts payable approximate fair value due to the
short-term nature of these instruments. The fair values of the bank borrowings
approximate the carrying amounts as of December 31, 2003 and 2002, and were
determined based upon interest rates currently available to us for borrowings
with similar terms. Based on quoted market prices as of the respective dates,
the fair value of our Senior Notes due 2009 was $135.6 million at December 31,
2003, and $129.0 million at December 31, 2002. Based upon quoted market prices
as of the respective dates, the fair value of our Senior Notes due 2012 was
$218.0 million at December 31, 2003, and $189.2 million at December 31, 2002.
Our credit facility with the banks expires October 1, 2005.
Foreign Currency Risk. We are exposed to the risk of fluctuations in
foreign currencies, most notably the New Zealand Dollar. Fluctuations in rates
between the New Zealand Dollar and U.S. Dollar may impact our financial results
from our New Zealand subsidiaries since we have receivables and liabilities
denominated in New Zealand Dollars. We use the U.S. Dollar as our functional
currency in New Zealand, because of this our results of operations, cash flows
and effective tax rate are impacted from fluctuations between the U.S. Dollar
the New Zealand Dollar.
Customer Credit Risk. We are exposed to the risk of financial
non-performance by customers, who are mainly in the energy industry. Our ability
to collect on sales to our customers is dependent on the liquidity of our
customer base. To manage customer credit risk, we monitor credit ratings of
customers and seek to minimize exposure to any one customer where other
customers are readily available. Due to availability of other purchasers, we do
not believe the loss of any single oil or gas customer would materially affect
our revenues.
33
Item 8. Financial Statements and Supplementary Data
Report of Independent Auditors.........................................35
Report of Independent Public Accountants...............................36
Consolidated Balance Sheets............................................37
Consolidated Statements of Income......................................38
Consolidated Statements of Stockholders' Equity........................39
Consolidated Statements of Cash Flows..................................40
Notes to Consolidated Financial Statements.............................41
1. Summary of Significant Accounting Policies.......................41
2. Earnings Per Share...............................................48
3. Provision for Income Taxes.......................................48
4. Long-Term Debt ..................................................50
5. Commitments and Contingencies....................................51
6. Stockholders' Equity.............................................52
7. Related-Party Transactions.......................................54
8. Foreign Activities...............................................54
9. Acquisitions and Dispositions....................................54
10. Segment Information..............................................56
Supplemental Information (Unaudited)..................................58
34
Report of Independent Auditors
Board of Directors
Swift Energy Company
We have audited the accompanying consolidated balance sheets of Swift
Energy Company and subsidiaries as of December 31, 2003 and 2002, and the
related consolidated statements of income, stockholders' equity, and cash flows
for each of the two years in the period ended December 31, 2003. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits. The consolidated financial statements of Swift Energy Company and
subsidiaries for the year ended December 31, 2001, were audited by other
auditors who have ceased operations and whose report dated February 18, 2002,
expressed an unqualified opinion on those statements.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the 2002 and 2003 financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
Swift Energy Company and subsidiaries at December 31, 2003 and 2002, and the
consolidated results of their operations and their cash flows for each of the
two years in the period ended December 31, 2003 in conformity with accounting
principles generally accepted in the United States.
As discussed in Note 1 to the consolidated financial statements, in 2003
the Company changed its method of accounting for asset retirement obligations.
ERNST & YOUNG LLP
Houston, Texas
February 10, 2004
35
Report of Independent Public Accountants
To the Stockholders and Board of Directors of Swift Energy Company:
We have audited the accompanying consolidated balance sheets of Swift
Energy Company (a Texas corporation) and subsidiaries as of December 31, 2001
and 2000, and the related consolidated statements of income, stockholders'
equity, and cash flows for each of the three years in the period ended December
31, 2001. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Swift Energy Company and
subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
February 18, 2002
NOTE: This is a copy of the report previously issued by Arthur Andersen LLP and
has not been reissued.
36
Consolidated Balance Sheets
Swift Energy Company and Subsidiaries
December 31,
ASSETS 2003 2002
----------------- ----------------
Current Assets:
Cash and cash equivalents $ 1,066,280 $ 3,816,107
Accounts receivable-
Oil and gas sales 26,942,920 17,360,716
Affiliated limited partnerships 356,118 191,964
Joint interest owners 1,350,707 3,364,846
Other current assets 4,957,647 5,034,566
----------------- ----------------
Total Current Assets 34,673,672 29,768,199
----------------- ----------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties 1,305,763,355 1,150,633,802
Unproved properties 67,557,969 69,603,481
----------------- ----------------
1,373,321,324 1,220,237,283
Furniture, fixtures, and other equipment 10,602,786 9,595,944
----------------- ----------------
1,383,924,110 1,229,833,227
Less - Accumulated depreciation, depletion, and amortization (567,464,334) (504,323,773)
----------------- ----------------
816,459,776 725,509,454
----------------- ----------------
Other Assets:
Deferred income taxes 1,905,909 2,680,585
Debt issuance costs 8,015,575 9,047,621
----------------- ----------------
9,921,484 11,728,206
----------------- ----------------
$ 861,054,932 $ 767,005,859
================= ================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 63,100,669 $ 43,028,708
Payable to affiliated limited partnerships 516,006 91,126
Undistributed oil and gas revenues 6,156,055 3,764,350
----------------- ----------------
Total Current Liabilities 69,772,730 46,884,184
----------------- -----------------
Long-Term Debt 340,254,783 324,271,973
Deferred Income Taxes 43,498,682 30,776,518
Asset Retirement Obligation 10,137,473 ---
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none
outstanding --- ---
Common stock, $.01 par value, 85,000,000 shares authorized,
28,011,109 and27,811,632 shares issued, and 27,484,091
and 27,201,509 sharesoutstanding, respectively 280,111 278,116
Additional paid-in capital 334,865,204 333,543,471
Treasury stock held, at cost, 527,018 and 610,123 shares,
respectively (7,558,093) (8,749,922)
Retained earnings 70,073,384 40,179,572
Accumulated other comprehensive loss, net of income tax (269,342) (178,053)
----------------- ----------------
397,391,264 365,073,184
----------------- ----------------
$ 861,054,932 767,005,859
================= ================
See accompanying Notes to Consolidated Financial Statements.
37
Consolidated Statements of Income
Swift Energy Company and Subsidiaries
Year Ended December 31,
2003 2002 2001
----------------- ----------------- --------------
Revenues:
Oil and gas sales $ 211,032,639 $ 141,195,713 $ 181,184,635
Fees from affiliated limited partnerships 28,068 67,173 427,583
Interest income 184,383 263,738 49,281
Gain on asset disposition --- 7,332,668 ---
Price-risk management and other, net (2,344,107) 1,110,519 2,145,991
---------------- ---------------- --------------
208,900,983 149,969,811 183,807,490
---------------- ---------------- --------------
Costs and Expenses:
General and administrative, net 14,097,066 10,564,849 8,186,654
Depreciation, depletion, and amortization 63,072,057 56,224,392 59,502,040
Accretion of asset retirement obligation 857,356 --- ---
Oil and gas production 52,866,802 41,497,312 36,719,609
Interest expense, net 27,268,524 23,274,969 12,627,022
Other expenses --- --- 2,102,251
Write-down of oil and gas properties --- --- 98,862,247
---------------- ---------------- --------------
158,161,805 131,561,522 217,999,823
---------------- ---------------- --------------
Income (Loss) Before Income Taxes and
Change in Accounting Principle 50,739,178 18,408,289 (34,192,333)
Provision (Benefit) for Income Taxes 16,468,514 6,485,062 (12,237,436)
---------------- ---------------- --------------
Income (Loss) Before Change
In Accounting Principle $ 34,270,664 $ 11,923,227 $ (21,954,897)
Cumulative Effect of Change in Accounting Principle
(net of taxes) 4,376,852 --- 392,868
---------------- ---------------- --------------
Net Income (Loss) $ 29,893,812 $ 11,923,227 $ (22,347,765)
================ ================ ==============
Per Share Amounts-
Basic: Income (Loss) Before
Change in Accounting Principle $ 1.25 $ 0.45 $ (0.89)
Change in Accounting Principle (0.16) --- (0.01)
---------------- ---------------- --------------
Net Income (Loss) $ 1.09 $ 0.45 $ (0.90)
================ ================ ==============
Diluted: Income (Loss) Before
Change in Accounting Principle $ 1.24 $ 0.45 $ (0.89)
Change in Accounting Principle (0.16) --- (0.01)
---------------- ---------------- --------------
Net Income (Loss) $ 1.08 $ 0.45 $ (0.90)
================ ================ ==============
Weighted Average Shares Outstanding 27,357,579 26,382,906 24,732,099
================ ================ ==============
See accompanying Notes to Consolidated Financial Statements.
38
Consolidated Statements of Stockholders' Equity
Swift Energy Company and Subsidiaries
Accumulated
Additional Retained Other
Common Paid-in Treasury Earnings Comprehensive
Stock (1) Capital Stock (Deficit) Loss Total
---------- --------------- ------------- ------------- ---------------- -------------
Balance, December 31, 2000 $ 254,521 $ 293,396,723 $ (12,101,199) $ 50,604,110 $ - $ 332,154,155
Stock issued for benefit plans
(11,945 shares) 72 354,973 68,408 - - 423,453
Stock options exercised
(152,915 shares) 1,529 1,942,634 - - - 1,944,163
Employee stock purchase plan
(22,360 shares) 224 478,490 - - - 478,714
Comprehensive income:
Net loss - - - (22,347,765) - (22,347,765)
-------------
Total comprehensive income - - - - - (22,347,765)
---------- --------------- ------------- ------------- ---------------- -------------
Balance, December 31, 2001 $ 256,346 $ 296,172,820 $ (12,032,791) $ 28,256,345 $ - $ 312,652,720
========== =============== ============= ============= ================ =============
Stock issued for benefit plans
(38,149 shares) 292 617,960 127,795 - - 746,047
Stock options exercised
(112,995 shares) 1,130 1,206,413 - - - 1,207,543
Public stock offering
(1,725,000 shares) 17,250 30,465,809 - - - 30,483,059
Employee stock purchase plan
(9,801 shares) 98 122,343 - - - 122,441
Stock issued in acquisitions
(520,000 shares) 3,000 4,958,126 3,155,074 - - 8,116,200
Comprehensive income:
Net income - - - 11,923,227 - 11,923,227
Change in fair value of
cash flow hedges, net of
income tax - - - - (178,053) (178,053)
-------------
Total comprehensive income - - - - - 11,745,174
---------- --------------- -------------- ------------- ---------------- -------------
Balance, December 31, 2002 $ 278,116 $ 333,543,471 $ (8,749,922) $ 40,179,572 $ (178,053) $ 365,073,184
========== =============== ============== ============= ================ =============
Stock issued for benefit plans
(83,201 shares) 1 (408,178) 1,191,829 - - 783,652
Stock options exercised
(142,807 shares) 1,428 1,315,964 - - - 1,317,392
Employee stock purchase plan
(56,574 shares) 566 413,947 - - - 414,513
Comprehensive income:
Net income - - - 29,893,812 - 29,893,812
Change in fair value of
cash flow hedges, net of
income tax - - - - (91,289) (91,289)
-------------
Total comprehensive income - - - - - 29,802,523
---------- --------------- ------------- ------------- ---------------- -------------
Balance, December 31, 2003 $ 280,111 $ 334,865,204 $ (7,558,093) $ 70,073,384 $ (269,342) $ 397,391,264
========== =============== ============= ============= ================ =============
(1)$.01 par value.
See accompanying Notes to Consolidated Financial Statements.
39
Consolidated Statements of Cash Flows
Swift Energy Company and Subsidiaries
Year Ended December 31,
------------------------------------------------------
2003 2002 2001
----------------- ---------------- ----------------
Cash Flows from Operating Activities:
Net income (loss) $ 29,893,812 $ 11,923,227 $ (22,347,765)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities-
Cumulative effect of change in accounting principle 4,376,852 --- ---
Depreciation, depletion, and amortization 63,072,057 56,224,392 59,502,040
Write-down of oil and gas properties --- --- 98,862,247
Accretion of asset retirement obligation 857,356 --- ---
Deferred income taxes 16,332,492 6,482,724 (12,555,618)
Gain on asset disposition --- (7,332,668) ---
Other 908,927 270,770 509,973
Change in assets and liabilities-
(Increase) decrease in accounts receivable, (7,163,304) 283,419 16,207,377
excluding income taxes receivable
Increase in accounts payable and accrued
liabilities 2,542,803 3,174,450 12,984
(Increase) decrease in income taxes receivable
and payable 6,284 600,000 (306,983)
----------------- ---------------- ----------------
Net Cash Provided by Operating Activities 110,827,279 71,626,314 139,884,255
----------------- ---------------- ----------------
Cash Flows from Investing Activities:
Additions to property and equipment (144,503,180) (155,233,923) (275,126,333)
Proceeds from the sale of property and equipment 10,186,970 13,256,674 9,274,440
Net cash received as operator of oil and gas properties 3,073,718 4,152,645 5,927,539
Net cash received (distributed) as operator of
partnerships 260,726 (23,241,501) (3,574,601)
Other (71,193) (39,953) (534,898)
----------------- ---------------- ----------------
Net Cash Used in Investing Activities (131,052,959) (161,106,058) (264,033,853)
----------------- ---------------- ----------------
Cash Flows from Financing Activities:
Proceeds from long-term debt --- 200,000,000 ---
Net proceeds from (payments of) bank borrowings 15,900,000 (134,000,000) 123,400,000
Net proceeds from issuances of common stock 1,575,853 31,409,200 1,633,508
Payments of debt issuance costs --- (6,262,435) (721,756)
----------------- ---------------- ----------------
Net Cash Provided by Financing Activities 17,475,853 91,146,765 124,311,752
----------------- ---------------- ----------------
Net Increase (Decrease) in Cash and Cash Equivalents $ (2,749,827) $ 1,667,021 $ 162,154
Cash and Cash Equivalents at Beginning of Year 3,816,107 2,149,086 1,986,932
------------------ ---------------- ----------------
Cash and Cash Equivalents at End of Year $ 1,066,280 $ 3,816,107 $ 2,149,086
================= ================ ================
Supplemental Disclosures of Cash Flows Information:
Cash paid during year for interest, net of amounts capitalized $ 25,763,169 $ 19,189,822 $ 12,207,205
Cash paid during year for income taxes $ 129,738 $ 2,500 $ 441,926
Non-Cash Financing Activity:
Issuance of common stock in acquisitions $ --- $ 8,116,200 $ ---
See accompanying Notes to Consolidated Financial Statements.
