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, 2004
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 June
30, 2004 was approximately $599,027,785.
The number of shares of common stock outstanding as of March 1, 2005 was
28,218,062 shares of common stock, $.01 par value.
Documents Incorporated by Reference
Document
Incorporated as to
Proxy Statement for the Annual Part II, Item 5
Meeting of Shareholders to be Part III, Items 10, 11, 12, 13 and 14
held May 10, 2005
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 20
Item 4. Submission of Matters to a Vote of
Security Holders 20
Part II
Item 5. Market for Registrant's Common
Equity, Related Stockholder Matters,
and Issuer Purchasers of Equity Securities 20
Item 6. Selected Financial Data 21
Item 7. Management's Discussion and
Analysis of Financial Condition
and Results of Operations 23
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 42
Item 8. Financial Statements and Supple-
mentary Data 44
Item 9. Changes in and Disagreements with
Accountants on Accounting and
Financial Disclosure 80
Item 9A. Controls and Procedures 80
Item 9B. Other Information 80
Part III
Item 10. Directors and Executive Officers of
the Registrant (1) 81
Item 11. Executive Compensation (1) 81
Item 12. Security Ownership of Certain Bene-
ficial Owners and Management and
Related Stockholders Matters (1) 81
Item 13. Certain Relationships and Related
Transactions (1) 81
Item 14 Principal Accountant Fees and Services (1) 81
Part IV
Item 15 Exhibits and Financial Statement
Schedules 82
(1) Incorporated by reference from Proxy Statement for the Annual Meeting
of Shareholders to be held May 10, 2005.
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 oil and natural gas reserves
onshore and in the inland waters of Louisiana and Texas and onshore in New
Zealand. We were founded in 1979 and are headquartered in Houston, Texas. At
year-end 2004, we had estimated proved reserves of 799.8 Bcfe with a PV-10 Value
of $2.0 billion. Our proved reserves at year-end 2004 were comprised of
approximately 49% crude oil, 40% natural gas, and 11% NGLs, of which 56% were
proved developed. Our proved reserves are concentrated 46% in Louisiana, 33% in
Texas, and 18% in New Zealand.
We currently focus primarily on development and exploration in four
domestic core areas and two core areas in New Zealand:
o AWP Olmos -- South Texas
o Brookeland -- East Texas
o Lake Washington -- South Louisiana
o Masters Creek -- Central Louisiana
o Rimu/Kauri -- New Zealand
o TAWN -- New Zealand
Competitive Strengths and Business Strategy
Our competitive strengths, together with a balanced and comprehensive
business strategy, provide us with the flexibility and capability to achieve our
goals. Our primary goals for the next five years are to increase proved oil and
natural gas reserves at an average rate of 5% to 10% per year and to increase
production at an average rate of 7% to 12% per year.
Demonstrated Ability to Grow Reserves and Production
We have grown our proved reserves from 454.8 Bcfe to 799.8 Bcfe over the
five-year period ended December 31, 2004. Over the same period, our annual
production has grown from 42.9 Bcfe to 58.3 Bcfe and our annual net cash
provided by operations has increased from $73.6 million to $182.6 million. Our
growth in reserves and production over this five-year period has resulted
primarily from drilling activities in our six core areas combined with producing
property acquisitions. More recently, we increased our production by 10% during
2004 as compared to 2003 production. During 2004, our proved reserves decreased
by 3%, which replaced 65% of our 2004 production, primarily due to a slowdown in
drilling activity in Lake Washington in order to allow for the implementation of
a three-dimensional seismic survey and facilities improvements in the area.
Also, we focused our drilling efforts in 2004 mainly on development wells, which
converted proved undeveloped reserves to proved developed, but did not increase
our overall proved reserves. Based on our long-term historical performance and
our business strategy going forward, we believe that we have the opportunities,
experience, and knowledge to grow our reserves and production.
Balanced Approach to Growth
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. In general, we focus on drilling in our core
3
property and emerging growth areas when oil and natural gas prices are strong.
When prices weaken and the per unit cost of acquisitions becomes more
attractive, or a strategic opportunity exists, we shift our focus toward
acquisitions. We believe this balanced approach has resulted in our ability to
grow in a strategically cost effective manner. Over the five-year period ended
December 31, 2004, we replaced 239% of our production at an average cost of
$1.47 per Mcfe. For 2005, we are targeting total production and proved reserves
to increase 7% to 12% over the 2004 levels.
Our 2005 capital expenditures are currently budgeted at $200 million to
$220 million, net of approximately $5 million to $15 million of non-core
property dispositions. Approximately 80% of the budget is targeted for domestic
activities, primarily in South Louisiana for Lake Washington and the surrounding
area, with about 20% planned for activities in New Zealand. Approximately $15
million to $20 million will be focused on activities at our new properties in
the Bay de Chene and Cote Blanche Island fields in South Louisiana that were
acquired in December 2004. No acquisitions are currently included in our 2005
capital budget. We expect our 2005 capital expenditures will initially be at the
low end of the range, and depending on commodity prices and operational
performance, they may increase to the high end of the range during the course of
the year. We anticipate 2005 capital expenditures to approximate our cash flow
provided from operating activities during 2005.
Reserve Replacement Ratio and Reserve Replacement Cost
Historically we have added proved reserves due to both our drilling and
acquisition activities. We believe that this strategy will continue to add
reserves for us, however, external factors beyond our control, such as
governmental regulations and commodity market factors, could limit our ability
to drill wells and acquire proved properties in the future. We calculate and
analyze reserve replacement ratios and costs to use as benchmarks against our
competitors. These ratios and costs are limited in use by the inherent
uncertainties in the reserve estimation process, and other factors discussed
below. We have included a table listing the vintages of our proved undeveloped
reserves in the table titled "Proved Undeveloped Reserves," and believe this
table will provide an understanding of the time horizon required to convert
proved undeveloped reserves to oil and gas production. Our reserve additions for
each year are estimates. Reserve volumes can change over time and, therefore
cannot be absolutely known or verified until all volumes have been produced and
a cumulative production total for a well or field can be calculated. Many
factors will impact our ability to access these reserves, such as availability
of capital, new and existing government regulations, competition within our
industry, the requirement of new or upgraded infrastructure at the production
site, and technological advances.
The reserve replacement ratio is calculated using reserve replacement
volumes divided by production volumes during a specific period. The reserve
replacement volumes used in this calculation are listed in the "Supplemental
Information (Unaudited)" section of this report, specifically in a table titled
"Supplemental Reserve Information." Within this table there are categories
titled "Revisions of previous estimates," "Purchases of minerals in place" and
"Extensions, discoveries, and other additions," which when added total the
reserve replacement volumes. Production volumes are also listed in the same
table, and these production volumes are also used in the reserve replacement
ratio calculation.
The reserve replacement cost is calculated using reserve replacement
volumes divided by acquisition, exploration and development costs incurred
during a specific period. Our acquisition, exploration, and development costs
are listed in the "Supplemental Information (Unaudited)" section of this report,
specifically in a table titled "Costs Incurred." Development costs as defined by
Securities and Exchange Commission rules, include costs incurred to obtain
access to proved reserves and provide facilities for extracting, treating,
gathering and storing the oil and gas. Development costs thus include well costs
for our development wells and facility costs, such as those facility and
platform costs we have incurred in our Lake Washington area over the past
several years. Costs incurred to explore and develop reserves may extend over
several years. We believe a reserve replacement cost estimate is more meaningful
when calculated over several periods. Future development costs from prior years
are included in this calculation to the extent that they have been included, in
our actual costs incurred.
4
Concentrated Focus on Core Areas with Operational Control
The concentration of our operations in six core areas allows us to realize
economies of scale in drilling and production by enabling us to manage larger
producing fields with less personnel while minimizing incremental costs of
increased drilling and completions. Our average lease operating costs, excluding
taxes, were $0.71, $0.64, and $0.58 per Mcfe in 2004, 2003, and 2002,
respectively. This concentration allows us to utilize the experience and
knowledge we gain in these areas to continually improve our operations and guide
us in developing our future activities and in operating similar type assets. For
example, we will apply the experience we have gained in Lake Washington to our
recently acquired Bay de Chene and Cote Blanche Island properties, which are
also situated around South Louisiana salt domes. The value of this concentration
is enhanced by our operating 97% of our proved oil and natural gas reserve base
as of December 31, 2004. Retaining operational control allows us to more
effectively manage production, control operating costs, allocate capital and
time field development.
Develop Under-Exploited Properties
We are focused on applying modern technologies and recovery methods to
areas with known hydrocarbon resources to optimize our exploration and
exploitation of such properties. For example, the Lake Washington field was
discovered in the 1930s. We acquired our properties in this area for $30.5
million in 2001. Since that time, we have increased our average daily net
production from less than 700 BOE to 12,900 BOE for the quarter ended December
31, 2004. We have also increased our proved reserves in the area from 7.7
million BOE, or 46.2 Bcfe, to approximately 45.4 million BOE or 272.5 Bcfe, as
of December 31, 2004. Additionally, 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 drilled 32 wells in New Zealand since 1999. When we first
acquired our interests in AWP Olmos, Brookeland, and Masters Creek, these areas
also had significant additional development potential. Our properties in the Bay
de Chene and Cote Blanche Island fields hold mainly proved undeveloped reserves
and we intend to begin our initial development activities of these properties in
the second half of 2005. We intend to continue acquiring large acreage positions
in under-explored and under-exploited areas, where we can apply modern
technologies and our experience and knowledge in the areas to grow production
from developed fields.
Capitalize on the Near Term Depletion of New Zealand's Largest Gas Field
The Maui field in New Zealand currently supplies over 70% of the natural
gas produced in New Zealand. The Maui field is expected to be depleted by 2007,
which has caused significant upward pressure on prices for natural gas in the
country. Due to currency exchange increases between the New Zealand Dollar and
the U.S. Dollar, along with increases in our natural gas contract prices, our
average natural gas price in New Zealand has increased 77% from the first
quarter of 2003 to the fourth quarter of 2004. We expect the prices we receive
for our natural gas in New Zealand to continue to remain strong in the
foreseeable future. During 2005, we anticipate drilling seven to ten development
wells and expect to drill three to five exploration tests, which includes our
Tarata Thrust exploration activity. These 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.
Maintain Financial Flexibility and Disciplined Capital Structure
We practice a disciplined approach to financial management and have
historically maintained a disciplined capital structure to provide us with the
ability to execute our business plan. As of December 31, 2004, our debt to
capitalization was approximately 43%, debt per proved reserves was $0.45 per
Mcfe, and our debt to PV-10 ratio was 18%. We plan to maintain a capital
structure that provides financial flexibility through the prudent use of
capital, aligning our capital expenditures to our cash flows, and an active
hedging program. The combination of hedging with collars, floors, forward sales,
and the sale of our New Zealand natural gas production under long-term,
fixed-price contracts will provide for a more stable cash flow for the limited
periods covered as described in the "Commodity Risk" section of this report.
Experienced Technical Team
We employ 42 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 us for an average of over eight
years. In addition, we engage
5
experienced and qualified consultants to perform various comprehensive seismic
acquisitions, processing, reprocessing, interpretation, and other services. We
continually apply our extensive in-house experience and current technologies to
benefit our drilling and production operations.
We have increasingly used seismic technology to enhance the results of our
drilling and production efforts, including two and three-dimensional seismic
acquisition, post-stack image enhancement reprocessing, amplitude versus offset
datasets, correlation cubes, and detailed formation depletion studies. In 2004,
we completed our three dimensional seismic survey covering our Lake Washington
area and at least four of our 2005 wells in this area will be exploration wells
with targets derived from this 3-D seismic data.
We use various recovery techniques, including gas lift, water flooding, and
acid treatments to enhance crude oil and natural gas production. We also
fracture reservoir rock through the injection of high-pressure fluid, install
gravel packs, and insert coiled-tubing velocity strings to enhance and maintain
production. We believe that the application of fracturing and coiled-tubing
technology has resulted in significant increases in production and decreases in
completion and operating costs, particularly in our AWP Olmos area.
When appropriate, we develop new applications for existing technology. For
example, in New Zealand we acquired seismic data by effectively combining marine
seismic data with land seismic data, an application we have not seen any other
company use in New Zealand.
We have developed an 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 also employ measurement-while-drilling techniques extensively in our
Lake Washington area, which allows us to guide the drill bit during the drilling
process. This technology allows Swift Energy to steer the well bore path
parallel to the salt face and to intersect multiple targeted sands in a single
well bore.
Operating Areas
The following table sets forth information regarding our proved reserves
and production in our six core areas:
% of Year-End
2004 Proved % of 2004
Area Location Reserves Production
---- ------------------- -------------- ----------
AWP Olmos..............South.Texas...................24% 15%
Brookeland.............East.Texas.....................5% 6%
Lake Washington........South.Louisiana...............34% 40%
Masters Creek..........Central.Louisiana..............7% 6%
Rimu/Kauri.............New.Zealand...................14% 9%
TAWN...................New.Zealand....................5% 19%
--- ---
% of Total........................................89% 95%
--- ---
Domestic Core Operating Areas
AWP Olmos Area. As of December 31, 2004, we owned 27,534 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 69% natural
gas. At year-end 2004, we owned interests in and operated 512 wells in this area
producing natural 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 2004, we completed 13 development wells in this area, and performed four
fracture enhancements. At year-end 2004, we had 112 proved undeveloped
locations. Our planned 2005 capital expenditures in this area will focus on
drilling 12 to 15 wells in this area.
Brookeland Area. As of December 31, 2004, we owned drilling and production
rights in 79,040 net acres and 3,500 fee mineral acres in the Brookeland area,
which contains substantial proved undeveloped reserves. This area is
6
located in East Texas near the border of Louisiana in Jasper and Newton
counties. We primarily drill horizontal wells and produce from the Austin Chalk
formation. The reserves are approximately 56% oil and natural gas liquids. At
year-end 2004, we had 11 proved undeveloped locations. Our planned 2005 capital
expenditures in this area include drilling one to two development wells.
Lake Washington Area. As of December 31, 2004, we owned drilling and
production rights in 15,199 net acres in the Lake Washington area located in
Plaquemines Parish in South Louisiana, along with lease and seismic options
covering another 6,645 acres. Approximately 92% of our proved reserves of 45.4
million BOE in this area at December 31, 2004 were oil and NGLs. To date, we
have primarily produced from multiple Miocene sands ranging in depth from
greater than 1,700 feet to less 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 109 producing wells is gathered
from three platforms located in water depths from two to 12 feet, with drilling
and workover operations performed with rigs on barges.
In 2004, we drilled 23 development wells and seven exploratory wells, of
which 19 development and two exploratory wells were completed. At year-end 2004,
we had 85 proved undeveloped locations in this field. Our planned 2005 capital
expenditures in this area will focus on drilling at least 30 wells, of these at
least four will be exploratory wells with targets derived from recently acquired
three-dimensional data. Additional facility work is planned to further improve
the deliverability and efficiency in this area.
Masters Creek Area. As of December 31, 2004, we owned drilling and
production rights in 48,810 net acres and 91,994 fee mineral acres in the
Masters Creek area, which contains substantial proved undeveloped reserves. This
area is located in Central Louisiana near the Texas-Louisiana border in the two
parishes of Vernon and Rapides. It contains horizontal wells producing both oil
and gas from the Austin Chalk formation. The reserves are approximately 68% oil
and NGLs. In 2004, we drilled and successfully completed one development well in
this area. At year-end 2004, we had nine proved undeveloped locations. Our
planned 2005 capital expenditures include drilling one to two development wells.
Domestic Emerging Growth Areas
Garcia Ranch Area. We have been focusing on the deep sands of the Frio
formation (10,000 to 16,000 feet) in an area known as Garcia Ranch, which
straddles the border of Kenedy County and Willacy County in the southern tip of
Texas. Three exploratory wells and one development well were drilled in this
area in 2004, of which two exploratory wells were completed.
Bay de Chene and Cote Blanche Island. In December 2004, we acquired
approximately 14,200 gross acres in the Bay de Chene field and approximately
6,200 gross acres in the Cote Blanche Island field, both of which are in South
Louisiana in close proximity to Lake Washington. Bay de Chene is located in
Jefferson Parish and Lafourche Parish, while Cote Blanche Island is located in
St. Mary Parish. These fields hold predominantly undeveloped reserves. We plan
to spend $15 million to $20 million to begin developing these fields in the
later part of 2005. These fields were shut-in following the acquisition for
facility enhancements and to repair a gas supply line.
New Zealand Core Operating Areas
Our activity in New Zealand began in 1995. As of December 31, 2004, our
exploration permit 38719, which we operate, included approximately 72,769 acres
in the Taranaki Basin of New Zealand's north island. In April 2004, two other
permits (38756 and 38759) within the Taranaki Basin were consolidated with our
permit 38719 to form one permit area. This acreage includes our Rimu/Kauri area,
our Rimu mining permit area, and our Tawa prospect.
Rimu/Kauri Area. Since 2002, we have held a 100% working interest in
petroleum mining permit 38151 covering approximately 5,500 acres in the Rimu
area for a primary term of 30 years. We began commercial production from the
Rimu area in May 2002. During 2004, we completed ten of 11 wells in the Kauri
area. Five of these wells successfully targeted the Kauri sands, and five were
completed in the Manutahi sand. We have applied for a 30-year primary term
mining permit covering approximately 8,714 acres in the Kauri area. Our natural
gas production from this area 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.
7
TAWN Area. Our interest in TAWN consists of a 100% working interest in four
petroleum mining permits, 38138 through 38141, covering producing oil and gas
fields and extensive associated hydrocarbon-processing facilities and pipelines.
The properties are collectively identified as the TAWN properties, an acronym
derived from the first letters of the field names -- the Tariki field, the
Ahuroa field, the Waihapa field, and the Ngaere field. The four fields include
18 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. In 2004, we completed the Tariki-D1 well in this area.
The TAWN assets are located approximately 17 miles north of the Rimu/Kauri area.
Our infrastructure at TAWN includes two hydrocarbon-processing plants with
significant excess capacity. We also own the pipelines connecting the fields and
facilities to export terminals and interior markets.
New Zealand Emerging Growth Areas
The Tawa prospect, which is scheduled for drilling in 2005, is located in
permit 38719 northwest of the Rimu area. Its main targets are the Kauri, Tariki,
and Kapuni sands. Consisting of a combination of structural and stratigraphic
traps, this prospect was developed based upon our analysis of existing two and
three-dimensional seismic data. The Tawa prospect may also include a shallower
prospect located on the southeast flank of the prospect.
Two prospects, also scheduled for drilling in 2005, are located in our TAWN
area and are identified as the Goss prospect (Goss A1 well), and the Trapper
prospect (Trapper A1 well). Both 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
producing sands in the basin .We have entered into a series of farm-out
agreements with Mighty River Power ("MRP"), a state owned New Zealand utility,
that provide for a 50% working interest in relation to the Goss A1 well, the
Trapper A1 well, and a well on our Tawa prospect. Under the farm-out agreement,
MRP will provide the funding for the drilling of the three exploration wells to
earn a 50% working interest in any commercial discoveries resulting from these
prospects. Once MRP has earned its 50%, we will equally share any future
development costs subject to the terms of the agreements. Swift will continue to
maintain its 100% working interest in the existing producing horizons and
facilities in both the TAWN and Rimu/Kauri areas.
Swift also holds a 71% interest in exploration permit 38718, covering
approximately 28,600 gross acres northeast of our TAWN area, and a 21% interest
in exploration permit 38716, covering approximately 33,000 gross acres southeast
of our TAWN area. In December 2004, we entered into a farm-in agreement with
Ballance Agri-Nutrients Limited of New Zealand for 60% of their exploration
permit 38742. The approximately 16,800 gross acre permit is located onshore in
the north-central Taranaki Basin. Under the terms of the contract we became the
operator of the permit and anticipate drilling an exploratory well in this area
in the second half of 2005.
8
Summary of New Zealand Government Licenses and Permits
Our acreage in New Zealand is licensed from the New Zealand government
under both production exploration permits (PEP), production mining licenses
(PML), and production mining permits (PMP). These licenses and permits are
summarized in the following table:
Date Swift
Acquired / Granted Swift's
Permit Initial Interest Interest
PEP 38716 1999 21%
PEP 38718 2000 71%
PEP 38719 1996 100%
PEP 38742 2004 60%
PML 38138 2002 100%
PML 38139 2002 100%
PML 38140 2002 100%
PML 38141 2002 100%
PMP 38151 2002 100%
The New Zealand government's Crown Minerals website has details of these
licenses at http://crownminerals.med.govt.nz/index.asp.
Oil and Natural Gas Reserves
The following tables present information regarding proved reserves of oil
and natural gas attributable to our interests in producing properties as of
December 31, 2004, 2003, and 2002. The information set forth in the tables
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 has audited 100% of our proved reserves. 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
all available production histories and other geological, economic, and
engineering data, all of which was provided by us.
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, for that
year's reserve calculation, 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 2004 consisted mainly of crude oil and natural gas price
floors with strike prices lower than the period-end price and thus did not
materially affect prices used in these calculations. The weighted averages of
such year-end 2004 prices domestically were $5.87 per Mcf of natural gas, $42.21
per barrel of oil, and $26.49 per barrel of NGL, compared to $5.53, $30.88, and
$21.81 at year-end 2003 and $4.23, $29.36, and $17.30 at year-end 2002,
respectively. The weighted averages of such year-end 2004 prices for New Zealand
were $3.07 per Mcf of natural gas, $33.60 per barrel of oil, and $20.48 per
barrel of NGL, compared to $2.04, $26.78, and $14.10 in 2003 and $1.48, $28.80,
and $12.24 in 2002, respectively. The weighted averages of such year-end 2004
prices for all our reserves, both domestically and in New Zealand, were $5.16
per Mcf of natural gas, $41.07 per barrel of oil, and $25.48 per barrel of NGL,
compared to $4.56, $30.16, and $20.61 in 2003 and $3.49, $29.27, and $16.54 in
2002, 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 tables.
The following tables set forth estimates of future net revenues presented
on the basis of unescalated prices and costs in accordance with criteria
prescribed by the SEC and its PV-10 Value as of December 31, 2004, 2003, and
2002. 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,
9
which is calculated after provision for future income taxes. We combine NGLs
with oil for reserve reporting purposes.
As of December 31, 2004
Total Domestic New Zealand
Estimated Proved Oil and Natural Gas Reserves
Natural gas reserves (MMcf):
Proved developed......................................................... 193,311 140,549 52,762
Proved undeveloped....................................................... 124,935 97,343 27,593
------------- ------------- -----------
Total................................................................... 318,246 237,892 80,355
============= ============= ===========
Oil reserves (MBbl):
Proved developed......................................................... 42,038 36,629 5,409
Proved undeveloped....................................................... 38,229 32,510 5,719
------------- ------------- -----------
Total................................................................... 80,267 69,139 11,128
============= ============= ===========
Estimated Present Value of Proved Reserves (In thousands)
Proved developed.........................................................$ 1,181,748 $ 1,037,617 $ 144,130
Proved undeveloped....................................................... 839,127 759,724 79,403
------------- ------------- -----------
PV-10 Value.............................................................$ 2,020,875 $ 1,797,341 $ 223,533
============= ============= ===========
As of December 31, 2003
Total Domestic New Zealand
Estimated Proved Oil and Natural Gas Reserves
Natural gas reserves (MMcf):
Proved developed......................................................... 210,120 138,173 71,947
Proved undeveloped....................................................... 125,685 104,148 21,537
------------- ------------- -----------
Total................................................................... 335,805 242,321 93,484
============= ============= ===========
Oil reserves (MBbl):
Proved developed......................................................... 45,525 38,768 6,757
Proved undeveloped....................................................... 35,235 28,248 6,987
------------- ------------- -----------
Total................................................................... 80,760 67,016 13,744
============= ============= ===========
Estimated Present Value of Proved Reserves (In thousands)
Proved developed.........................................................$ 940,883 $ 805,834 $ 135,049
Proved undeveloped....................................................... 597,912 517,485 80,427
------------- ------------- -----------
PV-10 Value.............................................................$ 1,538,795 $ 1,323,319 $ 215,476
============= ============= ===========
As of December 31, 2002
Total Domestic New Zealand
Estimated Proved Oil and Natural Gas Reserves
Natural gas reserves (MMcf):
Proved developed......................................................... 233,515 149,732 83,783
Proved undeveloped....................................................... 93,217 90,092 3,125
------------- ------------- -----------
Total................................................................... 326,732 239,824 86,908
============= ============= ===========
Oil reserves (MBbl):
Proved developed......................................................... 35,928 26,530 9,398
Proved undeveloped....................................................... 34,511 32,500 2,011
------------- ------------- -----------
Total................................................................... 70,439 59,030 11,409
============= ============= ===========
Estimated Present Value of Proved Reserves (In thousands)
Proved developed.........................................................$ 679,356 $ 516,833 $ 162,523
Proved undeveloped....................................................... 481,833 456,632 25,201
------------- ------------- -----------
PV-10 Value.............................................................$ 1,161,189 $ 973,465 $ 187,724
============= ============= ===========
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.
10
No other reports on our reserves have been required to be filed, nor have
any been filed with any federal agency.
Proved Undeveloped Reserves
The following table sets forth the aging and PV-10 value of our proved
undeveloped reserves as of December 31, 2004:
PV-10
Volume % of PUD Value % of PUD
Year Added (Bcfe) Volumes (in millions) PV-10 Value
2004 111.5 31% $ 367.5 44%
2003 80.0 23% 205.2 24%
2002 30.6 9% 61.7 7%
2001 17.7 5% 40.1 5%
2000 43.4 12% 54.8 7%
Prior to 2000 71.0 20% 109.1 13%
----------- ------------- ----------------- ----------------
Total 354.2 100% $ 838.4 100%
=========== ============= ================= ================
Sensitivity of Reserves to Pricing
As of December 31, 2004, a 5% increase in crude oil an NGL pricing would
increase our total estimated proved reserves of 799.8 Bcfe by approximately 0.6
Bcfe, and increase the total PV-10 value of $2.0 billion by approximately $89
million. Similarly, a 5% decrease in crude oil and NGL pricing would decrease
our total estimated proved reserves by approximately 0.7 Bcfe and decrease the
total PV-10 value by approximately $89 million.
As of December 31, 2004 a 5% increase in natural gas pricing (exclusive of
fixed contract volumes) would increase our total estimated proved reserves by
approximately 0.6 Bcfe and increase the total PV-10 value by approximately $33
million. Similarly, a 5% decrease in natural gas pricing (exclusive of fixed
contract volumes) would decrease our total estimated proved reserves ay
approximately 0.6 Bcfe and decrease the total PV-10 value by approximately $34
million.
Oil and Gas Wells
The following table sets forth the gross and net wells in which we owned an
interest at the following dates:
Oil Wells Gas Wells Total Wells(1)
December 31, 2004:
Gross................................358.......574...........932
Net................................308.8.....525.9.........834.7
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
- ------------
(1) Excludes 40 service wells in 2004, 41 service wells in 2003, and 35 service
wells in 2002.
11
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, 2004:
Developed(1) Undeveloped(1)
------------------------- --------------------------
Gross Net Gross Net
---------- ---------- ----------- -----------
Alabama................ 9,046.11 2,588.73 124.22 79.82
Louisiana..............100,464.00 82,814.43 16,342.11 11,481.30
Texas..................151,824.86 103,029.72 17,765.95 9,396.36
Wyoming................ 681.07 151.06 66,015.91 64,252.13
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.......269,825.41 189,201.55 105,648.19 85,725.27
New Zealand............ 8,240.00 7,865.60 173,043.90 132,578.17
---------- ---------- ----------- ------------
Total...............278,065.41 197,067.15 278,692.09 218,303.44
========== ========== =========== ============
(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.
Drilling Activities
The following table sets forth the results of our drilling activities
during the three years ended December 31, 2004:
Gross Wells Net Wells
------------------------- -------------------------
Year Type of Well Total Producing Dry Total Producing Dry
---- ----------------------- ------ --------- ------- ------- --------- ------
2004 Exploratory -- Domestic 10 4 6 7.5 2.3 5.2
Development -- Domestic 44 37 7 41.7 35.0 6.7
Exploratory -- New 1 -- 1 1.0 -- 1.0
Zealand
Development -- New 11 10 1 11.0 10.0 1.0
Zealand
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 1 -- 1 0.5 -- 0.5
Zealand
Development -- New 3 3 -- 3.0 3.0 --
Zealand
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 3 2 1 2.2 2.0 0.2
Zealand
Development -- New 3 2 1 3.0 2.0 1.0
Zealand
12
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 natural gas. The fees for these
activities in 2004 totaled $5.8 million and ranged from $600 to $2,155 per well
per month.
Marketing of Production
Domestically, we typically sell our oil and natural gas production at
market prices near the wellhead or at a central point after gathering and/or
processing. We typically sell our natural gas in the spot market on a monthly
basis, while we sell our oil at prevailing market prices. We do not refine any
oil we produce. Shell, both domestically and in New Zealand accounted for 10% or
more of our total revenues during the year ended December 31, 2004, with
purchases accounting for approximately 48% of total oil and gas sales. For the
year-ended December 31, 2003, Shell, both domestically and in New Zealand, and
Contact Energy in New Zealand together accounted for approximately 26% of our
total oil and gas sales. 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 natural 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, and then assumed by Enterprise Hydrocarbons L.P. in
September 2004, for up to 75,000 Mcf per day, which provided for a ten-year term
with automatic one- year extensions unless earlier terminated. We believe that
these arrangements adequately provide for our gas transportation and processing
needs in the AWP Olmos area for the foreseeable future.
Our oil production from the Brookeland and Masters Creek areas is sold to
various purchasers at prevailing market prices. Our natural 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 transported on barges for sales to
various purchasers at prevailing market prices or at fixed prices tied to the
then current Nymex crude oil contract for the applicable month(s) Our natural
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 natural gas production from our TAWN fields is sold under a long-term
fixed price contract with Contact Energy. Our natural gas production from the
Rimu field is sold to Genesis Power Ltd. under a long-term fixed price contract
that was modified in 2003 and covers approximately 7.2 Bcfe per year for a
three-year period. During 2004, additional production volumes from our fields,
over the contract maximum, were sold to Contact Energy or Genesis Power Ltd. at
prevailing market rates.
Production of NGLs in New Zealand is sold to Rockgas Ltd. under long-term
contracts tied to New Zealand's domestic natural gas liquids market.
13
The following table summarizes sales volumes, sales prices, and production
cost information for our net oil and natural gas production for the three-year
period ended December 31, 2004.
Year Ended December 31,
2004 2003 2002
---- ---- ----
Net Sales Volume:
Oil (MBbls)(1)........................... 4,722 3,369 2,597
Natural Gas Liquids (MBbls)(2)........... 1,040 823 1,174
Natural gas (MMcf)(3).................... 23,742 28,003 27,132
Total (MMcfe)........................... 58,319 53,158 49,752
Average Sales Price:
Oil (Per Bbl)(1).........................$ 40.24 $ 29.89 $ 24.52
Natural Gas Liquids (Per Bbl)(2).........$ 22.52 $ 17.60 $ 12.82
Natural gas (Per Mcf)(3).................$ 4.12 $ 3.42 $ 2.30
Average Production Cost (Per Mcfe).........$ 1.23 $ 0.99 $ 0.83
- ------------
(1) Oil production for 2004, 2003, and 2002 includes New Zealand production of
452,753 barrels at an average price per barrel of $42.15, 572,683 barrels at
an average price per barrel of $29.58, and 483,591 barrels at an average
price per barrel of $24.31, respectively.
(2) Natural gas liquids production for 2004, 2003 and 2002 includes New Zealand
production of 350,303 barrels at an average price of $17.96 per barrel,
283,227 barrels with an average price of $13.50 per barrel, and 211,864
barrels with an average price of $11.06 per barrel.
(3) Natural gas production for 2004, 2003 and 2002 includes New Zealand
production of 11,441,954 Mcf with an average price of $2.38 per Mcf,
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.
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. We
maintain comprehensive insurance coverage, including general liability insurance
in an amount not less than $50 million. 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. We have a price-risk management policy to use derivative
instruments to protect against declines in oil and gas prices, mainly through
the purchase of price floors and collars. At December 31, 2004, we had in place
price floors in effect through the December 2005 contract month for natural gas;
these cover a portion of our domestic natural gas production for January 2005 to
December 2005. The natural gas price floors cover notional volumes of 4,000,000
MMBtu, with a weighted average floor price of $5.83 per MMBtu. Our natural gas
price floors in place at December 31, 2004 are expected to cover approximately
30% to 35% of our domestic natural gas production from January 2005 to December
2005. At December 31, 2004, we also had in place price crude oil price floors in
effect through the March 2005 contract month, which cover a portion of our
domestic crude oil production for January 2005 to March 2005. The crude oil
price floors cover notional volumes of 216,000 barrels, with a weighted average
floor price of $37.00 per barrel. Our crude oil price floors in place at
December 31, 2004 are expected to cover approximately 15% to 20% of our domestic
crude oil production from January 2005 to March 2005.
