Back to GetFilings.com
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
1
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.
3
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,
4
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
6
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.
7
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
8
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