40
Notes to Consolidated Financial Statements
Swift Energy Company and Subsidiaries
1. Summary of Significant Accounting Policies
Principles of Consolidation. The accompanying consolidated financial
statements include the accounts of Swift Energy Company and our wholly owned
subsidiaries, which are engaged in the exploration, development, acquisition,
and operation of oil and natural gas properties, with a focus on onshore and
inland waters oil and natural gas reserves in Texas and Louisiana, as well as
onshore oil and natural gas reserves in New Zealand. Our investments in ventures
and affiliated oil and gas partnerships are accounted for using the
proportionate consolidation method, whereby our proportionate share of each
entity's assets, liabilities, revenues, and expenses are included in the
appropriate classifications in the consolidated financial statements.
Intercompany balances and transactions have been eliminated in preparing the
consolidated financial statements.
Use of Estimates. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities, if
any, at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from estimates. Significant estimates include proved reserve volumes, DD&A, and
deferred income taxes.
Property and Equipment. We follow the "full-cost" method of accounting for
oil and gas property and equipment costs. Under this method of accounting, all
productive and nonproductive costs incurred in the exploration, development, and
acquisition of oil and gas reserves are capitalized. Under the full-cost method
of accounting, such costs may be incurred both prior to and after the
acquisition of a property and include lease acquisitions, geological and
geophysical services, drilling, completion, and equipment. Internal costs
incurred that are directly identified with exploration, development, and
acquisition activities undertaken by us for our own account, and which are not
related to production, general corporate overhead, or similar activities, are
also capitalized. For the years 2003, 2002, and 2001, such internal costs
capitalized totaled $11.5 million, $10.7 million, and $11.6 million,
respectively. Interest costs are also capitalized to unproved oil and gas
properties. For the years 2003, 2002, and 2001, capitalized interest on unproved
properties totaled $6.8 million, $7.0 million, and $6.3 million, respectively.
Interest not capitalized and general and administrative costs related to
production and general overhead are expensed as incurred.
No gains or losses are recognized upon the sale or disposition of oil and
gas properties, except in transactions involving a significant amount of
reserves or where the proceeds from the sale of oil and gas properties would
significantly alter the relationship between capitalized costs and proved
reserves of oil and gas attributable to a cost center. Internal costs associated
with selling properties are expensed as incurred.
Future development costs are estimated property by property based on
current economic conditions and are amortized to expense as our capitalized oil
and gas property costs are amortized.
We compute the provision for depreciation, depletion, and amortization of
oil and gas properties using the unit-of-production method. Under this method,
we compute the provision by multiplying the total unamortized costs of oil and
gas properties--including future development costs, gas processing facilities,
and capitalized asset retirement obligations, net of salvage values, but
excluding costs of unproved properties--by an overall rate determined by
dividing the physical units of oil and gas produced during the period by the
total estimated units of proved oil and gas reserves at the beginning of the
period. This calculation is done on a country-by-country basis. Our amortization
per Mcfe was $1.17, $1.11, and $1.31 in 2003, 2002, and 2001, respectively.
Furniture, fixtures, and other equipment are depreciated by the straight-line
method at rates based on the estimated useful lives of the property. Repairs and
maintenance are charged to expense as incurred. Renewals and betterments are
capitalized.
Geological and geophysical (G&G) costs are recorded in Proved Property and
therefore subject to amortization as incurred on developed properties. In
exploration areas, G&G costs are capitalized in Unproved Property and evaluated
as part of the total capitalized costs associated with a prospect.
The cost of unproved properties not being amortized is assessed quarterly,
on a country-by-country basis, to determine whether such properties have been
impaired. In determining whether such costs should be impaired, we evaluate
current drilling results, lease expiration dates, current oil and gas industry
conditions,
41
international economic conditions, capital availability, foreign currency
exchange rates, the political stability in the countries in which we have an
investment, and available geological and geophysical information. Any impairment
assessed is added to the cost of proved properties being amortized. To the
extent costs accumulate in countries where there are no proved reserves, any
costs determined by management to be impaired are charged to expense.
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the
unamortized cost of oil and gas properties, including gas processing facilities
and the fair value of asset retirement obligations, net of related salvage
values, deferred income taxes, and excluding the asset retirement obligation
liability is limited to the sum of the estimated future net revenues from proved
properties, excluding cash outflows from asset retirement obligations, using
hedged adjusted period-end prices, discounted at 10%, and the lower of cost or
fair value of unproved properties, adjusted for related income tax effects
("Ceiling Test"). Our hedges at year-end 2003 consisted of natural gas price
floors with strike prices lower than the period end price and thus did not
affect prices used in this calculation. This calculation is done on a
country-by-country basis for those countries with proved reserves.
The calculation of the Ceiling Test and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves. There are
numerous uncertainties inherent in estimating quantities of proved reserves and
in projecting the future rates of production, timing, and plan of development.
The accuracy of any reserves estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. Results of
drilling, testing, and production subsequent to the date of the estimate may
justify revision of such estimate. Accordingly, reserves estimates are often
different from the quantities of oil and gas that are ultimately recovered.
In the fourth quarter of 2001, as a result of low oil and gas prices at
December 31, 2001, we reported a non-cash write-down on a before-tax basis of
$98.9 million ($63.5 million after tax) on our domestic properties. We had no
write-down on our New Zealand properties.
Given the volatility of oil and gas prices, it is reasonably possible that
our estimate of discounted future net cash flows from proved oil and gas
reserves could change in the near term. If oil and gas prices decline from the
Company's period-end prices used in the Ceiling Test, even if only for a short
period, it is possible that additional non-cash write-downs of oil and gas
properties could occur in the future.
Revenue Recognition. Oil and gas revenues are recognized when production is
sold to a purchaser at a fixed or determinable price, when delivery has occurred
and title has transferred, and if collectibility of the revenue is probable. The
Company uses the entitlement method of accounting in which the Company
recognizes its ownership interest in production as revenue. If our sales exceed
our ownership share of production, the differences are reported in "Accounts
payable and accrued liabilities" on the accompanying balance sheet. Natural gas
balancing receivables are reported in "Other current assets" on the accompanying
balance sheet when our ownership share of production exceeds sales. As of
December 31, 2003, we did not have any material natural gas imbalances.
Accounts Receivable. Included in the total "Accounts receivable" balance,
which totaled $28.6 million and $20.9 million at December 31, 2003 and 2002,
respectively, on the accompanying balance sheet, is approximately $2.3 million
of receivables related to volumes produced from 2001 and 2002 that we were
notified, were disputed in early 2003. Accordingly, we did not record a
receivable with regard to 2003 volumes. We assess the collectibility of trade
and other receivables. Based on our judgment, we accrue a reserve when we
believe a receivable may not be collected. At December 31, 2003 and 2002, we had
an allowance for doubtful accounts of $0.8 million and $0.3 million,
respectively. These allowances for doubtful accounts balances have been deducted
from the total "Accounts receivable" balances on the accompanying consolidated
balance sheet.
Debt issuance costs. Legal and accounting fees, underwriting fees, printing
costs, and other direct expenses associated with the public offering in August
1999 of our 10.25% Senior Subordinated Notes (the "Senior Notes"), the September
2001 extension of our bank credit facility, and the public offering in April
2002 of our 9.375% Senior Subordinated Notes were capitalized and are amortized
over the life of each of the respective note offerings and credit facility. The
Senior Notes due 2009 mature on August 1, 2009, and the balance of their
issuance costs at December 31, 2003, was $2.4 million, net of accumulated
amortization of $1.1 million. The issuance costs associated with our revolving
credit facility, which was extended in September 2001, have been capitalized and
are being amortized over the life of the facility. The balance of revolving
credit facility issuance costs at December 31, 2003, was $0.6 million, net of
accumulated amortization of $1.3 million.
42
The Senior Notes due 2012 mature on May 1, 2012, and the balance of their
issuance costs at December 31, 2003, was $5.0 million, net of accumulated
amortization of $0.6 million.
Limited Partnerships. At year-end 2003, we serve as managing general
partner for six drilling partnerships, and during fiscal 2003 less than 1% of
our total oil and gas sales was attributable to our interests in those
partnerships. These six partnerships were formed between 1996 and 1998, and will
continue to operate until their limited partners vote otherwise.
Price-Risk Management Activities. The Company follows SFAS No. 133, which
requires that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. The statement also
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or a liability
measured at its fair value. Special hedge accounting for qualifying hedges would
allow the gains and losses on derivatives to offset related results on the
hedged item in the income statements and requires that a company formally
document, designate, and assess the effectiveness of transactions that receive
hedge accounting. Hedges that do not meet the criteria for special hedge
accounting are accounted for under mark to market accounting. SFAS No. 133, as
amended by SFAS No. 137 and SFAS No. 138, was adopted by us on January 1, 2001.
We have a price-risk management policy to use derivative instruments to
protect against declines in oil and gas prices, mainly through the purchase of
price floors and collars. Upon adoption of SFAS No. 133 on January 1, 2001, we
recorded a net of taxes charge of $0.4 million, which is recorded as a
Cumulative Effect of Change in Accounting Principle. During 2003, 2002 and 2001,
we recognized net losses (gains) of $2.8 million, $0.2 million and ($1.2)
million, respectively, relating to our derivative activities. This activity is
recorded in "Price-risk management and other, net" on the accompanying
statements of income. At December 31, 2003, the Company had recorded $0.3
million, net of taxes of $0.2 million, of derivative losses in "Other
comprehensive loss" on the accompanying balance sheet. This amount represents
the change in fair value for the effective portion of our collar transactions
that were qualified as cash flow hedges. The ineffectiveness reported in
"Price-risk management and other, net" for 2003 and 2002 was not material. The
Company expects to reclassify all amounts currently held in "Other comprehensive
loss" into the statement of income within the next six months when the
forecasted sale of hedged production occurs.
As of December 31, 2003, we had in place natural gas price floors in effect
for the January 2004 contract month through the June 2004 contract, which cover
our domestic natural gas production for January 2004 to June 2004. The natural
gas price floors cover notional volumes of 3,300,000 Mmbtu with a weighted
average floor price of $4.77. When we entered into these transactions, they were
designated as a hedge of the variability in cash flows associated with the
forecasted sale of natural gas production. Changes in the fair value of a hedge
that is highly effective and is designated and qualifies as a cash flow hedge,
to the extent that the hedge is effective, are recorded in Other Comprehensive
Income (Loss). When the hedged transactions are recorded upon the actual sale of
oil and natural gas, these gains or losses are reclassified from Other
Comprehensive Income (Loss) and recorded in "Price-risk management and other,
net" on the consolidated statement of income. The fair value of our derivatives
are computed using the Black-Scholes option pricing model and are periodically
verified against quotes from brokers. The fair value of these instruments at
December 31, 2003, was $0.5 million and is recognized on the balance sheet in
"Other current assets."
Supervision Fees. Consistent with industry practice, we charge a
supervision fee to the wells we operate including our working interest share on
wells where we have a 100% working interest. These supervision fees are recorded
as a reduction to general and administrative expenses and oil and gas production
expenses based on our estimate of the costs incurred to operate the wells.
Effective October 1, 2003, we began recording the supervision fee as a reduction
to general and administrative expense only. The total amount of supervision fees
charged to the wells we operate was $5.1 million in 2003, $5.3 million in 2002,
and $6.8 million in 2001.
Inventories. Inventories consist principally of tubular goods and
equipment, stated at the lower of weighted-average cost or market, and oil
produced but not sold, stated at the lower of cost (a combination of production
costs and depreciation, depletion and amortization expense) or market.
Income Taxes. Under SFAS No. 109, "Accounting for Income Taxes," deferred
taxes are determined based on the estimated future tax effects of differences
between the financial statement and tax bases of assets and liabilities, given
the provisions of the enacted tax laws.
43
Accounts Payable and Accrued Liabilities. Included in accounts payable and
accrued liabilities at December 31, 2003 and 2002 are liabilities of
approximately $11.9 million and $8.4 million, respectively, representing the
amount by which checks issued, but not presented to the Company's banks for
collection, exceeded balances in the applicable bank accounts.
Cash and Cash Equivalents. We consider all highly liquid debt instruments
with an initial maturity of three months or less to be cash equivalents.
Credit Risk Due to Certain Concentrations. We extend credit, primarily in
the form of uncollateralized oil and gas sales and joint interest owners
receivables, to various companies in the oil and gas industry, which results in
a concentration of credit risk. The concentration of credit risk may be affected
by changes in economic or other conditions within our industry and may
accordingly impact our overall credit risk. However, we believe that the risk of
these unsecured receivables is mitigated by the size, reputation, and nature of
the companies to which we extend credit. During 2003, oil and gas sales to
Shell, both domestically and in New Zealand, were $31.1 million, or 15% of total
oil and gas sales, while sales to subsidiaries of Contact Energy in New Zealand
were $23.5 million, or 11.2% of total oil and gas sales. During 2002, oil and
gas sales to Eastex Crude Company were $25.4 million, or 18.0% of total oil and
gas sales, while sales to subsidiaries of Contact Energy in New Zealand were
$14.6 million, or 10.3% of total oil and gas sales. During 2001, oil and gas
sales to Eastex Crude Company were $31.6 million, or 18.1% of total oil and gas
sales, while sales to subsidiaries of Enron were $18.2 million, or 10.4% of
total oil and gas sales. During the fourth quarter of 2001, we wrote off $1.4
million due to uncollected receivables related to gas sold to Enron in November
2001. This amount is included in "Other expenses" on the Consolidated Statement
of Income. In 2001, we discontinued sales of oil and gas to Enron and are
selling that production to other purchasers. Credit losses in 2002 and 2003 have
been immaterial.
Environmental Costs. Our operations include activities that are subject to
extensive federal and state environmental regulations. Costs associated with
redemption projects, which are probable and quantifiable, are accrued in
advance. Ongoing environmental compliance costs are expensed as incurred.
Foreign Currency. We use the U.S. Dollar as our functional currency in New
Zealand. The functional currency is determined by examining the entities cash
flows, commodity pricing environment and financing arrangements. We have both
assets and liabilities denominated in New Zealand Dollars, predominantly our
portion of our "Deferred income taxes" and a portion of our "Asset Retirement
Obligation" on the accompanying balance sheet. For accounts other than "Deferred
income taxes," as the currency rate changes between the U.S. Dollar and the New
Zealand Dollar, we recognize transaction gains and losses in "Price-risk
management and other, net" on the accompanying statements of income. We
recognize transaction gains and losses on "Deferred income taxes" in "Provision
for Income Taxes" on the accompanying statement of income.
Fair Value of Financial Instruments. Our financial instruments consist of
cash and cash equivalents, accounts receivable, accounts payable, bank
borrowings, and senior notes. The carrying amounts of cash and cash equivalents,
accounts receivable, and accounts payable approximate fair value due to the
highly liquid nature of these short-term instruments. The fair values of the
bank borrowings approximate the carrying amounts as of December 31, 2003 and
2002, and were determined based upon variable interest rates currently available
to us for borrowings with similar terms. Based on quoted market prices as of the
respective dates, the fair values of our Senior Notes due 2009 were $135.6
million and $129.0 million at December 31, 2003 and 2002, respectively. Based
upon quoted market prices as of December 31, 2003 and 2002, the fair values of
our Senior Notes due 2012 were $218.0 million and $189.2 million, respectively.