14
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 domestic exploration, production, and marketing operations are subject
to complex and stringent federal, state, and local laws and regulations
governing the discharge of substances into the environment or otherwise relating
to environmental protection. These laws and regulations may require the
acquisition of a permit by operators before drilling commences, prohibit
drilling activities on certain lands lying within wilderness areas, wetlands,
and other ecologically sensitive and protected areas, and impose substantial
remedial liabilities for pollution resulting from drilling operations. Failure
to comply with these laws and regulations may result in the assessment of
administrative, civil, and criminal penalties, the imposition of significant
investigatory or remedial obligations, and the imposition of injunctive relief
that limits or prohibits our operations. Changes in environmental laws and
regulations occur frequently, and any changes that result in more stringent and
costly waste handling, storage, transport, disposal or cleanup requirements
could materially adversely affect our operations and financial position, as well
as those of the oil and gas industry in general. While we believe that we are in
substantial compliance with current environmental laws and regulations and have
not experienced any material adverse effect from such compliance, there is no
assurance that this trend will continue in the future.
We currently own or lease, and have in the past owned or leased, numerous
properties in connection with our domestic operations that have been used for
the exploration and production of oil and gas for many years. Although we have
used operation and disposal practices that were standard in the industry at the
time, petroleum hydrocarbons or other wastes may have been disposed or released
on or under the properties owned or leased by us or on or under other locations
where such wastes have been taken for disposal. In addition, many of these
properties have been operated by third parties whose treatment and disposal or
release of petroleum hydrocarbons or other wastes was not under our control.
These properties and the wastes disposed thereon or away from could be subject
to stringent and costly investigatory or remedial requirements under applicable
laws, some of which are strict liability laws without regard to fault or the
legality of the original conduct, including the federal Comprehensive
Environmental Response, Compensation, and Liability Act, also known as "CERCLA"
or the "Superfund" law, the federal Resource Conservation and Recovery Act or
"RCRA," the federal Clean Water Act, the federal Clean Air Act, the federal Oil
Pollution Act or "OPA," and analogous state laws. Under such laws and any
implementing regulations, we could be required to remove or remediate previously
disposed wastes (including wastes disposed of or released by prior owners or
operators) or property contamination (including groundwater contamination), to
perform natural resource mitigation or restoration practices, or to perform
remedial plugging or closure operations to prevent future contamination. In
addition, it is not uncommon for neighboring landowners and other third parties
to file claims for personal injury or property damages allegedly caused by the
release of petroleum hydrocarbons or other wastes into the environment.
Our domestic operations offshore in the Gulf of Mexico are subject to OPA,
which imposes a variety of requirements related to the prevention of oil spills,
and liability for damages resulting from such spills in United States waters.
The OPA imposes strict, joint and several liability on responsible parties for
oil removal costs and a variety of public and private damages, including natural
resource damages. Liability limits for offshore facilities require a responsible
party to pay all removal costs, plus up to $75 million in other damages. These
liability limits do not apply, however, if the spill was caused by gross
negligence or willful misconduct of the party, if the spill resulted from
violation of a federal safety, construction or operation regulation, or if the
party fails to report the spill or cooperate fully in any resulting cleanup. The
OPA also requires a responsible party at an offshore facility to submit proof of
its financial ability to cover environmental cleanup and restoration costs that
could be incurred in connection with an oil spill. We believe our operations are
in substantial compliance with OPA requirements.
15
Our operations in New Zealand could also potentially be subject to similar
foreign governmental controls and restrictions pertaining to protection of human
health and the environment. These controls and restrictions may include the need
to acquire permits, prohibitions on drilling in certain environmentally
sensitive areas, performance of investigatory or remedial actions for any
releases of petroleum hydrocarbons or other wastes caused by us or prior
operators, closure and restoration of facility sites, and payment of penalties
for violations of applicable laws and regulations. While we believe that we are
in substantial compliance with current environmental laws and regulations in New
Zealand, and have not experienced any material adverse effect from such
compliance, there is no assurance that this trend will continue in the future.
United States Federal, State and New Zealand Regulation of Oil and Natural
Gas
The transportation and certain sales of natural gas in interstate commerce
are heavily regulated by agencies of the federal government and are affected by
the availability, terms and cost of transportation. The price and terms of
access to pipeline transportation are subject to extensive federal and state
regulation. The Federal Energy Regulatory Commission ("FERC") is continually
proposing and implementing new rules and regulations affecting the natural gas
industry, most notably interstate natural gas transmission companies that remain
subject to the FERC's jurisdiction. The stated purpose of many of these
regulatory changes is to promote competition among the various sectors of the
natural gas industry. Some recent FERC proposals may, however, adversely affect
the availability and reliability of interruptible transportation service on
interstate pipelines.
Our sales of crude oil, condensate and NGLs are not currently subject to
FERC regulation. However, the ability to transport and sell such products is
dependent on certain pipelines whose rates, terms and conditions of service are
subject to FERC regulation.
Production of any oil and gas by us will be affected to some degree by
state regulations. Many states in which we operate have statutory provisions
regulating the production and sale of oil and gas, including provisions
regarding deliverability. Such statutes, and the regulations promulgated in
connection therewith, are generally intended to prevent waste of oil and gas and
to protect correlative rights to produce oil and gas between owners of a common
reservoir. Certain state regulatory authorities also regulate the amount of oil
and gas produced by assigning allowable rates of production to each well or
proration unit, which could restrict the rate of production below the rate that
a well would otherwise produce in the absence of such regulation. In addition,
certain state regulatory authorities can limit the number of wells or the
locations where wells may be drilled. Any of these actions could negatively
affect the amount or timing of revenues. 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.
Litigation
In the ordinary course of business, we have been party to various legal
actions, which arise primarily from our activities as operator of oil and gas
wells. In our opinion, the outcome of any such currently pending legal actions
will not have a material adverse effect on our financial position or results of
operations.
Employees
At December 31, 2004, we employed 272 persons. Of these employees, 69 were
in New Zealand, including four expatriate employees. Eight of our New Zealand
employees are members of a union. None of our other employees are represented by
a union. Relations with employees are considered to be good.
16
Facilities
At December 31, 2004, we occupied approximately 102,000 square feet of
office space at 16825 Northchase Drive, Houston, Texas, under a ten-year lease
expiring in 2015. The lease requires payments of approximately $194,000 per
month. In New Zealand we leased approximately 16,000 square feet of office
space, under leases expiring in 2008 and 2009. These New Zealand leases require
payments of approximately $15,000 per month. We also have field offices in
various locations from which our employees supervise local oil and gas
operations.
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.
17
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.
EBITDA -- Earnings before interest, taxes, depreciation, depletion and
amortization.
EBITDAX -- Earnings before interest, taxes, depreciation, depletion and
amortization, and exploration expenses. Since Swift uses full-cost accounting
for oil and property expenditures, as noted in footnote one of the
accompanying consolidated financial statements, exploration expenses are not
applicable to Swift.
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.
18
MMcfe -- Million cubic feet of natural gas equivalent (see Mcfe).
Net Acre -- A net acre is deemed to exist when the sum of fractional working
interests owned in gross acres equals one. The number of net acres is the sum
of fractional working interests owned in gross acres expressed as whole
numbers and fractions thereof.
Net Well -- A net well is deemed to exist when the sum of fractional working
interests owned in gross wells equals one. The number of net wells is the sum
of fractional working interests owned in gross wells expressed as whole
numbers and fractions thereof.
NGL-- Natural gas liquid.
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.
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.
* These definitions regarding various types of proved reserves are only
abbreviated versions of the Securities and Exchange Commission's definitions
of these terms contained in Rule 4-10(a) of Regulation S-X. See
www.sec.gov/divisions/corpfin/forms/regsx.htm#gas for the full text of the
SEC's definitions of these terms.
19
Item 3. Legal Proceedings
No material legal proceedings are pending other than ordinary, routine
litigation and claims incidental to our business.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted during the fourth quarter of 2004 to a vote of
security holders.
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities
Common Stock, 2003 and 2004
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 2003 and 2004 were as follows:
2003 2004
----------------------------------- ------------------------------------
First Second Third Fourth First Second Third Fourth
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
----------------------------------- ------------------------------------
Low $8.51 $7.60 $10.64 $13.57 $15.90 $18.72 $18.16 $23.50
High $9.76 $12.14 $14.57 $18.00 $20.02 $22.75 $25.16 $30.34
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 298 stockholders of record as of December 31, 2004.
Equity Compensation Plan Information
Information regarding our equity compensation plans, including both
shareholder approved plans and plans not approved by shareholders, is set forth
in Proxy Statement for our annual meeting to be held May 10, 2005 ("Proxy
Statement"), which Proxy Statement is to be filed within 120 days after
Registrant's fiscal year end of December 31,2004, and which information is
incorporated by reference.
20
Item 6. Selected Financial Data
2004 2003 2002 2001 2000
Total Revenues $310,276,774 $208,900,983 $149,969,811 $183,807,490 $191,624,946
Income (Loss) Before Income Taxes and
Change in Accounting Principle (1) $101,440,242 $50,739,178 $18,408,289 ($34,192,333) 92,449,488
Net Income (Loss) $68,450,917 $29,893,812 $11,923,227 ($22,347,765) $59,184,008
Net Cash Provided by Operating Activities $182,582,887 $110,827,279 $71,626,314 $139,884,255 $128,197,227
Per Share Data
Weighted Average Shares Outstanding(1) 27,822,413 27,357,579 26,382,906 24,732,099 21,244,684
Earnings (Loss) per Share--Basic(1) $2.46 $1.09 $0.45 ($0.90) $2.79
Earnings (Loss) per Share--Diluted(1) $2.41 $1.08 $0.45 ($0.90) $2.51
Shares Outstanding at Year-End 28,089,764 27,484,091 27,201,509 24,795,564 24,608,344
Book Value per Share at Year-End $16.88 $14.46 $13.42 $12.61 $13.50
Market Price(1)
High $30.34 $18.00 $20.58 $37.70 $43.50
Low $15.90 $7.60 $6.80 $16.66 $9.75
Year-End Close $28.94 $16.85 $9.67 $20.20 $37.63
Effect on Net Income and Earnings Per Share
From Changes in Accounting Principles (2)
Cumulative Effect of Change in Accounting
Principle (Net of Taxes) --- ($4,376,852) --- ($392,868) ---
Effect per Share--Basic --- ($0.16) --- ($0.01) ---
Effect per Share--Diluted --- ($0.16) --- ($0.01) ---
Assets
Current Assets $54,385,996 $33,460,957 $29,768,199 $36,752,980 $41,872,879
Oil and Gas Properties, Net of Accumulated
Depreciation, Depletion, and Amortization $923,438,160 $815,807,003 $721,617,941 $628,304,060 $524,052,828
Total Assets $990,573,147 $859,838,544 $767,005,859 $671,684,833 $572,387,001
Liabilities
Current Liabilities $68,618,291 $69,353,342 $46,884,184 $73,245,335 $64,324,771
Long-Term Debt $357,500,000 $340,254,783 $324,271,973 $258,197,128 $134,729,485
Total Liabilities $516,401,007 $462,447,280 $401,932,675 $359,032,113 $240,232,846
Stockholders' Equity $474,172,140 $397,391,264 $365,073,184 $312,652,720 $332,154,155
Number of Employees 272 241 234 209 181
Producing Wells
Swift Operated 835 870 820 854 817
Outside Operated 97 128 112 381 711
Total Producing Wells 932 998 932 1,235 1,528
Wells Drilled (Gross) 66 75 36 53 70
Proved Reserves
Natural Gas (Mcf) 318,246,294 335,804,862 326,731,672 324,912,125 418,613,976
Oil, NGL, & Condensate (barrels) 80,267,208 80,759,903 70,438,963 53,482,636 35,133,596
Total Proved Reserves (Mcf equivalent) 799,849,539 820,364,284 749,365,449 645,807,939 629,415,552
Production (Mcf equivalent)(3) 58,318,502 53,158,384 49,752,346 44,791,202 42,356,705
Average Sales Price
Natural Gas (per Mcf) $4.12 $3.42 $2.30 $4.23 $4.24
Natural Gas Liquids (per barrel)(4) $22.52 $17.60 $12.82 --- ---
Oil (per barrel)(4) $40.24 $29.89 $24.52 $22.64 $29.35
Mcf Equivalent $5.34 $3.97 $2.84 $4.05 $4.47
1)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.
2)We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on
January 1, 2003. We adopted SFAS No. 133 "Accounting for Derivative Instruments
and Hedging Transactions" on January 1, 2001. As of January 1, 1994, we changed
our revenue recognition policy for earned interests.
3)Natural gas production from 1994 to 2000 includes volumes under a production
payment agreement ranging from 1.4 Bcfe in 1994 to 0.4 Bcfe in 2000.
4)Prior to 2002, we combined NGLs with natural gas for reporting purposes.
21
1999 1998 1997 1996 1995 1994
$110,671,007 $82,469,221 $74,712,180 $56,298,026 $25,092,230 $21,624,231
$29,736,151 ($73,391,581) $33,129,606 $28,785,783 $6,894,537 $4,837,829
$19,286,574 ($48,225,204) $22,310,189 $19,025,450 $4,912,512 ($13,047,027)
$73,603,426 $54,249,017 $55,255,965 $37,102,578 $14,376,463 $10,394,514
18,050,106 16,436,972 16,492,856 15,000,901 10,035,143 7,308,673
$1.07 ($2.93) $1.35 $1.27 $0.49 ($1.79)
$1.07 ($2.93) $1.26 $1.25 $0.49 ($1.79)
20,823,729 16,291,242 16,459,156 15,176,417 12,509,700 6,685,137
$8.18 $6.71 $9.69 $9.41 $7.46 $6.30
$13.31 $21.00 $34.20 $28.86 $11.48 $10.35
$5.69 $6.94 $16.93 $9.89 $7.05 $7.75
$11.50 $7.38 $21.06 $27.16 $10.91 $8.86
--- --- --- --- --- ($16,772,698)
--- --- --- --- --- ($2.52)
--- --- --- --- --- ($2.52)
$50,605,488 $35,246,431 $29,981,786 $101,619,478 $43,380,454 $39,208,418
$392,986,589 $356,711,711 $301,312,847 $200,010,375 $125,217,872 $88,415,612
$454,299,414 $403,645,267 $339,115,390 $310,375,264 $175,252,707 $135,672,743
$34,070,085 $31,415,054 $28,517,664 $32,915,616 $40,133,269 $52,345,859
$239,068,423 $261,200,000 $122,915,000 $115,000,000 $28,750,000 $28,750,000
$283,895,297 $294,282,628 $179,714,470 $167,613,654 $81,906,742 $93,545,612
$170,404,117 $109,362,639 $159,400,920 $142,761,610 $93,345,965 $42,127,131
173 203 194 191 176 209
769 836 650 842 767 750
788 917 917 986 3,316 3,422
1,557 1,753 1,567 1,828 4,083 4,172
27 75 182 153 76 44
329,959,750 352,400,835 314,305,669 225,758,201 143,567,520 76,263,964
20,806,263 13,957,925 7,858,918 5,484,309 5,421,981 4,553,237
454,797,327 436,148,385 361,459,177 258,664,055 176,099,406 103,583,566
42,874,303 39,030,030 25,393,744 19,437,114 11,186,573 9,600,867
$2.40 $2.08 $2.68 $2.57 $1.77 $1.93
--- --- --- --- --- ---
$16.75 $11.86 $17.59 $19.82 $15.66 $14.35
$2.54 $2.05 $2.72 $2.71 $2.01 $2.06
22
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 2004, 2003 and 2002 consolidated
financial statements and our accompanying notes included with this report.
Overview
For 2004, we had revenues of $310.3 million and production of 58.3 Bcfe.
Our revenues were bolstered by oil and gas prices remaining strong and our
domestic production for 2004 increasing to 42.1 Bcfe or by 25% compared to 2003.
We continued to focus our efforts and capital throughout the year on
infrastructure improvements, increased production and the development of
long-lived reserves in the Lake Washington and AWP Olmos areas. Our net
production in Lake Washington for the fourth quarter of 2004 almost doubled as
compared to the same period in 2003, averaging approximately 12,900 net barrels
of oil equivalent per day in the fourth quarter of 2004, compared to
approximately 6,900 net barrels of oil equivalent per day for the same period in
2003. During 2004, capital expenditures were also used for development in our
other domestic core areas. New Zealand accounted for 16.3 Bcfe of production in
2004, a 16% decrease from production in the same period in 2003. Natural gas
production in New Zealand declined primarily due to natural production declines
in our TAWN properties. The TAWN gas contract was renegotiated to lower the
total contract quantity and deliverability rates, and we anticipate meeting
these revised contracted volumes. There is no penalty if the fields are unable
to produce the minimum contracted volumes under the TAWN gas contract. New
Zealand natural gas and natural gas liquids ("NGL") contracts are denominated in
the New Zealand dollar, which has significantly strengthened during the last
several years against the U.S. dollar.
Our production costs were up in 2004 predominantly because of increased
production in Lake Washington, higher severance taxes due to increased domestic
revenues, and currency exchange rates in New Zealand. Our general and
administrative expenses increased in 2004 primarily due to an increase in costs
related to our on going compliance efforts with the Sarbanes-Oxley Act, and to
increased salaries and benefits.
Our debt to PV-10 ratio decreased to 18% at December 31, 2004 compared to
22% at December 31, 2003, due to higher crude oil and natural gas prices, which
have increased our PV-10 value. Our debt to capitalization ratio was 43% at
December 31, 2004 compared to 46% at year-end 2003, as debt levels increased
slightly in 2004 but were offset by the increase in retained earnings as a
result of current year profit. In June 2004, we repurchased $32.1 million of our
10-1/4% senior subordinated notes due 2009 through a tender offer. In July 2004,
we repurchased $0.5 million of our 10-1/4% notes at the close of the tender
offer. On August 1, 2004, we redeemed the remaining $92.5 million of these notes
in accordance with our redemption rights under the indenture governing these
notes. In 2004, we recorded approximately $9.5 million of debt retirement costs
related to the repurchase of these notes. The redemption of these 10-1/4% notes
lowered our effective interest rate.
Year-end 2004 proved reserves of 799.8 Bcfe, representing a 3% decline for
the year, were 49% crude oil, 40% natural gas and 11% NGLs, compared to year-end
2003 proved reserves of 820.4 Bcfe, which were 47% crude oil, 41% natural gas
and 12% NGLs. Proved developed reserves remained essentially the same at 56% of
total reserves at year-end 2004, compared to 59% the previous year. Domestic
proved reserves increased at year-end 2004 to 652.7 Bcfe, driven by the
acquisition of reserves in December 2004 in the Bay de Chene and Cote Blanche
Island fields, which were predominantly proved undeveloped. Proved reserves in
New Zealand decreased to 147.1 Bcfe at year-end 2004, primarily attributable to
2004 production and slight downward revisions in the Manutahi and upper Tariki
Sands. In 2004 we focused our drilling activity, both domestically and in New
Zealand, on proved undeveloped locations that helped maximize production in a
high-price environment, but which also resulted in smaller additions to proved
reserves.
Results of Operations -- Years Ended 2004, 2003, and 2002
Revenues. Our revenues in 2004 increased by 49% compared to revenues in
2003, and our revenues in 2003 increased by 39% compared to 2002 revenues due
primarily to increases in oil and natural gas prices in each successive year and
increases in production from our Lake Washington area. Revenues from our oil and
gas sales
23
comprised substantially all of total revenues for 2004 and 2003, and 94% of
total revenues for 2002. Crude oil production comprised 49% of our production
volumes in 2004, 38% in 2003, and 31% in 2002. Natural gas production comprised
41% of our production volumes in 2004, 53% in 2003, and 55% in 2002. Domestic
production comprised 72% of our total production volumes in 2004, 64% in 2003,
and 69% in 2002.
The following table provides information regarding the changes in the
sources of our oil and gas sales and volumes for the years ended December 31,
2004, 2003, and 2002:
Oil and Gas
Oil and Gas Sales Sales Volume
(In millions) (Bcfe)
----------------------------- -----------------------
Area 2004 2003 2002 2004 2003 2002
- ---- -------- -------- -------- ----- ----- -----
AWP Olmos................$ 49.9 $ 43.7 $ 33.1 9.0 8.4 10.9
Brookeland............... 18.0 16.4 11.9 3.4 3.9 4.1
Lake Washington.......... 152.3 59.5 18.5 23.2 12.1 4.4
Masters Creek............ 21.0 25.7 32.3 3.7 5.7 9.7
Other.................... 17.5 18.9 16.3 2.8 3.7 5.2
-------- -------- -------- ----- ---- ----
Total Domestic........$ 258.7 $ 164.2 $ 112.1 42.1 33.8 34.3
Rimu/Kauri............... 24.5 11.6 4.0 5.3 3.3 1.5
TAWN..................... 28.1 35.2 25.1 11.0 16.1 14.0
-------- -------- -------- ----- ---- ----
Total New Zealand.....$ 52.6 $ 46.8 $ 29.1 16.3 19.4 15.5
-------- -------- -------- ----- ---- ----
Total...................$ 311.3 $ 211.0 $ 141.2 58.3 53.2 49.8
======== ======== ======== ===== ==== ====
Oil and gas sales in 2004 increased by 48%, or $100.3 million, from the
level of those revenues for 2003, and our net sales volumes in 2004 increased by
10%, or 5.2 Bcfe, over net sales volumes in 2003. Average prices for oil
increased to $40.24 per Bbl in 2004 from $29.89 per Bbl in 2003. Average natural
gas prices increased to $4.12 per Mcf in 2004 from $3.42 per Mcf in 2003.
Average NGL prices increased to $22.52 per Bbl in 2004 from $17.60 per Bbl in
2003.
In 2004, our $100.3 million increase in oil, NGL, and natural gas sales
resulted from:
o Price variances that had a $70.6 million favorable impact on sales, of
which $48.9 million was attributable to the 35% increase in average oil
prices received, $16.6 million was attributable to the 20% increase in
natural gas prices and $5.1 million was attributable to the 28% increase
in NGL prices; and
o Volume variances that had a $29.7 million favorable impact on sales,
with $40.4 million of increases attributable to the 1.4 million Bbl
increase in oil sales volumes and $3.8 million to the 217,000 Bbl
increase in NGL sales volumes, offset by a decrease of $14.5 million due
to the 4.3 Bcf decrease in natural gas sales volumes primarily from our
TAWN area in New Zealand.
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 for oil
increased to $29.89 per Bbl in 2003 from $24.52 per Bbl in 2002. Average natural
gas prices increased to $3.42 per Mcf in 2003 from $2.30 per Mcf in 2002.
Average NGL prices increased to $17.60 per Bbl in 2003 from $12.82 per Bbl in
2002.
In 2003, our $69.8 million increase in oil, NGL, and natural gas sales
resulted from:
o Price variances that had a $59.0 million favorable impact on sales, of
which $31.4 million was attributable to the 49% increase in average
natural gas prices and $27.6 million was attributable to the 32%
increase in average combined oil and NGL prices; and
o Volume variances that had a $10.8 million favorable impact on sales,
with $8.8 million of the increases attributable to the 422,000 Bbl
increase in oil and NGL sales volumes, and $2.0 million to the 0.9 Bcf
increase in natural gas sales volumes.
24
The following table provides additional information regarding our quarterly
oil and gas sales:
Sales Volume Average Sales Price
Natural
Oil NGL Gas Combined Oil NGL Gas
------- --------- --------- ---------- ------- ------- -------
(MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf)
2002:
First.................... 594 351 6.6 12.3 $ 19.21 $ 10.83 $ 1.72
Second................... 673 329 6.7 12.7 $ 25.11 $ 12.52 $ 2.60
Third.................... 683 225 6.7 12.2 $ 26.17 $ 13.58 $ 2.32
Fourth................... 647 269 7.1 12.6 $ 27.00 $ 15.25 $ 2.55
------- --------- --------- ----------
Total................. 2,597 1,174 27.1 49.8 $ 24.52 $ 12.82 $ 2.30
======= ========= ========= ==========
2003:
First.................... 690 174 7.6 12.9 $ 32.73 $ 21.90 $ 3.71
Second................... 822 211 7.1 13.3 $ 27.97 $ 15.81 $ 3.47
Third.................... 917 247 6.7 13.6 $ 29.24 $ 16.81 $ 3.17
Fourth................... 941 191 6.6 13.4 $ 30.10 $ 16.71 $ 3.29
------- --------- --------- ----------
Total................. 3,370 823 28.0 53.2 $ 29.89 $ 17.60 $ 3.42
======= ========= ========= ==========
2004:
First.................... 1,124 277 5.9 14.3 $ 34.14 $ 22.30 $ 3.64
Second................... 1,142 269 5.8 14.3 $ 37.24 $ 18.84 $ 4.19
Third.................... 1,076 251 6.0 13.9 $ 41.99 $ 23.33 $ 3.97
Fourth................... 1,380 243 6.1 15.9 $ 46.33 $ 26.01 $ 4.67
------- --------- --------- ----------
Total................. 4,722 1,040 23.7 58.3 $ 40.24 $ 22.52 $ 4.12
======= ========= ========= ==========
Costs and Expenses. Our expenses in 2004 increased $50.7 million, or 32%,
compared to 2003 expenses. The majority of the increase was due to an $18.5
million increase in DD&A, an $11.4 million increase in severance and other
taxes, and a $7.4 million increase in lease operating costs, all of which are
primarily due to increased production volumes and oil and gas commodity prices
in 2004. We also recorded $9.5 million of debt retirement costs in 2004. Our
expenses in 2003 increased $26.6 million, or 20%, compared to 2002 expenses. The
majority of the increase was due to a $4.9 million increase in lease operating
costs, a $6.5 million increase in severance and other taxes, and a $6.8 million
increase in DD&A, all of which increased as our production volumes and revenues
increased in 2003.
Our 2004 general and administrative expenses, net, increased $3.7 million,
or 26%, from the level of such expenses in 2003, while 2003 general and
administrative expenses, net, increased $3.5 million, or 33%, over 2002 levels.
The increase in both 2004 and 2003 were primarily due to compliance with the
Sarbanes-Oxley Act, increased salaries and burdens, and our increased activities
in New Zealand. In 2004, Sarbanes-Oxley Act compliance costs, including internal
and external costs, totaled $2.2 million.. The increase in 2003 was also due to
a reduction in reimbursements from partnerships that we managed as almost all of
the partnerships have been liquidated, along with an increase in franchise tax
expense. For the years 2004, 2003, and 2002, our capitalized general and
administrative costs totaled $13.1 million, $11.5 million, and $10.7 million,
respectively. Our net general and administrative expenses per Mcfe produced
increased to $0.30 per Mcfe in 2004 from $0.27 per Mcfe in 2003 and $0.21 per
Mcfe in 2002. The portion of supervision fees recorded as a reduction to general
and administrative expenses was $5.8 million for 2004, $3.6 million for 2003,
and $3.1 million for 2002.
DD&A increased $18.5 million, or 29%, in 2004 from 2003 levels, while 2003
DD&A increased $6.8 million, or 12%, from 2002 levels. Domestically, DD&A
increased $17.6 million in 2004 due to increases in the depletable oil and gas
property base, higher production in the 2004 period and slightly lower reserve
volumes. In New Zealand, DD&A increased by $0.9 million in 2004 due to increases
in the depletable oil and gas property base along with lower reserve volumes,
offset by lower production in the 2004 period. In 2003, our domestic DD&A
increased by $1.0 million 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. Our New Zealand DD&A increased by $5.8 million in 2003 due to
increased production in the 2003 period. Our DD&A rate per Mcfe of production
was $1.40 in 2004, $1.19 in 2003, and $1.13 in 2002, resulting from increases in
per unit cost of reserves additions.
We recorded $0.7 million and $0.9 million of accretions to our asset
retirement obligation in 2004 and 2003, respectively.
25
Our lease operating costs per Mcfe produced were $0.71 in 2004, $0.64 in
2003 and $0.58 in 2002. There were no supervision fees recorded as a reduction
to production costs in 2004, while there were $1.5 million in 2003 and $2.1
million in 2002. Our lease operating costs in 2004 increased $7.4 million, or
22%, over the level of such expenses in 2003, while 2003 costs increased $4.9
million, or 17% over 2002. Approximately $6.2 million of the increase in lease
operating costs during 2004 was related to our domestic operations, which
increased primarily due to increased compression and chemical costs in Lake
Washington resulting from higher production from our Lake Washington area along
with the reduction of 2003 expense of $1.5 million from supervision fees. Our
lease operating cost in New Zealand increased in 2004 by $1.2 million due to the
continued development of our Rimu/Kauri area and the increased currency exchange
rate of the New Zealand dollar as compared to the U.S. dollar. Approximately
$4.2 million of the increase in 2003 was due to our New Zealand operations as
production increased over 2002 levels.
Severance and other taxes increased $11.4 million, or 60% over 2003 levels,
while in 2003 these taxes increased $6.5 million, or 51% over 2002 levels. The
increase was due primarily to higher commodity prices and increased Lake
Washington and Rimu/Kauri production in each of the periods. Severance taxes on
oil in Louisiana are 12.5% of oil sales, which is higher than the other states
where we have production. As our percentage of oil production in Louisiana
increases, the overall percentage of severance costs to sales also increases.
Severance and other taxes, as a percentage of oil and gas sales, were
approximately 9.8%, 9.0% and 8.9% in 2004, 2003 and 2002, respectively.
Interest expense on our 7-5/8% senior notes due 2011 issued in June 2004,
including amortization of debt issuance costs, totaled $6.2 million in 2004.
Interest expense on our 9-3/8% senior subordinated notes due 2012 issued in
April 2002, including amortization of debt issuance costs, totaled $19.2 million
in 2004, $19.1 million in 2003 and $13.5 million in 2002. Interest expense on
our 10-1/4% senior subordinated notes issued in August 1999 and repurchased and
retired in 2004, including amortization of debt issuance costs, totaled $7.4
million in 2004, and $13.2 million in both 2003 and 2002. Interest expense on
our bank credit facility, including commitment fees and amortization of debt
issuance costs, totaled $1.5 million in 2004, $1.6 million in 2003, and $3.6
million in 2002. Other interest cost was $0.3 million in 2003. Our total
interest cost in 2004 was $34.2 million, of which $6.5 million was capitalized.
Our total interest cost in 2003 was $34.2 million, of which $6.8 million was
capitalized. Our total interest cost in 2002 was $30.3 million, of which $7.0
million was capitalized. We capitalize a portion of interest related to unproved
properties. The increase of interest expense in 2004 was due to lower
capitalized interest than in 2003. The increase in interest expense in 2003 was
attributed to the replacement of our bank borrowings in April 2002 with our
9-3/8% senior subordinated notes due 2012 with a longer repayment term but a
higher interest rate.
In 2004, we incurred $9.5 million of debt retirement costs related to the
repurchase and redemption of our 10-1/4% senior subordinated notes due 2009. The
costs were comprised of approximately $6.5 million of premiums paid to
repurchase the notes, $2.2 million to write-off unamortized debt issuance costs,
$0.6 million to write-off unamortized debt discount and approximately $0.2
million of other costs.
The overall effective tax rate was 32.5% in both 2004 and 2003 and 35.2% in
2002. The effective tax rate for 2004 was lower than the statutory tax rates
primarily due to reductions from the New Zealand statutory rate attributable to
the currency effect on the New Zealand deferred tax calculation, along with
favorable corrections to tax basis amounts discovered while preparing the prior
year's tax returns. These amounts were partially offset by higher deferred state
income taxes. 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 was
partially offset by higher domestic state income taxes and other items.
As discussed in Note 1 to the consolidated financial statements, we adopted
SFAS No. 143 "Accounting for Asset Retirement Obligations" on January 1, 2003.
Our adoption of SFAS No. 143 resulted in a one-time net of taxes charge of $4.4
million, which was recorded as a cumulative effect of change in accounting
principle in the 2003 consolidated statement of income.
Net Income. Our net income in 2004 of $68.5 million was 129% higher than
our 2003 net income of $29.9 million due to higher commodity prices and
increased production.
Our net income in 2003 of $29.9 million was 151% higher than our 2002 net
income of $11.9 million due to higher commodity prices and increased production.
26
Contractual Commitments and Obligations
Our contractual commitments for the next five years and thereafter as of
December 31, 2004 are as follows:
2005 2006 2007 2008 2009 Thereafter Total
-------- -------- ------- ------- ------- ---------- ----------
(In thousands)
Non-cancelable operating leases(1).....$ 2,476 $ 2,559 $ 2,519 $ 2,472 $ 2,342 $ 13,025 $ 25,393
Asset retirement obligation(2)......... 463 515 515 515 515 15,116 17,639
Drilling rigs and seismic.............. 4,355 -- -- -- -- -- 4,355
7-5/8% senior notes due 2011(3)........ -- -- -- -- -- 150,000 150,000
9-3/8% senior subordinated notes
due 2012(3).......................... -- -- -- -- -- 200,000 200,000
Credit facility(4)..................... -- -- -- 7,500 -- -- 7,500
-------- -- -- ------- ------ ---------- ----------
Total................................$ 7,294 $ 3,074 $ 3,034 $10,487 $ 2,857 $ 378,141 $ 404,887
======== ======== ======= ======= ======= ========== ==========
(1) Our office lease in Houston, Texas extends until 2015.
(2) Amounts shown by year are the fair values at December 31, 2004.
(3) Amounts do not include the interest obligation, which is paid semiannually.