The carrying value of our Senior Notes due 2009 was $124.4 million and $124.3
million at December 31, 2003 and 2002, respectively. The carrying value of our
Senior Notes due 2012 was $200.0 million at both December 31, 2003 and 2002.
44
Other Comprehensive Loss. We follow the provisions of SFAS No. 130,
"Reporting Comprehensive Income," which establishes standards for reporting
comprehensive income. In addition to net income, comprehensive income or loss
includes all changes to equity during a period, except those resulting from
investments and distributions to the owners of the Company. At December 31,
2003, we recorded $0.3 million, net of taxes of $0.2 million, of derivative
losses in "Other comprehensive loss" on the accompanying balance sheet. The
components of accumulated other comprehensive loss and related tax effects for
2003 were as follows:
Net of Tax
Gross Value Tax Effect Value
---------------- --------------- ---------------
Balance at December 31, 2002 $ 278,208 $ 100,155 $ 178,053
Change in fair value of cash flow
hedges 2,488,136 895,729 1,592,407
Effect of cash flow hedges settled
during the period (2,345,497) (844,379) (1,501,118)
---------------- --------------- ---------------
Balance at December 31, 2003 $ 420,847 $ 151,505 $ 269,342
================ =============== ===============
Total comprehensive income was $29.8 million and $11.7 million for 2003 and
2002, respectively. Total comprehensive loss was $22.3 million in 2001.
Stock Based Compensation. We have three stock-based compensation plans,
which are described more fully in Note 6. We account for those plans under the
recognition and measurement principles of APB Opinion No. 25, "Accounting for
Stock Issued to Employees," and related interpretations. No stock-based employee
compensation cost is reflected in net income, as all options granted under those
plans had an exercise price equal to the market value of the underlying common
stock on the date of the grant; or in the case of the employee stock purchase
plan, the purchase price is 85% of the lower of the closing price of our common
stock as quoted on the New York Stock Exchange at the beginning or end of the
plan year or a date during the year chosen by the participant. Had compensation
expense for these plans been determined based on the fair value of the options
consistent with SFAS No. 123, "Accounting for Stock-Based Compensation," our net
income (loss) and earnings (loss) per share would have been adjusted to the
following pro forma amounts:
2003 2002 2001
---------------- -------------- ----------------
Net Income As Reported $29,893,812 $11,923,227 $ (22,347,765)
(Loss):
Stock-based
employee
compensation expense
determined under
fair value method
for all awards, net
of tax (4,112,455) (4,451,799) (4,284,859)
---------------- -------------- ----------------
Pro Forma $25,781,357 $ 7,471,428 $ (26,632,624)
Basic EPS: As Reported $1.09 $.45 $(0.90)
Pro Forma $0.94 $.28 $(1.08)
Diluted EPS: As Reported $1.08 $.45 $(0.90)
Pro Forma $0.94 $.27 $(1.08)
Pro forma compensation cost reflected above may not be representative of the
cost to be expected in future years. The fair value of each option grant, as
opposed to its exercise price, is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted average
assumptions in 2003, 2002, and 2001, respectively: no dividend yield; expected
volatility factors of 34.71%, 73.72%, and 46.9%; risk-free interest rates of
4.63%, 4.74%, and 5.24%; and expected lives of 7.2, 7.4, and 7.3 years.
Asset Retirement Obligation. In June 2001, the Financial Accounting
Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." The statement requires entities to record the fair value of a
liability for legal obligations associated with the retirement obligations of
tangible long-lived assets in the period in which it is incurred. When the
liability is initially recorded, the carrying amount of the related long-lived
asset is increased. The liability is discounted from the year the well is
expected to deplete. Over time, accretion of the liability is recognized each
period, and the capitalized cost is depreciated over the
45
useful life of the related asset. Upon settlement of the liability, an entity
either settles the obligation for its recorded amount or incurs a gain or loss
upon settlement. This standard requires us to record a liability for the fair
value of our dismantlement and abandonment costs, excluding salvage values. SFAS
No. 143 was adopted by us effective January 1, 2003. Upon adoption of SFAS No.
143 effective January 1, 2003, we recorded an asset retirement obligation of
$8.9 million, an addition to oil and gas properties of $2.0 million, and a
non-cash charge of $4.4 million (net of $2.5 million of deferred taxes), which
is recorded as a Cumulative Effect of Change in Accounting Principle. The
cumulative charge to earnings took into consideration the impact of adopting
SFAS No. 143 on previous full-cost ceiling tests. SFAS No. 143 is silent with
respect to whether prior period ceiling tests should be reflected in the
implementation entry calculation; however, management believes that any
impairment on the properties should be reflected in the historical periods. Had
the Company not considered the impact of adopting SFAS No. 143 on previous
full-cost ceiling tests, the charge recognized would have been reduced.
Excluding the Cumulative Effect of Change in Accounting Principle, the adoption
of SFAS No. 143 reduced our 2003 net income by approximately $0.6 million, or
$0.02 per diluted share. The following provides a roll-forward of our asset
retirement obligation:
Asset Retirement Obligation recorded as of January 1, 2003 $ 8,934,320
Accretion expense for 2003 857,356
Liabilities incurred for new wells and facilities construction 608,166
Reductions due to sold and abandoned wells (443,391)
Revisions in estimated cash flows 67,511
Increase due to currency exchange rate fluctuations 113,511
-----------------
Asset Retirement Obligation as of December 31, 2003 $ 10,137,473
-----------------
The pro forma effect for 2001, assuming adoption of SFAS No. 143 effective
January 1, 2001, would have included a non-cash charge of $2.6 million (net of
$1.5 million of deferred taxes), which would have been recorded as a Cumulative
Effect of Change in Accounting Principle and recognition of an asset retirement
obligation of $4.3 million. The following table displays our pro forma results
for the years ended December 31, 2002 and 2001, had we adopted SFAS No. 143
effective January 1, 2001.
(Unaudited)
Year Ended Year Ended
December 31, 2002 December 31, 2001
------------------ -------------------
Net Income (Loss):
Actual - as reported $ 11,923,227 $ (22,347,765)
Pro Forma $ 11,515,205 $ (25,246,667)
Basic EPS:
Actual - as reported $ 0.45 $ (0.90)
Pro Forma $ 0.44 $ (1.02)
Diluted EPS:
Actual - as reported $ 0.45 $ (0.90)
Pro Forma $ 0.43 $ (1.02)
New Accounting Pronouncements. In June 2001, the FASB issued SFAS No. 141 ,
"Business Combinations," and SFAS No. 142, "Goodwill and Intangible Assets." We
adopted these statements on July 1, 2001 and January 1, 2002, respectively. SFAS
No. 141 requires that all business combinations initiated after June 30, 2001,
be accounted for using the purchase method and that intangible assets be
disaggregated and reported separately from goodwill. SFAS No. 142 establishes
new guidelines for accounting for goodwill and other intangible assets. Under
SFAS No. 142, goodwill and other indefinite lived intangible assets are not
amortized but reviewed annually for impairment.
An issue has arisen for companies engaged in oil and gas exploration and
production regarding the application of SFAS No. 141 and SFAS No. 142 as they
relate to mineral rights held under lease or other contractual arrangements, and
as to whether costs associated with these rights should be classified as
intangible assets on the balance sheet, apart from other capitalized oil and gas
property costs, and to provide specific footnote disclosure. We understand that
the Emerging Issues Task Force of the FASB has placed this issue on its agenda,
although the date and outcome of the resolution of the issue is unknown.
46
Historically, we have classified our oil and gas mineral rights held under
lease as tangible assets along with our other oil and gas properties, which is
in accordance with the Securities and Exchange Commission's ("SEC") full cost
accounting rules, and we intend to continue to do so until further guidance is
provided. We have estimated the amount associated with these mineral rights
using historical depletion rates, estimates of the timing of impairment of
unproved properties and assuming the cost for the mineral rights was unaffected
by the ceiling test write-down recorded in December 2001 because we cannot
associate the ceiling test write-down with particular types of costs. Based on
these limitations and assumptions, we estimate the net cost of mineral rights
that would be reclassified from oil and gas properties to intangible assets to
be approximately $55-60 million at December 31, 2003 and approximately $45-50
million at December 31, 2002. These amounts are from July 1, 2001 (the date we
adopted SFAS No. 141) to December 31, 2003 as we are not able to calculate
amounts to reclassify before that period as our property records did not break
out that information. Only our balance sheet accounts would be affected by the
reclassification, and our results of operations and cash flows would not be
materially impacted by any such reclassification. These mineral rights would
continue to be amortized in accordance with full cost accounting rules for oil
and gas companies provided in SEC Regulation S-X Rule 4-10. We also do not
believe classifying these assets as intangible would have any impact on our
compliance with covenants under our debt agreements.
In November 2002, the FASB issued Interpretation No. 45 "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others." This interpretation elaborates on the
disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has issued. It
also clarified that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligation undertaken in
issuing the guarantee. The initial recognition and initial measurement
provisions of this Interpretation are applicable on a prospective basis to
guarantees issued or modified after December 31, 2002, irrespective of the
guarantor's fiscal year-end. The Company adopted this pronouncement upon the
FASB's issuance and the implementation had no impact on the consolidated
financial statements.
In January 2003, the FASB issued Interpretation No. 46 (Revised December
2003), Consolidation of Variable Interest Entities, an Interpretation of
Accounting Research Bulletin No. 51 Consolidated Financial Statements (the
"Interpretation"). The Interpretation significantly changes whether entities
included in its scope are consolidated by their sponsors, transferors, or
investors. The Interpretation introduces a new consolidation model-the variable
interest model; which determines control (and consolidation) based on potential
variability in gains and losses of the entity being evaluated for consolidation.
The Interpretation provides guidance for determining whether an entity lacks
sufficient equity or its equity holders lack adequate decision-making ability.
These variable interest entities ("VIEs") are covered by the Interpretation and
are to be evaluated for consolidation based on their variable interests. These
provisions apply immediately to variable interests in VIEs created after January
31, 2003, and to variable interests in special purpose entities for periods
ending after December 15, 2003. The provisions apply for all other types of
variable interests in VIEs for periods ending after March 15, 2004. We have no
variable interests in VIEs created after January 31, 2003, nor do we have
variable interests in special purpose entities. The effect of applying the
Interpretation is to be reported as the cumulative effect of an accounting
change. We have not completed the process of evaluating the effects that will
result from adopting the Interpretation.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." This
statement sets standards for classifying and measuring certain financial
instruments with characteristics of both liabilities and equity. This statement
is effective for periods ending after December 15, 2003. The impact of
recognizing this statement was not material for the Company.
47
2. Earnings Per Share
Basic EPS has been computed using the weighted average number of common
shares outstanding during the respective periods. Diluted earnings per share for
all periods also assumes, as of the beginning of the period, exercise of stock
options using the treasury stock method. Certain of our stock options that would
potentially dilute Basic EPS in the future were also antidilutive for the 2003,
2002, and 2001 periods.
The following is a reconciliation of the numerators and denominators used
in the calculation of Basic and Diluted EPS for the years ended December 31,
2003, 2002, and 2001:
2003 2002 2001
-------------------------------- ---------------------------------- -----------------------------------
Net Share Net Per Share Net Per Share
Income Shares Amount Income Shares Amount Loss Shares Amount
----------- ---------- -------- ----------- ---------- --------- ------------ ---------- ---------
Basic EPS:
Net Income (Loss)
and Share Amounts $29,893,812 27,357,579 $ 1.09 $11,923,227 26,382,906 $ 0.45 $(22,347,765) 24,732,099 $ (0.90)
Dilutive
Securities:
Stock Options -- 203,360 -- 372,700 -- --
----------- ---------- ----------- ---------- --------- ------------ ----------
Diluted EPS:
Net Income (Loss)
and Assumed Share
Conversions $29,893,812 27,560,939 $ 1.08 $11,923,227 26,755,606 $ 0.45 $(22,347,765) 24,732,099 $ (0.90)
=========== ========== =========== ========== ========= ============ ==========
Options to purchase approximately 3.2 million shares at an average exercise
price of $16.37 were outstanding at December 31, 2003. Approximately 1.7
million, 1.3 million, and 0.8 million options to purchase shares were not
included in the computation of Diluted EPS for the year ended December 31, 2003,
2002, and 2001, respectively, because these options were antidilutive in that
the option price was greater than the average closing market price for the
common shares during those periods.
3. Provision for Income Taxes
Income before taxes is as follows:
Year Ended December 31,
----------------------------------------------------
2003 2002 2001
---------------- -------------- --------------
United States $ 38,955,404 $ 12,889,583 $ (35,427,252)
Foreign 11,783,773 5,518,706 1,234,919
---------------- -------------- --------------
Total $ 50,739,177 $ 18,408,289 $ (34,192,333)
================ ============== ==============
The following is an analysis of the consolidated income tax provision
(benefit):
Year Ended December 31,
----------------------------------------------------
2003 2002 2001
---------------- -------------- --------------
Current $ 164,284 $ 2,338 $ 114,611
---------------- -------------- --------------
Deferred - 14,386,868 4,870,239 (12,759,570)
Domestic- 1,917,362 1,612,485 407,523
---------------- -------------- --------------
Foreign
Total Deferred 16,304,230 6,482,724 (12,352,047)
---------------- -------------- --------------
Total $ 16,468,514 $ 6,485,062 $ (12,237,436)
================ ============== ==============
48
The differences between income taxes computed using the federal statutory
rate of 35% and our effective income tax rates (32.5%, 35.2%, and 35.8% for
2003, 2002, and 2001, respectively), are primarily the result of the currency
exchange rate effect on foreign deferred income taxes, state income taxes and
foreign income taxes (New Zealand's statutory rate is 33%). We have not computed
any provision for U.S. taxes on the undistributed earnings of our New Zealand
subsidiaries as management intends to permanently reinvest such earnings. Upon
distribution of these earnings in the form of dividends or otherwise, we may be
subject to U.S. income taxes and New Zealand withholding taxes. It is not
practical, however, to estimate the amount of taxes that may be payable on the
eventual remittance of these earnings. Presently, there are no foreign tax
credits available to reduce the U.S. taxes on such amounts if repatriated.
SENZ uses the U.S. Dollar as its functional currency for financial
reporting purposes, but income taxes are paid in the New Zealand Dollar. Because
of the difference in currencies used for financial reporting and tax, there is
potential for significant exchange impact on the tax provision calculation. Due
to the strengthening of the New Zealand Dollar vs. the U.S. Dollar in 2003, the
U.S. Dollar value of the deferred tax assets in New Zealand increased, resulting
in favorable adjustment of $2.9 million compared to the 33% New Zealand
statutory rate.
During 2003 the Company increased its provision for state income taxes by
$1.2 million, primarily due to its increased level of business activity in
Louisiana. The company calculates its Louisiana income tax using the
"apportionment" accounting method. Under apportionment accounting, total federal
taxable income is allocated based on the proportional level of U.S. business
activity within the state. Due to the relative increase in the Company's
domestic activity conducted in Louisiana, the Company increased its estimate of
future Louisiana taxable income that will result from the reversal of prior
years' timing differences.
Reconciliations of income taxes computed using the statutory rate to the
effective income tax rates are as follows:
2003 2002 2001
--------------- -------------- ---------------
Income taxes computed at U.S. statutory rate $ 17,758,712 $ 6,442,901 $ (11,967,317)
State tax provisions, net of federal benefits 373,992 323,902 (279,875)
Effect of foreign operations (235,675) (110,374) (24,698)
Currency remeasurement gain on foreign tax asset (2,893,655) (208,688) ---
Change in estimate for deferred Louisiana income
taxes 1,216,105 --- ---
Other, net 249,035 37,321 34,454
--------------- -------------- ---------------
Provision (benefit) for income taxes $ 16,468,514 $ 6,485,062 $ (12,237,436)
=============== ============== ===============
The tax effects of temporary differences representing the net deferred tax
liability (asset) at December 31, 2003 and 2002, were as follows:
2003 2002
---- ----
Deferred tax assets:
Alternative minimum tax credits (Domestic) $ (1,979,399) $ (1,979,399)
Carryover items (Domestic) (53,036,919) (51,174,237)
Acquired deferred tax asset (Foreign) (3,802,435) (4,753,044)
Carryover Items (Foreign) (28,294,320) (19,494,129)
------------ -------------
Total deferred tax assets $(87,113,073) $ (77,400,809)
------------ -------------
Deferred tax liabilities
Domestic oil and gas exploration and development costs $ 98,010,617 $ 83,361,520
Foreign oil and gas exploration and development costs 30,190,846 21,566,588
Other 504,383 568,634
------------ -------------
Total deferred tax liabilities $128,705,846 $ 105,496,742
------------ -------------
Net deferred tax liabilities $ 41,592,773 $ 28,095,933
============ =============
The tax basis of the assets of Southern NZ on the acquisition date exceeded
the cash purchase price paid by SENZ to acquire this entity. To account for the
future tax benefits of this additional basis, SENZ recorded a deferred tax asset
of $4.9 million. The asset is being amortized over the period in which the tax
amortization is deducted. The remaining asset value at December 31, 2003, is
$3.8 million. The other foreign carryover asset
49
is attributable to cumulative New Zealand net operating losses. New Zealand
tax net operating losses do not expire.
At December 31, 2003, the Company had alternative minimum tax credits of
$2.0 million that carry forward indefinitely. These credits are available to
reduce future regular tax liability to the extent they exceed the alternative
minimum tax otherwise due.
The domestic deferred tax carryover items are attributable to expected
future tax benefits in the amounts of $44.9 million for federal net operating
losses, $1.5 million for State of Louisiana net operating losses and $6.5
million for capital losses. At December 31, 2003, cumulative federal net
operating losses were $128.1 million, which will expire between 2018 and 2022.
Louisiana net operating losses total $44.1 million and will expire between 2013
and 2018.
The Company has not recorded any valuation allowance against the deferred
tax assets attributable to net operating loss carryovers at December 31, 2003
and 2002, as management estimates that it is more likely than not that these
assets will be fully utilized before they expire. Significant changes in
estimates caused by changes in oil and gas prices, production levels, capital
expenditures, and other variables could impact the Company's ability to utilize
the carryover amounts.
In 2002 we recognized a capital loss of approximately $18.6 million as the
result of the liquidation of our partnerships. This loss can only be utilized to
offset capital gains and will expire in 2007. The Company plans to sell a number
of oil and gas properties over the next few years in order to optimize its
portfolio of non-core oil and gas properties. To generate capital gains from
these dispositions, the sales proceeds must exceed the Company's total
investment in the properties. Company management has identified several
qualified properties it intends to sell that have estimated current market
values in excess of the total original costs. Management believes that it is
more likely than not that the Company will fully utilize the capital loss
carryover. If the Company is unable to complete the sale of these properties at
the prices it has estimated to be the fair market value, then a significant
portion of the capital loss carryover could expire before it is utilized.
4. Long-Term Debt
Our long-term debt as of December 31, 2003 and 2002, is as follows:
2003 2002
------------ -------------
Bank Borrowings $ 15,900,000 $ ---
Senior Notes due 2009 124,354,783 124,271,973
Senior Notes due 2012 200,000,000 200,000,000
------------ -------------
Long-Term Debt $ 340,254,783 $ 324,271,973
============ =============
Bank Borrowings. At December 31, 2003, we had $15.9 million in outstanding
borrowings under our $300.0 million credit facility with a syndicate of ten
banks that has a borrowing base of $250.0 million and expires in October 2005.
At December 31, 2002, we had no outstanding borrowings under our credit
facility. The interest rate is either (a) the lead bank's prime rate (4.00% at
December 31, 2003) or (b) the adjusted London Interbank Offered Rate ("LIBOR")
plus the applicable margin depending on the level of outstanding debt. The
applicable margin is based on the ratio of the outstanding balance to the last
calculated borrowing base. Of the $15.9 million borrowed at December 31, 2003,
$15.5 million was borrowed at the LIBOR rate plus applicable margin, which
averaged 2.41%.
The terms of our credit facility include, among other restrictions, a
limitation on the level of cash dividends (not to exceed $5.0 million in any
fiscal year), a remaining aggregate limitation on purchases of our stock of
$15.0 million, requirements as to maintenance of certain minimum financial
ratios (principally pertaining to working capital, debt, and equity ratios), and
limitations on incurring other debt or repurchasing our Senior Notes. Since
inception, no cash dividends have been declared on our common stock. We are
currently in compliance with the provisions of this agreement. The credit
facility is secured by our domestic oil and gas properties. We have also pledged
65% of the stock in our two active New Zealand subsidiaries as collateral for
this credit facility. The borrowing base is re-determined at least every six
months and was reconfirmed by our bank group and increased to $250.0 million
effective November 1, 2003, an increase of $55.0 million from the previous level
of $195.0 million. We requested that the commitment amount with our bank group
be reduced to $150.0 million effective May 9, 2003. Under the terms of the
credit facility, we can increase this commitment amount back to the total amount
of the borrowing base at our discretion, subject to the terms of the credit
agreement. The next scheduled borrowing base review is in May 2004.
50
Interest expense on the credit facility, including commitment fees and
amortization of debt issuance costs, totaled $1.6 million in 2003, $3.6 million
in 2002, and $5.8 million in 2001. The amount of commitment fees included in
interest expense was $0.6 million in both 2003 and 2002 and $0.3 million in
2001.
Senior Notes Due 2009. Our Senior Notes due 2009 consist of $125.0 million
of 10.25% Senior Subordinated Notes due August 2009. The Senior Notes were
issued at 99.236% of the principal amount on August 4, 1999, and will mature on
August 1, 2009. The Senior Notes are unsecured senior subordinated obligations
and are subordinated in right of payment to all our existing and future senior
debt, including our bank borrowings. Interest on the Senior Notes is payable
semiannually, on February 1 and August 1, and commenced with the first payment
on February 1, 2000. On or after August 1, 2004, the Senior Notes are redeemable
for cash at the option of Swift, with certain restrictions, at 105.125% of
principal, declining to 100% in 2007. Upon certain changes in control of Swift,
each holder of Senior Notes will have the right to require us to repurchase the
Senior Notes at a purchase price in cash equal to 101% of the principal amount,
plus accrued and unpaid interest to the date of purchase. The terms of these
Senior Notes include, among other restrictions, a limit on repurchases by Swift
of its common stock. We are currently in compliance with the provisions of the
indenture governing the Senior Notes.
Interest expense on the Senior Notes due 2009, including amortization of
debt issuance costs and discount, totaled $13.2 million in both 2003 and 2002,
and $13.1 million in 2001.
Senior Notes Due 2012. Our Senior Notes due 2012 consist of $200.0 million
of 9.375% Senior Subordinated Notes due May 2012. The Senior Notes were issued
on April 11, 2002, and will mature on May 1, 2012. The notes are unsecured
senior subordinated obligations and are subordinated in right of payment to all
our existing and future senior debt, including our bank debt. Interest on the
Senior Notes is payable semiannually on May 1 and November 1, with the first
interest payment on November 1, 2002. On or after May 1, 2007, the Senior Notes
are redeemable for cash at the option of Swift, with certain restrictions, at
104.688% of principal, declining to 100% in 2010. In addition, prior to May 1,
2005, we may redeem up to 33.33% of the Senior Notes with the proceeds of
qualified offerings of our equity at 109.375% of the principal amount of the
Senior Notes, together with accrued and unpaid interest. Upon certain changes in
control of Swift, each holder of Senior Notes will have the right to require us
to repurchase the Senior Notes at a purchase price in cash equal to 101% of the
principal amount, plus accrued and unpaid interest to the date of purchase. The
terms of these Senior Notes include, among other restrictions, a limit on
repurchases by Swift of its common stock. We are currently in compliance with
the provisions of the indenture governing the Senior Notes.
Interest expense on the Senior Notes due 2012, including amortization of
debt issuance costs and discount, totaled $19.1 million in 2003 and $13.5
million in 2002.
The aggregate maturities on our long-term debt are $0, $15.9 million, $0,
$0, and $0, and $325.0 million for 2004, 2005, 2006, 2007, 2008, and thereafter,
respectively.
We have capitalized interest on our unproved properties in the amount of
$6.8 million, $7.0 million, and $6.3 million, in 2003, 2002, and 2001,
respectively.
5. Commitments and Contingencies
Total rental and lease expenses were $2.2 million in 2003, $1.9 million in
2002, and $1.3 million in 2001 and are included in "General and administrative,
net" on our consolidated statements of income. Our remaining minimum annual
obligations under non-cancelable operating lease commitments are $2.1 million
for 2004, $0.5 million for 2005, $0.2 million for 2006, $0.2 million for 2007,
$0.1 million in 2008, and less than $0.1 million thereafter or $3.1 million in
the aggregate. The rental and lease expenses and remaining minimum annual
obligations under non-cancelable operating lease commitments primarily relate to
the lease of our office space in Houston, Texas, and in New Zealand.
In the ordinary course of business, we have entered into agreements with
pipeline operators that require us to contribute a portion of the pipeline
construction cost in the event certain transportation volumes are not met. We
have $0.1 million accrued in "Accounts payable and accrued liabilities" at
December 31, 2003, on the accompanying balance sheet related to these
commitments.
In the ordinary course of business, we have entered into agreements with
drilling and seismic contractors for such services. The remaining commitments at
December 31, 2003 for these services totaled $5.9 million and these services are
expected to be provided in 2004.
51
As of December 31, 2003, we were the managing general partner of six
limited partnerships. Because we serve as the general partner of these entities,
under state partnership law we are contingently liable for the liabilities of
these partnerships, which liabilities are not material for any of the periods
presented in relation to the partnerships' respective assets.
In the ordinary course of business, we have been party to various legal
actions, which arise primarily from our activities as operator of oil and gas
wells. In management's opinion, the outcome of any such currently pending legal
actions will not have a material adverse effect on the consolidated financial
position or results of operations of Swift.
6. Stockholders' Equity
Common Stock. During the first quarter of 2002, we issued 1.725 million
shares of common stock at a price of $18.25 per share. Gross proceeds from this
offering were $31.5 million, with issuance costs of $1.0 million.
Stock-Based Compensation Plans. We have two current stock option plans, the
2001 Omnibus Stock Compensation Plan, which was adopted by our board of
directors in February 2001 and was approved by shareholders at the 2001 annual
meeting of shareholders, and the 1990 Non-Qualified Stock Option Plan solely for
our independent directors. In addition, we have an employee stock purchase plan.
Under the 2001 plan, incentive stock options and other options and awards
may be granted to employees to purchase shares of common stock. Under the 1990
non-qualified plan, non-employee members of our board of directors are
automatically granted options to purchase shares of common stock on a formula
basis. Both plans provide that the exercise prices equal 100% of the fair value
of the common stock on the date of grant. Unless otherwise provided, options
become exercisable for 20% of the shares on the first anniversary of the grant
of the option and are exercisable for an additional 20% per year thereafter.
Options granted expire 10 years after the date of grant or earlier in the event
of the optionee's separation from employment. At the time the stock options are
exercised, the option price is credited to common stock and additional paid-in
capital.
The employee stock purchase plan provides eligible employees the
opportunity to acquire shares of Swift common stock at a discount through
payroll deductions. The plan year is from June 1 to the following May 31. The
first year of the plan commenced June 1, 1993. To date, employees have been
allowed to authorize payroll deductions of up to 10% of their base salary during
the plan year by making an election to participate prior to the start of a plan
year. The purchase price for stock acquired under the plan is 85% of the lower
of the closing price of our common stock as quoted on the New York Stock
Exchange at the beginning or end of the plan year or a date during the year
chosen by the participant. Under this plan for the last three years, we have
issued 56,574 shares at a price range of $6.80 to $11.85 in 2003, 9,801 shares
at a price of $12.47 in 2002, and 22,360 shares at a price of $21.41 in 2001.
The estimated weighted average fair value of shares issued under this plan, as
determined using the Black-Scholes option-pricing model, was $1.75 in 2003,
$1.92 in 2002, and $8.19 in 2001. As of December 31, 2003, 296,053 shares
remained available for issuance under this plan.
52
The following is a summary of our stock options under these plans as of
December 31, 2003, 2002, and 2001:
2003 2002 2001
------------------------ ------------------------ -----------------------------
Wtd. Avg. Wtd. Avg. Wtd. Avg.
Shares Exer. Price Shares Exer. Price Shares Exer. Price
----------- ----------- ---------- ----------- ------------- -------------
Options outstanding, beginning of period 3,018,505 $ 16.64 2,639,504 $ 17.44 2,076,593 $ 11.70
Options granted 504,014 $ 13.20 585,055 $ 12.32 747,073 $ 31.51
Options canceled (110,901) $ 21.02 (84,254) $ 23.37 (31,247) $ 14.09
Options exercised (173,007) $ 8.85 (121,800) $ 8.61 (152,915) $ 8.69
----------- ---------- -------------
Options outstanding, end of period 3,238,611 $ 16.37 3,018,505 $ 16.64 2,639,504 $ 17.44
=========== ========== =============
Options exercisable, end of period 1,714,789 $ 15.00 1,480,490 $ 13.71 1,181,141 $ 11.49
=========== ========== =============
Options available for future grant, end of
period 494,925 419,845 1,155,057
=========== ========== =============
Estimated weighted average fair value per
share of options granted during the year $6.93 $9.55 $20.68
=========== ========== =============
The following table summarizes information about stock options outstanding
at December 31, 2003:
Options Outstanding Options Exercisable
--------------------------------------- -------------------------
Range of Number Wtd. Avg. Wtd. Avg. Number Wtd. Avg.