(4) The credit facility expires in October 2008 and 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. The price of oil has increased over
the last two years and is currently significantly higher when compared to
longer-term historical prices. Factors such as worldwide supply disruptions,
worldwide economic conditions, weather conditions, actions taken by OPEC, and
fluctuating currency exchange rates can cause wide fluctuations in the price of
oil. Domestic natural gas prices continue to remain high when compared to
longer-term historical prices. North American weather conditions, the industrial
and consumer demand for natural gas, storage levels of natural gas, and the
availability and accessibility of natural gas deposits in North America can
cause significant fluctuations in the price of natural gas. Such factors are
beyond our control.
27
Liquidity and Capital Resources
During 2004, we largely relied upon our net cash provided by operating
activities of $182.6 million, the issuance of our 7-5/8% senior notes due 2011,
proceeds from the sale of non-core properties and equipment of $5.1 million,
less the repayment of our 10-1/4% senior subordinated notes due 2009 to fund
capital expenditures of $171.1 million and acquisitions of $27.2 million. During
2003, we relied upon our net cash provided by operating activities of $110.8
million, proceeds from bank borrowings of $15.9 million, and proceeds from the
sale of non-core properties and equipment of $10.2 million to fund capital
expenditures of $144.5 million.
Net Cash Provided by Operating Activities. For 2004, our net cash provided
by operating activities was $182.6 million, representing a 65% increase as
compared to $110.8 million generated during 2003. The $71.8 million increase in
2004 was primarily due to an increase of $100.3 million in oil and gas sales,
attributable to higher commodity prices and production, offset in part by higher
lease operating costs due to higher domestic production and severance taxes as a
result of higher commodity prices in 2004. In 2003, net cash provided by
operating activities increased by 55% to $110.8 million, as compared to $71.6
million in 2002. 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.
Accounts Receivable. Included in the "Accounts receivable" balance, which
totaled $39.0 million and $27.4 million at December 31, 2004 and 2003,
respectively, on the accompanying balance sheets, is approximately $2.3 million
of receivables related to hydrocarbon volumes produced from 2002 and 2001 that
have been disputed since early 2003. As a result of the dispute, we did not
record a receivable with regard to any 2003 disputed volumes and our contract
governing these sales expired in 2003.
We assess the collectibility of accounts receivable and, based on our
judgment, we accrue a reserve when we believe a receivable may not be collected.
At December 31, 2004 and 2003, we had an allowance for doubtful accounts of $0.5
million. The allowance for doubtful accounts has been deducted from the total
"Accounts receivable" balances on the accompanying consolidated balance sheets.
Sarbanes-Oxley Compliance Costs. We have incurred substantial costs to
comply with the Sarbanes-Oxley Act of 2002. These expenditures have reduced our
net cash provided by operating activities in each of the last two years. In
2004, Sarbanes-Oxley Act compliance costs, including internal and external
costs, totaled $2.2 million and are reflected in "General and administrative,
net" on the accompanying statements of income. We expect the costs of
Sarbanes-Oxley compliance to decrease from 2004 levels in future years.
Existing Credit Facility. We had $7.5 million in borrowings under our bank
credit facility at December 31, 2004, and $15.9 million in outstanding
borrowings at December 31, 2003. Our bank credit facility at December 31, 2004
consisted of a $400.0 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 reaffirmed by our bank group at $250.0 million, effective November 1,
2004. In June 2004, we renewed this credit facility, increasing the facility
amount to $400.0 million from $300.0 million and extending its expiration to
October 1, 2008 from October 1, 2005. We maintained the commitment amount at
$150.0 million, which amount was set at our request effective May 9, 2003. Under
the terms of our bank credit facility, we can increase this commitment amount to
the total amount of the borrowing base at our discretion, subject to the terms
of the credit agreement. Our revolving credit facility includes, among other
restrictions that changed somewhat as the facility was renewed and extended,
requirements to maintain certain minimum financial ratios (principally
pertaining to adjusted working capital ratios and EBITDAX), and limitations on
incurring other debt. We are in compliance with the provisions of this
agreement.
Our access to funds from our credit facility is not restricted under any
"material adverse condition" clause, a clause that is common for credit
agreements to include. A "material adverse condition" clause can remove the
obligation of the banks to fund the credit line if any condition or event would
reasonably be expected to have an adverse or material effect on our operations,
financial condition, prospects or properties, and would impair our ability to
make timely debt repayments. Our credit facility includes covenants that require
us to report events or conditions having a material adverse effect on our
financial condition. The obligation of the banks to fund the credit facility is
not conditioned on the absence of a material adverse effect.
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Working Capital. Our working capital improved from a deficit of $35.9
million at December 31, 2003, to a deficit of $14.2 million at December 31,
2004. The improvement primarily resulted from a decrease in accrued capital
costs due to a reduction in our drilling activities at year-end 2004 in
comparison with year-end 2003 activity, along with an increase in accounts
receivable for oil and gas sales due to higher sales volumes and commodity
prices.
Repurchase of 10-1/4% Senior Subordinated Notes Due 2009. In June 2004, we
repurchased $32.1 million of our 10-1/4 senior subordinated notes due 2009
pursuant to a tender offer, and recorded debt retirement costs of $2.7 million
related to this repurchase. In July 2004, we repurchased approximately $0.5
million of these notes, and as of August 1, 2004, we redeemed the remaining
$92.5 million of these notes. We have recorded a total of $9.5 million in debt
retirement costs related to the total repurchase of these notes.
Debt Maturities. Our credit facility extends until October 1, 2008. Our
$150.0 million of 7-5/8% senior notes mature July 15, 2011, and our $200.0
million of 9-3/8% senior subordinated notes mature May 1, 2012.
Capital Expenditures. We relied upon our net cash provided by operating
activities of $182.6 million, the issuance of our 7-5/8% senior notes due 2011,
and proceeds from the sale of non-core properties and equipment of $5.1 million,
less the repayment of our 10-1/4% senior subordinated notes due 2009, to fund
capital expenditures of $171.1 million and acquisitions of $27.2 million. Our
total capital expenditures of approximately $198.3 million in 2004included:
Domestic expenditures of $162.5 million as follows:
o $87.7 million for drilling and developmental activity costs,
predominantly in our Lake Washington area;
o $31.8 million on property acquisitions, including $27.2 million to
acquire properties in the Bay de Chene and Cote Blanche Island fields;
o $28.7 million of domestic prospect costs, principally prospect
leasehold, Lake Washington three-dimensional seismic activity, and
geological costs of unproved prospects;
o $9.9 million on exploratory drilling, mainly in our Lake Washington
area;
o $2.5 million primarily for a field office building, computer equipment,
software, furniture, and fixtures;
o $1.3 million on field compression facilities; and
o $0.6 million on gas processing plants in the Brookeland and Masters
Creek areas.
New Zealand expenditures of $35.8 million as follows:
o $26.7 million for drilling costs and developmental activity costs,
predominantly in our Rimu/Kauri area;
o $7.0 million on prospect costs, principally prospect leasehold, seismic
and geological costs of unproved properties;
o $1.2 million on gas processing plants;
o $0.7 million on exploratory drilling; and
o $0.2 million for computer equipment, software, furniture, and fixtures.
We have spent considerable time and capital in 2004 and 2003 on significant
facility capacity upgrades in the Lake Washington field to increase facility
capacity to approximately 20,000 barrels per day for crude oil, up from 9,000
barrels per day capacity in the first quarter of 2003. We have upgraded three
production platforms, added new compression for the gas lift system, and
installed a new oil delivery system and permanent barge loading facility.
29
We successfully completed 51 of 66 wells in 2004, for a success rate of
77%. Domestically, we completed 37 of 44 development wells for a success rate of
84% and completed four of ten exploration wells. A total of 30 wells were
drilled in the Lake Washington area, of which 21 were completed, and 15 wells
were drilled in the AWP Olmos area, of which 13 were completed. In New Zealand,
we completed 10 of 12 wells, consisting of four Kauri sand wells drilled, five
of six Manutahi sand wells, and the Tariki-D1 well.
Our 2005 capital expenditure budget is $200 million to $220 million, net of
$5 million to $15 million of dispositions and excluding any acquisitions.
Approximately 80% of the budget is targeted for domestic activities, primarily
in South Louisiana, with about 20% planned for activities in New Zealand.
Approximately $15 million to $20 million of the 2005 budget will be focused on
activity in the newly acquired properties in Bay de Chene and Cote Blanche
Island fields. The $5 million to $15 million of dispositions relate to non-core
properties planned for later in 2005. We expect that our 2005 capital
expenditures will begin at the low end of the range, and depending on commodity
prices and operational performance, they may increase to the high end of the
range during the course of the year. We anticipate 2005 capital expenditures to
approximate our cash flows provided from operating activities during 2005,
similar to 2004. For 2005, we are targeting total production and proved reserves
to increase 7% to 12% over the 2004 levels.
Our capital expenditures were approximately $144.5 million in 2003 and
$155.2 million in 2002. During 2003, we relied upon our net cash provided by
operating activities of $110.8 million, proceeds from bank borrowings of $15.9
million, and proceeds from the sale of non-core properties 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 of 9-3/8%
senior subordinated notes due 2012, and net proceeds from our public stock
offering of $30.5 million, less the repayment of bank borrowings of $134.0
million, to fund capital expenditures of $155.2 million. Our capital
expenditures in 2003 of approximately $144.5 million included:
Domestic activities of $114.4 million as follows:
o $57.0 million on drilling and developmental activities, primarily in our
Lake Washington area;
o $25.9 million for the construction of production and surface facilities,
mainly in our Lake Washington area;
o $11.9 million on exploratory drilling, primarily in our Lake Washington
area;
o $11.4 million on domestic prospect costs, principally leasehold, seismic,
and geological costs;
o $4.4 million on field compression facilities;
o $2.0 million for producing property acquisitions;
o $0.9 million for fixed assets; and
o $0.9 million on gas processing plants in the Brookeland and Masters Creek
areas.
New Zealand activities of $30.1 million as follows:
o $15.1 million on developmental activities primarily to further delineate
the Rimu/Kauri area;
o $6.4 million on prospect costs;
o $5.7 million on gas processing plants;
o $2.3 million for exploratory drilling mainly for the Tuihu exploratory
well;
o $0.3 million on producing properties acquisitions; and
30
o $0.3 million for fixed assets.
In 2003, we participated in drilling 63 domestic development wells and
eight domestic exploratory wells, of which 53 development wells and five
exploratory wells were completed. In New Zealand we drilled and completed three
development wells and drilled one unsuccessful exploratory well.
Income Tax Regulations
The tax laws in the jurisdictions we operate in are continuously changing
and professional judgments regarding such tax laws can differ. We do not believe
the recently enacted American Jobs Creation Act of 2004 will have a material
impact on our financial position or cash flow from operations in the near-term.
New Accounting Principles
In January 2003, the FASB issued Interpretation No. 46 (Revised December
2003) ("FIN 46R"), Consolidation of Variable Interest Entities, an
Interpretation of Accounting Research Bulletin No. 51 consolidated financial
statements (the "Interpretation"). The Interpretation significantly changes
whether entities included in its scope are consolidated by their sponsors,
transferors, or investors. The Interpretation introduces a new consolidation
model - the variable interest model; which determines control (and
consolidation) based on potential variability in gains and losses of the entity
being evaluated for consolidation. The Interpretation provides guidance for
determining whether an entity lacks sufficient equity or its equity holders lack
adequate decision-making ability. These variable interest entities ("VIEs") are
covered by the Interpretation and are to be evaluated for consolidation based on
their variable interests. These provisions applied immediately to variable
interests in VIEs created after January 31, 2003, and to variable interests in
special purpose entities for periods ending after December 15, 2003. The
provisions apply for all other types of variable interests in VIEs for periods
ending after March 15, 2004. We have no variable interests in VIEs, nor do we
have variable interests in special purpose entities. The adoption of this
interpretation had no impact on our financial position or results of operations.
In September and November 2004, the EITF discussed a proposed framework for
addressing when a limited partnership should be consolidated by its general
partner, EITF Issue 04-5. The proposed framework presumes that a sole general
partner in a limited partnership controls the limited partnership, and therefore
should consolidate the limited partnership. The presumption of control can be
overcome if the limited partners have (a) the substantive ability to remove the
sole general partner or otherwise dissolve the limited partnership or (b)
substantive participating rights. The EITF reached a tentative conclusion on the
circumstances in which either kick-out rights or protective rights would be
considered substantive and preclude consolidation by the general partner and
what limited partner's rights would be considered participating rights that
would preclude consolidation by the general partner. The EITF tentatively
concluded that for kick out rights to be considered substantive, the conditions
specified in paragraph B20 of FIN 46R should be met. With regard to the
definition of participating rights that would preclude consolidation by the
general partner, the EITF concluded that the definition of those rights should
be consistent with those in EITF Issue 96-16. The EITF also reached a tentative
conclusion on the transition for Issue 04-05. We do not believe this EITF will
have a material impact on our consolidated financial statements because we
believe our limited partners have substantive kick-out rights under paragraph
B20 of FIN 46R.
In September 2004, the Securities and Exchange Commission issued Staff
Accounting Bulletin No. 106 (SAB 106). SAB 106 expresses the SEC staff's views
regarding SFAS No. 143 and its impact on both the full-cost ceiling test and the
calculation of depletion expense. In accordance with SAB 106, beginning in the
fourth quarter of 2004, undiscounted abandonment cost for future wells, not
recorded at the present time but needed to develop the proved reserves in
existence at the present time, should be included in the unamortized cost of oil
and gas properties, net of related salvage value, for purposes of computing
DD&A. The effect of including undiscounted abandonment costs of future wells to
the undiscounted cost of oil and gas properties will increase depletion expense
in future periods, however, we currently do not believe such increases will be
material.
In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment. SFAS
No. 123R is a revision of SFAS No. 123, Accounting for Stock-Based Compensation,
and supercedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and
amends SFAS No. 95, Statement of Cash Flows. SFAS No. 123R requires all employee
share-based payments, including grants of employee stock options, to be
recognized in the financial
31
statements based on their fair values. SFAS No. 123 discontinues the ability to
account for these equity instruments under the intrinsic value method as
described in APB Opinion No. 25. SFAS No. 123R requires the use of an option
pricing model for estimating fair value, which is amortized to expense over the
service periods. The requirements of SFAS No. 123R are effective for fiscal
periods beginning after June 15, 2005. SFAS No. 123R permits public companies to
adopt its requirements using one of two methods:
o A "modified prospective" method in which compensation cost is recognized
beginning with the effective date based on the requirements of SFAS No.
123R for all share-based payments granted after the effective date and
based on the requirements of SFAS No. 123 for all awards granted to
employees prior to the adoption date of SFAS No. 123R that remain
unvested on the adoption date.
o A "modified retrospective" method which includes the requirements of the
modified prospective method described above, but also permits entities
to restate either all prior periods presented or prior interim periods
of the year of adoption based on the amounts previously recognized under
SFAS No. 123 for purposes of pro forma disclosures.
We have elected to adopt the provisions of SFAS No. 123R on July 1, 2005
using the modified prospective method. As permitted by Statement 123, the
Company currently accounts for share-based payments to employees using APB
Opinion No. 25's intrinsic value method and, as such, generally recognizes no
compensation cost for employee stock options. Accordingly, the adoption of
Statement No. 123R's fair value method is expected to have a significant impact
on our result of operations. However, it will have no impact on our overall
financial position. We currently use the Black-Scholes formula to estimate the
value of stock options granted to employees and expect to continue to use this
acceptable option valuation model upon the required adoption of SFAS No. 123R.
The significance of the impact of adoption will depend on levels of share-based
payments granted in the future. However, had we adopted Statement No. 123R in
prior periods, the impact of that standard would have approximated the impact of
Statement No. 123 as described in the disclosure of pro forma net income and
earnings per share in "Stock Based Compensation," under Note 1 to our
accompanying consolidated financial statements. Statement No. 123R also requires
the benefits of tax deductions in excess of recognized compensation cost to be
reported as a financing cash flow, rather than as an operating cash flow as
required under current literature. This requirement will reduce net operating
cash flows and increase net financing cash flows in periods after adoption.
While the Company cannot estimate what those amounts will be in the future
(because they depend on, among other things, when employees exercise stock
options), the amount of excess tax deductions recognized were $2.0 million, $0.2
million, and $0.3 million in 2004, 2003 and 2002, respectively. These deductions
resulted in an increase in operating cash flows, however, due to the Company's
net operating tax loss position, deferred income taxes were reduced rather than
actual cash taxes paid.
Proved Oil and Gas Reserves.
At year-end 2004, our total proved reserves were 799.8 Bcfe with a PV-10
Value of $2.0 billion. In 2004, our proved natural gas reserves decreased 17.6
Bcf, or 5%, while our proved oil reserves increased 1.8 MMBbl, or 3%, and our
NGL reserves decreased 2.3 MMBbl, or 14%, for a total equivalent decrease of
20.5 Bcfe, or 3%. In 2003, our proved natural gas reserves increased by 9.1 Bcf,
or 3%, while our proved oil reserves increased by 11.4 MMBbl, or 22%, and our
NGL reserves decreased by 1.0 MMBbl, or 6%, for a total equivalent increase of
71.0 Bcfe, or 9%. We added reserves over the past three years through both our
drilling activity and purchases of minerals in place. Through drilling we added
7.2 Bcfe (all of which was domestic) of proved reserves in 2004, 105.6 Bcfe
(36.1 Bcfe of which came from New Zealand) in 2003, and 83.9 Bcfe (15.9 Bcfe of
which came from New Zealand) in 2002. Through acquisitions we added 43.4 Bcfe of
proved reserves in 2004, 0.5 Bcfe in 2003, and 74.2 Bcfe in 2002. At year-end
2004, 56% of our total proved reserves were proved developed, compared with 59%
at year-end 2003 and 60% at year-end 2002.
The PV-10 Value of our total proved reserves increased 31% from the PV-10
Value at year-end 2003. Gas prices increased in 2004 to $5.16 per Mcf from $4.56
per Mcf at year-end 2003, compared to $3.49 per Mcf at year-end 2002. Oil prices
increased in 2004 to $41.07 per Bbl from $30.16 per Bbl at year-end 2003,
compared to $29.27 in 2002. Under SEC guidelines, estimates of proved reserves
must be made using year-end oil and gas sales prices and are held constant, for
that year's reserve calculation, 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.
32
Critical Accounting Policies
The following summarizes several of our critical accounting policies. See a
complete list of significant accounting policies in Note 1 to the consolidated
financial statements.
Use of Estimates. The preparation of financial statements in conformity
with generally accepted accounting principles (GAAP) requires us to make
estimates and assumptions that affect the reported amount of certain assets and
liabilities and the reported amounts of certain revenues and expenses during
each reporting period. We believe our estimates and assumptions are reasonable;
however, such estimates and assumptions are subject to a number of risks and
uncertainties that may cause actual results to differ materially from such
estimates. Significant estimates that were used to prepare these financial
statements include:
o the estimated quantities of proved oil and natural gas reserves used to
compute depletion of our properties and the related present value of
estimated future net cash flows from these properties,
o accruals related to oil and gas production and revenues, capital
expenditures and lease operating and severance tax expenses,
o the estimated future cost and timing of asset retirement obligations, and
o estimates made in our income tax calculations.
While we are not aware of any significant revisions to any of our
estimates, there will likely be future revisions to our estimates resulting from
matters such as changes in ownership interests, payouts, joint venture audits,
re-allocations by purchasers or pipelines, or other corrections and adjustments
common in the oil and gas industry, many of which require retroactive
application. These types of adjustments cannot be currently estimated and will
be recorded in the period during which the adjustment occurs.
Property and Equipment. We follow the "full-cost" method of accounting for
oil and gas property and equipment costs. Under this method of accounting, all
productive and nonproductive costs incurred in the exploration, development, and
acquisition of oil and gas reserves are capitalized. Such costs may be incurred
both prior to and after the acquisition of a property and include lease
acquisitions, geological and geophysical services, drilling, completion, and
equipment. Internal costs incurred that are directly identified with
exploration, development, and acquisition activities undertaken by us for our
own account, and which are not related to production, general corporate
overhead, or similar activities, are also capitalized. For the years 2004, 2003,
and 2002, such internal costs capitalized totaled $13.1 million, $11.5 million,
and $10.7 million, respectively. Interest costs are also capitalized to unproved
oil and gas properties. For the years 2004, 2003, and 2002, capitalized interest
on unproved properties totaled $6.5 million, $6.8 million, and $7.0 million,
respectively. Interest not capitalized and general and administrative costs
related to production and general overhead are expensed as incurred.
Full-CostCeiling Test. At the end of each quarterly reporting period, the
unamortized cost of oil and gas properties, including gas processing facilities,
capitalized asset retirement obligations, net of related salvage values and
deferred income taxes, and excluding the asset retirement obligation liability
is limited to the sum of the estimated future net revenues from proved
properties, excluding cash outflows from asset retirement obligations, including
future abandonment costs of wells to be drilled, using period-end prices,
adjusted for the effects of hedging, discounted at 10%, and the lower of cost or
fair value of unproved properties, adjusted for related income tax effects
("Ceiling Test"). Our hedges at year-end 2004 consisted mainly of natural gas
and crude oil price floors with strike prices lower than the period end price
and thus did not materially affect prices used in this calculation. This
calculation is done on a country-by-country basis for those countries with
proved reserves.
The calculation of the Ceiling Test and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves. There are
numerous uncertainties inherent in estimating quantities of proved reserves and
in projecting the future rates of production, timing, and plan of development.
The accuracy of any reserves estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. Results of
drilling, testing, and production subsequent to the date of the estimate may
justify revision of such estimate. Accordingly, reserves estimates are often
different from the quantities of oil and gas that are ultimately recovered.
33
Given the volatility of oil and gas prices, it is reasonably possible that
our estimate of discounted future net cash flows from proved oil and gas
reserves could change in the near term. If oil and gas prices decline from our
period-end prices used in the Ceiling Test, even if only for a short period, it
is possible that non-cash write-downs of oil and gas properties could occur in
the future.
Price-Risk Management Activities. The Company follows SFAS No. 133, which
requires that changes in the derivative's fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. The statement also
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) is recorded in the balance sheet as either an asset or a liability
measured at its fair value. Hedge accounting for a qualifying hedge allows the
gains and losses on derivatives to offset related results on the hedged item in
the income statements and requires that a company formally document, designate,
and assess the effectiveness of transactions that receive hedge accounting.
Changes in the fair value of derivatives that do not meet the criteria for hedge
accounting, and the ineffective portion of the hedge, are recognized currently
in income.
We have a price-risk management policy to use derivative instruments to
protect against declines in oil and gas prices, mainly through the purchase of
price floors and collars. During 2004, 2003 and 2002, we recognized net losses
of $1.3 million, $2.8 million and $0.2 million, respectively, relating to our
derivative activities. This activity is recorded in "Price-risk management and
other, net" on the accompanying statements of income. At December 31, 2004, the
Company had recorded $0.5 million, net of taxes of $0.3 million, of derivative
losses in "Accumulated other comprehensive income (loss), net of income tax" on
the accompanying balance sheet. This amount represents the change in fair value
for the effective portion of our hedging transactions that qualified as cash
flow hedges. The ineffectiveness reported in "Price-risk management and other,
net" for 2004, 2003 and 2002 was not material. We expect to reclassify all
amounts currently held in "Accumulated other comprehensive income (loss), net of
income tax" into the statement of income within the next twelve months when the
forecasted sale of hedged production occurs.
At December 31, 2004, we had in place price floors in effect through the
December 2004 contract month for natural gas, these cover a portion of our
domestic natural gas production for January 2005 to December 2005. The natural
gas price floors cover notional volumes of 4,000,000 MMBtu, with a weighted
average floor price of $5.83 per MMBtu. Our natural gas price floors in place at
December 31, 2004 are expected to cover approximately 30% to 35% of our domestic
natural gas production from January 2005 to December 2005. At December 31, 2004,
we also had in place crude oil price floors in effect through the March 2005
contract month, which cover a portion our domestic crude oil production for
January 2005 to March 2005. The crude oil price floors cover notional volumes of
216,000 barrels, with a weighted average floor price of $37.00 per barrel. Our
crude oil price floors in place at December 31, 2004 are expected to cover
approximately 15% to 20% of our domestic crude oil production from January 2005
to March 2005.
When we entered into these transactions discussed above, they were
designated as a hedge of the variability in cash flows associated with the
forecasted sale of natural gas and crude oil production. Changes in the fair
value of a hedge that is highly effective and is designated and documented and
qualifies as a cash flow hedge, to the extent that the hedge is effective, are
recorded in "Accumulated other comprehensive income (loss), net of income tax."
When the hedged transactions are recorded upon the actual sale of oil and
natural gas, these gains or losses are reclassified from "Accumulated other
comprehensive income (loss), net of income tax" and recorded in "Price-risk
management and other, net" on the consolidated statement of income. The fair
value of our derivatives are computed using the Black-Scholes option pricing
model and are periodically verified against quotes from brokers. The fair value
of these instruments at December 31, 2004, was $1.8 million and is recognized on
the balance sheet in "Other current assets."
From January 2005 to the date of this filing, we entered into additional
natural gas price floors covering contract periods April 2005 to October 2005,
which cover our natural gas production for April 2005 to October 2005. Notional
volumes are 1,300,000 MMBtu at a weighted average floor price of $5.73 per
MMBtu.
See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk"
for additional discussion of commodity risk.
34
Stock Based Compensation. We have two stock-based compensation plans, which
are described more fully in Note 6 to our accompanying consolidated financial
statements. We account for those plans under the recognition and measurement
principles of APB Opinion No. 25, "Accounting for Stock Issued to Employees,"
and related interpretations. We issued restricted stock for the first time in
2004, and recorded expense related to these shares of less than $0.1 million in
"General and administrative, net" on the accompanying statements of income. No
stock-based employee compensation cost is reflected in net income for employee
stock options, as all options granted under those plans had an exercise price
equal to the market value of the underlying common stock on the date of the
grant; or in the case of the employee stock purchase plan, the purchase price is
85% of the lower of the closing price of our common stock as quoted on the New
York Stock Exchange at the beginning or end of the plan year or a date during
the year chosen by the participant.
Foreign Currency. We use the U.S. Dollar as our functional currency in New
Zealand. The functional currency is determined by examining the entities' cash
flows, commodity pricing, environment and financing arrangements. We have both
assets and liabilities denominated in New Zealand Dollars, predominantly a
portion of our "Deferred income taxes" and a portion of our "Asset Retirement
Obligation" on the accompanying balance sheet. For accounts other than "Deferred
income taxes," as the currency rate changes between the U.S. Dollar and the New
Zealand Dollar, we recognize transaction gains and losses in "Price-risk
management and other, net" on the accompanying statements of income. We
recognize transaction gains and losses on "Deferred income taxes" in "Provision
for Income Taxes" on the accompanying statement of income.
Related-Party Transactions
We have been the operator of a number of properties owned by affiliated
limited partnerships and, accordingly, charge these entities operating fees. The
operating fees charged to the partnerships totaled approximately $0.2 million in
2004 and 2003 and approximately $0.3 million in 2002, and are recorded as
reductions of general and administrative, net. We also have been reimbursed for
administrative, and overhead costs incurred in conducting the business of the
limited partnerships, which totaled approximately $0.2 million, $0.4 million,
and $1.0 million in 2004, 2003, and 2002, respectively, and are recorded as
reductions in general and administrative, net. Included in "Accounts receivable"
and "Accounts payable and accrued liabilities" on the accompanying balance
sheets, is less than $0.1 million and $1.1 million, respectively, in receivables
from and payables to the partnerships at December 31, 2004.
We receive research, technical writing, publishing, and website-related
services from Tec-Com Inc., a corporation located in Knoxville, Tennessee and
controlled by the sister of the Company's Chairman and Vice Chairman of the
Board. The sister and brother-in-law of Messrs. A. E. Swift and V. Swift also
own a substantial majority of Tec-Com. In 2004, 2003 and 2002, we paid
approximately $0.4 million per year to Tec-Com for such services pursuant to the
terms of the contract between the parties. The contract was renewed June 30,
2004 on substantially the same terms and expires June 30, 2007. We believe that
the terms of this contract are consistent with third party arrangements that
provide similar services. As a matter of corporate governance policy and
practice, related party transactions are annually presented and considered by
the Corporate Governance Committee of our Board of Directors in accordance with
the Committee's charter.
Other Factors Affecting Our Business and Financial Results
Oil and natural gas prices are volatile. A substantial decrease in oil and
natural gas prices would adversely affect our financial results.
Our future financial condition, results of operations, and the value of our
oil and natural gas properties depend primarily upon market prices for oil and
natural gas. Oil and natural gas prices historically have been volatile and will
likely continue to be volatile in the future. The recent record high oil and
natural gas prices may not continue and could drop precipitously in a short
period of time. The prices for oil and natural gas are subject to wide
fluctuation in response to relatively minor changes in the supply of and demand
for oil and natural gas, market uncertainty, worldwide economic conditions,
weather conditions, import prices, political conditions in major oil producing
regions, especially the Middle East, and actions taken by OPEC. A significant
decrease in price levels for an extended period would negatively affect us in
several ways:
35
o our cash flow would be reduced, decreasing funds available for capital
expenditures employed to increase production or replace reserves;
o certain reserves would no longer be economic to produce, leading to both
lower cash flow and proved reserves;
o our lenders could reduce the borrowing base under our bank credit
facility because of lower oil and natural gas reserve values, reducing
our liquidity and possibly requiring mandatory loan repayments; and
o access to other sources of capital, such as equity or long term debt
markets, could be severely limited or unavailable in a low price
environment.
Consequently, our revenues and profitability would suffer.
Our level of debt could reduce our financial flexibility, and we currently
have the ability to incur substantially more debt, including secured debt.
As of December 31, 2004, our total debt comprised approximately 43% of our
total capitalization. Although our bank credit facility and indentures limit our
ability and the ability of our restricted subsidiaries to incur additional
indebtedness, we will be permitted to incur significant additional indebtedness,
including secured indebtedness, in the future if specified conditions are
satisfied. All borrowings under our bank credit facility are effectively senior
to our outstanding 7-5/8% senior notes and 9-3/8% senior subordinated notes to
the extent of the value of the collateral securing those borrowings. Our current
level of indebtedness:
o will require us to dedicate a substantial portion of our cash flow to the
payment of interest;
o will subject us to a higher financial risk in an economic downturn due to
substantial debt service costs;
o may limit our ability to obtain financing or raise equity capital in the
future; and
o may place us at a competitive disadvantage to the extent that we are more
highly leveraged than some of our peers. Higher levels of indebtedness
would increase these risks.
Estimates of proved reserves are uncertain, and revenues from production may
vary significantly from expectations.
The quantities and values of our proved reserves included in this report
are only estimates and subject to numerous uncertainties. Estimates by other
engineers might differ materially. The accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geological
interpretation. These estimates depend on assumptions regarding quantities and
production rates of recoverable oil and natural gas reserves, future prices for
oil and natural gas, timing and amounts of development expenditures and
operating expenses, all of which will vary from those assumed in our estimates.
These variances may be significant.
Any significant variance from the assumptions used could result in the
actual amounts of oil and natural gas ultimately recovered and future net cash
flows being materially different from the estimates in our reserve reports. In
addition, results of drilling, testing, production, and changes in prices after
the date of the estimates of our reserves may result in substantial downward
revisions. These estimates may not accurately predict the present value of net
cash flows from our oil and natural gas reserves.
At December 31, 2004, approximately 44% of our estimated proved reserves
were undeveloped. Recovery of undeveloped reserves generally requires
significant capital expenditures and successful drilling operations. The reserve
data assumes that we can and will make these expenditures and conduct these
operations successfully, which may not occur.
36
If we cannot replace our reserves, our revenues and financial condition will
suffer.
Unless we successfully replace our reserves, our long- term production will
decline, which could result in lower revenues and cash flow. When oil and
natural gas prices decrease, our cash flow decreases, resulting in less
available cash to drill and replace our reserves and an increased need to draw
on our bank credit facility. Even if we have the capital to drill, unsuccessful
wells can hurt our efforts to replace reserves. Additionally, lower oil and
natural gas prices can have the effect of lowering our reserve estimates and the
number of economically viable prospects that we have to drill.
Drilling wells is speculative and capital intensive.
Developing and exploring properties for oil and natural gas requires
significant capital expenditures and involves a high degree of financial risk.
The budgeted costs of drilling, completing, and operating wells are often
exceeded and can increase significantly when drilling costs rise. Drilling may
be unsuccessful for many reasons, including title problems, weather, cost
overruns, equipment shortages, and mechanical difficulties. Moreover, the
successful drilling or completion of an oil or gas well does not ensure a profit
on investment. Exploratory wells bear a much greater risk of loss than
development wells.
We may incur substantial losses and be subject to substantial liability
claims as a result of our oil and natural gas operations.
We are not insured against all risks. Losses and liabilities arising from
uninsured and underinsured events could materially and adversely affect our
business, financial condition, or results of operations. Our oil and natural gas
exploration and production activities are subject to all of the operating risks
associated with drilling for and producing oil and natural gas, including the
possibility of:
o environmental hazards, such as uncontrollable flows of oil, natural gas,
brine, well fluids, toxic gas, or other pollution into the environment,
including groundwater and shoreline contamination;
o abnormally pressured formations;
o mechanical difficulties, such as stuck oil field drilling and service
tools and casing collapse;
o fires and explosions;
o personal injuries and death; and
o natural disasters.