Exercise Outstanding Remaining Exercise Exercisable Exercise
Prices at 12/31/03 Contractual Price At 12/31/03 Price
Life
------------------- -------------- ----------- ----------- ------------- -----------
$ 7.00 to $17.99 2,301,259 6.2 $ 11.04 1,224,119 $ 9.67
$18.00 to $28.99 246,111 4.7 $ 22.79 195,911 $ 22.88
$29.00 to $41.00 691,241 7.2 $ 31.82 294,759 $ 31.89
-------------- -------------
$ 7.00 to $41.00 3,238,611 6.3 $ 16.37 1,714,789 $ 15.00
============== =============
Employee Stock Ownership Plan. In 1996, we established an Employee Stock
Ownership Plan ("ESOP") effective January 1, 1996. All employees over the age of
21 with one year of service are participants. This plan has a five-year cliff
vesting, and service is recognized after the ESOP effective date. The ESOP is
designed to enable our employees to accumulate stock ownership. While there will
be no employee contributions, participants will receive an allocation of stock
that has been contributed by Swift. Compensation expense is reported when such
shares are released to employees. The plan may also acquire Swift common stock,
purchased at fair market value. The ESOP can borrow money from Swift to buy
Swift stock. Benefits will be paid in a lump sum or installments, and the
participants generally have the choice of receiving cash or stock. At December
31, 2003, 2002, and 2001, all of the ESOP compensation was earned. Our
contribution to the ESOP plan totaled $0.2 million for the years ended December
31, 2003, 2002, and 2001 and are recorded as "General and administrative, net"
on the accompanying consolidated statements of income.
Employee Savings Plan. We have a savings plan under Section 401(k) of the
Internal Revenue Code. Eligible employees may make voluntary contributions into
the 401(k) savings plan with Swift contributing on behalf of the eligible
employee an amount equal to 100% of the first 2% of compensation and 75% of the
next 4% of compensation based on the contributions made by the eligible
employees. Our contributions to the 401(k) savings plan were $0.6 million for
each of the years ended December 31, 2003, 2002, and 2001 and are recorded as
"General and administrative, net" on the accompanying consolidated statements of
income. The contributions in 2003, 2002, and 2001 were made all in common stock.
The shares of common stock contributed to the 401(k) savings plan totaled
34,280, 64,490, and 28,798 shares for the 2003, 2002, and 2001 contributions,
respectively.
Common Stock Repurchase Program. In March 1997, our board of directors
approved a common stock repurchase program that terminated as of June 30, 1999.
Under this program, we spent approximately $13.3 million to acquire 927,774
shares in the open market at an average cost of $14.34 per share. At December
31, 2003, 527,018 shares remain in treasury (net of 400,756 shares used to fund
ESOP, 401(k) contributions and acquisitions) with a total cost of $7.6 million
and are included in "Treasury stock held, at cost" on the balance sheet.
53
Shareholder Rights Plan. In August 1997, the board of directors declared a
dividend of one preferred share purchase right on each outstanding share of
Swift common stock. The rights are not currently exercisable but would become
exercisable if certain events occurred relating to any person or group acquiring
or attempting to acquire 15% or more of our outstanding shares of common stock.
Thereafter, upon certain triggers, each right not owned by an acquirer allows
its holder to purchase Swift securities with a market value of two times the
$150 exercise price.
7. Related-Party Transactions
We are the operator of a number of properties owned by our affiliated
limited partnerships and, accordingly, charge these entities operating fees. In
accordance with the partnership agreements, operating fees charged to the
partnerships in 2003, 2002, and 2001 totaled approximately $0.2 million, $0.3
million, and $1.0 million, respectively, and are recorded as reductions in
general and administrative expense and oil and gas production expense. We are
also reimbursed for direct, administrative, and overhead costs incurred in
conducting the business of the limited partnerships, which totaled approximately
$0.4 million, $1.0 million, and $3.1 million in 2003, 2002, and 2001,
respectively. In partnerships in which the limited partners have voted to sell
their remaining properties and liquidate their limited partnerships, we are also
reimbursed for direct, administrative, and overhead costs incurred in the
disposition of such properties, totaling less than $0.1 million, $0.5 million,
and $2.4 million in 2003, 2002, and 2001, respectively.
8. Foreign Activities
As of December 31, 2003, our gross capitalized oil and gas property costs
in New Zealand totaled approximately $205.3 million. Approximately $169.5
million has been included in the proved properties portion of our oil and gas
properties, while $35.8 million is included as unproved properties. Our
functional currency in New Zealand is the U.S. Dollar.
9. Acquisitions and Dispositions
New Zealand
Through our subsidiary, Swift Energy New Zealand Limited ("SENZ"), we
acquired Southern Petroleum (NZ) Exploration Limited ("Southern NZ") in January
2002 for approximately $51.4 million in cash. We allocated $36.1 million of the
acquisition price to "Proved properties," $10.0 million to "Unproved
properties," $4.9 million to "Deferred income taxes," and $0.4 million to "Other
current assets" on our Consolidated Balance Sheet. Southern NZ was an affiliate
of Shell New Zealand and owns interests in four onshore producing oil and gas
fields, hydrocarbon processing facilities, and pipelines connecting the fields
and facilities to export terminals and markets. These assets fit strategically
with our existing assets in New Zealand. This acquisition was accounted for by
the purchase method of accounting. The revenues and expenses from these TAWN
properties have been included in our consolidated statements of income from the
date of acquisition forward. In conjunction with this TAWN acquisition, we
granted Shell New Zealand a short-term option to acquire an undivided 25%
interest in our permit 38719, which included our Rimu and Kauri areas and the
Rimu Production Station. This option was not exercised and expired on May 15,
2002.
In March 2002, we purchased through our subsidiary, SENZ, all of the New
Zealand assets owned by Antrim for 220,000 shares of Swift Energy common stock
valued at $4.2 million and an effective date adjustment of approximately $0.5
million for total consideration of $4.7 million. Antrim owned a 5% interest in
permit 38719 and a 7.5% interest in permit 38716.
In September 2002, we purchased through our subsidiary, SENZ, Bligh's 5%
working interest in permit 38719 and 5% interest in the Rimu petroleum mining
permit 38151, along with their 3.24% working interest in the four TAWN petroleum
mining licenses for 300,000 shares of Swift Energy common stock valued at $3.9
million and $2.7 million in cash for total consideration of $6.6 million.
54
Russia
In 1993, we entered into a Participation Agreement with Senega, a Russian
Federation joint stock company, to assist in the development and production of
reserves from two fields in Western Siberia and received a 5% net profits
interest. We also purchased a 1% net profits interest. Our investment in Russia
was fully impaired in the third quarter of 1998. In March 2002, we received $7.5
million for our investment in Russia. Although the proceeds from sales of oil
and gas properties are generally treated as a reduction of oil and gas property
costs, because we had previously charged to expense all $10.8 million of
cumulative costs relating to our Russian activities, this cash payment, net of
transaction expenses, resulted in recognition of a $7.3 million non-recurring
gain on asset disposition in the first quarter of 2002.
55
10. Segment Information
The Company has two reportable segments that are in the business of crude
oil and natural gas exploration and production. The accounting policies of the
segments are the same as those described in the summary of significant
accounting policies. The Company evaluates performance based on profit or loss
from oil and gas operations before other revenues, general and administrative
expenses, and interest expense, net. The Company's reportable segments are
managed separately based on their geographic locations. Financial information by
operating segment is presented below:
2003
--------------------------------------------
New
Domestic Zealand Total
------------- ------------- -------------
Oil and gas sales $ 164,167,390 $ 46,865,249 $ 211,032,639
Costs and Expenses:
Depreciation, depletion, and
amortization (44,645,939) (18,426,118) (63,072,057)
Accretion of asset retirement
obligation (623,948) (233,408) (857,356)
Oil and gas production (39,313,081) (13,553,721) (52,866,802)
------------- ------------- -------------
Income from oil and gas operations $ 79,584,422 $ 14,652,002 $ 94,236,424
Other revenues (1) (2,131,656)
General and administrative, net (14,097,066)
Interest expense, net (27,268,524)
-------------
Income before Income Taxes and
Cumulative Effect of Change in
Accounting Principle $ 50,739,178
=============
Property and Equipment, net $ 642,019,661 $ 174,440,115 $ 816,459,776
============= ============= =============
2002
--------------------------------------------
New
Domestic Zealand Total
------------- ------------- -------------
Oil and gas sales $ 112,065,003 $ 29,130,710 $ 141,195,713
Costs and Expenses:
Depreciation, depletion, and
amortization (43,660,843) (12,563,549) (56,224,392)
Oil and gas production (33,088,958) (8,408,354) (41,497,312)
------------- ------------- -------------
Income from oil and gas operations $ 35,315,202 $ 8,158,807 $ 43,474,009
Other revenues (1) 8,774,098
General and administrative, net (10,564,849)
Interest expense, net (23,274,969)
------------
Income before Income Taxes and
Cumulative Effect of Change in
Accounting Principle $ 18,408,289
=============
Property and Equipment, net $ 565,149,393 $ 160,360,061 $ 725,509,454
============= ============= =============
56
2001
--------------------------------------------
(Unaudited) (Unaudited)
New
Domestic Zealand Total
------------- ------------- ------------
Oil and gas sales $ 179,360,844 $ 1,823,791 $ 181,184,635
Costs and Expenses:
Depreciation, depletion, and
amortization (59,318,768) (183,272) (59,502,040)
Oil and gas production (36,554,418) (165,191) (36,719,609)
Write-down of oil and gas
properties (98,862,247) --- (98,862,247)
------------- ------------- ------------
Income from oil and gas operations $ (15,374,589) $ 1,475,328 $ (13,899,261)
Other revenues (1) 2,622,855
General and administrative, net (8,186,654)
Other expenses (2,102,251)
Interest expense, net (12,627,022)
-------------
Income before Income Taxes and
Cumulative
Effect of Change in Accounting $ (34,192,333)
Principle
=============
Property and Equipment, net $ 547,232,724 $ 83,975,947 $ 631,208,671
============= ============= =============
(1) Other revenues consist of Fees from affiliated limited partnerships,
Interest income, Gain on asset disposition, Price-risk management and other,
net, on the accompanying consolidated statements of income.
57
Supplemental Information (Unaudited)
Swift Energy Company and Subsidiaries
Capitalized Costs. The following table presents our aggregate capitalized
costs relating to oil and gas producing activities and the related depreciation,
depletion, and amortization:
Total Domestic New Zealand
==================== ================ ================
December 31, 2003:
Proved oil and gas properties $ 1,305,763,355 $ 1,136,267,890 $ 169,495,465
Unproved oil and gas properties 67,557,969 31,802,621 35,755,348
-------------------- ---------------- ----------------
1,373,321,324 1,168,070,511 205,250,813
Accumulated depreciation, depletion, and amortization (560,961,013) (529,272,658) (31,688,355)
-------------------- ---------------- ----------------
Net capitalized costs $ 812,360,311 $ 638,797,853 $ 173,562,458
==================== ================ ================
December 31, 2002:
Proved oil and gas properties $ 1,150,633,802 $ 1,005,583,492 $ 145,050,310
Unproved oil and gas properties 69,603,481 41,850,890 27,752,591
-------------------- ---------------- ----------------
1,220,237,283 1,047,434,382 172,802,901
Accumulated depreciation, depletion, and amortization (498,619,342) (485,289,654) (13,329,688)
-------------------- ---------------- ----------------
Net capitalized costs $ 721,617,941 $ 562,144,728 $ 159,473,213
==================== ================ ================
Of the $31,802,621 of domestic unproved property costs (primarily seismic
and lease acquisition costs) at December 31, 2003, excluded from the amortizable
base, $8,350,017 was incurred in 2003, $7,952,698 was incurred in 2002,
$7,294,531 was incurred in 2001, and $8,205,375 was incurred in prior years.
When we are in an active drilling mode, we evaluate the majority of these
unproved costs within a two to four year time frame.
Of the $35,755,348 of New Zealand unproved property costs at December 31,
2003, excluded from the amortizable base, $9,309,694 was incurred in 2003,
$17,593,162 was incurred or acquired in 2002, $2,644,091 was incurred in 2001,
and $6,208,401 was incurred in prior years. We expect to continue drilling in
New Zealand to delineate our prospects there within a two to four year time
frame.
Capitalized asset retirement obligations have been included in the proved
properties as of December 31, 2003, as we adopted SFAS No. 143 "Accounting for
Asset Retirement Obligations" effective January 1, 2003.
58
Costs Incurred. The following table sets forth costs incurred related to
our oil and gas operations:
Year Ended December 31, 2003
----------------------------------------------------------
Total Domestic New Zealand
-------------------- ---------------- ----------------
Acquisition of proved properties $ 1,942,868 $ 1,635,316 $ 307,552
Lease acquisitions1 18,869,099 12,440,144 6,428,955
Exploration 14,467,455 11,789,700 2,677,755
Development 116,451,112 100,549,351 15,901,761
-------------------- ---------------- ----------------
Total acquisition, exploration, and development 2 $ 151,730,534 $ 126,414,511 $ 25,316,023
-------------------- ---------------- ----------------
Processing plants $ 6,192,199 $ 907,771 $ 5,284,428
Field compression facilities 3,521,522 3,521,522 --
-------------------- ---------------- ----------------
Total plants and facilities $ 9,713,721 $ 4,429,293 $ 5,284,428
-------------------- ---------------- ----------------
Total costs incurred3 $ 161,444,255 $ 130,843,804 $ 30,600,451
==================== ================ ================
Year Ended December 31, 2002
----------------------------------------------------------
Total Domestic New Zealand
-------------------- ---------------- ----------------
Acquisition of proved properties $ 64,229,283 $ 5,415,932 $ 58,813,351
Lease acquisitions1 16,009,939 10,789,876 5,220,063
Exploration 18,395,335 7,571,215 10,824,120
Development 47,407,087 40,366,378 7,040,709
-------------------- ---------------- ----------------
Total acquisition, exploration, and development 2 $ 146,041,644 $ 64,143,401 $ 81,898,243
-------------------- ---------------- ----------------
Processing plants $ 7,845,520 $ 1,313,299 $ 6,532,221
Field compression facilities 2,251,247 2,251,247 --
-------------------- ---------------- ----------------
Total plants and facilities $ 10,096,767 $ 3,564,546 $ 6,532,221
-------------------- ---------------- ----------------
Total costs incurred $ 156,138,411 $ 67,707,947 $ 88,430,464
==================== ================ ================
Year Ended December 31, 2001
----------------------------------------------------------
Total Domestic New Zealand
-------------------- ---------------- ----------------
Acquisition of proved properties $ 41,286,539 $ 40,491,203 $ 795,336
Lease acquisitions1 31,225,493 25,688,068 5,537,425
Exploration 41,981,536 35,944,405 6,037,131
Development 132,246,713 112,597,856 19,648,857
-------------------- ---------------- ----------------
Total acquisition, exploration, and development 2 $ 246,740,281 $ 214,721,532 $ 32,018,749
-------------------- ---------------- ----------------
Processing plants $ 23,331,095 $ 817,454 $ 22,513,641
Field compression facilities 319,703 319,703 --
-------------------- ---------------- ----------------
Total plants and facilities $ 23,650,798 $ 1,137,157 $ 22,513,641
-------------------- ---------------- ----------------
Total costs incurred $ 270,391,079 $ 215,858,689 $ 54,532,390
==================== ================ ================
1 These are actual amounts as incurred by year, including both proved and
unproved lease costs. The annual lease acquisition amounts added to proved oil
and gas properties in 2003, 2002, and 2001 were $20,702,276, $23,454,234, and
$22,470,263, respectively.
2 Includes capitalized general and administrative costs directly associated with
the acquisition, exploration, and development efforts of approximately $11.5
million, $10.7 million, and $11.6 million in 2003, 2002, and 2001, respectively.
In addition, total includes $6.9 million, $7.0, and $6.3 million in 2003, 2002,
and 2001, respectively, of capitalized interest on unproved properties.
59
3 Asset retirement obligations incurred during 2003 have been included in
exploration and development costs as applicable for the year ended December 31,
2003, as we adopted SFAS No. 143 "Accounting for Asset Retirement Obligations"
effective January 1, 2003.
Results of Operations.
Year Ended December 31, 2003
---------------------------------------------------
Total Domestic New Zealand
---------------- --------------- ----------------
Oil and gas sales $ 211,032,639 $ 164,167,390 $ 46,865,249
Oil and gas production costs (52,866,802) (39,313,081) (13,553,721)
Depreciation and depletion (62,037,680) (43,818,709) (18,218,971)
Accretion of asset retirement obligation (857,356) (623,948) (233,408)
---------------- --------------- ----------------
95,270,801 80,411,652 14,859,149
Provision for income taxes 32,321,635 29,696,023 2,625,612
---------------- --------------- ----------------
Results of producing activities $ 62,949,166 $ 50,715,629 $ 12,233,537
================ =============== ================
Amortization per physical unit of production
(equivalent Mcf of gas) $ 1.17 $ 1.30 $ 0.94
================ =============== ================
Year Ended December 31, 2002
---------------------------------------------------
Total Domestic New Zealand
---------------- --------------- ----------------
Oil and gas sales $ 141,195,713 $ 112,065,003 $ 29,130,710
Oil and gas production costs (41,497,312) (33,088,958) (8,408,354)
Depreciation and depletion (55,254,467) (42,807,364) (12,447,103)
---------------- --------------- ----------------
44,443,934 36,168,681 8,275,253
Provision for income taxes 15,860,064 13,129,231 2,730,833
---------------- --------------- ----------------
Results of producing activities $ 28,583,870 $ 23,039,450 $ 5,544,420
================ =============== ================
Amortization per physical unit of production
(equivalent Mcf of gas) $ 1.11 $ 1.25 $ 0.80
================ =============== ================
Year Ended December 31, 2001
---------------------------------------------------
Total Domestic New Zealand
---------------- --------------- ----------------
Oil and gas sales $ 181,184,635 $ 179,360,844 $ 1,823,791
Oil and gas production costs (36,719,609) (36,554,418) (165,191)
Depreciation and depletion (58,589,116) (58,417,637) (171,479)
Write-down of oil and gas properties (98,862,247) (98,862,247) --
---------------- --------------- ----------------
(12,986,337) (14,473,458) 1,487,121
---------------- --------------- ----------------
Provision (benefit) for income taxes $ (4,647,810) (5,138,560) 490,750
================ =============== ================
Results of producing activities (8,338,527) $ (9,334,898) $ 996,371
Amortization per physical unit of production
(equivalent Mcf of gas) $ 1.31 1.32 0.34
================ =============== ================
These results of operations do not include the losses (gains) from our
hedging activities of $2.8 million, $0.2 million and ($1.2) million for 2003,
2002 and 2001, respectively.
The accretion of asset retirement obligation has been included in the 2003
period, as we adopted SFAS No. 143 "Accounting for Asset Retirement Obligations"
effective January 1, 2003.
We used our effective tax rate in each country to compute the provision for
income taxes in each year presented.
60
Supplemental Reserve Information. The following information presents estimates
of our proved oil and gas reserves. Reserves were determined by us and audited
by H. J. Gruy and Associates, Inc. ("Gruy"), independent petroleum consultants.
Gruy's audit was conducted according to standards approved by the Board of
Directors of the Society of Petroleum Engineers, Inc. and included examination,
on a test basis, of the evidence supporting our reserves. Gruy's audit was based
upon review of production histories and other geological, economic, and
engineering data provided by Swift. Where Gruy had material disagreements with
Swift reserve estimates, we revised our estimates to be in agreement. Gruy's
report dated January 23, 2004, is set forth as an exhibit to the Form 10-K
Report for the year ended December 31, 2003, and includes definitions and
assumptions that served as the basis for the audit of proved reserves and future
net cash flows. Such definitions and assumptions should be referred to in
connection with the following information:
Estimates of Proved Reserves
Total Domestic New Zealand
------------------------- ----------------------------- ------------------------
Oil, NGL, Oil, NGL, Oil, NGL,
and and and
Natural Gas Condensate Natural Gas Condensate Natural Gas Condensate
(Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls)
------------- ----------- ------------- ------------ ------------ -----------
Proved reserves as of December 31, 2000 418,613,976 35,133,596 363,300,499 23,942,709 55,313,477 1,190,887
Revisions of previous estimates1 (122,127,541) 5,621,556 (101,693,477) 8,460,690 (20,434,064) (2,839,134)
Purchases of minerals in place 10,038,803 7,430,591 10,038,803 7,430,591 -- --
Sales of minerals in place (7,508,064) (555,586) (7,508,064) (555,586) -- --
Extensions, discoveries, and other
additions 52,353,909 8,907,852 50,810,697 6,257,441 1,543,212 2,650,411
Production (26,458,958) (3,055,373) (26,458,958) (2,971,112) -- (84,261)
------------ ------------ -------------- ------------ ------------ -----------
Proved reserves as of December 31, 2001 324,912,125 53,482,636 288,489,500 42,564,733 36,422,625 10,917,903
Revisions of previous estimates1 (29,972,714) 5,298,439 (29,470,419) 8,675,082 (502,295) (3,376,643)
Purchases of minerals in place 51,940,044 3,711,948 226,245 24,207 51,713,799 3,687,741
Sales of minerals in place (3,839,124) (464,490) (3,839,124) (464,490) -- --
Extensions, discoveries, and other
additions 10,822,919 12,180,558 197,919 11,304,782 10,625,000 875,776
Production (27,131,578) (3,770,128) (15,780,059) (3,074,674) (11,351,519) (695,454)
------------ ----------- -------------- ------------ ------------ -----------
Proved reserves as of December 31, 2002 326,731,672 70,438,963 239,824,062 59,029,640 86,907,610 11,409,323
Revisions of previous estimates1 (6,445,114) 4,975,920 (1,418,312) 3,497,022 (5,026,802) 1,478,898
Purchases of minerals in place 273,623 35,472 273,623 35,472 -- --
Sales of minerals in place (3,984,209) (228,505) (3,984,209) (228,505) -- --
Extensions, discoveries, and other
additions 47,231,609 9,730,665 21,370,151 8,018,766 25,861,458 1,711,899
Production (28,002,719) (4,192,612) (13,744,040) (3,336,702) (14,258,679) (855,910)
------------ ----------- ------------- ------------ ------------ -----------
Proved reserves as of December 31, 2003 335,804,862 80,759,903 242,321,275 67,015,693 93,483,587 13,744,210
============ =========== ============= ============ ============ ===========
Proved developed reserves: 2
December 31, 2000 215,169,833 10,980,196 215,169,833 10,980,196 -- --
December 31, 2001 181,651,578 23,759,574 167,401,736 20,393,142 14,249,842 3,366,432
December 31, 2002 233,514,572 35,928,395 149,731,562 26,530,112 83,783,010 9,398,283
December 31, 2003 210,119,927 45,525,366 138,173,341 38,767,983 71,946,586 6,757,383
1 Revisions of previous estimates are related to upward or downward variations
based on current engineering information for production rates, volumetrics, and
reservoir pressure. Additionally, changes in quantity estimates are affected by
the increase or decrease in crude oil, NGL, and natural gas prices at each
year-end. Proved reserves, as of December 31, 2003, were based upon hedge
adjusted prices in effect at year-end. Our hedges at year-end 2003 consisted of
natural gas price floors with strike prices lower than the period end price and
thus did not affect prices used in these calculations. The weighted average of
2003 year-end prices for total, domestic, and New Zealand were $4.56, $5.53, and
$2.04 per Mcf of natural gas, $30.16, $30.88, and $26.78 per barrel of oil, and
$20.61, $21.81 and $14.10 per barrel of NGL, respectively. This compares to
$3.49, $4.23, and $1.48 per Mcf, $29.27, $29.36, and $28.80 per barrel of oil,
and $16.54, $17.30 and $12.24 per barrel of NGL as of December 31, 2002, for
total, domestic, and New Zealand, respectively. The weighted average of 2001
year-end prices for total, domestic, and New Zealand were $2.51, $2.68, and
$1.18 per Mcf of natural gas, $18.45, $18.51, and $18.25 per barrel of oil, and
$10.70, $11.00, and $8.90 per barrel of NGL, respectively.
2 At December 31, 2003, 59% of our reserves were proved developed, compared to
60% at December 31, 2002, 50% at December 31, 2001, and 45% at December 31,
2000.
61
Standardized Measure of Discounted Future Net Cash Flows. The standardized
measure of discounted future net cash flows relating to proved oil and gas
reserves is as follows:
Year Ended December 31, 2003
---------------------------------------------------------
Total Domestic New Zealand
----------------- ----------------- -----------------
Future gross revenues $ 3,805,349,886 $ 3,279,884,680 $ 525,465,206
Future production costs (831,430,479) (678,983,441) (152,447,038)
Future development costs (331,816,723) (301,874,087) (29,942,636)
----------------- ----------------- -----------------
Future net cash flows before income taxes 2,642,102,684 2,299,027,152 343,075,532
Future income taxes (729,624,048) (657,354,849) (72,269,199)
----------------- ----------------- -----------------
Future net cash flows after income taxes 1,912,478,636 1,641,672,303 270,806,333
Discount at 10% per annum (777,622,101) (678,769,827) (98,852,274)
----------------- ----------------- -----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 1,134,856,535 $ 962,902,476 $ 171,954,059
================= ================= =================
Year Ended December 31, 2002
---------------------------------------------------------
Total Domestic New Zealand
----------------- ----------------- -----------------
Future gross revenues $ 2,990,669,570 $ 2,578,435,576 $ 412,233,994
Future production costs (720,599,745) (612,094,088) (108,505,657)
Future development costs (224,792,520) (208,492,520) (16,300,000)
----------------- ----------------- -----------------
Future net cash flows before income taxes 2,045,277,305 1,757,848,968 287,428,337
Future income taxes (599,195,484) (512,966,321) (86,229,163)
----------------- ----------------- -----------------
Future net cash flows after income taxes 1,446,081,821 1,244,882,647 201,199,174
Discount at 10% per annum (609,212,030) (540,375,347) (68,836,683)
----------------- ----------------- -----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 836,869,791 $ 704,507,300 $ 132,362,491
================= ================= =================
Year Ended December 31, 2001
---------------------------------------------------------
Total Domestic New Zealand
----------------- ----------------- -----------------
Future gross revenues $ 1,706,475,138 $ 1,485,480,927 $ 220,994,211
Future production costs (483,588,857) (436,141,429) (47,447,428)
Future development costs (198,172,628) (185,347,628) (12,825,000)
----------------- ----------------- -----------------
Future net cash flows before income taxes 1,024,713,653 863,991,870 160,721,783
Future income taxes (261,635,331) (208,726,729) (52,908,602)
----------------- ----------------- -----------------
Future net cash flows after income taxes 763,078,322 655,265,141 107,813,181
Discount at 10% per annum (308,520,417) (274,882,174) (33,638,243)
----------------- ----------------- -----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 454,557,905 $ 380,382,967 $ 74,174,938
================= ================= =================
The standardized measure of discounted future net cash flows from
production of proved reserves was developed as follows:
1. Estimates are made of quantities of proved reserves and the future
periods during which they are expected to be produced based on year-end economic
conditions.
2. The estimated future gross revenues of proved reserves are priced on the
basis of year-end prices, except in those instances where fixed and determinable
gas price escalations are covered by contracts limited to the price we
reasonably expect to receive.
62
3. The future gross revenue streams are reduced by estimated future costs
to develop and to produce the proved reserves, as well as asset retirement
obligation costs, net of salvage value, based on year-end cost estimates and the
estimated effect of future income taxes.
4. Future income taxes are computed by applying the statutory tax rate to
future net cash flows reduced by the tax basis of the properties, the estimated
permanent differences applicable to future oil and gas producing activities, and
tax carry forwards.
The estimates of cash flows and reserves quantities shown above are based
on year-end hedge adjusted oil and gas prices for each period and do not include
the effects of our hedging activities. Our hedges at year-end 2003 consisted of
natural gas price floors with strike prices lower than the period end price and
thus did not affect prices used in these calculations. Subsequent changes to
such year-end oil and gas prices could have a significant impact on discounted
future net cash flows. Under Securities and Exchange Commission rules, companies
that follow the full-cost accounting method are required to make quarterly
Ceiling Test calculations using hedge adjusted prices in effect as of the period
end date presented (see Note 1 to the Consolidated Financial Statements).
Application of these rules during periods of relatively low oil and gas prices,
even if of short-term seasonal duration, may result in non-cash write-downs.
The standardized measure of discounted future net cash flows is not
intended to present the fair market value of our oil and gas property reserves.