Any of these risks could adversely affect our ability to conduct operations
or result in substantial losses. We may elect not to obtain insurance if we
believe that the cost of available insurance is excessive relative to the risks
presented. In addition, pollution and environmental risks generally are not
fully insurable. If a significant accident or other event occurs and is not
fully covered by insurance, it could adversely affect our financial condition.
We are exposed to the risk of fluctuations in foreign currencies, primarily
the New Zealand dollar.
Fluctuations in rates between the New Zealand dollar and U.S. dollar impact
our financial results from our New Zealand subsidiaries since we have
receivables, liabilities, and natural gas and NGL sales contracts denominated in
New Zealand dollars. We do not hedge against the risks associated with
fluctuations in exchange rates. Although we may use hedging techniques in the
future, we may not be able to eliminate or reduce the effects of currency
fluctuations. As a result, exchange rate fluctuations could have an adverse
impact on our operating results.
We have incurred a write-down of the carrying values of our properties in
the past and could incur additional
37
write-downs in the future.
Under the full cost method of accounting, SEC accounting rules require that
on a quarterly basis we review the carrying value of our oil and gas properties
on a country-by-country basis for possible write-down or impairment. Under these
rules, capitalized costs of proved reserves may not exceed a ceiling calculated
at the present value of estimated future net revenues from those proved
reserves, determined using a 10% per year discount and unescalated prices in
effect as of the end of each fiscal quarter. Capital costs in excess of the
ceiling must be permanently written down.
We recorded an after-tax, non-cash charge during the fourth quarter of 2001
of $63.5 million. This write-down resulted in a charge to earnings and a
reduction of stockholders' equity, but did not impact our cash flow from
operating activities. If commodity prices decline or if we have significant
downward reserve revisions, we could incur additional write-downs in the future.
Substantial acquisitions or other transactions could require significant
external capital and could change our risk and property profile.
To finance acquisitions, we may need to substantially alter or increase our
capitalization through the use of our bank credit facility, the issuance of debt
or equity securities, the sale of production payments, or by other means. These
changes in capitalization may significantly affect our risk profile.
Additionally, significant acquisitions or other transactions can change the
character of our operations and business. The character of the new properties
may be substantially different in operating or geological characteristics or
geographic location than our existing properties. Furthermore, we may not be
able to obtain external funding for any such acquisitions or other transactions
or to obtain external funding on terms acceptable to us.
Reserves on acquired properties may not meet our expectations, and we may be
unable to identify liabilities associated with acquired properties or obtain
protection from sellers against associated liabilities.
Property acquisition decisions are based on various assumptions and
subjective judgments that are speculative. Although available geological and
geophysical information can provide information about the potential of a
property, it is impossible to predict accurately a property's production and
profitability. In addition, we may have difficulty integrating future
acquisitions into our operations, and they may not achieve our desired
profitability objectives. Likewise, as is customary in the industry, we
generally acquire oil and gas acreage without any warranty of title except
through the transferor. In many instances, title opinions are not obtained if,
in our judgment, it would be uneconomical or impractical to do so. Losses may
result from title defects or from defects in the assignment of leasehold rights.
While our current operations are primarily in Louisiana, Texas, and New Zealand,
we may pursue acquisitions of properties located in other geographic areas,
which would decrease our geographical concentration, and could also be in areas
in which we have no or limited experience.
In addition, our assessment of acquired properties may not reveal all
existing or potential problems or liabilities, nor will it permit us to become
familiar enough with the properties to assess fully their capabilities and
deficiencies. In the course of our due diligence, we may not inspect every well,
platform, or pipeline. Inspections may not reveal structural and environmental
problems, such as pipeline corrosion or groundwater contamination. We may not be
able to obtain contractual indemnities from the seller for liabilities that it
created. We may be required to assume the risk of the physical condition of
acquired properties in addition to the risk that the properties may not perform
in accordance with our expectations.
Prospects that we decide to drill may not yield oil or natural gas in
commercially viable quantities.
There is no way to predict in advance of drilling and testing whether any
particular prospect will yield oil or natural gas in sufficient quantities, if
at all, to recover drilling or completion costs or to be economically viable.
The use of seismic data and other technologies and the study of producing fields
in the same area will not enable us to know conclusively prior to drilling
whether oil or natural gas will be present. We cannot assure you that the
analogies we draw from available data from other wells, more fully explored
prospects, or producing fields will be applicable to our drilling prospects. In
addition, a variety of factors, including geological and market-related, can
cause a well to become uneconomical or only marginally economical. For example,
if oil and natural gas prices are
38
much lower after we complete a well than when we identified it as a prospect,
the completed well may not yield commercially viable quantities.
Our use of oil and natural gas price hedging contracts involves credit risk
and may limit future revenues from price increases and expose us to risk of
financial loss.
We enter into hedging transactions for our oil and natural gas production
to reduce exposure to fluctuations in the price of oil and natural gas,
primarily to protect against declines in prices. Our hedges at year-end 2004
consisted of mainly natural gas price floors with strike prices lower than the
period end prices. Our hedging transactions have also consisted of financially
settled crude oil and natural gas forward sales contracts with major financial
institutions as well as crude oil price floors. We intend to continue to enter
into these types of hedging transactions in the foreseeable future. Hedging
transactions expose us to risk of financial loss in some circumstances,
including if production is less than expected, the other party to the contract
defaults on its obligations, or there is a change in the expected differential
between the underlying price in the hedging agreement and actual prices
received. Hedging transactions other than floors may limit the benefit we would
have otherwise received from increases in the price for oil and natural gas.
Additionally, hedging transactions other than floors may expose us to cash
margin requirements.
We may have difficulty competing for oil and gas properties or supplies.
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 the 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.
Our business depends on oil and natural gas transportation facilities, some
of which are owned by others.
The marketability of our oil and natural gas production depends in part on
the availability, proximity, and capacity of pipeline systems owned by third
parties. The unavailability of or lack of available capacity on these systems
and facilities could result in the shut-in of producing wells or the delay or
discontinuance of development plans for properties. Although we have some
contractual control over the transportation of our product, material changes in
these business relationships could materially affect our operations. Federal and
state regulation of oil and natural gas production and transportation, tax and
energy policies, changes in supply and demand, pipeline pressures, damage to or
destruction of pipelines and general economic conditions could adversely affect
our ability to produce, gather and transport oil and natural gas.
Governmental laws and regulations are costly and stringent, especially those
relating to environmental protection.
Our domestic exploration, production, and marketing operations are subject
to complex and stringent federal, state, and local laws and regulations
governing the discharge of substances into the environment or otherwise relating
to environmental protection. These laws and regulations affect the costs,
manner, and feasibility of our operations and require us to make significant
expenditures in our efforts to comply. Failure to comply with these laws and
regulations may result in the assessment of administrative, civil, and criminal
penalties, the imposition of investigatory and remedial obligations, and the
issuance of injunctions that could limit or prohibit our operations. In
addition, some of these laws and regulations may impose joint and several,
strict liability for contamination resulting from spills, discharges, and
releases of substances, including petroleum hydrocarbons and other wastes,
without regard to fault or the legality of the original conduct. Under such laws
and regulations, we could be required to remove or remediate previously disposed
substances and property contamination, including wastes disposed or released by
prior owners or operations. Changes in or additions to environmental laws and
regulations occur frequently, and any changes or additions that result in more
stringent and costly waste handling, storage, transport, disposal, or cleanup
requirements could have a material adverse effect our operations and financial
position.
Our operations outside of the United States could also be subject to
similar foreign governmental controls and restrictions pertaining to protection
of human health and the environment. These controls and restrictions may
39
include the need to acquire permits, prohibitions on drilling in certain
environmentally sensitive areas, performance of investigatory or remedial
actions for any releases of petroleum hydrocarbons or other wastes caused by us
or prior owners or operators, closure, and restoration of facility sites, and
payment of penalties for violations of applicable laws and regulations.
40
Forward-Looking Statements
The statements contained in this report that are not historical facts are
forward-looking statements as that term is defined in Section 21E of the
Securities Exchange Act of 1934, as amended. Such forward-looking statements may
pertain to, among other things, financial results, capital expenditures,
drilling activity, development activities, cost savings, production efforts and
volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory
matters, and competition. Such forward-looking statements generally are
accompanied by words such as "plan," "future," "estimate," "expect," "budget,"
"predict," "anticipate," "projected," "should," "believe," or other words that
convey the uncertainty of future events or outcomes. Such forward-looking
information is based upon management's current plans, expectations, estimates,
and assumptions, upon current market conditions, and upon engineering and
geologic information available at this time, and is subject to change and to a
number of risks and uncertainties, and, therefore, actual results may differ
materially. Among the factors that could cause actual results to differ
materially are: volatility in oil and natural gas prices, internationally or in
the United States; availability of services and supplies; fluctuations of the
prices received or demand for our oil and natural gas; the uncertainty of
drilling results and reserve estimates; operating hazards; requirements for
capital; general economic conditions; changes in geologic or engineering
information; changes in market conditions; competition and government
regulations; as well as the risks and uncertainties discussed in this report and
set forth from time to time in our other public reports, filings, and public
statements. Also, because of the volatility in oil and gas prices and other
factors, interim results are not necessarily indicative of those for a full
year.
41
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk. Our major market risk exposure is the commodity pricing
applicable to our oil and natural gas production. Realized commodity prices
received for such production are primarily driven by the prevailing worldwide
price for crude oil and spot prices applicable to natural gas. The effects of
such pricing volatility are expected to continue.
Our price-risk management policy permits the utilization of agreements and
financial instruments (such as futures, forward contracts, swaps and options
contracts) to mitigate price risk associated with fluctuations in oil and
natural gas prices. Below is a description of the financial instruments we have
utilized to hedge our exposure to price risk.
o Price Floors - At December 31, 2004, we had in place price floors in
effect through the December 2005 contract month for natural gas, these
cover a portion of our domestic natural gas production for January 2005
to December 2005. The natural gas price floors cover notional volumes of
4,000,000 MMBtu, with a weighted average floor price of $5.83 per MMBtu.
Our natural gas price floors in place at December 31, 2004 are expected
to cover approximately 30% to 35% of our domestic natural gas production
from January 2005 to December 2005. At December 31, 2004, we also had in
place crude oil price floors in effect through the March 2005 contract
month, which cover a portion of our domestic crude oil production for
January 2005 to March 2005. The crude oil price floors cover notional
volumes of 216,000 barrels, with a weighted average floor price of $37.00
per barrel. Our crude oil price floors in place at December 31, 2004 are
expected to cover approximately 15% to 20% of our domestic crude oil
production from January 2005 to March 2005. The fair value of these
instruments at December 31, 2004, was $1.8 million and is recognized on
the accompanying balance sheet in "Other current assets." There are no
additional cash outflows for these price floors, as the cash premium was
paid at inception of the hedge. The maximum loss that could be sustained
from these price floors in 2005 would be their fair value at December 31,
2004 of $1.8 million.
o New Zealand Gas Contracts - All of our gas production in New Zealand is
sold under long-term, fixed-price contracts denominated in New Zealand
Dollars. These contracts protect against price volatility, and our
revenue from these contracts will vary only due to production
fluctuations and foreign exchange rates.
Interest Rate Risk. Our senior notes and senior subordinated notes both
have fixed interest rates, so consequently we are not exposed to cash flow risk
from market interest rate changes on these notes. At December 31, 2003, we had
$7.5 million in outstanding borrowings under our credit facility, which bears a
floating rate of interest and therefore is susceptible to interest rate
fluctuations. The result of a 10% fluctuation in the bank's base rate would
constitute 53 basis points and would reduce 2005 cash flows by less than $0.1
million based on the December 31, 2004 level of borrowing.
Income Tax Carryforwards. We had significant federal and state net
operating loss and capital loss carryforwards at December 31, 2004. The Company
has not recorded a valuation allowance against the deferred tax assets
attributable to these carryovers at December 31, 2004, as management estimates
that it is more likely than not that these assets will be fully utilized before
they expire except for a $0.5 million valuation allowance against the capital
loss carryforward, as detailed in Note 3 of the accompanying consolidated
financial statements. Significant changes in estimates caused by changes in oil
and gas prices, production levels, capital expenditures, and other variables
could impact the Company's ability to utilize the carryover amounts. If we are
not able to use our carryforwards, our results of operations and cash flows will
be negatively impacted.
Financial Instruments and Debt Maturities. Our financial instruments
consist of cash and cash equivalents, accounts receivable, accounts payable,
bank borrowings, and senior notes. The carrying amounts of cash and cash
equivalents, accounts receivable, and accounts payable approximate fair value
due to the highly liquid or short-term nature of these instruments. The fair
values of the bank borrowings approximate the carrying amounts as of December
31, 2004 and 2003, and were determined based upon variable interest rates
currently available to us for borrowings with similar terms. Based upon quoted
market prices as of December 31, 2004 and 2003, the fair values of our senior
subordinated notes due 2012 were $224.0 million, or 112.0% of face value, and
$218.0 million, or 109% of face value, respectively. Based upon quoted market
prices as of December 31, 2004, the fair value of our senior notes due 2011 was
$162.4 million, or 108.25% of face value.
42
The carrying value of our senior subordinated notes due 2012 was $200.0 million
at December 31 for both 2004 and 2003. The carrying value of our senior notes
due 2011 was $150.0 million at December 31, 2004.
Foreign Currency Risk. We are exposed to the risk of fluctuations in
foreign currencies, most notably the New Zealand Dollar. Fluctuations in rates
between the New Zealand Dollar and U.S. Dollar may impact our financial results
from our New Zealand subsidiaries since we have receivables, liabilities,
natural gas and NGL sales contracts, and New Zealand income tax calculations,
all denominated in New Zealand Dollars. We use the U.S. Dollar as our functional
currency in New Zealand and because of this, our results of operations, cash
flows and effective tax rate are impacted from fluctuations between the U.S.
Dollar and the New Zealand Dollar.
Customer Credit Risk. We are exposed to the risk of financial
non-performance by customers. Our ability to collect on sales to our customers
is dependent on the liquidity of our customer base. To manage customer credit
risk, we monitor credit ratings of customers and seek to minimize exposure to
any one customer where other customers are readily available. Due to
availability of other purchasers, we do not believe the loss of any single oil
or gas customer would have a material adverse effect on our results of
operations.
43
Item 8. Financial Statements and Supplementary Data
Management's Report on Internal Control
Over Financial Reporting...........................................45
Report of Independent Registered Public Accounting Firm on Internal
Control Over Financial Reporting...................................46
Report of Independent Registered Public Accounting Firm...................47
Consolidated Balance Sheets...............................................48
Consolidated Statements of Income.........................................49
Consolidated Statements of Stockholders' Equity...........................50
Consolidated Statements of Cash Flows.....................................51
Notes to Consolidated Financial Statements................................52
1. Summary of Significant Accounting Policies..........................52
2. Earnings Per Share..................................................61
3. Provision for Income Taxes..........................................61
4. Long-Term Debt .....................................................65
5. Commitments and Contingencies.......................................68
6. Stockholders' Equity................................................68
7. Related-Party Transactions..........................................69
8. Foreign Activities..................................................70
9. Acquisitions and Dispositions.......................................70
10. Segment Information.................................................71
Supplemental Information (Unaudited).....................................73
44
Management's Report on Internal Control over Financial Reporting
Management of Swift Energy Company is responsible for establishing and
maintaining adequate internal control over financial reporting as defined in
Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The
Company's internal control over financial reporting is a process designed by, or
under the supervision of, the Company's Chief Executive Officer and Chief
Financial Officer to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of the Company's financial statements
for external purposes in accordance with U. S. generally accepted accounting
principles.
Management of the Company assessed the effectiveness of the Company's internal
control over financial reporting as of December 31, 2004. In making this
assessment, management used the criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO) in Internal
Control--Integrated Framework. Based on our assessment and those criteria,
management determined that the Company maintained effective internal control
over financial reporting as of December 31, 2004.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
Ernst & Young LLP, the independent registered public accounting firm that
audited the consolidated financial statements of the Company included in this
Annual Report on Form 10-K, has issued an attestation report on management's
assessment of the Company's internal control over financial reporting as of
December 31, 2004. That report, which expresses unqualified opinions on
management's assessment and on the effectiveness of the Company's internal
control over financial reporting as of December 31, 2004, appears on the
following page.
45
Report of Independent Registered Public Accounting Firm on Internal Control
Over Financial Reporting
The Board of Directors and Stockholders of Swift Energy Company
We have audited management's assessment, included in the accompanying
Management's Report on Internal Control Over Financial Reporting, that Swift
Energy Company maintained effective internal control over financial reporting as
of December 31, 2004, based on criteria established in Internal
Control--Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria). Swift Energy
Company's management is responsible for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express an opinion on
management's assessment and an opinion on the effectiveness of the company's
internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
In our opinion, management's assessment that Swift Energy Company maintained
effective internal control over financial reporting as of December 31, 2004, is
fairly stated, in all material respects, based on the COSO criteria. Also, in
our opinion, Swift Energy Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2004,
based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated balance sheets of
Swift Energy Company as of December 31, 2004 and 2003, and the related
consolidated statements of income, stockholders' equity, and cash flows for each
of the three years in the period ended December 31, 2004 and our report dated
March 11, 2005 expressed an unqualified opinion thereon.
ERNST & YOUNG LLP
Houston, Texas
March 11, 2005
46
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of Swift Energy Company
We have audited the accompanying consolidated balance sheets of Swift Energy
Company and subsidiaries as of December 31, 2004 and 2003, and the related
consolidated statements of income, stockholders' equity, and cash flows for each
of the three years in the period ended December 31, 2004. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Swift Energy
Company and subsidiaries at December 31, 2004 and 2003, and the consolidated
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2004, in conformity with U.S. generally accepted
accounting principles.
As discussed in Note 1 to the consolidated financial statements, in 2003 the
Company changed its method of accounting for asset retirement obligations.
We also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of Swift Energy
Company's internal control over financial reporting as of December 31, 2004,
based on criteria established in Internal Control--Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission and our
report dated March 11, 2005 expressed an unqualified opinion thereon.
ERNST & YOUNG LLP
Houston, Texas
March 11, 2005
47
Consolidated Balance Sheets
Swift Energy Company and Subsidiaries
December 31,
ASSETS 2004 2003
----------------- -----------------
Current Assets:
Cash and cash equivalents $ 4,920,118 $ 1,066,280
Accounts receivable-
Oil and gas sales 38,029,409 26,082,650
Joint interest owners 1,013,938 1,350,707
Other current assets 10,422,531 4,961,320
----------------- -----------------
Total Current Assets 54,385,996 33,460,957
----------------- -----------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties 1,479,681,903 1,305,110,582
Unproved properties 80,121,509 67,557,969
----------------- -----------------
1,559,803,412 1,372,668,551
Furniture, fixtures, and other equipment 12,820,622 10,602,786
----------------- -----------------
1,572,624,034 1,383,271,337
Less - Accumulated depreciation, depletion, and amortization (649,185,874) (567,464,334)
----------------- -----------------
923,438,160 815,807,003
----------------- -----------------
Other Assets:
Deferred income taxes 1,666,058 1,905,909
Debt issuance costs 9,148,977 8,015,575
Restricted assets 1,933,956 649,100
----------------- -----------------
12,748,991 10,570,584
----------------- -----------------
$ 990,573,147 $ 859,838,544
================= =================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 29,406,877 $ 26,247,477
Accrued capital costs 22,489,467 29,417,542
Accrued interest 9,209,192 8,748,656
Undistributed oil and gas revenues 7,512,755 4,939,667
----------------- -----------------
Total Current Liabilities 68,618,291 69,353,342
----------------- -----------------
Long-Term Debt 357,500,000 340,254,783
Deferred Income Taxes 73,106,580 43,498,682
Asset Retirement Obligation 17,176,136 9,340,473
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none
outstanding --- ---
Common stock, $.01 par value, 85,000,000 shares authorized, 28,570,632
and 28,011,109 shares issued, and 28,089,764 and 27,484,091
shares outstanding, respectively 285,706 280,111
Additional paid-in capital 343,536,298 334,865,204
Treasury stock held, at cost, 480,868 and 527,018 shares,
respectively (6,896,245) (7,558,093)
Unearned compensation (1,728,585) ---
Retained earnings 138,524,301 70,073,384
Accumulated other comprehensive income (loss), net of income tax 450,665 (269,342)
----------------- -----------------
474,172,140 397,391,264
----------------- -----------------
$ 990,573,147 $ 859,838,544
================= =================
See accompanying Notes to Consolidated Financial Statements.
48
Consolidated Statements of Income
Swift Energy Company and Subsidiaries
Year Ended December 31,
2004 2003 2002
----------------- ----------------- ---------------
Revenues:
Oil and gas sales $ 311,285,172 $ 211,032,639 $ 141,195,713
Gain on asset disposition --- --- 7,332,668
Price-risk management and other, net (1,008,398) (2,131,656) 1,441,430
----------------- ----------------- ---------------
310,276,774 208,900,983 149,969,811
----------------- ----------------- ---------------
Costs and Expenses:
General and administrative, net 17,787,125 14,097,066 10,564,849
Depreciation, depletion, and amortization 81,580,828 63,072,057 56,224,392
Accretion of asset retirement obligation 673,654 857,356 ---
Lease operating cost 41,214,256 33,833,198 28,918,858
Severance and other taxes 30,401,293 19,033,604 12,578,454
Interest expense, net 27,643,108 27,268,524 23,274,969
Debt retirement cost 9,536,268 --- ---
----------------- ----------------- ---------------
208,836,532 158,161,805 131,561,522
----------------- ----------------- ---------------
Income Before Income Taxes and
Change in Accounting Principle 101,440,242 50,739,178 18,408,289
Provision for Income Taxes 32,989,325 16,468,514 6,485,062
----------------- ----------------- ---------------
Income Before Change
in Accounting Principle $ 68,450,917 $ 34,270,664 $ 11,923,227
Cumulative Effect of Change in Accounting Principle
(net of taxes) --- 4,376,852 ---
----------------- ----------------- ---------------
Net Income $ 68,450,917 $ 29,893,812 $ 11,923,227
================= ================= ===============
Per Share Amounts-
Basic: Income Before
Change in Accounting Principle $ 2.46 $ 1.25 $ 0.45
Change in Accounting Principle --- (0.16) ---
----------------- ----------------- ---------------
Net Income $ 2.46 $ 1.09 $ 0.45
================= ================= ===============
Diluted: Income Before
Change in Accounting Principle $ 2.41 $ 1.24 $ 0.45
Change in Accounting Principle --- (0.16) ---
----------------- ----------------- ---------------
Net Income $ 2.41 $ 1.08 $ 0.45
================= ================= ===============
Weighted Average Shares Outstanding 27,822,413 27,357,579 26,382,906
================= ================= ===============
See accompanying Notes to Consolidated Financial Statements.
49
Consolidated Statements of Stockholders' Equity
Swift Energy Company and Subsidiaries
Accumulated
Additional Other
Common Paid-in Treasury Unearned Retained Comprehensive
Stock (1) Capital Stock Compensation Earnings Income (Loss) Total
---------- -------------- -------------- ------------- ------------- ------------- ------------
Balance, December 31, 2001 $ 256,346 $ 296,172,820 $ (12,032,791) $ - $ 28,256,345 $ - $312,652,720
Stock issued for benefit
plans (38,149 shares) 292 617,960 127,795 - - - 746,047
Stock options exercised
(112,995 shares) 1,130 924,719 - - - - 925,849
Tax benefits from
exercise of stock options - 281,694 - - - - 281,694
Public stock offering
(1,725,000 shares) 17,250 30,465,809 - - - - 30,483,059
Employee stock purchase
plan (9,801 shares) 98 122,343 - - - - 122,441
Stock issued in
acquisitions
(520,000 shares) 3,000 4,958,126 3,155,074 - - - 8,116,200
Comprehensive income:
Net income - - - - 11,923,227 - 11,923,227
Change in fair value of
cash flow hedges, net of
income tax - - - - - (178,053) (178,053)
------------
Total comprehensive
income - - - - - - 11,745,174
---------- -------------- -------------- ------------- ------------- ------------- ------------
Balance, December 31, 2002 $ 278,116 $ 333,543,471 $ (8,749,922) $ - $ 40,179,572 $ (178,053) $365,073,184
========== ============== ============== ============= ============= ============= ============
Stock issued for benefit
plans (83,201 shares) 1 (408,178) 1,191,829 - - - 783,652
Stock options exercised
(142,807 shares) 1,428 1,158,984 - - - - 1,160,412
Tax benefits from
exercise of stock options - 156,980 - - - - 156,980
Employee stock purchase
plan (56,574 shares) 566 413,947 - - - - 414,513
Comprehensive income:
Net income - - - - 29,893,812 - 29,893,812
Change in fair value of
cash flow hedges, net of
income tax - - - - - (91,289) (91,289)
------------
Total comprehensive - - - - - - 29,802,523
income
---------- -------------- -------------- -------------- ------------- ------------- ------------
Balance, December 31, 2003 $ 280,111 $ 334,865,204 $ (7,558,093) $ - $ 70,073,384 $ (269,342) $397,391,264
========== ============== ============== ============== ============= ============= ============
Stock issued for benefit
plans (46,150 shares) - 166,298 661,848 - - - 828,146
Stock options exercised
(509,105 shares) 5,091 4,260,882 - - - - 4,265,973
Tax benefits from
exercise of stock options - 1,956,555 - - - - 1,956,555
Employee stock purchase
plan (50,418 shares) 504 502,097 - - - - 502,601
Issuance of restricted
stock - 1,785,262 - (1,785,262) - - -
Amortization of
restricted stock
compensation - - 56,677 - - 56,677
Comprehensive income:
Net income - - - - 68,450,917 - 68,450,917
Change in fair value of
cash flow hedges, net of
income tax - - - - - 720,007 720,007
------------
Total comprehensive
income - - - - - - 69,170,924
---------- -------------- -------------- -------------- ------------- ------------- ------------
Balance, December 31, 2004 $ 285,706 $ 343,536,298 $ (6,896,245) $ (1,728,585) $ 138,524,301 $ 450,665 $474,172,140
=========== ============== ============== ============= ============== ============= ============
(1)$.01 par value.
See accompanying Notes to Consolidated Financial Statements.
50
Consolidated Statements of Cash Flows
Swift Energy Company and Subsidiaries
Year Ended December 31,
------------------------------------------------------
2004 2003 2002
----------------- ---------------- ----------------
Cash Flows from Operating Activities:
Net income $ 68,450,917 $ 29,893,812 $ 11,923,227
Adjustments to reconcile net income to net cash provided
by operating activities-
Cumulative effect of change in accounting principle --- 4,376,852 ---
Depreciation, depletion, and amortization 81,580,828 63,072,057 56,224,392
Accretion of asset retirement obligation 673,654 857,356 ---
Deferred income taxes 32,513,325 16,332,492 6,482,724
Debt retirement cost - cash and non-cash 9,536,268 --- ---
Gain on asset disposition --- --- (7,332,668)
Other (435,439) 908,927 270,770
Change in assets and liabilities-
(Increase) decrease in accounts receivable (11,040,543) (7,163,304) 883,419
Increase in accounts payable and accrued
liabilities 843,341 2,432,111 206,163
Increase in accrued interest 460,536 116,976 2,968,287
----------------- ---------------- ----------------
Net Cash Provided by Operating Activities 182,582,887 110,827,279 71,626,314
----------------- ---------------- -----------------
Cash Flows from Investing Activities:
Additions to property and equipment (171,095,101) (144,503,180) (103,773,337)
Proceeds from the sale of property and equipment 5,058,147 10,186,970 13,256,674
Acquisition of TAWN fields --- --- (51,460,586)
Acquisition of Bay de Chene and Cote Blanche Island fields (27,196,336) --- ---
Net cash received as operator of oil and gas properties 3,921,673 3,073,718 4,152,645
Net cash received (distributed) as operator of
partnerships 884,093 260,726 (23,241,501)
Other (658,630) (71,193) (39,953)
----------------- ---------------- -----------------
Net Cash Used in Investing Activities (189,086,154) (131,052,959) (161,106,058)
----------------- ---------------- -----------------
Cash Flows from Financing Activities:
Proceeds from long-term debt 150,000,000 --- 200,000,000
Payments of long-term debt (125,000,000) --- ---
Net proceeds from (payments of) bank borrowings (8,400,000) 15,900,000 (134,000,000)
Net proceeds from issuances of common stock 4,825,251 1,575,853 31,409,200
Payments of debt retirement costs (6,734,611) --- ---
Payments of debt issuance costs (4,333,535) --- (6,262,435)
----------------- ---------------- ----------------
Net Cash Provided by Financing Activities 10,357,105 17,475,853 91,146,765
----------------- ---------------- ----------------
Net Increase (Decrease) in Cash and Cash Equivalents $ 3,853,838 $ (2,749,827) $ 1,667,021
Cash and Cash Equivalents at Beginning of Year 1,066,280 3,816,107 2,149,086
----------------- ---------------- ----------------
Cash and Cash Equivalents at End of Year $ 4,920,118 $ 1,066,280 $ 3,816,107
================= ================ ================
Supplemental Disclosures of Cash Flows Information:
Cash paid during year for interest, net of amounts capitalized $ 26,064,158 $ 25,763,169 $ 19,189,822
Cash paid during year for income taxes $ 476,000 $ 129,738 $ 2,500
Non-Cash Financing Activity:
Issuance of common stock in acquisitions $ --- $ --- $ 8,116,200
See accompanying Notes to Consolidated Financial Statements.
51
Notes to Consolidated Financial Statements
Swift Energy Company and Subsidiaries
1. Summary of Significant Accounting Policies
Principles of Consolidation. The accompanying consolidated financial
statements include the accounts of Swift Energy Company and our wholly owned
subsidiaries, which are engaged in the exploration, development, acquisition,
and operation of oil and natural gas properties, with a focus on inland waters
and onshore oil and natural gas reserves in Louisiana and Texas, as well as
onshore oil and natural gas reserves in New Zealand. Our investments in oil and
gas limited partnerships where we are the general partner, and our undivided
interests in gas processing plants, are accounted for using the proportionate
consolidation method, whereby our proportionate share of each entity's assets,
liabilities, revenues, and expenses are included in the appropriate
classifications in the accompanying consolidated financial statements.
Intercompany balances and transactions have been eliminated in preparing the
accompanying consolidated financial statements.
Use of Estimates. The preparation of financial statements in conformity
with generally accepted accounting principles (GAAP) requires us to make
estimates and assumptions that affect the reported amount of certain assets and
liabilities and the reported amounts of certain revenues and expenses during
each reporting period. We believe our estimates and assumptions are reasonable;
however, such estimates and assumptions are subject to a number of risks and
uncertainties that may cause actual results to differ materially from such
estimates. Significant estimates underlying these financial statements include:
o the estimated quantities of proved oil and natural gas reserves used to
compute depletion of oil and natural gas properties and the related
present value of estimated future net cash flows there from,
o accruals related to oil and gas revenues, capital expenditures and lease
operating expenses,
o the estimated future cost and timing of asset retirement obligations, and
o estimates made in our income tax calculations.
While we are not aware of any material revisions to any of our estimates,
there will likely be future revisions to our estimates resulting from matters
such as changes in ownership interests, payouts, joint venture audits,
re-allocations by purchasers or pipelines, or other corrections and adjustments
common in the oil and gas industry, many of which require retroactive
application. These types of adjustments cannot be currently estimated and will
be recorded in the period during which the adjustment occurs.
Property and Equipment. We follow the "full-cost" method of accounting for
oil and gas property and equipment costs. Under this method of accounting, all
productive and nonproductive costs incurred in the exploration, development, and
acquisition of oil and gas reserves are capitalized. Such costs may be incurred
both prior to and after the acquisition of a property and include lease
acquisitions, geological and geophysical services, drilling, completion, and
equipment. Internal costs incurred that are directly identified with
exploration, development, and acquisition activities undertaken by us for our
own account, and which are not related to production, general corporate
overhead, or similar activities, are also capitalized. For the years 2004, 2003,
and 2002, such internal costs capitalized totaled $13.1 million, $11.5 million,
and $10.7 million, respectively. Interest costs are also capitalized to unproved
oil and gas properties. For the years 2004, 2003, and 2002, capitalized interest
on unproved properties totaled $6.5 million, $6.8 million, and $7.0 million,
respectively. Interest not capitalized and general and administrative costs
related to production and general overhead are expensed as incurred.
No gains or losses are recognized upon the sale or disposition of oil and
gas properties, except in transactions involving a significant amount of
reserves or where the proceeds from the sale of oil and gas properties would
significantly alter the relationship between capitalized costs and proved
reserves of oil and gas attributable to a cost center. Internal costs associated
with selling properties are expensed as incurred.
Future development costs are estimated property-by-property based on
current economic conditions and are amortized to expense as our capitalized oil
and gas property costs are amortized.