An estimate of fair value would also take into account, among other things, the
recovery of reserves in excess of proved reserves, anticipated future changes in
prices and costs, an allowance for return on investment, and the risks inherent
in reserves estimates.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
Year Ended December 31,
---------------------------------------------------------
2003 2002 2001
------------------ ------------------ -----------------
Beginning balance $ 836,869,791 $ 454,557,905 $ 1,577,958,466
------------------ ------------------ -----------------
Revisions to reserves proved in prior years--
Net changes in prices, production costs,
and future development costs 109,501,730 373,890,614 (1,692,627,074)
Net changes due to revisions in quantity
estimates 48,194,999 2,582,633 (93,669,181)
Accretion of discount 116,136,717 60,298,619 231,325,481
Other (57,822,716) (88,675,455) (204,768,815)
------------------ ------------------ -----------------
Total revisions 216,010,730 348,096,411 (1,759,739,589)
New field discoveries and extensions, net of future
production and development costs 243,183,114 190,461,371 110,213,160
Purchases of minerals in place 1,019,290 76,538,437 39,544,163
Sales of minerals in place (13,660,012) (5,769,642) (50,131,970)
Sales of oil and gas produced, net of production
costs (158,165,836) (99,698,403) (144,262,145)
Previously estimated development costs incurred 77,404,994 48,752,814 94,107,760
Net change in income taxes (67,805,536) (176,069,102) 586,868,060
------------------ ------------------ -----------------
Net change in standardized measure of discounted
future net cash flows 297,986,744 382,311,886 (1,123,400,561)
------------------ ------------------ -----------------
Ending balance $ 1,134,856,535 $ 836,869,791 $ 454,557,905
================== ================== =================
63
Quarterly Data (Unaudited). The following table presents summarized
quarterly financial information for the years ended December 31, 2002 and 2003:
Income
Before
Income Taxes, Income Basic EPS Diluted EPS
and Before Income Before Income Before Basic Diluted
Change in Change in Change In Change In EPS EPS
Accounting Accounting Net Accounting Accounting Net Net
Revenues Principle(b) Principle(b) Income Principle(b) Principle(b) Income Income
------------ ------------- ------------- ------------- ----------------- ------------------ --------- ---------
2002:
First a $ 34,354,077 $ 4,674,075 $ 3,019,810 $ 3,019,810 $ 0.12 $ 0.12 $ 0.12 $ 0.12
Second 38,570,269 5,518,886 3,584,092 3,584,092 0.13 0.13 0.13 0.13
Third 36,570,809 2,933,350 1,947,006 1,947,006 0.07 0.07 0.07 0.07
Fourth 40,474,656 5,281,978 3,372,319 3,372,319 0.12 0.12 0.12 0.12
------------ ------------- ------------- -------------
Total $149,969,811 $ 18,408,289 $ 11,923,227 $ 11,923,227 $ 0.45 $ 0.45 $ 0.45 $ 0.45
============ ============= ============= =============
2003:
First $ 53,499,993 $ 16,223,744 $ 10,484,937 $ 6,108,085 $ 0.38 $ 0.38 $ 0.22 $ 0.22
Second 50,717,529 11,073,804 7,221,426 7,221,426 0.26 0.26 0.26 0.26
Third 51,552,522 11,153,368 7,062,625 7,062,625 0.26 0.26 0.26 0.26
Fourth 53,130,939 12,288,262 9,501,676 9,501,676 0.35 0.34 0.35 0.34
------------ ------------- ------------- -------------
Total $208,900,983 $ 50,739,178 $ 34,270,664 $ 29,893,812 $ 1.25 $ 1.24 $ 1.09 $ 1.08
============ ============= ============= =============
a First quarter 2002 results include a gain on asset disposition of $7,332,668.
bThere were no extraordinary items in 2002 or 2003.
The sum of the individual quarterly net income per common share amounts may not
agree with year-to-date net income per common share as each quarterly
computation is based on the weighted average number of common shares outstanding
during that period. In addition, certain potentially dilutive securities were
not included in certain of the quarterly computations of diluted net income per
common share because to do so would have been antidilutive.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
We have had no changes in or disagreements with our independent accountants
since our Board of Directors' June 12, 2002 appointment, based upon the
recommendation of our Audit Committee, of Ernst & Young LLP as Swift's
independent auditors for the fiscal year ended December 31, 2002, replacing
Arthur Andersen LLP as our independent auditors. That change was reported by
Swift in a Current Report on Form 8-K dated June 12, 2002, filed with the SEC on
June 18, 2002.
A copy of the previously issued report dated February 18, 2002 of Arthur
Andersen LLP on the consolidated financial statements of the Company as of
December 31, 2001 and 2000 and for each of the three years ended December 31,
2001 is included in this Form 10-K Report for the year ended December 31, 2003,
but such previously issued report has not been reissued.
Item 9A. Controls and Procedures
The Company's chief executive officer and chief financial officer have
evaluated the Company's disclosure controls and procedures, as defined in Rules
13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the "Exchange
Act") as of the end of the period covered by the report. Based on that
evaluation, they have concluded that such disclosure controls and procedures are
effective in alerting them on a timely basis to material information relating to
the Company required under the Exchange Act to be disclosed in this report.
There were no significant changes in the Company's internal controls that could
significantly affect such controls subsequent to the date of their evaluation.
64
PART III
Item 10. Directors and Executive Officers of the Registrant
The information required under Item 10 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 11, 2004, annual shareholders'
meeting is incorporated herein by reference.
Item 11. Executive Compensation
The information required under Item 11 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 11, 2004, annual shareholders'
meeting is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information required under Item 12 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 11, 2004, annual shareholders'
meeting is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions
The information required under Item 13 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 11, 2004, annual shareholders'
meeting is incorporated herein by reference.
Item 14. Principal Accountant Fees and Services
The information required under Item 14 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 11, 2004, annual shareholders'
meeting is incorporated by reference.
65
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. The following consolidated financial statements of Swift Energy
Company together with the report thereon of Ernst & Young LLP dated
February 10, 2004, and the data contained therein are included in Item 8
hereof:
Report of Independent Auditors.............................34
Report of Independent Public Accountants...................35
Consolidated Balance Sheets................................36
Consolidated Statements of Income..........................37
Consolidated Statements of Stockholders' Equity............38
Consolidated Statements of Cash Flows......................39
Notes to Consolidated Financial Statements.................40
2. Financial Statement Schedules
[None]
3. Exhibits
EXHIBITS
3(a)1 Amended and Restated Articles of Incorporation of Swift
Energy Company.
3(b)12 Second Amended and Restated Bylaws of Swift Energy
Company, as amended through November 5, 2002.
4(a).12 Indenture dated as of July 29, 1999, between Swift Energy
Company and Bank One, N.A., as Trustee.
4(a).23 First Supplemental Indenture dated as of August 4, 1999,
between Swift Energy Company and Bank One, N.A., including
the form of 10.25% Senior Subordinated Notes due 2009.
4(a).34 Indenture dated as of April 16, 2002, between Swift Energy
Company and Bank One, N.A., as Trustee.
4(a).45 First Supplemental Indenture dated as of April 16, 2002,
between Swift Energy Company and Bank One, N.A., including
the form of 9 3/8% Senior Subordinated Notes due 2012.
10.113 Indemnity Agreement dated July 8, 1988, between Swift
Energy Company and A. Earl Swift (plus schedule of other
persons with whom Indemnity Agreements have been entered
into).
10.26 + Amended and Restated Swift Energy Company 1990
Nonqualified Stock Option Plan, as of May 1997.
10.36 + Amended and Restated Swift Energy Company 1990 Stock
Compensation Plan, as of May 1997.
10.47 + Amendment to the Swift Energy Company 1990 Stock
Compensation, as of May 9, 2002.
10.57 + Swift Energy Company 2001 Omnibus Stock Compensation Plan
10.68 + Amended and Restated Employment Agreement dated as of
May 9, 2001 between Swift Energy Company and A. Earl
Swift.
10.71 + Amended and Restated Employment Agreement dated as of May
9, 2001 between Swift Energy Company and Terry E. Swift.
10.81 + Amended and Restated Employment Agreement dated as of May
9, 2001 between Swift Energy Company and James M.
Kitterman.
10.91 + Amended and Restated Employment Agreement dated as of May
9, 2001 between Swift Energy Company and Bruce H. Vincent.
10.101 + Amended and Restated Employment Agreement dated as of May
9, 2001 between Swift Energy Company and Joseph A.
D'Amico.
66
10.111 + Employment Agreement dated as of May 9, 2001 between Swift
Energy Company and Victor R. Moran.
10.131 + Amended and Restated Employment Agreement dated as of
May 9, 2001 between Swift Energy Company and Alton D.
Heckaman, Jr.
10.148 + Fourth Amended and Restated Agreement and Release, by and
between Swift Energy Company and Virgil Neil Swift, dated
November 20, 2000.
10.159 Amended and Restated Rights Agreement between Swift Energy
and American Stock Transfer & Trust Company, dated March
31, 1999.
10.1610 Amended and Restated Credit Agreement among Swift Energy
Company and Bank One, N.A. as administrative agent, CIBC
Inc. as syndication agent and Credit Lyonnais New York
Branch and Societe Generale as documentation agents and
the lenders signatory hereto dated September 28, 2001.
10.1711 First Amendment to Amended and Restated Credit Agreement,
effective January 25, 2002 among Swift Energy Company, as
Borrower, Bank One, NA as Administrative Agent, CIBC Inc.
as Syndication Agent, Credit Lyonnais, New York Branch as
Documentation Agent, Societe Generale as Documentation
Agent and The Lenders Signatory Hereto and Banc One
Capital Markets, Inc. as Sole Lead Arranger and Sole Book
Runner.
10.1811 Second Amendment to Amended and Restated Credit Agreement,
effective April 5, 2002 among Swift Energy Company, as
Borrower, Bank One, NA as Administrative Agent, CIBC Inc.
as Syndication Agent, Wells Fargo Bank (Texas), National
Association as Syndication Agent, Credit Lyonnais, New
York Branch as Documentation Agent, Societe Generale as
Documentation Agent and The Lenders Signatory Hereto and
Banc One Capital Markets, Inc. as Sole Lead Arranger and
Sole Book Runner.
10.19* Consulting Agreement dated as of October 13, 2003 between
Swift Energy Company and Raymond O. Loen.
12* Swift Energy Company Ratio of Earnings to Fixed Charges.
21* List of Subsidiaries of Swift Energy Company
23(a)* The consent of H.J. Gruy and Associates, Inc.
23(b)* Consent of Ernst & Young LLP as to incorporation by
reference regarding Forms S-8 and S-3 Registration
Statements.
99.1* The summary of H.J. Gruy and Associates, Inc. report,
dated January 23, 2004.
99.2* Certification of Chief Executive Officer and Chief
Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K filed during the quarter ended December 31, 2003,
which are incorporated herein by reference:
On November 5, 2003, the Company filed a Current Report on Form 8-K
that reported under Item 7, "Financial Statements and Exhibits" and Item
12, "Results of Operations and Financial Condition" relating to the
press release of the announcement of third quarter earnings.
- --------------------------------------------------------------------------------
1 Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q for the quarterly period ended June 30, 2001, File No. 1-8754.
2 Incorporated by reference from Exhibit 4.2 to Pre-Effective Amendment No. 1
to Form S-3 Registration Statement No. 33-81651 of Swift Energy Company,
filed July 9, 1999, which Exhibit 4.2 is the form of such indenture.
3 Incorporated by reference from Swift Energy Company Report on Exhibit 4.1 to
Form 8-K dated August 4, 1999, File No. 1-8754.
4 Incorporated by reference from Swift Energy Company Report on Exhibit 4-1 to
Form 8-K dated April 16, 2002, File No. 1-8754.
5 Incorporated by reference from Swift Energy Company Report on Exhibit 4-2 to
Form 8-K dated April 16, 2002, File No. 1-8754.
67
6 Incorporated by reference from Swift Energy Company definitive proxy
statement for annual shareholders meeting filed April 14, 1997, File No.
1-8754.
7 Incorporated by reference from Registration Statement No. 333-67242 on Form
S-8 filed on August 10, 2001.
8 Incorporated by reference from Swift Energy Company Annual Report on Form
10-K for the fiscal year ended December 31, 2000, File No. 1-8754.
9 Incorporated by reference from Swift Energy Company Amendment No. 1 to Form
8-A, filed April 7, 1999.
10 Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q for the quarterly period ended September 30, 2001, File No. 1-8754.
11 Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q for the quarterly period ended March 31, 2002, File No. 1-8754.
12 Incorporated by reference from Registration Statement No. 33-60469 on Form
S-2 filed on June 22, 1995.
13 Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q for the quarterly period ended September 30, 2002, File No. 1-8754.
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
68
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant, Swift Energy Company, has duly caused this report
to be signed on its behalf by the undersigned, thereunto duly authorized.
SWIFT ENERGY COMPANY
By : /s/ A. Earl Swift
------------------------------
A. Earl Swift
Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant,
Swift Energy Company, and in the capacities and on the dates indicated:
Signatures Title Date
----------- ------ -----
/s/ A. Earl Swift
- -------------------------- Chairman of the Board March 8, 2004
A. Earl Swift
/s/ Terry E. Swift Director
- -------------------------- Chief Executive Officer March 8, 2004
Terry E. Swift President
/s/ Alton D Heckaman Jr. Sr. Vice-President--Finance
- -------------------------- Principal Financial Officer March 8, 2004
Alton D. Heckaman Jr.
/s/ David W. Wesson Controller
- -------------------------- Principal Accounting Officer March 8, 2004
David W. Wesson
69
/s/ G. Robert Evans
- -------------------------- Director March 8, 2004
G. Robert Evans
/s/ Raymond E. Galvin
- -------------------------- Director March 8, 2004
Raymond E. Galvin
/s/ Greg Matiuk
- -------------------------- Director March 8, 2004
Greg Matiuk
/s/ Henry C. Montgomery
- -------------------------- Director March 8, 2004
Henry C. Montgomery
/s/ Clyde W. Smith Jr.
- -------------------------- Director March 8, 2004
Clyde W. Smith, Jr.
/s/ Virgil N. Swift
- -------------------------- Director March 8, 2004
Virgil N. Swift
/s/ Harold J. Withrow
- -------------------------- Director March 8, 2004
Harold J. Withrow
70
CERTIFICATION
I, Terry E. Swift, certify that:
1. I have reviewed this Annual Report on Form 10-K for the year ended December
31, 2003, of Swift Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e) for Swift Energy and we have:
a) designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures and presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and
c) disclosed in this report any changes in the registrant's internal control
over financial reporting that occurred during the registrant's most recent
fiscal quarter (the registrant's fourth fiscal quarter in case of an annual
report) that has materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or
operation of internal controls over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal control over
financial reporting.
Date: March 8, 2004
/s/ Terry E. Swift
----------------------------------
Terry E. Swift
President and
Chief Executive Officer
71
CERTIFICATION
I, Alton D. Heckaman, Jr., certify that:
1. I have reviewed this Annual Report on Form 10-K for the year ended December
31, 2003, of Swift Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e) for the registrant and we have:
a) designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures and presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and
c) disclosed in this report any changes in the registrant's internal control
over financial reporting that occurred during the registrant's most recent
fiscal quarter (the registrant's forth fiscal quarter in case of an annual
report) that has materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or
operation of internal controls over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal control over
financial reporting.
Date: March 8, 2004
/s/ Alton D. Heckaman, Jr.
-----------------------------
Alton D. Heckaman, Jr.
Senior Vice President - Finance
Chief Financial Officer
72
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
EXHIBITS
TO
FORM 10-K REPORT
FOR THE
YEAR ENDED DECEMBER 31, 2003
SWIFT ENERGY COMPANY
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060
73
EXHIBITS
10.19* Consulting Agreement dated as of October 13, 2003 between
Swift Energy Company and Raymond O. Loen.