We compute the provision for depreciation, depletion, and amortization of
oil and gas properties by the unit-of-production method. Under this method, we
compute the provision by multiplying the total unamortized
52
costs of oil and gas properties--including future development costs, gas
processing facilities, and both capitalized asset retirement obligations and
undiscounted abandonment costs of wells to be drilled, net of salvage values,
but excluding costs of unproved properties--by an overall rate determined by
dividing the physical units of oil and gas produced during the period by the
total estimated units of proved oil and gas reserves at the beginning of the
period. This calculation is done on a country-by-country basis, and the period
over which we will amortize these properties is dependant on our production from
these properties in future years. Our total amortization per Mcfe was $1.38,
$1.17, and $1.11 in 2004, 2003, and 2002, respectively. Our domestic
amortization per Mcfe was $1.46, $1.30, and $1.25 in 2004, 2003, and 2002,
respectively. Our New Zealand amortization per Mcfe was $1.17, $0.94, and $0.80
in 2004, 2003 and 2002, respectively. Furniture, fixtures, and other equipment,
held at cost, are depreciated by the straight-line method at rates based on the
estimated useful lives of the property, which range between three and 20 years.
Repairs and maintenance are charged to expense as incurred. Renewals and
betterments are capitalized.
Geological and geophysical (G&G) costs incurred on developed properties are
recorded in Proved Property and therefore subject to amortization. In
exploration areas, G&G costs directly associated with specific unproved
properties are capitalized in "Unproved properties" and evaluated as part of the
total capitalized costs associated with a prospect.
The cost of unproved properties not being amortized is assessed quarterly,
on a country-by-country basis, to determine whether such properties have been
impaired. In determining whether such costs should be impaired, we evaluate
current drilling results, lease expiration dates, current oil and gas industry
conditions, international economic conditions, capital availability, foreign
currency exchange rates, the political stability in the countries in which we
have an investment, and available geological and geophysical information. Any
impairment assessed is added to the cost of proved properties being amortized.
To the extent costs accumulate in countries where there are no proved reserves,
any costs determined by management to be impaired are charged to expense.
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the
unamortized cost of oil and gas properties, including gas processing facilities,
capitalized asset retirement obligations, net of related salvage values and
deferred income taxes, and excluding the recognized asset retirement obligation
liability is limited to the sum of the estimated future net revenues from proved
properties, excluding cash outflows from recognized asset retirement
obligations, including future development and abandonment costs of wells to be
drilled, using period-end prices, adjusted for the effects of hedging,
discounted at 10%, and the lower of cost or fair value of unproved properties,
adjusted for related income tax effects ("Ceiling Test"). Our hedges at year-end
2004 consisted mainly of natural gas and crude oil price floors with strike
prices lower than the period end price and thus did not materially affect prices
used in this calculation. This calculation is done on a country-by-country
basis.
The calculation of the Ceiling Test and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves. There are
numerous uncertainties inherent in estimating quantities of proved reserves and
in projecting the future rates of production, timing, and plan of development.
The accuracy of any reserves estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. Results of
drilling, testing, and production subsequent to the date of the estimate may
justify revision of such estimate. Accordingly, reserves estimates are often
different from the quantities of oil and gas that are ultimately recovered.
Given the volatility of oil and gas prices, it is reasonably possible that
our estimate of discounted future net cash flows from proved oil and gas
reserves could change in the near term. If oil and gas prices decline from our
period-end prices used in the Ceiling Test, even if only for a short period, it
is possible that non-cash write-downs of oil and gas properties could occur in
the future.
Revenue Recognition. Oil and gas revenues are recognized when production is
sold to a purchaser at a fixed or determinable price, when delivery has occurred
and title has transferred, and if collectibility of the revenue is probable.
Processing costs for natural gas and natural gas liquids (NGLs) that are paid
in-kind are deducted from revenues. The Company uses the entitlement method of
accounting in which the Company recognizes its ownership interest in production
as revenue. If our sales exceed our ownership share of production, the natural
gas balancing payables are reported in "Accounts payable and accrued
liabilities" on the accompanying balance sheet. Natural gas balancing
receivables are reported in "Other current assets" on the
53
accompanying balance sheet when our ownership share of production exceeds sales.
As of December 31, 2004, we did not have any material natural gas imbalances.
Accounts Receivable. Included in the "Accounts receivable" balance, which
totaled $39.0 million and $27.4 million at December 31, 2004 and 2003,
respectively, on the accompanying balance sheets, is approximately $2.3 million
of receivables related to hydrocarbon volumes produced from 2001 and 2002 that
have been disputed since early 2003. As a result of the dispute, we did not
record a receivable with regard to any 2003 disputed volumes and our contract
governing these sales expired in 2003.
We assess the collectibility of accounts receivable, and based on our
judgment, we accrue a reserve when we believe a receivable may not be collected.
At December 31, 2004 and 2003, we had an allowance for doubtful accounts of $0.5
million. The allowance for doubtful accounts has been deducted from the total
"Accounts receivable" balances on the accompanying consolidated balance sheets.
Debt issuance costs. Legal and accounting fees, underwriting fees, printing
costs, and other direct expenses associated with the public offering in April
2002 of our 9-3/8% senior subordinated notes due 2012, the June 2004 extension
of our bank credit facility, and the public offering in June 2004 of our 7-5/8%
senior notes due 2011 were capitalized and are amortized on an effective
interest basis over the life of each of the respective note offerings and credit
facility. The 9-3/8% senior subordinated notes due 2012 mature on May 1, 2012,
and the balance of their issuance costs at December 31, 2004, was $4.6 million,
net of accumulated amortization of $1.0 million. The issuance costs associated
with our revolving credit facility, which was extended in June 2004, have been
capitalized and are being amortized over the life of the facility. The balance
of revolving credit facility issuance costs at December 31, 2004, was $0.8
million, net of accumulated amortization of $1.6 million. The 7-5/8% senior
notes due 2011 mature on July 15, 2011, and the balance of their issuance costs
at December 31, 2004, was $3.7 million, net of accumulated amortization of $0.2
million. The remaining $2.2 million of debt issuance costs related to the
10-1/4% senior subordinated notes due 2009 was charged to "debt retirement cost"
on the accompanying statements of income when the related debt was retired in
2004.
Limited Partnerships. At year-end 2004, we serve as managing general
partner for six private limited partnerships, and during fiscal 2004, less than
1% of our total oil and gas sales was attributable to our interests in those
partnerships. These six partnerships were formed between 1996 and 1998, and will
continue to operate until their limited partners vote otherwise.
Price-Risk Management Activities. The Company follows SFAS No. 133, which
requires that changes in the derivative's fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. The statement also
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) is recorded in the balance sheet as either an asset or a liability
measured at its fair value. Hedge accounting for a qualifying hedge allows the
gains and losses on derivatives to offset related results on the hedged item in
the income statements and requires that a company formally document, designate,
and assess the effectiveness of transactions that receive hedge accounting.
Changes in the fair value of derivatives that do not meet the criteria for hedge
accounting, and the ineffective portion of the hedge, are recognized currently
in income.
We have a price-risk management policy to use derivative instruments to
protect against declines in oil and gas prices, mainly through the purchase of
price floors and collars. During 2004, 2003 and 2002, we recognized net losses
of $1.3 million, $2.8 million and $0.2 million, respectively, relating to our
derivative activities. This activity is recorded in "Price-risk management and
other, net" on the accompanying statements of income. At December 31, 2004, the
Company had recorded $0.5 million, net of taxes of $0.3 million, of derivative
gains in "Accumulated other comprehensive income (loss), net of income tax" on
the accompanying balance sheet. This amount represents the change in fair value
for the effective portion of our hedging transactions that qualified as cash
flow hedges. The ineffectiveness reported in "Price-risk management and other,
net" for 2004, 2003 and 2002 was not material. We expect to reclassify all
amounts currently held in "Accumulated other comprehensive income (loss), net of
income tax" into the statement of income within the next twelve months when the
forecasted sale of hedged production occurs.
At December 31, 2004, we had in place price floors in effect through the
December 2005 contract month for natural gas, that cover a portion of our
domestic natural gas production for January 2005 to December 2005. The natural
gas price floors cover notional volumes of 4,000,000 MMBtu, with a weighted
average floor
54
price of $5.83 per MMBtu. Our natural gas price floors in place at December 31,
2004 are expected to cover approximately 30% to 35% of our domestic natural gas
production from January 2005 to December 2005. At December 31, 2004, we also had
in place crude oil price floors in effect through the March 2005 contract month,
which cover a portion our domestic crude oil production for January 2005 to
March 2005. The crude oil price floors cover notional volumes of 216,000
barrels, with a weighted average floor price of $37.00 per barrel. Our crude oil
price floors in place at December 31, 2004 are expected to cover approximately
15% to 20% of our domestic crude oil production from January 2005 to March 2005.
When we entered into these transactions discussed above, they were
designated as a hedge of the variability in cash flows associated with the
forecasted sale of natural gas and crude oil production. Changes in the fair
value of a hedge that is highly effective and is designated and documented and
qualifies as a cash flow hedge, to the extent that the hedge is effective, are
recorded in "Accumulated other comprehensive income (loss), net of income tax."
When the hedged transactions are recorded upon the actual sale of oil and
natural gas, these gains or losses are reclassified from "Accumulated other
comprehensive income (loss), net of income tax" and recorded in "Price-risk
management and other, net" on the consolidated statement of income. The fair
value of our derivatives is computed using the Black-Scholes option pricing
model and are periodically verified against quotes from brokers. The fair value
of these instruments at December 31, 2004, was $1.8 million and is recognized on
the accompanying balance sheet in "Other current assets."
Supervision Fees. Consistent with industry practice, we charge a
supervision fee to the wells we operate including our wells in which we own up
to a 100% working interest. Supervision fees are recorded as a reduction to
general and administrative, net based on our estimate of the costs incurred to
operate the wells, with the remainder applied as a reduction to lease operating
cost. Based on recent estimates, effective October 1, 2003, we began recording
the supervision fee only as a reduction to general and administrative, net. The
total amount of supervision fees charged to the wells we operate was $5.8
million in 2004, $5.1 million in 2003, and $5.3 million in 2002.
Inventories. We value inventories at the lower of cost or market value.
Cost of crude oil inventory is determined using the weighted average method and
all other inventory is accounted for using the first in, first out method
("FIFO"). The major categories of inventories, which are included in "Other
current assets" on the accompanying balance sheets, are shown as follows:
Balance at Balance at
December 31, 2004 December 31, 2003
(000's) (000's)
- ------------------ ------------------ ------------------ ------------------
Materials, Supplies and Tubulars... $ 6,417 $ 2,966
Crude Oil ......................... 770 238
------------------ -----------------
Total .................... $ 7,187 $ 3,204
================== =================
Income Taxes. Under SFAS No. 109, "Accounting for Income Taxes," deferred
taxes are determined based on the estimated future tax effects of differences
between the financial statement and tax basis of assets and liabilities, given
the provisions of the enacted tax laws. The effective tax rate for 2004 was
lower than the statutory tax rates primarily due to reductions from the New
Zealand statutory rate attributable to the currency effect on the New Zealand
deferred tax calculation, along with favorable corrections to tax basis amounts
discovered while preparing the prior year's tax returns. These amounts were
partially offset by higher deferred state income taxes. Income tax expense in
2003 includes a reduction from the U.S. statutory rate, primarily from the
result of the currency exchange rate effect on the New Zealand deferred tax.
This amount was partially offset by higher deferred state income taxes and other
items. The tax laws in the jurisdictions we operate in are continuously changing
and professional judgments regarding such laws can differ. The Company is
currently evaluating the impact of the recently enacted American Jobs Creation
Act of 2004. We do not believe this act will have a material impact in the
near-term on our financial position or cash flow from operations.
Accounts Payable and Accrued Liabilities. Included in "Accounts payable and
accrued liabilities," on the accompanying balance sheets, at December 31, 2004
and 2003 are liabilities of approximately $6.9 million and $11.9 million,
respectively, represents the amount by which checks issued, but not presented to
the Company's banks for collection, exceeded balances in the applicable bank
accounts.
55
Cash and Cash Equivalents. We consider all highly liquid debt instruments
with an initial maturity of three months or less to be cash equivalents.
Credit Risk Due to Certain Concentrations. We extend credit, primarily in
the form of uncollateralized oil and gas sales and joint interest owners
receivables, to various companies in the oil and gas industry, which results in
a concentration of credit risk. The concentration of credit risk may be affected
by changes in economic or other conditions within our industry and may
accordingly impact our overall credit risk. However, we believe that the risk of
these unsecured receivables is mitigated by the size, reputation, and nature of
the companies to which we extend credit. During 2004, oil and gas sales to
Shell, both domestically and in New Zealand, were $149.2 million, or 48% of
total oil and gas sales. During 2003, oil and gas sales to Shell, both
domestically and in New Zealand, were $31.1 million, or 15% of total oil and gas
sales, while sales to subsidiaries of Contact Energy in New Zealand were $23.5
million, or 11% of total oil and gas sales. During 2002, oil and gas sales to
Eastex Crude Company were $25.4 million, or 18% of total oil and gas sales,
while sales to subsidiaries of Contact Energy in New Zealand were $14.6 million,
or 10% of total oil and gas sales. Credit losses in 2004, 2003 and 2002 have
been immaterial.
Environmental Costs. Our operations include activities that are subject to
extensive federal and state environmental regulations. Costs associated with
redemption projects, which are probable and quantifiable, are accrued in
advance. Ongoing environmental compliance costs are expensed as incurred.
Restricted Assets. These balances include amounts deposited on plugging
bonds in New Zealand, along with amounts held in escrow accounts to satisfy
domestic plugging and abandonment obligations. These amounts are restricted as
to their current use, and will be released when we have satisfied all plugging
and abandonment obligations in certain fields domestically and in New Zealand.
Foreign Currency. We use the U.S. Dollar as our functional currency in New
Zealand. The functional currency is determined by examining the entities cash
flows, commodity pricing environment and financing arrangements. We have both
assets and liabilities denominated in New Zealand Dollars, predominantly our
portion of our "Deferred income taxes" and a portion of our "Asset Retirement
Obligation" on the accompanying balance sheet. For accounts other than "Deferred
income taxes," as the currency rate changes between the U.S. Dollar and the New
Zealand Dollar, we recognize transaction gains and losses in "Price-risk
management and other, net" on the accompanying statements of income. We
recognize transaction gains and losses on "Deferred income taxes" in "Provision
for Income Taxes" on the accompanying statement of income.
Fair Value of Financial Instruments. Our financial instruments consist of
cash and cash equivalents, accounts receivable, accounts payable, bank
borrowings, and senior notes. The carrying amounts of cash and cash equivalents,
accounts receivable, and accounts payable approximate fair value due to the
highly liquid or short-term nature of these instruments. The fair values of the
bank borrowings approximate the carrying amounts as of December 31, 2004 and
2003, and were determined based upon variable interest rates currently available
to us for borrowings with similar terms. Based upon quoted market prices as of
December 31, 2004 and 2003, the fair values of our senior subordinated notes due
2012 were $224.0 million , or 112.0% of face value, and $218.0 million, or 109%
of face value, respectively. Based upon quoted market prices as of December 31,
2004, the fair value of our senior notes due 2011 was $162.4 million, or 108.25%
of face value. The carrying value of our senior subordinated notes due 2012 was
$200.0 million at December 31 for both 2004 and 2003. The carrying value of our
senior notes due 2011 was $150.0 million at December 31, 2004.
Reclassification of Prior Period Balances. Certain reclassifications have
been made to prior period amounts to conform to the current year presentation.
56
Accumulated Other Comprehensive Income (Loss), Net of Income Tax. We follow
the provisions of SFAS No. 130, "Reporting Comprehensive Income," which
establishes standards for reporting comprehensive income. In addition to net
income, comprehensive income or loss includes all changes to equity during a
period, except those resulting from investments and distributions to the owners
of the Company. At December 31, 2004, we recorded $0.5 million, net of taxes of
$0.3 million, of derivative gains in "Accumulated other comprehensive income
(loss), net of income tax" on the accompanying balance sheet. The components of
accumulated other comprehensive Income (loss) and related tax effects for 2004
were as follows:
Gross Value Tax Effect Net of Tax Value
------------------- ----------------- -------------------
Other comprehensive loss at December 31, 2003 $ (420,847) $ 151,505 $ (269,342)
Change in fair value of cash flow hedges 2,433,433 (890,636) 1,542,797
Effect of cash flow hedges settled
during the period (1,301,758) 478,968 (822,790)
------------------- ----------------- -------------------
Other comprehensive income at December 31, 2004 $ 710,828 $ (260,163) $ 450,665
=================== ================= ===================
Total comprehensive income was $69.2 million, $29.8 million, and $11.7
million for 2004, 2003, and 2002, respectively.
Stock Based Compensation. We have two stock-based compensation plans, which
are described more fully in Note 6. We account for those plans under the
recognition and measurement principles of APB Opinion No. 25, "Accounting for
Stock Issued to Employees," and related interpretations. We issued restricted
stock to employees for the first time in 2004, and recorded expense related to
these shares of less than $0.1 million in "General and administrative, net" on
the accompanying statements of income. No stock-based employee compensation cost
is reflected in net income for employee stock options, as all options granted
under those plans had an exercise price equal to the fair market value of the
underlying common stock on the date of the grant; or in the case of the employee
stock purchase plan, the purchase price is 85% of the lower of the closing price
of our common stock as quoted on the New York Stock Exchange at the beginning or
end of the plan year or a date during the year chosen by the participant. Had
compensation expense for these plans been determined based on the fair value of
the options consistent with SFAS No. 123, "Accounting for Stock-Based
Compensation," our net income and earnings per share would have been adjusted to
the following pro forma amounts:
2004 2003 2002
---------------- -------------- ----------------
Net Income: As Reported $68,450,917 $29,893,812 $11,923,227
Stock-based
employee
compensation expense
determined under
fair value method
for all awards, net
of tax (3,557,541) (4,112,455) (4,451,799)
---------------- -------------- ----------------
Pro Forma $64,893,376 $25,781,357 $7,471,428
Basic EPS: As Reported $2.46 $1.09 $0.45
Pro Forma $2.33 $0.94 $0.28
Diluted EPS: As Reported $2.41 $1.08 $0.45
Pro Forma $2.29 $0.94 $0.27
Pro forma compensation cost reflected above may not be representative of
the cost to be expected in future years. The fair value of each option grant, as
opposed to its exercise price, is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted average
assumptions in 2004, 2003, and 2002, respectively: no dividend yield; expected
volatility factors of 38.6%, 34.71%, and 73.72%; risk-free interest rates of
3.59%, 4.63%, and 4.74%; and expected lives of 5.4, 7.2, and 7.4 years. We view
all awards of stock compensation as a single award with an expected life equal
to the average expected life of component awards and amortize the award on a
straight-line basis over the life of the award.
57
Asset Retirement Obligation. In June 2001, the Financial Accounting
Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." The statement requires entities to record the fair value of a
liability for legal obligations associated with the retirement obligations of
tangible long-lived assets in the period in which it is incurred. When the
liability is initially recorded, the carrying amount of the related long-lived
asset is increased. The liability is discounted from the year the well is
expected to deplete. Over time, accretion of the liability is recognized each
period, and the capitalized cost is depreciated on a unit-of-production basis
over the useful life of the related asset. Upon settlement of the liability, an
entity either settles the obligation for its recorded amount or incurs a gain or
loss upon settlement. This standard requires us to record a liability for the
fair value of our dismantlement and abandonment costs, excluding salvage values.
Based on our experience and analysis of the oil and gas services industry, we
have not factored a market risk premium into our asset retirement obligation.
SFAS No. 143 was adopted by us effective January 1, 2003. Upon adoption of SFAS
No. 143, we recorded an asset retirement obligation of $8.9 million, an addition
to oil and gas properties of $2.0 million, and a non-cash charge of $4.4 million
(net of $2.5 million of deferred taxes), which is recorded as a Cumulative
Effect of Change in Accounting Principle. The cumulative charge to earnings took
into consideration the impact of adopting SFAS No. 143 on previous full-cost
ceiling tests. SFAS No. 143 is silent with respect to whether prior period
ceiling tests should be reflected in the implementation entry calculation;
however, management believes that any impairment on the properties should be
reflected in the historical periods. Had we not considered the impact of
adopting SFAS No. 143 on previous full-cost ceiling tests, the charge recognized
would have been reduced. Excluding the Cumulative Effect of Change in Accounting
Principle, the adoption of SFAS No. 143 reduced our 2003 net income by
approximately $0.6 million, or $0.02 per diluted share. The following provides a
roll-forward of our asset retirement obligation:
Asset Retirement Obligation recorded as of January 1, 2003 $ 8,934,320
Accretion expense for 2003 857,356
Liabilities incurred for new wells and facilities construction 608,166
Reductions due to sold and abandoned wells (443,391)
Revisions in estimated cash flows 67,511
Increase due to currency exchange rate fluctuations 113,511
-----------------
Asset Retirement Obligation as of December 31, 2003 $ 10,137,473
-----------------
Accretion expense for 2004 673,654
Liabilities incurred for new wells and facilities construction 712,521
Liabilities incurred for Bay de Chene and Cote Blanche Island
acquisitions 2,941,490
Reductions due to sold and abandoned wells (1,083,174)
Revisions in estimated cash flows 4,195,474
Increase due to currency exchange rate fluctuations 61,698
-----------------
Asset Retirement Obligation as of December 31, 2004 $ 17,639,136
-----------------
At December 31, 2004 and 2003, approximately $0.5 million and $0.8 million,
respectively, of our asset retirement obligation is classified as a current
liability in "Accounts payable and accrued liabilities" on the accompanying
consolidated balance sheets.
The pro forma effect for 2002, assuming adoption of SFAS No. 143 effective
January 1, 2002, would have included a non-cash charge of $3.7 million (net of
$2.1 million of deferred taxes), which would have been recorded as a Cumulative
Effect of Change in Accounting Principle and recognition of an asset retirement
obligation of $6.2 million. The following table displays our pro forma results
for the year ended December 31, 2002, had we adopted SFAS No. 143 effective
January 1, 2002.
Year Ended
December 31, 2002
------------------
Net Income:
Actual - as reported $ 11,923,227
Pro Forma $ 7,542,383
Basic EPS:
Actual - as reported $ 0.45
Pro Forma $ 0.29
Diluted EPS:
Actual - as reported $ 0.45
Pro Forma $ 0.28
58
New Accounting Pronouncements. In January 2003, the FASB issued
Interpretation No. 46 (Revised December 2003) ("FIN 46R"), Consolidation of
Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No. 51 consolidated financial statements (the "Interpretation"). The
Interpretation significantly changes whether entities included in its scope are
consolidated by their sponsors, transferors, or investors. The Interpretation
introduces a new consolidation model - the variable interest model; which
determines control (and consolidation) based on potential variability in gains
and losses of the entity being evaluated for consolidation. The Interpretation
provides guidance for determining whether an entity lacks sufficient equity or
its equity holders lack adequate decision-making ability. These variable
interest entities ("VIEs") are covered by the Interpretation and are to be
evaluated for consolidation based on their variable interests. These provisions
applied immediately to variable interests in VIEs created after January 31,
2003, and to variable interests in special purpose entities for periods ending
after December 15, 2003. The provisions apply for all other types of variable
interests in VIEs for periods ending after March 15, 2004. We have no variable
interests in VIEs, nor do we have variable interests in special purpose
entities. The adoption of this interpretation had no impact on our financial
position or results of operations.
In September and November 2004, the EITF discussed a proposed framework for
addressing when a limited partnership should be consolidated by its general
partner, EITF Issue 04-5. The proposed framework presumes that a sole general
partner in a limited partnership controls the limited partnership, and therefore
should consolidate the limited partnership. The presumption of control can be
overcome if the limited partners have (a) the substantive ability to remove the
sole general partner or otherwise dissolve the limited partnership or (b)
substantive participating rights. The EITF reached a tentative conclusion on the
circumstances in which either kick-out rights or protective rights would be
considered substantive and preclude consolidation by the general partner and
what limited partner's rights would be considered participating rights that
would preclude consolidation by the general partner. The EITF tentatively
concluded that for kick out rights to be considered substantive, the conditions
specified in paragraph B20 of FIN 46R should be met. With regard to the
definition of participating rights that would preclude consolidation by the
general partner, the EITF concluded that the definition of those rights should
be consistent with those in EITF Issue 96-16. The EITF also reached a tentative
conclusion on the transition for Issue 04-05. We do not believe this EITF will
have a material impact on our consolidated financial statements because we
believe our limited partners have substantive kick-out rights under paragraph
B20 of FIN 46R.
In September 2004, the Securities and Exchange Commission issued Staff
Accounting Bulletin No. 106 (SAB 106). SAB 106 expresses the SEC staff's views
regarding SFAS No. 143 and its impact on both the full-cost ceiling test and the
calculation of depletion expense. In accordance with SAB 106, beginning in the
fourth quarter of 2004, undiscounted abandonment cost for future wells, not
recorded at the present time but needed to develop the proved reserves in
existence at the present time, should be included in the unamortized cost of oil
and gas properties, net of related salvage value, for purposes of computing
DD&A. The effect of including undiscounted abandonment costs of future wells to
the undiscounted cost of oil and gas properties will increase depletion expense
in future periods, however, we currently do not believe such increases will be
material.
In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment. SFAS
No. 123R is a revision of SFAS No. 123, Accounting for Stock-Based Compensation,
and supercedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and
amends SFAS No. 95, Statement of Cash Flows. SFAS No. 123R requires all employee
share-based payments, including grants of employee stock options, to be
recognized in the financial statements based on their fair values. SFAS No. 123
discontinues the ability to account for these equity instruments under the
intrinsic value method as described in APB Opinion No. 25. SFAS No. 123R
requires the use of an option pricing model for estimating fair value, which is
amortized to expense over the service periods. The requirements of SFAS No. 123R
are effective for fiscal periods beginning after June 15, 2005. SFAS No. 123R
permits public companies to adopt its requirements using one of two methods:
o A "modified prospective" method in which compensation cost is recognized
beginning with the effective date based on the requirements of SFAS No.
123R for all share-based payments granted after the effective date and
based on the requirements of SFAS No. 123 for all awards granted to
employees prior to the adoption date of SFAS No. 123R that remain
unvested on the adoption date.
o A "modified retrospective" method which includes the requirements of the
modified prospective method described above, but also permits entities
to restate either all prior periods presented
59
or prior interim periods of the year of adoption based on the amounts
previously recognized under SFAS No. 123 for purposes of pro forma
disclosures.
We have elected to adopt the provisions of SFAS No. 123R on July 1, 2005
using the modified prospective method. As permitted by Statement 123, the
Company currently accounts for share-based payments to employees using APB
Opinion No. 25's intrinsic value method and, as such, generally recognizes no
compensation cost for employee stock options. Accordingly, the adoption of
Statement No. 123R's fair value method is expected to have a significant impact
on our result of operations. However, it will have no impact on our overall
financial position. We currently use the Black-Scholes formula to estimate the
value of stock options granted to employees and expect to continue to use this
acceptable option valuation model upon the required adoption of SFAS No. 123R.
The significance of the impact of adoption will depend on levels of share-based
payments granted in the future. However, had we adopted Statement No. 123R in
prior periods, the impact of that standard would have approximated the impact of
Statement No. 123 as described in the disclosure of pro forma net income and
earnings per share under "Stock Based Compensation." Statement No. 123R also
requires the benefits of tax deductions in excess of recognized compensation
cost to be reported as a financing cash flow, rather than as an operating cash
flow as required under current literature. This requirement will reduce net
operating cash flows and increase net financing cash flows in periods after
adoption. While the Company cannot estimate what those amounts will be in the
future (because they depend on, among other things, when employees exercise
stock options), the amount of excess tax deductions recognized were $2.0
million, $0.2 million, and $0.3 million in 2004, 2003 and 2002, respectively.
These deductions resulted in an increase in operating cash flows, however, due
to the Company's net operating tax loss position, deferred income taxes were
reduced rather than actual cash taxes paid.
60
2. Earnings Per Share
Basic earnings per share ("Basic EPS") have been computed using the
weighted average number of common shares outstanding during the respective
periods. Diluted earnings per share ("Diluted EPS") for all periods also
assumes, as of the beginning of the period, exercise of stock options and
restricted stock grants using the treasury stock method. Certain of our stock
options that would potentially dilute Basic EPS in the future were also
antidilutive for the 2004, 2003, and 2002 periods and are discussed below.
The following is a reconciliation of the numerators and denominators used
in the calculation of Basic and Diluted EPS for the years ended December 31,
2004, 2003, and 2002:
2004 2003 2002
----------------------------------- -------------------------------- --------------------------------------
Per Per Per
Net Share Net Share Net Share
Income Shares Amount Income Shares Amount Income Shares Amount
------------ ---------- ----------- ------------- ---------- -------- ------------- ---------- ---------
Basic EPS:
Net Income and
Share Amounts $ 68,450,917 27,822,413 $ 2.46 $ 29,893,812 27,357,570 $ 1.09 $ 11,923,227 26,382,906 $ 0.45
Dilutive
Securities:
Restricted Stock -- -- -- -- -- --
Stock Options -- 524,860 -- 203,360 -- 372,700
------------ ---------- ------------- ---------- ------------- ----------
Diluted EPS:
Net Income and
Assumed Share
Conversions $ 68,450,917 28,347,273 $ 2.41 $ 29,893,812 27,560,930 $ 1.08 $ 11,923,227 26,755,606 $ 0.45
============ ========== ============= ========== ============= ==========
Options to purchase approximately 3.0 million shares at an average exercise
price of $18.51 were outstanding at December 31, 2004, while options to purchase
3.2 million shares at an average exercise price of $16.37 were outstanding at
December 31, 2003, and options to purchase 3.0 million shares at an average
exercise price of $16.64 were outstanding at December 31, 2002. Approximately
1.1 million, 1.7 million, and 1.3 million options to purchase shares were not
included in the computation of Diluted EPS for the years ended December 31,
2004, 2003, and 2002, respectively, because these options were antidilutive in
that the option price was greater than the average closing market price for the
common shares during those periods. Employee restricted stock grants of 70,900
shares, which were issued in 2004, were not included in the computation of
Diluted EPS for the year ended December 31, 2004, because these restricted stock
grants were antidilutive in that the amount of future compensation expense per
share recognized as proceeds in the treasury stock method was greater than the
average closing market price for the common shares during that period. Other
restricted stock grants of 30,000 shares, which were issued in 2004, were not
included in the computation of Diluted EPS for the year ended December 31, 2004,
as performance conditions surrounding the vesting of these shares had not
occurred.
3. Provision for Income Taxes
Income before taxes is as follows:
Year Ended December 31,
--------------------------------------------------
2004 2003 2002
--------------- -------------- --------------
United States $ 86,000,508 $ 38,955,405 $ 12,889,583
Foreign 15,439,734 11,783,773 5,518,706
--------------- -------------- --------------
Total $ 101,440,242 $ 50,739,178 $ 18,408,289
=============== ============== ==============
61
The following is an analysis of the consolidated income tax provision:
Year Ended December 31,
------------------------------------------------------
2004 2003 2002
--------------- --------------- ----------------
Current $ 469,717 $ 164,284 $ 2,338
--------------- --------------- ----------------
Deferred - Domestic 31,137,643 14,386,868 4,870,239
- Foreign 1,381,965 1,917,362 1,612,485
--------------- --------------- ----------------
Total Deferred 32,519,608 16,304,230 6,482,724
--------------- --------------- ----------------
Total $ 32,989,325 $ 16,468,514 $ 6,485,062
=============== =============== ================
Reconciliations of income taxes computed using the U.S. Federal statutory
rate to the effective income tax rates are as follows:
2004 2003 2002
--------------- --------------- ---------------
Income taxes computed at U.S. statutory rate (35%) $ 35,504,086 $ 17,758,712 $ 6,442,901
State tax provisions, net of federal benefits 1,140,499 373,992 323,902
Effect of foreign operations 317,967 (235,675) (110,374)
Currency exchange impact on foreign tax calculation (2,516,120) (2,893,655) (208,688)
Correction to tax basis of foreign oil and gas
properties (1,378,900) --- ---
Change in estimate for deferred Louisiana income
taxes, net of federal benefits 858,943 1,216,105 ---
--------------- --------------- ---------------
Other, net (937,150) 249,035 37,321
--------------- --------------- ---------------
Provision for income taxes $ 32,989,325 $ 16,468,514 $ 6,485,062
=============== =============== ===============
Effective rate 32.5% 32.5% 35.2%
As noted in the above table, the most significant contributor to the
difference between the federal statutory rate and the effective rate for 2004
and 2003 is attributed to currency exchange impact on the foreign income tax
calculation. The Company's New Zealand subsidiaries use the U.S. Dollar as their
functional currency for financial reporting purposes, but income taxes are
calculated from New Zealand Dollar financial statements and re-measured into
U.S. Dollars. Volatility in exchange rates creates variable results when
computing income in different currencies. The most significant difference in the
relative income computations for 2004 and 2003 was attributable to depreciation,
depletion, and amortization (DD&A). Because of the relative strengthening of the
New Zealand Dollar vs. the U.S. Dollar, the value of the tax DD&A deduction
reflects the relative appreciation in the New Zealand Dollar tax basis of
amortizable assets vs. the historical U.S. Dollar investment costs. As a result,
taxable income (and accordingly income tax expense) computed in New Zealand
Dollars and then converted to U.S. Dollars at the average exchange rates for
each respective year was significantly less than net income computed in the
subsidiaries' U.S. Dollar financial statements. Additionally, the deferred tax
asset is revalued at the ending exchange rate for each period. This revaluation
also resulted in favorable adjustments for 2004, 2003, and 2002. In aggregate,
the Company recognized foreign exchange benefits to tax expense in the amounts
of $2.5 million, $2.9 million, and $0.2 million for 2004, 2003, and 2002,
respectively. If exchange rates remain volatile in the future significant
fluctuations in the impact on the Company's effective tax rate are likely to
continue.
In addition to the exchange impact, the Company also had a favorable
adjustment in 2004 from a correction in the tax basis of the TAWN assets. The
majority of these adjustments were discovered when
62
preparing the 2002 New Zealand tax returns which were due and filed in March
2004. Additionally, the basis adjustments resulted in an increase in the
acquired deferred tax asset balance of $1.1 million.
The primary unfavorable differences between the federal statutory and the
effective rate are attributable to state income taxes (computed net of the
offsetting federal benefit), which were $1.1 million, $0.4 million and $0.3
million for 2004, 2003, and 2002, respectively. Additional, the Company recorded
adjustments to the cumulative Louisiana deferred tax liability in the amounts of
$0.9 million and $1.2 million during 2004 and 2003, respectively due to its
increased level of business activity in Louisiana. The Company calculates its
Louisiana income tax using the "apportionment" accounting method. Under
apportionment accounting, total federal taxable income is allocated based on the
proportional level of U.S. business activity within the state. Due to the
relative increase in the Company's Louisiana activity, the Company increased its
estimate of future Louisiana taxable income that will result from the reversal
of prior years' timing differences. The 2004 increase was primarily due to
acquisitions and development activities in Lake Washington. The 2003 increase
was primarily due to development activities in Lake Washington.
The New Zealand statutory rate is 33%, which resulted in differences of
$0.3 million, $0.2 million, and $0.1 million for 2004, 2003, and 2002
respectively vs. the U.S. statutory rate. The 2004 favorable rate impact is more
than offset by a $0.6 million accrual for taxes expected to be incurred on a
planned dividend from the Company's New Zealand subsidiaries. Except for a
limited dividend tied to a cost of capital computation, the Company does not
compute a provision for U.S. taxes on the undistributed earnings of our New
Zealand subsidiaries as management has plans to reinvest such earnings outside
of the United States indefinitely. If, in the future, these earnings are
distributed into the U.S. in the form of dividends or otherwise, we may be
subject to U.S. income taxes and New Zealand withholding taxes. It is not
practical, however, to estimate the amount of taxes that may be payable if such
remittances occur. Presently, there are no foreign tax credits available to
reduce the U.S. taxes on such amounts if repatriated.
The Company is currently evaluating the possibility of utilizing a special
one-time tax deduction relating to the repatriation of foreign earnings created
by the American Jobs Creation Act of 2004. To be eligible the Company would need
to develop a qualified domestic reinvestment plan. As of this date the Company
has not yet completed this evaluation or developed a reinvestment plan. However,
as of December 31, 2004 the Company is in a cumulative tax loss position with
respect to its foreign operations. The Company believes the maximum available
deduction would be limited to the 2005 taxable earnings of its foreign
subsidiaries, if any. The Company will not be in a position to make a reasonable
estimate until later in the year as to how much, if any, income will be
available to repatriate at the reduced rate.
63
The tax effects of temporary differences representing the net deferred tax
liability (asset) at December 31, 2004 and 2003, were as follows:
2004 2003
---- ----
Deferred tax assets:
Alternative minimum tax credits (Domestic) $ (2,579,399) $ (1,979,399)
Carryover items (Domestic) (47,600,945) (53,006,919)
Acquired deferred tax asset (Foreign) (3,407,885) (3,802,435)
Carryover Items (Foreign) (37,852,559) (28,294,320)
Other (Domestic) (167,475) (152,725)
------------- -------------
Total deferred tax assets $ (91,608,263) $ (87,235,798)
------------- -------------
Deferred tax liabilities
Domestic oil and gas exploration and development costs $ 121,893,202 $ 98,092,129
Foreign oil and gas exploration and development costs 39,594,386 30,160,846
Scheduled dividend from foreign subsidiary 626,762 --
Other (Domestic) 934,435 575,596
------------- -------------
Total deferred tax liabilities $ 163,048,785 $ 128,828,571
------------- -------------
Net deferred tax liabilities $ 71,440,522 $ 41,592,773
============= =============
The total change in the net deferred liability from 2003 to 2004 was $29.8
million. Increases in the liability were attributable to deferred tax expense of
$32.5 million plus $0.4 million for the tax effect of unrealized hedging gains.
Unrealized hedging gains and losses are recorded net of tax as other
comprehensive income (loss) adjustments to equity. Reductions were made to the
net liability for the tax benefit of stock compensation deductions of $2.0
million, which are recorded as additions to paid-in-capital, and $1.1 million
for an adjustment to the foreign acquired deferred tax asset.
The tax basis of the assets of Southern Petroleum (NZ) Exploration Limited
("Southern NZ") on the acquisition date exceeded the cash purchase price paid by
SENZ to acquire this entity. To account for the future tax benefits of this
additional basis, SENZ recorded a deferred tax asset of $4.9 million. The asset
is being amortized over the period in which the tax amortization is deducted.
The remaining asset value at December 31, 2003, was $3.8 million. During 2004
the deferred tax asset was increased by $1.1 million as noted previously.
Amortization during 2004 was $1.5 million. The other foreign carryover asset is
attributable to cumulative New Zealand net operating losses of $114.7 million.
New Zealand tax net operating losses do not expire.
At December 31, 2004, the Company had alternative minimum tax credits of
$2.6 million that carry forward indefinitely. These credits are available to
reduce future regular tax liability to the extent they exceed the alternative
minimum tax otherwise due.
The domestic deferred tax carryover items are attributable to expected
future tax benefits in the amounts of $40.0 million for federal net operating
losses, $1.6 million for State of Louisiana net operating losses and $6.0
million net for capital losses. The gross capital loss asset is $6.5 million
less a $.5 million impairment. At December 31, 2004, cumulative estimated
federal net operating losses were $113.9 million, which will expire between 2018
and 2023. Louisiana estimated net operating losses total $44.8 million and will
expire between 2013 and 2018.
The Company has not recorded any valuation allowance against the deferred
tax assets attributable to net operating loss carryovers at December 31, 2004
and 2003, as management estimates that it is more likely than not that these
assets will be fully utilized before they expire. Significant changes in
estimates caused by changes in oil and gas prices, production levels, capital
expenditures, and other variables could impact the Company's ability to utilize
the carryover amounts.
In 2002 we recognized a capital loss of approximately $18.6 million as the
result of the liquidation of our partnerships. This loss can only be utilized to
offset capital gains and will expire in 2007. The Company plans to sell one or
more of its oil and gas properties during the next few years that will generate
sufficient capital gains to utilize the loss carry over. To generate capital
gains from these dispositions, the sales proceeds must exceed the Company's
total investment in the properties. Company management has identified several
64
qualified properties that have estimated current market values well in excess of
the total original costs. Management believes that it is more likely than not
that the Company will fully utilize the capital loss carryover. If the Company
is unable to complete the sale of these properties at the prices it has
estimated to be the fair market value, then a significant portion of the capital
loss carryover could expire before it is utilized. During 2004 the Company
recorded a valuation allowance of $0.5 million, primarily for incremental state
income tax expenses that it expects to incur as a result of the planned property
dispositions.
4. Long-Term Debt
Our long-term debt as of December 31, 2004 and 2003, is as follows:
2004 2003
------------- -------------
Bank Borrowings $ 7,500,000 $ 15,900,000
10-1/4% senior subordinated notes due 2009 --- 124,354,783
7-5/8% senior notes due 2011 150,000,000 ---
9-3/8% senior subordinated notes due 2012 200,000,000 200,000,000
-------------- --------------
Long-Term Debt $ 357,500,000 $ 340,254,783
============== ==============
Bank Borrowings. At December 31, 2004, we had $7.5 million in outstanding
borrowings under our $400.0 million credit facility with a syndicate of ten
banks that has a borrowing base of $250.0 million and expires in October 2008.
At December 31, 2003, we had $15.9 million in outstanding borrowings under our
credit facility. The interest rate is either (a) the lead bank's prime rate
(5.25% at December 31, 2004) or (b) the adjusted London Interbank Offered Rate
("LIBOR") plus the applicable margin depending on the level of outstanding debt.
The applicable margin is based on the ratio of the outstanding balance to the
last calculated borrowing base. All amounts borrowed at December 31, 2004 were
at the bank's prime rate. In June 2004, we increased, renewed and extended this
credit facility, increasing the facility to $400 million from $300 million and
extending its expiration to October 1, 2008 from October 1, 2005. The other
terms of the credit facility, such as the borrowing base amount and commitment
amount, stayed largely the same. The covenants related to this credit facility
changed somewhat with the extension of the facility and are discussed below. We
incurred $0.4 million of debt issuance costs related to the renewal of this
facility in 2004, which is included in "Debt issuance costs" on the accompanying
consolidated balance sheets and will be amortized to interest expense over the
life of the facility.
The terms of our credit facility include, among other restrictions, a
limitation on the level of cash dividends (not to exceed $5.0 million in any
fiscal year), a remaining aggregate limitation on purchases of our stock of
$15.0 million, requirements as to maintenance of certain minimum financial
ratios (principally pertaining to adjusted working capital ratios and EBITDAX),
and limitations on incurring other debt or repurchasing our 7-5/8% senior notes
due 2011 or 9-3/8% senior subordinated notes due 2012. Since inception, no cash
dividends have been declared on our common stock. We are currently in compliance
with the provisions of this agreement. The credit facility is secured by our
domestic oil and gas properties. We have also pledged 65% of the stock in our
two New Zealand subsidiaries as collateral for this credit facility. The
borrowing base is re-determined at least every six months and was reconfirmed by
our bank group at $250.0 million effective November 1, 2004. We requested that
the commitment amount with our bank group be reduced to $150.0 million effective
May 9, 2003. Under the terms of the credit facility, we can increase this
commitment amount back to the total amount of the borrowing base at our
discretion, subject to the terms of the credit agreement. The next scheduled
borrowing base review is in May 2005.
Interest expense on the credit facility, including commitment fees and
amortization of debt issuance costs, totaled $1.5 million in 2004, $1.6 million
in 2003, and $3.6 million in 2002. The amount of commitment fees included in
interest expense, net was $0.5 million in 2004 and $0.6 million in both 2003 and
2002.
Senior Subordinated Notes Due 2009. These notes consisted of $125.0 million
of 10-1/4% senior subordinated notes due August 2009, which were issued at
99.236% of the principal amount on August 4, 1999, and were scheduled to mature
on August 1, 2009. These notes were unsecured senior subordinated obligations
with interest payable semiannually, on February 1 and August 1. In June 2004, we
repurchased $32.1 million of these notes pursuant to a tender offer. In July
2004, we repurchased an additional $0.5 million of these notes, and as of August
1, 2004, we redeemed the remaining $92.5 million in outstanding notes. In 2004,
we recorded a charge of $9.5 million related to the repurchase of these notes,
which is recorded in "Debt
65
retirement costs" on the accompanying consolidated statement of income. The
costs were comprised of approximately $6.5 million of premiums paid to
repurchase the notes, $2.2 million to write-off unamortized debt issuance costs,
$0.6 million to write-off unamortized debt discount, and approximately $0.2
million of other costs.
Interest expense on the 10-1/4% senior subordinated notes due 2009,
including amortization of debt issuance costs and discount, totaled $7.4 million
in 2004 and $13.2 million in both 2003 and 2002.
Senior Notes Due 2011. These notes consist of $150.0 million of 7-5/8%
senior notes due 2011, which were issued on June 23, 2004 at 100% of the
principal amount and will mature on July 15, 2011. The notes are senior
unsecured obligations that rank equally with all of our existing and future
senior unsecured indebtedness, are effectively subordinated to all our existing
and future secured indebtedness to the extent of the value of the collateral
securing such indebtedness, including borrowing under our bank credit facility,
and rank senior to all of our existing and future subordinated indebtedness.
Interest on these notes is payable semi-annually on January 15 and July 15, and
commenced on January 15, 2005. On or after July 15, 2008, we may redeem some or
all of the notes, with certain restrictions, at a redemption price, plus accrued
and unpaid interest, of 103.813% of principal, declining to 100% in 2010 and
thereafter. In addition, prior to July 15, 2007, we may redeem up to 35% of the
notes with the net proceeds of qualified offerings of our equity at a redemption
price of 107.625% of the principal amount of the notes, plus accrued and unpaid
interest. We incurred approximately $3.9 million of debt issuance costs related
to these notes, which is included in "Debt issuance costs" on the accompanying
consolidated balance sheets and will be amortized to interest expense, net over
the life of the notes using the effective interest method. Upon certain changes
in control of Swift Energy, each holder of notes will have the right to require
us to repurchase all or any part of the notes at a purchase price in cash equal
to 101% of the principal amount, plus accrued and unpaid interest to the date of
purchase. The terms of these notes include, among other restrictions, a
limitation on how much of our own common stock we may repurchase. We are
currently in compliance with the provisions of the indenture governing these
senior notes.
Interest expense on the 7-5/8% senior notes due 2011, including
amortization of debt issuance costs totaled $6.2 million in 2004.
Senior Subordinated Notes Due 2012. These notes consist of $200.0 million
of 9-3/8% senior subordinated notes due May 2012, which were issued on April 11,
2002, and will mature on May 1, 2012. The notes are unsecured senior
subordinated obligations and are subordinated in right of payment to all our
existing and future senior debt, including our bank credit facility. Interest on
these notes is payable semiannually on May 1 and November 1, with the first
interest payment on November 1, 2002. On or after May 1, 2007, we may redeem
these notes, with certain restrictions, at a redemption price, plus accrued and
unpaid interest, of 104.688% of principal, declining to 100% in 2010. In
addition, prior to May 1, 2005, we may redeem up to 33.33% of these notes with
the net proceeds of qualified offerings of our equity at 109.375% of the
principal amount of these notes, plus accrued and unpaid interest. Upon certain
changes in control of Swift Energy, each holder of these notes will have the
right to require us to repurchase the notes at a purchase price in cash equal to
101% of the principal amount, plus accrued and unpaid interest to the date of
purchase. The terms of these notes include, among other restrictions, a
limitation on how much of our own common stock we may repurchase. We are
currently in compliance with the provisions of the indenture governing these
subordinated notes due 2012.
Interest expense on the 9-3/8% senior subordinated notes due 2012,
including amortization of debt issuance costs totaled $19.2 million in 2004,
$19.1 million in 2003 and $13.5 million in 2002.
The aggregate maturities on our long-term debt are $0, $0, $0, $7.5
million, $0, and $350.0 million for 2005, 2006, 2007, 2008, 2009, and
thereafter, respectively.
We have capitalized interest on our unproved properties in the amount of
$6.5 million, $6.8 million, and $7.0 million, in 2004, 2003, and 2002,
respectively.
66
5. Commitments and Contingencies
Total rental and lease expenses were $2.4 million in 2004, $2.2 million in
2003, and $1.9 million in 2002 and are included in "General and administrative,
net" on our accompanying consolidated statements of income. Our remaining
minimum annual obligations under non-cancelable operating lease commitments are
$2.5 million for 2005, $2.6 million for 2006, $2.5 million for 2007, $2.5
million for 2008, $2.3 million in 2009, and $13.0 million thereafter or $25.4
million in the aggregate. The rental and lease expenses and remaining minimum
annual obligations under non-cancelable operating lease commitments primarily
relate to the lease of our office space in Houston, Texas, and in New Zealand.
In the ordinary course of business, we have entered into agreements with
drilling and seismic contractors for such services. The remaining commitments at
December 31, 2004 for these services totaled $4.4 million and these services are
expected to be provided in 2005.
As of December 31, 2004, we were the managing general partner of six
private limited partnerships. Because we serve as the general partner of these
entities, under state partnership law we are contingently liable for the
liabilities of these partnerships, which liabilities are not material for any of
the periods presented in relation to the partnerships' respective assets.
In the ordinary course of business, we have been party to various legal
actions, which arise primarily from our activities as operator of oil and gas
wells. In management's opinion, the outcome of any such currently pending legal
actions will not have a material adverse effect on our financial position or
results of operations.
6. Stockholders' Equity
Common Stock. During the first quarter of 2002, we issued 1.725 million
shares of common stock at a price of $18.25 per share pursuant to a public
underwriting offering. Gross proceeds from this offering were $31.5 million,
with issuance costs of $1.0 million.
Stock-Based Compensation Plans. We have two stock option plans that awards
are currently granted under, the 2001 Omnibus Stock Compensation Plan, which was
adopted by our Board of Directors in February 2001 and was approved by
shareholders at the 2001 annual meeting of shareholders, and the 1990
Non-Qualified Stock Option Plan solely for our independent directors. No further
grants will be made under the 1990 Stock Compensation Plan, which was replaced
by the 2001 Omnibus Stock Compensation Plan, although options remain outstanding
under such plan and are accordingly included in the tables below. In addition,
we have an employee stock purchase plan.
Under the 2001 plan, incentive stock options and other options and awards
may be granted to employees to purchase shares of common stock. Under the 1990
non-qualified plan, non-employee members of our Board of Directors are
automatically granted options to purchase shares of common stock on a formula
basis. Both plans provide that the exercise prices equal 100% of the fair value
of the common stock on the date of grant. Unless otherwise provided, options
become exercisable for 20% of the shares on the first anniversary of the grant
of the option and are exercisable for an additional 20% per year thereafter.
Options granted typically expire ten years after the date of grant or earlier in
the event of the optionee's separation from employment. At the time the stock
options are exercised, the cash received is credited to common stock and
additional paid-in capital. Options issued under this plan also include a reload
feature where additional options are granted at the then current market price
when mature shares of Swift Energy common stock are used to satisfy the exercise
price of an existing stock option grant. When Swift Energy common stock is used
to satisfy the exercise price, the net shares actually issued are reflected in
the accompanying Statement of Stockholders' Equity (see note 1 to table below).
We view all awards of stock compensation as a single award with an expected life
equal to the average expected life of component awards and amortize the award on
a straight-line basis over the life of the award.
The employee stock purchase plan provides eligible employees the
opportunity to acquire shares of Swift Energy common stock at a discount through
payroll deductions. The plan year is from June 1 to the following May 31. The
first year of the plan commenced June 1, 1993. To date, employees have been
allowed to authorize payroll deductions of up to 10% of their base salary during
the plan year by making an election to participate prior to the start of a plan
year. The purchase price for stock acquired under the plan is 85% of the
68
lower of the closing price of our common stock as quoted on the New York Stock
Exchange at the beginning or end of the plan year or a date during the year
chosen by the participant. Under this plan for the last three years, we have
issued 50,418 shares at a price range of $9.98 to $10.83 in 2004, 56,574 shares
at a price range of $6.80 to $11.85 in 2003, and 9,801 shares at a price of
$12.47 in 2002. As of December 31, 2004, 245,635 shares remained available for
issuance under this plan.
The following is a summary of our stock options under these plans as of December
31, 2004, 2003, and 2002:
2004 2003 2002
------------------------ ------------------------ ------------------------------
Wtd. Avg. Wtd. Avg. Wtd. Avg.
Shares Exer.Price Shares Exer. Price Shares Exer. Price
------------ ---------- ----------- ----------- --------------- -------------
Options outstanding, beginning of period 3,238,611 $ 16.37 3,018,505 $ 16.64 2,639,504 $ 17.44
Options granted 415,744 $ 23.36 504,014 $ 13.20 585,055 $ 12.32
Options canceled (64,866) $ 21.85 (110,901) $ 21.02 (84,254) $ 23.37
Options exercised1 (590,821) $ 9.83 (173,007) $ 8.85 (121,800) $ 8.61
------------ ----------- ---------------
Options outstanding, end of period 2,998,668 $ 18.51 3,238,611 $ 16.37 3,018,505 $ 16.64
============ =========== ===============
Options exercisable, end of period 1,542,571 $ 17.78 1,714,789 $ 15.00 1,480,490 $ 13.71
============ =========== ===============
Options available for future grant, end of
period 89,278 494,925 419,845
============ =========== ===============
Estimated weighted average fair value per
share of options granted during the year $9.51 $6.93 $9.55
============ =========== ===============
The following table summarizes information about stock options outstanding
at December 31, 2004:
Options Outstanding Options Exercisable
--------------------------------------- --------------------------
Range of Wtd. Avg.
Exercise Number Remaining Wtd. Avg. Number Wtd. Avg.
Prices Outstanding Contractual Exercise Exercisable Exercise
at 12/31/04 Life Price At 12/31/04 Price
---------------- -------------- ----------- ----------- ------------- -----------
$ 7.00 to $17.99 1,723,401 6.1 $ 11.64 955,298 $ 10.76
$18.00 to $28.99 598,044 7.0 $ 23.23 169,924 $ 22.60
$29.00 to $41.00 677,223 6.2 $ 31.84 417,349 $ 31.89
-------------- -------------
$ 7.00 to $41.00 2,998,668 6.3 $ 18.51 1,542,571 $ 17.78
============== =============
1 The option plans allow for the use of a "stock swap" in lieu of a cash
exercise, under certain circumstances. The delivery of Swift Energy common
stock, held by the optionee for a minimum of six months, which are considered
mature shares, with a fair market value equal to the required purchase price of
the shares to which the exercise relates, constitutes a valid "stock swap."
Options issued under a "stock swap" also include a reload feature where
additional options are granted at the then current market price when mature
shares of Swift stock are used to satisfy the exercise price of an existing
stock option grant. The terms of the plans provide that the mature shares
delivered, as full or partial payment in a "stock swap", shall again be
available for awards under the plans. The options exercised above include
81,716, 30,200 and 8,805 shares in 2004, 2003 and 2002 respectively, related to
"stock swap" shares that were also reloaded.
Restricted Stock. In 2004, the Company issued the rights to 70,900 shares
of restricted stock to employees. These shares vest over a five-year period and
remain subject to forfeiture if vesting conditions are not met. In accordance
with APB Opinion No. 25, we recognize unearned compensation in connection with
the grant of restricted shares equal to the fair value of our common stock on
the date of grant. The fair value of these shares when issued in 2004 was
approximately $25 per share, and resulted in an increase in "Additional paid-in
capital" and "Unearned compensation" on the accompanying balance sheet of $1.8
million. As restricted shares vest, we reduce unearned compensation and
recognize compensation expense. In 2004, we recorded expense related to these
shares of less than $0.1 million in "General and administrative, net" on the
accompanying statements of income.
In 2004, we also issued the rights to 30,000 shares of restricted stock to
non-employees. These shares vest over a two-year period and remain subject to
forfeiture if performance conditions are not met within that
68
period. This issuance is accounted for under FAS No. 123 and as such a
measurement date for assessing fair value of this grant has not been achieved.
We recognized approximately $0.2 million of compensation cost in 2004 related to
these shares. The non-employee performs work that is capitalized to unproved
properties, and as such the compensation cost recognized in 2004 was recorded to
"Unproved properties" on the accompanying balance sheets.
Employee Stock Ownership Plan. In 1996, we established an Employee Stock
Ownership Plan ("ESOP") effective January 1, 1996. All employees over the age of
21 with one year of service are participants. This plan has a five-year cliff
vesting. The ESOP is designed to enable our employees to accumulate stock
ownership. While there will be no employee contributions, participants will
receive an allocation of stock that has been contributed by Swift Energy.
Compensation expense is recognized upon vesting when such shares are released to
employees. The plan may also acquire Swift Energy common stock, purchased at
fair market value. The ESOP can borrow money from Swift Energy to buy Swift
Energy common stock. ESOP payouts will be paid in a lump sum or installments,
and the participants generally have the choice of receiving cash or stock. At
December 31, 2004, 2003, and 2002, all of the ESOP compensation was earned. Our
contribution to the ESOP plan totaled $0.2 million for the years ended December
31, 2004, 2003, and 2002, and were made all in common stock, and are recorded as
"General and administrative, net" on the accompanying consolidated statements of
income. The shares of common stock contributed to the ESOP plan totaled 6,911,
11,870, and 18,711 shares for the 2004, 2003, and 2002 contributions,
respectively.
Employee Savings Plan. We have a savings plan under Section 401(k) of the
Internal Revenue Code. Eligible employees may make voluntary contributions into
the 401(k) savings plan with Swift contributing on behalf of the eligible
employee an amount equal to 100% of the first 2% of compensation and 75% of the
next 4% of compensation based on the contributions made by the eligible
employees. Our contributions to the 401(k) savings plan were $0.7 million for
2004 and $0.6 million for each of the years ended December 31, 2003 and 2002,
and are recorded as "General and administrative, net" on the accompanying
consolidated statements of income. The contributions in 2004, 2003, and 2002
were made all in common stock. The shares of common stock contributed to the
401(k) savings plan totaled 24,513, 34,280, and 64,490 shares for the 2004,
2003, and 2002 contributions, respectively.
Common Stock Repurchase Program. In March 1997, our Board of Directors
approved a common stock repurchase program that terminated as of June 30, 1999.
Under this program, we spent approximately $13.3 million to acquire 927,774
shares in the open market at an average cost of $14.34 per share. At December
31, 2004, 480,868 shares remain in treasury (net of 446,906 shares used to fund
ESOP, 401(k) contributions and acquisitions) with a total cost of $6.9 million
and are included in "Treasury stock held, at cost" on the accompanying balance
sheet.
Shareholder Rights Plan. In August 1997, our board of directors declared a
dividend of one preferred share purchase right on each outstanding share of
Swift Energy common stock. The rights are not currently exercisable but would
become exercisable if certain events occurred relating to any person or group
acquiring or attempting to acquire 15% or more of our outstanding shares of
common stock. Thereafter, upon certain triggers, each right not owned by an
acquirer allows its holder to purchase Swift securities with a market value of
two times the $150 exercise price.
7. Related-Party Transactions
We have been the operator of a number of properties owned by private
limited partnerships and, accordingly, charge these entities operating fees. The
operating supervision fees charged to the partnerships totaled approximately
$0.2 million in both 2004 and 2003, and $0.3 million in 2002, and are recorded
as reductions of "General and administrative, net." We also have been reimbursed
for administrative, and overhead costs incurred in conducting the business of
the private limited partnerships, which totaled approximately $0.2 million, $0.4
million, and $1.0 million in 2004, 2003, and 2002, respectively, and are
recorded as reductions in "General and administrative, net." Included in
"Accounts receivable" and "Accounts payable and accrued liabilities" on the
accompanying balance sheets, is less than $0.1 million and $1.1 million,
respectively, in receivables from and payables to the partnerships at December
31, 2004.
We receive research, technical writing, publishing, and website-related
services from Tec-Com Inc., a corporation located in Knoxville, Tennessee and
controlled by the sister of the Company's Chairman and Vice
69
Chairman of the Board. The sister and brother-in-law of Messrs. A. E. Swift and
V. Swift also own a substantial majority of Tec-Com. In 2004, 2003 and 2002, we
paid approximately $0.4 million per year to Tec-Com for such services pursuant
to the terms of the contract between the parties. The contract was renewed June
30, 2004 on substantially the same terms and expires June 30, 2007. We believe
that the terms of this contract are consistent with third party arrangements
that provide similar services. As a matter of corporate governance policy and
practice, related party transactions are annually presented and considered by
the Corporate Governance Committee of our Board of Directors in accordance with
the Committee's charter.
8. Foreign Activities
As of December 31, 2004, our gross capitalized oil and gas property costs
in New Zealand totaled approximately $243.2 million. Approximately $209.8
million has been included in the "Proved properties" portion of our oil and gas
properties, while $33.4 million is included as "Unproved properties." Our
functional currency in New Zealand is the U.S. Dollar. Net assets of our New
Zealand operations total $197.4 million at December 31, 2004. Our expenditures
on oil and gas property in New Zealand were approximately $36.5 million in 2004.
9. Acquisitions and Dispositions
New Zealand
Through our subsidiary, Swift Energy New Zealand Limited ("SENZ"), we
acquired Southern Petroleum (NZ) Exploration Limited ("Southern NZ") in January
2002 for approximately $51.4 million in cash. We allocated $36.1 million of the
acquisition price to "Proved properties," $10.0 million to "Unproved
properties," $4.9 million to "Deferred income taxes," and $0.4 million to "Other
current assets" on our consolidated balance sheet. Southern NZ was an affiliate
of Shell New Zealand and owns interests in four onshore producing oil and gas
fields, hydrocarbon processing facilities, and pipelines connecting the fields
and facilities to export terminals and markets. These assets fit strategically
with our existing assets in New Zealand. This acquisition was accounted for by
the purchase method of accounting. The revenues and expenses from these TAWN
properties have been included in our consolidated statements of income from the
date of acquisition forward. In conjunction with this TAWN acquisition, we
granted Shell New Zealand a short-term option to acquire an undivided 25%
interest in our permit 38719, which included our Rimu/Kauri areas and the Rimu
Production Station. This option was not exercised and expired on May 15, 2002.
In March 2002, we purchased through our subsidiary, SENZ, all of the New
Zealand assets owned by Antrim for 220,000 shares of Swift Energy common stock,
which we held in treasry, valued at $4.2 million and an effective date
adjustment of approximately $0.5 million in cash for total consideration of $4.7
million. Antrim owned a 5% interest in permit 38719 and a 7.5% interest in
permit 38716.
In September 2002, we purchased through our subsidiary, SENZ, Bligh's 5%
working interest in permit 38719 and 5% interest in the Rimu petroleum mining
permit 38151, along wth their 3.24% working interest in the four TAWN petroleum
mining licenses for 300,000 shares of Swift Energy common stock valued at $3.9
million and $2.7 million in cash for total consideration of $6.6 million.
Domestic
In December 2004 we acquired interests in two fields in South Louisiana,
the Bay de Chene and Cote Blanche Island fields. We paid approximately $27.7
million in cash for hese interests. After taking into account internal
acquisition costs of $2.8 million, our total cost was $30.5 million. We
allocated $27.8 million of the acquisition price to "Proved properties," $5.1
million to "Unproved properties," we also recorded $0.5 million to "Restricted
assets," and recorded a liability of $2.9 million to "Asset retirement
obligation" on our accompanying consolidated balance sheet. This acquisition was
accounted for by the purchase method of accounting. We made this acquisition to
increase our exploration and development opportunities in South Louisiana. The
revenues and expenses from these properties have been included in our
accompanying consolidated statements of income from the date of acquisition
forward, however, given the acquisition was in late December 2004, these amounts
were immaterial.
70
Russia
In 1993, we entered into a Participation Agreement with Senega, a Russian
Federation joint stock company, to assist in the development and production of
reserves from two fields in Western Siberia and received a 5% net profits
interest. We also purchased a 1% net profits interest. Our investment in Russia
was fully impaired in the third quarter of 1998. In March 2002, we received $7.5
million for our investment in Russia. Although the proceeds from sales of oil
and gas properties are generally treated as a reduction of oil and gas property
costs, because we had previously charged to expense all $10.8 million of
cumulative costs relating to our Russian activities, this cash payment, net of
transaction expenses, resulted in recognition of a $7.3 million non-recurring
gain on asset disposition in the first quarter of 2002, and is included in our
accompanying statements of income.
10. Segment Information
The Company has two reportable segments, one domestic and one foreign,
which are in the business of crude oil and natural gas exploration and
production. The accounting policies of the segments are the same as those
described in the summary of significant accounting policies. We evaluate our
performance based on profit or loss from oil and gas operations before gain on
asset disposition, price-risk management and other, net, general and
administrative, net, interest expense, net and debt retirement costs. Our
reportable segments are managed separately based on their geographic locations.