12* Swift Energy Company Ratio of Earnings to Fixed Charges.
21* List of Subsidiaries of Swift Energy Company
23(a)* The consent of H.J. Gruy and Associates, Inc.
23(b)* Consent of Ernst & Young LLP as to incorporation by
reference regarding Forms S-8 and S-3 Registration
Statements.
99.1* The summary of H.J. Gruy and Associates, Inc. report,
dated January 23, 2004.
99.2* Certification of Chief Executive Officer and Chief
Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
74
Exhibit 10.19
October 13, 2003
Mr. Raymond O. Loen
16 Becket Street
Lake Oswego, OR 97034
Re:Consulting Agreement
Dear Ray:
This letter will set forth the terms and conditions under which you have agreed
to provide consulting services to Swift Energy Company ("Swift"), as an
independent contractor, effective July 1, 2003 ("Effective Date").
1. This Agreement shall be in effect for a term of two (2) years
beginning on the Effective Date and ending on June 30, 2005, unless
earlier terminated by either party upon at least thirty (30) days
prior written notice of termination given to the other party.
2. You shall provide consulting services to Swift, concentrating your
efforts on projects as may be designed from time to time by the
Chairman of the Board, or his designee.
3. As consideration of said personal services, Swift will pay you each
month two thousand dollars ($2,000.00).
4. You will be reimbursed, upon presentation of your itemized invoice,
for any reasonable out-of-pocket expenses incurred by you.
5. Except as otherwise provided in Paragraph 4 above, you shall not
incur any third party expenses on behalf of Swift without the prior
consent of the Chairman of the Board, or his designee.
6. It is expressly understood that you are performing your services as
an independent contractor, that you are the sole judge of the manner
in which you perform such services, that you are not an employee of
Swift, that you are not an agent of Swift and that you have no
authority to bind Swift or speak for, or on behalf of Swift, unless
specially directed in writing to do so by the Chairman of the Board
of Swift. It is further understood that, as an independent
contractor, you are solely responsible for payment of your own State
and Federal income taxes, FICA, self-employment tax and any other
taxes that may be due as a result of the consideration that you
receive hereunder. There will be no withholding for taxes from any
payments made to you by Swift under this Agreement. It is further
understood that you will not be eligible to participate in any of
Swift's employee benefit plans or programs. It shall be your sole
responsibility to carry any insurance for your benefit, such as
worker's compensation, life, accident, disability and medical
insurance to cover you and/or your dependents. You shall retain the
right to perform services for others during the term of this
Agreement.
75
7. You understand that during the term of this Agreement, you may have
access to trade secrets and confidential, technical and proprietary
business information, belonging to Swift or persons, customers, or
other contractors with which Swift has a business relationship or
with which Swift is obligated to maintain confidentiality of such
information ("Confidential Information"). You pledge to use your
best efforts and utmost diligence to protect and keep confidential
such Confidential Information.
8. It is mutually agreed that this Agreement is intended to supersede
any and all previous agreements, oral or written, between you and
Swift. This Agreement is effective as of the Effective Date,
regardless of the date of actual execution.
9. This Agreement shall be subject to, and governed by, the laws of the
State of Texas.
If the foregoing terms of this Agreement meet with your approval, please so
indicate by executing in the space provided below and on the enclosed copy and
return one (1) fully executed original to us for our files.
Very truly yours,
By: /s/ A. Earl Swift
------------------
A. Earl Swift
Chairman of the Board
ACCEPTED AND AGREED TO
THIS 20th DAY OF October, 2003
----- -------
By:/s/ Raymond O. Loen
--------------------
Raymond O. Loen
76
Exhibit 12
SWIFT ENERGY COMPANY
RATIO OF EARNINGS TO FIXED CHARGES
Year ended
Years Ended December 31, December 31,
------------------------------------- ------------------
2002 2001 2003
GROSS G&A 26,074,408 25,974,568 29,803,405
NET G&A 10,564,849 8,186,654 14,097,066
INTEREST EXPENSE, NET 23,274,969 12,627,022 27,268,524
RENTAL & LEASE EXPENSE 1,923,451 1,322,618 2,173,313
INCOME BEFORE INCOME TAXES AND CUMULATIVE 18,408,289 (34,192,333) 50,739,178
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE
CAPITALIZED INTEREST 6,973,480 6,256,222 6,835,983
DEPLETED CAPITALIZED INTEREST 215,433 280,929 548,996
CALCULATED DATA
EXPENSED OR NON-CAPITAL G&A (%) 40.52% 31.52% 47.30%
NON-CAPITAL RENT EXPENSE 779,345 416,889 1,027,981
1/3 NON-CAPITAL RENT EXPENSE 259,782 138,963 342,660
FIXED CHARGES 30,508,231 19,022,198 34,447,167
EARNINGS 42,158,473 (21,145,428) 78,899,358
1.38 --- 2.29
RATIO OF EARNINGS TO FIXED CHARGES (12/11)
For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expense, capitalized interest, amortization of debt
issuance costs and discounts, and that portion of non-capitalized rental expense
deemed to be the equivalent of interest. Earnings represents income before
income taxes and cumulative effect of change in accounting principle before
interest expense, net, depleted capitalized interest and that portion of rental
expense deemed to be the equivalent of interest. Due to the $98.9 million
non-cash charge incurred in the fourth quarter of 2001 caused by a write-down in
the carrying value of oil and gas properties, 2001 earnings were insufficient by
$40.2 million to cover fixed charges in this period. If the $98.9 million
non-cash charge is excluded, the ratio of earnings to fixed charges would have
been 4.09 for 2001.
77
Exhibit 21
Swift Energy Company - Significant Subsidiaries
Swift Energy International, Inc.
Swift Energy New Zealand Limited
Southern Petroleum (NZ) Exploration Limited
78
Exhibit 23 (a)
CONSENT OF H.J. GRUY AND ASSOCIATES, INC.
We hereby consent to the use of the name H.J. Gruy and Associates, Inc. and of
references to H. J. Gruy and Associates, Inc. and to the inclusion of and
references to our report, or information contained therin, dated January 23,
2004, prepared for Swift Energy Company in the Annual Report on Form 10-K of
Swift Energy Company for the filing dated on or about March 8, 2004.
H.J. GRUY AND ASSOCIATES, INC.
by: /s/ Marilyn Wilson
-----------------------------
Marilyn Wilson
President & Chief Operating Officer
Houston, Texas
March 4, 2004
79
Exhibit 23 (b)
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in the Registration Statements
(Form S-8 Nos. 333-112042, 333-67242 and 333-45354, and Form S-3 No. 333-112041)
of Swift Energy Company and in the related Prospectus of our report dated
February 10, 2004, with respect to the consolidated financial statements of
Swift Energy Company included in this Annual Report (Form 10-K) for the year
ended December 31, 2003.
/s/ Ernst & Young LLP
Houston, Texas
March 5, 2004
80
Exhibit 99.1
H.J. GRUY AND ASSOCIATES, INC.
333 Clay Street, Suite 3850, Houston, Texas 77002 o TEL. (713) 739-1000 o
FAX(713) 739-6112
January 23, 2004
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Re: Year-End 2003
Reserves Audit
Gentlemen:
At your request, we have independently audited the estimates of oil, natural
gas, and natural gas liquid reserves and future net cash flows as of December
31, 2003, that Swift Energy Company (Swift) attributes to net interests owned by
Swift. Based on our audit, we consider the Swift estimates of net reserves and
net cash flows to be in reasonable agreement, in the aggregate, with those
estimates that would result if we performed a completely independent evaluation
effective December 31, 2003.
The Swift estimated net reserves, future net cash flow, and discounted future
net cash flow are summarized below:
Domestic and International
Proved Reserves
- --------------------------------------------------------------------------------
Estimated Estimated
Net Reserves Future Net Cash Flow
--------------------------------- -------------------------------------------
Oil, NGL, & Discounted
Condensate Gas at 10%
(Barrels) (Mcf) Nondiscounted Pe r Year
------------ ----------- -------------------- --------------------
Proved Developed 45,525,366 210,119,927 $ 1,603,808,980 $ 940,882,612
Proved Undeveloped 35,234,537 125,684,935 $ 1,071,347,728 $ 597,912,185
Total Proved 80,759,903 335,804,862 $ 2,675,156,708 $ 1,538,794,797
81
Domestic
Proved Reserves
- --------------------------------------------------------------------------------
Estimated Estimated
Net Reserves Future Net Cash Flow
--------------------------------- --------------------------------------------
Oil, NGL, & Discounted
Condensate Gas at 10%
(Barrels) (Mcf) Nondiscounted Per Year
------------ ----------- -------------------- --------------------
Proved Developed 38,767,983 138,173,341 $ 1,415,473,983 $ 805,834,173
Proved Undeveloped 28,247,710 104,147,935 $ 911,764,557 $ 517,485,024
Total Proved 67,015,693 242,321,276 $ 2,327,238,540 $ 1,323,319,197
New Zealand
Proved Reserves
- --------------------------------------------------------------------------------
Estimated Estimated
Net Reserves Future Net Cash Flow
--------------------------------- --------------------------------------------
Oil, NGL, & Discounted
Condensate Gas at 10%
(Barrels) (Mcf) Nondiscounted Per Year
------------ ----------- -------------------- --------------------
Proved Developed 6,757,383 71,946,586 $ 188,334,997 $ 135,048,439
Proved Undeveloped 6,986,827 21,537,000 $ 159,583,171 $ 80,427,161
New Zealand Total 13,744,210 93,483,586 $ 347,918,168 $ 215,475,600
The discounted future net cash flows summarized in the above tables are computed
using a discount rate of 10 percent per annum. Proved reserves are estimated in
accordance with the definitions contained in Securities and Exchange Commission
Regulation S-X, Rule 4-10(a). The definitions are included, in part, as
Attachment I. The reserves discussed herein are estimates only and should not be
construed as exact quantities. Future economic or operating conditions may
affect recovery of estimated reserves and cash flows, and reserves of all
categories may be subject to revision as more performance data become available.
Swift represents that the future net cash flows discussed herein were computed
using prices received for oil and natural gas as of December 31, 2003. Domestic
oil and condensate prices are based on a year-end 2003 reference price of $32.55
per barrel. Natural gas price is based on a year-end 2003 reference price of
$5.97 per MMBtu. New Zealand oil and condensate prices
82
are based on a year-end 2003 reference price of $27.96 per barrel. The New
Zealand gas prices are based on existing long-term contract prices. The sales
price for natural gas liquids is based on a reference price of US$ 0.66 per
gallon adjusted by the appropriate differential. A differential is applied to
the oil, condensate, and natural gas reference prices to adjust for
transportation, geographic property location, and quality or energy content.
Product prices, direct operating costs, and future capital expenditures are not
escalated and therefore remain constant for the projected life of each property.
Swift represents that the provided product sales prices and operating costs are
in accordance with Securities and Exchange Commission guidelines.
This audit has been conducted according to the Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserve Information approved by the Board
of Directors of the Society of Petroleum Engineers, Inc. Our audit included
examination, on a test basis, of the evidence supporting the reserves discussed
herein. We have reviewed the subject properties, and where we had material
disagreements with the Swift reserve estimates, Swift revised its estimate to be
in agreement. In conducting our audit, we investigated each property to the
level of detail that we deem reasonably appropriate to form the judgements
expressed herein.
Based on our investigations, it is our judgement that Swift used appropriate
engineering, geologic, and evaluation principles and methods that are consistent
with practices generally accepted in the petroleum industry. Reserve estimates
were based on extrapolation of established performance trends, material balance
calculations, volumetric calculations, analogy with the performance of
comparable wells, or a combination of these methods. Reserve estimates from
volumetric calculations or from analogies may be less certain than reserve
estimates based on well performance obtained over a period during which a
substantial portion of the reserve was produced.
Estimates of net cash flow and discounted net cash flow should not be
interpreted to represent the fair market value for the audited reserves. The
estimated reserves and cash flows discussed herein have not been adjusted for
uncertainty.
Future net cash flow as presented herein is defined as the future cash inflow
attributable to the evaluated interest less, if applicable, future operating
costs, ad valorem taxes, and future capital expenditures. Future cash inflow is
defined as gross cash inflow less, if applicable, royalties and severance taxes.
Future cash inflow and future net cash flow stated in this report exclude
consideration of state or federal income tax. Future costs of facility and well
abandonments and the restoration of producing properties to satisfy
environmental standards are not deducted from cash flow.
In conducting this audit, we relied on data supplied by Swift. The extent and
character of ownership, oil and natural gas sales prices, operating costs,
future capital expenditures, historical production, accounting, geological, and
engineering data were accepted as represented, and we have assumed the
authenticity of all documents submitted. No independent well tests, property
inspections, or audits of operating expenses were conducted by our staff in
conjunction with this work. We did not verify or determine the extent,
character, status, or liability, if any, of production imbalances or any current
or possible future detrimental environmental site conditions.
83
In order to audit the reserves and future cash flows estimated by Swift, we have
relied in part on geological, engineering, and economic data furnished by our
client. Although we have made a best efforts attempt to acquire all pertinent
data and to analyze it carefully with methods accepted by the petroleum
industry, there is no guarantee that the volumes of hydrocarbons or the cash
flows projected will be realized. The reserve and cash flow projections
discussed in this report may require revision as additional data become
available.
If investments or business decisions are to be made in reliance on these
judgements by anyone other than our client, such person, with the approval of
our client, is invited to visit our offices at his expense so that he can
evaluate the assumptions made and the completeness and extent of the data
available on which our opinions are based. This report is for general guidance
only, and responsibility for subsequent decisions resides with the decision
maker.
Any distribution or publication of this work or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
Texas Registration Number F-000637
by: /s/ Marilyn Wilson
-----------------------
Marilyn Wilson, PE
President and Chief Operating Officer
84
ATTACHMENT I
85
DEFINITIONS OF PROVED OIL AND GAS RESERVES PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquid which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
PROVED DEVELOPED OIL AND GAS RESERVES
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
PROVED UNDEVELOPED RESERVES
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
' Contained in Securities and Exchange Commission Regulation S-X, Rule 4-10 (a)
86
Exhibit 99.1
Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
In connection with the accompanying Annual Report on Form 10-K for the year
ended December 31, 2003 (the "Report") of Swift Energy Company ("Swift") as
filed with the Securities and Exchange Commission on March 8, 2004, the
undersigned, in his capacity as an officer of Swift, hereby certifies pursuant
to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, that to his knowledge:
1. The Report fully complies with the requirements of Section 13(a) or 15(d)
of the Securities Exchange Act of 1934, as amended; and
2. The information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of Swift.
Dated: March 8, 2004
/s/ Alton D. Heckaman, Jr.
-----------------------------------
Alton D. Heckaman, Jr.
Senior Vice President-Finance and
Chief Financial Officer
Dated: March 8, 2004
/s/ Terry E. Swift
-----------------------------------
Terry E. Swift
President and Chief Executive
Officer
87