Financial information by operating segment is presented below:
2004
--------------------------------------------
New
Domestic Zealand Total
------------- ------------- -------------
Oil and gas sales $ 258,663,936 $ 52,621,236 $ 311,285,172
Costs and Expenses:
Depreciation, depletion, and
amortization (62,283,350) (19,297,478) (81,580,828)
Accretion of asset retirement
obligation (505,174) (168,480) (673,654)
Lease operating cost (30,191,889) (11,022,367) (41,214,256)
Severance and other taxes (26,713,592) (3,687,701) (30,401,293)
------------- ------------- -------------
Income from oil and gas operations $ 138,969,931 $ 18,445,210 $ 157,415,141
Price-risk management and other,
net (1,008,398)
General and administrative, net (17,787,125)
Interest expense, net (27,643,108)
Debt retirement costs (9,536,268)
-------------
Income before Income Taxes and Change
in Accounting Principle $ 101,440,242
=============
Property and Equipment, net $ 731,890,068 $ 191,548,092 $ 923,438,160
Total Assets 778,611,100 211,962,047 990,573,147
Capital Expenditures $ 162,535,617 $ 35,755,820 $ 198,291,437
============= ============= =============
71
2003
--------------------------------------------
New
Domestic Zealand Total
------------- ------------- -------------
Oil and gas sales $ 164,167,390 $ 46,865,249 $ 211,032,639
Costs and Expenses:
Depreciation, depletion, and
amortization (44,645,939) (18,426,118) (63,072,057)
Accretion of asset retirement
obligation (623,948) (233,408) (857,356)
Lease operating cost (24,022,412) (9,810,786) (33,833,198)
Severance and other taxes (15,290,669) (3,742,935) (19,033,604)
------------- ------------- -------------
Income from oil and gas operations $ 79,584,422 $ 14,652,002 $ 94,236,424
Price-risk management and other,
net (2,131,656)
General and administrative, net (14,097,066)
Interest expense, net (27,268,524)
-------------
Income before Income Taxes and Change
in Accounting Principle $ 50,739,178
=============
Property and Equipment, net $ 641,366,888 $ 174,440,115 $ 815,807,003
Total Assets 672,721,551 187,116,993 859,838,544
Capital Expenditures $ 114,443,475 $ 30,059,705 $ 144,503,180
============= ============= =============
2002
--------------------------------------------
New
Domestic Zealand Total
------------- ------------- -------------
Oil and gas sales $ 112,065,003 $ 29,130,710 $ 141,195,713
Costs and Expenses:
Depreciation, depletion, and
amortization (43,660,843) (12,563,549) (56,224,392)
Lease operating costs (23,308,444) (5,610,414) (28,918,858)
Severance and other taxes (9,780,514) (2,797,940) (12,578,454)
------------- ------------- -------------
Income from oil and gas operations $ 35,315,202 $ 8,158,807 $ 43,474,009
Gain on asset disposition 7,332,668
Price-risk management and other,
net 1,441,430
General and administrative, net (10,564,849)
Interest expense, net (23,274,969)
-------------
Income before Income Taxes and Change
in Accounting Principle $ 18,408,289
=============
Property and Equipment, net $ 565,149,393 $ 160,360,061 $ 725,509,454
Total Assets 594,627,972 172,377,887 767,005,859
Capital Expenditures $ 59,981,376 $ 95,252,547 $ 155,233,923
============= ============= =============
72
Supplemental Information (Unaudited)
Swift Energy Company and Subsidiaries
Capitalized Costs. The following table presents our aggregate capitalized
costs relating to oil and gas producing activities and the related depreciation,
depletion, and amortization:
Total Domestic New Zealand
===================== ================ =================
December 31, 2004:
Proved oil and gas properties $ 1,479,681,903 $ 1,271,354,490 $ 208,327,413
Unproved oil and gas properties 80,121,509 46,751,416 33,370,093
--------------------- ---------------- -----------------
1,559,803,412 1,318,105,906 241,697,506
Accumulated depreciation, depletion, and amortization (641,917,990) (590,906,014) (51,011,976)
--------------------- ---------------- -----------------
Net capitalized costs $ 917,885,422 $ 727,199,892 $ 190,685,530
===================== ================ =================
December 31, 2003:
Proved oil and gas properties $ 1,305,110,582 $ 1,135,615,117 $ 169,495,465
Unproved oil and gas properties 67,557,969 31,802,621 35,755,348
--------------------- ---------------- -----------------
1,372,668,551 1,167,417,738 205,250,813
Accumulated depreciation, depletion, and amortization (560,961,013) (529,272,658) (31,688,355)
--------------------- ---------------- -----------------
Net capitalized costs $ 811,707,538 $ 638,145,080 $ 173,562,458
===================== ================ =================
Of the $46.7 million of domestic Unproved property costs (primarily seismic
and lease acquisition costs) at December 31, 2004, excluded from the amortizable
base, $30.3 million was incurred in 2004, $2.9 million was incurred in 2003,
$2.5 million was incurred in 2002, and $11.1 million was incurred in prior
years. When we are in an active drilling mode, we evaluate the majority of these
unproved costs within a two to four year time frame.
Of the $33.4 million of New Zealand Unproved property costs at December 31,
2004, excluded from the amortizable base, $3.7 million was incurred in 2004,
$8.3 million was incurred in 2003, $17.0 million was incurred or acquired in
2002, and $4.4 million was incurred in prior years. We expect to continue
drilling in New Zealand to delineate our prospects there within a two to four
year time frame.
Capitalized asset retirement obligations have been included in the Proved
properties as of December 31, 2004 and 2003, as we adopted SFAS No. 143
"Accounting for Asset Retirement Obligations" effective January 1, 2003.
73
Costs Incurred. The following table sets forth costs incurred related to
our oil and gas operations:
Year Ended December 31, 2004
-----------------------------------------------------------
Total Domestic New Zealand
--------------------- ---------------- -----------------
Acquisition of proved and unproved properties $ 31,771,094 $ 31,771,094 $ --
Lease acquisitions and prospect costs 1 34,545,393 27,713,059 6,832,334
Exploration 17,430,265 16,714,982 715,283
Development 105,947,485 78,163,289 27,784,196
--------------------- ---------------- -----------------
Total acquisition, exploration, and development 2 $ 189,694,237 $ 154,362,424 $ 35,331,813
--------------------- ---------------- -----------------
Processing plants $ 1,283,515 $ 147,317 $ 1,136,198
Field compression facilities 1,028,091 1,028,091 --
--------------------- ---------------- -----------------
Total plants and facilities $ 2,311,606 $ 1,175,408 $ 1,136,198
--------------------- ---------------- -----------------
Total costs incurred 3 $ 192,005,843 $ 155,537,832 $ 36,468,011
===================== ================ =================
Year Ended December 31, 2003
-----------------------------------------------------------
Total Domestic New Zealand
--------------------- ---------------- -----------------
Acquisition of proved and unproved properties $ 1,942,868 $ 1,635,316 $ 307,552
Lease acquisitions and prospect costs 1 18,869,099 12,440,144 6,428,955
Exploration 14,467,455 11,789,700 2,677,755
Development 116,451,112 100,549,351 15,901,761
--------------------- ---------------- -----------------
Total acquisition, exploration, and development 2 $ 151,730,534 $ 126,414,511 $ 25,316,023
--------------------- ---------------- -----------------
Processing plants $ 6,192,199 $ 907,771 $ 5,284,428
Field compression facilities 3,521,522 3,521,522 --
--------------------- ---------------- -----------------
Total plants and facilities $ 9,713,721 $ 4,429,293 $ 5,284,428
--------------------- ---------------- -----------------
Total costs incurred 3 $ 161,444,255 $ 130,843,804 $ 30,600,451
===================== ================ =================
Year Ended December 31, 2002
-----------------------------------------------------------
Total Domestic New Zealand
--------------------- ---------------- -----------------
Acquisition of proved and unproved properties $ 64,229,283 $ 5,415,932 $ 58,813,351
Lease acquisitions and prospect costs 1 16,009,939 10,789,876 5,220,063
Exploration 18,395,335 7,571,215 10,824,120
Development 47,407,087 40,366,378 7,040,709
--------------------- ---------------- -----------------
Total acquisition, exploration, and development 2 $ 146,041,644 $ 64,143,401 $ 81,898,243
--------------------- ---------------- -----------------
Processing plants $ 7,845,520 $ 1,313,299 $ 6,532,221
Field compression facilities 2,251,247 2,251,247 --
--------------------- ---------------- -----------------
Total plants and facilities $ 10,096,767 $ 3,564,546 $ 6,532,221
--------------------- --------------- -----------------
Total costs incurred 3 $ 156,138,411 $ 67,707,947 $ 88,430,464
===================== ================ =================
1 These are actual amounts as incurred by year, including both proved and
unproved lease costs. The annual lease acquisition amounts added to proved oil
and gas properties in 2004, 2003, and 2002 were $17,811,217, $20,702,276, and
$23,454,234, respectively.
2 Includes capitalized general and administrative costs directly associated with
the acquisition, exploration, and development efforts of approximately $13.1
million, $11.5 million, and $10.7 million in 2004, 2003, and 2002, respectively.
In addition, total includes $6.5 million, $6.8 million , and $7.0 million in
2004, 2003, and 2002, respectively, of capitalized interest on unproved
properties.
3 Asset retirement obligations incurred have been included in exploration,
development and acquisition costs as applicable for the years ended December 31,
2004 and 2003, as we adopted SFAS No. 143 "Accounting for Asset Retirement
Obligations" effective January 1, 2003.
74
Results of Operations.
Year Ended December 31, 2004
--------------------------------------------------
Total Domestic New Zealand
--------------- -------------- ---------------
Oil and gas sales $ 311,285,172 $ 258,663,936 $ 52,621,236
Lease operating cost (41,214,256) (30,191,889) (11,022,367)
Severance and other taxes (30,401,293) (26,713,592) (3,687,701)
Depreciation and depletion (80,504,043) (61,478,364) (19,025,679)
Accretion of asset retirement obligation (673,654) (505,174) (168,480)
--------------- -------------- ---------------
158,491,926 139,774,917 18,717,009
Provision for income taxes 53,093,022 51,576,944 1,516,078
--------------- -------------- ---------------
Results of producing activities $ 105,398,904 $ 88,197,973 $ 17,200,931
=============== ============== ===============
Amortization per physical unit of production
(equivalent Mcf of gas) $ 1.38 $ 1.46 $ 1.17
=============== ============== ===============
Year Ended December 31, 2003
--------------------------------------------------
Total Domestic New Zealand
---------------- -------------- ---------------
Oil and gas sales $ 211,032,639 $ 164,167,390 $ 46,865,249
Lease operating cost (33,833,198) (24,022,412) (9,810,786)
Severance and other taxes (19,033,604) (15,290,669) (3,742,935)
Depreciation and depletion (62,037,680) (43,818,709) (18,218,971)
Accretion of asset retirement obligation (857,356) (623,948) (233,408)
--------------- -------------- ----------------
95,270,801 80,411,652 14,859,149
Provision for income taxes 32,321,635 29,696,023 2,625,612
--------------- -------------- ---------------
Results of producing activities $ 62,949,166 $ 50,715,629 $ 12,233,537
=============== ============== ===============
Amortization per physical unit of production
(equivalent Mcf of gas) $ 1.17 $ 1.30 $ 0.94
=============== ============== ===============
Year Ended December 31, 2002
---------------------------------------------------
Total Domestic New Zealand
--------------- -------------- ----------------
Oil and gas sales $ 141,195,713 $ 112,065,003 $ 29,130,710
Lease operating cost (28,918,858) (23,308,444) (5,610,414)
Severance and other taxes (12,578,454) (9,780,514) (2,797,940)
Depreciation and depletion (55,254,467) (42,807,364) (12,447,103)
--------------- -------------- ---------------
44,443,934 36,168,681 8,275,253
Provision for income taxes 15,860,064 13,129,231 2,730,833
--------------- -------------- ---------------
Results of producing activities $ 28,583,870 $ 23,039,450 $ 5,544,420
=============== ============== ===============
Amortization per physical unit of production
(equivalent Mcf of gas) $ 1.11 $ 1.25 $ 0.80
=============== ============== ===============
These results of operations do not include the losses from our hedging
activities of $1.3 million, $2.8 million, and $0.2 million for 2004, 2003 and
2002, respectively. Our lease operating costs per Mcfe produced were $0.71 in
2004, $0.64 in 2003, and $0.58 in 2002.
The accretion of asset retirement obligation has been included in the 2004
and 2003 periods, as we adopted SFAS No. 143 "Accounting for Asset Retirement
Obligations" effective January 1, 2003.
We used our effective tax rate in each country to compute the provision for
income taxes in each year presented.
75
Supplemental Reserve Information. The following information presents
estimates of our proved oil and gas reserves. Reserves were determined by us and
audited by H. J. Gruy and Associates, Inc. ("Gruy"), independent petroleum
consultants. Gruy has audited 100% of our proved reserves. Gruy's audit was
conducted according to standards approved by the Board of Directors of the
Society of Petroleum Engineers, Inc. and included examination, on a test basis,
of the evidence supporting our reserves. Gruy's audit was based upon review of
production histories and other geological, economic, and engineering data
provided by Swift. Where Gruy had material disagreements with Swift reserve
estimates, we revised our estimates to be in agreement. Gruy's report dated
January 27, 2005, is set forth as an exhibit to the Form 10-K Report for the
year ended December 31, 2004, and includes definitions and assumptions that
served as the basis for the audit of proved reserves and future net cash flows.
Such definitions and assumptions should be referred to in connection with the
following information:
Estimates of Proved Reserves
Total Domestic New Zealand
------------------------- ---------------------------- ------------------------
Oil, NGL, Oil, NGL, Oil, NGL,
and and and
Natural Gas Condensate Natural Gas Condensate Natural Gas Condensate
(Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls)
------------ ----------- ------------- ----------- ----------- -----------
Proved reserves as of December 31, 2001 324,912,125 53,482,636 288,489,500 42,564,733 36,422,625 10,917,903
Revisions of previous estimates 1 (29,972,714) 5,298,439 (29,470,419) 8,675,082 (502,295) (3,376,643)
Purchases of minerals in place 51,940,044 3,711,948 226,245 24,207 51,713,799 3,687,741
Sales of minerals in place (3,839,124) (464,490) (3,839,124) (464,490) -- --
Extensions, discoveries, and other
additions 10,822,919 12,180,558 197,919 11,304,782 10,625,000 875,776
Production (27,131,578) (3,770,128) (15,780,059) (3,074,674) (11,351,519) (695,454)
------------ ----------- ------------- ----------- ----------- -----------
Proved reserves as of December 31, 2002 326,731,672 70,438,963 239,824,062 59,029,640 86,907,610 11,409,323
Revisions of previous estimates 1 (6,445,114) 4,975,920 (1,418,312) 3,497,022 (5,026,802) 1,478,898
Purchases of minerals in place 273,623 35,472 273,623 35,472 -- --
Sales of minerals in place (3,984,209) (228,505) (3,984,209) (228,505) -- --
Extensions, discoveries, and other
additions 47,231,609 9,730,665 21,370,151 8,018,766 25,861,458 1,711,899
Production (28,002,719) (4,192,612) (13,744,040) (3,336,702) (14,258,679) (855,910)
------------ ------------ ------------- ------------ ----------- -----------
Proved reserves as of December 31, 2003 335,804,862 80,759,903 242,321,275 67,015,693 93,483,587 13,744,210
Revisions of previous estimates 1 (3,306,705) (1,117,715) (1,619,531) 695,274 (1,687,174) (1,812,989)
Purchases of minerals in place 9,808,953 5,602,508 9,808,953 5,602,508 -- --
Sales of minerals in place (2,524,760) (44,803) (2,524,760) (44,803) -- --
Extensions, discoveries, and other
additions 2,205,670 830,111 2,205,670 830,111 -- --
Production (23,741,726) (5,762,796) (12,299,772) (4,959,740) (11,441,954) (803,056)
------------ ----------- ------------- ----------- ----------- -----------
Proved reserves as of December 31, 2004 318,246,294 80,267,208 237,891,835 69,139,043 80,354,459 11,128,165
============ =========== ============= =========== =========== ===========
Proved developed reserves: 2
December 31, 2001 181,651,578 23,759,574 167,401,736 20,393,142 14,249,842 3,366,432
December 31, 2002 233,514,572 35,928,395 149,731,562 26,530,112 83,783,010 9,398,283
December 31, 2003 210,119,927 45,525,366 138,173,341 38,767,983 71,946,586 6,757,383
December 31, 2004 193,310,761 42,037,852 140,549,052 36,628,873 52,761,709 5,408,979
1 Revisions of previous estimates are related to upward or downward variations
based on current engineering information for production rates, volumetrics, and
reservoir pressure. Additionally, changes in quantity estimates are affected by
the increase or decrease in crude oil, NGL, and natural gas prices at each
year-end. Proved reserves, as of December 31, 2004, were based upon prices in
effect at year-end. Our hedges at year-end 2004 consisted of oil and natural gas
price floors with strike prices mostly lower than the period end price and thus
would not materially affect prices used in these calculations. The weighted
average of 2004 year-end prices for total, domestic, and New Zealand were $5.16,
$5.87, and $3.07 per Mcf of natural gas, $41.07, $42.21, and $33.60 per barrel
of oil, and $25.48, $26.49 and $20.48 per barrel of NGL, respectively. This
compares to $4.56, $5.53, and $2.04 per Mcf of natural gas, $30.16, $30.88, and
$26.78 per barrel of oil, and $20.61, $21.81 and $14.10 per barrel of NGL as of
December 31, 2003, for total, domestic, and New Zealand, respectively. The
weighted average of 2002 year-end prices for total, domestic, and New Zealand
were $3.49, $4.23, and $1.48 per Mcf of natural gas, $29.27, $29.36, and $28.80
per barrel of oil, and $16.54, $17.30, and $12.24 per barrel of NGL,
respectively.
2 At December 31, 2004, 56% of our reserves were proved developed, compared to
59% at December 31, 2003, 60% at December 31, 2002, and 50% at December 31,
2001.
76
Standardized Measure of Discounted Future Net Cash Flows. The standardized
measure of discounted future net cash flows relating to proved oil and gas
reserves is as follows:
Year Ended December 31, 2004
--------------------------------------------------------
Total Domestic New Zealand
---------------- ---------------- ----------------
Future gross revenues $ 4,711,060,300 $ 4,122,705,861 $ 588,354,439
Future production costs (1,029,449,670) (819,035,166) (210,414,504)
Future development costs (480,093,684) (434,305,537) (45,788,147)
---------------- ---------------- ----------------
Future net cash flows before income taxes 3,201,516,946 2,869,365,158 332,151,788
Future income taxes (896,135,438) (866,598,544) (29,536,894)
---------------- ---------------- ----------------
Future net cash flows after income taxes 2,305,381,508 2,002,766,614 302,614,894
Discount at 10% per annum (840,436,013) (746,227,690) (94,208,323)
---------------- ---------------- ----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 1,464,945,495 $ 1,256,538,924 $ 208,406,571
================ ================ ================
Year Ended December 31, 2003
--------------------------------------------------------
Total Domestic New Zealand
---------------- ---------------- ----------------
Future gross revenues $ 3,805,349,886 $ 3,279,884,680 $ 525,465,206
Future production costs (831,430,479) (678,983,441) (152,447,038)
Future development costs (331,816,723) (301,874,087) (29,942,636)
---------------- ---------------- ----------------
Future net cash flows before income taxes 2,642,102,684 2,299,027,152 343,075,532
Future income taxes (729,624,048) (657,354,849) (72,269,199)
---------------- ---------------- ----------------
Future net cash flows after income taxes 1,912,478,636 1,641,672,303 270,806,333
Discount at 10% per annum (777,622,101) (678,769,827) (98,852,274)
---------------- ---------------- ----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 1,134,856,535 $ 962,902,476 $ 171,954,059
================ ================ ================
Year Ended December 31, 2002
--------------------------------------------------------
Total Domestic New Zealand
---------------- ---------------- ----------------
Future gross revenues $ 2,990,669,570 $ 2,578,435,576 $ 412,233,994
Future production costs (720,599,745) (612,094,088) (108,505,657)
Future development costs (224,792,520) (208,492,520) (16,300,000)
---------------- ---------------- ----------------
Future net cash flows before income taxes 2,045,277,305 1,757,848,968 287,428,337
Future income taxes (599,195,484) (512,966,321) (86,229,163)
---------------- ---------------- ----------------
Future net cash flows after income taxes 1,446,081,821 1,244,882,647 201,199,174
Discount at 10% per annum (609,212,030) (540,375,347) (68,836,683)
---------------- ---------------- ----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 836,869,791 $ 704,507,300 $ 132,362,491
================ ================ ================
The standardized measure of discounted future net cash flows from
production of proved reserves was developed as follows:
1. Estimates are made of quantities of proved reserves and the future
periods during which they are expected to be produced based on year-end economic
conditions.
2. The estimated future gross revenues of proved reserves are priced on the
basis of year-end prices, except in those instances where fixed and determinable
gas price escalations are covered by contracts limited to the price we
reasonably expect to receive.
3. The future gross revenue streams are reduced by estimated future costs
to develop and to produce the proved reserves, as well as asset retirement
obligation costs, net of salvage value, based on year-end cost estimates and the
estimated effect of future income taxes.
77
4. Future income taxes are computed by applying the statutory tax rate to
future net cash flows reduced by the tax basis of the properties, the estimated
permanent differences applicable to future oil and gas producing activities, and
tax carry forwards.
The estimates of cash flows and reserves quantities shown above are based
on year-end oil and gas prices for each period. Our hedges at year-end 2004
consisted mainly of crude oil and natural gas price floors with strike prices
lower than the period end price and thus did not materially affect prices used
in these calculations. Subsequent changes to such year-end oil and gas prices
could have a significant impact on discounted future net cash flows. Under
Securities and Exchange Commission rules, companies that follow the full-cost
accounting method are required to make quarterly Ceiling Test calculations using
hedge adjusted prices in effect as of the period end date presented (see Note 1
to the consolidated financial statements). Application of these rules during
periods of relatively low oil and gas prices, even if of short-term seasonal
duration, may result in non-cash write-downs.
The standardized measure of discounted future net cash flows is not
intended to present the fair market value of our oil and gas property reserves.
An estimate of fair value would also take into account, among other things, the
recovery of reserves in excess of proved reserves, anticipated future changes in
prices and costs, an allowance for return on investment, and the risks inherent
in reserves estimates.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
Year Ended December 31,
-------------------------------------------------------
2004 2003 2002
----------------- ----------------- ---------------
Beginning balance $ 1,134,856,535 $ 836,869,791 $ 454,557,905
----------------- ----------------- ---------------
Revisions to reserves proved in prior years--
Net changes in prices, and production costs 398,333,372 218,104,882 418,531,747
Net changes in future development costs (117,672,270) (108,603,152) (44,641,133)
Net changes due to revisions in quantity
estimates (12,754,357) 48,194,999 2,582,633
Accretion of discount 152,715,946 116,136,717 60,298,619
Other 49,111,385 (57,822,716) (88,675,455)
----------------- ----------------- ---------------
Total revisions 469,734,076 216,010,730 348,096,411
New field discoveries and extensions, net of future
production and development costs 30,609,517 243,183,114 190,461,371
Purchases of minerals in place 118,575,886 1,019,290 76,538,437
Sales of minerals in place (7,339,601) (13,660,012) (5,769,642)
Sales of oil and gas produced, net of production
costs (239,669,623) (158,165,836) (99,698,403)
Previously estimated development costs incurred 98,924,021 77,404,994 48,752,814
Net change in income taxes (140,745,316) (67,805,536) (176,069,102)
----------------- ----------------- ----------------
Net change in standardized measure of discounted
future net cash flows 330,088,960 297,986,744 382,311,886
----------------- ----------------- ---------------
Ending balance $ 1,464,945,495 $ 1,134,856,535 $ 836,869,791
================= ================= ===============
78
Quarterly Data (Unaudited). The following table presents summarized
quarterly financial information for the years ended December 31, 2003 and 2004:
Income
Before
Income
Taxes, Income Basic EPS Diluted EPS
and Before Income Before Income Before Basic Diluted
Change in Change in Change In Change In EPS EPS
Accounting Accounting Net Accounting Accounting Net Net
Revenues Principle Principle Income Principle Principle Income Income
------------ ------------ ------------ ------------ ---------------- ----------------- -------- ---------
2003:
First $ 53,499,993 $ 16,223,744 $ 10,484,937 $ 6,108,085 $ 0.38 $ 0.38 $ 0.22 $ 0.22
Second 50,717,529 11,073,804 7,221,426 7,221,426 0.26 0.26 0.26 0.26
Third 51,552,522 11,153,368 7,062,625 7,062,625 0.26 0.26 0.26 0.26
Fourth 53,130,939 12,288,262 9,501,676 9,501,676 0.35 0.34 0.35 0.34
------------ ------------ ------------ ------------
Total $208,900,983 $ 50,739,178 $ 34,270,664 $ 29,893,812 $ 1.25 $ 1.24 $ 1.09 $ 1.08
============ ============ ============ ============
2004:
First $ 65,355,730 $ 20,086,182 14,587,854 $ 14,587,854 $ 0.53 $ 0.52 $ 0.53 $ 0.52
Second 71,043,735 20,001,147 12,897,927 12,897,927 0.46 0.46 0.46 0.46
Third 74,942,751 19,472,596 14,130,717 14,130,717 0.51 0.50 0.51 0.50
Fourth 98,934,558 41,880,317 26,834,419 26,834,419 0.96 0.93 0.96 0.93
------------ ------------ ------------ ------------
Total $310,276,774 $101,440,242 $ 68,450,917 $ 68,450,917 $ 2.46 $ 2.41 $ 2.46 $ 2.41
============ ============ ============ ============
There were no extraordinary items in 2003 or 2004. As described in Note 4
to the consolidated financial statements, in 2004 we incurred debt retirement
costs relating to the repurchase of our 10-1/4% senior subordinated notes due
2009 totaling $9.5 million. Debt retirement costs totaled $2.7 million, $6.8
million and less than $0.1 million in the second, third and fourth quarters of
2004, respectively.
The sum of the individual quarterly net income per common share amounts may
not agree with year-to-date net income per common share as each quarterly
computation is based on the weighted average number of common shares outstanding
during that period. In addition, certain potentially dilutive securities were
not included in certain of the quarterly computations of diluted net income per
common share because to do so would have been antidilutive.
79
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
We have had no changes in or disagreements with our independent accountants
since our Board of Directors' June 12, 2002 appointment, based upon the
recommendation of our Audit Committee, of Ernst & Young LLP as Swift's
independent auditors for the fiscal year ended December 31, 2002, replacing
Arthur Andersen LLP as our independent auditors. That change was reported by
Swift in a Current Report on Form 8-K dated June 12, 2002, filed with the SEC on
June 18, 2002.
Item 9A. Controls and Procedures
The Company's chief executive officer and chief financial officer have
evaluated the Company's disclosure controls and procedures, as defined in Rules
13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the "Exchange
Act") as of the end of the period covered by the report. Based on that
evaluation, they have concluded that such disclosure controls and procedures are
effective in alerting them on a timely basis to material information relating to
the Company required under the Exchange Act to be disclosed in this report.
There were no significant changes in the Company's internal controls that could
significantly affect such controls subsequent to the date of their evaluation.
Management's Report On Internal Control Over Financial Reporting as of
December 31, 2004 is included in Item 8. Financial Statements and Supplementary
Data. The Report of Independent Registered Public Accounting Firm on Internal
Control Over Financial Reporting is also included in Item 8.
Item 9B. Other Information
None
80
PART III
Item 10. Directors and Executive Officers of the Registrant
The information required under Item 10 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 10, 2005, annual shareholders'
meeting is incorporated herein by reference.
Item 11. Executive Compensation
The information required under Item 11 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 10, 2005, annual shareholders'
meeting is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
The information required under Item 12 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 10, 2005, annual shareholders'
meeting is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions
The information required under Item 13 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 10, 2005, annual shareholders'
meeting is incorporated herein by reference.
Item 14. Principal Accountant Fees and Services
The information required under Item 14 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 10, 2005, annual shareholders'
meeting is incorporated by reference.
81
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) 1. The following consolidated financial statements of Swift Energy Company
together with the report thereon of Ernst & Young LLP dated March 11, 2005,
and the data contained therein are included in Item 8 hereof:
Management's Report on Internal Control Over
Financial Reporting..........................................45
Report of Independent Registered Public Accounting Firm on
Internal Control Over Financial Reporting...................46
Report of Independent Registered Public Accounting Firm........47
Consolidated Balance Sheets....................................48
Consolidated Statements of Income..............................49
Consolidated Statements of Stockholders' Equity................50
Consolidated Statements of Cash Flows..........................51
Notes to Consolidated Financial Statements.....................52
2. Financial Statement Schedules
Report of Independent Registered Public Accounting Firm on Internal
Control Over Financial Reporting
[None]
3. EXHIBITS
3(a).1 Amended and Restated Articles of Incorporation of
Swift Energy Company.
3(b).9 Second Amended and Restated Bylaws of Swift Energy
Company, as amended through November 5, 2002.
4(a).1.2 Indenture dated as of April 16, 2002, between Swift
Energy Company and Bank One, N.A., as Trustee.
4(a).2.2 First Supplemental Indenture dated as of April 16,
2002, between Swift Energy Company and Bank One,
N.A., including the form of 9 3/8% Senior
Subordinated Notes due 2012.
4(a).3.12 Indenture dated as of June 23, 2004, between Swift
Energy Company and Wells Fargo Bank, National
Association, as Trustee.
4(a).4.12 First Supplemental Indenture dated as of June 23,
2004, between Swift Energy Company and Wells Fargo
Bank, National Association, as Trustee, including the
form of 7 5/8% Senior Notes.
10.1.13 Indemnity Agreement dated July 8, 1988, between Swift
Energy Company and A. Earl Swift (plus schedule of
other persons with whom Indemnity Agreements have
been entered into).
10.2.3 + Amended and Restated Swift Energy Company 1990
Nonqualified Stock Option Plan, as of May 1997.
10.3.3 + Amended and Restated Swift Energy Company 1990 Stock
Compensation Plan, as of May 1997.
10.4.4 + Amendment to the Swift Energy Company 1990 Stock
Compensation Plan, as of May 9, 2002.
82
10.5.4 + Swift Energy Company 2001 Omnibus Stock Compensation
Plan.
10.6.5 + Amended and Restated Employment Agreement dated as of
November 15, 2000 between Swift Energy Company and
A.Earl Swift.
10.7.1 + Amended and Restated Employment Agreement dated as of
May 9, 2001 between Swift Energy Company and
Terry E.Swift.
10.8.1 + Amended and Restated Employment Agreement dated as of
May 9, 2001 between Swift Energy Company and
James M.Kitterman.
10.9.1 + Amended and Restated Employment Agreement dated as of
May 9, 2001 between Swift Energy Company and
Bruce H. Vincent.
10.10.1 + Amended and Restated Employment Agreement dated as of
May 9, 2001 between Swift Energy Company and
Joseph A. D'Amico.
10.11.1 + Employment Agreement dated as of May 9, 2001 between
Swift Energy Company and Victor R. Moran.
10.13.1 + Amended and Restated Employment Agreement dated as of
May 9, 2001 between Swift Energy Company and
Alton D. Heckaman, Jr.
10.14.5 + Fourth Amended and Restated Agreement and Release,
by and between Swift Energy Company and Virgil Neil
Swift, dated November 20, 2000.
10.15.14+* Employee Stock Purchase Plan
10.16 +* Description of non-employee directors' compensation
arrangements.
10.17 +* Forms of agreements for grant of incentive and
non-qualified stock options and forms of agreement
for grant of restricted stock under Swift Energy 2001
Omnibus Stock Compensation Plan.
10.18.6 Amended and Restated Rights Agreement between Swift
Energy and American Stock Transfer & Trust Company,
dated March 31, 1999.
10.19.7 Amended and Restated Credit Agreement among Swift
Energy Company and Bank One, N.A. as administrative
agent, CIBC Inc. as syndication agent and Credit
Lyonnais New York Branch and Societe Generale as
documentation agents and the lenders signatory hereto
dated September 28, 2001.
10.20.8 First Amendment to Amended and Restated Credit
Agreement, effective January 25, 2002 among Swift
Energy Company, as Borrower, Bank One, NA as
Administrative Agent, CIBC Inc. as Syndication Agent,
Credit Lyonnais, New York Branch as Documentation
Agent, Societe Generale as Documentation Agent and
The Lenders Signatory Hereto and Banc One Capital
Markets, Inc. as Sole Lead Arranger and Sole Book
Runner.
10.21.8 Second Amendment to Amended and Restated Credit
Agreement, effective April 5, 2002 among Swift Energy
Company, as Borrower, Bank One, NA as Administrative
Agent, CIBC Inc. as Syndication Agent, Wells Fargo
Bank (Texas), National Association as Syndication
Agent, Credit Lyonnais, New York Branch as
Documentation Agent, Societe Generale as
Documentation Agent and The Lenders Signatory Hereto
and Banc One Capital Markets, Inc. as Sole Lead
Arranger and Sole Book Runner.
83
10.22.11 First Amended and Restated Credit Agreement effective
as of June 29, 2004, among Swift Energy Company and
Bank One, NA as Administrative Agent, Wells Fargo
Bank, National Association as Syndication Agent, BNP
Paribas, as Syndication Agent, Caylon, as
Documentation agent, Societe Generale, as
Documentation Agent and the Lenders Signatory Hereto
and Banc One Capital Markets, Inc., as Sole Lead
Arranger and Sole Book Runner.
10.23.10 Consulting Agreement dated as of October 13, 2003
between Swift Energy Company and Raymond O. Loen.
10.24.11 Eighth Amendment to Lease Agreement between Swift
Energy Company and Greenspoint Plaza Limited
Partnership dated as of June 30, 2004.
10.25+* Description of executive officers' compensation
arrangements.
12 * Swift Energy Company Ratio of Earnings to Fixed
Charges.
13 * Incorporated by reference from Swift Energy Company
Annual Report on Form 10-K for the fiscal year ended
December 31, 2002, File No. 1-8754.
21 * List of Subsidiaries of Swift Energy Company.
23(a) * The consent of H.J. Gruy and Associates, Inc.
23(b) * Consent of Ernst & Young LLP as to incorporation by
reference regarding Forms S-8 and S-3 Registration
Statements.
31.1 * Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 * Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
32 * Certification of Chief Executive Officer and Chief
Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
99.1 * The summary of H.J. Gruy and Associates, Inc. report,
dated January 27, 2005.
- --------------------------------------------------------------------------------
1. Incorporated by reference from Swift Energy Company Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 2001, File No.
1-8754.
2. Incorporated by reference from Swift Energy Company Report on Form 8-K
dated April 16, 2002, File No. 1-8754.
3. Incorporated by reference from Swift Energy Company definitive proxy
statement for annual shareholders meeting filed April 14, 1997, File
No. 1-8754.
4. Incorporated by reference from Registration Statement No. 333-67242 on
Form S-8 filed on August 10, 2001.
84
5. Incorporated by reference from Swift Energy Company Annual Report on
Form 10-K for the fiscal year ended December 31, 2000, File No. 1-8754.
6. Incorporated by reference from Swift Energy Company Amendment No. 1 to
Form 8-A filed April 7, 1999.
7. Incorporated by reference from Swift Energy Company Quarterly Report on
Form 10-Q for the quarterly period ended September 30-2001, Form No.
1-8754.
8. Incorporated by reference from Swift Energy Company Quarterly Report on
Form 10-Q for the quarterly period ended March 31, 2002, File No.
1-8754.
9. Incorporated by reference from Swift Energy Company Quarterly Report on
Form 10-Q for the quarterly period ended March 31, 2003. File No.
1-8754.
10. Incorporated by reference from Swift Energy Company Annual Report on
Form 10-K for the fiscal year ended December 31, 2003, File No. 1-8754.
11. Incorporated by reference from Swift Energy Company Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 2004, File No.
1-8754.
12. Incorporated by reference from Swift Energy Company Quarterly Form 8-K
filed with the SEC on June 25, 2004, File No. 1-8754.
13. Incorporated by reference from Swift Energy Company Annual Report on
Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8754.
14. Incorporated by reference from Swift Energy Company Annual Report on
Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8754.
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
85
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant, Swift Energy Company, has duly caused this report
to be signed on its behalf by the undersigned, thereunto duly authorized.
SWIFT ENERGY COMPANY
By :
------------------------------
A. Earl Swift
Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant, Swift Energy Company, and in the capacities and on the dates
indicated:
Signatures Title Date
----------- ------ -----
- -------------------------- Chairman of the Board March 15, 2005
A. Earl Swift
Director
- -------------------------- Chief Executive Officer March 15, 2005
Terry E. Swift
Executive Vice-President
- -------------------------- Principal Financial Officer March 15, 2005
Alton D. Heckaman Jr.
Controller
- -------------------------- Principal Accounting Officer March 15, 2005
David W. Wesson
86
- ------------------------- Director March 15, 2005
G. Robert Evans
- ------------------------- Director March 15, 2005
Raymond E. Galvin
- ------------------------- Director March 15, 2005
Greg Matiuk
- ------------------------- Director March 15, 2005
Henry C. Montgomery
- ------------------------- Director March 15, 2005
Clyde W. Smith, Jr.
- ------------------------- Director March 15, 2005
Virgil N. Swift
- ------------------------- Director March 15, 2005
Deanna L. Cannon
87
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
EXHIBITS
TO
FORM 10-K REPORT
FOR THE
YEAR ENDED DECEMBER 31, 2004
SWIFT ENERGY COMPANY
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060
88
EXHIBIT INDEX
10.16 Description of non-employee directors' compensation
arrangements.
10.17 Forms of agreements for grant of incentive and nonqualified
stock options and forms of agreement for grant of restricted
stock under Swift Energy 2001 Omnibus Stock Compensation
Plan.
10.25 Description of executive officers' compensation
arrangements.
12 Swift Energy Company Ratio of Earnings to Fixed Charges.
21 List of Subsidiaries of Swift Energy Company.
23(a) The consent of H.J. Gruy and Associates, Inc.
23(b) Consent of Ernst & Young LLP as to incorporation by
reference regarding Forms S-8 and S-3 Registration
Statements.
31.1 Certification of Chief Executive Officer pursuant to Section
302 of the Sarbanes-Oxley Act of 2003.
31.2 Certification of Chief Financial Officer pursuant to Section
3-2 of the Sarbanes-Oxley Act of 2002.
32 Certification of Chief Executive Officer and Chief
Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
99.1 The summary of H.J. Gruy and Associates, Inc. report, dated
January 27, 2005.
89
Exhibit 10.16
Description of Non-Employee Director Compensation
Effective October 1, 2004, as a result of significantly increased duties
and responsibilities for the entire Board of Directors and its committees, the
cash compensation of non-employee directors was increased to a base of $40,000
payable in cash, with an additional $5,000 for serving on one or more committees
of the Board of Directors, as compared to $34,750 and $ 5,000, respectively,
earned per year by non-employee directors prior to that time. The Chairman of
the Audit Committee will receive an additional $12,000 in cash for a minimum of
four meetings annually. The Chairmen for each of the Corporate Governance and
Compensation Committees will receive an additional $6,000 in cash for a minimum
of two meetings annually. All of these amounts are to be paid over the course of
a year in four equal installments.
Since 1990, non-employee directors upon joining the Board have been
entitled to receive stock options to purchase 10,000 shares of common stock, and
on an annual basis on the day after the Annual Meeting of Shareholders, options
to purchase an additional 5,000 shares of common stock, with each director
entitled to hold options covering no more than 66,000 shares at any one time. A
new director is not entitled to receive the annual grant if his or her initial
grant was within 11 months of the initial grant of options. All such stock
options are granted at the current market price for the Company's common stock
on the date of grant.
At the date of this filing, the Compensation Committee of the Board is
reviewing equity compensation of non-employee board members, any changes in
which would be submitted to shareholders for their approval under New York Stock
Exchange rules.
90
Exhibit 10.17
INCENTIVE STOCK OPTION AGREEMENT
2001 Omnibus Stock Compensation Plan
((Date))
Grant of Options. Swift Energy Company hereby grants to ((NAME)) (the
"Optionee") incentive stock options for a total of ((AMOUNT)) (((AMOUNT1>>)
shares of the Company's common stock, par value of $.01 per share (the
"Options"), exercisable at the price and upon the terms and conditions set forth
hereinbelow, and subject to any adjustments made pursuant to Section 12 of the
Plan.
Approval of Counsel Required for Issuance of Common Stock. No share of
Common Stock shall be issued pursuant to the exercise of the Options unless
counsel for the Company shall be satisfied that such issuance will be in
compliance with applicable Federal and state securities laws.
Options Subject to Plan. The Options are granted as Incentive Stock Options
(subject to the $100,000 per calendar year limitations contained in Section 6(j)
of the Plan, as such limit may be changed by the Code) pursuant to the Company's
2001 Omnibus Stock Compensation Plan (the "Plan"), and are in all respects
subject to the terms, provisions, conditions and restrictions of the Plan. A
copy of the Plan is attached hereto as Exhibit A and is incorporated herein by
reference. In the event of any conflict between this instrument and the Plan,
the Plan shall control.
Defined Terms. Except as otherwise defined herein, capitalized terms used
in this instrument shall have the meanings ascribed to such terms in the Plan.
Date of Grant. The Options are granted as of the date first set forth
above.
Exercise Price. Each Option shall have an exercise price for the related
share of Common Stock of $_______, which is not less than the Fair Market Value
of each share of Common Stock calculated in accordance with Section 2(j) of the
Plan, or, if the Optionee is a Ten Percent Shareholder, is not less than 110% of
such Fair Market Value. The exercise price is subject to adjustment pursuant to
Section 12 of the Plan.
Vesting of Options. The Options shall be exercisable in installments in
accordance with the following table, except as otherwise provided in the Plan:
Date First Exercisable Number of Options
DATE ((NUMBER))
DATE ((NUMBER))
DATE ((NUMBER))
DATE ((NUMBER))
DATE ((NUMBER))
----------
Total: ((NUMBER1))
Option Period. Each Option may be exercised at any time between the date at
which it becomes exercisable and ten years from the Date of Grant, or five years
from the Date of Grant if Optionee is a Ten Percent Shareholder, inclusive of
91
such dates, except that in the event of the Optionee's death, or his or her
Disability (defined under Section 2 of the Plan), or if the Optionee's
employment by the Company is terminated for any reason, or if there is a Change
in Control of the Company, then the provisions of Sections 10(a), 10(c) and 13
of the Plan, respectively, shall govern the option period.
Method of Exercise. The Options are exercisable in accordance with the
procedures, but subject to all conditions and restrictions, set forth in the
Plan.
Limitation on Exercise. The aggregate Fair Market Value (determined as of
the date first set forth above) of the number of shares of Common Stock with
respect to which Options are exercisable for the first time by the Optionee
during any calendar year as "Incentive Stock Options" under Section 422 of the
code shall not exceed $100,000, or such other limit as may be required by the
Code.
Transferability. The Options are not assignable or transferable except by
will or the laws of descent and distribution.
SWIFT ENERGY COMPANY
By:_________________________________
The Optionee acknowledges receipt of a copy of the Plan, represents that he
is familiar with the terms and provisions thereof, and hereby accepts the
Options evidenced hereby subject to all the terms, provisions, conditions and
restrictions of the Plan.
----------------------------------------
Printed Name: ___________________________
92
NONQUALIFIED STOCK OPTION AGREEMENT
2001 Omnibus Stock Compensation Plan
Date of Grant
Grant of Options. Swift Energy Company hereby grants to ((NAME)) (the
"Optionee") NonQualified stock options for a total of ((AMOUNT)) (((AMOUNT1)))
shares of the Company's common stock, par value of $.01 per share (the
"Options"), exercisable at the price and upon the terms and conditions set forth
hereinbelow, and subject to any adjustments made pursuant to Section 12 of the
Plan.
Approval of Counsel Required for Issuance of Common Stock. No share of
Common Stock shall be issued pursuant to the exercise of the Options unless
counsel for the Company shall be satisfied that such issuance will be in
compliance with applicable Federal and state securities laws.
Options Subject to Plan. The Options are granted as NonQualified Stock
Options pursuant to the Company's 2001 Omnibus Stock Compensation Plan (the
"Plan"), and are in all respects subject to the terms, provisions, conditions
and restrictions of the Plan. A copy of the Plan is available upon request and
is incorporated herein by reference. In the event of any conflict between this
instrument and the Plan, the Plan shall control.
Defined Terms. Except as otherwise defined herein, capitalized terms used
in this instrument shall have the meanings ascribed to such terms in the Plan.
Date of Grant. The Options are granted as of the date first set forth
above.
Exercise Price. Each Option shall have an exercise price for the related
share of Common Stock of $________, which is not less than the Fair Market Value
of each share of Common Stock calculated in accordance with Section 2(j) of the
Plan. The exercise price is subject to adjustment pursuant to Section 12 of the
Plan.
Vesting of Options. The Options shall be exercisable in installments in
accordance with the following table, except as otherwise provided in the Plan:
Date First Exercisable Number of Options
DATE ((NUMBER))
DATE ((NUMBER))
DATE ((NUMBER))
DATE ((NUMBER))
DATE ((NUMBER))
-----------
Total: ((NUMBER1))
Option Period. Each Option may be exercised at any time between the date at
which it becomes exercisable and ten years from the Date of Grant, inclusive of
such dates, except that in the event of the Optionee's death, or his or her
Disability (defined under Section 2 of the Plan), or if there is a Change in
Control of the Company, then the provisions of Sections 10(a), and 13 of the
Plan, respectively, shall govern the option period.
Method of Exercise. The Options are exercisable in accordance with the
procedures, but subject to all conditions and restrictions, set forth in the
Plan.
93
Transferability. The Options are not assignable or transferable except by
will or the laws of descent and distribution.
SWIFT ENERGY COMPANY
By:_________________________________
The Optionee acknowledges receipt of a copy of the Plan, represents that he
is familiar with the terms and provisions thereof, and hereby accepts the
Options evidenced hereby subject to all the terms, provisions, conditions and
restrictions of the Plan.
--------------------------------------
Printed Name: ________________________
94
SWIFT ENERGY COMPANY
RESTRICTED STOCK AWARD AGREEMENT
This RESTRICTED STOCK AWARD AGREEMENT (the "Agreement") is effective as of
the ____ day of ______________, 200__, by and between SWIFT ENERGY COMPANY, a
Texas corporation (the "Company") and ____________________, individually
("Participant"), in connection with the Participant's past and future employment
with the Company.
A. Award. The Company hereby grants to Participant a restricted stock
award covering ________________ shares (the "Shares") of common stock, par
value $.01 per share, of the Company according to the terms and conditions
set forth herein and in the Company's 2001 Omnibus Stock Compensation Plan
(the "Plan") and shall constitute a Restricted Stock Grant under Section 8
of the Plan. A copy of the Plan has been furnished or made available to the
Participant.
Participant hereby acknowledges (i) opportunity to review the Plan, (ii)
Participant's understanding of the terms and provisions of the award and the
Plan, and (iii) Participant's understanding that, by its signature below,
Participant is agreeing to be bound by all of the terms and provisions of this
award and the Plan.
Without limitation, Participant agree to accept as binding, conclusive and
final all decisions or interpretations (including, without limitation, all
interpretations of the meaning of provisions of the Plan, or award, or both) of
the Compensation Committee of the Company's Board of Directors upon any
questions arising under the Plan, or this award, or both.
B. Restrictions on Transfer. Until the award covering specified Shares
vests pursuant to Section C below, the Shares may not be transferred,
pledged, alienated, attached or otherwise encumbered, and any purported
pledge, alienation, attachment or encumbrance shall be void and
unenforceable against the Company, and no attempt to transfer the unvested
portion of the award covering any of the Shares or the Shares, whether
voluntary or involuntary, by operation of law or otherwise, shall vest the
purported transferee with any interest or right in or with respect to such
award or Shares.
C. Vesting. Except as otherwise provided in this Agreement, the
restrictions set out in Section B above shall lapse as to twenty percent
(20%) of the Shares and the award covering such twenty percent (20%) of the
Shares shall vest on February 8, 2006 (the "Vesting Date"), and twenty
percent (20%) of the Shares shall vest on each anniversary of the Vesting
Date thereafter until all of the Shares are fully vested unless earlier
forfeited pursuant to the terms of Section D of this Agreement.
D. Forfeiture. All of Participant's rights to all of the unvested
portion of the award covering any of the Shares shall be immediately and
irrevocably forfeited if Participant ceases to be an employee of the
Company or any affiliate of the Company prior to vesting of all or any part
of the Shares pursuant to Section C of this Agreement, whether or not
employment is terminated with or without cause, unless the Compensation
Committee shall determine otherwise. Upon forfeiture, Participant will no
longer have any rights relating to unvested Shares, including the right to
vote such Shares and the right to receive dividends, if any, declared on
such Shares.
E. Termination. This Agreement shall terminate (i) immediately without
any notice upon termination of Participant's employment, with or without
cause, or (ii) when all of the Shares are fully vested hereunder.
F. Legends; Certificates. Participant agrees that each certificate
representing unvested Shares will bear any legend required by law and a
legend reading substantially as follows:
95
The securities represented by this certificate are subject to the provisions of
a Restricted Stock Award Agreement with Swift Energy Company effective as of
September 1, 2004. None of the securities represented by this certificate may be
transferred, pledged, alienated, attached or otherwise encumbered, and any
purported transfer, pledge, alienation, attachment or encumbrance shall be void
and unenforceable against the Company, and no attempt to transfer, pledge,
alienate, attach or encumber such securities, whether voluntary or involuntary,
by operation of law or otherwise, shall vest the purported transferee, pledgee
or the like with any interest or right in or with respect to such securities.
Stock certificates shall be issued in respect of each twenty percent (20%)
vesting block of the Shares in the name of Participant. Participant agrees that
it shall deliver to the Company duly executed stock powers in blank for each
certificate and that the Company shall hold all certificates representing
unvested Shares accompanied by the executed stock power in escrow until such
time such Shares represented by the certificate become vested. After vesting and
upon delivery of written instructions by Participant, the Company shall remove
the legend and re-issue a certificate to be delivered to Participant in
accordance with Participant's written instructions.
Miscellaneous.
1. Plan Provisions Control. In the event that any provision of the
Agreement conflicts with or is inconsistent in any respect with the
terms of the Plan, the terms of the Plan shall control.
2. No Right to Retention. The issuance of the Shares shall not be
construed as giving Participant the right to be employed or continue to
be employed by the Company or an affiliate of the Company, nor will it
affect in any way the right of the Company or an affiliate of the
Company to terminate such employment or position at any time, with or
without cause, pursuant to the terms of an employment agreement, if
any, or otherwise in accordance with applicable law. In addition, the
Company or an affiliate of the Company may at any time terminate any
employment agreement free from any liability or any claim under the
Plan or this Agreement. Nothing in this Agreement shall confer on any
person any legal or equitable right against the Company or any
affiliate of the Company, directly or indirectly, or give rise to any
cause of action at law or in equity against the Company or an affiliate
of the Company. The award covering the Shares granted hereunder shall
not form any part of the consideration, compensation of fees of
Participant for purposes of termination indemnities, irrespective of
the reason for termination of any employment agreement. Under no
circumstances shall Participant be entitled to any compensation for any
loss of any right or benefit under the Agreement or Plan which such
Participant might otherwise have enjoyed but for termination of an
employment agreement, whether such compensation is claimed by way of
damages for breach of contract or otherwise. By entering into this
Agreement, Participant shall participate in the Plan and be deemed to
have accepted all the conditions of the Plan and the terms and
conditions of any rules and regulations adopted by the Committee (as
defined in the Plan) and shall be fully bound thereby.
3. Governing Law. The validity, construction and effect of the
Plan and this Agreement, and any rules and regulations relating to the
Plan and this Agreement, shall be determined in accordance with the
internal laws, and not the law of conflicts, of the State of Texas.
4. Unenforceability. If any provision of this Agreement is or
becomes or is deemed to be invalid, illegal or unenforceable in any
jurisdiction or would disqualify the Agreement under any applicable
law, such provision shall be construed or deemed amended to conform to
applicable laws, or if it cannot be so construed or deemed amended
without materially altering the purpose or intent of the Plan or the
Agreement, such provision shall be stricken as to such jurisdiction or
the Agreement, and the remainder of the Agreement shall remain in full
force and effect.
5. No Trust or Fund Created. Neither the Plan nor the Agreement
shall create or be construed to create a trust or separate fund of any
kind or a fiduciary relationship between the Company or any affiliate
of the Company and Participant or any other person.
96
6. Headings. Headings are given to the Sections and subsections of
the Agreement solely as a convenience to facilitate reference. Such
headings shall not be deemed in any way material or relevant to the
construction or interpretation of the Agreement or any provision
thereof.
IN WITNESS WHEREOF, the Company and Participant have executed this Agreement
effective as of the date set forth in the first paragraph.
SWIFT ENERGY COMPANY
By:
-----------------------------
Name:
---------------------------
PARTICIPANT
--------------------------------
Print Name:
---------------------
Title:
--------------------------
97
Exhibit 10.25
Description of Executive Officer Compensation
Executive officer compensation is set by the Compensation Committee of
Swift's Board of Directors on an annual basis, with base compensation set at the
Committee's discretion without any specified weighting or formula, although
individual performance and responsibility, along with compensation by peer
companies and Swift's performance are typically factors evaluated by the
Compensation Committee. Executive officer compensation is determined using the
same system and methods applicable to compensation of all officers.
Annual incentive bonuses for 2004 and prior periods have been paid in cash
and also were determined by the Compensation Committee. Bonus awards for 2004
were based upon the Company reaching specified pre-determined growth targets in
four areas, each with a one-sixth weighting: earnings per share, cash flow per
share, volumes of proved oil and gas reserves and volumes of probable oil and
gas reserves. The other factor with a one-third weighting was subjective, and
measured an individual executive's personal performance based upon individual
goals set at the beginning of the year. Other than the subjective analysis of
individual performance, success was measured for all executive officers by the
same factors. Success in these five areas was then measured against maximum
target bonus ranges as percentages of base salaries.
For 2005, the four objective factors have been expanded to additionally
include: net margin per oil and gas equivalent produced, production growth,
controllable lease operating expenses per oil and gas equivalent produced and
finding costs per oil and gas equivalent reserves added, and the former two
reserve growth categories have been combined to measure growth in proved and
probable reserves taken together. The application of these seven factors has
also been modified so that different factors and different percentages of base
salary apply to different executive officers, with each executive officer given
different weightings of these seven factors to measure performance. The
one-third weighting based upon individual performance remains in place for 2005
and will continue to be monitored against individual goals determined at the
beginning of the year.
Long-term incentives, currently consisting of stock options and/or
restricted stock, are awarded by the Compensation Committee historically toward
the end of each year, although beginning in 2005 long-term incentives are
anticipated to be awarded early in the following year, using different
percentages of base salary for different level executive officers, with stock
options valued using a Black-Scholes model, and restricted stock valued based
upon prevailing market prices at the date of grant. Stock options to executive
officers typically contain the same vesting provisions as stock options granted
to all employees, with the exception of accelerated vesting provisions in
specified circumstances for those executive and other officers with employment
agreements. The only time restricted stock has been granted was in late 2004,
with 20% to vest over 5 years, with the first 20% to vest February 8, 2006 and
an additional 20% to vest on each February 7 thereafter until fully vested. It
is currently anticipated that restricted stock awards will continue to be made
in the future.
98
Exhibit 12
SWIFT ENERGY COMPANY
RATIO OF EARNINGS TO FIXED CHARGES
Years Ended December 31,
-----------------------------------------------------------
2002 2003 2004
GROSS G&A 26,074,408 29,803,405 37,850,281
NET G&A 10,564,849 14,097,066 17,787,125
INTEREST EXPENSE, NET 23,274,969 27,268,524 27,643,108
RENTAL & LEASE EXPENSE 1,923,451 2,173,313 2,375,598
INCOME BEFORE INCOME TAXES AND CUMULATIVE 18,408,289 50,739,178 101,440,242
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE
CAPITALIZED INTEREST 6,973,480 6,835,983 6,489,763
DEPLETED CAPITALIZED INTEREST 215,433 548,996 679,709
CALCULATED DATA
EXPENSED OR NON-CAPITAL G&A (%) 40.52% 47.30% 46.99%
NON-CAPITAL RENT EXPENSE 779,345 1,027,981 1,116,374
1/3 NON-CAPITAL RENT EXPENSE 259,782 342,660 372,125
FIXED CHARGES 30,508,231 34,447,167 34,504,996
EARNINGS 42,158,473 78,899,358 130,135,183
1.38 2.29 3.77
RATIO OF EARNINGS TO FIXED CHARGES (12/11)
For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expense, capitalized interest, amortization of debt
issuance costs and discounts, and that portion of non-capitalized rental expense
deemed to be the equivalent of interest. Earnings represents income before
income taxes and cumulative effect of change in accounting principle before
interest expense, net, depleted capitalized interest and that portion of rental
expense deemed to be the equivalent of interest.
99
Exhibit 21
Swift Energy Company - Significant Subsidiaries
Swift Energy International, Inc.
Swift Energy New Zealand Limited
Southern Petroleum (NZ) Exploration Limited
100
Exhibit 23 (a)
CONSENT OF H.J. GRUY AND ASSOCIATES, INC.
We hereby consent to the use of the name H.J. Gruy and Associates, Inc. and of
references to H. J. Gruy and Associates, Inc. and to the inclusion of and
references to our report, or information contained therin, dated January 27,
2005, prepared for Swift Energy Company in the Annual Report on Form 10-K of
Swift Energy Company for the filing dated on or about March 15, 2005.
H.J. GRUY AND ASSOCIATES, INC.
by: ______________________________
Marilyn Wilson
President & Chief Operating Officer
Houston, Texas
March 14, 2005
101
Exhibit 23 (b)
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in the Registration Statements on
Form S-8 (Nos. 333-112042, 333-67242, 333-45354, and 33-80228), pertaining to
the Swift Energy Company 2001 Omnibus Stock Compensation Plan, Swift Energy
Company 1990 Stock Compensation Plan (Amended and Restated as of May 13, 1997),
Swift Energy Company 1990 Nonqualified Stock Option Plan (Amended and Restated
as of May 13, 1997), Swift Energy Company Employee Savings Plan, Swift Energy
Company Employee Stock Purchase Plan, and in the Registration Statements on Form
S-3 (Nos. 333-112041 and 333-12831) of Swift Energy Company and in the related
Prospectus and pertaining to the Swift Energy Company Employee Stock Ownership
Plan of our reports dated March 11, 2005, with respect to the consolidated
financial statements of Swift Energy Company, Swift Energy Company management's
assessment of the effectiveness of internal control over financial reporting,
and the effectiveness of internal control over financial reporting of Swift
Energy Company, included in this Annual Report onForm 10-K for the year ended
December 31, 2004.
/s/ ERNST & YOUNG LLP
Houston, Texas
March 11, 2005
102
Exhibit 31.1
CERTIFICATION
I, Terry E. Swift, certify that:
1. I have reviewed this Annual Report on Form 10-K for the period ended December
31, 2004, of Swift Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the
registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such
internal control over financial reporting, to be designed under our supervision,
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant's disclosure controls and
procedures and presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant's internal control over
financial reporting that occurred during the registrant's most recent fiscal
quarter (the registrant's fourth fiscal quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal control over
financial reporting.
Date: March 15, 2005
/s/ Terry E. Swift
--------------------------------------
Terry E. Swift
Chief Executive Officer
103
Exhibit 31.2
CERTIFICATION
I, Alton D. Heckaman, Jr., certify that:
1. I have reviewed this Annual Report on Form 10-K for the period ended December
31, 2004, of Swift Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the
registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such
internal control over financial reporting, to be designed under our supervision,
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant's disclosure controls and
procedures and presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant's internal control over
financial reporting that occurred during the registrant's most recent fiscal
quarter (the registrant's fourth fiscal quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal control over
financial reporting.
Date: March 15, 2005
/s/ Alton D. Heckaman, Jr.
-----------------------------------
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
104
Exhibit 32
Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
In connection with the accompanying Annual Report on Form 10-K for the period
ended December 31, 2004 (the "Report") of Swift Energy Company ("Swift") as
filed with the Securities and Exchange Commission on March 15, 2005, the
undersigned, in his capacity as an officer of Swift, hereby certifies pursuant
to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, that to his knowledge:
1. The Report fully complies with the requirements of Section 13(a) or 15(d)
of the Securities Exchange Act of 1934, as amended; and
2. The information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of Swift.
Dated: March 15, 2005 /s/ Alton D. Heckaman, Jr.
-----------------------------
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
Dated: March 15, 2005
/s/ Terry E. Swift
-----------------------------
Terry E. Swift
Chief Executive Officer
105
Exhibit 99.1
H.J. GRUY AND ASSOCIATES, INC.
- --------------------------------------------------------------------------------
333 Clay Street, Suite 3850, Houston, Texas 77002
o TEL. (713) 739-1000 o FAX (713) 739-6112
January 27, 2005
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Re: Year-End 2004 R
Reserves Audit
Gentlemen:
At your request, we have independently audited the estimates of oil, natural
gas, and natural gas liquid reserves and future net cash flows as of December
31, 2004, that Swift Energy Company (Swift) attributes to net interests owned by
Swift. Based on our audit, we consider the Swift estimates of net reserves and
net cash flows to be in reasonable agreement, in the aggregate, with those
estimates that would result if we performed a completely independent evaluation
effective December 31, 2004.
The Swift estimated net reserves, future net cash flow, and discounted future
net cash flow are summarized below:
Domestic and International
Proved Reserves
- --------------------------------------------------------------------------------
Estimated Estimated
Net Reserves Future Net Cash Flow
-------------------------------- ---------------------------------------------
Oil, NGL, & Discounted
Condensate Gas at 10%
(Barrels) (Mcf) Nondiscounted Per Year
-------------------------------- ---------------------------------------------
Proved Developed 42,037,852 193,310,761 $ 1,865,056,103 $ 1,181,747,770
Proved Undeveloped 38,229,356 124,935,533 $ 1,426,565,121 $ 839,126,752
------------ ------------ -------------------- ---------------------
Total Proved 80,267,208 318,246,294 $ 3,291,621,224 $ 2,020,874,522
106
Domestic
Proved Reserves
- --------------------------------------------------------------------------------
Estimated Estimated
Net ReservesFuture Net Cash Flow
--------------------------------- ---------------------------------------------
Oil, NGL, & Discounted
Condensate Gas at 10%
(Barrels) (Mcf) Nondiscounted Per Year
--------------------------------- -------------------- ---------------------
Proved Developed 36,628,873 140,549,052 $ 1,686,081,612 $ 1,037,617,262
Proved Undeveloped 32,510,170 97,342,783 $ 1,267,049,676 $ 759,724,044
----------- ----------- -------------------- ---------------------
Total Proved 69,139,043 237,891,835 $ 2,953,131,288 $ 1,797,341,306
New Zealand
Proved Reserves
- --------------------------------------------------------------------------------
Estimated Estimated
Net ReservesFuture Net Cash Flow
Oil, NGL, & Discounted
Condensate Gas at 10%
(Barrels) (Mcf) Nondiscounted Per Year
--------------------------------- -------------------- ---------------------
Proved Developed 5,408,979 52,761,709 $ 178,974,491 $ 144,130,508
Proved Undeveloped 5,719,186 27,592,750 $ 159,515,445 $ 79,402,708
New Zealand Total 11,128,165 80,354,459 $ 338,489,936 $ 223,533,216
The discounted future net cash flows summarized in the above tables are computed
using a discount rate of 10 percent per annum. Proved reserves are estimated in
accordance with the definitions contained in Securities and Exchange Commission
Regulation S-X, Rule 4-10(a). The definitions are included, in part, as
Attachment I. The reserves discussed herein are estimates only and should not be
construed as exact quantities. Future economic or operating conditions may
affect recovery of estimated reserves and cash flows, and reserves of all
categories may be subject to revision as more performance data become available.
Swift represents that the future net cash flows discussed herein were computed
using prices received for oil, natural gas, and natural gas liquids as of
December 31, 2004. Domestic oil and condensate prices are based on a year-end
2004 reference price of $43.45 per barrel. Natural gas price is based on a
year-end 2004 reference price of $6.18 per MMBtu. New Zealand oil and
107
condensate prices are based on a year-end 2004 reference price of $36.95 per
barrel. The New Zealand gas prices are based on existing long-term contract
prices. The sales price for natural gas liquids is based on a reference price of
US$ 0.64 per gallon adjusted as necessary for existing contract terms. A
differential is applied to the oil, condensate, natural gas, and natural gas
liquids reference prices to adjust for transportation, geographic property
location, and quality or energy content. Product prices, direct operating costs,
and future capital expenditures are not escalated and therefore remain constant
for the projected life of each property. Swift represents that the provided
product sales prices and operating costs are in accordance with Securities and
Exchange Commission guidelines.
This audit has been conducted according to the Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserve Information approved by the Board
of Directors of the Society of Petroleum Engineers, Inc. Our audit included
examination, on a test basis, of the evidence supporting the reserves discussed
herein. We have reviewed the subject properties, and where we had material
disagreements with the Swift reserve estimates, Swift revised its estimate to be
in agreement. In conducting our audit, we investigated each property to the
level of detail that we deem reasonably appropriate to form the judgements
expressed herein.
Based on our investigations, it is our judgement that Swift used appropriate
engineering, geologic, and evaluation principles and methods that are consistent
with practices generally accepted in the petroleum industry. Reserve estimates
were based on extrapolation of established performance trends, material balance
calculations, volumetric calculations, analogy with the performance of
comparable wells, or a combination of these methods. Reserve estimates from
volumetric calculations or from analogies may be less certain than reserve
estimates based on well performance obtained over a period during which a
substantial portion of the reserve was produced.
Estimates of net cash flow and discounted net cash flow should not be
interpreted to represent the fair market value for the audited reserves. The
estimated reserves and cash flows discussed herein have not been adjusted for
uncertainty.
Future net cash flow as presented herein is defined as the future cash inflow
attributable to the evaluated interest less, if applicable, future operating
costs, ad valorem taxes, and future capital expenditures. Future cash inflow is
defined as gross cash inflow less, if applicable, royalties and severance taxes.
Future cash inflow and future net cash flow stated in this report exclude
consideration of state or federal income tax. Future costs of facility and well
abandonments and the restoration of producing properties to satisfy
environmental standards are not deducted from cash flow.
In conducting this audit, we relied on data supplied by Swift. The extent and
character of ownership, oil and natural gas sales prices, operating costs,
future capital expenditures, historical production, accounting, geological, and
engineering data were accepted as represented, and we have assumed the
authenticity of all documents submitted. No independent well tests, property
inspections, or audits of operating expenses were conducted by our staff in
conjunction with this work. We did not verify or determine the extent,
character, status, or liability, if any, of production imbalances or any current
or possible future detrimental environmental site conditions.
108
In order to audit the reserves and future cash flows estimated by Swift, we have
relied in part on geological, engineering, and economic data furnished by our
client. Although we instructed our client to provide all pertinent data, and we
made a reasonable effort to analyze it carefully with methods accepted by the
petroleum industry, there is no guarantee that the volumes of hydrocarbons or
the cash flows projected will be realized. The reserve and cash flow projections
discussed in this report may require revision as additional data become
available.
If investments or business decisions are to be made in reliance on these
judgements by anyone other than our client, such person, with the approval of
our client, is invited to visit our offices at his expense so that he can
evaluate the assumptions made and the completeness and extent of the data
available on which our opinions are based. This report is for general guidance
only, and responsibility for subsequent decisions resides with the decision
maker.
Any distribution or publication of this work or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
Texas Registration Number F-000637
by: /s/ Marilyn Wilson
--------------------
Marilyn Wilson, P.E.
President and Chief Operating Officer
Attachment
MW:pab
F:\Admin\S\SWIFT\322\Revised 2004Audit\LHyear-endaudit2004.doc
109